Coal: Breaking Oil's Chokehold
Climate change is a hot topic, and it’s getting unprecedented play. On TV, talking heads connect the dots between melting glaciers and human-produced greenhouse gases. In our living rooms and classrooms Al Gore’s “An Inconvenient Truth” is passionately persuasive as it asks, in bold letters over images of Hurricane Katrina, “Did the planet betray us or did we betray the planet?”
But does science back the fact that the press and the pundits have declared the debate on man-made global warming over? Not exactly.
Gore’s linchpin ice core sample shows a clear correlation between carbon dioxide (CO2) and temperature, and he says this cause-and-effect relationship is complicated. But a lesser-known British documentary, “The Great Global Warming Swindle,” says subsequent ice core surveys show Gore’s got the relationship backward. Researchers from around the world, including Harvard and NASA scientists who say their data was misconstrued in the February 2007 Intergovernmental Panel on Climate Change report that backed Gore’s premise, show the rise in temperature precedes the rise in CO2 by 800 years, not the other way around.
Despite this debate, the issue of global warming has, importantly, bolstered scientists’ efforts to find more efficient and responsible ways to produce energy.
UK geologist Brandon Nuttall says, “To me, the debate over whether CO2 causes global warming or global warming in turn increases CO2 is fairly irrelevant. Humanity has never served itself well in failing to take care of the things we throw away.” UK’s Gerald Huffman, director of the Consortium for Fossil Fuel Science, says, “Regardless of their opinions on global warming, most scientists I know believe the only sensible way to reduce CO2 or any other emissions from fossil fuel combustion is to increase efficiency.”
In the short term, the University of Kentucky’s efficiency efforts center on Kentucky’s most abundant natural energy resource—coal. By improving the ways we convert coal, we can produce more energy while limiting CO2 byproducts.
How can we transition today’s petroleum-based gasoline and diesel production to cheap, domestically available coal? UK research teams are refining Fischer-Tropsch synthesis, a World War II-era process for converting coal and natural gas into liquid transportation fuels. And as part of the nationwide push for “carbon sequestration,” UK geologists are mapping underground spaces that can become permanent storage sites for CO2.
Looking for long-term solutions, UK researchers are tapping into hydrogen. But hydrogen doesn’t exist on its own—they’ve got to figure out how to efficiently pull it out of natural gas, coal, biomass, or water, purify it, pressurize it for transport, and then pump it into our cars. So while UK scientists work to fill today’s energy needs with coal, they’ll also pursue next-generation hydrogen projects, including membranes to separate hydrogen from CO2 and catalysts to generate hydrogen for fuel cells.
Is it a pipedream to think that in just five years hydrogen will power our cars and homes? Probably. Huffman says, “We’ve developed several novel methods of producing hydrogen from coal or natural gas with little or no production of CO2. But I think the first use of hydrogen for transportation is at least 10 to 15 years into the future—probably in fleets of buses in large urban areas before it fuels personal vehicles.”
Nuttall says, in response to the Bush administration’s view that climate change is bad for business, “I see this whole global warming thing as an opportunity. If the climate question makes us consider efficiency, alternative and renewable fuels, and carbon sequestration, there will be a lot of business and investment opportunities in developing the technologies we’ll need. Climate change is only ‘bad for business’ if the sole path to the future is the status quo.”
Coal’s Starring Role
“When I came to UK, Kentucky was going to be the Saudi Arabia of the West,” says a grinning Burt Davis. The patriarch of the Center for Applied Energy Research (CAER), Davis has spent his 30-year career at UK studying clean-fuel technology.
So why hasn’t coal broken oil’s chokehold on us? It’s a matter of efficiency, he says. “In the late ’50s, I started working for a petroleum company. When you looked at the cost—from finding the oil, pumping it out, pipelining it—you were getting 95 percent of the energy into your gas tank. It was exceptionally efficient. Now, if you take coal, you’ve got to do a lot more work to turn it into liquid fuel. You only get 70 percent of the energy you started with into your gas tank. Today it’s still easier to pump oil out of the ground than it is to dig coal and convert that coal to liquid.
“But here’s the thing. We—Kentucky and the United States—have much more energy in the form of coal than the world does in petroleum. And we’re finding ways to increase the efficiency of coal conversion.”
How much coal does the United States have left? The American Coal Foundation estimates that nearly 300 billion tons of recoverable coal remain. In 2006, the United States produced 1.2 billion tons of coal (a 2.6 percent increase over 2005). If the growth rate of 2.6 percent per year holds, it will take 77 years to mine all 300 billion tons of coal. If the growth rate increases due to increased demand, we’ll run out sooner.
