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Environment

Capturing Carbon And Saving Coal

Electric utilities face a tangle of choices when figuring how to pull CO2 from coal-fired plants

by Jeff Johnson
October 29, 2007 | A version of this story appeared in Volume 85, Issue 44

It's A Gas
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Credit: NETL
Using an X-ray photoelectron spectrometer, a National Energy Technology Lab scientist examines reactions between metal oxides and coal syngas.
Credit: NETL
Using an X-ray photoelectron spectrometer, a National Energy Technology Lab scientist examines reactions between metal oxides and coal syngas.

CONFUSION ABOUNDS when gambling on coal's role in the carbon-constrained world of the future. Much hope has been pinned on a vision in which carbon dioxide is captured in various ways from coal-fired utilities, compressed and piped to an injection site, and pumped into geologic repositories deep in Earth.

This vision would allow coal to remain the top fuel for generating electricity in a world increasingly affected by climate change. Coal provides a little more than half of U.S. electricity as well as more than one-third of anthropogenic CO2 emissions that are blamed, along with other greenhouse gases, for heating up the planet. But large-scale, industry-sized programs to sequester CO2 underground are just getting under way (C&EN, Sept. 24, page 74).

Technologies to pull CO2 from coal-fired utilities in a concentrated stream are in the same boat and are now just beginning to move from the lab to industrial pilot sites. Engineers designing systems to capture and sequester CO2 expect that the capture portion of these systems will amount to 75% of the total cost. In addition to upping the price that consumers will pay for electricity, capture technologies will affect the output and operation of existing and new power plants.

Right now there is no requirement for utilities to limit their CO2 emissions, but most in the industry think regulations are coming soon. For an industry that must plan years if not decades ahead to supply a critical energy source that cannot be stockpiled, this lack of clarity is a big problem.

Concerns and confusion over CO2 emissions and costs have resulted in courts, regulatory commissions, state officials, and local and national environmental groups blocking or challenging coal-fired power plants proposed for Kansas, Florida, Illinois, Montana, Colorado, Utah, Nevada, South Dakota, and Texas.

Rep. Henry Waxman (D-Calif.), chairman of the House Committee on Oversight & Government Reform, has criticized the Environmental Protection Agency for its unwillingness to regulate CO2 as a pollutant and include CO2 emission limits in permits. He recently began an investigation into EPA's permitting system and announced his intention to hold hearings.

Waxman, as well as coal supporters and opponents, frequently cite an influential Department of Energy rolling projection of new coal-fired power plants, which shows a rosy future for coal. The last incarnation of the report, released in June 2006, predicted a "coal resurgence," with some 300 new plants in the works and 154,000 MW of new coal-fired power coming on-line by 2030, a significant boost over today's 300,000-MW capacity. A month ago, however, the report was withdrawn, and a new version appeared on Oct. 10.

This version predicts a drastic cut in construction. And gone is any mention of "resurgence." Instead, the report stresses that most previously announced plants are not likely to be built and underscores the delays that often plague the industry. It says 24 coal-fired U.S. power plants are under construction with a capacity of 12,500 MW and another eight are near construction, with 4,500 MW of capacity. Thirteen plants have gained permits but have uncertain futures. These numbers are a far cry from the projections of past reports.

Among utilities that are rethinking coal is Tampa Electric Co. (TECO). It announced on Oct. 4 that it is dropping a long-planned project to build a 789-MW integrated gasification combined cycle (IGCC) coal-fired plant at its Polk County, Fla., site. The decision is particularly surprising because IGCC technology is favored by environmental activists and others due to its efficiency and ability to provide the least polluting coal-fired electricity. It can also be made to produce CO2 in a concentrated, 90% stream that can ease capture.

cleaning Coal
Credit: IPCC
Overview of options for CO2 capture from a power plant.

In TECO's case, the federal government was going to sweeten the deal by giving the utility a $133 million tax credit, part of a $1 billion federal package to encourage advanced coal technologies at nine U.S. plants. The cancellation also drew attention because TECO is owner of the nation's first and, at 255 MW, largest IGCC demonstration project. The new IGCC facility would have been built right next to the current one.

"We believe there is a role for IGCC in Tampa Electric's future generation plans," says Charles R. (Chuck) Black, TECO president. "But with the uncertainty of carbon capture and sequestration regulations being discussed at the federal and state levels, the timing is not right to utilize it for a baseload facility needed by 2013. We are not prepared to expose our customers and shareholders to that risk."

Black also says IGCC may not be the most cost-effective technology to use at this time. "We are going to take a step back and reevaluate how best to meet our 2013 needs," he notes.

