powermag201004 2 dl

Ap

ril 2010 • Vo

l. 154 • No

. 4

Vol. 154 • No. 4 • April 2010

Wind Destroyed and Now Powers Greensburg, Kansas

Biomass Cofiring at OPG

Benchmarking Nuclear Plant Staff

RO Plant Treats Brackish Water

Optimize Fleet Operations

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Some folks called it “the devil’s rope,” but there’s no

denying that barbed wire revolutionized the American

west in the 1860s. And RENTECH Boiler Systems has revolutionized the boiler industry

with its direct fired boilers, headered membrane waterwall design, and customer service. We think

you will cotton to our boilers because they will lower operating costs, reduce shutdowns and cut

emissions. So carve G.T.T. (gone to Texas) on your door and head to Abilene to discover solutions

to your boiler needs.

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BOILERS FOR PEOPLE WHO KNOW AND CARE

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April 2010 | POWER www.powermag.com 1

ON THE COVERGreensburg, Kansas, was destroyed by an EF5 tornado on May 4, 2007. The town has since rebounded and now faces a promising future as a model of sustainability. Citizens are rebuilding the town, literally from the ground up, using modern energy efficiency tech-niques and renewable power sources, including wind, photovoltaic, and geothermal tech-nologies. Photo source: National Renewable Energy Laboratory

COVER STORY: REnEwablES24 wind Destroyed and now Powers Greensburg, Kansas

When a tornado flattened Greensburg in 2007, residents resolved to rebuild the town and make it stronger than ever. Three years later, it is well on its way to becoming a showcase for energy efficient buildings and 100% renewable energy power supplies. The master plan not only puts Greensburg on the forefront of sustainable design and energy practices but also ensures a livable community for future generations.

SPECIal REPORT COfIRInG bIOmaSS30 OPG Charts move from Coal to biomass

Ontario’s plan to phase out coal-fired generation by the end of 2014 has prompted Ontario Power Generation to take the lead in evaluating its fuel-switching options. Its testing program has identified a number of issues that require attention and invest-ment to enable safe, commercial operation with 100% biofuels. Its experience also points to possible physical equipment modifications and operational changes that might be required of other plants considering this switch.

fEaTURES bEnCHmaRKInG42 benchmarking nuclear Plant Staffing

Survey data provided exclusively to POWER by the EUCG Nuclear Committee pro-vides valuable top-line results about how the industry continues to do more with less. You’ll find trends for average number of workers per plant, generating cost per worker, staffing levels per unit of installed capacity, worker productivity, and more.

SYSTEm PlannInG46 a Primer on Optimizing fleet Operations

Whether you are responsible for a fleet of two or 20 power generating units, the abil-ity to operate and dispatch those resources in the most cost-effective way demands that you engage in short- and mid-term optimization—first at the plant level and then at the fleet level. Begin with a bottom-up approach that leverages one optimization tool that every fleet already has at its disposal.

PlanT DESIGn51 Enhanced Condenser Tube Designs Improve Plant Performance

If someone told you that replacing plain condenser tubes with advanced technol-ogy condenser tubes would cost more but would pay for itself in just weeks, would you consider the option? The detailed economic analyses and demonstrations of performance improvements provided in this article should give you good reason to answer, Yes.

24

Some folks called it “the devil’s rope,” but there’s no

denying that barbed wire revolutionized the American

west in the 1860s. And RENTECH Boiler Systems has revolutionized the boiler industry

with its direct fired boilers, headered membrane waterwall design, and customer service. We think

you will cotton to our boilers because they will lower operating costs, reduce shutdowns and cut

emissions. So carve G.T.T. (gone to Texas) on your door and head to Abilene to discover solutions

to your boiler needs.

Fired Package Boilers / Wasteheat Boilers / HRSG Maintenance & Service Strategies / Boiler Repair Services / SCR and CO Systems

BOILERS FOR PEOPLE WHO KNOW AND CARE

WWW.RENTECHBOILERS.COM

Established 1882 • Vol. 154 • No. 4 April 2010

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www.powermag.com POWER | April 20102

Meeting the Energy Challenge—One Power Plant at a TimeWhile others are talking about clean-energy

solutions, Shaw is building some of the most effi cient Shaw is building some of the most effi cient

power plants in the world—including the nation’s fi rst power plants in the world—including the nation’s fi rst

new nuclear plants in 30 years, featuring Westinghouse’s new nuclear plants in 30 years, featuring Westinghouse’s

AP1000™ design. Along with providing cleaner sources of AP1000™ design. Along with providing cleaner sources of

energy through nuclear power, Shaw uses advanced gas energy through nuclear power, Shaw uses advanced gas

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WATER TREATMENT56 Sub-Sea Water Treatment System Provides Reliable Supply for the Huarun

Power PlantAs water supplies around the world become more constrained with growing popu-lations and industrial development, the use of water for power generation will con-tinue to attract greater scrutiny. Plants in China are developing one solution to the problem by using a two-step process that turns brackish water sources into boiler-friendly water supplies.

TRANSMiSSioN & DiSTRibuTioN61 Smart Grid: on the Money

Aside from the entrenched roadblocks to siting new transmission lines in the U.S., another barrier to developing a stronger, smarter grid is the conundrum of who should pay for improvements and how. One way to make the case for the cost is to demonstrate the benefits of grid improvements. A new project estimating tool may help make that case. Meanwhile, other countries are getting smarter grids faster—and beginning to reap the benefits.

DEPARTMENTS SPEAKiNG oF PoWER 6 What’s bugging Me

GLobAL MoNiToR 8 u.S. Spins Nuclear Wheels as other Nations Roll out New Plants10 initial Experiments Meet Requirements for Fusion ignition11 From GHG to useful Materials12 Marines Get Power from Waves12 Permeable uK Granite is Good News for Geothermal Energy 12 Dish Stirling Solar Plant Debuts14 PoWER Digest

FoCuS oN o&M16 Deciphering Desuperheater Failures19 Competitive Maintenance Strategies, Part ii

LEGAL & REGuLAToRY22 Gridlock Continues for Grid Policy

By Brian R. Gish of Davis Wright Tremaine

64 NEW PRoDuCTS

CoMMENTARY 72 Rethinking the Power industry’s Dash to Gas

By Bert Kalisch, president and CEO of the American Public Gas Association

61


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Meeting the Energy Challenge—One Power Plant at a TimeWhile others are talking about clean-energy

solutions, Shaw is building some of the most effi cient Shaw is building some of the most effi cient

power plants in the world—including the nation’s fi rst power plants in the world—including the nation’s fi rst

new nuclear plants in 30 years, featuring Westinghouse’s new nuclear plants in 30 years, featuring Westinghouse’s

AP1000™ design. Along with providing cleaner sources of AP1000™ design. Along with providing cleaner sources of

energy through nuclear power, Shaw uses advanced gas energy through nuclear power, Shaw uses advanced gas

turbine, air quality control and clean coal technologies to turbine, air quality control and clean coal technologies to

construct cutting-edge fossil-fi red power plants.construct cutting-edge fossil-fi red power plants.

