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BUSINESS AND TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRY February 2008 • Vol. 152 • No. 2 Vol. 152 No. 2 February 2008 www.powermag.com New long-run record set by 50-year-old TVA unit Alstom builds demo plant for capturing CO 2 Backup generators support the grid Designing future coal plants Alliant sweeps EUCG awards www.powermag.com

Transcript of Powermag200802 Dl

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BUSINESS AND TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRY

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Vol. 152 • No. 2 • February 2008www.powermag.com

New long-run record set by 50-year-old TVA unit

Alstom builds demo plant for capturing CO2

Backup generators support the grid

Designing future coal plants

Alliant sweeps EUCG awards

www.powermag.com

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ONE HITACHI...ONE HITACHI...

BOILERS NUCLEAR SCR TURBINES

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www.hitachi.us/hpsa [email protected] Power Systems America, Ltd. 645 Martinsville Road Basking Ridge, NJ 07920 Tel: 908.605.2800

... vertically integrated to meet yourtotal power and environmental generation needs.

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February 2008 | POWER www.powermag.com 1

Established 1882 • Vol. 152 • No. 2 February 2008

www.powermag.com

On the coverTennessee Valley Authority’s 1,369-MW Shawnee Fossil Plant’s 10 coal-fired units may have been constructed in the early 1950s, but they are far from retirement. The plant’s string of long-run records, recently punctuated by Unit 6’s 1,093-day run, puts the plant in the prime of its life. Photo courtesy TVA

DEPARTMENTS

4 SPEAKING OF POWER

6 GLOBAL MONITOR 6 FutureGen picks Mattoon, Ill. 6 Duke applies for first greenfield COL 7 PPL to work with UniStar on

another COL 7 Areva seeks NRC certification of

its reactor 8 Mitsubishi also in line at the NRC 8 PV project shines in Nevada 8 SunEdison commissions Colorado

PV plant 9 Big concentrating solar plant

proposed 9 Super Boiler celebrates first

anniversary10 Small fuel cell uses JP-8 jet fuel11 POWER digest

12 FOCUS ON O&M12 Survey captures industry’s carbon

concerns12 Sequestering coal plant emissions16 Comparing mercury measurement

methods

20 LEGAL & REGULATORY

56 NEW PRODUCTS

64 COMMENTARY

COVER STORY: COAL PLANT OPERATIONS

22 TVA’s Shawnee Fossil Plant Unit 6 sets new record for continuous operationThis plant is half a century old, but it boasts a string of records and has plenty to teach younger generating plants. We share Shawnee’s top 10 practices for record-setting performance.

SPECIAL REPORT

OPERATIONAL EXCELLENCE

30 Alliant Energy sweeps EUCG Best Performer awardsWe look at how the EUCG determines what makes a best-performing coal plant and at the top-to-bottom elements that helped Alliant’s Lansing Generating Station and Edgewater Generating Station win top honors in the small and large plant categories, respectively.

FEATURES

CARBON CAPTURE

38 Alstom’s chilled ammonia CO2-capture process advances toward commercializationOne advantage of Alstom’s chilled ammonia design for capturing carbon dioxide is that it does not require extremely low levels of SO2 removal from flue gas; if a plant already has a scrubber operating at a 95% removal rate, and its steam system can be reconfigured to accommodate the process steam demand, a chilled ammonia system may be just the ticket.

PLANT DESIGN

42 Accelerating the deployment of cleaner coal plantsCoalFleet for Tomorrow—an EPRI-sponsored collaboration—is helping early adopt-ers of new technologies avoid some of the pitfalls of pushing the leading edge.

BENCHMARKING

46 Who’s doing coal plant maintenance?How many people does it take to change a lightbulb or repair a boiler tube in a coal plant? Are those folks in-house maintenance staff or contractors? A new EUCG sur-vey has the answers.

GAS PIPELINE SAFETY

51 The case for cathodic protectionAny plant that uses even a small amount of gas—for any purpose—faces the po-tential for a gas explosion. This article presents an overview of the problem and an introduction to cathodic protection systems used to keep gas pipelines from corrod-ing and exploding.

DISTRIBUTED GENERATION

53 Aggregated backup generators help support San Diego gridManaging demand response capacity is fast becoming an essential tool for avoiding brownouts and blackouts—without incurring the costs and hassles of building new generation. Here’s how one company, EnerNOC, aggregates distributed generation assets and remotely controls their dispatch for San Diego Gas & Electric.

PWPowerMagazine_Ad_Feb08_rev1_6.indd 1 1/16/2008 9:49:38 AM

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www.powermag.com POWER | February 20082

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www.powermag.com POWER | February 20084

SPEAKING OF POWER

U.S. a paper tiger in nuclear power

I was talking with a utility executive the other day about his recent vacation in India. It’s certainly not your usual holiday destination, but he’s the adventurous type, eager to mingle

with different cultures and sample their cuisine. The exec did a lot more than tour the Taj Mahal and get a glimpse of endan-gered tigers; he went where real people live and work.

Some years ago, I also had the opportunity to visit India dur-ing construction of a power plant by my employer at the time. My experiences were somewhat different; they included a near-fatal collision with an overloaded gravel truck that is nearly as memo-rable as the six months it took me to recover from “Mahatma’s revenge.” The executive’s visit and mine to the same country were unforgettable, but for different reasons.

Foreign-flavored renaissance The international adoption of nuclear power can be likened to those widely different experiences—it has either left countries forever changed or has been an experience best forgotten. If Americans look beyond their insular society, they’ll see that most of the adopters now rely heavily on fission to power their econo-mies. But a few remain hostage to the past and refuse to recog-nize the advances in technology and safety that make the next generation of nuclear plants so attractive. Focusing only on the past is shortsighted—we must expand our views of the industry and of the world around us. As with visiting a foreign country, perspective comes from both experience and attitude.

The latest International Atomic Energy Agency report—En-ergy, Electricity and Nuclear Power Estimates for the Period up to 2030—reveals the degree to which the world beyond the U.S. is newly embracing nuclear power. The report projects firm growth of 77 GW between now and 2030 for plants that are under con-struction or firmly committed. “Promising” projects push the prediction up to 300 GW.

The report notes that since 1986, worldwide nuclear generation capacity has remained essentially constant at around 371 GW, or about 15% of total global electricity production. For comparison purposes, the U.S. figure is about 20% of capacity, provided by 104 nuclear plants with a cumulative rating of 100 GW. The top five list is rounded out by France’s 59 plants (63 GW), Japan’s 55 (48 GW), Russia’s 31 (22 GW), and Korea’s 20 (17 GW). Today, 30 different countries have nuclear power plants.

Here’s where the data get interesting. At the end of November 2007, there were 435 operating nuclear plants worldwide, with 27 units in the works (ignoring two Russian floating nuclear plants of 30-MW capacity). The locations of those plants are enlightening:

■ Russia, with three plants under construction, plans to signifi-cantly increase its nuclear power output.

■ India has seven plants under construction and hopes to in-crease its fleet capacity eight-fold by 2022.

■ China is installing four reactors and has announced plans to quintuple its nuclear power production by 2020.

■ Japan, with just one reactor under construction, still wants to increase nuclear’s share of its capacity mix from 30% to 40% over the next decade.

■ Korea completed one reactor in 2006 and has three more un-der way.

■ Europe’s schizophrenic approach to nuclear hasn’t stopped the construction of six new reactors. Nuclear power is now banned in Austria, Italy, Denmark, and Ireland; Germany and Belgium say they intend to phase out their programs.

■ The remainder of the new units include one in France, one in Pakistan, and the resumption of construction of Watts Bar 2 in Tennessee.

Behind the power curveThe trend should be abundantly clear: Most of the growth in the nuclear power industry is already under way in India, Asia, and Russia, and those countries have made firm commitments for more in the future. The G8 countries represent 65% of the world’s economy but are home to only six of the 27 units currently under construction, including Watts Bar 2.

There’s no denying that the drumbeat for nuclear power in the U.S. is louder today than it has been in a quarter-century. In the past month alone, Duke Energy and PPL have announced their interest in building new plants, joining a half-dozen other utili-ties, while Areva and Mitsubishi submitted their reactor designs to the Nuclear Regulatory Commission for certification. Those two new designs join the Westinghouse/Toshiba AP-1000 and GE’s advanced boiling water reactor and economic simplified boiling water reactor designs, which are already approved and being marketed.

The UK also wants to refresh its nuclear capability, given that most of the country’s 19 reactors are due for retirement within the next 15 years. Prime Minister John Hutton said in a Janu-ary address to Parliament, “I invite energy companies to bring forward plans to build and operate new nuclear power stations.” If the Brits complete their first plant by 2020, the UK’s program will then be several years behind America’s.

Attitude mattersI recognize that little can be done today to accelerate U.S. nu-clear plant expansion plans. However, what I suggest is that Americans, as a nation, recognize that development of a robust nuclear power infrastructure is vital to the country’s future eco-nomic well-being. Understanding that need will require a change in attitude.

Russia, China, and India have made nuclear power a national priority and are pouring concrete and fabricating steel this very minute. Meanwhile, the U.S. is generating only mountains of paper. Unlike those Bengal tigers my executive buddy recently saw in India, we can offer only paper tigers. ■

—Dr. Robert Peltier, PEEditor-in-Chief

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23,800Personnel

32Countries

84Offi ces

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www.powermag.com POWER | February 20086

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FutureGen picks Mattoon, Ill.In mid-December, members of the Future-Gen for Illinois taskforce, elected offi-cials, local residents, and Governor Rod R. Blagojevich (D) celebrated the FutureGen Industrial Alliance’s decision to build the first near-zero-emissions coal-fired power plant in their state. Mattoon, a town of 18,000 about 180 miles south of Chicago, in the heart of southern Illinois’ coal belt, was the unanimous choice of the Alliance’s board of directors. It edged out Tuscola, Ill., and the Texas towns of Jewett and Odessa to secure the coveted $1.5 billion project.

Announcement of the final site followed more than four years of extensive plan-ning and preparation in Illinois and came nearly five years after President Bush first announced the project (Figure 1). The FutureGen Alliance is a nonprofit organi-zation of utilities and coal companies that is partnering with the Department of En-ergy to design and build the project.

FutureGen will take the form of a near-zero-emissions, integrated gasification combined-cycle (IGCC) power plant that will capture 90% of its CO2 emissions and sequester them in geological formations more than one mile underground. The Mt. Simon Sandstone, as it’s known, is a sa-line reservoir underlying most of the Il-linois Basin that has served as a natural gas reservoir, and scientists expect it will work well to store CO2 as well. The possi-bility of on-site injection at Mattoon was likely a key factor in its selection. Alliance officials said the on-site sequestration would both simplify operations and help with public education because visitors to FutureGen could just “step out the back door of the plant” to see where its CO2 is going.

“We are thrilled that Illinois will be home to FutureGen,” said Gov. Blagojev-ich at the announcement in the nation’s capital. “This decision represents the culmination of years of hard work and dedication, and we are honored that the FutureGen Alliance and the U.S. Depart-ment of Energy have entrusted us with this groundbreaking project. FutureGen’s near zero-emissions coal-gasification technology holds great promise to revolu-tionize our nation’s coal industry and en-sure that coal continues to be an integral part of our energy future while reducing the greenhouse gases that cause climate change. As the entire world watches, Il-linois is ready to get to work to ensure that FutureGen is a success.”

The site selection occurred during a period of apparent tension between the Alliance and the DOE, which would like Al-liance members to shoulder more of the project’s growing development costs. The DOE included in its FY 2008 research bud-get request for the Office of Fossil Energy proposed legislative language that would change FutureGen’s current cost-sharing formula. The current formula calls for tax-payers and industry to pay 74% and 26% of the project’s costs, respectively.

In a December 2007 statement, James A. Slutz, the DOE’s acting principal deputy assistant secretary for fossil energy, said, “As [the DOE] has discussed with the FutureGen Alliance for the past several months, projected cost overruns require a reassessment of FutureGen’s design. This will require restructuring FutureGen to maximize the role of private-sector in-novation, facilitate the most productive public-private partnership, and prevent further cost escalation.”

When President Bush unveiled the FutureGen proposal in 2003, the DOE es-timated the plant would cost $950 mil-lion. The estimate has since risen to $1.5 billion, driven by sharp increases in the cost of steel and other essential construc-tion components. Cost inflation also has wreaked havoc on private-sector proposals to build commercial IGCC plants. Michael Mudd, CEO of the FutureGen Alliance, noted that “Sticker shock . . . has been a very difficult hurdle [for private IGCC projects].”

Construction of the FutureGen plant is expected to begin in 2010, with full-scale operations commencing in 2013.

Duke applies for first greenfield COL Duke Energy has submitted to the Nuclear Regulatory Commission (NRC) an appli-cation for a combined construction and operating license (COL) for a new nuclear plant in Cherokee County, S.C. The pro-posed two-unit William States Lee III Nuclear Station would get its generating capacity of 2,234 MW from Westinghouse AP1000 pressurized water reactors.

Duke’s application would reference Ten-nessee Valley Authority’s October applica-tion to build and operate two units of the same design at its unfinished Bellefonte Nuclear Plant site in Alabama (POWER, December 2007, p. 6), theoretically ac-celerating the approval process (Figure 2). The project is expected to be completed by 2017.

“Submitting this COL application to the NRC is an important step for our cus-tomers and company,” said Brew Barron, Duke Energy’s chief nuclear officer. “[It] allows us to move forward in keeping the new nuclear generation option available [to help meet] the growing energy needs of the Carolinas.” Duke Energy Carolinas expects its capacity needs to increase by 10,700 MW by 2027.

Duke Energy is the fourth company to submit an application to the NRC under the revised COL licensing process, but its filing is the first for a greenfield site.

1. FutureGen finds a home. The

FutureGen Alliance has selected Mattoon,

Ill., as the site for the world’s first near-zero-

emissions coal-fired power plant, shown

here as an artist’s conception. Source: DOE

Decision to developCOL application

Decision to submitCOL application

Preparation ofCOL application

NRC reviewand hearing

Plant construction and start-up

2005 2006 2007 2008 2009 2010

2011 2012 2013 2014 2015 2016

Full power operations

2. Nuclear timeline. Duke Energy has

submitted a COL application to the NRC for

the William States Lee III Nuclear Station,

which would be the first new greenfield proj-

ect of its kind in the U.S. in decades. The proj-

ect schedule calls for commercial operation

to begin in 2017. Source: Duke Energy

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In addition to submitting the COL, Duke Energy is pursuing expanded de-mand-side management and energy-effi-ciency programs, an 800-MW coal unit at Cliffside Steam Station in North Carolina, and licensing and permitting of new com-bined-cycle peaking units at the Buck and Dan River steam stations in North Carolina. It’s also evaluating options for building and acquiring renewable-fueled and other near- and long-term generating resources to meet its customers’ needs well into the future.

PPL to work with UniStar on another COLPPL Corp.’s Nuclear Development LLC sub-sidiary will partner with UniStar Nuclear Energy to develop a COL application for a new nuclear reactor on a site adjacent to the Susquehanna Nuclear Power Plant (Figure 3) near Berwick, Pa.

Susquehanna is a two-unit, 2,360-MW plant that is operated by PPL Susquehan-

na and jointly owned by it and Allegheny Electric Cooperative Inc. A PPL spokesman said the company has already begun boring and testing at the site, and that it is the “most likely” location for a new reactor, al-though alternatives have been identified. Though PPL says it has not yet decided to move forward with construction, it plans to apply for a COL for the Berwick site in the fourth quarter of 2008, in time for the plant to qualify for production tax credits under the U.S. Energy Policy Act of 2005.

The yet-unnamed reactor would use evolutionary pressurized water reactor (EPR) technology developed by the French firm Areva. The announcement adds mo-mentum to UniStar’s plan to build a fleet of at least four EPRs, each rated at 1,600 MW, in the U.S. by 2015. In November, the company—a joint venture of Constellation Energy and Electricité de France, France’s state-owned electric utility—announced it had chosen Alstom to supply the reac-tors’ turbine generators.

As it develops the COL application for Berwick with UniStar, PPL is actively seeking partners to build the plant. “[We] would not undertake nuclear construction alone,” said William Spence, PPL Corp.’s chief operating officer. “Because of the large capital commitment required, we would [do so] only as part of some type of joint venture arrangement.” Spence added that PPL is now “in talks” with Areva about the possibility of such an arrangement.

Areva seeks NRC certification of its reactorIn mid-December, Areva applied for NRC certification of its evolutionary pressur-ized water reactor (EPR) design. The ap-plication is ahead of schedule, making it more likely that the company will be able to meet its goal of deploying at least four reactors of that type in the U.S by 2015.

“By building on our considerable li-censing experience in the U.S. as well as that gained through the detailed licens-ing processes in Finland and France, we have prepared what we believe is the most thorough design certification application the NRC has received to date,” said Tom Christopher, president and CEO of Areva NP Inc. “We were able to achieve a high level of detail and confidence in the design ap-plication because of the completeness of the global EPR design now under construc-tion, and by working directly with a large and highly respected energy company, Constellation Energy. We look forward to a timely NRC review and continued success for the EPR in the U.S.”

The EPR is the only reactor technology in the industry’s Generation III+ design category currently under construction anywhere in the world (Figure 4). Safety-grade construction of the first Areva EPR began in Finland in 2005, and another re-actor broke ground in 2007 in France. The

3. Expanded nuclear family? By the end of this year, PPL Corp. and UniStar Nuclear

expect to develop and submit to the NRC an application to build and operate a reactor based

on Areva technology on a site adjacent to the Susquehanna Nuclear Power Plant in Pennsylva-

nia. Courtesy: PPL Corp.

4. Coming to America? Areva has

applied for NRC certification of its evolution-

ary pressurized water reactor (EPR) design.

Shown is an EPR-based plant under con-

struction at TVO’s Olkiluoto site in Finland that

has an estimated start-up date of 2011. Cour-tesy: Areva NP

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POWER | February 20088

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EPR has begun the prelicensing phase in the UK, so the NRC’s certification of the design would authorize its use in a fourth country. The fifth licensing process will occur in China, where a contract for two EPRs was signed in November as part of the big-gest deal ever in the history of nuclear power.

Areva’s application for NRC certification of the EPR design comprises 12,000 pages of documentation prepared by a project team of 325 engineers and 55 support staff. To ensure an effi-cient and timely review of the application, Areva began official discussions with the NRC in January 2005. Dozens of technical exchanges and planning meetings with the agency followed the initial meeting; during them, Areva provided topical reports and supporting materials in the hope of obtaining early approval of some parts of the design.

Mitsubishi also in line at the NRCMitsubishi Heavy Industries (MHI) has applied to the NRC for certification of its U.S.-advanced pressurized water reactor (US-APWR), a 1,700-MW design that the Japanese company hopes to deploy in the U.S.

Last year, TXU Energy (now Luminant), the Dallas-based elec-tric utility, signed a deal with MHI to use the US-APWR design for two new reactors it is considering building at its Comanche Peak plant in Glen Rose, Texas.

PV project shines in NevadaOn December 17, 2007, the U.S. Air Force celebrated the comple-tion of North America’s largest photovoltaic (PV) system at Nellis Air Force Base in northeast Las Vegas. A joint venture of MMA

Renewable Ventures LLC, SunPower Corp., and Nevada Power Co., the 14-MW project (Figure 5) supplies about 25% of the power used by the base and its population of 12,000.

Covering 140 acres of land at the western edge of the base, the system comprises 72,000 solar panels that use SunPower’s proprietary single-axis Tracker T20 technology to follow the sun throughout the day. According to the company, the technology delivers up to 30% more energy than traditional fixed-tilt ground systems.

MMA Renewable Ventures financed and operates the plant and will sell its output to the base under a guaranteed fixed-rate con-tract for the next 20 years. Nevada Power supports the project by purchasing the renewable energy credits it generates.

“This solar project at Nellis is a first step of many toward making renewable electricity integral to [our] operations,” said William Anderson, assistant secretary of U.S. Air Force Instal-lations, Environment, and Logistics. “As the largest consumer of energy in the federal government, the Air Force is well-posi-tioned to promote both solar technology and new approaches to its implementation. This pioneering initiative is a good ex-ample of how a creative approach to public-private partnership can make our energy supply more sustainable, more secure, and more affordable.”

“The best way to secure a healthy and prosperous economy is to develop our affordable, reliable local resources,” added Nevada Governor Jim Gibbons. “With these 14 megawatts, Nellis Air Force Base is leading the country in solar energy deployment, a move that is good for the environment and our nation’s energy security alike.”

SunEdison commissions Colorado PV plantIn late December, SunEdison announced the start-up of another PV plant, its 8.22-MW facility in Alamosa, Colo., ahead of sched-ule. The facility—the largest solar PV plant in the U.S. support-ing substation loads for a major public utility—is expected to generate about 17,000 MWh annually. The solar plant was fi-nanced and built and will be maintained by SunEdison pursuant to an agreement with Xcel Energy under which the utility will buy both the plant’s output and the renewable energy credits it generates for the next 20 years.

The plant, on an 80-acre site near an Xcel substation, is no-table for its use of three distinct types of solar technologies: a

5. Air Force goes solar. These photovoltaic panels at Nellis Air

Force Base use tracking devices to keep them pointed toward the sun

throughout the day. Tilted toward the south, each set of panels rotates

around a central bar. Courtesy: Nellis Air Force Base

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single-axis tracking array, a fixed-mount array, and a dual-axis tracking array with PV concentrator technology.

According to Karen Hyde, VP of resource planning and acquisition at Xcel Energy, “This is a unique facility—three types of solar technologies have been deployed in parallel. Performance monitoring will al-low us to study the system’s performance and evaluate the relative benefits of each technology over the system’s expected 20-year lifespan.”

Big concentrating solar plant proposedA consortium of southwestern electric utilities has issued a request for proposals (RFP) by developers to build a large (100-MW to 250-MW) solar thermal power plant in Nevada or Arizona by 2012.

Members of the Southwest Energy Ser-vice Provider’s Consortium for Solar Devel-opment would buy all of the plant’s output. Bids are due March 19 of this year. The con-sortium consists of Arizona Electric Power Cooperative, Arizona Public Service Co. (the group’s coordinator), Southern California Public Power Authority, Salt River Project, Tucson Electric Power, and Xcel Energy.

The RFP specifies that the plant must employ concentrating solar power tech-nology like that used by Acciona Solar Power’s 64-MW Solar One project, which recently came on-line in southern Nevada (POWER, December 2007, p. 40). It also states that projects including thermal energy storage will be given preference. More information is available at www.aps.com.

