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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
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Established 1882 • Vol. 152 • No. 2 February 2008
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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 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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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
February 2008 | POWER 7
GLOBAL MONITOR
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
POWER | February 20088
GLOBAL MONITOR
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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February 2008 | POWER 9
GLOBAL MONITOR
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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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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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
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
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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(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
February 2008 | POWER 17
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
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
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CIRCLE 11 ON READER SERVICE CARD
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
POwer Mag Ad 2008.eps 1/23/2008 8:26:53 AM
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CIRCLE 12 ON READER SERVICE CARD
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
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CIRCLE 13 ON READER SERVICE CARD
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
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
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
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CIRCLE 14 ON READER SERVICE CARD
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. ■
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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
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.
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
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
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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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
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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.
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
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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CARBON CAPTURE
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
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.
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
BURNPRBCOAL?VISITwww.powermag.com/prb101
PRBCOAL 101
SPONSORS:
International, Inc.®
for an overview of the requirements to safely and efficiently use Powder River Basin coal.
Organized by:
PLANT DESIGN
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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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.
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
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
www.appl iedbolt ing.com email: [email protected] 1413 Rockingham Rd. Bellows Falls, VT 05101 USA
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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
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
CIRCLE 18 ON READER SERVICE CARD
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
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
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
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
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
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
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)
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)
www.powermag.com POWER | February 200858
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
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
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
READER SERVICE NUMBER 213
POWER PLANT BUYERS’ MART
February 2008 | POWER www.powermag.com 61
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
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
Babcock and Wilcox . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 4. . . . . . . . . 4 www.babcock.com
Benetech . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23. . . . . . . . 13 www.benetechusa.com
Columbus McKinnon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14. . . . . . . . . 9 www.cmindustrial.com
Hitachi Power Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 3. . . . . . . . . 2 www.hitachi.com
Martin Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15. . . . . . . . 10 www.martin-eng.com
Membrana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21. . . . . . . . 12 www.liqui-cel.com
Paharpur Cooling Towers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49. . . . . . . . 18 www.paharpur.com
Panasonic Toughbook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19. . . . . . . . 11 www.panasonic.com/toughbook/utilities
Power Systems Mfg. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35. . . . . . . . 16 www.powermfg.com
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
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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