For clean, safe, economical power, choose excellence. Choose Shaw.

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SPEAKING OF POWER

What’s Bugging MeI’m often asked about my source of ideas

for this space each month. I have two primary sources of subject material.

First, I read the industry news every day and save those items that either annoy or agitate me. At the end of the month, I go over the list, often a long one, and pick the one item that immediately motivates me to take virtual pen to paper. This month, no single item emerged as the topic for my bully pulpit, so I present a potpourri of loosely connected topics for your con-sideration. (It should be noted that other things bug other members of the editorial staff; we’re a diverse group and do not al-ways agree about industry issues.)

Foreign Corporate InfluencesThe American Clean Energy and Security Act (H.R. 2454), a.k.a. Waxman-Markey, is frozen in the U.S. Senate, and the recent “climategate” revelations will help keep it in the deep freeze. However, several enormous non-U.S.-based engineered-equipment conglomerates continue to support lobbying organizations that seek passage of this legislation. The email stream is unending. Why is that? Could it be that Waxman-Markey manufactures new and potentially lucrative “business opportunities” that will surely ship fat profits earned in the U.S. (your tax dol-lars) overseas?

Another interesting press release ar-rived this month from the Investigative Reporting Workshop. That group found that 79% of the more than $2 billion in stimulus payments for wind turbine equipment so far went to foreign manu-facturers. Both trends are a slap in the face of U.S. manufacturers.

Every Media Release Is Now Greenwashed The number of organizations cloaking themselves in green to shape market perceptions is increasing every month. One of my favorite press releases was a company that sells recycled motor and industrial oil burner systems. The “fuel” for the boiler burners was described as “renewable,” making the oil burning system a “green” technology. This logic

leap defies gravity. In a similar fashion, a pro-nuclear group sent out a press re-lease calling for 40 new nuclear plants by 2035 titled “Nuclear Power: A Green Technology.” There’s an old tailor’s ad-age, modified slightly for the occasion: “If a man wants a green suit, turn on a green light.” Marketeers: Green is going out of fashion this year.

Green Jobs Are a ChimeraAn online story at fastcompany.com in January 2009 presented the magazine’s list of the top 10 green jobs in the com-ing decade: farmer, forester, solar power installer, energy efficiency builder, wind turbine fabricator, conservation biolo-gist, green MBA and entrepreneur, recy-cler, sustainability systems developer (IT geek), and urban planner. Stimulus funds were advertised as an investment in new green jobs, but federal government stim-ulus funds are by design short-lived, and the hype of green jobs has subsided.

I don’t see millions of newly formed, “highly paid” green jobs but rather a natural progression of existing jobs in transitional industries—redeploying exist-ing, not new, skills according to market forces.

Instead, how about building a few nu-clear plants each year that will generate tens of thousands of new jobs along the entire nuclear supply chain—jobs that will last for generations. Those are the kind of “baseload” jobs this country requires.

Making MarketsFirst, the United States Climate Action Partnership (USCAP) wrote the white paper that later morphed into the cap-and-trade program in Waxman-Markey. Now the group has announced a renewed effort to kick-start the stalled legislation by initiating a new PR campaign. “The USCAP campaign will include a series of advertisements focusing on the connec-tion between action on climate and ener-gy legislation and U.S. jobs, the economy, and energy security.” What they failed to note is that BP America, ConocoPhillips, and Caterpillar finally recognized that the group’s agenda is unfair to American

industry and resigned their membership in mid-February.

I hope the remaining members will again put shareholders and consumers ahead of politics or market advantage. In my estimation, the organizations that remain in USCAP are merely engaged in rent-seeking—attempting to game the regulatory system to predetermine mar-ket winners and losers in a potential tril-lion dollar carbon market.

Carbon Bragging RightsCalpine finally sealed a deal with the Cal-ifornia Energy Commission for construc-tion of its new Russell City Energy Center, a 600-MW combined-cycle plant located near San Francisco. You may ask, “What’s so interesting about another combined-cycle plant?” Calpine voluntarily asked for and received a permit to emit CO2 from the facility.

Calpine spokesman Don Neal said, “Our idea was that we wanted to undertake a process for establishing (Russell City) that would be identical to what the EPA will require.” Last time I checked, the En-vironmental Protection Agency had yet to begin writing rules for combustion tur-bine CO2 limits, and its carbon rulemak-ing will be years in the making, if it ever happens. To meet the new limits, I ex-pect Calpine will try to minimize cycling and part-load operation, preferring base-load whenever possible; will judiciously perform the necessary operation and maintenance activities to ensure high combustion turbine efficiency; and will use the supplemental burners sparingly. But wait, that’s how combined-cycle owners already operate their plants.

Your Concerns?The second source of ideas for this col-umn is reader email. Will you share with me what concerns or excites you about the power industry? Send your short list to me at [email protected]. Keep it short, factual, and focused, and I promise to print the most interesting submissions.

—Dr. Robert Peltier, PE, is POWER’s editor-in-chief.

GE Energy / POWER Magazine / GEP9042 / IGCC Now Showing

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GE Energy / POWER Magazine / GEP9042 / IGCC Now Showing

GE Energy

Cleaner burning coal technology is here, and innovation from GE Energy is playing a leading role. IGCC offers a power solution that taps the globe’s abundant coal supply, while reducing emissions and enabling carbon capture retrofit. The largest cleaner coal facility in the world, Duke Energy’s 630MW IGCC Edwardsport, Indiana, power plant (now under construction), is advancing the evolution of proven IGCC technology to the next stage.