Super Boiler celebrates first anniversaryAn industrial boiler that operates at 94% thermal efficiency and produces fewer emissions than conventional boilers has operated successfully for a full year, pro-ducing high-pressure steam for a manu-facturer of rubber parts. DOE officials attended the first birthday party for the “Super Boiler” (Figure 6) on November 30 at Specification Rubber Products Inc. in Alabaster, Ala.

Since 2000, the DOE’s Industrial Tech-nologies Program has subsidized the basic research that led to the Super Boiler to the tune of $4.2 million. The unit itself was developed by the Gas Technology Institute and its partner, Cleaver-Brooks Inc.

The boiler geometry incorporates a two-stage firetube design that is both compact and very efficient. Key innovations (Figure 7) include a transport membrane condens-er (TMC), a humidifying air heater (HAH)

6. Happy birthday. The DOE-spon-

sored Super Boiler, developed by the Gas

Technology Institute and Cleaver-Brooks Inc.,

recently completed its first year of service,

racking up more than 6,000 hours of opera-

tion at a thermal efficiency approaching 94%. Courtesy: DOE

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POWER | February 200810

GLOBAL MONITOR

that extracts sensible and latent heat from the boiler’s flue gas, compact convective zones with intensive heat transfer, and

a staged/intercooled combustion system that minimizes emissions.

The boiler at Specification Rubber Prod-

ucts is a single-stage, 300-hp, gas-fired TMC/HAH boiler that has been running 24 hours a day, five days a week with promis-ing results. After more than 6,000 hours of operation, its efficiency converting fuel to steam has consistently been in the 93% to 94% range, producing annual gas savings of nearly 13%.

The Super Boiler’s unique design, which incorporates high-intensity heat transfer using extended-surface firetubes, has ex-hibited heat transfer coefficients about 18 times greater than those of boilers using plain firetubes. In laboratory tests, the technology reduced NOx emissions to as low as 3 ppm while maintaining CO lev-els below 10 ppm across the firing range. Maintaining excess-air levels at 3% or lower has delivered better efficiency than low-NOx burners that employ flue gas re-circulation or high amounts of excess air.

With one year of successful operation under the Super Boiler’s belt, the next step in its evolution is further testing. New hosts will be the fruit-juice maker Clement Pappas & Co. (Ontario, Calif.) and Third Dimension Inc. (West Jordan, Utah), a manufacturer of boxes and packaging. Steam generation typically accounts for about one-third of the energy used by manufacturers.

Small fuel cell uses JP-8 jet fuelTwo core technologies developed at the DOE’s Pacific Northwest National Laboratory (PNNL)—a fuel desulfurization system and a fuel reforming system—were instrumen-tal in the demonstration of a 5-kW fuel cell running on JP-8, a popular military fuel.

Portable fuel cell power units are qui-eter, cleaner, more reliable, easy to main-tain, and up to three times more efficient than internal combustion engines such as diesels. But they are challenged by JP-8 fuel’s high sulfur content. The fuel desul-furization and reforming systems devel-

JP-8Desulfurization

unit

Cleanfuel

Fuelprocessor

H2 Fuelcell

stack

O2 from normal air

Balance of plantH2O

Water

8. Stand up and salute. Converting

JP-8 fuel to hydrogen for use by an onboard

fuel cell has many potential applications, es-

pecially in the military. Source: PNNL

Steam

Fuel Primaryfurnace

Interstagecooling

pass

Secondaryfurnace

Convectivepass

HPeconomizer

LPeconomizer

Transportmembranecondenser

Water

Flue gas

Deaerator

Preheated humidified air

Humidifyingair heater Air

7. Saving Btus. The Super Boiler’s unique flow path improves its combustion efficiency. Source: DOE

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GLOBAL MONITOR

oped at PNNL reduce the sulfur content of JP-8 and generate a hydrogen stream compatible with an integrated fuel cell (Figure 8).

Although they are being developed for military use, the desulfurization and re-forming technologies can be used with different liquid fuels to provide portable power almost anywhere that small size and high performance are important. For example, researchers at PNNL are looking to make the desulfurization technology compatible with diesel fuel.

The fuel cell–centric auxiliary power unit (Figure 9) is modular and can be re-configured for a wide range of uses. Re-searchers envision using the technology to supply auxiliary power and heat for long-haul commercial trucks, which would eliminate the need for and cost of running less-efficient engines while the vehicles are stopped. Battelle, which operates PNNL for the DOE, operated a prototype system demonstrating these technologies during the three-day 2007 Fuel Cell Semi-nar last fall. During the demonstration, an integrated 5-kW electric power system successfully powered area lights and a commercial refrigerator.

The unique catalytic hydrodesulfuriza-tion process developed by PNNL removes sulfur from JP-8 fuel using syngas as the co-reactant in place of hydrogen. Gas-phase operation of the process allows for a significant increase in throughput as well as a decrease in operating pressure compared with conventional technology. The process doesn’t require consumables or periodic regeneration.

POWER digestNews items of interest to power industry professionals.

Oxy-combustion tests show promise. Babcock & Wilcox Power Generation

Group (B&W PGG) has reached a major milestone on the road to commercializing a new technology that could greatly re-duce CO2 emissions from new and existing coal-fired power plants.

B&W PGG became the first in the world to burn coal in full oxygen-combustion mode at a 30-MWt scale during recent test-ing at its Clean Environment Development Facility (CEDF) in Alliance, Ohio. The CEDF operated in full oxygen-coal combustion mode for over 250 hours as it burned more than 500 tons of bituminous coal.

As the name implies, B&W PGG’s oxy-gen-coal combustion process uses oxy-gen, rather than air, to fire coal. Doing so keeps nitrogen out of the process, and as a result its exhaust gas is mostly relatively pure CO2, rather than a mix of nitrogen oxides and other pollutants. Furthermore, the exhaust gas has less volume, is easier to capture, and with further purification is ready for sequestration or injection into wells to enhance oil recovery.

Working closely with B&W PGG on this project was American Air Liquide, which provided the oxygen, engineering, and chemistry expertise related to combus-tion as well as the equipment and sensors needed for safe and efficient handling of the liquefied oxygen used during testing. An Oxy-Coal Combustion Advisory Group representing utility and merchant power generators also actively participated in the testing process.

B&W PGG will continue its oxy-coal combustion research at the CEDF through the second quarter of this year. Next up on the development schedule are tests of the process on subbituminous and Powder River Basin coals and lignite.

B&W PGG is currently seeking inter-ested parties to conduct further oxy-coal combustion testing at a demonstration plant large enough to capture more than a million tons of CO2 annually. The Oxy-Coal Combustion Advisory Group will help B&W PGG evaluate applicants and select a site for this large-scale demonstration.

FERC licenses first wave energy pilot. The Federal Energy Regulatory Commis-sion has issued the first U.S. license for a wave energy plant. It will operate as a pilot project for five years to demonstrate the potential—and work out the technical and environmental kinks—of the technol-ogy, which converts the kinetic energy of waves into electricity.

FERC said the 1-MW Makah Bay Offshore Wave Pilot Project off the shore of north-west Washington will be torn down after five years, as proposed by the developer, Finavera Renewables Inc.

Finavera Renewables’ planned offshore power projects consist of patented wave energy converters based on proven, ma-rine buoy technology. Clusters of these modular devices, called AquaBuOYs, will be moored several miles offshore, where waves are taller than they are close to shore.

The project will consist of four steel buoys, each capable of producing 250 kW by harnessing the up-and-down motion of waves to drive power-generating equip-ment. The power will be sent to shore through a 3.7-mile underwater transmis-sion cable that will be hooked into the distribution system operated by the Clal-lam County Public Utility District.

A cluster of AquaBuOYs would have a low silhouette in the water. Located sever-al miles offshore, the wave power project arrays would be visible enough to allow for safe navigation but would be no more noticeable than a small fleet of fishing boats.

FERC has touted the potential benefits of bringing hydrokinetic projects on-line, saying that they could double the nation’s share of hydro capacity from its current 10% to 20%.

GE shortens turbine start-up time. GE Energy recently introduced a 10-minute start capability for its Frame 7FA gas tur-bines as an expansion of the company’s OpFlex gas turbine technology program.

When equipped with the feature, a 7FA gas turbine would achieve stable combus-tion and be ready for dispatching 10 min-utes after receiving a start signal. During the start-up period, NOx and CO emissions would both be less than 9 ppm. When incorporated into GE’s next-generation Rapid Response combined-cycle power plant design, the feature would reduce the start-up emissions of a 207FA system (two gas turbines and one steam turbine) by as much as 20% and increase starting ef-ficiency by up to 30%. Targeted for 60-Hz markets, the fast start-up feature will be available for simple-cycle applications in 2009 and for combined-cycle operation in late 2010.

“A power company using GE’s Rapid Response combined-cycle power plant de-sign with 10-minute start capability can provide high-efficiency power when it is needed most,” said John Reinker, general manager of GE Energy’s heavy-duty and combined-cycle gas turbine product line. “It is designed for customers who want to extend operation under an emissions cap, are contemplating cyclic duty, or have an opportunity to tap into additional revenue from the ancillary market.” ■

9. Clean and compact. This 5-kW

electric power system incorporates a PNNL-

developed fuel processor. Source: PNNL

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www.powermag.com POWER | February 200812

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FOCUS ON O&MMANAGEMENT

Survey captures industry’s carbon concernsBlack & Veatch recently published 2007 Strategic Directions in the Electric Utility Industry Survey: The Changing Climate in the Electric Utility Industry, which reports the expectations, activities, and plans of energy companies in the North American power industry, based on the responses of nearly 400 executives to the compa-ny’s survey.

A little over one-third of the execs work at investor-owned utilities, and 17% are with munis. Some 45% of re-spondents classified their firm as “other,” a survey category that includes indepen-dent power producers (IPPs), consul-tants, and regulators. Three out of four respondents said they hold an executive or management/supervisory position at their company.

As expected, service reliability was the executives’ top overall concern, with the aging workforce problem in second place. Environmental issues took the third spot, followed by aging infrastructure. Other reported concerns included security, reg-ulation, and long-term and technology investment.

Some 82% of survey respondents said they believe that global warming is in-deed occurring, and 44% answered that it is caused by human activity. Overall, about 36% of the executives believe global warming is real and caused by human activities. Nearly 35% of respon-dents said they were highly confident about the accuracy of climate change science. But a greater share (42%) said they doubted its usefulness.

“Those were surprising results,” said Richard Rudden, a senior VP and manag-ing director of Black & Veatch, a leading engineering/procurement/construction firm. “They suggest less support for the underlying science than we had ex-pected. The results also underscore the substantial differences in views of global warming between U.S. executives and ex-ecutives of nations that have endorsed the Kyoto Protocol.”

Most expect CO2 controls soonSeventy-two percent of respondents be-lieve that some form of federal CO2 leg-islation will be enacted by 2011. “Given the executives’ expressions of great

uncertainty about the timing and level of carbon caps, and heightened pub-lic awareness of the effects of climate change, one would have expected that percentage to be higher in our 2007 survey than in years past,” said Rudden. “One explanation for the low number is that respondents may have expected some action by Congress on this issue in 2007, which did not occur.”

Asked which type of carbon con-trols they would prefer, 29% of survey respondents said a cap-and-trade sys-tem for CO2 emissions, 14% preferred a straight carbon tax, 8% voted for statu-tory restrictions on physical emissions, and 49% wanted a combination of the three approaches.

Although the reality and cause of cli-mate change continue to be debated, the issue’s higher public profile has led to significant changes in corporate strate-gies and behavior. For example, nearly 20% of respondents said they have de-ferred or canceled a planned coal-fired power project due to uncertainty about carbon regulations. Independent analy-sis by Black & Veatch indicates that plans for 13 coal plants, representing 11 GW of baseload capacity, have been scrapped or delayed over the past year, despite an urgent and growing need for new capacity identified by the DOE and the North American Electric Reliability Corp.

Another interesting survey result: De-spite the wariness of 42% of executives about climate change science, almost 50% of respondents said their organi-zations now publicly acknowledge that global warming is a manmade problem. In addition, 86% expressed confidence that their organizations are doing enough to position themselves as environmentally aware.

The executives said they expect the business costs of cutting carbon caps or paying a carbon tax to be high—al-though not as high as independent es-timates by Black & Veatch. Some 22% of survey respondents believe that the all-in (operating, fuel, and capital) costs of coal-fired generation will increase between 10% and 20% under a carbon-control regime. Many more (62%) expect costs to rise between 21% and 50%. Only 15% of respondents think that comply-ing with carbon regulations will increase their costs by more than 50%.

Where to invest to cut costsBy comparison, independent analyses by Black & Veatch suggest that all-in coal plant costs under carbon controls will rise between 40% and 80%. The specific in-crease for a particular utility or IPP will reflect its carbon-capture technology choices, the size of its plants, and their proximity to suitable sequestration sites.

The top five supply-side technologies that respondents believe should be em-phasized in the future are, in order of preference: nuclear, coal gasification, wind power, carbon capture and seques-tration, and solar power. The ranking cor-relates with the top five environmental concerns reported by respondents: carbon emissions, water supply, mercury control, and emissions of NOx and SOx. Nuclear fuel disposal ranked sixth on the list of environmental concerns, suggesting that the industry is reasonably comfortable with this downside of nuclear power.

This summary of the report barely scratches its surface. To fully appreciate its depth and breadth, download the pdf from www.bv.com/markets/management_consulting/Strategic_Directions_Survey.aspx.

EMISSIONS CONTROL

Sequestering coal plant emissions“Sequester” is an interesting word. Our industry has been using it to describe any way to permanently store the carbon diox-ide produced by fossil-fueled power plants so it no longer contributes to climate change. Various references provide syn-onyms such as “isolate” and “impound.”

However, the first definition of “se-quester” that pops up in the thesaurus of my version of Word is the one that law-yers use: to “confiscate,” or take custody of property belonging to a defendant who may be in contempt of a court until he or she complies with its orders. In the court of public opinion regarding climate change, the coal industry is the defendant and the “property” is the “right” to build a new coal-fired unit. Make no mistake: It is coal-fired electricity production that is already being sequestered. Without a credible plan for managing carbon, new projects are being squelched across the U.S., even in what normally would be considered coal-friendly states.

What became painfully obvious at

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February 2008 | POWER 13

FOCUS ON O&M

Carbon Capture: Status and Outlook—a conference organized and presented by Infocast last December in Washington, D.C.—is this: A defensible, commercial, and financeable solution for capturing and sequestering large volumes of car-bon dioxide is at least a decade—and probably more like 15 years—away. The necessary process technology has not been demonstrated at scale; long-term storage, monitoring, testing, and veri-fication of sequestration sites has not been accomplished for the various geo-logic structures being considered (Figure 1); and, most critically, we’re not even close to a legal framework for permitting and siting such facilities. Without these pieces in place, it’s not worthwhile dwell-ing on the exorbitant costs of stripping CO2 from flue gas, storing it underground, and monitoring a site forever, or at least for a very long time.

To give you an idea of the volumes we’re talking about, a large coal-fired plant discharges 6 million tons of CO2 an-nually. According to one estimate given at the meeting, the total from 800 coal plants would be twice the volume of oil transported in the U.S. For this reason, one speaker—Bill Martin of Atlantic En-ergy Ventures LLC—said we need a “CO2 superhighway” to service many plants. Imagining the necessary infrastructure boggles the mind.

The technical issuesSpeakers who addressed process technol-ogy, engineering, and construction issues drove home some important points:

■ Mark Langford of Kiewit Industrial Co. asked, “Is 50% [carbon dioxide] capture without enhanced oil recovery econom-ical?” He answered his own question “no,” but then elaborated by saying that integrated gasification combined-cycle (IGCC) technology alone can’t be made economical on a straight electric-ity-output basis. Later, Tom Lynch of ConocoPhillips said that the costs of IGCC—without carbon capture—calcu-late out to around $3,200/kW for proj-ects today “across the board.”

■ Christopher Wedig of Shaw Group ob-served that a total post-combustion carbon capture and storage (CCS) system has not been demonstrated at commercial scale, and that the cap-ture process impacts most other parts of the power plant design, including the electrical system (large parasitic load), main steam turbine flow (steam is consumed in CO2 absorption), stack

discharge (lower temperature), and plant water balance. “Scale-up,” he said, “is a big risk issue.”

■ Hope Chase, also of Shaw Group, ad-dressed similar issues for in-situ CCS employing oxygen-fired combustion. For this option, total system design

and operation have not been demon-strated. She also noted that operating and feedstock (fuel) flexibilities are “non-trivial” issues.”

Calvin Hartman of Worley Parsons prob-ably summed up the predicament for coal

1. Drilling to store gas. Properly sited, engineered, and managed geological reservoirs

can be expected to retain stored CO2 for hundreds to thousands of years. However, there are

many legal issues remaining for developers of sequestration facilities. Source: EPRI

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POWER | February 200814

best. One year ago, “capture-ready” was the requirement for a coal-fired project to move forward. Not too long after that, 50% capture became a popular target. Today, even that doesn’t sell. Even higher carbon capture levels are being discussed. This is an important trend, said Hartman, because 80% capture is an inflection point. Going from 80% to 90% “triples the amount of equipment,” he said.

The financial and legal issuesCoal’s road forward appeared even more difficult as the meet-ing waded into financial and institutional issues. David Reis-inger of AIG Global Marine & Energy asked a question that was surely dreaded by the audience: Could a CO2 sequestration site be labeled “hazardous” or even a Superfund site? Swaminathan Venkataram of Standard & Poor’s stated that power companies are not the logical entities to be liable for sequestration sites; however, he did not identify who that logical candidate might be. Venkataram also noted that CCS-equipped plants would have to plan for more down time, build in contingent O&M reserves, plan for longer ramp-up times, and expect lower capacity fac-tors. All this “impacts credit quality,” he said.

Another speaker, Martin Smith of Xcel Energy, reviewed his company’s experience trying to develop a 600-MW IGCC project over the past several years in Colorado. The project committed to CCS from the beginning. First, it was 50% capture, a level that would make the IGCC plant’s discharge equivalent to that from a gas-fired combined-cycle plant. Then the target moved to 80% capture. However, the issues moved way beyond the tech-nical. Despite well surveys, seismic analysis, and 3-D geospatial modeling, there is much uncertainly about sequestration—for example, who owns the “pore space” below the surface? Dozens of land owners are involved. Eminent domain issues crop up. Post-closure requirements are not specified. EPA’s designation of Class V wells is not adequate for commercial sequestration. Smith concluded that although Xcel has done the work, it has barely scratched the surface of the problem.

Julio Friedmann of Lawrence Livermore Laboratory advised that, since you cannot ensure the integrity of the storage site, you must select a low-risk site, conduct a thorough site char-acterization, and provide a technical basis for decision-making. There are three major hazards to consider: atmospheric release, groundwater degradation, and deformation of the boundary ma-terial holding the CO2 volumes in place. Operational protocols for sequestration sites are only now being formulated. He also proclaimed that the “window of opportunity” for pairing CCS with enhanced oil recovery (EOR) would close in a few short years.

Not technically ready for prime timeThe good news, if there was any, from the meeting is that CCS is a robust solution to the problem of climate change. Estimates are that it can deal with 15% to 50% of global greenhouse gas emissions. The bad news: The U.S. lags in developing and im-plementing the technology. There are no operational large-scale sequestration facilities, and proposed projects are proceeding with “great uncertainty.” (The Great Plains Gasification Plant in North Dakota does transport large volumes of CO2 several hundred miles to Canada for use in EOR. Recovering power plant CO2 for EOR represents an opportunity for actually selling the material, but it is currently considered a limited opportunity in the U.S. EOR also requires use of very pure CO2.)

A generally accepted definition of a “commercial” technol-ogy for electric utility application (especially one that provides no competitive advantage) is one for which three variations

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FOCUS ON O&M

(or vendor offerings) have been operat-ing for several years at appropriate scale. If that’s the goal, and you consider both that no facilities are operating today and that institutional and legal frame-works are ambiguous at best, it doesn’t take a genius to see that we’re at least a decade away from new coal plants be-ing technically viable in our apparently carbon-constrained future. Most utility executives now believe legislation to ad-dress global warming is inevitable, and several are actively lobbying for such leg-islation sooner rather than later, simply to provide the certainty needed to go for-ward with the business of building new generating capacity.

Still failing the economic testPlacing a firm value on a ton of carbon (either via a cap-and-trade system or a carbon tax) could provide the monetary incentive necessary to accelerate CCS de-velopment. Venkataram reported numbers showing that IGCC with CSS, assuming storage in EOR wells and revenues from CO2 sales, becomes competitive at a $40/ton price for carbon. However, forecasts based on proposed legislative frame-works now before Congress don’t show the carbon markets reaching such a level until 2020. This suggests that CCS won’t be economically competitive for at least another decade, and probably longer.

At that point, of course, the question is whether coal would remain a lower-cost option for electricity generation than nuclear or renewables. Another speaker estimated that CCS would increase capi-tal costs by 30% to 40%, operating costs by 30% to 50%, and bus-bar electricity costs by 30%.

To sum up, America’s most plentiful source of electricity is being not just se-questered, but bound, tied, and gagged, while other options have the freedom to progress forward. In that respect, se-quester is not just an interesting word; it’s a dangerous word.

—Contributed by Jason Makansi, presi-dent of Pearl Street Inc. (www

.pearlstreetinc.com).

MERCURY CONTROL

Comparing mercury measurement methodsThe U.S. EPA has designated mercury a persistent, bio-accumulative, and toxic pollutant and says that a significant por-tion of anthropomorphic (manmade) lev-els of the element in the environment

comes from burning coal. The Great Lakes Initiative (www.epa.gov/osti/gli), a coop-erative effort of the U.S. EPA and Environ-ment Canada, was established to eliminate anthropogenic sources of mercury.

Measuring the mercury content of the coal entering a plant, as well as the mer-cury content of coal combustion residue, can be helpful in the development of a plant’s mercury control strategy. The two

2. Get wet. The Hydra AA mercury analyzer is capable of analyzing four wet-digested

coal samples with differing mercury content. Courtesy: Teledyne Leeman Labs

Argon gas

Gas control

Sample Reductant

Nafion dryer

Atomic absorption cell

Hg lamp

Reference

Pump

Mix coil

Liq/gasseparator

3. Atomic power. A simplified schematic of the Hydra AA. Source: Teledyne Leeman Labs

Parameter Value

Argon flow rate 0.05 liters/min

Peristaltic pump speed 7 milliliters/min

Rinse time 60 seconds

Uptake time 50 seconds

Integration time 20 seconds

Table 1. Key operational para-meters of the Hydra AA mercury analyzer. Source: Teledyne Leeman Labs

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FOCUS ON O&M

commonly used analytical methods for doing so are ASTM D6414-99 (wet diges-tion) and ASTM 6722-01 (thermal decom-position). To compare these approaches, five portions of four coal samples were analyzed by both techniques.