Kentucky, one of the big three coal producers along with Wyoming and West Virginia, generates more than 90 percent of the state’s electricity from coal, and more than 50 percent of the nation’s electricity is produced from coal. It’s a cheap power source, especially considering the rising cost of natural gas. And coal has the potential to overhaul our transportation fuel infrastructure by providing emissions-free diesel. (For more on clean diesel, see “Fischer-Tropsch: A New Lease on Some Old Technology.")
Davis says the United States would no longer need to battle the fluctuating price of imported petroleum if we could produce our own fuel domestically. “Each year 60 percent of our oil is imported. Some of that oil comes from unstable parts of the world, but two of the three countries that we import the largest amounts of crude from are our nearest neighbors—Canada and Mexico.”
The diagram above illustrates how coal could play a key role in tomorrow’s hydrogen economy, how CO2 could be stored underground through geologic sequestration, and how coal can provide us with the transportation fuels and chemicals we need today. UK researchers Gerald Huffman, Doug Kalika and Burt Davis walk us through the necessary steps for making more of our coal resources.
It all comes down to carbon. Made from ancient plant material, this stuff gives coal most of its energy. A single carbon molecule is the genesis of fuel production.
To produce liquid fuel, coal must be broken down into its most basic ingredients through gasification—applying heat under pressure to convert coal into a gaseous mixture, primarily hydrogen and carbon monoxide, called synthesis gas, or syngas.
“Carbon monoxide is a C1 molecule—it contains a single atom of carbon,” explains Gerald Huffman, loosening his tie. “When you gasify coal, you produce a mixture of carbon monoxide and hydrogen called syngas. From syngas, you can make other C1 molecules such as methane [the principal component of natural gas] and methanol [the simplest alcohol, used as an antifreeze, solvent and fuel]. You can also produce the more complicated hydrocarbon molecules we use to power our vehicles and planes—gasoline, diesel and jet fuel.”
Huffman, a UK physicist, says his interest in energy research started in the mid-’70s after the first Arab oil embargo. “I was working as a research scientist at the U.S. Steel Corporation Research Center in Pennsylvania. At that time, U.S. Steel was not only the world’s leading steel producer, they were also the third-leading coal producer in the United States. We were encouraged to get into coal utilization research and, somewhat to my surprise, I found it fascinating.”
Since 1986, he has managed the Consortium for Fossil Fuel Science (CFFS), a partnership of five universities (UK, West Virginia, Utah, Pittsburgh, and Auburn) led by UK, which has focused on the development of alternative sources for transportation fuel.
“Both the production and combustion of liquid fuels from coal produce a lot of carbon dioxide,” says Huffman.
“We’ve just started a new contract with the Department of Energy to combine biomass—agricultural and lumber waste—with coal to make liquid fuels. Theoretical calculations indicated that if you combine 30 percent biomass with 70 percent coal to produce your syngas, you can make a savings of up to 60 percent in total CO2 emissions.” Huffman adds that coupling biomass with coal would make good use of what is currently a waste material and could significantly extend the lifetime of our national coal resource.
Electricity & Hydrogen
Coal gasification is one of the most versatile and cleanest ways to convert coal into electricity, hydrogen and other valuable energy products. And it’s the cornerstone of the DOE’s FutureGen prototype power plant. This $1 billion, 10-year initiative will build the world’s first coal-based, “near-zero-emissions” power plant. Gasification, turbines to produce electricity, membranes to selectively remove hydrogen from processed syngas, and technology to remove and sequester CO2 are all vital components in the FutureGen power plant project.
Focusing on the third element of this process, Doug Kalika is improving membrane separation performance on the molecular level. For the past three years, Kalika’s polymer research group in the UK chemical and materials engineering department has partnered with Benny Freeman’s membrane team at the University of Texas at Austin. The leading-edge work resulting from this partnership has turned membrane science on its head.
“Membranes are incredibly energy efficient, simple and reliable, and they’ve been used for many kinds of gas separations over the years,” says Kalika, who in May 2007 received the Henry Mason Lutes Award for Excellence in Teaching in the College of Engineering, the eighth award he’s received in more than 17 years of teaching undergrads at UK.
“Our membranes are called ‘reverse-selective,’ because we’re reversing what’s ordinarily perceived as the way in which membranes work—as a size filter. Hydrogen, a much smaller molecule than CO2, would ordinarily fly right through.”