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U.S. Spins Nuclear Wheels as Other Nations Roll Out New PlantsPresident Barack Obama’s January State of the Union speech called for incentives to make clean energy profitable—mainly through the construction of a new genera-tion of nuclear power plants. That com-ment, an apparent effort to reach out to Republican members of Congress, drew furious applause. Within three weeks, the president’s backing of nuclear power had already made a significant impact on the U.S. nuclear sector.

In the week following the president’s speech, the administration’s freshly un-veiled Fiscal Year 2011 budget request for the Department of Energy highlighted a tripling of nuclear loan guarantees—$36 billion added to the $18.5 billion allot-ted by the Energy Policy Act of 2005 and $2 billion that was subsequently added for fuel cycle facilities. Energy Secretary Steven Chu went on record to say that the guarantees could support the con-struction of seven to 10 new reactors and promised that the first of two conditional offers would be made soon. And it was: With much fanfare, the president in mid-February announced conditional commit-ment for an $8.33 billion loan guarantee to Southern Co. for its expansion of Plant Vogtle in Georgia.

The budget also indicated the adminis-tration’s commitment to entirely withdraw the Yucca Mountain application from the Nuclear Regulatory Commission (NRC)—an effort that has cost some $9 billion since its inception in 1982. At the end of January, the DOE announced the formation of a Blue Ribbon commission, a 15-member body ex-pected to provide, within two years, rec-ommendations for developing a long-term platform to manage used nuclear fuel and nuclear waste. On March 3, the administra-tion did in fact file a motion to withdraw the Yucca Mountain license application.

Despite the open question of what to do with nuclear waste, on March 8, Secretary Chu announced awards of approximately $40 million in total to two international teams led by Pittsburgh-based Westing-house Electric Co. and San Diego–based General Atomics for conceptual design and planning work for the Next Genera-tion Nuclear Plant (NGNP). The results of this work will help the administra-tion determine whether to proceed with detailed efforts toward construction and

demonstration of the NGNP. If success-ful, the NGNP Demonstration Project will demonstrate high-temperature gas-cooled reactor technology that will be capable of producing electricity as well as process heat for industrial applications and will be configured for low technical and safety risk with highly reliable operations.

U.S. Nuclear Plans in Reverse. Could these rapid-fire developments perk up the fading dream of a U.S. nuclear renaissance? It is too soon to tell, though momentum has been building in the opposite direction.

In January, for example, Progress En-ergy suspended plans for four new Florida reactors, after a state commission denied requests for electricity rate hikes. Last August, the Tennessee Valley Authority scrapped plans for three new reactors in Alabama and delayed a fourth by at least four years. Reactors have also been can-celed in Texas, Missouri, and Idaho, and applications for combined construction and operation licenses have been suspended in Mississippi, Louisiana, and New York. Of the 26 new applications submitted to the NRC since 2007, nine have been canceled or suspended indefinitely, and 10 more have been delayed by one to five years.

Also, the White House has proposed bar-ring the DOE from research on fast breeder reactors that could recycle our repository of spent nuclear fuel. Energy Daily, a sister publication of POWER, reported on January 15 that the plan drew “protests from Energy Secretary Steven Chu that such prohibitions will have broad adverse effects, including hurting the U.S. nuclear industry’s renais-sance; crimping U.S. ability to influence other countries’ fast reactor designs to address proliferation concerns; and taking away nuclear waste disposal options that might be considered by the administration’s planned blue-ribbon panel on alternatives to the Yucca Mountain repository.” In a let-ter from Chu to the Office of Management and Budget dated Dec. 22, Chu said that he “strongly disagree[s] with the policy direc-tion [proposed by OMB] concerning allow-able nuclear energy R&D activities.”

Other Nations Are Lapping the U.S. Meanwhile, a global nuclear revival is well under way. From China to Brazil, more than 50 reactors are being built around the world, another 130 or more are planned to come online during the next 10 years, and more than 200 are further back in the pipeline, according to the World Nuclear Association. Several countries are quietly, but steadily,

pushing agendas to make nuclear power a major part of their future energy supplies.

India Betting on Local Talent. India is a prime example. That country’s efforts to keep up with its frenzied economic development include plans to build up to 20,000 MW in new nuclear capacity by 2020, and 63,000 MW by 2032. Those plans rely largely on indigenous designs; the country with meager uranium reserves has been pressing on with a unique long-term program that pushes for research and development of nuclear reactors using all three main fissionable materials: urani-um-235, plutonium, and uranium-233. The three-pronged program, developed largely during the country’s almost 30-year-long isolation from international nuclear trade,

1. Fast and furious. This 500-MW pro-totype fast breeder reactor is being built at Kalpakkam, in Tamil Nadu state, by federal enterprises Bharatiya Nabhikiya Vidyut Nigam (BHAVINI), Indira Gandhi Centre for Atomic Research, and the Nuclear Power Corp. of In-dia. On Dec. 5, 2009, the stainless steel main vessel was lowered into the safety vessel. The main vessel—12.9 meters in diameter, 12.94 meters high, and weighing 206 metric tons—will house the third and smallest inner vessel and associated components. The project has reportedly been delayed; it will now come on-line in 2011. Courtesy: BHAVINI


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also factors in India’s abundant reserves of thorium, which con-stitute 25% of the world’s total reserves.

Five reactors, of both indigenous and foreign design, are under construction, including a 500-MW prototype fast breeder reactor. That project, which is being built at Kalpakkam, near Chennai, in Tamil Nadu state, was expected to come online at the end of 2010, though it could be delayed a couple of months or up to a year, an unnamed source told the Business Standard in Febru-ary. The delays are being blamed on the lengthy commissioning of equipment that is “being made for the first time,” the source said. The main vessel was recently installed at the project, which is being spearheaded by federal research enterprise Bharatiya Nabhikiya Vidyut Nigam (Figure 1).

Meanwhile, the country keeps rolling out new plants. This February, for example, state-owned Nuclear Power Corp. of India Ltd. put into commercial operation a fifth unit at the Rajasthan Atomic Power Project, a 202-MW pressurized heavy water reac-tor (PHWR). A sixth unit at that plant, also a 202-MW PHWR, is currently undergoing testing, with commissioning expected this March (after this issue goes to press). The two reactors will bring the total number of operating nuclear reactors in India to 19 for a combined generating capacity of some 4,700 MW.

Will South Korea Come in Third? South Korea is also position-ing itself in the nuclear spotlight. Its most recent unit, Ulchin 6, came online in 2005, and the country hopes to provide 45% of its electricity from nuclear power by 2015. But it is also looking beyond its borders to build new plants.