TECO spokesman Rick Morera adds that a few months back, the Florida Public Service Commission denied permits for two coal power plants in the state, and TECO and other utilities took note. TECO decided to hold off. Says Morera, "There is new sentiment in the state that we need to take a good hard look at coal."

The proposed TECO plant would have cost $2 billion but would not have captured CO2, Morera stresses, although it would have offered the higher efficiency that comes with IGCC when compared with conventional coal plants. TECO worried, he says, that some time in the future the utility might have been ordered to install carbon capture technology. "This might put our project at a cost disadvantage compared to other alternative technologies," Morera points out.

Hence, Morera adds, TECO will turn to improving energy efficiency and adopting other noncoal alternatives to meet growing energy needs until 2013, when the utility believes new baseload generation will be needed. The company, he stresses, wants to see what laws are enacted to control CO2 emissions—not just utility emissions but across the board—before building a large, expensive baseload unit.

TECO's decision is just fine with George Peridas, senior fellow with the Natural Resources Defense Council, an environmental group that has pushed hard for carbon capture and sequestration.

"We are opposed to construction of any new coal plants that do not capture and sequester the majority of their CO2," he says. "Meanwhile, there are much better things utilities can do, such as increasing energy efficiency and maximizing use of renewable energy. We believe, however, the technology exists today to build a new generation of coal plants that do not vent CO2."

Many in the power industry aren't so sure.

Peridas and others in the environmental community see IGCC as a way out of the carbon crisis and point to several hundred IGCC plants operating around the world, but most of these plants are used to produce hydrogen and other chemical products. Only two U.S. plants use IGCC to generate electricity, and neither captures carbon.

"The power industry is very conservative when it comes to technology," notes Larry S. Monroe, senior research consultant for Southern Company Generation. The company has two IGCC plants in planning, but neither includes carbon capture capabilities.

"Utilities get into new technologies like you get into a very cold swimming pool," Monroe explains. "First you put your toe in and take it out and then put your whole foot in and take it out and then start wading in. That is what you see the industry doing with IGCC. Carbon capture is another step in the process, but that would take us up to the waist. We want to get more experience before we jump into that."

The immediate coal question, however, revolves around what to do about the nation's 1,500 existing coal-fired plants, more than half of which are more than 35 years old.

"Every major power company has made an analysis of shutting down versus retrofitting existing plants," says George R. Offen, technical executive with the Electric Power Research Institute (EPRI). "But the unknown is how successful we will be in developing inexpensive and successful control technologies."

Offen says EPRI calculates that it costs at least 30% more to add controls for conventional pollutants to an existing plant than to build them into a new one. For CO2 capture, he says, it will be at least that expensive, mostly due to energy drawn from the plant's output that will be used for capture. Cost will drop, he predicts, but when and how much remain unknown.

Offen adds that it might not even be physically possible to upgrade some old plants, because CO2 capture equipment takes up about 6 acres for a typical 500-MW plant.

With the unknowns ahead and the time for action growing more urgent, engineers such as Thomas J. Feeley III, technology manager of the Innovations for Existing Plants Program at DOE's National Energy Technology Laboratory, expect to see a sort of "learn on the job" approach to carbon capture and sequestration technologies.

CO2 capture at utility-scale size with huge air-flow volumes is the most technically difficult and expensive part of carbon capture and sequestration. The costs are split between buying and installing capture equipment and the loss of output power due to diverting it to equipment needed to concentrate and remove CO2.

There are three basic approaches to capturing CO2 from a coal-fired power plant, Feeley says. They are called postcombustion, oxy-fuel combustion, and precombustion.

Add-on postcombustion technologies are the most applicable to existing pulverized-coal plants, which make up nearly all of the current plants. Consequently, these technologies are most likely to be used to retrofit an existing plant, Feeley notes, but adds that retrofitting with oxy-fuel technologies may prove to be a possibility.

In such a conventional pulverized-coal plant, coal is burned to make steam to turn turbines. The gas exiting the furnace contains about 15% CO2, and the rest is mostly nitrogen and steam at atmospheric pressure. Feeley says the low pressure and low CO2 concentration makes capture difficult and expensive. To concentrate the CO2, engineers have turned to a chemical solvent, an amine compound, to adsorb or absorb the CO2.

THE PROCESS BEGINS when flue gas that would be vented to a stack is bubbled through a solution of water and amines. The amines react with CO2 and form an intermediate that remains in solution. The CO2-rich amines are pumped to another vessel and heated, causing them to revert back to amines and CO2; the amines are recycled and the CO2 is collected.