That’s a problem, he explains, because the processing of syngas results in mixtures of hydrogen and CO2, where hydrogen is the primary component. “In membrane separations you want to avoid having your majority component be the one that passes through the membrane, as this increases overall processing costs. Our reverse-selective membranes are synthesized from polymer material that has a natural chemical affinity for CO2. As a result, 10 times more CO2 than hydrogen permeates across the membrane, where it can be captured for eventual sequestration.
“A big advantage of our reverse-selective membranes has to do with pressure,” Kalika continues. “Ideally, you want to keep hydrogen at high pressure.” And that’s because hydrogen is very light. You need to increase the pressure to condense it in order to efficiently transport it. “Our process retains the hydrogen on the high-pressure side of the membrane. This eliminates a costly re-compression step that would be required with traditional sizes-elective membranes. So our membranes offer an additional cost advantage.”
Kalika points out that the ideal location for this separation to take place is inside a power plant. “You take coal or biomass, produce syngas—a mixture of carbon monoxide and hydrogen—and subject the syngas to an appropriate ‘shift’ reaction to maximize the hydrogen content, and convert carbon monoxide to CO2. Reverse-selective membrane separation results in a high-pressure hydrogen stream that can be burned for clean electricity or transported off-site for use as fuel or a feedstock for chemicals.” (To learn how UK scientists are improving hydrogen fuel processors, see “Hydrogen Nation.") “At the same time, CO2 is recovered rather than being released into the atmosphere.”
But today we’re not quite ready to employ hydrogen for transportation.
An alternative is to use coal gasification for the production of more traditional transportation fuels like diesel. After coal is gasified, the syngas is cleaned to remove sulfur, which can be sold for other industrial purposes. This purification is critical because sulfur and other chemicals could poison the next step: the Fischer-Tropsch (FT) reaction.
Discovered by two German scientists in the 1920s, the FT process uses a catalyst (a reaction accelerator) to convert syngas to hydrocarbons. Combustible hydrocarbons are the main components of fossil fuels (petroleum, coal and natural gas).
The hydrocarbons come out of the FT reactor as wax, and about 10 percent of this wax is approved by the USDA to preserve fruits and vegetables. “Did you know that the cucumbers or apples you get at the grocery store have a thin layer of Fischer-Tropsch wax on them?” CAER scientist Burt Davis asks, adding that it’s a profitable byproduct: today the going rate for edible wax is four times that of transportation fuel.
The rest of the wax is “cracked” (long molecules are chemically broken into shorter ones), a process called upgrading, to yield 20 percent low-quality gasoline and 80 percent high-quality diesel. “This is far superior to any diesel on the market made from petroleum, because it has no nitrogen or sulfur— no emissions,” says Davis from his office in the 30-year-old CAER building.
FT diesel has a high cetane number (the diesel equivalent of octane for gasoline). “In Europe, this is great because they use predominantly diesel vehicles. In America we’ve shied away from diesel in favor of flex-fuel vehicles.” These are cars and trucks that can run on a mixture of gasoline and ethanol. “We’d get a big savings if we’d invest in FT and produce diesel vehicles that take advantage of this high-quality, no-emissions fuel. We’d get more miles per gallon.”
Huffman’s CFFS team is tackling one downside to FT diesel—leaky rubber gaskets. He explains, “Alterations need to be made in the molecular structure of the fuel to properly swell gaskets to make seals. We don’t want trucks and planes dripping fuel all over the place.”
Huffman says efficiency is why a process from the 1920s is once again gaining momentum. “For a long time scientists didn’t seem interested in Fischer-Tropsch. ‘It’s an established commercial process, so why would you want to do research on that?’”
But improving industrial processes is the hallmark of engineering, Huffman says, adding, “Once in a great while you invent a completely new thing: that’s the revolutionary side. But most of research is on the evolutionary side. Gee, what if we had stopped doing research on airplanes 50 years ago—they’re commercial. We’d still be flying around in those little prop planes.”
“Everything in FT has improved,” says Davis. “The catalyst for FT is much more active—instead of working for one or two months, now they run for years.”
Just 10 minutes away from the UK campus, in the basement of CAER, Davis shows off his 16 Fischer-Tropsch reactors. Over the whir of experiments under way, he describes the catalyst testing his team does for large and small companies. “Our Fischer-Tropsch lab is the largest, open-access, non-commercial liquefaction lab in the country. We make and test promoters, chemicals that can be added to the cobalt and iron catalysts used in FT. Our objective is to discover which properties give the catalyst superior performance.”