Korea Electric Power Corp. (KEPCO) is in talks with multiple countries to explore exporting its nuclear plant construction ca-

pabilities. In March it signed a cooperative protocol to to es-tablish a nuclear power plant in the northern Turkish province of Sinop. The World Nuclear Organization notes that, following the sale of four nuclear reactors to the United Arab Emirates, the South Korean Ministry of Knowledge Economy declared in Janu-ary 2010 that it hoped to export 80 nuclear power reactors worth $400 billion by 2030, in the course of becoming the world’s third-largest supplier of such technology, with a 20% share of the world market, behind the U.S. and France or Russia.

One new customer could be the Philippines. In light of a power crisis in Mindanao (the second-largest of the islands) early this year caused by lack of hydro resources, several parties are suggest-ing that the country protect itself against overreliance on hydro-power by considering other energy sources, including nuclear.

The Manila Times reported that President Gloria Arroyo has expressed interest in acquiring two reactors from South Korea. On Mar. 2 a letter from President Arroyo to President Lee Myung-bak asked South Korea to sign a deal to sell two partially built Korean-built reactors, originally intended for North Korea, to the Philippines rather than selling the parts piecemeal. Presidential candidate Gilbert Teodoro Jr. has pointed out that Filipinos used to operate nuclear plants in Korea and Japan, so they should be able to do so in their own country.

Initial Experiments Meet Requirements for Fusion IgnitionScientists at Lawrence Livermore National Laboratory’s National Ignition Facility (NIF) in California speculate that a prototype nuclear fusion power plant could be operational within a decade, thanks to a test of the world’s largest laser array that confirmed a technique called inertial fusion ignition is feasible. Their first ex-periments have demonstrated a unique physics effect that bodes well for NIF’s success in generating a self-sustaining nuclear fu-sion reaction. Fusion energy is what powers the sun and stars.

In inertial confinement fusion (ICF) experiments, the energy of 192 powerful laser beams is fired into a pencil eraser–sized cylinder called a hohlraum, which contains a tiny spherical tar-get filled with deuterium and tritium, two isotopes of hydrogen (Figures 2 and 3). Rocket-like compression of the fuel capsule forces the hydrogen nuclei to combine, or fuse, releasing many times more energy than the laser energy that was required to spark the reaction.

The interplay between the NIF’s high-energy laser beams and the hot plasma in NIF fusion targets, known as laser-plasma in-

2. Precision alignment. A National Ignition Facility technician checks the target positioner, which precisely centers the target inside the target chamber before each experiment and serves as a reference to align the laser beams. Source: Lawrence Livermore National Laboratory


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teractions (LPI) has long been regarded as a major challenge in ICF research be-cause of the tendency to scatter the laser beams and dissipate their energy. But dur-ing a series of test shots using helium- and hydrogen-filled targets last fall, NIF researchers were able to use LPI effects to their advantage to adjust the energy distribution of NIF’s laser beams.

The experiments resulted in highly symmetrical compression of simulated fuel capsules—a requirement for NIF to achieve its goal of fusion ignition and en-ergy gain when ignition experiments be-gin later this year.

In a Science Express article, Siegfried Glenzer, NIF plasma physics group leader, ICF Program Director Brian MacGowan, and their NIF colleagues reported that “self-generated plasma-optics gratings on either end of the hohlraum tune the laser power distribution in the hohlraum, producing symmetric X-ray drive.” Glenzer said the gratings act like tiny prisms, re-directing the energy of some of the laser beams just as a prism splits and redirects sunlight according to its wavelength.

The test shots proved the NIF’s ability to deliver sufficient energy to the hohlraum to reach the radiation temperatures—more than 3 million degrees Centigrade—needed to create the intense bath of X-rays that compress the fuel capsule. When NIF sci-entists extrapolate the results of the initial experiments to higher-energy shots on full-sized hohlraums, they think they will be able to create the necessary hohlraum con-ditions to drive an implosion to ignition.

From GHG to Useful MaterialsCould the transformation of carbon diox-ide (CO2) into carbonates and oxides solve the problem of greenhouse gas emissions (GHG) from fossil-fired power plants? Some

companies are betting that such processes could make everyone happy and even cre-ate new profits. Buzz has been growing about this approach, though the concept has been around for many years.

Indian scientists, for example, have been looking at bacteria that can be used as enzymes to convert CO2 into calcium carbonate (CaCO3), which has multiple uses. Meanwhile, companies around the world—including Carbon Sense Solutions Inc. (Canada), Novacem (UK), Calix (Aus-tralia), and C-Fix (The Netherlands)—have been working on processes that use CO2 to create minerals and materials that have market value.

Above-ground sequestration of CO2 would seem to be simpler and more re-liable than storing the gas below the planet’s surface, because you can see and monitor its location. There are, of course, other ways to sequester CO2 emissions above ground, such as in forests, but se-questration in the biosphere doesn’t last indefinitely, and the capture mechanism is vulnerable to wildfires.

Recently, two companies announced strides toward commercially viable se-questration of the GHG in solid, inert forms. Their efforts were among a dozen projects selected to receive funding from the American Recovery and Reinvestment Act of 2009 (ARRA) under the competitive “Carbon Capture and Sequestration from Industrial Sources and Innovative Con-cepts for Beneficial CO2 Use” grant admin-istered by the Department of Energy and the National Energy Technology Laboratory (DOE/NETL).

Skyonic Corp. was awarded $3 million in ARRA funds. Its patent-pending SkyMine process can capture CO2 emissions from coal-burning power generators and other stationary emitters and mineralize the gas into stable baking soda (NaHCO3). The company says the process can be profit-able, as the feedstocks are inexpensive and available, and the byproducts are widely used and comparatively expensive.

The federal grant, plus private invest-ment, will fund Phase 1 of the commercial Capitol-SkyMine project to be located at the Capitol Aggregates Ltd. cement plant in San Antonio, Texas. Phase 1 will fund modeling, simulation, design, costing, and procurement activities in preparation for construction of the plant this year.

The company says that the Capitol-SkyMine plant is targeted to capture 75,000 metric tons of CO2 from flue gas emitted by the cement plant and miner-alize the CO2 emissions as baking soda, while offsetting an additional 200,000

metric tons of CO2 in the manufacture of benign chemical byproducts. The plant is expected to operate at a profit, due to the sale of these byproducts. The mineralized NaHCO3 will be used in several industrial applications and tested as feedstock for bio-algae fuels. The company says that Capitol-SkyMine will also neutralize acid-rain emissions and reduce mercury and heavy metals emissions.

