Air Pollution Control Equipment Services, Coal

Homeland Security from Homeland Coal
U.S. Brownfield Coal-Fired Development

Issue 6 and Volume 106.

By: Steve Blankinship, Associate Editor

More than half of the Nation’s electricity comes from coal, and needed additional capacity is being built to keep the U.S. electricity supply adequately diversified. Most of that new coal-fired capacity is being developed at brownfield sites using a variety of coal technologies.

The 521 MW Reliant Seward plant is reported to be the first merchant plant ever built to use solid fuel. Photo courtesy of Reliant Resources.
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Before being named Director of Homeland Security, Tom Ridge was known for his strong beliefs in energy security too, as evidenced by the aggressive stance on energy matters he espoused as governor of Pennsylvania. That included leading the state toward competitive electricity markets and strongly supporting the development of new generating capacity in Pennsylvania, with a definite emphasis on fuel diversity.

Shortly before getting the call from President George W. Bush to assume the newly created federal position, Ridge took part in a public ceremony illustrating his belief that energy security requires fuel diversity. In June of 2001, Governor Ridge, state and local officials, members of governmental and conservation groups, and executives of Reliant Energy attended the dedication of the $800 million, 521 MW Seward Power Plant in East Wheatfield Township, Pa. Seward is the first major coal plant to be built in Pennsylvania in 20 years.

Yet Seward is but one of more than 2,500 MW of coal capacity in construction, another 4,000 MW nearing construction, and about 18,000 MW in various stages of development tracked by Arlington, Va.-based Energy Ventures Analysis (EVA). Pennsylvania lawmakers aren’t the only ones who realize that new capacity fueled by a stable coal supply is essential to hedge against the inherent price volatility associated with making virtually all new capacity dependent on natural gas. Regulators and lawmakers in Wisconsin, Illinois, Iowa, Kentucky, Wyoming, South Carolina, Louisiana and elsewhere are aggressively promoting diversification with coal.

Overwhelmingly, most of the new coal capacity is being built on brownfield sites – from Arizona Power’s Springerville station in the west to Santee Cooper’s Cross Unit 3 in the east, and from Wisconsin Energy’s Oak Creek plant in the north to NRG’s Big Cajun II in the south. The preference for brownfield development centers on existing permitting coupled with the presence of infrastructure such as rail or barge, water and transmission access. For new coal plants under development, brownfield add-ons such as these four dominate, followed by replacements such as Seward, with greenfield sites such as Peabody’s 1,500 MW Thoroughbred plant in Muhlenberg County, Ky. trailing a distant third, says Seth Schwartz, who tracks coal development for EVA.

Seward’s lifetime fuel supply will be waste coal taken from a 30-mile radius of the plant. Photo courtesy of Reliant Resources.
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In addition, most new coal capacity is being built by regulated utilities or public power entities possessing a solid customer base and benefiting from an all-but-assured cost recovery mechanism. Yet several new players are emerging, including Peabody Energy, EnviroPower, Westmoreland Energy, LS Power and National Energy Group.

Everyone Wins

When it goes on line in May of 2004, Seward’s 521 MW will displace the existing 196 MW of coal capacity at the site, while emitting less sulfur dioxide, nitrogen oxide and particulate. And over its 40-year lifetime, the plant will consume 100 million tons of waste coal that for decades has polluted Pennsylvania’s Kiskiminetas-Conemaugh watersheds.

Each day Seward operates – and with a projected capacity factor of 90 percent that will be just about every day – the plant will be reducing mountains of waste coal from the Pennsylvania landscape, diminishing – and eventually eliminating – a significant source of acid discharge to area rivers. Alkaline ash produced by the plant’s two circulating fluidized bed (CFB) boilers, will be returned to many of the waste-coal sites to neutralize any remaining acids. Seward’s CFB combustion will allow it to burn the waste coal that has accumulated within a 30-mile radius of the plant over nearly a century of heavy industrial activity, including steel manufacturing. General contractor ALSTOM Power designed the plant incorporating its CFB technology.