Just how expensive would it be to do FT on a grand scale? Davis estimates that a commercial plant based on coal which would do all three steps—gasification, FT and upgrading—would cost $6 billion and produce 50,000 barrels of high-quality diesel per day. “Let’s put this in perspective. For starters, you’d have to invest $125,000 to produce a barrel of fuel per day. This initial investment is what makes companies reluctant to build FT plants. But operation of the plant can produce transportation fuels for about $15 per barrel, so that once the plant is paid for, the production cost of the fuel would be low. And at current prices—with crude oil at $65 per barrel—the plant could be very profitable.”
Who has the most incentive to try FT? The military, says Huffman decisively. The single largest user of foreign oil is the U.S. military.
CFFS has just recently started work on a Department of Defense contract, which was secured with the help of Senator Mitch McConnell, looking at FT fuel production. Huffman says, “If we can make fuels domestically, the United States won’t have to rely on petroleum-based fuels from unstable parts of the world.” The military needs about 300,000 barrels of oil to fuel their jets, tanks and trucks each day. A 50,000 barrel-a-day FT plant, times six plants, is doable, he says.
“They spend $300 a gallon—that’s the real estimate of the military’s cost to get fuel to the battlefield. The problem is transportation. Ultimately, the military would like to produce fuels closer to where they use them. We’re looking at how to miniaturize, so to speak, the FT process so you could build a plant on a military base in Iraq and use local resources to make the fuel.”
A single battlefield fuel. That’s the military’s goal. Right now they use a combination of jet fuel, diesel and gasoline to run their planes, tanks and trucks. A single fuel is not a new idea, says Davis. “In doing some research on the history of catalysis in the agriculture archives outside Washington, D.C., I saw that in the 1920s they were talking about two things: a single fuel for the military and using ethanol instead of gasoline. Not much has changed over the years.”
But with an ever-increasing supply of CO2, the need to do something with it other than vent it into the atmosphere is growing. The best solution to this problem may be right under our feet.
Deep rock reservoirs thousands of feet below Kentucky are a potential burying ground for coal’s CO2 downside. Kentucky Geological Survey (KGS) scientists Brandon Nuttall and Stephen Greb are investigating underground rock formations as part of two multi-state, DOE-funded partnerships centered on the nation’s carbon sequestration future.
These groups are looking at two kinds of sequestration. The first is terrestrial—storing CO2 in soils and wetlands. The second type is geologic—storing CO2 in depleted oil and gas reservoirs, unmineable coal seams and saline reservoirs. With data on oil and gas drilling that dates back to 1818, KGS is leading UK’s geologic research.
“When you think of an oil or gas reservoir, imagine a glass jar full of marbles,” says Nuttall, an Eastern Kentucky University geology grad who’s been at KGS since 1977. He’s a self-proclaimed “computer guy” whose expertise in databases and computer mapping mesh well with petroleum geology and stratigraphy—the study of layered rocks. “The marbles are like the grains of the rock—but you’ll note that there are spaces between the marbles, and that space is described in two basic ways. First, volume—the capacity to hold fluid—a.k.a. porosity. Second, permeability—how well the space is connected. Permeability controls how well things like oil, gas and water can move through the rock.
“You also need a seal. It’s like the lid on the jar. It’s something that will prevent the migration of whatever’s down there. How do we know that reservoirs and seals exist underground? Because we’ve found oil and gas fields where those resources have been trapped underground for millions of years. How well can those old reservoirs hold CO2? We don’t know, but it’s something people across the country will soon be testing.”
Nuttall leads the KGS team in the Midwest Geologic Sequestration Consortium (Kentucky, Indiana and Illinois), a partnership managed by the Illinois State Geologic Survey. His research focuses on shale—a fine-grained rock that underlies approximately two-thirds of Kentucky. In Eastern Kentucky that shale is up to 1,600 feet thick; in Western Kentucky it’s more than 400 feet thick. Shale typically functions as a seal for oil and gas. It’s a lot less porous than other rocks, so it’s a good cap.
But Kentucky’s pitch black Devonian shale is unique. Its color and smell indicate the presence of preserved organic matter (plant material) mixed in with the rock. Nuttall pulls a saran-wrapped sample from his shelf. As he unwraps it, a sharp odor fills his office. “That smell tells you it’s got a lot of organic content. This is a sample from Knott County I collected at 2,900 feet. With samples like this, I’ve found a relationship between the organic matter content of the shale and how much CO2 it can potentially store.