Wet digestionA Hydra AA mercury analyzer (Figure 2) from Teledyne Leeman Labs is well-suited to this method. Figure 3 is a schematic of the instrument; Table 1 lists its key op-erational parameters. The unit can ana-lyze coal samples with differing mercury content. Samples are prepared by placing about 1 gram of each into separate 50-ml polypropylene tubes and then adding 2 ml of 15N HNO3 and 6 ml of 12N HCl. All of the tubes are then held at about 180F for one hour. Next, 36.5 ml of deionized water is added to each tube, followed by 5 ml of 5% KMnO4.

After allowing 10 minutes for oxida-tion, each tube is examined to ensure that there is an excess of oxidant, indi-cated by a purple color. Adding 0.5 ml of 12% NaCl:12% NH2OH removes the excess oxidant and completes the digestion.

Standard or sample solutions are then added to the analyzer’s autosampler. As Figure 3 shows, the unit pumps a 10% so-lution of stannous chloride solution and either the standard or sample into a gas/liquid separator to produce free mercury. The Hydra AA bubbles argon through the liquid mixture; the gas extracts the mer-cury and carries it to the atomic absorp-tion cell (the upper right of Figure 3) for quantification.

Thermal decompositionA Hydra-C direct mercury analyzer, also from Teledyne Leeman Labs, is suitable for running the thermal decomposition analysis and comparing its results to those of the wet digestion method. The instrument and its schematic are shown in Figures 4 and 5, respectively; Table 2 lists its key operational parameters. A feature of the Hydra-C that is important to users at coal-fired plants is its ability to measure the level of mercury in sor-bent traps, as specified by CFR 40, part 75, Appendix K.

Analysis of coal samples begins with the deposition of about 0.5 gm of each sample into the Hydra-C’s combustion furnace. Using four replicates allows measurement of the precision of the thermal decomposition method.

As Figure 5 shows, the principle of the Hydra-C is quite simple. A weighed sample is deposited into a sample boat

and then into the instrument. Oxygen begins to flow over the sample. The de-composition furnace temperature is then increased in two stages: the first increase dries the sample; the second decomposes it. The evolved gases are carried through a heated catalyst to produce free mer-cury while removing halogens, nitrogen oxides, and sulfur oxides. The remaining combustion products, including elemen-tal mercury (Hg0), are swept through a gold amalgamation trap that captures and concentrates the Hg0. After the amalgamation step, the trap is heated to release the mercury into a carrier gas that transports it into an atomic absorp-tion spectrometer.

4. Some like it hot. The Hydra-C analyzer is well-suited for thermal decomposition

mercury measurement. Courtesy: Teledyne Leeman Labs

Sample boat

O2 supplyDecomposition

furnaceCatalystfurnace

Dryingtube

50–900C 600C

Amalgamfurnace

Delay tube

Goldamalgamation

trap

Absorption cells

High sensitivity

Low sensitivity

5. Simple, yet powerful. The basic process executed by the Hydra-C. Source: Teledyne Leeman Labs

Parameter Value

Oxygen flow rate 350 milliliters/min

Dry temperature 570F

Dry time 30 seconds

Decomposition temperature 1,500F

Decomposition time 250 seconds

Catalyst temperature 1,100F

Catalyst delay time 60 seconds

Amalgamator temperature 1,112F

Amalgamator time 20 seconds

Integration time 100 seconds

Table 2. Key operational para-meters of the Hydra-C direct mer-cury analyzer. Source: Teledyne Leeman Labs

Page 20: Powermag200802 Dl

POWER | February 200818

FOCUS ON O&M

Comparing the resultsTable 3 lists the results of the two measurement methods for comparison

purposes. Both methods show similar precision, and their average values are well within confidence limits of the coal

reference materials. Figure 6 compares the average values of the techniques graphically.

Despite the fundamental differences between the wet digestion and the ther-mal decomposition approaches to mer-cury analysis, the two techniques show excellent correlation. The comparative results presented here showed no analyti-cal bias and were well within the tech-niques’ confidence limits.

Practical application notesIt’s interesting to note that thermal de-composition can determine the mercury level in coal at lower concentrations than wet digestion. For coal samples, the wet digestion process results in about a 50-fold dilution of the sample, whereas no dilution occurs with thermal decomposi-tion. What’s more, with thermal decom-position, all of the mercury contained in each sample is collected (that is, precon-centrated) on the amalgam tube before analysis. That helps give the technique its lower detection limits.

The thermal decomposition technique has two additional benefits that some laboratories may appreciate. First, with thermal decomposition, no concentrated mineral acids or strong redox reagents are used. Such chemicals must be handled with care by qualified personnel and with appropriate attention to safety. Second, because the aqueous digestion step is eliminated, no aqueous hazardous waste is produced. Specifically, there are no acidic wastes high in metal content (tin, manganese, sodium, and potassium) re-quiring disposal (Table 4).

For most samples, either technique will suffice, so the choice can depend on practical rather than analytical consider-ations. For many power plant chemistry labs, existing instrumentation or legisla-tive requirements may dictate use of a specific technique.

In some applications, such as process control, minimizing the total time re-quired from sampling to report genera-tion may be the deciding factor. Others may prefer to keep things simple for operators who lack a strong background in chemistry, or to avoid the complex-ity involved in the reduction technique, with its reactive reagents and hazardous waste. Also, if your lab has an interest in 40 CFR, part 75, Appendix K, the thermal decomposition approach may be better-suited to your overall needs. ■

—Contributed by Bruce MacAllister and David Pfeil of Teledyne Leeman Labs

(www.teledyneleeman.com).

Thermal decomposition Wet digestion

No need for sample preparation Better detection limit for water measurements

No hazardous chemicals or waste Standalone or Hydra AA attachment

Analysis takes about 5 minutes/sample Rapid analysis after digestion

Same calibration needed for various matrices Dilutions of high samples possible

Compliant with 40 CFR, part 75, Appendix K

Table 4. Pros and cons to consider when deciding which mercury measurement technique to use. Source: Teledyne Leeman Labs

Hydra-C thermal decomposition analysis of sample replicates

Run 1

Run 2

Run 3

Run 4

Run 5

Average

Std. deviation

Run 1

Run 2

Run 3

Run 4

Run 5

Average

Std. deviation

20025B

81.5

85.0

75.2

79.0

81.3

80.4

3.6

20025B

80.4

77.5

84.1

77.1

75.0

78.8

3.5

20100B

64.5

78.9

73.8

65.2

64.0

69.3

6.7

20100B

76.4

84.9

69.1

70.1

71.0

74.3

6.6

30075B

58.5

56.2

56.5

48.6

51.1

54.2

4.2

30075B

65.6

54.7

46.4

60.0

53.3

56.0

7.2

40150B

ND

ND

ND

ND

ND

NA

40150B

3.1

2.8

2.4

2.5

2.3

2.6

0.3

Notes: NA = not applicable, ND = less than the method’s detection limit.

Hydra AA wet digestion analysis of four samples

Table 3. Summarizing the results of the two measurement methods. Source: Teledyne Leeman Labs

90

80

70

60

50

40

30

20

10

0

Con

cent

rati

on (p

pb)

Wet digestion Thermal decomposition

20025B 20100B 30075B 40150B

Sample

6. Close correlation. A comparison of the average readings produced by the wet

digestion and thermal decomposition methods. Source: Teledyne Leeman Labs

PAN2105_U_Power_Feb.v2.indd 1 1/9/08 3:19:52 PM

Page 21: Powermag200802 Dl

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CIRCLE 11 ON READER SERVICE CARD

Page 22: Powermag200802 Dl

www.powermag.com POWER | February 200820

LEGAL & REGULATORY

Steven F. Greenwald Jeffrey P. Gray

Given a chance to make a positive change in California’s wholesale generation market, the California Public Utili-ties Commission (CPUC) in December opted instead to

maintain the state’s existing “hybrid” market model. That deci-sion will further restrict meaningful opportunities for indepen-dent power producers (IPPs) and increase the likelihood that future generation will consist of utility ratebase projects.

The CPUC presented its decision as an interim measure that supports development of a competitive market that will stimu-late private investment in new generation without the need for long-term power-purchase agreements. However, promoting new utility ratebase generation is the antithesis of a “merchant mod-el” and, notwithstanding the CPUC’s reasoning, will likely inhibit the emergence of a competitive market.

Still ignoring the problemsAs previously discussed in this column, institutional advantages favor utility generation over IPP resources and make the benefits that hybrid markets supposedly offer, at best, illusory (POWER, March 2006). An administrative law judge’s proposed decision recognized this inherent flaw in the California hybrid model and, if adopted, would have prohibited utility-owned projects from participating in utility resource solicitations. But the CPUC com-missioners dismissed this recommendation in favor of protec-tive measures. In particular, a (currently undefined) “code of conduct” prevents the sharing of information between utility personnel responsible for developing utility bids and utility per-sonnel responsible for selecting winning bids.

Restrictions on the sharing of information presuppose that utilities actually develop and construct “utility generation” and do not address fundamental problems of a hybrid market. Recent utility-owned generation projects in California have consisted of facilities added to the utility’s ratebase that were developed and bid into resource solicitations by third parties—circumstances the “code of conduct” would not affect. However, the financial incentive for a utility to select a “turnkey” project over a com-peting IPP power-purchase agreement in a resource solicitation is the same as for projects developed by the utility: an incremen-tal addition to the utility’s ratebase and the attendant ability for shareholders to earn a cost-plus “return” for 30 years or more.

The absence of a rational and transparent methodology for comparing utility-owned generation and IPP power-purchase agreements on an apples-to-apples basis means that the hybrid model provides a utility with ample opportunity to favor proj-ects promising ratebase recovery, irrespective of the cost conse-quences to customers.

If that weren’t enough . . . The CPUC identified five “unique circumstances” in which it will authorize development of utility-owned generation outside of any competitive process. Inviting utilities to acquire new ratebase generation assets that are not subject to competitive

scrutiny simply denies electric consumers the benefits of com-petition. The unique circumstances include mitigating “market power,” developing preferred/renewable resources, expanding existing utility facilities, acquiring “unique” opportunities, and meeting reliability needs. The reasons for allowing utility gen-eration under these circumstances, however, are unconvincing and seem aimed at solving problems that do not exist.

For instance, the CPUC suggests that markets may be inad-equate to ensure that utilities procure sufficient preferred/re-newable resources. Currently, the primary impediments to the successful development of preferred/renewable resources include such “nonmarket” factors as permitting challenges and the lack of adequate transmission—each of which affects utility and IPP proj-ects equally. Given the utilities’ near-monopsony power and their discretion to specify the resources they procure, the development of additional utility generation should be expected—without the opportunity for IPPs to compete in any meaningful manner.

A self-fulfilling prophecyThe perception of an unlevel playing field in the procurement pro-cess is sufficient, by itself, to dampen participation from IPPs and their investors. IPPs will become increasingly reluctant to invest in the development of new generation in California and will migrate to other markets, where the regulatory environment better ensures that projects can compete fairly and be judged on their merits.

To the extent that fewer IPPs participate in California’s hybrid market, the state’s ability to meet reliability requirements and environmental mandates through utility resource solicitations will suffer, creating (in the CPUC’s view) “unique circumstances” that the utilities can use to justify bypassing any competitive process and increasing their own generation. Thus, California utilities will be perversely rewarded for failing to conduct suc-cessful resource solicitations, and competitive procurement will be further inhibited.

Two steps backwardA truly competitive wholesale market encourages private invest-ment in new generation, promotes innovation, lowers prices, and best ensures the timely availability of resources needed to meet reliability requirements and achieve environmental goals. The CPUC has missed an opportunity to advance meaningful com-petition and instead chose to perpetuate an inherently flawed hybrid model. That model further erodes competition by, in ef-fect, encouraging the acquisition of utility ratebase generation outside of even the minimally competitve process offered by the existing hybrid model.

The actions of the CPUC undermine effective competition in the near term and threaten to set back efforts to develop a com-petitive wholesale energy market over the long term. ■

—Steven F. Greenwald ([email protected]) leads Davis Wright Tremaine’s Energy Practice Group. Jeffrey P. Gray (jeffgray

@dwt.com) is a partner in the firm’s Energy Practice Group.

California constrains competition againBy Steven F. Greenwald and Jeffrey P. Gray

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CIRCLE 12 ON READER SERVICE CARD

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www.powermag.com POWER | February 200822

COAL PLANT OPERATIONS

TVA’s Shawnee Fossil Plant Unit 6 sets new record for continuous operationShawnee’s new 1,093-day long-run record is a testament to the plant’s highly

qualified and trained staff, excellent operations and maintenance pro-cesses, and the quality leadership required to keep all the moving parts pointed in the right direction. If running a power plant is a team sport, then the staff of Shawnee are in a league of their own.

By Dr. Robert Peltier, PE

Tennessee Valley Authority’s (TVA)

Shawnee Fossil Plant sits on 2,696

acres on the south bank of the Ohio

River about 10 miles northwest of Paducah,

Kentucky. The plant is a local landmark,

easily recognizable by its 10 original stacks

flanked by two tall stacks stretching 800 feet

into the sky (Figure 1). Its stacks may stand

out in the landscape, but it’s the plant’s op-

erations reputation that’s truly outstanding.

Shawnee, one of 11 TVA coal plants, has a

long history of operations excellence, begin-

ning with its timely completion more than 50

years ago (see sidebar, p. 24). In 2006 alone,

Shawnee generated 9.4 million MWh—its

highest since 1977—while ranking in the top

25% of plants nationwide for lowest cost of

production.

The latest honor accorded Shawnee is the

national continuous operating title won by

Unit 6: 1,093 days, 11 hours, and 24 minutes

when it went off-line on February 15, 2007.

The previous national record of 1,017 days,

2 hours, and 59 minutes was set by First

Energy’s W.H. Sammis Unit 2 in Ohio on

November 14, 2005.

“This phenomenal national achievement

is a tribute to the knowledge, positive atti-

tudes, and commitment by every employee

at Shawnee, and it bolsters TVA’s mission

1. Operations excellence. Shawnee Fossil Plant Unit 6 set a new long-run operations record for a coal-fired power plant of 1,093

days, 11 hours, and 24 minutes. Courtesy: TVA

Page 25: Powermag200802 Dl

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Page 26: Powermag200802 Dl

POWER | February 200824

COAL PLANT OPERATIONS

to provide affordable, reliable power to the

people of the Valley,” said TVA President

and CEO Tom Kilgore.

What makes Shawnee first among equals

is a plant staff of 330 dedicated employees,

each contributing in his or her own way to

the plant’s history of operations excellence.

“We achieved this outstanding milestone as

a result of the knowledge, pride, and passion

of every individual working at the plant,” said

Jeff Parsley, Shawnee plant manager. “This

record reflects the joint efforts of our plant

employees and the support organizations

that continuously work together on improv-

ing plant operations” (Figure 2). Parsley, not

content to rest on the plant’s recent achieve-

ments, went on to note, “I am proud to work

for TVA and of Shawnee’s successful opera-

tions record. Our goal is to continuously im-

prove on these records in the future. That’s

my vision for Shawnee.”

Shawnee is no one-trick pony. The plant

routinely ranks in the top 10% nationally

for availability and reliability, and long runs

extend beyond Unit 6. Unit 2 recently had a

record run of 569 days, Unit 4 ran for 407

Enterprise is where you find itThe March 1, 1954, issue of TIME maga-zine reported on a University of Chicago lecture presented by TVA Chairman Gor-don R. Clapp the previous week in an article titled “The Wrong Horse.” When queried about the cost difference be-tween public works projects constructed by private enterprise and the govern-ment, Clapp pointed to the “race” be-tween TVA and Electric Energy Inc. to supply power for Atomic Energy Commis-sion (AEC) installations in Paducah, Ky.

Electric Energy Inc., a partnership of five privately owned utility firms, con-tracted with the AEC in 1950 to build a power plant at Joppa, Ill., just across the Ohio River from Shawnee (now the 1,086-MW merchant plant Joppa Power Station, 80% owned by Ameren and 20% by Kentucky Utilities). TVA was also con-tracted to build a plant of similar size the same year, and the race was on.

Joppa was scheduled to begin ser-vice three months ahead of Shawnee, and handicappers made Joppa the over-whelming favorite to capture the long-term contract to supply baseload power to the AEC.

Clapp noted in his lecture that “Both TVA and E.E., Inc. suffered from delayed deliveries from equipment manufactur-ers. Both encountered labor difficulties. Both projects missed the completion dates originally scheduled. Trade jour-nals and some of the daily press herald-ed this ‘race.’ . . . After a while, however, the cries of the professional spectators died down. It began to be apparent that the wrong horse was coming in ahead. Two years and three months from the time construction was started, the first unit at TVA’s Shawnee plant was placed in commercial operation, while the smokestacks of Joppa . . . were still clean and cold.”

TIME noted that Clapp ended his lec-ture with a comparison of the costs to construct each facility. “Electric Energy, Inc. had to raise its estimates from $126/kW to $184/kW, while TVA kept well within the original estimate of $147.50/kW. Clapp added, ‘If this story has a moral, perhaps this is it: enter-prise is where you find it.’ ”

2. Culture club. “It takes people, processes, and passion to be successful,” said Jeff Parsley, Shawnee plant manager. “That’s the kind of culture we have here.” Courtesy: TVA

3. Ten in a row. Jeff Parsley confers with Tom Kilgore, TVA president and CEO, on the turbine room floor. Courtesy: TVA

Page 27: Powermag200802 Dl

February 2008 | POWER 25

COAL PLANT OPERATIONS

days, and Unit 5 ran for 522 days. Shawnee

also set a 10-unit continuous-run record in

2006, when it ran all 10 units for 45 con-

secutive days and topped a mark set in 1961.

This is no small feat for a plant completed

in 1957, the last year the Dodgers played at

Ebbets Field in Brooklyn.

Perfect 10Shawnee’s 10 coal-fired generating units

produce about 1,369 net MW by consuming

some 9,600 tons of coal each day. Units 1

through 9 are identical Babcock & Wilcox

wall-fired, pulverized fuel boilers that burn

a blend of low-sulfur coal with low-NOx

burners to limit NOx emissions. Unit 10, the

nation’s first utility-scale atmospheric fluid-

ized-bed combustion boiler, built to test the

technology for sulfur removal, began opera-

tion in 1988. All 10 prime movers are identi-

cal Westinghouse units (Figure 3).

Shawnee is the lowest total production

cost plant in the TVA fossil system and posts

the second-highest net margin in TVA’s fos-

sil fleet. Between 2003 and 2006, Shawnee

experienced the best availability and reliabil-

ity record in the history of the plant (Units 1

to 9), with an EFOR average of 0.82% and an

EAF of 94.6%.

The three PsParsley attributes Shawnee’s success to the

three Ps—people, processes, and passion—

and the plant works hard on all three.

Parsley has spent his entire 28-year career

with TVA at Shawnee, working his way up

from the operator ranks to running Shawnee

for the past five years, so his management

style is informed by real-world experience

and long-term working relationships with

many at the plant. He confessed that his long

experience with Shawnee has been a key in-

fluence on his management style: “With ex-

perience comes credibility, with credibility

comes trust, and with trust comes success.”

Hiring, training, and keeping good people

are perhaps Parsley’s greatest challenges as

plant manager. Shawnee, like many pow-

er stations in the U.S., has been working

through the aging workforce “brain drain”

problem for the past several years. The lead

time for new operators to become productive

is about two years, beginning with a year-

long operator training program followed by

another year of on-the-job training and con-

tinuous mentoring and feedback before op-

erators complete their qualifications.

The key to a smooth workforce transition

is making a commitment to training a new

workforce regardless of actual losses. TVA

has elected to err on the side of having a few

too many operators rather than too few when

long-time employees retire unexpectedly

and leave the plant shorthanded for several

years. Shawnee begins its classes approxi-

mately once a year and staffs them based on

projected retirements and other losses three

years down the road rather than on actual

losses that have occurred. Today, 50% of

Shawnee’s workforce has less than 10 years’

experience.

On the ops side, entry-level requirements

are typically a two-year degree from a com-

munity college or vocational or technical

school or five years of equivalent experience.

History has shown that employees recruited

within a 60-mile radius tend to stay longer

and are quicker to make the transition into

the Shawnee lifestyle and culture.

Shawnee has been able to keep an experi-

enced workforce on the maintenance side. It

brings on board journeymen craft workers as

well as trainees and has been able to main-

tain a first-rate mix of talent.

Attracting the best operations and main-

tenance supervision talent into the manage-

ment ranks also remains a crucial challenge

for plant management. First-line supervisors

usually are promoted from within the opera-

tions or maintenance ranks. However, a top-

notch first-line supervisor may pause before

taking the jump into plant management; de-

veloping and encouraging that raw talent is

the never-ending responsibility of the plant

management team.

Parsley was clear that one of the secrets to

the plant’s recent success has been a manage-

ment team that has served Shawnee a long

time; in fact, there are a fair number of sec-

ond- and third-generation TVA employees at

the plant, testifying to the attractiveness of

Shawnee’s working environment.

Top 10 practicesHigh-performing plants somehow find a

way to stretch a dollar a little further or chal-

lenge employees to do just a bit more. TVA

has invested much in the development of the

Shawnee staff, and the staff have invested

heavily of themselves for many years to

achieve spectacular results. When asked for

the secret of their success, the conversation

inevitably returns to the three Ps and a focus

on executing the details in the plant’s day-to-

day operation. Parsley refers to consistently

executing the basics of “blocking and tack-

ling” rather than going for the more dramatic

end zone toss with seconds left in the game.

So let’s look at those basics.

Have you ever tried to make a list of what

you do every day in your job? So many of

the tasks are automatic and completed with-

out a second thought. Good plant operating

practices should be so institutionalized that

they are not burdensome, make good intui-

tive sense to the staff, have a specific goal

in mind, and can be repeatable with predict-

able results. These 10 essentials, though not

meant to constitute a comprehensive list,

provide insight into the culture of success at

Shawnee. Perhaps they will spark an idea or

two for your plant.

1. Use a systems engineering ap-proach. At Shawnee, each major system

has an engineer assigned to it who is respon-

sible for its health and welfare. The system

engineer is responsible for preparing a daily

status report with key performance metrics

as well as recommending planned and rou-

tine maintenance, determining equipment

overhaul frequency, and providing economic

justifications of upgrades and repairs. That

individual is also the go-to person when

there are any questions or if troubleshooting

is required. Shawnee management believes

this proactive system of monitoring and con-

tinuous system health reporting is critical to

the plant’s success.