There is a price to pay, however. Energy needed to reverse the amine reaction and capture the CO2 cuts power output by some 30% and increases costs of electricity by 65%, according to DOE and industry analyses. The amine process is now in use to capture CO2 in non-coal-based industrial applications at volumes of about 800 metric tons of CO2 per day. That's far below the 9,000 or more metric tons of CO2 an average coal-fired power plant produces each day.

Researchers at both DOE labs and utilities are investigating new solvents that capture CO2 more efficiently than amine solutions and take less energy to do it. In one prospect, CO2 is absorbed by a solution of ammonium carbonate at low temperature and atmospheric pressure, forming ammonia bicarbonate. Ammonium carbonate has twice the CO2-loading capacity of amines and it takes less than half the heat to regenerate the solvent, according a study by EPRI, which is part of a consortium funding the research. Regeneration or separation also occurs under higher pressure, so less energy is needed to compress CO2 for pipeline transportation and injection underground.

EPRI claims the process would cut power plant output by only 10% and raise electricity costs by 25%. There are doubters, however, and field research projects are getting under way.

Separation
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Credit: NETL
A membrane developed by National Energy Technology Lab to separate CO2 from hydrogen in syngas uses an ionic liquid encapsulated in an organic substrate.
Credit: NETL
A membrane developed by National Energy Technology Lab to separate CO2 from hydrogen in syngas uses an ionic liquid encapsulated in an organic substrate.

We Energies, a Midwest utility, is trying chilled ammonia on a small portion of flue gas from its 1,200-MW coal-fired plant in Pleasant Prairie, Wis. If successful, American Electric Power (AEP) will use the technology at its New Haven, W.Va., plant on a 30-MW stream from its 1,300-MW power plant. Beginning next year, it intends to sequester 100,000 metric tons of CO2 per year in a saline aquifer under the site.

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If these projects go well, AEP intends to install the same system in 2011 at its 450-MW plant in Oologah, Okla., to capture 1.5 million metric tons of CO2 per year. The company will pump the gas into its underground oil assets to help recover the petroleum.

Another demonstration project using an ammonia-based capture technology is getting under way at FirstEnergy's Burger Plant in Shadyside, Ohio. The process was developed by Powerspan Corp. and can be used in combination with its technology to capture conventional pollutants. EPRI's Offen notes that sulfur dioxide must be removed before solvent capture of CO2 by amines or ammonia. Consequently, the Powerspan technology, by capturing other pollutants as well as SO2, might lead to an all-pollutant-in-one approach to carbon capture. Last August, Powerspan and oil-and-gas giant BP announced their intention to collaborate on the technology and to have it in operation at the Burger facility in early 2008.

The second broad-capture-technology approach, according to Feeley, is known as oxy-fuel combustion. It is less developed than amine-related approaches but holds promise because it could be used to capture other pollutants along with CO2. Unlike postcombustion approaches, this method modifies combustion conditions by burning coal in an oxygen-enriched environment by injecting pure oxygen diluted with CO2 and water into a boiler. After combustion, the primary output products are CO2 and H2O, as well as nitrogen oxides, SO2, and mercury. These pollutants can be pulled out with conventional control equipment or condensed out, leaving a relatively pure CO2 stream.

Besides capturing CO2, early studies show, oxy-fuel combustion allows for a 60% reduction in nitrogen oxides production as well as for better mercury removal compared with conventional coal combustion.

AEP and Babcock & Wilcox are planning to run oxy-fuel combustion trials at Babcock's 30-MW test facility in Alliance, Ohio. The partners are also looking at the feasibility of retrofitting existing plants in the coming years. And just weeks ago, Foster Wheeler and Praxair announced that they would build a 30-MW demonstration project testing oxy-fuel technology at a fluidized-bed power plant in Jamestown, N.Y.

The third capture approach, Feeley says, is precombustion, or gasification, a completely different way of pulling energy from coal or any other carbonaceous material. For electricity generation, this means IGCC systems.

IGCC produces a syngas of mostly hydrogen that fuels gas turbines, and the waste heat can be reused to produce steam that can turn a second set of turbines. The hydrogen can also be used in fuel cells to produce electricity.

Removal of CO2 and other pollutants takes place as the hydrogen is purified. There are no postcombustion releases. To produce syngas, coal is processed with oxygen and steam under high pressure. The syngas consists mainly of hydrogen, carbon monoxide, and CO2. CO2 can be removed relatively easily from the syngas but CO cannot, so the gas is sent to a water-gas shift reactor, where most of the CO reacts with water to produce CO2 and hydrogen at a roughly 40% and 55% mix, respectively. At that point, the CO2 is under pressure and can be removed with a physical solvent-based system such as Selexol, but Feeley notes that membranes, solvents, and sorbents are undergoing development to improve their separation performance and costs.