“My hypothesis is that we can recover methane, a.k.a. natural gas, by injecting CO2 into this organic-rich shale. CO2 is a little bit smaller than the methane, so it has a tendency to stick to the shale more effectively than methane does, and it displaces the methane. The research I’ve done in Eastern Kentucky shows that it’s a 5-to-1 deal—five volumes of CO2 will replace one volume of methane. You’re storing CO2 and you’re recovering methane that you can sell.”
Nuttall admits this concept isn’t new in Kentucky. “We began producing natural gas from shale in Western Kentucky around the time of the Civil War. In Eastern Kentucky it started in the 1890s. We know shale can produce methane—we’ve got a long history.
“And for more than 30 years, oil companies in West Texas have been injecting CO2 into their depleted oil and gas fields to increase the pressure and force the oil to the surface, and, as an added bonus, the CO2 dissolves into the oil and changes its viscosity or flow characteristics, making it easier to get it out.
“As far as I can tell,” Nuttall says, “shale itself will never be a primary CO2 storage zone, simply because you’re probably not going to be able to put in as much CO2 as a power plant can generate on a daily basis, quickly enough. Shale has the capacity to do it, but it doesn’t have the permeability.” Here’s where economics come in, he explains. If the price of natural gas is high enough and the price of CO2 is low enough, it may be economical to use CO2 to increase production of methane, and shale will come into its own for sequestration.
But it’s much more likely that the bulk of carbon sequestration will be focused on saline reservoirs. Stephen Greb, an artist, K-12 earth science speaker and geologist at KGS for the past 20 years, says, “These are deep underground rocks with saline water in them.” And these are much lower than underground water wells, which are about 300 feet deep, compared to reservoir depths of more than 2,500 feet. “Most people tend to think of underground water as caves and conduits, but that’s not what most saline reservoirs are.
“Using Brandon’s marble analogy, shrink the marbles down to the size of sand grains. There are still spaces between those grains, just like the spaces you see between the marbles. Those microscopic pores between each rock grain act like a sponge that fills with very salty water deep underground.
“The DOE FutureGen proposal that went out last year said they want to store a million tons of CO2 per year for 30 years. That means one really big saline reservoir or a group of reservoirs.” By analyzing oil and gas drilling data, Greb and other geologists at KGS, and around the nation, are trying to locate the biggest and potentially best reservoirs for carbon sequestration. “Saline reservoirs can be sandstones or carbonate rocks. And we’ve found a lot of oil and gas in sandstones and carbonates.
“We’re looking for reservoirs at least 2,500 feet. Because of the pressure at that depth, any injected CO2 would exist in what’s called supercritical conditions.” Greb explains, as you go deeper beneath the surface of the earth, pressure and temperature increase. In this high-pressure, high-temperature “supercritical” state, CO2 has the density of a liquid but the properties of a gas. “You can inject about 10 times the volume of CO2 into a space when it’s supercritical than you could in the same space at lower pressure. In Kentucky, we estimate that at depths of more than 2,500 feet CO2 gas should convert to a supercritical state.”
Locally, saline research is focused on the Mt. Simon sandstone (the largest and one of the deepest sandstone formations in the Midwest, stretching from Illinois to Indiana and Kentucky). In the center of Kentucky and north to Cincinnati, the Mt. Simon occurs at depths of 3,000 to 4,000 feet, and in Eastern and Western Kentucky it’s 10,000 to 20,000 feet deep. The depth itself is a challenge, Greb says, simply because most of the 150,000 records at KGS are for oil and gas wells at less than 1,500 feet. “Drilling that deep for oil has not been economical,” he explains. “And it’s going be an economic question for sequestration as well.”
Greb leads the KGS team that’s part of the Midwest Regional Carbon Sequestration Partnership (MRCSP), which includes Kentucky, Indiana, Ohio, Pennsylvania, West Virginia, New York, Michigan, and Maryland. This partnership is managed by Battelle, a global science and technology company headquartered in Columbus, Ohio. “The Nation’s Engine Room.” Greb states the slogan for the MRCSP region with an easy smile. “One in six Americans live here. One-fifth of the electricity in the United States is generated here. And coal-fired power plants play a huge role.”
In Phase I of this partnership, the scientists pooled existing data, including oil and gas wells and pipeline infrastructure, and identified current CO2 sources. “Representatives from each of the states got together and mapped the subsurface geology,” Greb says. “Phase II involves more detailed investigations of what we mapped and small-scale injection testing, including a demonstration project here in Northern Kentucky at the East Bend power plant.