2. Plan for outages. A 10-unit plant like

Shawnee will usually have at least one unit in-

volved in an overhaul or maintenance outage

at all times. Shawnee uses a 42-month out-

age cycle, which means two or three units are

Shawnee control room staff enjoy a visit

from Tom Kilgore, TVA president and CEO.

From left to right are Scott Record, unit

operator; Sidney Lovelace, shift opera-

tions supervisor; Tom Kilgore; and Bobby

Gainey, unit operator. Courtesy: TVA

Unit Operator Jeff Cunningham keeps a

sharp eye on unit performance. Courtesy: TVA

Page 28: Powermag200802 Dl

POWER | February 200826

COAL PLANT OPERATIONS

overhauled every year. Detailed outage plan-

ning, completed well in advance, ensures that

all plant staff are prepared to meet the outage

planning milestones. Shawnee has developed

this process into an art form: the team meets

over 95% of the schedule’s outage milestones.

Plant staff fully expect an overhauled unit to

run until the next outage, but typically it will

have 400- to 500-day runs.

3. Document your procedures. During

the early years at Shawnee, staff thought it a

sign of weakness if an operator had to break

out the procedure book. Today the culture

has changed, and using procedures is the

natural order of things. Every critical job

maintenance work package is accompanied

by a set of instructions—peer checks, check-

lists, and step-by-step procedures. Staff

members are also expected to continuously

review the procedure and suggest updates or

changes. The operations manager receives

all completed checklists and constantly up-

dates them as new methods or processes are

identified. Procedures and checklists are all

available on the plant intranet, and emer-

gency operations books are present in every

control room.

4. Focus on good labor relations. Shaw-

nee has seven separate bargaining units at the

plant, yet they have found common ground:

they all agree on excellence in plant mainte-

nance and operations. Plant management be-

lieves that its responsibility is to ensure that

each member of the plant staff is treated as a

team member who, when necessary, will do

the right thing. This atmosphere of trust must

work, as labor problems tend to be minimal at

Shawnee. Everyone who works at Shawnee,

regardless of affiliation, is considered part of

the Shawnee team—including contractors,

vendors, and other temporary TVA employ-

ees—and is treated as such.

5. Improve your water chemistry and predictive maintenance (PdM) pro-grams. Believe it or not, all 10 boilers are

Maintenance Mechanic Tech III Susan

Walden and Maintenance Mechanic Tech III

Eric Shipley work on a sootblower repair.

Courtesy: TVA

Tech Services Analyst Sheryl Wildharber

prepares chemical standards used in boiler

water analysis. Courtesy: TVA

System Engineers Brian Palmer and Randy

Dehart keep an eye on the health and wel-

fare of a steam turbine by running a tur-

bine efficiency test. Courtesy: TVA

4. Safety always comes first. Shawnee completed two million man-hours without a lost-time accident in 2006. Leading that effort is the Shawnee Health and Safety Committee. Front row (L to R): Rick Hubbard, Jennifer McCallon, Rick Stimson, Mary Lynn Spear, and Tim Pace. Back row: Kent Saxon, David Grief, Ronnie Coleman, Joey McCallon, Tony Mangina, Lane Van Winkle, and Ronnie Puckett. Courtesy: TVA

Page 29: Powermag200802 Dl

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So, when you hire a trained UBC

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work, you’ll know the job will get done

right. We have the skills to satisfy your

most demanding customers, and a

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you meet your deadlines. Today’s UBC

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CIRCLE 14 ON READER SERVICE CARD

Page 30: Powermag200802 Dl

POWER | February 200828

still outfitted with the original waterwall

tubes that Babcock & Wilcox erected more

than 50 years ago. Now that’s a testament

to the quality of the plant’s water chemistry

program. The laboratory reports to the prin-

cipal engineer, as do all the system engineers.

The lab includes a strong PdM program rely-

ing on thermography, oil analysis, vibration,

acoustics for detecting pinhole leaks during

any boiler outage, and more to give early

warning of potential equipment problems.

Shawnee has avoided many catastrophic fail-

ures due to the success of its PdM program.

6. Develop a multitasking staff. A good

portion of the maintenance staff is composed

of technicians who have multiple qualifica-

tions, but a cadre of experts will always re-

main. During a typical day shift, four shops

are open at the plant: machine, boiler, elec-

trical, and instrument. The first three shops

have multiskilled techs who cover the range

of crafts expected in a plant. Shawnee also

has a small maintenance staff that rotates

with the operations staff so that techs with

various expertise are also available during the

night shift and weekends. This approach has

significantly reduced night callouts and unit

derates that would normally occur. Mainte-

nance staffs also do their own work on boiler

tubes and pulverizers—chores that are typi-

cally outsourced at other power plants. Find-

ing the best mix of multiskilled technicians

and experts (certified welders, for example)

is a work in progress.

7. Develop a safety culture. Shawnee

had the best safety record in FY07 of all 11

TVA fossil plants, and the plant staff strongly

believe there is a link between a best-perform-

ing plant and a safe plant. OSHA recordables

were 1.0—only two recordable injuries for

a staff of 330 people over the course of the

entire year. The plant staff has a continuous

focus on safety, and every employee has a

high expectation of safety. Shawnee has a

five-year safety plan that moves up a level in

expectations each year. Safety is now part of

the plant’s culture and not just a management

expectation (Figure 4).

8. Manage your time. Shawnee practic-

es careful advance planning of the upcoming

workweek to ensure that the highest-prior-

ity projects are completed. A workweek

management meeting, attended by the vari-

ous foremen and first-line supervisors from

maintenance, operations, and engineering, is

scheduled each Friday at 12:15 p.m. At that

meeting they plan and prioritize the details

of the following week, crew by crew. The

detailed planning loads about 85% of the

available work hours based on work plan-

ning estimates, leaving the remaining hours

for emerging work and unexpected absences.

Shawnee, and TVA as a whole, uses the EPRI

Maintenance Optimization Program (MOP)

for work order planning.

9. Spend your dollars wisely. Capital

investments over the past few years have sig-

nificantly improved the overall material con-

dition of the plant. Those investments have

reinforced the employees’ belief that TVA

is serious about organizational excellence

at all levels. Where those dollars were spent

to improve plant reliability and availability

was guided by input from throughout the

workforce, including engineers and bargain-

ing unit members. Regardless of the amount

of capital spending approved, it’s important

that those dollars are properly invested.

10. Expect success. High expectations

are set for every plant staff member, and

teamwork is put at the top of the list. Man-

agers and employees are put in positions to

succeed. Employees are involved in deci-

sion-making at all levels, including decisions

that concern capital spending priorities. Em-

ployees also are deeply involved in safety

initiatives, the Combined Federal Campaign,

and community involvement projects. The

plant is a community mainstay, and so are its

employees. ■

WANTED:WRITER/EDITOR

TO JOIN THE POWER TEAM

We’re looking for a multitalentedteam member to research and write technically detailed storiestypically related to the designand construction of power plants,plant operations and maintenance,and advanced technology. Thisnew editor may be asked to workon material for the magazines,electronic newsletter, website, and events.

REQUIREMENTS:

Send cover letterand resume [email protected] calls, please.

• BS in engineering, preferably with a PE license and 3 to 5 years’ experience in the power industry, or journalist with proven expertise in writing about the industry. Coal plant and/or combined-cycle O&M experience a plus.

• Outstanding oral and written communication skills.• Obsessive about quality and accuracy.

• Ability to manage multiple projects under tight deadlines.

• Proficient with Microsoft Office programs and willingness to become familiar with other software.

• Ability to work with minimal daily supervision in a virtual team-oriented environment.• Some travel to inspect power plants, attend events, and generally make POWER’s presence known in the industry.

Tech Services Analyst Darren French per-

forms a lube oil analysis as part of the

plant’s extensive predictive maintenance

program. Courtesy: TVAAssistant Unit Operator Todd Douglas re-

cords filter plant readings. Courtesy: TVA

COAL PLANT OPERATIONS

Page 31: Powermag200802 Dl

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Page 32: Powermag200802 Dl

www.powermag.com POWER | February 200830

OPERATIONAL EXCELLENCE

Alliant Energy sweeps EUCG Best Performer awardsThe Fossil Productivity Committee of the EUCG conducts an annual analysis

of its member plants’ operating results and selects the Best Performer in the categories of small and large coal plants. For 2007, Alliant Energy’s Lansing and Edgewater Generating Stations took the top spots—the first time in recent history that a single utility claimed both awards.

By Dr. Robert Peltier, PE

The EUCG (formerly Electric Util-

ity Cost Group) annual Best Performer

awards were presented at the group’s

fall 2007 meeting in Denver, where Alliant

Energy swept the top awards. The three-unit,

328-MW Lansing Generating Station (Fig-

ure 1) was named Best Performer Small Coal

(<250 MW average unit size), and the three-

unit, 803-MW Edgewater Generating Station

(Figure 2) was selected as Best Performer

Large Coal (>250 MW average unit size). Al-

liant Energy’s M.L. Kapp Generating Station

took second place in the Small Coal division.

Approximately 80 coal-fired generating sta-

tions from across the U.S. were benchmarked

for the EUCG’s annual awards program.

To be fair, Lower Colorado River Author-

ity’s Fayette Power Plant finished in a tie

with Edgewater, but because Fayette’s NOx

reduction program was profiled in the May/

June 2007 issue of our sister publication,

COAL POWER (www.coalpowermag-digi-

tal.com), we’re focusing on Alliant Energy’s

corporate- and plant-level approach to man-

aging its aging coal plant assets to achieve

such outstanding results.

POWER has been privileged to publish

findings from a number of EUCG-con-

ducted benchmarking studies over the past

several years; the latest findings (p. TK) are

from the group’s most recent plant mainte-

nance staffing study. But this is the first time

POWER has taken the opportunity to exam-

ine the EUCG’s Best Performer selection

criteria (see sidebar, p. TK) and then discuss

with each winning plant’s staff the key indi-

cators they believe differentiate them from

their peers.

Change agentAlliant Energy serves about a million elec-

tric customers in a territory that covers the

very southern portion of Minnesota, much of

Iowa, and portions of Wisconsin. The com-

pany has 860 employees in the Generation

1. Best of the small. Alliant Energy’s Lansing Generating Station won the EUCG’s Best Performer award in the small coal category at the group’s fall meeting. Courtesy: Alliant Energy

2. Best of the large. Alliant Energy’s Edgewater Generating Station was named the EUCG’s Best Performer in the large coal category. Courtesy: Alliant Energy

Page 33: Powermag200802 Dl

February 2008 | POWER 31

OPERATIONAL EXCELLENCE

Group working at 14 baseload plants; two

new baseload plants are moving through the

permitting process.

Significant management changes occurred

in the Generation Group about 10 years ago

when Tim Bennington, VP generation, began

the slow process of redirecting the organiza-

tion from a utility-centric to a business-cen-

tric one in which modern business practices

were made a requirement rather than a goal.

Bennington named this program Generation

Excellence.

Not all of the “old school” plant managers

were able to make the transition. In fact, all of

the plant managers were eventually replaced

with a new cadre of highly motivated, plant-

savvy folks with good business acumen and

excellent leadership skills. Many in the cur-

rent corps of plant managers were recruited

from outside the Alliant Energy organization

from a diverse group of industries, typically

manufacturing. After all, a power plant is

really a complex manufacturing facility for

electricity, and the required management

skill sets for the two industries are similar.

Today, over 80% of salaried personnel in

the Generation Group have a college degree;

100% is the long-term goal.

Change doesn’t happen unless employees

clearly understand why the new direction is

necessary and what’s in it for them. The Gen-

eration Excellence program is distinguished

by its focus on industry-leading performance

and an empowered workforce. Benning-

ton summarizes Generation Excellence as

a constant commitment to daily operational

excellence as characterized by six specific

ingredients.

Employee safety. Zero accidents is the

goal of every power plant, and Alliant Energy

is no different. But what Alliant does differ-

ently is specifically track and document safe-

ty inspections and suggestions, and record

near-misses so those events can be included

in future safety lessons along with lessons

learned from recordables and lost-time acci-

dents. Housekeeping and safety audits have

become part of the plant culture rather than

optional.

Fiscal and operational excellence. Ac-

cording to Bennington, “fiscal execution is

a key requirement for professional success.”

That means a plant manager at Alliant must

have the skills of both an engineer and a fi-

nancier. Yes, generation results such as heat

rate, forced outage rates, and plant availabil-

ity remain extremely important to Alliant,

as they have been for all plants since Edison

commissioned the first U.S. central power

plant in 1882. But O&M and capital bud-

get management is now equally important

to achieving plant generation goals. A good

plant manager must also adopt best practices

identified by industry benchmarking and

use quality tools such as Six Sigma and lean

management practices. The new generation

of plant manager must be multidisciplined

rather than purely a technical expert.

“We know from benchmarking that our

generating stations are top performers when it

comes to managing costs and operating reli-

ably,” said Ken Wilmot, regional director-gen-

eration. “Operating efficiently by controlling

costs on behalf of our customers is central to

our core values. Our employees continually

How the EUCG selects best performersThe EUCG awards program looks at two periods of performance excellence: a calendar year for the fall awards and a five-year aver-age for the spring awards.

The awards program is entirely data-driven—the plant with the best reliability and lowest O&M costs combined is the winner. However, the details of the calculations reveal the Fossil Produc-tivity Committee’s interest in using very specific metrics when making the calculation.

Reliability analysis. The reliability calculation is based on an equivalent unplanned outage factor (EUOF) that is calculated by the following formula:

EUOF = FOH + EFDH + MOH + EMOH

PHWhere,FOH = forced outage hoursEFDH = equivalent forced derate hoursMOH = maintenance outage hoursEMOH = equivalent maintenance derate hoursPH = period hoursCost analysis. The cost analysis portion of the evaluation

process is unique: it uses a ratio of actual O&M costs compared with those predicted by a regression analysis of the actual O&M

costs experienced by the group. This approach has the effect of minimizing the variances in cost due to capacity factor, net plant generation, and the number of units at a plant, so all plants are placed on an equal footing.

Putting it all together. The analysis is a two-step process. The first regression is used to predict the O&M cost based on a plant capacity factor. An equation of the regression fit to the data is found. Step two is to predict the O&M cost as a function of the EUOF. A plant’s actual O&M costs are then compared with the pre-dicted O&M costs for its EUOF to arrive at a second ranking.

The rankings of each plant are then summed to develop a final placement for the awards standing, and the plant with the low-est score wins. Combining scores from the two evaluation tech-niques allows a plant to win by being best of class in one ranking while scoring well in the second category. Conversely, a plant that scores at the top in one ranking but that lags in the second will be an “also ran” in the final standings.

The final rankings for fall 2007 identified Lansing Generating Station as the Best Performer in the Small Coal category, result-ing from its second place in O&M and fourth place in EUOF. Lower Colorado River Authority’s Fayette Power Plant (#4 in O&M and #3 in EUOF) tied with Alliant Energy’s Edgewater Generating Station (#2 O&M and #5 EUOF) in the Large Coal category.

According to Bennington, “fiscal execution is a key requirement for professional success.” That means a plant manager at Alliant must have the skills of both an engineer and a financier.

Page 34: Powermag200802 Dl

POWER | February 200832

OPERATIONAL EXCELLENCE

look for ways to manage costs while maintain-

ing our high reliability and safety standards.”

Environmental stewardship. Any sig-

nificant environmental mistake today will

reverberate all the way to the board room and

can attract considerable scrutiny from regu-

lators and the press, whether or not a viola-

tion was intentional. Generation Excellence

implemented a system of environmental peer

reviews and audits to ensure regulatory com-

pliance and anticipate potential problems. A

proactive approach to environmental issues

was also introduced that includes the benefi-

cial use of ash to minimize landfill usage and

use of advanced NOx reduction technologies

such as SmartBurn (www.smartburn.com).

Performance goals tied to stakehold-er value. Individual plant operation goals

are now directly linked with monitored op-

erational and commercial availability, O&M

costs, the efficiency of capital investments,

Six Sigma savings, any environmental vio-

lations, and the severity and rate of safety

violations.

Improved asset performance monitor-ing. A plant manager can’t manage what he

can’t monitor. Accurate and timely data is a

key feature of an organization striving to op-

erate using lean management principles. Sig-

nificant investment has been made to improve

standard work practices by using Maximo

at all of Alliant Energy’s plants for manag-

ing preventive and predictive maintenance

programs and hours tracking, and by using

EtaPRO and Thermal Engineering software

tools for thermal performance monitoring.

Alliant’s generating fleet is also migrating to

Maximo 6.2, the new browser-based upgrade

that will link the maintenance management

system more closely to the company’s enter-

prise resource management system.

Workforce planning and engagement. Alliant Energy, like so many other companies

in this industry, is addressing the effects of an

aging workforce on plant operations with a

series of recruiting and retention programs.

The brunt of the impact on Alliant began

last year and is expected to extend through

2011, when the largest projected turnover in

the company’s history will occur. Alliant has

the typical recruitment processes in place for

technical staff and skilled craft labor but has

also focused on hiring skilled management

staff from outside the utility industry—an

unusual approach in what is typically thought

of as a very insular industry. The plant staff

is also more engaged with daily and weekly

planning meetings, during which improve-

ments in operating processes are explored

and best practices are shared among plants.

Lansing—big on performanceWhen one plant wins a performance award

multiple times, it reflects well on plant man-

agement and staff (Figure 3). When multiple

plants from the same company win the same

EUCG annual Best Performer Small Coal

award four years running, it not only reflects

well on the winning plants but also on the en-

tire corporation.

Lansing Generating Station, located south

of the Minnesota border in Iowa, is the fourth

in a succession of Alliant Energy Iowa plants

to take top honors in the small plant category.

In 2006, Alliant Energy’s Sixth Street Gen-

erating station in Cedar Rapids took the title.

In 2005, the award went to Alliant’s Dubuque

Generating Station. The M.L. Kapp Gener-

ating Station in Clinton started the winning

streak in 2004.

A staff of 51 is responsible for operation

and maintenance of the three-unit Lansing

Generating Station. Unit 2, commissioned

in 1948, is a 15-MW unit. Unit 3, added in

1954, is a 38-MW unit, and the 275-MW

Unit 4 was commissioned in 1977. Unit 1

was retired in 2004. Units 2 and 3 boilers and

Units 2 and 3 turbines are on a common 850-

psi header, allowing operation of boilers and

turbines in any combination.

Units 3 and 4 run continuously through-

out the year, so the statistics presented to the

EUCG came from those units. Unit 2, with

boilers 1 and 2, is usually run only during

peak periods in the summer months. Unit 4

burns approximately 2,800 tons of Powder

River Basin (PRB) coal each day, while Unit

3 burns a blend of high-Btu and PRB coals.

Ingram Barge Co. makes about four barge

deliveries of coal to Lansing daily while the

Mississippi River is open, and each barge

carries approximately 1,500 tons of fuel.

Fuel deliveries are highly seasonal: PRB coal

is brought by train to southeastern Iowa and

then barged to the plant, usually between

April 1 and November 1. The river freezes

over during the winter months, so all deliver-

ies have to be planned well in advance.

3. The power of teamwork. The staff of the Lansing Generating Station. Courtesy: Alliant Energy

Page 35: Powermag200802 Dl

February 2008 | POWER 33

OPERATIONAL EXCELLENCE

Lansing, coal-constrained during the win-

ter, also operates in a transmission-congested

region of Iowa. Unit 3 is typically operated

in baseload mode, and Unit 4 operates on au-

tomatic generation control and is baseloaded

daily, typically from 6 a.m. to 10 p.m., when

demand drops to about 140 MW, every day

of the week.

Proud staff. Marty Burkhardt, Lansing’s

operations manager, provided some insight

into his plant’s excellent operations and

safety record. He is especially proud of the

plant’s strong safety committee that continu-

ally communicates with every staff member

the importance of a safe working environ-

ment. The results speak volumes: the plant

recently completed one million man-hours

without a lost-time accident. For the small

staff at Lansing, that record started in Febru-

ary 1999 and continues today.

Burkhardt also noted that all members of

the plant staff have deep pride in their jobs

and are dedicated to securing the plant’s fu-

ture success. The plant is located in a remote,

rural area of the state and is a mainstay in the

community. (See sidebar.)

Location hasn’t protected the plant from

the challenges of an aging workforce; a large

number of staff members are eligible to re-

tire in the next five years. The plant, with the

strong support of the IBEW local, has invest-

ed in an active apprenticeship program that

will maintain a well-trained workforce.

Empowered staff. The plant has very

strong leaders within the hourly ranks who

are involved in all significant plant initia-

Plant stack provides a safe haven for raptorsThe once-endangered Peregrine Falcon is again flying above the Mississippi River bluffs thanks to Raptor Resource Project (www.raptorresource.org) and the Lansing Generating Station.

The Peregrine Utility Program began in 1990 when the first home for nesting falcons was placed at Xcel Energy’s King Power Plant, located in Oak Park Heights, Minn. Plant stacks are at-tractive nesting sites for these raptors because falcons capture their prey in the air, and the stacks provide an undisturbed, tall lookout. Since the start of the program, approximately 300 young falcons have been born at power plant locations along the

Mississippi River and its tributaries and more than 500 at power plants in the Midwest. Today, tens of thousands of people world-wide visit web sites featuring utility-based Peregrine Falcon and owl cams, waiting for the young birds to hatch each spring.

Alliant Energy’s Lansing Generating Station was an early member of the program, and in June 2005, five Peregrine Falcons hatched in a nesting box halfway up Unit 4’s 499-foot stack (Figure 4). The nesting box was eventually moved to the cliff next to the plant (Figure 5).

4. Happy home. Five new Peregrine Falcons, known as eyas-ses, were born in a nesting box on Lansing Generating Station’s Unit 4 stack in 2005. Courtesy: Alliant Energy

5. New neighbors. A more permanent nesting place for the fal-cons was constructed adjacent to the plant. Courtesy: Alliant Energy

Page 36: Powermag200802 Dl

POWER | February 200834

OPERATIONAL EXCELLENCE

tives. For example, most new craft and op-

erations employees are local residents who

are hired after a rigorous assessment of their

skills, knowledge, and abilities. When more-

senior positions are being filled, hourly and

bargaining unit employees serve as members

of the hiring committee to ensure that new

employees not only have the requisite skills

but also fit the plant culture (Figure 6).

Employees are also involved in determin-

ing how limited capital and O&M dollars

are invested in their plant to support plant

reliability goals. Who better to determine the

timing of these expenditures than those who

have to grapple with problems every day?