Another company engaged in recy-cling CO2, Calera Corp., was called out in a March Thomas Friedman New York Times editorial. Calera will receive $1,681,377 in DOE ARRA funds. In December, Calera Corp. and Bechtel Power Corp. announced an alliance in which the two companies will develop and build facilities using Cal-era’s patented process to repurpose CO2 emitted by coal- or gas-fired power plants. The process captures CO2 from raw flue gas in water and then converts the GHG into calcium and magnesium carbonates for use in manufacturing carbon-negative products such as sand, aggregate (Figure 4), supplementary cementitious materials, and cement, as well as freshwater.

Bechtel noted that although challeng-es remain to bring the process to com-mercial scale, they are less daunting than those facing alternative carbon seques-tration approaches.

Friedman quoted Ian Copeland, presi-

3. Tiny target. This artist’s rendering shows a target pellet (the white ball) inside a hohlraum capsule with laser beams entering through openings on either end. The beams compress and heat the target to the necessary conditions for nuclear fusion to occur. Source: Lawrence Livermore National Laboratory

4. From gas to solid. This sample of supplemental cementitious material (SCM) blended with portland cement and Calera aggregate uses CO2 recycled by the Calera process. SCM is used to replace cement in concrete mixtures. Each pound of cement replaced with Calera SCM means 1.5 pounds of CO2 not released to the atmosphere. Cour-tesy: Calera Corp.

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dent of Bechtel Renewables and New Technology as saying: “The fundamental chemistry and physics of the Calera process are based on sound scientific principles and its core technology and equipment can be integrated with base power plants very ef-fectively.”

Calera says that based upon pilot scale data, its process can also easily achieve SO2 capture efficiencies in the range of 95% to 98% and can capture other components with aqueous solubility, including mercury, trace metals, NO2, ammonia, HF, and HCl.

Marines Get Power from WavesOcean Power Technologies Inc. (OPT) announced on Feb. 1 that it had successfully deployed one of its PowerBuoy wave energy devices about a mile offshore from a U.S. Marine Corps Base on the island of Oahu in Hawaii (Figure 5). The device generates up to 40 kW of power from the rise and fall of waves, and since its deployment in December 2009, it has been generating power within specifications.

OCT built and will operate the device as part of a program with the U.S. Navy, which is testing OPT’s wave power technology. (To comply with Executive Order 13423, federal agencies must ensure that at least half of all renewable energy required under the Energy Policy Act of 2005 comes from new renewable sources developed after January 1, 1999.) The company has been awarded $380,000 for the PowerBuoy’s commissioning and in-ocean operation.

Last November, OPT announced the completion of trials of its Underwater Substation Pod (USP) in waters off Spain. The USP is designed to help collect and network power and data generated by up to 10 of its PowerBuoys for transmission to a shore-based electricity grid by one subsea power cable.

The OPT test is part of a growing drive to harness ocean en-ergy for renewable power. In late November 2009, Aquamarine

Power launched what it said was the world’s largest working wave energy device, known as the “Oyster” at the European Marine Energy Centre in Orkney, Scotland (see Global Monitor, Dec. 2009 online). Meanwhile, in Norway, Statkraft has opened the world’s first osmotic power prototype, which generates power by exploit-ing the energy available when freshwater and seawater are mixed (see Global Monitor, Feb. 2010).

A new report from Pike Research concludes that if the hydro-kinetic trials now under way globally succeed, the ocean could yield as much as 200 GW of power by 2025. If these pioneering projects do not prove feasible, however, marine renewable energy might reach no more than 25 GW global capacity by 2025. The report assesses the market potential for five types of marine and hydrokinetic energy technologies: ocean wave, tidal stream, river hydrokinetic, ocean current, and ocean thermal energy. It notes that these technologies are “On the verge of widespread commer-cialization, with the U.K., U.S., and Canada in the lead.”

Permeable UK Granite Is Good News for Geothermal EnergyIn mid-February, the Geological Society of London raised the hopes of those promoting geothermal energy when results of ex-ploratory drilling in Weardale, County Durham, revealed record levels of permeability in granite. Although the results are prom-ising for the development of geothermal energy, they may have less welcome implications for the safe disposal of radioactive waste in deep repositories.

Scientists from Newcastle University were investigating poten-tial sources of geothermal energy, which is becoming increasingly popular in the search for low-carbon energy resources. Granite can be particularly useful, as it can be rich in radioactive ele-ments that generate heat as they decay. The permeability of the rock is important, as heat is extracted by pumping a “working fluid” such as water into the rock and drawing it back up again.

Professor Paul Younger, who led the research, said that “Hy-drogeologists have traditionally viewed granite as poorly perme-able,” but his team decided to challenge that assumption and found the “highest permeability ever recorded for a granite any-where in the world.”

The results were obtained by pumping naturally occurring saline groundwater from an exploratory borehole and monitor-ing the change in water levels. A permeability of almost 200 darcies—a unit of permeability—was recorded, far higher than most prolific oil and gas reservoirs.

The scientists believe the find is not unique to the Weardale granite, as there are similar granites worldwide that may display equally high levels of permeability. High natural permeability means less cost for hydraulic stimulation.

However, the research also means that caution needs to be taken when selecting sites for nuclear waste disposal. Granite is a popular rock in which to site repositories, and the higher-than-expected permeability of this rock suggests that safety estimates previously made may have to be reconsidered.

Dish Stirling Solar Plant Debuts In late January, a 1.5-MW concentrating solar power (CSP) plant began providing power to Salt River Project customers in Greater Phoenix, Ariz. Though small, the plant, developed by Tessera So-lar and Stirling Energy Systems (SES), is seen as a prelude to 1,500-MW projects that are due to break ground in California and Texas later this year.

The Maricopa Solar power plant (Figure 6) is the first com-mercial project for the SunCatcher CSP technology designed and

5. Marine waves benefit Marines. Ocean Power Technolo-gies’ PowerBuoy wave energy converter off the coast of Hawaii is pro-viding power to a U.S. Marine Corps base. By design, the PowerBuoy sits primarily below the sea surface when deployed, resulting in mini-mal visual impact. Courtesy: Ocean Power Technologies Inc.