“The Mt. Simon sandstone is at a depth of 3,000 to 4,000 feet in that area. We’ve just finished doing seismic analysis—shooting vibrations into the ground that reflect back and give you a picture of the subsurface geology. The next steps will be to drill a well, get rock samples, and test the permeability, porosity and water chemistry of the saline reservoir and overlying rocks that will act as a seal above the reservoir. From that data we’ll determine if the reservoir is suitable for injection. If it is, we’ll run computer models to simulate how far CO2 will likely spread at that pressure and plan the injection test. Tests like this are under way all over the United States.”
But ironically, the biggest challenge to this testing is getting CO2. “With all of the CO2 we put into the air, actually finding CO2 that we can inject for a test is hard, and expensive, because you’ve basically got to use beverage-grade CO2, the stuff designed for soda carbonation.” Until the infrastructure is built to economically capture CO2 at a power plant or other industrial source, and then pipeline CO2 directly from that source, large-scale sequestration demonstrations will be expensive. Greb says large-scale and long-term projects are currently being planned under Phase III of DOE’s carbon sequestration program.
“We have to look at all the geologic options,” he says, adding that if a national cap-and-trade program is enacted, power plants wanting to earn credits by sequestering CO2 will need to use the resources close to them.
“What’s under your power plant, ethanol plant, cement plant? These folks all produce a lot of CO2 and could end up using this technology in the future. It’s going to be increasingly important for many industries looking for new plant sites to consider the area’s geologic sequestration options.”
But an important question remains: What happens when CO2 goes wrong underground? Case in point: Lake Nyos in Cameroon. Nuttall relates the tale: “This is a very deep lake in an old volcano. Over a long period of time, a massive amount of CO2 leaked from the magma below the volcano into the lake. Because the lake was so deep, the CO2 stayed at the bottom of the lake—until one day in 1988 it exploded to the surface all at once.” Because CCO2 is denser than air, it hugged the ground, flowed down two nearby valleys, and suffocated 1,800 people and 3,500 livestock.
Obviously, this was a catastrophic CO2 event. “What’s interesting is how they fixed it,” Nuttall says. “They installed a floating ‘straw’ into the lake, basically a pipe that went very deep. They used a pump to prime the straw, and now CO2 just continuously bubbles up, so it doesn’t accumulate to dangerous levels.” Greb notes, “We won’t be injecting CO2 into deep volcanic lakes.” But to avoid a similar dangerous scenario, he says, significant research is under way to examine the natural seals above potential reservoirs and methods for monitoring injection sites.
How will scientists know that injected CO2 is staying where it should? And how can they tell the difference between injected gas that is leaking back to the surface and CO2 that results from normal biologic activity in the soil? KGS geologist Marty Parris is exploring these questions.
“In a carbon sequestration project, the goal is to keep CO2 in the subsurface reservoir,” says Parris. “But for both man-made and natural reasons, such as improperly plugged wells and faults, there could be leakage from a reservoir even before injection. And if it’s leaking naturally, you’re just going to enhance that leak potential by pressurizing the reservoir with CO2. The only way we’ll know if there is a leak is if we have a baseline database.” Parris will create this database with over 2,000 gas samples, including soil, atmospheric and natural gases from underground reservoirs across Kentucky. This data will be invaluable for coal-fired power companies in selecting future sequestration sites.
Greb sums things up:“In our state for sure, but in the country as well, the resources we have now are the ones we are going to use. I tell people all the time, we can’t get rid of anything. We need everything—biomass, nuclear, water, coal, oil, gas—and every year we need more and more because population increases and our need for cheap energy grows. So we’ve got to figure out the best way to use what we have, and we need to do it in a way that doesn’t cause environmental harm.”
And the biggest resource Kentucky has is coal. By pursuing Fischer-Tropsch reactions to make clean diesel from coal and by mapping potential CO2 burying grounds, the University of Kentucky is leading the push for “clean coal” and a cleaner, greener tomorrow.
Burt Davis reminisces about his days at Mobile in the 1960s: “Hydrogen lines ran along the ceiling in the hallways to the labs, and every Friday afternoon the safety officer would get a broom, hold it up to the pipes and walk along the lines. If there was a significant leak, the broom would ignite.” He chuckles and adds, “That was the safety procedure of the day.
“Hydrogen is the only gas that will auto-ignite. So if you’ve got a leak, you’ve got a flame. And it’s so light that it can escape through much smaller holes than other gases.”