The operations organization is empowered

as few other plant staffs are. The plant has

no shift supervisors and no first-line super-

visors for technicians or maintenance work-

ers. Of the 50-plus staff members, only six

are salaried. Certainly, the small staff makes

this option more attractive, but there is a wide

gap between the concept of an empowered

workforce and actually fitting together a jig-

saw puzzle of people with different techni-

cal skills, personalities, and self-motivation.

Lansing has successfully solved this puzzle

for the past five years.

Active communication among staff mem-

bers continues to be seen as essential for a

smoothly operating plant. Every day begins

with a coordination meeting involving the

chief plant operator, maintenance foreman,

and coal yard foreman, who plan the day’s

events. Minor outages are supported by plant

staff, although boiler welds require contrac-

tor support.

The predictive maintenance program is a

shared responsibility between the operations

and maintenance staffs. The program’s scope

is typical for most plants: predictive, vibra-

tion trending, thermography, lube oil analy-

sis, and the like. The plant engineer receives

the data and makes an evaluation that is fed

back to the maintenance planner, who sched-

ules repairs. The plant also has a full-time

water chemistry technician to keep an eye on

the plant’s working fluids; that person’s col-

lateral duties include preparing the inevitable

list of environmental reports for the plant

manager’s signature.

Edgewater’s edge: A finely tuned staffThe Edgewater Generating Station, located

in Sheboygan, Wis., has much in common

with the Lansing plant: both began service

with now-retired units in the 1940s and both

have baseload units that are dispatched to

serve areas with constrained transmission

access. Both have also benefited greatly

from the Generation Excellence program,

as evidenced by their top-place EUCG rank-

ing, which is all the more impressive be-

cause the competition included a number of

other very well run plants.

Edgewater operates three coal-fired units

today. Unit 3 is a 78-MW cyclone unit built

in the early 1950s. Unit 4 is a 330-MW cy-

clone unit that went commercial in 1969,

followed by the 395-MW pulverized coal

Unit 5 that entered service in 1985. All

three units use a common, centralized con-

trol room. Control systems are continuous-

ly upgraded by the plant staff, which also

handled the Unit 3 and 4 DCS conversion.

All three units also now burn PRB coal.

All are equipped with secondary overfire

air modifications by RMT (www.rmtinc

.com), originally developed through Alliant

Energy’s Combustion Initiative Program to

reduce NOx.

Alliant has made the economic decision

to operate all three units continuously, and

it takes the MISO-offered system power

price at minimum load during off-peak hours

rather than cycle the units every night. Unit

5 was originally designed as a peaking plant

with a minimum load of around 50 MW,

which is often reached at night. The decision

whether or not to cycle units over the week-

end is dependent on MISO marginal pricing.

However, because the units serve a transmis-

sion-constrained region of Wisconsin, the

plant typically provides baseload power and

is constrained only by periodic coal delivery

disruptions during the summer.

Patrick Hartley, Edgewater’s plant man-

ager, identified his highly motivated work

force as the secret of the plant’s success.

Edgewater relies heavily on a cadre of

6. Culture of success. Stan Schwartzhoff at the controls of Lansing Generating Station. Courtesy: Alliant Energy

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Page 38: Powermag200802 Dl

POWER | February 200836

OPERATIONAL EXCELLENCE

highly skilled, experienced hourly foremen

and technicians in the craft group (Figure

7). Plant operations is organized into five

crews on 12-hour shifts, each with a tech-

nically knowledgeable salaried shift super-

visor. There are only 12 salaried positions,

including the five shift supervisors, among

the staff of 120 who operate the plant.

Safety is always on a plant manager’s

mind, and Hartley is no exception. His plant

hasn’t experienced a lost-time accident in

more than 500 days. Edgewater’s safety

committee is organized with representa-

tives from each department plus the plant

manager, the administrative assistant, and

the plant environmental and safety special-

ist; the chief union steward is also a stand-

ing member (Figure 8). That committee is

charged with making the zero-injuries cor-

porate policy a reality at Edgewater.

Day-to-day maintenance requires periodic

contractor assistance in specialized areas,

although the plant does have its own “R”

Stamp program for repairing tube leaks. The

decision to develop this in-house capabil-

ity came at the conclusion of a recent tube

failure–reduction program. A task force ex-

amined the root cause of tube leaks and de-

veloped specific projects to address nagging

tube leak problems that were reducing plant

availability. This project has more than paid

for itself many times over.

A process performance engineer on the

staff is responsible for maintaining the right

combustion stoichiometry and optimizing

performance of the three steam generators.

Burning PRB coal has also challenged the

plant with learning how to balance erosion

versus cleaning frequency with sootblowers

in certain areas of the boiler. In other loca-

tions, additional sootblowers were added,

as were boiler cleanliness probes for bet-

ter monitoring of boiler performance. Coal

combustion by-products, such as bottom

ash, are sold to a contractor for recycling,

and the slag from the cyclones is sold to

road-paving contractors.

Hartley also emphasized the pride the staff

have in their plant and what the plant has ac-

complished. Edgewater has a long history of

service to its community, beginning in the

1930s, and the staff take pride in passing down

not only their experience, by training new

operating staff members, but also the plant’s

heritage and history to the next generation.

In addition to the three coal-fired units,

the plant operates and maintains two remote

simple-cycle combustion turbine sites. The

Fond du Lac, Wis., site has four ABB 11 N1

units rated at 83 MW each; two other units at

the Sheboygan Falls, Wis., site are GE Frame

7 units rated at 147 MW apiece.

No-excuses excellenceThe preeminent common trait shared by the

two Alliant Energy plants profiled in this

article, and probably all Alliant plants, is a

culture of excellence that’s engrained in the

DNA of every employee. It doesn’t matter if

the employee happens to be a union member,

technician, or member of the management

staff, each person has a part to play if the

plant is to be successful.

A razor-thin plant staff is not uncommon

today. What is uncommon are staffs that

can consistently focus on excellence in op-

erations and maintenance regardless of the

staffing and budgeting constraints now com-

mon in our industry. Congratulations to the

Lansing and Edgewater Generating Stations

staffs for safely walking that tightrope. ■

8. Focused on safety. The Edgewater Generating Station safety committee. Back row

(L to R): Mike Cichocki, Coal Yard Supervisor; Jerry Strouf, Senior Environmental and Safety

Specialist; Joy Hoffman, Administrative Assistant; Jason Mills, Maintenance Technician; and

Don Yanna, Equipment Operator. Front row (L to R): Paul Schlegel, Equipment Operator; John

Hodzinski, Maintenance Electrician; and Pat Hartley, Plant Manager. Courtesy: Alliant Energy

7. Self-motivated staff. Don Singer is a master maintenance technician on second shift

at Edgewater. Courtesy: Alliant Energy

Page 39: Powermag200802 Dl

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www.powermag.com POWER | February 200838

CARBON CAPTURE

Alstom’s chilled ammonia CO2-capture process advances toward commercializationCarbon dioxide emissions aren’t yet regulated by the EPA, but it’s likely they

will be soon. There are many technically feasible, but as-yet-undemon-strated ways to reduce the considerable carbon footprint of any coal-fired plant, whether it uses conventional or unconventional technology. One promising approach to removing CO2 from a plant’s flue gas uses chilled ammonium bicarbonate to drive the separation process.

By Dr. Robert Peltier, PE

King Dionysius I, ruler of Syracuse,

Italy, in the 4th century B.C., invited his

courtier Damocles to exchange places

with him for a day. While enjoying a feast,

Damocles immediately lost his appetite when

he noticed a sword suspended above him by

a single horsehair. Dionysius, as they say in

Las Vegas, was making his point the hard way:

handling risk is part of a leader’s job, and dan-

ger can arise at the most unexpected times.

Today, utility executives have a better re-

tirement plan than Dionysius, but there’s a

figurative sword hanging over their heads:

uncertainty about the timing and strength of

future federal and/or state CO2 regulations.

Congress currently seems to be favoring a Eu-

ropean-style cap-and-trade approach over a

straight tax on carbon emissions, but that may

change once this election year passes. Indeed,

it may take the rest of the decade to exorcise

the devil from federal legislation that will

surely raise everyone’s electricity rates and

create a two-tier (large and small carbon foot-

print) national bulk power supply system.

Managing riskThe list of utilities that have decided to cancel

a new coal plant rather than bear its unquan-

tifiable carbon risk is growing. Last month,

POWER’s 2008 industry forecast attributed

the cause of this collective loss of appetite

to FUD: fear, uncertainty, and doubt—each

anathema to utility executives.

For example, last November Southern

Company and Florida’s Orlando Utilities

Commission terminated a 285-MW integrated

gasification combined-cycle (IGCC) project

just two months after it broke ground at the

latter’s Stanton Energy Center. The stunning

reversal of fortune was viewed as a slap in the

face to the U.S. DOE, which was planning to

pay $294 million of the project’s $855 million

cost to make it a showpiece for the Bush ad-

ministration’s Clean Coal Power Initiative.

Mike Tyndall, a spokesman for Southern

Company, said no single event during the

two-month period had changed the company’s

mind about the IGCC project. “It was a cul-

mination of the growing uncertainty,” he said

of the cancellation decision. “The partners are

just not able to take the financial risk.”

As another example, Florida’s Public

Service Commission, citing potential CO2

control costs and other related project risks,

last June rejected a proposed coal plant by

Florida Power & Light. The “no” vote came

shortly after Gov. Charlie Crist (R) issued an

executive order to substantially reduce Flor-

ida’s emissions of the greenhouse gas. Fear

of carbon risk wasn’t limited to the Sunshine

State, parts of which are projected to end up

under water if global warming raises world-

wide sea levels. Far from any coast, two 700-

MW coal-fired units that Sunflower Electric

Power Corp. had proposed building at its ex-

isting plant near Holcomb were axed by the

Kansas Department of Health and Environ-

ment in late October.

Perhaps another dozen coal projects have

gotten a thumbs-down from a state regula-

tor over the past year; the reason most often

cited was the rising uncertainty of carbon

controls or untenable project cost risks. The

crazy quilt of different state carbon caps that

could emerge if California’s emissions stan-

dards aren’t adopted as national standards

would only heighten the FUD felt by utilities.

Expect more utilities to take a wait and see

position on carbon and, in the interim, resort

to the lowest-risk option for adding capac-

ity—building more gas-fired generation.

Big retrofit marketThe industry may have put new coal projects

on hold while it deals with carbon paralysis,

but greater commercial opportunities for car-

bon capture lie with the future retrofitting of

many of the 1,100-plus existing U.S. coal

plants. Whether you prefer your carbon leg-

islation with a cap-and-trade or a tax flavor,

the aftertaste will be bitter: the need to build a

small refinery on the power plant’s grounds.

Considerable chemical processing is need-

ed to implement all of the post-combustion

carbon capture processes that have proven

their worth in the lab or at pilot scale and

are now advancing toward commercial vi-

ability (POWER, October 2006, p. 60). Two

processes that seem to have gathered the

most steam in the marketplace are the chilled

ammonia process favored by Alstom Power

(see sidebar) and Powerspan’s Electro-Cata-

lytic Oxidation (ECO) process, which was re-

cently upgraded to include CO2 removal and

relabeled ECO2. Powerspan and FirstEnergy

Corp. plan to demonstrate the ECO2 process

at a 1-MW (equivalent) pilot scale at the util-

ity’s R.E. Burger plant in Ohio early this year

(POWER, October 2007, p. 54).

Greater commercial opportunities for carbon capture lie with the future retrofitting of many of the 1,100-plus existing U.S. coal plants.

Page 41: Powermag200802 Dl

February 2008 | POWER 39

CARBON CAPTURE

There’s no doubt that Alstom is about

to enter the flue gas treatment market; the

company continues to fund an extensive

R&D program whose target is to make a

CO2 capture system commercially available

before the end of 2011. The evolution of

Alstom’s business development plans for its

chilled ammonia systems has been transpar-

ent from the start:

■ A 5-MW (equivalent) pilot plant with

EPRI and We Energies.

■ A 5-MW demonstration plant for E.ON in

Sweden.

■ A 30-MW (equivalent) product validation

unit for American Electric Power (AEP),

followed by the design, construction, and

commissioning of a commercial-scale (up

to 200 MW) unit by 2011.

■ A 40-MW (equivalent) product validation

facility for Statoil in Norway.

Taking the first stepAlstom’s first carbon capture pilot project is

currently under construction at We Energies’

Pleasant Prairie Power Plant (P4) in Kenosha

County, Wis. (Figure 2). Working closely with

EPRI, Alstom is responsible for the design,

Inside Alstom’s chilled ammonia CO2 capture systemYou don’t need a degree in chemical en-gineering to understand Alstom’s chilled ammonia CO2 removal process—but it wouldn’t hurt. First, let’s break the entire process down into three separate process blocks (Figure 1) and follow the exhaust gas as it leaves the plant and is treated to remove its CO2.

One key point about Alstom’s chilled ammonia design is that it does not require extremely low levels of SO2 removal from flue gas. If the candidate plant already has a scrubber operating at a 95% removal rate, and its steam system can be recon-figured to accommodate the process steam demand, a chilled ammonia system may be just the ticket, assuming there’s sufficient space for it.

Step 1: Cool and clean the gasThe first step is to cool and clean the flue gas, which typically is at 120F to 140F, is water-saturated, and contains residual amounts of SO2, NOx, HCl, and particulate matter. Both steps can be accomplished by injecting refrigerated water directly into the gas stream. As the gas is cooled, much of its water content condenses out, carry-ing the residual contaminants with it. The water is then evaporated in cooling tow-ers, substantially reducing the total flue gas volume. The cooled flue gas leaves as a chilly (35F) and dry (<1% moisture) gas-eous substance.

Cooling the flue gas first pays big divi-dends by reducing the size and cost of equipment required downstream. For ex-ample, if the volume of the saturated flue gas is one-third smaller at 32F than at 140F, a smaller, cheaper induced-draft fan would suffice. Flue gas cooling itself consumes only 1% to 2% of the plant’s power output.

Step 2: Absorb the CO2The second process step is CO2 absorption, which is similar to the SO2 absorption com-mon at many coal-fired plants today. After the 35F flue gas enters the bottom of the absorber vessel, it is forced upward against the current of a slurry containing a dis-solved and suspended mix of lean ammo-nium carbonate (AC) and rich ammonium bicarbonate (ABC). Chemical reactions re-move over 90% of the CO2 in the flue gas,

leaving it only with nitrogen, excess oxy-gen, and low concentrations of CO2. Any re-sidual ammonia is captured by a cold-water wash and returned to the absorber.

Step 3: Separate the CO2The third step of the process takes the CO2-rich slurry at 1,200 to 1,500 psi (anticipat-ed for commercial use or for transportation to an enhanced oil recovery process or sequestration) from the ABC-rich output of the high-pressure pump and directs it to a heat exchanger. The heat exchanger dissolves the slurry into a clear solution

at about 175F and sends it on to the high-pressure regenerator, where additional heat is added by a reboiler to strip away the CO2 gas. The only by-product of the entire process is a small amount of water; it can either be treated by the plant’s wastewater system or recycled and reused.

A baseline study on the auxiliary load and cost of a full-scale CO2 capture project found that retrofitting a 462-MW super-critical pulverized coal–fired boiler operat-ing at 40.5% net thermal efficiency would result in only small performance penalties (see table).

The performance penalties of a chilled ammonia CO2 separation system. Source: Alstom Power

Parameter

Supercritical PC-fired unit

without CO2 removal

Same unit with chilled

ammonia CO2 removal

Illinois #6 coal feed rate (lb/hr) 333,542 333,542

Coal heating value (Btu/lb), (HHV) 11,666 11,666

Boiler heat input (mmBtu) 3,891 3,891

LP steam extraction for reboiler (lb/hr) 0 179,500

Steam turbine power (kW) 498,319 484,995

Total auxiliary power used by plant (kW) 29,050 53,950

Net power output (kW) 462,058 421,717

Net efficiency (HHV), (%) 40.5 37.0

1. Coming to a coal plant near you? Schematic of a commercial chilled ammonia CO2 capture system added between a plant’s existing flue gas scrubber and stack. Source: Alstom

Fluegas

Flue gas

Scrubber

Purge

120F

2-stagecooling

Chiller

35F

CO2absorber

Wash

Wash

Stack

Leanammoniumcarbonate

Rich ammoniumbicarbonate

HPpump

Heatexchanger Reboiler

Regenerator

CO2

Cooling and cleaning of flue gas CO2 absorption CO2 regeneration

Water Rich slurry Lean slurry CO2

Page 42: Powermag200802 Dl

POWER | February 200840

construction, and operation of the $10 million

pilot plant, which engineers hope will be able

to extract 90% of the CO2 from 1% of the flue

gas produced by one of the plant’s two 617-

MW coal-fired units. Project costs are spread

among more than 30 project sponsors. The

goal of the project is to capture about 15,000

tons of CO2 per year (Figure 3).

Construction of the pilot plant began last

September; the plant will be operational by

press time. Alstom will then operate the plant

for at least one year while EPRI evaluates the

performance of the technology from several

perspectives (Figure 4). Specifically, Alstom

and EPRI will:

■ Validate operation of the entire system on

actual flue gas.

■ Measure the actual heat of reaction and

compare it to theoretical values.

■ Develop and evaluate the process control

logic and operating system.

■ Operate the system in long-term tests to

identify O&M issues and establish system

reliability baselines.

■ Conduct a techno-economic analysis of

scaling up the system for commercial use

(Figure 5).

“The development of cost-effective carbon

capture technology is one of the most impor-

tant environmental challenges facing the util-

ity industry in the 21st century,” said Gale

Klappa, chairman, president, and CEO of

Wisconsin Energy, the parent company of We

Energies. “This pilot is a crucial step in the re-

search and development process necessary for

achieving a long-term technology solution.”

This pilot project is just the latest in a

long line of improvements at the Wiscon-

Existing boiler(within P4*)

Coal

Removes 85%–90%of NOx

Selectivecatalyticreduction

unite

*Pleasant Prarie Power Plant

Electrostaticprecipitator

Flue gasdesulfurization

scrubber

Removes99.7%

of flyash

Removes90%–95%

of SO2

<1% flue gas fromone boiler unit

Step1

Step2

Fluegas

cooling

CO2capture

Two-stepcarbon capture pilot

Potential toremove 90% of CO2

Continuousemission

monitoringsystem

Existingchimney

2. Beta version. This two-step, 5-MW (equivalent) pilot CO2 capture process is being im-plemented at We Energies’ Pleasant Prairie Power Plant. Source: Alstom

3. Virtual design. This 3-D representation depicts the completed pilot plant at Pleasant Prairie. Courtesy: Alstom

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Page 43: Powermag200802 Dl

February 2008 | POWER 41

CARBON CAPTURE

sin plant. Last October, POWER designated

P4 as one of its Top Plants of 2007 on the

strength of several recently completed air

emissions upgrade projects. We Energies

has added a hot-side selective catalytic re-

duction (SCR) system to Unit 1 and a wet-

limestone, forced-oxidation scrubber to both

units. Unit 2 was retrofitted with a hot-side

SCR system in 2003.

Other steps to followMeanwhile, Alstom and AEP have signed an

agreement to bring Alstom’s chilled ammonia

process for CO2 capture to full commercial

scale by 2011. The project will be implement-

ed in two phases. In phase one, Alstom and

AEP will jointly develop a 30-MW (equiva-

lent) product validation plant that will capture

more than100,000 tons of CO2 per year from

the flue gas of AEP’s 1,300-MW Mountaineer

Plant in New Haven, W.Va. Notably, the cap-

tured CO2 will be sequestered in deep saline

aquifers at the site. This pilot project is sched-

uled to start up at the end of 2009 and operate

for at least 12 to 18 months.

In phase two, Alstom will design, build,

and add the first commercial-scale (up to

200-MW) CO2 capture system to one of the

450-MW coal-fired units at AEP’s Northeast-

ern Station in Oologah, Okla., by late 2011.

If the system captures about 1.5 million tons

of CO2 a year, Alstom will consider the ac-

complishment a successful validation of the

chilled ammonia separation technology. The

CO2 captured at Northeastern Station will be

used for enhanced oil recovery.

Alstom’s 5-MW (equivalent) CO2 cap-

turing demo plant being built at E.ON’s

Karlshamn Power Plant in southern Sweden

is expected to begin operation later this year.

The two companies plan to introduce the

technology at other Swedish power plants if

it passes muster.

For the longer term, Alstom has signed a

joint development contract with Norway’s

state-owned oil gas and company, Statoil-

Hydro, to test the chilled ammonia technolo-

gy’s ability to remove the CO2 from flue gases

particular to natural gas–fired combined-cycle

power plants. The first milestone of the agree-

ment calls for designing and building a 40-MW

(equivalent) test and product validation facil-

ity at Statoil’s Mongstad refinery in Norway

by 2009–2010. The facility will then be oper-

ated for up to a year and a half to see whether

it can capture at least 80,000 tons per year of

CO2, either from flue gases from the refinery’s

cracker unit or from a new combined heat and

power plant now under construction on-site. A

commercial-scale unit now in the early plan-

ning stages for Mongstad would capture over

2 million tons of CO2 per year.

Policymakers try to keep paceOnce CO2 has been removed from a power

plant’s flue gas, what can and should be done

with it? Given that a 1,000-MW coal plant

produces about 3 million pounds of CO2 per

hour, storing it on-site is not an option.

A bill called the Carbon Dioxide Pipeline

Study Act of 2007 recently introduced by Sen.

Norm Coleman (R-Minn.) would require the

DOE to identify and resolve key obstacles to

commercializing CO2 sequestration, trans-

portation, and storage technologies. S. 2144

also would ensure that a robust national CO2

infrastructure would be created as part of any

federal climate change legislation.

Last year also saw the introduction of the

National Carbon Dioxide Storage Capacity

Assessment Act of 2007 (S. 731) by Sen. Ken

Salazar (D-Colo.) and The Department of En-

ergy Carbon Capture and Storage Research,

Development and Demonstration Act of 2007

(S. 962) by Sen. Jeff Bingaman (D-N.M.).