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manufactured by SES. The facility uses 60 SunCatcher Stirling dishes. Each 25-kW SunCatcher consists of a 38-foot mirrored parabolic dish combined with an automatic tracking system to collect and focus the sun’s energy onto a Stirling engine to con-vert the solar thermal energy into electricity.

SES says that SunCatcher has a number of advantages, includ-ing the highest solar-to-grid electric efficiency, zero water use for power production, a modular and scalable design, low capital cost, and minimal land disturbance.

The technology was designed and developed in the U.S. through a public-private partnership with the Department of Energy. The Sun-Catchers used at Maricopa Solar were manufactured and assembled in North America, mostly in Michigan by automotive suppliers.

POWER DigestSiemens Hands Over 870-MW Dutch Gas Plant. Siemens En-ergy on Feb. 12 handed over the 870-MW Sloecentrale combined-cycle power plant to the joint venture of Dutch company Delta Energy and Electricité de France. The natural gas–fired plant in the Dutch town of Vlissingen-Oost reportedly has an efficiency of 59% and uses a state-of-the-art burner technology to keep nitrogen oxide emissions below 15 ppm. The plant is designed for 250 starts per year and is capable of supplying power to the grid within 30 to 40 minutes, Siemens said.

Sloecentrale comprises two single-shaft plants, in which the main components are arranged on a single line of shafting. Siemens built the plant as a turnkey project and supplied the main components—two SGT5-4000F gas turbines, two SST5-5000 steam turbines, two hydrogen-cooled generators, and all the electrical and instrumentation and control equipment. The company also signed a long-term service agreement for the main components.

Norway Pledges Funds to Develop World’s Largest Wind Turbine. Enova, an entity owned by Norway’s petroleum and oil industry ministry, on Feb. 12 announced it would provide Bergen-based company Sway AS with NOK 137 million (US$23 million) to demonstrate what it called “the world’s largest” turbine by 2011. Standing 162.5 meters tall, the 10-MW turbine will have a rotor diameter of 145 meters. The turbine’s concept was developed by Sway in cooperation with Norwegian technology firm Smartmo-tor AS, and it involves reducing turbine weight and the number of moving parts, as well as the use of a gearless generator system.

The prototype will be tested on land in Øygarden, southwestern Norway, for two years before being installation the North Sea as part of a Sway project that involves floating turbines.

eSolar and Ferrostaal to Deploy Solar Tower Projects in Spain, UAE, and South Africa. California-based solar thermal power technology maker eSolar and Ferrostaal on Feb. 18 said they had struck a deal to jointly deploy turnkey solar power proj-ects in Spain, the United Arab Emirates (UAE), and South Africa. Under the agreement, eSolar will provide solar field and receiver technology, while Ferrostaal will provide the power block as well as manage the overall realization as general contractor, includ-ing financing activities. The companies will use eSolar’s Sierra SunTower, a 5-MW commercial-scale solar power plant that uses mirrors to reflect sunlight onto a tower.

B&W Pilot Test of RSAT Carbon Capture Technology Suc-cessful. Babcock and Wilcox Power Generation Group (B&W PGG) on Feb. 1 said that researchers had successfully captured CO2 emissions from a pilot-scale, coal-fired boiler using advanced solvents and a proprietary CO2-capture process developed at the company’s research center in Barberton, Ohio. During the dem-onstration on flue gas from a coal-fired boiler at the company’s Regenerable Solvent Absorption Technology (RSAT) Pilot Plant, researchers were able to continuously remove more than 90% of the CO2 from the Small Boiler Simulator II’s flue gas stream using a fully integrated RSAT process.

The RSAT process uses a liquid solvent in an absorber vessel to remove CO2 from a plant’s flue gas stream. B&W PGG researchers are now evaluating proprietary solvents and characterizing their performance at this scale, the company said. Pilot-scale testing of solvents began at the B&W Research Center in June 2009 and will continue throughout 2010.

MAN Diesel Wins Major Equipment Contract for Brazil Diesel Plants. MAN Diesel, the Augsburg-based manufacturer of large-bore diesel engines, in early February said it had won a contract worth €300 million from Brazilian company Grupo Bertin to supply electromechanical equipment for six diesel power plants. These components include 120 large-bore diesel engines and generators, which together will form the heart of the plants.

Wärtsilä Wins Contract for 119-MW Heavy Fuel Oil Plant in Greece. Wärtsilä in December won a contract to supply equip-ment and engineering for the 119-MW South Rhodes Power Sta-tion proposed for the island of Rhodes in Greece. The plant, expected to become fully operational during the second half of 2011, will generate electricity for the island’s grid from seven Wärtsilä 18V46 engines running on heavy fuel oil. The order was placed by Terna S.A., which has been awarded the overall project contract by Public Power Corp. S.A., the national electricity util-ity of Greece.

Foster Wheeler to Design, Supply Equipment for 1,200-MW Vietnamese Coal Plant. Foster Wheeler AG announced on Feb. 9 that a subsidiary of its Global Power Group has been awarded a contract by Lilama Corp., a Vietnamese EPC contractor, to design and supply two steam surface condensers and auxiliary equipment for the Vung Ang Thermal Power Plant in Vietnam. The two-unit 1,200-MW coal-fired power plant will be located in Ha Tinh province on the north central coast of Vietnam. The project is being built by investments from the Vietnam Na-tional Oil and Gas Group as part of the government’s National Power Development Plan for the 2006–2015 period. Commercial operation of the first unit is scheduled for the second quarter of 2012. The second unit is expected to come online in the first quarter of 2013. —By Senior Writer Sonal Patel and Managing Editor Gail Reitenbach.

6. Focused energy. The 1.5-MW Maricopa Solar power plant is the first to use Stirling Energy Systems’ Stirling dish technology, which will be deployed at 1,500-MW plants in California and Texas. Courtesy: Stirling Energy Systems

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Deciphering Desuper- heater FailuresThe “combined” portion of a combined-cycle plant is the heat-recovery steam generator (HRSG) that generates high-pressure and high-temperature steam and the steam tur-bine generator that expands the steam to produce electricity. Integrating the HRSG and steam turbine with the combustion tur-bine is a key challenge for plant designers, as each system has differing operating profiles, operational constraints, and design require-ments. The combustion turbine can rapidly start, yet the rate of heating the large mass of metal tubes in the HRSG limits the com-bustion turbine start-up ramp rate. Some plants have resorted to “temperature match-ing” distributed control system software routines that carefully manage the turbine exhaust gas temperature during start-up to protect HRSG tubes and components. Like-wise, the temperature, pressure, and rate of HRSG steam production is often limited by the start-up ramp rate of the steam turbine.

