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Amid All the IGCC Talk, PC Remains the Go-To Guy

Issue 4 and Volume 110.

IGCC gets all the buzz while pulverized coal wins all the contracts for new coal-fired capacity.

By Steve Blankinship, Associate Editor

Integrated gasification combined cycle (IGCC) isn’t exactly new. Generally defined as gasifying coal to produce various combinations of power and/or a commercially marketable by-product such as methane, methanol, ammonia or sulfur, IGCC has been in commercial use for decades. Globally, more than 100 sites have IGCC installed, including more than a dozen locations that produce power. Those sites include the 262 MW Wabash River Coal Gasification Repowering Project in Indiana and TECO Energy’s 260 MW Polk Unit 1 in Florida.

But among a cross-section of politicians, regulators, news media, environmentalists and some major power industry players, IGCC wears the mantle of a Holy Grail for coal-fired electric power production. It’s not the first time a technology has emerged as the next big thing for coal plant design. In the 1980s, circulating fluidized bed (CFB) was all the talk at energy conferences and at the U.S. Department of Energy and Environmental Protection Agency. Today, CFB fills a valuable niche in the coal-fired sector by allowing owners under the right set of circumstances to use a variety of coals (including waste fuels) to produce highly reliable power to the grid.

IGCC buzz has now reached a crescendo, perhaps no better evidenced than by attendance numbers at last fall’s Gasification Technologies Conference. The event drew more than 700 registrants, double the attendance numbers for 2004. AEP plans to build up to 1,200 MW of IGCC capacity, assuming regulators allow it to recover construction and operating costs from ratepayers. Cinergy, which has now merged with Duke, and Energy Northwest have also announced plans to build IGCC power plants.

The ERORA Group will develop the Taylorville (Ill.) Energy Center, an IGCC coproduction facility. Coproduction means it will make a byproduct – often critical to assuring economic viability for an IGCC facility. Commercial operation is expected in the 2009-2010 timeframe. The plant will be fueled by about 2 million tons of Illinois Basin coal annually and will produce methane or methanol in addition to electricity.


TECO Energy’s Polk Unit 1 IGCC unit near Tampa, Fla., began commercial operation in 1996. After coal is gasified and burned in the combustion turbine, the combustion turbine’s exhaust heat is recovered in the heat recovery steam generator to produce steam. It then passes through a steam turbine to produce more electricity. The process removes at least 95 percent of the sulfur. Nitrogen oxide emissions are also lower than from many advanced coal-fired generating units currently in operation. Sulfuric acid and solid byproducts are sold for industry use. Photo courtesy of TECO Energy.
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GE Energy is producing a 630 MW IGCC reference plant design, which is expected to be unveiled late this year. Major petroleum and chemical companies that have decades of experience with IGCC in industrial applications have formed alliances with utilities, OEMs and A&E firms to develop projects. Major players include ConocoPhillips, Shell, Eastman Chemical, Bechtel, Black & Veatch, Fluor, Siemens and Burns & McDonnell, which is providing overall project management for the ERORA project.

Of the $200 million in loans, loan guarantees and direct grants earmarked for advanced coal-based power development by the federal Energy Policy Act, at least 70 percent must be used for gasification projects. And of the $1.3 billion in tax credits reserved for advanced coal projects, IGCC projects will be eligible for up to $800 million (and a 20 percent tax credit), while other advanced coal projects will be eligible for up to $500 million (and a 15 percent tax credit).

The U.S. government’s showcase clean technologies project, FutureGen, will be an IGCC plant intended to demonstrate IGCC’s full range of promises. It will generate electricity, produce a marketable byproduct, capture CO2 prior to combustion and sequester it. In effect, the FutureGen project now being pursued by more than a dozen states will be a zero emission coal-fired power plant.

In light of this array of dramatic developments, it seems appropriate to stop, take a deep breath, and assess the realities of both coal gasification and pulverized coal technologies, whose performance and ability to control emissions of all kinds – including mercury and CO2 – continue to advance.