The three bills are meant to work together

to bring all relevant federal departments and

regulators (Energy, Interior, Transportation,

the Federal Energy Regulatory Commission,

and the Environmental Protection Agency)

together to address the broad range of policy

questions surrounding CO2 sequestration,

transportation, and storage. ■

4. Up and running. The chilled ammonia pilot plant began operation in January. Courtesy: Alstom

CO

2 em

issi

ons

(met

ric

tons

/MW

h)

CO

2 re

duct

ion

from

sub

crit

ical

PC

pla

nt (%

)

0.90

0.85

0.80

0.75

0.70

0.65

0.60

30

25

20

15

10

5

0

Net plant efficiency (HHV), % 37 38 39 40 41 42 43 44 45 46 47 48 49 50

100% coal

Coal w/10% cofiring biomass

UltrasupercriticalPC plant range

SubcriticalPC plant Commercial

supercritical

5. CAFE vs. CO2 standards for plants. As with automotive fuel economy, the effect of overall power plant efficiency on CO2 emissions can be significant. For example, a 47% ef-ficient supercritical plant “naturally” has about 20% less CO2 in its flue gas than a 37% efficient subcritical plant. Today’s U.S. coal-fired fleet has an average thermal efficiency of about 33%. The curves shown were derived from plants firing Pittsburgh #8 coal. Source: Alstom

Page 44: Powermag200802 Dl

www.powermag.com POWER | February 200842

PLANT DESIGN

In recent years, U.S. utilities have shown

increasing interest in deploying new coal-

fired power plants based on advanced

technologies such as integrated gasification

combined-cycle (IGCC), ultrasupercritical

pulverized coal (USC PC) combustion, and

supercritical fluidized bed combustion (SC

FBC). The appeal of innovative and more-

efficient coal plants continues to be driven

by volatile natural gas prices, the need for

new baseload generating capacity, ever-low-

er limits on plants’ air pollution, and likely

future restrictions on carbon dioxide (CO2)

emissions.

Yet deployers of advanced coal plants face

considerable obstacles. Unlike natural gas–

fired plants of the 1990s, which were inexpen-

sive and could be built and permitted relatively

quickly, advanced coal plants are challenged

by high capital and construction costs, reli-

ability shortfalls, long project schedules, and

lengthy environmental permitting processes.

On a timeline of technology development

(Figure 1), advanced coal-fired facilities are

now nearing the crest of the curve, where

commercial units must overcome high initial

costs to reach technological maturity and the

lowest achievable cost. If advanced coal plants

are to succeed, the industry must get beyond

the current penalties in cost and schedule

that dog first-of-a-kind plants to achieve the

shared economies of “Nth-of-a-kind” plants.

A major contributor to this challenge has

been a lack of experience with the new tech-

nology. For example, although more than 130

coal gasification plants are currently operat-

ing worldwide, only 16 can be considered

IGCC plants, whose primary role is to pro-

duce electricity. Only four of those 16 plants

are in the U.S.

A shortage of operating experience has

not been the only hurdle on advanced coal

plants’ road to technological maturation and

lower costs. Another is the fact that all of the

advanced plants in commercial service today

were conceived, designed, and built as cus-

tom projects. Standard design specifications

are needed to lower initial capital costs, sup-

port repeatable and reliable performance, and

reduce development time and cost for poten-

tial plant owners.

CoalFleet for TomorrowAn EPRI-sponsored collaborative ef-

fort—called the CoalFleet for Tomorrow

program—seeks to lower the hurdle of tech-

nology development by deploying the first

group of full-scale advanced coal plants as

quickly as possible. Launched in 2004, the

program brings together a broad cross sec-

tion of generating companies, turbine and

boiler suppliers, engineering/procurement/

construction (EPC) firms, and research part-

ners from around the world. Today, more

than 60 companies from five continents are

active participants in the effort.

One of CoalFleet’s key initiatives is a

unique, circular, learn-by-doing process

in which expert information is provided to

utilities developing plant designs, and the

utilities’ experience is fed back into growing

databases of information on advanced coal

technologies.

The process works as follows. EPRI

provides expert consultation to an “early

deployment project” (EDP) utility that has

committed to design and build a new IGCC,

USC PC, or SC FBC plant. For this consulta-

tion, EPRI enlists a large team of indepen-

dent world-class experts to work with its own

knowledgeable staff to advise the EDP utility

on how to optimize the plant’s design. In re-

turn for the expert advice, the utility shares

nonproprietary information from its site-spe-

cific feasibility studies and front-end engi-

neering designs (FEEDs) with the broader

CoalFleet membership.

The expert consultations and the feedback

from EDPs are creating a family of design

guidelines and permitting data and guidance

that are continually updated to reflect new in-

formation and lessons learned. It is estimated

that participating in this process could cut the

costs of feasibility and preliminary engineer-

ing studies by 30% to 50%, shorten a proj-

ect’s development cycle by up to two years,

and reduce an advanced coal plant’s capital

costs by $100/kW to $200/kW or more.

It takes a villageTo date, the process has produced four types

of documents and databases that are used

Accelerating the deployment of cleaner coal plantsThe dearth of commercial operating experience for advanced coal-fired facili-

ties is forcing their early adopters and builders to use long development cycles and pay high costs for unique engineering design studies. A broad-based industry collaborative effort fostered by EPRI to address this issue is beginning to show results.

By Jack Parkes, Neville Holt, and Jeffrey Phillips, Electric Power Research Institute

1. Ride the wave. Advanced coal plants, like any new technology, must overcome the

crest of the technology development cost curve if they are to become economically viable. Source: EPRI

Research Development Demonstration Deployment Mature technologyAdvanced USC PC plants

CO2 capture

CO2 storage

760C 620C+

620C+ 600C

<600C

USC PC plants

Oxyfuel

IGCC plants

SC PC plants

565C

Expected availability canincrease with time/learning

Time

An

tici

pa

ted

co

st o

f fu

ll-s

cale

ap

pli

cati

on

Notes: IGCC = integrated gasification combined-cycle, SC PC = supercritical pulverized coal,

USC PC = ultrasupercritical pulverized coal.

Page 45: Powermag200802 Dl

February 2008 | POWER 43

both progressively and for feeding back les-

sons learned into their predecessor docu-

ments (Figure 2).

The first resource at the start of the process

is the Advanced Coal Technology Knowledge

Base, a web-based repository of information

on trends in advanced coal technology de-

sign, cost, and performance. The core of the

knowledge base is more than 50 design cases

from eight state-of-the-art studies conducted

by EPRI, the DOE, utilities, consultants, and

teams of technology suppliers. Each case

study details vital characteristics in up to 450

defined fields. CoalFleet adds data as they

become available from new feasibility stud-

ies by members and from design decisions

made by companies undertaking early de-

ployment projects. The Knowledge Base also

includes papers from key conferences and

lessons learned from demonstration units.

A second resource is a series of plant de-

sign guides that were developed out of the

knowledge base. The first of these guides,

developed for IGCC plants, is the CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification Combined Cycle, or UDBS for short. The UDBS is in-

tended to foster the benefits of standardiza-

tion in design specifications.

The 800-page IGCC UDBS defines the ma-

jor specifications needed to contract for IGCC

“reference plants”—generic, 600-MW and

900-MW (nominal) plants that use gasifica-

tion processes and combustion turbines from

several manufacturers that commercially guar-

antee their equipment. For bituminous coal

plants, the UDBS includes plant designs us-

ing commercial entrained-flow gasifiers from

GE Energy, ConocoPhillips, and Shell—both

with and without CO2 separation. For low-sul-

fur Powder River Basin (subbituminous) coal,

the UDBS includes plant designs from Cono-

coPhillips, Shell, and KBR—again, both with

and without CO2 separation.

A reference plant replicates both the design

and execution from project to project in order

to reduce costs, shorten project schedules, and

improve the project’s certainty of outcome.

However, while defining the reference plants,

the UDBS also allows for different coal types

and other basic options to match the needs of

different power companies.

The UDBS provides a comprehensive pic-

ture of what is involved in planning, building,

and operating an IGCC plant—including,

crucially, the tradeoffs an owner must make

when making design and operational deci-

sions. For example, the specification lays out

the risks and rewards of various strategies for

incorporating CO2 capture into a prospective

plant design.

The UDBS has two novel aspects. First,

it was written by more than 25 experts from

around the world with experience and ex-

pertise in IGCC technology—and with the

cooperation of equipment suppliers, plant de-

signers, and EPC firms. Second, the document

has been designed so users can substitute site-

and system-specific data for nominal data,

producing information that can become part

of a site-specific specification. The UDBS pro-

vides a choice of configurations, reference site

information, target performance, RAM (reli-

ability, availability, and maintainability), and

operability goals, along with matching data

based on an EPRI reference site. The designs

also provide for making a swap-out choice of

environmental cleanup systems tailored to two

levels of licensing constraint.

Pre-design and generic design specsTwo types of documents derive from the

UDBS: pre-design specifications and gener-

2. Design for success. The CoalFleet for Tomorrow program produces a series of de-

sign guides and specifications that are progressively more detailed. Early experience with the

specifications is fed back and captured in later editions of the documents. Source: EPRI

Knowledge base

Expert and user groupsPre-design specs Generic design specs

EPRI and DOE studies

Industry feasibilitystudiesOperating plant data Design guide

Supplier 1

Supplier 2

Supplier 3

Supplier 1

Supplier 2

Supplier 3

Early deployment projects

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PLANT DESIGN

Page 46: Powermag200802 Dl

POWER | February 200844

PLANT DESIGN

ic design specifications for IGCC plants. A

pre-design specification is a nonproprietary

description of the design of a specific IGCC

plant whose feasibility study has been com-

pleted and is ready to begin a FEED study.

Essentially, it is a generic version of the fea-

sibility study. As part of several EDPs, four

pre-design specifications have been devel-

oped for different IGCC suppliers and coal

types based on feasibility studies conducted

by Duke Energy, Excelsior Energy, Nuon,

and Southern Company.

By contrast, a generic design specification

is a nonproprietary description of the design

of an IGCC plant created after its developer

has completed a FEED study. It corresponds

to about the first half of the FEED study.

CoalFleet intends to publish its first generic

design specification early this year; it will

be based on the FEED study completed by

Southern Company and Orlando Utilities

Commission for the recently cancelled IGCC

project at the latter’s Stanton Energy Center.

Permitting histories and guidelinesThe owner of a proposed power plant must

obtain permits to build and operate the plant

during its planning and construction phases.

Obtaining an environmental permit for a new

IGCC plant is a critical-path item before con-

struction can begin. Given the limited regula-

tory experience base, permitting could cause

significant delays in a project’s schedule.

Accordingly, there is a need for readily ac-

cessible information on past permits for use

in system design and regulatory negotiations.

To meet this need, the CoalFleet for Tomor-

row program has compiled an IGCC permit-

ting database in Microsoft Access format. The

database includes narrative summaries of 18

existing or proposed IGCC plants, including

descriptions of the facilities and the permitted

discharge sources. The database also details

permit conditions for plant operations (heat

rate and hours of operation, for example),

limits on air and water emissions, and the test

methods required for compliance with the per-

mit conditions.

CoalFleet also has developed a series

of regularly updated IGCC permitting

guidelines that summarize federal require-

ments for obtaining air, water, and solid

waste permits for a generic IGCC facility,

as described in the CoalFleet UDBS. These

guidelines will improve the dialogues that

owners of planned facilities have with regu-

lators regarding IGCC plants’ technology,

typical emissions, and appropriate monitor-

ing and compliance approaches. By estab-

lishing a common basis for all IGCC permit

applications, owners could also reduce the

time needed to obtain permits.

Other advanced coal plantsThe CoalFleet for Tomorrow program is using

a similar process to develop design and per-

mitting guidelines for USC PC and SC FBC

power plants. Last year, EPRI published the

first of these guides—Versions 1 and 2 of the

CoalFleet Guideline for Advanced Pulverized Coal Power Plants, which are intended to help

power companies define the technical require-

ments for a site-specific USC PC plant.

Sharing pays offAs mentioned, Duke Energy is one of the EDP

utilities that has participated in the CoalFleet

program. Duke plans to build a 630-MW IGCC

power plant at the site of its existing coal- and

oil-fired power plant in Edwardsport, Ind.

(Figure 3). As part of the project development

process, the company has already completed

a FEED study. The utility is seeking to ensure

that the design incorporates the best available

information while accelerating the design pro-

cess and reducing its cost.

As a sponsor of a CoalFleet EDP, Duke

Energy has been able to use the UDBS and

the permitting guidelines to gain insight into

several areas of plant design and permit-

ting. They include the possible application

of selective catalytic reduction (SCR) for

additional NOx control, and engineering as-

sessments of future options that include vari-

ous levels of CO2 capture. These documents

have helped Duke develop a design that will

achieve very low emission levels and support

the air permit application process. Duke also

has gained an understanding of the technical

requirements for the sulfur market that were

incorporated into the design of the plant’s

sulfur recovery system.

The utility also worked with CoalFleet

IGCC experts to understand the issues in-

volved in potentially retrofitting CO2 cap-

ture into the plant design at a later date. For

example, Duke identified several options

for various levels of CO2 capture that could

be implemented at lower cost, compared to

other IGCC and PC designs.

Finally, information from permitting guide-

lines and CoalFleet meetings was used by

Duke in its discussions with the permitting

agency on technical issues affecting IGCC de-

sign and emissions. Among the subjects dis-

cussed were the feasibility of applying SCR

technology to IGCC, start-up and shutdown

emissions levels, and the applicability of EPA

guidelines and regulations to coal-fired IGCC

plant operations, as opposed to those of natu-

ral gas–fired combined-cycle plants.

In return for those tangible and intangible

benefits, Duke provided valuable support

to the CoalFleet program. Duke represen-

tatives maintained an open dialogue with

EPRI’s IGCC experts and other members of

the IGCC Design Guidelines working group

and provided significant input to the UDBS. Finally, as a designated EDP, Duke will help

develop a CoalFleet pre-design specification

that will contain a nonproprietary description

of the Edwardsport design that other Coal-

Fleet members can use as a reference when

deciding which “standard IGCC” they would

like to adopt for their own project. ■

—Jack Parkes ([email protected]) is the senior manager of EPRI’s Advanced Coal

Generation program. Neville Holt ([email protected]) is a technical fellow with

the program, and Jeffrey Phillips ([email protected]) is one of its managers.

3. Next-generation coal. An artist’s rendering of the 630-MW IGCC plant that Duke

Energy plans to build in Edwardsport, Ind. Source: Duke Energy

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Page 48: Powermag200802 Dl

www.powermag.com POWER | February 200846

BENCHMARKING

Who’s doing coal plant maintenance?POWER has reported on several EUCG benchmarking studies over the past

several years. This month we examine the maintenance staffing of 45 coal plants reported by 13 EUCG member utilities. If you benchmark your plants or fleet, as you should, some of the study’s results challenge what is considered conventional wisdom.

By Robert Oldani, DTE Energy and EUCG Inc.’s Fossil Productivity Committee

This maintenance staffing study is the

third in a series of plant staffing bench-

marking studies published in POWER. The first, in the September 2004 issue, was

on plant operator staffing; the second, in

July/August 2006, examined engineering

staffing. Taken as a whole, the three surveys

provide extraordinary insight into the staffing

of most coal-fired power plants. Such unique

information is not available elsewhere in the

industry at any price.

Though the detailed results are propri-

etary to EUCG members that participated

in it, POWER was given access to the over-

all findings. If you want details at the plant

or unit level, you’ll have to join the EUCG

and participate in the next study. Joining the

EUCG and participating in its ongoing se-

ries of benchmarking studies gives you ac-

cess to the next layer of detail and a way to

rank your plant against its peers.

The study’s scopeThe latest plant maintenance staffing bench-

marking study by the EUCG (formerly the

Electric Utility Cost Group, see sidebar) was

based on data from 45 baseload coal-fired

plants comprising 142 generating units. Only

day-to-day staffing data were collected, to

exclude the effects of planned outages on

overall staffing levels. Plant, fuel yard, and

instrumentation and control (I&C) mainte-

nance personnel were included in this study.

The plants range in size from less than 500

MW (27%) to over 2,000 MW (11%), and

most are owned by one of 13 geographically

dispersed utilities. Of the 45 plants, 71% re-

port that that their fuel mix includes at least

50% Powder River Basin (PRB) coal or lig-

nite. A little over half (58%) reported that a

regional maintenance supervision and craft

workforce was available to work at the plant.

Several other characteristics of the study

population add perspective to the survey re-

sults. For example, based on responses, 16%

of the steam generators have cyclone fur-

naces, 13% have been retrofitted with a flue

gas desulfurization (FGD) system, and 18%

have a selective catalytic reduction (SCR)

system. Not surprisingly, 82% of the units re-

port having a plant distributed control system

(DCS), but only 11% have cooling towers.

Some 74% of respondents said their plants

have an equivalent availability factor (EAF)

greater than 85%, and 44% said their EAF is

above 90%.

Finding good helpOne of the primary goals of the maintenance

staffing study was to develop benchmarking

targets for the split between in-house and

contract labor. Respondents from 31 plants in

the 45-plant sample said that, in addition to

plant maintenance staff, they use some full-

time contractors to perform plant mainte-

nance; contractor job descriptions range from

manager (14 plants) and supervisor (12) to

laborer (8). The most popular craft positions

included insulator (18), janitor/cleaner (18),

electrician (12), and scaffold erector (11).

About two-thirds of respondents noted that

paying full-time craft contractors consumed

20% or less of their plant’s total nonplanned

outage maintenance labor budget. Although

contract maintenance represented more than

50% of the overall maintenance outlay at two

plants, the average was 12%.

Many plants farm out specific mainte-

nance chores, as opposed to retaining several

contractors and having them share general

maintenance duties. A number of plants re-

ported spending more than 75% of their

budget for a particular type of maintenance

on hiring contractors. The top categories

here were “fuel yard mobile equipment” (26

plants), “air compressors” (21), and “forced

outage boiler tube repairs” (18).

To obtain more detailed information on

Meet the EUCGFounded in 1973, the EUCG is an associa-tion of utility professionals that provides a forum through which electric utilities can improve their operating, mainte-nance, and construction performance. It holds technical conferences, including workshops, twice yearly for the purpose of information exchange. The EUCG is orga-nized into committees and working groups by interest areas such as fossil, nuclear, and hydroelectric plants; transmission and distribution; and financial management.

One of the key functions of the EUCG is to develop benchmarking information and to share it and unit reliability strategies and best practices among member utilities to help them excel in competitive markets. To that end, the EUCG’s Fossil Productiv-

ity Committee has 32 members reporting operating data from their more than 300 individual units. A “Data Membership” in the EUCG entitles you to receive a com-plete benchmarking data set customized for your plant.

The maintenance staffing study, whose results are summarized in this article, and earlier benchmarking studies on plant op-erator staffing and engineering and tech-nical staffing, are ongoing EUCG projects. If you would like to include your plants in the study database and receive a copy of the complete study (with your data in-cluded), please contact the EUCG.

For more information about the EUCG, contact Executive Director Pat Kovalesky at 623-572-4140 or visit www.eucg.org.

Page 49: Powermag200802 Dl

February 2008 | POWER 47

BENCHMARKING

contractor use, the survey asked, “How would you most likely staff a

three-day forced outage caused by a boiler tube leak?” Just over half

of responding plants (24) said the majority of that ad hoc staff would

be in-house craft workers, supplemented by staffers from nearby

plants (we should all be so lucky). Another 13 respondents said they

would contract out that kind of repair work.

Notes added to survey forms provided the sought-for details. They

included these: “Plant personnel get core work, then supplement with

contractors,” and “Welding tube leaks is considered non-core work

since our plant personnel aren’t certified welders.” One respondent not-

ed that “All craft work outside the boiler will be ours, and work inside it

would be contracted out due to a staff shortage of certified welders.”

If you’re interested in more benchmarking data specific to boiler

tube repairs, I direct you to a two-part article on an earlier EUCG

benchmarking survey that ran in the October 2005 and November/De-

cember 2005 issues of POWER.

Sharing the loadMany plants report doing more multi-skill training of operators to

qualify them to perform the more routine maintenance tasks that in

the past would have been considered the purview of the maintenance

department. The top reported goals of such training were to have oper-

ators “assist maintenance during outages” (26 respondents), “replace

large motor air filters” (15), and “perform equipment oil changes”

(14). The two tasks for which maintenance craft workers were surely

grateful for operators’ help were “change light bulbs” (20) and “clean

the plant” (18).

To cover the other end of the spectrum, the study also asked re-

spondents whether they are increasingly asking maintenance work-

ers to perform “crossover” tasks traditionally done by operators. The

overwhelming response (93%) was “no,” although three plants did

note that their boiler water monitoring is done by chemistry/environ-

mental techs, and their daily chemistry by I&C techs. Clearly, the

trend is to train operators to perform more maintenance-related tasks,

rather than to train maintenance workers to handle more operations

chores.

The survey responses were mixed on whether in-house and con-

tracted craft workers were assigned jointly to maintenance tasks

(comingling). Fifty-three percent of respondents said that is common

practice, but only on a straight-time basis.

The detailed maintenance staffing survey has several layers of data

that can be sliced and diced by study participants. Let’s begin explor-

ing them by delving into the details of maintenance craft and full-time

contractor head count by plant size. (Remember, only by participat-

ing in the study can you gain access to all the raw data you’ll need to

benchmark yourself against your peers.)

Figure 1 illustrates the full-time craft maintenance head count at

small plants (<499 MW) in the reporting sample, identified by com-

pany and contractor. To enable comparisons on an apples-to-apples

basis, head counts include I&C and full-time contractors but exclude

supervisors, planners/schedulers, regional maintenance workers,

plant cleaners, occasional contractors, and non-craft maintenance

personnel. Figure 2 shows the maintenance craft head counts at

plants rated between 500 MW and 999 MW, Figure 3 shows the

0

20

40

60

80

90

70

50

30

10

55 57

71 72

83Company Contractor

Hea

d co

unt

29 34 26 43 38 45 4 21 36 7 6 15 41 18 27 44

18

34

Note: Red stars represent plants with >90% equivalent availability factor. Patterned bars represent units with a scrubber. Green triangles indicate units that burn more than 50% coal or lignite.

Plant code

37 3942 42 43 44

47 48 51

2. Full-time maintenance craft head counts at plants rated between 500 MW and 999 MW. Source: EUCG

6.5

1012

1312 1315

17

21

2729

4040

35

30

25

20

15

10

5

0

Hea

d co

unt

Company Contractor

33 20 31 37 13 25 39 2 22 19 35 11Plant code

Note: Red stars represent plants with >90% equivalent availability factor. Patterned bars represent units with a scrubber. Green triangles indicate units that burn more than 50% coal or lignite.

1. Full-time maintenance craft head counts at plants smaller than 499 MW. The plant codes shown were assigned to

respondents to ensure their anonymity. Source: EUCG

0

50

100

150

200Company Contractor

128 132145

181 182

Hea

d co

unt

30 40 8 12 24

Note: Red stars represent plants with >90% equivalent availability factor. Patterned bars represent units with a scrubber. Green triangles indicate units that burn more than 50% coal or lignite.