Many Operating ProblemsMost commercial combined-cycle plants were designed and constructed for base-load service where rapid start-ups and shutdowns were infrequent. When natural gas prices rose, many of these plants were relegated to summer cycling service—some twice a day—followed by months of inactiv-ity during the winter when demand for elec-tricity eases. During the 1990s, the design and operating temperature requirements for desuperheaters used in HRSGs to condition the steam supplied to the steam turbine in-creased from below 900F to over 1,050F. In most cases, probe style desuperheaters (also called attemperators) were not designed to deal with these elevated steam tempera-tures, much less the added thermodynamic stresses that came with cycling service.

Component problems in the main and re-heat steam systems were some of the first to experience potentially catastrophic opera-tional problems in these high-temperature steam systems. The favored design approach for matching steam temperatures with those required by the steam turbine is to insert a desuperheater between primary and second-ary superheater and reheater sections in the HRSG. When the desuperheater is not oper-ating correctly, prolonged exposure to the higher-than-specified steam temperatures in the reheater and superheater can damage expensive equipment and lead to unsafe op-

erating conditions for tubes and surrounding components. Not only are bent or cracked pipes extremely dangerous, but plants forced to shut down for costly repairs will lose elec-tricity sale revenue and may be required to purchase expensive replacement power.

The desuperheater operates by injecting condensate into high-temperature steam to precisely match the steam temperatures re-quired by the steam turbine. This temperature-matching function is most important during system start-up and shutdown to prevent large temperature gradients in the HRSG or steam turbine steam supply. When the desu-perheater fails to temper the steam correctly, even a single large overspray excursion can damage steam turbine internals, cause costly tube leaks, and significantly reduce the steam turbine efficiency. Wet steam can also quench regions of the steam pipes, causing addition-al, long-term problems. Heavy desuperheater sprays during start-up can, over time, initiate cracking in HRSG tube joints or even distort the shape of tube banks. Prolonged operation outside the design-operating envelope will produce accelerated fatigue damage to the pressure parts.

Some plant designs have also incorpo-rated a desuperheater after the secondary superheater pass to reduce heavy sprays by the first desuperheater and to trim the steam temperature prior to entering the steam turbine. These superheater and re-heater attemperators are exposed to tem-peratures routinely over 1,000F and have exhibited seat leakage and nozzle cracking; in some cases they have even contributed to premature failure of the surrounding pipe.

Low-load operation is also problematic. A typical industrial combustion turbine’s ex-haust temperature remains well above the design steam temperature even at low loads. Also, with lower gas flows, the heat trans-fer usually moves forward in the superheater section, where the exhaust gas first contacts heating surface. This design peculiarity means that heavy spraying of the superheated steam to maintain design steam conditions has on occasion allowed “wet” steam to enter the steam turbine. The same is true for the reheat-ers, assuming they are not designed to oper-ate dry during start-up. Wet steam can enter the cold reheat lines of the HRSG, causing the same type of steam turbine problems.

Minimum Design CriteriaA well-designed desuperheater will produce atomized water droplets that are completely

vaporized before entering the superheater or reheater header and will produce an at-omization pattern that completely fills the pipe to eliminate bypassing and formations of thermal gradients. Properly installed desuperheaters should also be installed in a straight section of piping with two to eight diameters upstream and 12 to 20 diameters downstream—not always possible in today’s very compact plant designs, but neverthe-less, this remains a good design criteria.

Ensuring that no water droplets remain in the steam is paramount. During operation, 15 degrees of superheat is desirable, 50 degrees is best, downstream of the desuperheater. Also, the thermocouple providing the tem-perature signal to the desuperheater should be mounted downstream of the desuper-heater, perhaps as far as 25 feet away, where all the water should have been evaporated. Finally, good design practice is to include a drip leg to eliminate any condensate buildup in the steam header and to slope the header away from the desuperheater.

Good operating practice is to closely monitor the desuperheater during those periods when sprays should be secured. Few desuperheaters are capable of full shutoff after a few years of service. ASME Section I of the boiler code provides guidelines for these and additional design requirements.

New Desuperheater OptionTyco Flow Control has developed a new desuperheater valve for combined-cycle power plants that addresses each of these operating concerns, especially for plants when steam temperatures exceed 1,000F with excursions up to 1,150F. The first in-stallation of the Yarway TempLow HT tech-nology desuperheater recently completed a five-year run at Iberdrola’s Santurce Plant located in Vizcaya, Spain.

Tyco Flow Control recognized the chal-lenge emerging in the marketplace as more and more plant managers expressed their frustration with standard construction desu-perheaters failing above 1,000F and the costs and operating penalties that created for them. The company decided to take a step back to research a safe, cost-effective, and scalable solution. The company embarked on a three-year study with the goal of bringing a new product to market that could function successfully at 1,150F, and the risk paid off.

The design of the new desuperheater began with the assumption that it must continuously operate at steam tempera-


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Inspection of Both Desuperheaters after Five Years of Service

Step 1: Superheater desuperheater disassembly. The desuperheater installed during the superheater inspection began with removal of the actuator. Part of the main steam lagging also was removed for proper access to the lower nuts of the steam flange connection. Courtesy: Tyco Flow Control

Step 2: Remove for inspection. Bolts from the steam flange were removed, and the unit was raised from its stub connec-tion. A visual inspection did not reveal any cracks or imperfections. The flanged upper part of the spray cylinder was in perfect con-dition as well as the sealing indication of the RTJ groove. Courtesy: Tyco Flow Control

Step 3: Visual inspection. The splash pattern around the nozzles is typical of probe type spray units. Because the plant was standing idle for some days, oxidation of the magnetite had occurred. Some small

scratches showed up on the cylindrical part of the spray cylinder, and visual inspection led to the conclusion that these were most likely mechanical fissures. A nondestructive examination (NDE) test would confirm that observation. Courtesy: Tyco Flow Control

Step 4: NDE test. Next, a dye penetrant NDE test was performed on the entire as-sembly. The investigation showed that zero cracks or imperfections were present in the spray cylinder, the flange area, and the noz-zle area. Courtesy: Tyco Flow Control