The waste coal is cheap and the net plant heat rate of 9,700 Btu/kWh compares favorably to plants burning bituminous and anthracite coals. The waste coals in the area will be blended to provide a consistent fuel to the boilers. The average fuel quality is 5,500 Btu/lb, 2.75 percent sulfur and 50 percent ash. Seward will be impervious to the price volatility of natural gas, which in recent years has ranged from less than $2.00/MMBtu to as high as $30.00/MMBtu. That’s because there is at least a 40-year supply of waste coal to fuel Seward. And to top it all off, the plant will reportedly become the first merchant plant ever built to use solid fuel. The plant will dispatch to the Pennsylvania-New Jersey-Maryland market at well below the grid average.

“This is the first solid fuel plant built for the merchant market in the world,” says Reliant Resources’ Mike Proffit, Project Engineering Manager of the Seward Repowering Project “We are not a regulated utility building to serve our own load and do not have a power purchase agreement. This plant was justified with a merchant market. We also believe it is the largest power plant designed to run on 100 percent waste fuel and we expect to do that.”

A super-critical 750 MW fourth unit will be operational at NRG’s Big Cajun II site in Louisiana by 2006, joining the three 575 MW units already at the site. Photo courtesy of NRG.
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Reliant owns about 30 other fossil plants that feed to the Pennsylvania, New Jersey and Maryland (PJM) electrical transmission system, but Proffit says the new Seward unit will have the lowest variable cost of any fossil-fueled plant in the system. “Seward will dispatch before other coal burning plants because we burn low grade, low cost fuel. If we didn’t beat them in dispatch order, we wouldn’t be run at baseload capacity.”

Yet the broad flexibility afforded by CFB technology at Seward is not limited to burning waste coals or other derivative fuels such as petroleum coke. ALSTOM is building a nearly identical CFB unit for East Kentucky Power Cooperative – the 268 MW E.A. Gilbert unit at the H.L. Spurlock Station near Maysville, Ky., where a 500 MW coal unit built in 1981 already operates. There are no design differences between the Seward CFB and the Gilbert unit. Commercial operation for Gilbert is expected in December of 2004.

Craig Johnson, project manager for the Gilbert unit, cites the flexibility afforded by CFB combined with the fact that it is a very clean coal technology as the two main factors for choosing it. Because the plant will burn various bituminous coals from several local Kentucky mines with heating values ranging from 10,215 Btu/lb to 12,502 Btu/lb – and sulfur content ranging from 1.5 percent to 4.5 percent – the CFB boiler will provide Gilbert with greater operating flexibility and efficiency while minimizing SO2 and NOx emissions through the use of in-furnace control techniques. Power from this unit will be sold to the 16 cooperatives that own the project to serve their native load.

The Seward and Gilbert installations will be the first U.S. plants to use ALSTOM’s Flash Dryer Absorber (FDA) system, which integrates several flue gas desulfurization functions into one unit to achieve 90 percent SO2 removal or better, regardless of the sulfur content in the fuel.

Compared to conventional dry FGD systems equipped with rotary atomizers or dual fluid nozzles, the FDA process requires no rotary atomizer with its high-speed machinery, nor are there any dual fluid nozzles requiring compressed air. Power requirements for the FDA recycle/reagent mixers are much lower than for the corresponding items in a conventional dry FGD system.

Other major component providers for Gilbert include GE (turbine/generator), Thermal Engineering and Yuba (condenser and feedwater heaters), Flowserve (boiler feed and condensate pumps), Ecodyne (deaerator), and Gould/ITT (circulating water pumps).

Pulverized Coal Boilers

The good news for the coal-fired power industry goes well beyond CFBs in Pennsylvania, Kentucky and elsewhere. It also includes subcritical and supercritical boiler technology being used to expand and repower coal-fired facilities across the U.S.