Plant code

4. Full-time maintenance craft head counts at plants larger than 2,000 MW. Source: EUCG

0

20

40

60

80

100

120 Company Contractor

Hea

d co

unt

28 5 10 3 32 23 1 9 17 42 16 14

37

43

Note: Red stars represent plants with >90% equivalent availability factor. Patterned bars represent units with a scrubber. Green triangles indicate units that burn more than 50% coal or lignite.

Plant code

6366

71 73

82 85

99

112 115 117

3. Full-time maintenance craft head counts at plants between 1,000 MW and 1,999 MW. Source: EUCG

Page 50: Powermag200802 Dl

POWER | February 200848

BENCHMARKING

counts for plants between 1,000 MW and

1,999 MW, and Figure 4 reflects plants larg-

er than 2,000 MW. The plant codes shown

below the bars were assigned to respondents

to ensure their anonymity.

Maintenance craft head count appears

to be a function of the number of units in a

plant, but only up to a point. For example,

Figure 5 shows that head count varies widely,

but—not unexpectedly—increases sharply

when a plant has larger units. Higher head

counts also seem to be the case for plants

configured with FGD systems.

The study results also indicate that some

plants cross-train their I&C technicians to

Plant capacity: <500 MW 500–999 MW 1,000–2,000 MW >2,000 MW

Hea

d co

unt

20 31 25 2 29 19 34 38 4 36 39 22 35 28 11 5 6 15 32 44 42 13 26 43 41 3 27 1 30 8 24 37 7 10 18 40 12 33 45 9 21* 16 17 23 14

Note: Patterned bars represent units with a scrubber.Plant code

200

180

160

140

120

100

80

60

40

20

0

1 unit 2 units 3 units 4 units 5 6 9 10

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5. Full-time maintenance craft head count by number of units per plant. Source: EUCG

CIRCLE 17 ON READER SERVICE CARD

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February 2008 | POWER 49

make them combination I&C techs/electricians, or IC&Es. Figures 6

through 9 show the head counts for this craft category in the same four

plant size categories as Figures 1 through 4 for full-time maintenance

craft personnel. The next layer of survey detail, available only to survey

participants, correlates I&C head count with the presence of a DCS

and an FGD system. The IC&E staffing strategy was found to be more

prevalent in smaller plants than in larger plants.

0

2

4

6

8

10

1

2

3 3

4 4

5 5 5

6

9

10

Hea

d co

unt

13 33 2 37 20 31 22 25 39 19 35 11Plant code

I&C IC&E

6. Full-time I&C and IC&E (I&C/electrician) craft head counts at plants smaller than 499 MW. Source: EUCG

0

3

6

9

12

15

Hea

d co

unt

29 43 45 21 26 36 7 41 15 27 34 4 18 38 6 44Plant code

I&C IC&E

5 5 5

7 7 78

910 10 10

11 11 11 11

14

7. Full-time I&C and IC&E head count at plants rated between 500 MW and 999 MW. Source: EUCG

0

5

10

15

20

Hea

d co

unt

5 28 9 10 23 3 1 14 32 17 16 42

Plant code

I&C IC&E

67

89 9

10

13

16 16 1618

19

8. Full-time I&C and IC&E head counts at plants be-tween 1,000 MW and 1,999 MW. Source: EUCG

0

5

10

15

20

25

Hea

d co

unt

24 8 30 40 12Plant code

I&C IC&E

14

18 18 18

24

9. Full-time I&C and IC&E head counts at plants larg-er than 2,000 MW. Source: EUCG

BENCHMARKING

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POWER | February 200850

BENCHMARKING

The leadership factorHiring craft journeymen, either to add expertise to a plant’s workforce

or to fill staff vacancies, will not be productive unless the workers are

well-supervised. Accordingly, the survey asked each of the 45 respon-

dents to state their plant’s “supervisory ratio”—the number of craft

workers (in-house craftsmen, I&C and IC&E techs, and apprentices)

divided by the number of managers, general foremen, and craft su-

pervisors. Eight plants reported their ratio as 10 or greater; one plant

reported a ratio of 19; the median was 7.3.

The survey asked the same question about the ratio of craft workers

to planners/schedulers. The median reported was 13.3, although the

data ranged from 30 to as low as three, with a ratio of 48 disregarded

in the calculation.

Cost of doing businessGetting a handle on hourly wage rates is always difficult because raw

reported figures fail to take into account the local cost of living, fringe

benefits, and the range of union pay scales. However, the survey did

request raw hourly wage information by craft specialty. The results

(Figure 10) underscore the wide range of rates that plants are paying

for essentially the same skill set.

Straight-time wage rates are only a ballpark measure of craft costs

because overtime assignments can bust a budget for direct labor. In

this survey, 36% of respondents reported that overtime was typically

11% to 15% of the straight-time 40 hours/week, 29% reported that it

was 6% to 10%, and 9% reported that it was 21% to 25%.

Maintenance coverage (the number of hours in a day when a main-

tenance staff is on duty) varied pretty much linearly by plant size.

Small plants (<499 MW) generally had 40 hours/week of coverage,

but two plants reported coverage of 96 hours/week. Plants larger than

1,000 MW tended to have two-shift coverage, although roughly one-

third reported still using single shifts of maintenance workers. Plants

larger than 2,000 MW tended to have two- or three-shift coverage, but

the mix of specific shift schedules and craft specialties varied signifi-

cantly among plants.

Filling the craft poolThe final survey questions asked about minimum requirements for en-

try-level positions in power plant maintenance. Of responding plants,

21 said new hires only had to be high school graduates, 13 required

the candidate to have a trade school diploma, and seven insisted on

an associate’s degree. More than three-quarters of respondents (76%)

reported having a formal maintenance apprenticeship program in

place, although some required new hires to work as a helper for one

year before entering the program, to avoid breaking company senior-

ity rules. Over half of the respondents (54%) said their maintenance

apprenticeship program lasts 37 to 48 months. ■

—Robert Oldani ([email protected]) is a plant performance manager at DTE Energy

and a member of the EUCG’s Fossil Productivity Committee.

$23.00–$25.99 $26.00–28.99 $29.00–31.99 ≥$32.00

MSmechanical

1

Mechanicaltech

1

Electricaltech

1

GeneralMS

12

5 5

Electrician

8

17

3

I&C

9

18

11

IC&E

2

4

6

Machinist

3

13

1

Pipefitter

10

Plumber

1

Ironworker

5

Certifiedwelder

3 3

12

1

MSelectrical

2

12

7

Mechanic

20

15

10

5

0

Notes: C&M = Controls and mechanical, MS = Multiskilled.

Res

pons

es

1

C&M

10. Reported hourly wage rates for craft maintenance workers. The numbers atop the bars indicate the number of responses

received for the specific specialty and wage rate range. Source: EUCG

CIRCLE 19 ON READER SERVICE CARD

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February 2008 | POWER www.powermag.com 51

GAS PIPELINE SAFETY

The case for cathodic protectionAll fossil fuels carry some risk with their reward of an energy density that’s

sufficient for producing electricity economically. For coal and natural gas, that threat is a fire or explosion. However, the risk of an explosion isn’t limited to gas-fired plants. Gas poses a threat to any plant that uses the fuel, even in small quantities for heating. Here’s an overview of what you should be doing to keep gas pipelines from corroding and exploding.

By Ted Huck, Matcor Inc.

It’s only a matter of time before someone

in a power plant is killed by a preventable

catastrophic failure of a buried natural gas

pipeline. The danger posed is less the result

of willful negligence than of the temptation

to ignore an invisible problem.

Safety has long been a primary concern

of U.S. industry, particularly in the power

generation sector. Today, on a tote board at

their entrances, many plants proudly display

a running count of the number of work days

accumulated without a lost-time accident.

All employees must attend numerous safety

training seminars, not only because the U.S.

Labor Department’s Occupational Safety &

Health Administration (OSHA) requires it,

but also because most companies have come

to realize that safety is good for business.

Despite this attention, major threats still es-

cape detection by the risk radars of plant work-

ers and managers. One such threat is external

corrosion of underground natural gas pipe-

lines at all plants, not just those that convert

the fuel to electricity. According to decades

of statistics compiled by the U.S. Department

of Transportation’s Office of Pipeline Safety

(OPS), the leading cause of pipeline failures is

external corrosion of buried pipe.

The threat is so significant that the OPS

insists that pipeline operators take extensive

steps to minimize it. Such steps include in-

stalling sophisticated corrosion-prevention

systems (Figure 1), regularly maintaining

and testing those systems, and reporting the

results to regulators—a process the industry

calls “pipeline integrity management.” An

1. Laying pipe. This segment of a natural gas pipeline is being installed to serve a power plant. Operators are required by law to protect

their pipelines from corrosion that could compromise pipe integrity and lead to an explosion. But their responsibility for corrosion protection ends

at the isolation flange, where the line enters the plant through a metering station. Courtesy: Matcor

Page 54: Powermag200802 Dl

POWER | February 200852

GAS PIPELINE SAFETY

army of specialists, consultants, and service

providers supports the pipeline companies in

their efforts to mitigate corrosion.

This process does much to protect the pub-

lic from the devastating effects of a ruptured

pipeline, but it does little to protect plant

workers. That’s because pipeline operators’

responsibility for integrity management ends

at the metering station, where the pipeline

enters the plant. There, the pipeline company

installs a flange that electrically isolates its

regulated portion of the line and its corrosion

system from the final unregulated segment of

pipe. The isolation flange marks the physical

and legal transfer of responsibility for pipe-

line safety from the pipeline operator to the

plant owner.

Pipeline companies’ corrosion-preven-

tion measures take three forms: coating the

pipeline during its construction, installing

what’s known as a cathodic protection (CP)

system to keep stray currents from foster-

ing corrosion as the coating deteriorates, and

regularly testing the integrity of the pipe-

line and the performance of the CP system.

The tests include monthly inspections of the

system’s key components—rectifiers (Figure

2), annual testing to ensure that the operat-

ing environment hasn’t changed, and intense

surveying every seven to 10 years to validate

the pipeline’s physical integrity. If any de-

fects detected in the system are not reported

to regulators and fixed promptly, the pipeline

operator is fined.

Out of sight, out of mindRecently, I visited a power plant built around

1970. Unlike many plants of that vintage, the

“inside the fence” portion of this plant’s gas

pipeline was coated and equipped with a CP

system to keep corrosion at bay. But although

my hosts showed me the detailed drawings

and other documentation supplied as part of

the installation, no commissioning report was

available, and the plant’s maintenance files

lacked any test data to confirm that the system

had ever worked properly. That didn’t surprise

me as much as it probably shocks you. At too

many power plants built with a pipeline CP

system, the system is installed and turned on

but never inspected or tested later.

At the plant I visited, the CP system was

neglected because it was forgotten. I talked

to some veteran maintenance personnel who

knew where the rectifiers were located and to

one technician who checked them occasion-

ally to see if they were still on. But there was

no rigorous testing of the system, and no pro-

cess was in place to balance the outputs of

individual rectifiers to optimize the system’s

compensation for coating deterioration. I at-

tribute those shortcomings not to negligence

on the part of workers or management but

rather to the sad fact that CP of buried gas

pipelines is not a priority at a competitive

power plant.

Finally, after operating with this risk for

more than 35 years, the plant hired a knowl-

edgeable CP service company to test the sys-

tem. Management took this step not for safety

reasons but as part of an unrelated corporate

environmental initiative to minimize the po-

tential for fuel oil leakage from two large,

above-ground storage tanks. The results were

predictable: the CP system installed in 1970

no longer worked because it had several

inoperable rectifiers and depleted anodes.

What the tests could not say, however, was

when the system had stopped working—or

even whether it had ever been functional.

What I found most disturbing about the CP

service company’s report was that it did not

identify the unprotected buried gas pipeline

as a threat to the plant’s personnel and as-

sets. Unfortunately, this “out of sight, out of

mind” attitude is all too common in the U.S.

power industry. At too many power plants,

the “contractor-grade” CP systems installed

to protect buried gas pipelines are neither

maintained nor tested. As the plants age and

pipeline coatings deteriorate, external corro-

sion becomes a very serious threat.

No time to loseWhat can power plants do to prevent failures

of their buried gas pipelines? Matcor recom-

mends taking the following basic steps:

■ Research your plant’s construction. Was

a CP system originally installed? Do you

have a copy of the original CP system ac-

ceptance test report?

■ Talk to your maintenance personnel. What

do they know about the plant CP system?

Do they inspect it periodically? Are they

maintaining good records? Has a third-

party expert been retained to advise them

and to validate the system’s performance

on a regular basis?

■ Develop a plan and budget for testing your

system and submit it to management. Be

sure the proposal emphasizes the dire and

expensive consequences of a catastrophic

gas pipeline failure inside the plant.

■ Hire a qualified expert to develop a budget

for thoroughly testing your existing CP

system and upgrading it to good working

condition. Make sure that the recommend-

ed test protocols meet criteria established

by NACE, formerly known as the National

Association of Corrosion Engineers.

■ Implement your own pipeline integrity

plan. A good initial resource for develop-

ing the plan is your natural gas provider,

which has a corrosion technician respon-

sible for your supply line up to your iso-

lation flange, as well as an integrity plan

that can be partially emulated. For exam-

ple, above-ground tools are available that

can detect signs of underground corrosion

and assess its severity.

■ Add a course on CP to your maintenance

training curriculum—a little knowledge

can go a long way.

In a subsequent article, I’ll explain in de-

tail how modern cathodic protection systems

work to mitigate the corrosion risks spe-

cific to power plants with buried natural gas

pipelines. Until then, I hope this article has

achieved its goal: alerting you to the very real

threats posed by unprotected gas pipelines.

Corrosion is a time-dependent phenomenon:

the longer you wait, the higher the risk. Giv-

en the deadly and costly consequences of a

natural gas explosion, why not act now? ■

—Ted Huck ([email protected]) is vice president of sales and marketing

for Matcor Inc.

2. Rectifying the problem. The key components of a pipeline’s cathodic protection

system are rectifiers like these. Courtesy: Matcor

Page 55: Powermag200802 Dl

February 2008 | POWER www.powermag.com 53

DISTRIBUTED GENERATION

Three years ago, Dennis Quinn, presi-

dent of what was then Seattle-based

Celerity Energy, proposed to San Diego

Gas & Electric Co. (SDG&E) that it develop

a “Clean Gen” program designed to upgrade

25 MW of existing backup generators to sup-

port the grid during times of peak demand.

Recognizing the value of the Clean Gen

program, in terms of both an operating cost

perspective and its ability to positively affect

SDG&E’s environmental impact, the utility

accepted Celerity’s proposal.

In May 2006, Celerity was acquired by

Boston-based EnerNOC Inc., a demand re-

sponse aggregator that has more than 900

MW of demand response capacity under

management.

Nonsmoking enginesThe Clean Gen program aggregates existing

backup generators and operates them during

periods of peak demand to support the elec-

tric grid and minimize blackout risk. Shortly

after partnering with SDG&E, Quinn and

the EnerNOC team signed contracts with

several end users to enroll their backup gen-

erators in the program. However, before it

could move forward, emissions had to be

addressed with San Diego County’s Air Pol-

lution Control District (APCD).

The APCD had concerns about 25 MW

worth of backup generators operating more

hours than their then-current permits would

allow because of the potential negative impact

on San Diego’s air quality. The APCD and

EnerNOC worked to identify filters that would

allow the generators to emit the same amount

of particulate matter or less in 200 hours as

they would have emitted in the normally per-

mitted 30 hours of operation per year.

Quinn and EnerNOC agreed to install

California Air Resources Board–approved

diesel particulate filters (DPFs) that would

reduce particulate matter emissions by over

85% (Figure 1). Another important ben-

efit of the DPFs is that they significantly

reduce carbon monoxide and hydrocarbon

emissions. In addition, recent California

regulations require the exclusive use of ultra-

low-sulfur diesel fuel.

Generators save the dayThe University of San Diego (USD) was the

first to come on-line in November 2006 with

three 2,000-kW diesel-fired Cummins gen-

erators. Not only does USD get payments

for the use of its generators, but EnerNOC

also has taken over responsibility for ongoing

generator maintenance, which, according to

Roger Manion, assistant vice president, facili-

ties management at USD, gives the university

a greater sense of security that its generators

will operate when needed. In addition, USD

is also notified when the grid is at risk, which

Aggregated backup generators help support San Diego gridLast year, San Diego Gas & Electric tapped Boston-based EnerNOC Inc. to

aggregate 25 MW of backup generators throughout SDG&E’s service area to relieve the grid when it’s stressed by peak demand for electricity. By combining stringent environmental controls with field-proven exper-tise managing distributed assets, EnerNOC has helped to improve grid stability in Southern California.

By Dr. Robert Peltier, PE

1. Nonsmokers only please. EnerNOC installs a California Air Resources Board–ap-

proved filter on each generator to reduce emissions. Both generators are running in this pic-

ture. The generator on the left shows post-installation air quality; the generator on the right

shows pre-installation air quality. Courtesy: EnerNOC

Page 56: Powermag200802 Dl

POWER | February 200854

DISTRIBUTED GENERATION

is important information for the managers of

a 7,600-student campus.

When an event is called, USD does not no-

tice the transition because the generators run

parallel with the grid. If there is a blackout de-

spite an event being called, USD won’t notice

because it will already be running on backup

generators. According to Les Young, senior

project manager at EnerNOC, “This is a great

aspect of the program because USD is not sub-

ject to a momentary outage if a program event

is called or the grid fails during an event.”

The San Diego County Water Authori-

ty’s (SDCWA’s) Olivenhain Dam facility

in Escondido, Calif., also enrolled its four

2,000-kW Caterpillar diesel generators in the

program (Figure 2). These generators, nor-

mally used to provide power to the facility’s

three 2,500-hp water pumps in the event of a

power failure, are the perfect fit for the pro-

gram: they’re big, powerful, and willing to

work. They are also set up in parallel with the

grid, so there is no interruption if a program

event is called or the grid blacks out.

EnerNOC didn’t stop with the USD and

SDCWA sites; it went on to include several

diesel generators from various San Diego

area wastewater treatment plants. All those

generators had open transition transfer

switches that would not allow EnerNOC to

use the full potential output of the generators,

because the loads running on the generators

were only a percentage of their nameplate

ratings. As a result, EnerNOC designed an

innovative “wrap around” breaker system

to parallel the generators with SDG&E. Ac-

cording to Young, this system picks up the fa-

cility load and then exports the excess power

back to the utility.

The “NOC” in EnerNOCTim Healy, EnerNOC’s chairman and CEO,

is proud of the company’s accomplishments.

When SDG&E calls an event, Healy’s team

in Boston at EnerNOC’s Network Operations

Center—the “NOC” in EnerNOC—springs

into action (Figure 3). The NOC sends auto-

mated dispatch information to all designated

facility managers informing them that their en-

gines will be remotely fired within 2 minutes.

NOC operators then initiate the event, which

automatically notifies customers and remotely

starts their generators. Within minutes, clean,

permitted generators from numerous sites re-

move 25 MW of load from the grid and help

SDG&E avoid blackouts and brownouts.

SDG&E can call an event during speci-

fied hours on any Monday through Saturday,

including holidays. However, there is a limit

on the total number of hours per year that

SDG&E can use Clean Gen.

“Remotely firing the engines is an added

service we provide,” says Healy. “In other

parts of the country it is not required that the

generators start so quickly, so we offer our

customers the option of firing the generators

up themselves or having us start them remote-

ly.” Because EnerNOC has invested millions

of dollars in its software to power the NOC, it

is not only capable of starting an engine in San

Diego with the click of a mouse in Boston,

but the NOC can also track and analyze elec-

tricity usage and manage demand response

events for thousands of locations across North

America simultaneously (Table 1).

2. Mighty generators. In this construction photo of Olivenhain Dam’s four 2,000-kW

Caterpillar diesel generators, the two generators on the right have the new filters installed; the

gensets on the left are awaiting the upgrade. Courtesy: EnerNOC

3. The “NOC” in EnerNOC. EnerNOC’s Network Operations Center in Boston is a

state-of-the-art facility that can dispatch thousands of assets across the U.S. and Canada. The

NOC is staffed 24/7/365—much like an ISO control room. Courtesy: EnerNOC

Page 57: Powermag200802 Dl

February 2008 | POWER 55

DISTRIBUTED GENERATION

Performance under fireOn October 24, 2007, the EnerNOC program

was put to the ultimate test. In response to

electricity shortages caused by multiple wild-

fires in southern California, the California In-

dependent System Operator declared a state of

emergency. With the overall electricity supply

in jeopardy, the NOC was notified and, within

minutes, the Clean Gen program was supply-

ing approximately 17 MW of electricity to the

grid. This event wasn’t the first time the pro-

gram had been called into action, but it was

the first time in an emergency situation, and

the results strongly validated the program.

“The Clean Gen program functioned just as

it was designed to, helping us to meet our needs

for increased electricity production through a

system of aggregated back-up generators,”

said Matt Burkhart, vice president of electric

and gas procurement for SDG&E. “The rapid

response of the EnerNOC team was especially

impressive and helped us address the situation

before the threat of brownouts became a seri-

ous concern.”

With field-proven effectiveness, even un-

der emergency circumstances, programs like

Clean Gen offer an innovative, economic

approach to tackling peak demand crises.