Overwhelmingly, utilities still build pulverized coal (PC) plants. The current resurgence in coal plant construction reflects that preference. A look at the coal plants currently in development or under construction in the United States shows almost all of them to be subcritical or supercritical PCs with a handful of CFBs, such as East Kentucky Power Cooperative’s three fluidized bed units at the Spurlock and J.K. Smith plants. The units allow the Kentucky co-op to burn a variety of coals in addition to supplemental feedstocks like tire-derived fuel and biomass.

It’s not that IGCC isn’t on utilities’ radar screens. Today, no utility builds new generating capacity without conducting a technology assessment that considers most if not all generation alternatives. David Wilks, president of energy supply for Xcel Energy, describes how various options were considered in choosing to build Comanche 3, a 750 MW supercritical coal plant scheduled for service in 2009. Comanche 3 will be the first coal plant built in Colorado in more than 25 years. The $1.3 billion unit was approved by the Colorado Public Utilities Commission as part of a larger resource planning process that resulted in a landmark settlement between Xcel Energy, the PUC staff and numerous environmental and consumer advocacy parties.

During the licensing process, Xcel Energy looked at various options, including IGCC, demand-side management and renewables, in lieu of building a pulverized coal plant. “We evaluated IGCC but believe that, especially at our high altitude, the technology is still unproven,” says Wilks. “No one at this high an altitude or with western coal – the logical coal for us since we are in the west – can consider an IGCC at this stage of development for utility use.”

Edward Lowe, general manager of gasification for GE Energy, notes the effect of altitude on IGCC units can be offset by methods that have been commercially demonstrated. “They include opening of inlet guide vanes that are normally closed at ISO conditions to maintain the gas turbine at its mechanical torque limit,” he says. And he adds that inlet chilling and/or humidification is more effective in lower ambient temperatures and humidity profiles found at high altitude. Other methods include increased nitrogen gas (N2) and/or steam injection, duct firing and inlet turbo charging similar to that applied to natural gas-fired combined cycle units.

Xcel Energy is investigating building an IGCC in Colorado. “To be comfortable that this technology is ready to be commercial, somebody needs to demonstrate it,” says Wilks. Xcel is trying to take advantage of current guarantees, price supports and credits to see how to get it developed. Xcel would likely include partial CO2 capture and sequestration to demonstrate the technology as a part of any project. “We don’t know yet about a by-product because it’s way too early in the thinking stage for that,” Wilks says. “But intellectually we have concluded that any demonstration we do should show the complete cycle.”

Wilks notes that Colorado has an abundance of sequestration sites in the oil field-rich eastern part of the state. “We’ve talked about something in the 300 MW range and spoken with several IGCC technology providers,” he says. “Within a decade or so we could have an IGCC operating here at our high altitude. A few companies in Colorado have told us they would be interested in partnering with us if we decide to go forward.”

Kansas City Power & Light also looked at options surrounding an IGCC before deciding on supercritical PC technology for its 850 MW Iatan 2 plant, to be built next to its 700 MW Iatan 1 unit in Westin, Mo. “We engaged in a very open and broad planning process, where we sat down with our regulators in Missouri and Kansas and examined what we needed to do over the next 10 years to meet the region’s energy needs,” says John Grimwade, KCP&L’s senior director of construction. “We set up workshops and invited many people to participate in the planning process. Through that collaborative effort, we came up with a comprehensive energy plan which included a 100 MW wind project, environmental retrofits on several plants, demand-side management and energy efficiency programs and distribution automation programs in addition to the coal plant. We looked at what made the best economic sense and looked at future scenarios involving carbon dioxide and renewable portfolio standards. We heard a lot of feedback from a lot of people.”

Grimwade, who serves on Kansas’ FutureGen task force, says that KCP&L assessed many aspects of IGCC’s ability to capture and sequester CO2 on a precombustion basis and examined the state of the technology. “With sequestration it becomes a site-specific geology issue. You might have to gasify the coal close to where you can sequester it, then pump the gas to a plant closer to your load. That’s one of the elements that hasn’t been worked out.”

He notes that KCP&L looked at the data EPRI has for IGCC units operating with various coals. “When you consider low-grade coals such as sub-bituminous that are the most economic and accessible to where we are in the Midwest, and compare IGCC’s performance with supercritical and ultra-supercritical, you actually have higher heat rates with IGCC,” he says. Much of the data on IGCC has been with petcoke and eastern bituminous coals rather than on low-rank coals that many utilities use. “We view IGCC as a promising technology, but not commercially developed. We can’t yet know if it will perform as you need it to. We’re as anxious as anyone to see how it develops.”