Davis’s partner on hydrogen is Gary Jacobs. He earned his Ph.D. in 2000 from the University of Oklahoma, worked as a postdoc in Davis’s lab, and since 2001 has been a full-time chemical engineer at CAER. He explains, “Trying to compress and pump hydrogen through a pipeline is very energy intensive, because hydrogen is so light. And if you want to deliver it as a liquid, you have to cryogenically freeze it. That’s very expensive.”
How hydrogen will be delivered to the consumer is still a big question mark. Jacobs describes three possibilities. “Option one: large stationary plants. Gasified coal or biomass could feed those plants, and the resulting CO2 could be sequestered. But then the hydrogen would have to be compressed to be sent through pipelines, which means you’d need a whole new pipeline infrastructure—you can’t send hydrogen through the same pipelines as gasoline and natural gas.”
Option two: a smaller stationary unit. “You might pipe natural gas to your home and you’d have a small fuel processor in your garage to convert methane to hydrogen. Smaller amounts of CO2 could be emitted than what would normally be produced from an internal combustion engine running on gasoline.”
Option three, “onboard reforming,” would take place in the vehicle itself. He explains you’d add the fuel—natural gas (methane) or alcohols (methanol, ethanol) that can travel through existing pipelines—then the fuel processor (a series of critical catalytic reactions that, coupled with a fuel cell, could power the vehicle) would convert the liquid or gas to hydrogen. Again, this option could emit less CO2 than the internal combustion engines we use today.
“The problem with onboard reforming,” Jacobs explains, “is that residual carbon monoxide (CO) from the hydrogen production steps of a fuel processor is a poison for fuel cell catalysts. To convert this CO, you need very active and stable catalysts in order to reduce the size and weight restrictions of the fuel processor.”
This is where Davis and Jacobs come in. Their work, sponsored in part by the Kentucky Office of Energy Policy, centers on low-temperature water-gas shift catalysts, which are the heart of the fuel processor. Water-gas shift is a chemical reaction in which water and carbon monoxide react to form carbon dioxide and hydrogen.
Water-gas shift is nothing new—it’s the chemistry behind the catalytic converters mandated by the EPA in 1975 to reduce toxic emissions on vehicle exhaust systems. The problem with water-gas shift reactions: they’re exothermic—a lot of the energy is released as heat.
At the table in Davis’s CAER office, Davis sketches a chart with CO conversion and temperature as he explains, “Chemical reactions happen very fast at high temperatures—and speed is a good thing—but for exothermic reactions, you run into a wall very quickly.”
“The thermodynamic barrier,” Jacobs adds. “Because the reaction generates heat, as the temperature is increased carbon monoxide conversion decreases.” “So basically, our low-temperature water-gas shift catalysts aim to make practical use of this CO conversion limit,” says Davis.
Jacobs adds, “But at low temperatures, the reaction slows down. So, to achieve high CO conversion for a prolonged period of time at low temperature, you need a very active and stable catalyst. And if we’re going to do onboard reforming, it has to be with a catalyst that can withstand the frequent startup-shutdown cycles we put our vehicles through. It’s one thing to activate a catalyst and run a reaction, but to shut it down and start it up many times is a whole new ballgame for catalyst design.”
Platinum and ceria catalysts are the focus of the team’s research. (Ceria, or cerium oxide, is used in the walls of self-cleaning ovens.) When ceria is linked with platinum, the goal is to create as much surface area between the two components as possible. “Catalysis is all about the surface, because that’s where the reaction takes place,” Jacobs says. “In essence, we activate the catalyst by digging out oxygen atoms from the surface of ceria to create a defect.”
And in this case a “defect” is a good thing. At these defects, water molecules “activate” when they are chemically split apart to form special oxygen-hydrogen groups. These OH groups, in turn, react with carbon monoxide to form what is called an intermediate molecule on the surface of the catalyst.
The next critical step is breaking the carbon-hydrogen (C-H) bond of this molecule to convert it to CO2, and, as an added bonus, generate more hydrogen for the fuel cell. Davis and Jacobs found that by adding more platinum to ceria, they could break this bond faster. And in a project sponsored by Honda Research Incorporated USA, the CAER team confirmed Honda’s discovery that by adding sodium to zirconia, a material related to ceria, you can electronically weaken the C-H bond.