According to Healy, “A 100-MW aggregat-

ed backup generator program is cheaper to

build, cheaper to maintain, has no transmis-

sion losses, and takes just a few months to

build. On the other hand, a gas peaking pow-

er plant can be 60 times the capital cost, be

more expensive to run, and take three years

to build” (Table 2). ■

Peak (MW)

60,279

133,763

26,922

131,434

32,075

45,431

40,081

26,160

Date

8/23/05

7/26/05

7/27/05

8/3/05

7/26/05

7/20/05

6/27/05

7/13/05

Peak (MW)

63,065

144,796

28,021

136,520

33,939

50,270

42,227

27,005

Date

8/17/06

8/2/06

8/2/06

8/1/06

8/2/06

7/24/06

7/19/06

8/1/06

Growth

4.62%

8.25%

4.08%

3.87%

5.81%

10.65%

5.35%

3.23%

ERCOT

PJM

ISO-NE

MISO

NYISO

CAISO

SPP

IESO

ISO

2005 2006

100-MW demand

response network

100-MW gas peaking

plant

Capital cost $60,000,000

Total annualized cost $90/kW-year

Transmission losses 8%

Time to build 3 years

Siting

$900,000

$80/kW-year

None

3 months

Anywhere Limited

with Platts new suite of Electric Power System wall maps for the US

New U.S. Electric Power Suite of Maps include:Megawatt Daily Pricing RegionsU.S. Electric Power System Map & CD-ROMU.S. Utilities Service TerritoriesU.S. Power GenerationU.S. Transmission SystemNortheast Electric Power SystemERCOT Electric Power SystemN. America Electric Power System Atlas & CD-ROM*WECC Electric Power System*Coming August 2007

Visit www.maps.platts.com or call the Platts sales office at 1-800-PLATTS8Priority code: JSUDI0707A

Visualize the electric power industry

Table 1. Demand is skyrocketing. All across the country electricity demand is in-

creasing as a result of economic growth. In order to keep pace with this demand, certain

utilities and independent system operators (ISOs) are finding that demand response programs

help address the problem. Source: EnerNOC

Table 2. Demand response vs. peakers. Instituting a 100-MW demand

response program is considerably more

cost-effective than installing a 100-MW GE

LMS 100 in a constrained air shed. Source: EnerNOC

Page 58: Powermag200802 Dl

www.powermag.com POWER | February 200856

NEW PRODUCTS TO POWER YOUR BUSINESS

Remote temperature and humidity measurement TandD Corp. has just introduced the TR-72W recorder with an integrated Ethernet/LAN interface. The unit can serve as both a data logger and monitor of temperatures between 0C and 50C and relative humidity between 10% and 95%.

The TR-72W can be connected either to a wired 10/100 Base-T Ethernet local area network or to a wireless LAN using the 802.11b standard. Thanks to this connectivity, it can even send warning e-mails and text messages to cell phones.

With this introduction, TandD also released a new software tool that enables end users to configure their LAN to automatically upload recorded data from the logger. (www.tandd.com)

Seal off valved slurry flows Red Valve Co., Inc. recently announced a new slurry knife gate valve designed for heavy applications in the power industry.

When the Series DX valve opens, its reinforced elastomer sleeves seal against each other, providing a 100% port opening while minimizing turbulence that causes wear. The seats isolate and protect all metal parts of the valve from coming into contact with the slurry. When the valve is closed, the sleeves provide a drop-tight seal in both directions.

Each time the Series DX valve strokes, it discharges a small amount of slurry, keeping the gate path and seat area clear of trapped particulates. This valve’s unique action prevents slurry from building up in the seat area and possibly keeping the valve from closing. (www.redvalve.com)

Prep your pipe ends Esco Tool has introduced a right-angle end-welding preparation tool whose pneumatic clamping option provides for instant attach and release of various tubes and pipes in high-volume, repetitive work.

The Millhog Air Clamp is an air-operated cylinder that fits the firm’s small-diameter welding end prep tools for use on tube and pipe with an inside diameter of up to 3 inches. The tool features a self-centering draw rod that rigidly mounts into the tube or pipe. The clamping mechanism uses clamp ribs that automatically retract off the mandrel, reducing friction and wear.

The Millhog Air Clamp is designed to be used with Esco’s line of Ground, Tube Weasel, and Wart Millhog welding-end prep tools, which can bevel, face, and bore tubes simultaneously and in any orientation. (www.escotool.com)

Page 59: Powermag200802 Dl

February 2008 | POWER 57

NEW PRODUCTS

Inclusion in New Products does not imply endorsement by POWER magazine.

Intelligent gas detector certified to SIL 2 General Monitors’ TS4000 Intelligent Toxic Gas Detector, which provides protection against a wide range of hazardous industrial gases and oxygen deficiency, is now suitable for use in safety instrumented systems rated at Safety Integrity Level 2.

The TS4000 monitors gases such as ammonia, carbon monoxide, chlorine, chlorine dioxide, hydrogen chloride, hydrogen sulfide, nitric oxide, nitrogen dioxide, oxygen, ozone, and sulfur dioxide. It displays gas concentrations up to 500 ppm, fault codes for troubleshooting, prompts when calibration is needed, and provides complete status to the user. According to

the manufacturer, the TS4000 is easy to operate and maintain and reduces downtime by indicating remaining sensor life.

Some of the important features of the detector include remote mounting at up to 2,000 feet, dual-redundant Modbus communications, a three-digit display, and a 4-20 mA output. All electronics are contained within an explosion-proof housing so sensor information can be processed at the point of monitoring.

The TS4000 is easy to install and can be calibrated simply, by activating a magnetic switch and applying gas. An interface module processes information at the sensing site and

communicates detected gas values to the base unit for control and display. (www.generalmonitors.com)

Premise cable puller Arnco Corp. has introduced the Kati-Blitz device that makes it easy to pull premise cables into conduits, even under difficult conditions. The Kati-Blitz navigates curves and long sections of conduit, or piping where cables have already been laid.

At the heart of the Kati-Blitz is a unique Polykat fiberglass rod that can be hand-cranked in and out quickly without knotting or forming loops in the cable. Threaded rod ends are attached at both ends of the rod, where cable grips, pulling eyes, or guide heads can be screwed on easily and quickly. Available in lengths of 50, 100, and 150 feet, the Polykat rod is housed in a solid, heavy-duty case that is light, compact, and easy to handle. (www.arncocorp.com)

Lower-cost, maintenance-free silica monitoring According to ABB, the new Navigator 600 silica analyzer substantially reduces the amount of reagents and maintenance needed for silica analysis without compromising the accuracy or reliability of the process.

The instrument is said to use one-fourth the amount of reagents consumed by units from other manufacturers, greatly lowering annual reagent cost. Maintenance is reduced by features such as remote management, automatic calibration, and self-cleaning; together, they allow three months of unattended operation.

The unit can detect silica concentrations from 0 to 5,000 ppb. It is available in single- or multi-stream configurations (that enable up to six streams to be monitored sequentially) and can be configured for either continuous or sampled measurements. As a standard feature, the instrument provides current-loop and Ethernet outputs; Profibus DP V1 output is optional.

The Navigator 600 offers a choice of data display formats, including chart, bar graph, and digital indicator views. Historical logs give operators access to alarm, totalizer, and audit trail data. Process data and historical logs are securely archived to a removable SD card with a capacity of up to 2 GB.

The instrument also includes a built-in Ethernet communications link with onboard web and ftp servers. This feature enables remote monitoring, the choice of configuration, and web browser access to the analyzer’s data and log files. (www.abb.us)

Page 61: Powermag200802 Dl

Management • Technical • ContractNuclear • Fossil • Renewable • T&D

Sanford Rose Associates265 Main St. Akron OH. 44308

888-333-3828 • Fax [email protected]

Best Recruiters in Power!

General CounselLong Island Power Authority (LIPA), a cor-porate municipal instrumentality of the State of New York, seeks candidates for the posi-tion of General Counsel. This position will be responsible for providing legal advice, assis-tance and representation to the Authority as well as managing, monitoring, and coordinat-ing LIPA’s in-house staff and outside counsel. All candidates must be admitted to the New York State Bar and possess a minimum of 15 years experience handling complex legal mat-ters and experience handling legal matters involving the electric utility industry. Experi-ence advising or representing public agencies is preferred. LIPA offers a competitive salary and benefi ts package commensurate with ex-perience and responsibilities.Interested parties should immediately submit their cover letter, resume, and salary require-ments to:Ms. Barbara Ann Dillon,Director of Human Resources and AdministrationLong Island Power Authority333 Earle Ovington Blvd., Suite 403Uniondale, NY, 11553or to:[email protected] is an equal opportunity employer.

Opportunities in Operations and Maintenance,

Project Engineering and Project Management,Business and Project Development,

First-line Supervision to Executive Level Positions.Employer pays fee. Send resumes to:

POWER PROFESSIONALS

P.O. Box 87875Vancouver, WA 98687-7875

email: [email protected]

(360) 260-0979 l (360) 253-5292www.powerindustrycareers.com

POWER PLANTBUYERS’ MART

Jacobs, one of the “Most Admired Companies” in the industry (FORTUNEMagazine, 2007) is integral in creating the world of tomorrow as one of thelargest and most diverse providers of architecture, engineering, construction,and other professional technical services. We have the following opportunitiesavailable in our Raleigh, NC office where we serve clients in the power andcogeneration, and pharmaceutical industries.

Mechanical Engineers (IRC420)5-15 years experience in industrial plant environments, including power andthermal generation, process, and infrastructure systems and the developmentof P&IDs, PFDs, scopes of work, equipment specifications, and arrangementdrawings. Experience with design of boiler, steam turbine generator, and gasturbine generator systems required. PE preferred.

Electrical Engineers (IRC3183)10-20 years of experience in the design of medium to high voltage electricalsystems, including generator systems, substations, and transmission. PErequired. Experience in a leadership position preferred.

Structural Engineers (IRC3706)10-20 years experience in industrial plant design, with experience in concreteand structural steel design. Proficiency in analysis software such as STAAD orRAM required. PE required.

Jacobs offers competitive compensation and full benefits packages. Forconsideration and a complete listing of our career opportunities worldwide, visitour website at www.jacobs.com or send your resume and cover letter [email protected].

www.JACOBS.comJacobs Values Diversity and is an Equal Opportunity and Affirmative Action employer.

February 2008 | POWER www.powermag.com 59

Established in 1979 UDC stands as an industryleader in outage management, professional boilerinspection services, and educational training. Drivenby the demand for experience and expertise ofquality continuing education we developed our inplant training seminars. UDC offers excellence ineducational training for organizations in the powerindustry aspiring to achieve proven and effectiveresults. Each individual seminar focuses on issuesexperienced at your plant. All seminar sessions areconducted on-site at your location.

Seminar topics include Inspection Techniques andPractical Solutions for Prevention of Tube Failure.

“We are enjoying a great year from a reliabilitystandpoint and realize United Dynamics Corpora-tion contributed to this in a major way. We appre-ciate what you do and look forward to workingwith you again.” Current UDC Client

Elevate your inspection team to its greatest potential.Schedule your In House Seminar today!

United Dynamics Corporation2681 Coral Ridge Road

Brooks, KY 40109

502.957.7525

www.udc.net

READER SERVICE NUMBER 200

Page 62: Powermag200802 Dl

POWEREQUIPMENT CO.

444 Carpenter Avenue, Wheeling, IL 60090

wabash

24 / 7 EMERGENCY SERVICEBOILERS

20,000 - 400,000 #/Hr.

DIESEL & TURBINE GENERATORS50 - 25,000 KW

GEARS & TURBINES25 - 4000 HP

WE STOCK LARGE INVENTORIES OF:Air Pre-Heaters • Economizers • Deaerators

Pumps • Motors • Fuel Oil Heating & Pump SetsValves • Tubes • Controls • CompressorsPulverizers • Rental Boilers & Generators

847-541-5600 FAX: 847-541-1279WEB SITE: www.wabashpower.com

FOR SALE/RENT

READER SERVICE NUMBER 206READER SERVICE NUMBER 205

NEED CABLE? FROM STOCKCopper Power to 69kv; Bare ACSR & AAC Conductor;

Underground UD-P & URD, PILC-AEIC; Interlock Armor to 35kv; Copper Instrumentation & Control; Thermocouple

BASIC WIRE & CABLEFax (773) 539-3500 Ph. (800) 227-4292

E-Mail: [email protected] SITE: www.basicwire.com

READER SERVICE NUMBER 208

READER SERVICE NUMBER 203

CONDENSER OR GENERATOR AIR COOLER TUBE PLUGSTHE CONKLIN SHERMAN COMPANY, INC.

Easy to install, saves time and money.ADJUSTABLE PLUGS-all rubber with brass insert. Expand it,

install it, reverse action for tight fi t. PUSH PULL PLUGS-are all rubber, simply push it in.

Sizes 0.530 O.D. to 2.035 O.D.Tel: (203) 881-0190 • Fax:(203)881-0178

E-mail: [email protected] • www.conklin-sherman.com

OVER ONE MILLION PLUGS SOLDREADER SERVICE NUMBER 201

READER SERVICE NUMBER 207

Providing 30+ years of wide-range metallurgical processing for those seeking the most effective and effi cient results

possible. We wrote the book...

”Metallurgical Failures in Fossil Fired Boilers.” Full Service Metallurgical Lab

David N. French Metallurgists We specialize in boiler tube failures.

2681 Coral Ridge Road Brooks, KY 40109502.955.9847 www.davidnfrench.com

Life Assessment • Condition Assessment • Failure Analysis

Metallurgical service solutions with unsurpassed results!

GEGU's - 7.5 MW Guascor - natural gas fi red - 3/60/480 volts (Qty 2)

GTGU’s - 20 MW Brown Boveri oil fi red “cheap”

BOILERS - 200,000#/HR Combustion Engineering package - 600# steam pressure - gas fi red

- 25,000#/HR ABCO - 150# steam pressure -natural gas and propane fi red (Qty 4)

We buy and sell transformers, boilers, steam turbine generator units, gas turbine generator

units, diesel engine generator units, etc.

INTERNATIONAL POWER MACHINERY CO.50 Public Square - Terminal Tower, Suite 834

Cleveland, OH 44113 U.S.A.PH 216-621-9514/FAX 216-621-9515

Email: [email protected] Web: www.intlpwr.comREADER SERVICE NUMBER 202

www.powermag.com POWER | February 200860

Seeking Plant Documentation ProjectsFossil/GT/CC/SCR

Rapid Turnaround, Low OverheadOperating Procedures, Turnover Sets, Training

Rydnbok3318 Highway 5 Suite 269Douglasville, GA 30135

(678) 361-5299

[email protected] SERVICE NUMBER 204

Team Industrial Services 200 Hermann Drive

Alvin, TX 77511

Phone: 800-662-8326

Fax: 281-331-4107

E-mail: [email protected]

Web: www.teamindustrialservices.com

General Physics Corp25 Northpointe Pkwy, Ste 100

Amherst, NY 14228 USA

Phone: 716-799-1080

Fax: 716-799-1081

E-mail: [email protected]

Website: http://www.energy.gpworldwide.com

Corrections/Additions for 2008 POWER Buyers' Guide

POWER PLANT BUYERS’ MART

Page 63: Powermag200802 Dl

READER SERVICE NUMBER 215 READER SERVICE NUMBER 216

READER SERVICE NUMBER 214

Need a Thorough Mix?Ash, coal, sludges, what do You need to mix?

Get a thorough mix with:Pugmill Systems, Inc.

P.O. Box 60Columbia, TN 38402 USA

ph: 931/388-0626 fax: 931/380-0319www.pugmillsystems.com

READER SERVICE NUMBER 212

Norm Harty - The First and Last Word in Professional Dynamiting, serving you since 1964. We have pioneered, perfected and proven the methods of explosive cleaning the worst of s\lag or ash out in a matter of hours—in all boiler areas. We specialize in Electric Utility work and have over 4000 jobs to our credit. Call the NUMBER ONE COMPANY for the quickest response and most effi cient job for your emergency needs and scheduled outages.

N.B. Harty General Contractors, Inc.Phone: 573-624-4645 or 573-624-4588 ● Fax: 573-624-4589E-mail: [email protected] ● www.nbharty.com

READER SERVICE NUMBER 209 READER SERVICE NUMBER 210

George H. BodmanPres. / Technical Advisor

Offi ce 1-800-286-6069 Offi ce (281) 359-4006PO Box 5758 E-mail: [email protected], TX 77325-5758 Fax (281) 359-4225

GEORGE H. BODMAN, INC. Chemical cleaning advisory services for boilers and balance of plant systems

BoilerCleaningDoctor.com

READER SERVICE NUMBER 211

CFB Boiler • Steaming Capacity: 700,000 lb/hr of superheated steam • Pressure: 1250 psig • Temperature: 1000 °F at main steam stop outlet valve • Feedstock: PRB Coal Fabrication is partially complete. Reduce your project schedule by purchasing the rights to this CFB Boiler.

For complete details please contact:Keith Schick, 720-945-0641

For Sale

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POWER PLANT BUYERS’ MART

February 2008 | POWER www.powermag.com 61

Page 64: Powermag200802 Dl

READER SERVICE NUMBER 218READER SERVICE NUMBER 217 READER SERVICE NUMBER 219

SELECTIVE CATALYTIC REDUCTIONSYSTEM FOR PACKAGE BOILERS

Nationwide Boiler offers a new six-page bro-chure describing the design confi gurations, principle of operation and performance of their selective catalytic reduction system, CataStak™. Suitable for use with package boilers to 250K lb/hr., CataStak reduces NOx emissions to 6ppm and lower. Brochure includes comments from users from different industries regarding their experience with CataStak. [email protected]

PRODUCT Showcase

www.powermag.com POWER | February 200862

Page 65: Powermag200802 Dl

ADVERTISERS’ INDEXEnter reader service numbers on the FREE Product Information Source card in this issue.

Page

ReaderServiceNumber

CLASSIFIED ADVERTISINGPages 58–62. To place a classified ad, contact:

Myla Dixon, POWER magazine, 832-242-1969, [email protected].

February 2008 | POWER www.powermag.com 63

Applied Bolting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48. . . . . . . . 17 www.appliedbolting.com

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Martin Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15. . . . . . . . 10 www.martin-eng.com

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Roberts & Schaefer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29. . . . . . . . 15 www.r-s.com

Stanley Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10. . . . . . . . . 7 www.stanleyconsultants.com

Sturtevant Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13. . . . . . . . . 8 www.sturtevantinc.com

The Shaw Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 2. . . . . . . . . 1 www.shawgrp.com

Turbine Energy Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50. . . . . . . . 19 [email protected]

Ultra Tech . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9. . . . . . . . . 6 www.ultratechpipe.com

United Brotherhood of Carpenters . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27. . . . . . . . 14 www.carpenters.org

Worley Parsons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5. . . . . . . . . 4 www.worleyparsons.com

Zolo Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8. . . . . . . . . 5 www.zolotech.com

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www.powermag.com POWER | February 200864

COMMENTARY

What Congress can learn from GoogleBy Michael Shellenberger and Ted Nordhaus

Chances are good that legislation to “cap and auction” green-house gas (GHG) emissions will become law as early as 2009. While many environmentalists, utilities, and energy compa-

nies agree that cap and auction is the right framework, huge dif-ferences remain. Environmentalists want an 80% reduction of GHG emissions by 2050, or sooner. Energy companies want more modest reductions and for pollution allowances to be given away rather than auctioned. The energy lobby will likely favor, and environ-mentalists oppose, a “safety valve” to prevent the price of carbon dioxide (and thus the cost of energy) from rising too high.

Though the regulatory aspects of managing greenhouse gases are important, the biggest reductions in emissions won’t come from regulations but from technology innovations that lower the price of clean energy. The opportunity for agreement between industry and environmentalists lies in using revenues from auc-tioning emissions allowances to fund major investment in clean energy technology and infrastructure. But before describing what this win-win might look like, we need to understand the lessons of the Kyoto treaty.

The failure of KyotoMany environmentalists believe that Kyoto’s failure is due to Bush administration opposition to it. This story gives too much credit to the U.S. and too little responsibility to the wealthy nations that ratified Kyoto. The latter saw their GHG emissions go up, not down, by 4% from 2000 to 2004. In Britain and Germany, emis-sions fell not because of Kyoto but because Margaret Thatcher broke the coal miners’ union, moving Britain to cleaner-burning natural gas, and because the East German economy collapsed af-ter the fall of communism, reducing a reunified Germany’s reli-ance on dirty coal plants. When you remove Germany and Britain from the calculation, European emissions rose 10% between 1990 and 2005. The reality is that Europe hasn’t reduced its emissions because its policymakers fear the backlash that will result from higher energy prices and slower economic growth.

U.S. lawmakers considering cap-and-auction legislation will soon face the same challenge as lawmakers in Europe: increase energy prices too much and face a public backlash; increase them too little and have no impact on emissions. This is the heart of the Kyoto problem. For regulations to work, the price of fossil fu-els must increase enough that clean energy alternatives become cost-competitive.

“Renewable Energy Cheaper than Coal”There is a better way. Instead of making clean energy relatively cheaper, a new, post-Kyoto agreement should focus on making clean energy absolutely cheaper. The right model comes not from past efforts dealing with pollution problems but rather from in-vestments in technology innovation and infrastructure. Silicon Valley, we often forget, was largely built on U.S. government contracts. In the 1950s, the Pentagon guaranteed the market for

computer microchips, driving the cost of a single microchip down from $1,000 to $20 in less than a decade. Before that the Penta-gon subsidized radio. And the Internet’s precursor was invented in a Defense Department lab.

Perhaps because they know this history, some Silicon Valley executives and investors seem to understand the energy challenge better than policymakers. In November, Google announced a “Re-newable Energy Cheaper than Coal” initiative to invest hundreds of millions of dollars in wind and solar power. But achieving this objective requires a global investment in the hundreds of billions, not millions. What would happen if Europe and the U.S. guaran-teed the market for silicon solar panels—as we did with silicon microchips? We know that for every doubling of production of so-lar panels, price drops 20%. Experts say it would cost $50 billion to $200 billion to make solar power as cheap as coal power.

Solar and wind are just part of the solution. What’s needed is a portfolio of investments made by the world’s wealthiest coun-tries. The U.S., Europe, Canada, Australia, and Japan should cre-ate a 10-year, $1 trillion energy fund to invest in a range of technologies—including geothermal, efficiency, carbon capture and storage, nuclear, low- to zero-emissions technologies, and other advanced energy technologies—many of which (like solar) would be manufactured in China. The prospect of substantial new investment might persuade China to adopt some emissions limits or even a carbon tax.

Raising the moneyWhether through auctioning permits or taxing carbon dioxide di-rectly, federal carbon regulation can potentially generate tens of billions of dollars annually for clean-energy investments. These investments should include dramatic increases in funding for ba-sic research in the energy sciences, a 10-year commitment to buy down the price of solar technology and battery and other energy storage technologies, and a commitment to build a smarter and more efficient electricity grid.

Just before the Bali climate change conference last December, more than three dozen Nobel laureates and energy scientists sent an open letter to presidential candidates and members of Congress calling for a minimum of $30 billion per year. Just as past public investment in railroads, highways, microchips, the Internet, com-puter science, and the medical biosciences triggered billions in pri-vate investment, and paid for themselves many times over, so will new investments in energy. One econometric analysis found that a $300 billion investment would pay for itself in 10 years through energy savings, economic growth, job creation, and profit taking.

It’s time for a new energy strategy that aligns economic and ecological interests and appeals to the aspirations of both devel-oped and developing nations. ■

—Ted Nordhaus and Michael Shellenberger are co-authors of Break Through: From the Death of Environmentalism to the Politics

of Possibility, and founders of the Breakthrough Institute.

Michael Shellenberger Ted Nordhaus

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