MidAmerican Energy Company is building a 750 to 900 MW addition to the Council Bluffs Energy Center in Iowa, site of three existing coal units with a combined capacity of 806 MW. Scheduled for service in 2007, the plant is a direct response to Iowa’s bipartisan effort to encourage construction of new electric generation in the state.

“One of the most critical economic development issues facing Iowa is the availability of affordable electricity for Iowa businesses and consumers,” said Gov. Tom Vilsack. He said MidAmerican’s plans to generate additional electric power in Iowa will have a significant positive impact on Iowa’s economy.

In 1997, Mid American built a railway to provide competitive mine-to-plant access to low-sulfur Powder River Basin coal. Competitive rail access, the existing site infrastructure and a well-trained work force on site, were key factors that played a role in the decision to expand the CBEC site. Project manager Steve Brewer says the company believes the addition of a new coal-fueled facility to MidAmerican’s generation portfolio represents an appropriate balance between the needs of customers and respecting the needs of future generations.

“We currently anticipate utilizing the best available emissions control devices including a cyclone collector or small hot ESP to remove a majority of the particulate, and plan to use an SCR, dry scrubber and baghouse,” he says. The PRB coal will average 8,400 Btu/lb. He notes that MidAmerican presently sells more than 50 percent of the fly ash the company’s plants produce and is looking for a market for the dry scrubber waste the new plant will create.

Wisconsin’s Power the Future

Wisconsin is another state committed to developing more domestic energy for a growing local economy without putting all its eggs in the natural gas basket. Wisconsin Energy’s Power the Future program calls for the addition of 2,800 MW of new capacity, two-thirds of it composed of three new 600 MW coal-fired units at the Oak Creek plant. WE’s generation fuel mix is presently 20 percent nuclear, 60 percent coal and 20 percent gas. Capacity factor for its coal units is currently in the mid-70 percent range. The new units will run at 85 to 90 percent capacity. Natural gas units are used primarily for peaking.

“The fuel diverse solution that we have proposed will save our customers about $8 billion over the 35 to 40 year lifetime of the new plants compared to what the same amount of power would cost if all 2,800 MW were from natural gas,” says WE spokesman Mike John. “And that’s without compromising environmental standards. It’s really a cool opportunity – energy policy and environmental policy in balance – by doing the right things with technology and fuel choice selection.”

Two of the three new 600 MW units will utilize supercritical boilers, chosen primarily because they will emit less carbon dioxide per MW produced than other pulverized coal technology. “We have chosen to go the supercritical route because it’s a mature reliable technology and the only way you can address CO2 is through efficiency,” says Al Mihm, director of engineering for WE Power. “Incrementally, it helps on all emissions,” he says, referring to the impact the high thermal efficiency has on reducing the rate of all stack emissions.

WE’s plan also illustrates a range of coal technologies. The third new 600 MW unit will use gasified coal in a combined-cycle power plant similar to the company’s planned Port Washington natural gas-fired plant. “Integrated gasification combined cycle (IGCC) is a technology that shows great promise,” says Mihm. “Diversity in coal technology goes hand in hand with diversity in fuel type as the cornerstone of our proposal.”


“You will see so much more reference by us in this state to mercury than elsewhere because it is a big issue here,” says John. “It’s entirely possible we’ll see rules set that are more challenging than federal ones and that means we have to be on the forefront of this.”

WE has filed its citing permits to use bituminous coal in its new units. “But we are currently evaluating both bituminous and sub-bituminous because we’ll be very aggressive about removing mercury with our new generation,” says John. EPA has announced it will regulate emissions from coal plants, with final compliance by December 2007.

The choice of coal is significant because of differences in how bituminous and sub-bituminous coals respond to mercury mitigation technologies. “With bituminous coal, the mercury comes out in an oxidized form that’s water soluble,” says Mihm. “Industry data suggest that if you run your flue gas through a baghouse and wet scrubber, you remove, along with the particulate and SO2, 80 to 90 percent of the mercury. With sub-bituminous coal, the mercury comes out of the boiler in an elemental form – as a mercury gas – which is not water-soluble. Therefore, only 5 to 10 percent of the mercury is collected by a baghouse and scrubber.”