“Breaking this bond is the rate-limiting step that can slow down our process like a traffic bottleneck,” says Jacobs. “Say, you’re on I-75,” adds Davis, “and construction takes two lanes of traffic down to one. It takes you 20 more minutes to get to work. You’re able to speed up the flow by widening the bottleneck. In our case, by adding promoters like platinum and sodium to ceria, and by increasing the contact area between them, we are able to attack the C-H bond and turn over the intermediate molecule more rapidly.”
By studying ways to speed up low-temperature reactions, boost surface area and prolong catalyst lifespan, Davis and Jacobs are making molecular-level discoveries that will directly affect the function of tomorrow’s fuel processors.
How much coal does the United States have left? The American Coal Foundation estimates that nearly 300 billion tons of recoverable coal remain. In 2006, U.S. coal production increased 2.6 percent over the previous year to 1.2 billion tons. If the growth rate of 2.6 percent per year holds, it will take 77 years to mine all 300 billion tons of our coal.
Gerald Huffman, a UK physicist who leads the five-university Consortium for Fossil Fuel Science, is working on projects to marry biomass and coal to save up to 60 percent in total CO2 emissions and miniaturize coal-based liquid fuels production for the military.
How can the United States reduce carbon emissions? One idea, a national cap-and-trade program, would limit the level of carbon that can be emitted by an industry. Companies that hold their emissions below the cap can sell their remaining "carbon credits" to other industries. Companies that exceed their limit must purchase credits. If such a program is implemented, CO2 producers like power plants, ethanol plants and cement plants would have an economic incentive to capture CO2 and pipe it into the ground for long-term storage. (For more, see "Underground Carbon.")
Under a DOE contract, Gerald Huffman and Naresh Shah (Consortium for Fossil Fuel Science) developed a method to produce pure hydrogen in a single step from hydrocarbon gases that can come from coal-derived syngas. Carbon nanotubes (tiny, cylindrical structures that are stronger than steel and conduct electricity) are produced as a valuable byproduct.
The partnership between UK’s Doug Kalika, pictured here, and University of Texas researcher Benny Freeman is turning membrane science on its head. Instead of letting tiny hydrogen molecules fly right through and retaining CO2 like traditional membranes, the team’s “reverse-selective” membranes keep hydrogen and let CO2 pass through for capture and eventual storage.
In the basement of the Center for Applied Energy Research, Burt Davis shows off his 16 Fischer-Tropsch reactors and describes the catalyst testing his team does for large and small companies. “Our Fischer-Tropsch lab is the largest, open-access, non-commercial liquefaction lab in the country.” Fisher-Tropsch is a World War II-era process that makes liquid fuels from coal and natural gas.
A Brief History of Fischer-Tropsch
The original process was discovered by German researchers Franz Fischer and Hans Tropsch in the 1920s, and within 10 years commercial plants were built in Germany. Coal-based fuels powered the German war machine through the 1940s.
The only commercial Fischer-Tropsch (FT) plant in the United States was in Brownsville, Texas, in the early 1950s. (It shut down when cheap oil from the Middle East made FT production too pricey by comparison).
Today, there are only pilot-scale FT plants in the United States. Worldwide, the only commercial FT plants are in South Africa (Sasol, which produces liquid fuels from coal, and PetroSA, from natural gas) and Malaysia (Shell, natural gas). “Fifty percent of the airplanes that take off from Johannesburg every day are fueled by coal,” says Center for Applied Energy Research scientist Burt Davis.
Shale—a fine-grained rock that underlies approximately two-thirds of Kentucky—keeps oil and gas from migrating underground.
Brandon Nuttall at the Kentucky Geological Survey says because CO2 is smaller than methane, it has a tendency to stick to shale more effectively than methane does, and it displaces the methane. “The research I’ve done in Eastern Kentucky shows that it’s a 5-to-1 deal—five volumes of CO2 will replace one volume of methane. You’re storing CO2 and you’re recovering methane that you can sell.”
Sandstones make up most saline reservoirs—deep underground rocks that hold saline water. These are much lower than underground water wells, which are about 300 feet deep, compared to reservoir depths of more than 2,500 feet.
Stephen Greb, an artist, K-12 earth science speaker and Kentucky Geological Survey scientist, is looking for saline reservoirs in sandstones deep underground. Sandstones—rocks with microscopic pores that act like a sponge to soak up salty water—hold great promise for long-term CO2 storage.
By studying ways to speed up low-temperature reactions, boost surface area and prolong catalyst lifespan, Burt Davis (left) and Gary Jacobs are making molecular-level discoveries that will directly affect the function of tomorrow’s fuel processors.