Déjà Vu?

One power sector insider recalls how in 1988, the industry went through a similar debate, except then it was CFBs versus PCs. CFBs looked slightly better on emissions than PC. CFBs were just emerging and had lower operating temperatures, therefore the NOx profile was lower. CFBs also allowed controlling sulfur in the bed at levels higher than the wet FGDs being built at the time.

EPA signaled that CFB was going to be best available control technology (BACT). But for various reasons, including size limitations, CFB did not replace PC. Nevertheless, it still found a significant niche within the market and provided power providers with a new option under the right set of conditions. Furthermore, competitive pressure from CFB’s environmental profile led to the use of selective catalytic reduction for higher NOx control in PC coal-fired units as well as increases in wet scrubber efficiency.

The result is that 20 years later, depending on the fuel and the site, a PC may offer a cleaner profile than a CFB. It therefore seems reasonable to assume the same thing could happen this time in terms of competition in performance between IGCC and PC. Therefore, any attempt by industry or government to pick PC or IGCC now as BACT would only stifle innovation.

“One of the perceived issues of IGCC technology is overall plant availability,” says Jim Jurczak, director of IGCC projects for Burns & McDonnell. “Related to that is the gasifier itself and the potential need for a spare gasifier.” Adding a spare gasifier should improve availability but at the expense of higher capital costs and O&M expense.

Then there are issues related to availability, load following and dispatch that a baseload coal plant must address to operate in an electric utility model. Adding a gasification train or trains in front of combustion adds another element with a potential for failure. Gasifiers, for example, can’t be turned on and off with impunity. Heavy refractory lined gasifiers, for example, require at least 48 hours to go from cold to full capacity. To most utility operators, that doesn’t sound like a fit for the load and temperature swings and cycles power plants must be able to accomplish routinely over decades of operation.

Apples and Oranges

Many power industry professionals see the current debate on the merits of IGCC and PC as being skewed. That’s because it starts by assuming that IGCC can already accomplish everything proponents propose. Meanwhile, much public discussion minimizes what PC already does and will be able to do in the future. In fact, PC is viewed by some as a technology that hasn’t advanced in the past 40 years.

“There’s a double standard in play,” says Nancy Mohn, director of marketing strategy for Alstom. “We know the performance for a range of PC technologies in terms of availability, operating curves and their ability to cycle. If you wanted to build an ultra-supercritical PC, you’d have to prove its availability. Yet with IGCC, we have a lot of environmental, economic and performance projections that are only on paper. We can’t have EPA or a state agency say they are going to select the best available control technology based simply on projections.”

She says some people seem to forget how fast improvements take place once markets start to emerge. As proof, she points to the first SO2 scrubbers. “They had 12 modules, and six of them were spares,” she says. “Now we see entire systems contained in a single tower.” Likewise, the industry is seeing some potential for post-combustion CO2 capture using advanced amines and alternative sorbents such as ammonia. “Ammonia costs one tenth what monoethanolomine (MEA) solvent costs and promises to use less power for regeneration.”

But Mohn sees situations where IGCC makes sense. “You’re somewhere next to a refinery and you can sell them some of your syngas and they can make it into product. You can sell them your waste products because otherwise you just pile the sulfur out on the ground. And maybe you have petcoke that can be gasified easily and quickly.”

She believes the best thing for the power industry will be to get three or four IGCC units built that address the concerns of utility operation. “Then stand back and let’s see what the real numbers and performance are.”

A Red Herring?

One of IGCC’s biggest selling points is its inherent ability to capture CO2 before combustion. But is that really something the technology should hang its hat on?

Mohn doesn’t think so. “If someone wants to strip out CO2 from an 800 MW PC plant today, probably the only technology you could buy to do it would be an MEA amine system. But IGCCs don’t capture CO2 unless you add some significant components.”