IGCC has a host of advantages for electricity generators, regardless of the CO2 capture issue. The process might approach 50% efficiency, far above the 33% of conventional plants or the 40–45% of advanced combustion technologies. Hence, the efficiencies themselves can lower CO2 emissions per unit of electricity output, Feeley notes. IGCC also can produce a concentrated, high-pressure stream of 95% CO2 that can be piped directly to a sequestration site without compression. Building an IGCC plant, however, is at least 20% more expensive than constructing a conventional power plant, Feeley adds. But when examining costs, he says, it is important to calculate efficiencies. Efficiencies for all coal units drop when carbon capture is included, but IGCC comes out on top at 33% due to better efficiency to begin with and ease in capturing CO2.

IGCC has created quite a buzz, and almost all power providers are considering or planning construction. AEP, Southern, Cinergy, and Xcel are among those providers. DOE and a coalition of companies just broke ground on a 285-MW unit to be built in Orlando, Fla. The facility will join two other IGCC plants built with DOE support. None of them, however, can capture carbon.

One plant that will collect CO2 and generate electricity is being planned by a venture between Rio Tinto, an international mining company, and BP. The 500-MW facility is intended for Carson, Calif., near Los Angeles, and will gasify coke waste from petroleum refining. It will collect and sequester the CO2 near the plant for enhanced oil recovery. How many companies will take TECO's path and drop out when they get closer to construction, however, is yet to be seen.

Estimates for how much the cost of these new plants will raise the price of electricity vary widely. Estimates compiled by DOE, utilities, and a study by Massachusetts Institute of Technology show a cost increase of as much as 65% for carbon capture and sequestration at a conventional coal-fired plant and 30–40% for an IGCC facility.

Even with this increase, the U.S. has some of the cheapest electricity in the world. A report by DOE's Energy Information Administration and the International Energy Agency found that average U.S. household electricity prices are about 10 cents per kWh when state and local taxes and miscellaneous service charges are figured in. The report compared U.S. electricity with that of the rest of the world and found that in Germany, household electricity cost in U.S. dollars is 21 cents per kWh. Denmark pays almost 30 cents; Austria, 17 cents; Japan, 19 cents; and the Netherlands, 25 cents.

While Congress and states debate what should be done to address CO2 emissions and climate change, utilities are looking for direction.

"We don't think regulations should come along until we are further down the technology path," says Southern's Monroe. "Meanwhile, we'll keep looking for efficiency."

Capture
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Credit: NETL
The ability of an amine-based sorbent to capture CO2 from a coal plant's flue gas stream is tested in a research reactor at the National Energy Technology Lab.
Credit: NETL
The ability of an amine-based sorbent to capture CO2 from a coal plant's flue gas stream is tested in a research reactor at the National Energy Technology Lab.

HE OUTLINES both end-use and generation efficiencies. Southern is exploring incentives to spur residential and commercial efficiency, such as greater use of compact fluorescent lighting and ground source heat pumps, Monroe notes. On the generational side, Southern is working to increase the efficiency of its coal plants.

When asked how Southern will proceed with meeting its future electricity supply needs, Monroe explains that when determining how to comply with other new pollution control requirements, the company usually starts with the biggest and newest plants to retrofit and determines how far down the chain of coal plants, considering age and size, it will go when adding controls.

But for CO2-driven efficiency improvements, he doubts that there are many opportunities left at existing plants. Most of that has been done, he says. He is also skeptical that the company can economically retrofit current plants to include carbon capture. Still, the company is involved in several demonstration projects that could lead to retrofits and is closely watching others.

Southern has no current plans to build a pulverized coal plant, Monroe says, but if it moves that way, the plant will be based on an advanced supercritical unit that uses higher temperatures and higher steam pressures to get efficiencies in the 40–45% range, rather than the 33% of a conventional plant. The company also has two IGCC plants in the works—one in Florida with DOE as a partner and one proposed for Mississippi, which will get federal tax aid like the plant TECO dropped would have.

"Is this an appropriate time to shut a plant down and build newer plants?" Monroe wonders, shaking his head. "CO2 makes you sort of ask, 'Well, should I build a conventional coal plant, should I build an IGCC, should I build an IGCC with carbon capture or should I make it capture-ready—whatever that means—or should I just build a nuclear plant?'

"We are involved in that decision-making process now, and I can't give you a good answer," Monroe continues. "But we must make decisions soon. I can't say what we are going to do because I don't know."

Feeley commiserates: "Utilities are holding the decision close to the vest. If you toss in requirements for renewable energy, it is hard for utilities to plan. At times like this, it would be interesting if we could go ahead 20 years and look back."

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