Little wonder that WE has become a major test site for one of the leading mercury control technologies. Last summer, the world’s only full-scale mercury removal tests to-date using sub-bituminous coal were run at WE’s Pleasant Prairie coal plant. The tests, conducted by EPA, DOE, EPRI and ADA Environmental Solutions, evaluated activated carbon and other, potentially less expensive sorbents for mercury removal. “Although those test results are preliminary, they give us some confidence than we can continue looking at sub-bituminous coal for our new units,” says Mihm. “Sub-bituminous coals are generally lower in cost and produce a flyash that can be readily used as a cement admixture mitigating any landfill requirements.”

Big Cajun Will Get Bigger

Minneapolis-based NRG is another U.S. company adding a new supercritical coal-fired unit at a brownfield site. Preliminary construction is underway for a 750 MW fourth unit at the Big Cajun II site in New Roads, La. The site already has three 575 MW coal units built between 1980 and 1983. The new Big Cajun unit will become operational in May of 2006. Like the first three Big Cajun II units, Unit 4 will use low-sulfur Powder River Basin coal from Wyoming, averaging about 8,400 Btu/lb and less than 0.5 percent sulfur.

Maintaining fuel diversity and providing lower costs to Louisiana customers are the reasons cited for adding additional coal-capacity in lieu of natural gas capacity, says Alan Williams, vice president of NRG’s south central region. Williams says high efficiency, lower emissions per kWh produced, and improved cycling characteristics are the reasons for choosing a supercritical boiler design.

NRG, in a move consistent with new coal-fired generation being cost competitive in competitive wholesale power markets, is applying for exempt wholesale generator status. “We expect the cost to be very competitive and much less volatile than power generated by gas,” says Williams. “Power sales discussions are ongoing at this time. Some of the power will go to meet load growth of our exiting customers.”

Current environmental limits on the three existing Big Cajun units are 0.50 lb/MMBtu NOx and 1.2 lb/MMBtu SOx. Although Louisiana’s department of air quality has issued new NOx RACT (reasonably available control technology) regulations for the ozone season at 0.21 lb/MMBtu for coal units effective May 2005, the new unit is expected to achieve emission levels of 0.10 lb/MMBtu NOx and SOx. The existing units at Big Cajun are being retrofitted with low-NOx burners and over-fire air.

New Coal Generation will Clean Pennsylvania’s Rivers

For close to 100 years, the Conemaugh River was dead due to the impacts of mining, steel making and other industries in the area. However, in recent years the Conemaugh River has been on the road to recovery. The benefits of the Federal Clean Water Act and the Pennsylvania Clean Streams Law, along with the dedication of local watershed organizations, are showing positive results. Fish and other aquatic life are returning to the river, but a lot of cleanup work remains. One of the remaining major problems are the mountains of waste coal located near the Conemaugh River watershed. Rain hits the piles and seeps through, removing heavy metals and producing a low-pH runoff. Removal of this waste coal will go a long way toward bringing the Conemaugh River watershed back to the pristine conditions of the early 19th century.

“We’re going to benefit the watershed in two ways,” says Reliant’s Proffit. “Number 1, we’re going to burn that waste, so it will be gone. Number 2, when you burn it in a CFB, you mix it with limestone to capture the sulfur. That limestone doesn’t get totally used. So with all the remaining limestone in it when it comes out, you have alkaline bottom ash and fly ash.”

The ash from the process is rated as a beneficial ash by the state of Pennsylvania. He explains that mixing CFB ash with waste fuel at a waste fuel site neutralizes the remaining waste fuel.

Proffit says there are lots of other potential sites for similar projects, but with fuel nearby and existing permits, Seward was the perfect site.

Alkaline ash produced by Seward’s CFB boilers will help clean up area watersheds. Photo courtesy of Reliant Resources
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