That’s because syngas produced by a gasifier and sent to the turbine is made up primarily of hydrogen and carbon monoxide (CO). To capture the CO2 prior to combustion, the CO must be converted to CO2. That is accomplished by a shift reactor that takes the hydrogen, carbon monoxide and water and makes more hydrogen and CO2. Then, when the CO2 is captured and removed from the stream, the remaining gas fed to the turbine is almost pure hydrogen. Conventional gas turbines generally can’t operate on hydrogen unless it has been diluted about 50 percent. That would likely mean that if and when the plant has to capture CO2, the turbine would need to be replaced or modified to burn hydrogen.

GE’s gasification general manger Edward Lowe states that GE’s experience includes 28 gas turbines operating with 50 percent and higher hydrogen, even as high as 95 percent. “Hydrogen is a fully acceptable gas turbine fuel when used with an inert diluent as we currently practice with any syngas,” says Lowe. “In an oxygen-blown IGCC plant, nitrogen is produced as a byproduct of the air separation process. GE’s IGCC combustors are designed to use this nitrogen to reduce NOx and to increase turbine output, thus enhancing project economics.”

He says that while it is possible to burn pure hydrogen in a turbine, it is neither practical nor desirable because high flame temperatures will push NOx to high levels. “On a per-pound basis, hydrogen has more than two times the heating value of natural gas and more than 10 times that of typical syngas,” he says, “which will result in lower mass flow and output from the turbine.”

Zurczak says most Burns & McDonnell clients looking at IGCC want to know how an IGCC should be designed for future CO2 capture and what that entails. Presently, the answer is not all that clear. He says that to benefit from incentives provided by the Energy Policy Act and be prepared for potential carbon legislation, the plant must be CO2 capture-capable. “There’s potential for a lot of interpretation as to just what that means,” he says. “It may not be simply a matter of leaving space for the addition of a shift reactor and a CO2 absorber and stripper.”

Grounding CO2

If CO2 capture and sequestration is ever mandated, sequestering may well mean putting it into the ground. A potential economic advantage is to inject it where it will enhance oil recovery. Some oil and gas producers are already doing this. But in order to inject CO2 on a massive scale, some complex issues must be resolved.

“The reality is nobody is really looking at capturing CO2 on either IGCC or PC projects today because we have some work to do on sequestration,” says Mohn. “We have to get the protocols, the legal structure, the ownership and liabilities, and proof of which type of geologic formations are safest. There’s a lot of work to do. And it’s going to take 10 years to get that done.”

During that time, she predicts, significant strides will be made in CO2 capture. “In the last two years we’ve seen more R&D on post-combustion CO2 capture than we’ve seen in the past 30 years, mainly because it looks like there’s a market for it. It’s coming from Fluor and their ECONAMINE process, Mitsubishi and their KS1 and KS2, from PowerSpan with ECO technology and from Alstom. We’re working on several promising technologies, which we’re not ready just yet to announce. But the focus of these is to cut power usage and cost of the solvents.”

That means there’s a good chance PC will be able to capture CO2 post-combustion at least as well as IGCC will be able to precombustion. “And you’ll be able to retrofit the post-combustion systems,” says Mohn. “So if you’re building a supercritical PC today, there’s every reason to believe that 10 or 15 years from now, if you have to start stripping out CO2, you just add a scrubber to do it. And you’ll have suppliers competing with solutions.”

She fears factions within the industry are sniping at each other. “That’s not beneficial or productive for anyone. When we start running numbers and apply it to plants at high elevation, the balance tips toward PC. If it’s close to where someone can use syngas as a feedstock and will pay you for your sulfur or other byproduct, IGCC has the advantage. Today, the decision is largely based on site criteria.”

KCP&L’s Grimwade sees the issue as a debate in which the challenge is getting all the parties working with the same information. “Environmental groups believe IGCC is a technology you can deploy today and has a whole lot more benefits than pulverized coal, because they seem to be comparing it to the pulverized coal plants of the ’60s. At least that’s what’s reflected in the numbers they use to talk about emissions reductions and CO2. They are not comparing it to a new source compliant supercritical unit with all the best control technology on it. If you compare it on that basis and removal of sulfur dioxide, nitrogen oxide, particulates and mercury with the latest mercury technology, you’re not that far off on the deltas. Then when you apply Powder River Basin coal to the heat rate, you’ve really come pretty close. That’s the information that could help form a more productive debate around this topic.”