Step 5: Return to service. Plant man-agement decided to reinstall the unit with no further dismantling or testing. Plant records showed excellent temperature control and smooth responsiveness over the entire operat-ing range since start-up, five years earlier. The offset from setpoint was never more than 4C on a controller over a 600C span. All operat-ing and mechanical inspection results showed that a complete overhaul was not required. The desuperheater was then reinstalled and re-turned to service. Courtesy: Tyco Flow Control

Step 6: Reheat desuperheater dis-assembly. There was much more access to the reheat desuperheater given the larger size of its pipe—32-inch outer diameter (OD)—than the superheat pipe (18-inch OD). The liquid on the bolting is WD-40 used as a rust solvent. Courtesy: Tyco Flow Control

Step 7: Remove for inspection. The spray cylinder shows considerably more corro-sion than the superheat unit because the unit is fabricated from a ferritic steel that is prone to oxidation. The superheat unit is constructed from F91. Courtesy: Tyco Flow Control

Step 8: Visual inspection. The flanged upper part also revealed no imper-fections during visual inspection. Courtesy: Tyco Flow Control

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tures above 1,000F. Tyco selected met-allurgy for the probe, seating design, and water delivery system to work up to 1,150F. The device was also designed to fit into any combined-cycle plant as a new or retrofit solution. The valve also meets all U.S. and international codes, making it a truly international solution.

Tyco also maintains that, although other probe style desuperheaters require inspection and perhaps replacement every two years, the TempLow HT design will last for many more years. A recent inspec-tion of an early installation in Spain after five years of service with no maintenance and zero leakage appears to confirm Tyco’s claims (see sidebar).

Desuperheater Case StudyThe 400-MW Santurce Plant is one of three Iberdrola combined-cycle plants placed in service in 2004 (see “Arcos de la Frontera Grupo III Combined-Cycle Plant, Cádiz, Spain” in the August 2006 issue of POWER). Santurce is a single-shaft combined-cycle plant based on a GE 9001FA combustion turbine, a three-pressure Kawasaki HRSG, and a GE steam turbine. The primary fuel is natural gas with a heavy fuel backup. The three-pressure HRSG mixes steam from the reheat with the intermediate-pressure (IP) steam, and the low-pressure (LP) steam turbine receives steam from the IP turbine plus the LP steam generating cir-cuit. The high-pressure (HP) steam oper-ates at 1,700 psig/1,094F; the IP section operates at 700F. The two Yarway desu-perheaters are installed in both the cross-over between the HP superheater sections and in the cold reheat return line.

After five years of operation, the plant reports not one single leak, damaged probe, cracked nozzle, or pipe damage di-rectly caused by operation of the desuper-heater. Also, the desuperheater was able to sustain 1,150F steam temperatures without degradation. Avoiding unexpect-ed outages to repair the desuperheater has paid good dividends to the plant given that each outage day penalizes the plant $200,000 to $250,000 in lost revenue.

Cycling Plant OperationAccording to Plant Director Pavel J.F. Rodri-guez, the plant emissions-limited minimum load case for the plant is 230 MW. When operating between 230 MW and 280 MW, the outlet temperature of the combustion turbine is at its peak and attemperation in both the superheat and reheat lines is required. Above 280 MW to approximately 300 MW, attemperation may be required in-termittently, although when is difficult to

predict. Above 300 MW, the desuperheaters are in the closed position. The steam pipe connection on the superheat and reheat desuperheater is 4-inch with a 1½-inch water supply connection. The superheat steam line is an 18-inch OD pipe. The re-heat steam line is 32-inch OD pipe.

The sidebar provides a photo essay of the first inspection of both desuperheaters af-ter five years of service, in May 2009. Based on the inspection reports, these units have at least another two years of life remaining for a total of seven years of cycling service without major maintenance—a remarkable record. The first five photos are of the su-perheat desuperheater, and the second five photos are of the reheat desuperheater.

—Contributed by Tyco Flow Control

Competitive Maintenance Strategies, Part IINearly every combined-cycle operator rec-ognizes that cycling reduces the life ex-pectancy of hot-gas-path components in combustion turbines. Often overlooked, however, is that the same phenomenon affects the heat-recovery steam generator (HRSG). In fact, the greater physical size, elevated gas temperature, and higher steam conditions in today’s HRSGs have dispro-portionately increased thermal stresses and fatigue damage, particularly in the super-heater section. Not surprisingly, improve-ments made in the design stage offer the greatest benefits in extending cyclic life.

However, existing plants also can reduce fatigue through equipment modifications, such as relatively minor changes to drain piping and drain valves, and by changing start-up and shutdown procedures. Fol-lowing are some specific improvements that you can make at your plant.

Drain Piping and Valve ImprovementsCarefully Size Drains. Generously size the HRSG drains to permit removal, at high temperature and pressure, of the large quantities of condensate that collect in the lower headers of superheaters during coast down and prestart purge. If condensate at saturation temperature is not removed prior to reestablishing high-pressure (HP) steam flow on a hot HRSG, a condensate quench occurs in outlet headers and steam pipes. Restarts shortly after a combustion turbine trip are a particularly nasty source of quench damage. Designers and opera-tors often overlook the damaging fatigue effects of condensate quenching.

Superheater drains at some installa-tions are not designed for, and cannot be used during, shutdowns and hot restarts.

Step 9: NDE test. The reheat unit sub-sequently was cleaned and a dye penetrant check investigation was performed. The dye check revealed no imperfections or linear in-dications, showing the unit was in perfect condition. Courtesy: Tyco Flow Control

Step 10: Return to service. Again, all operating and mechanical inspection re-sults showed that a complete overhaul was not required. The desuperheater was then reinstalled and returned to service. Cour-tesy: Tyco Flow Control

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At other installations, the drains are avail-able, but operators fail to use them cor-rectly. At still other plants, the drains are inadequately sized to handle the substan-tial quantities of condensate. Regardless of the reason, failure to remove conden-sate from superheater headers obstructs steam flow during the next start-up. This produces a significant temperature differ-ential between adjacent tubes and raises thermal stresses. Failures caused by this condensate-quench phenomenon have oc-curred after only 300 cycles.

Also, the substantial quantities of con-densate in the superheater tubes should be drained during the combustion turbine coast down to further minimize thermal stresses. Superheater drain valves should be motorized to permit convenient, re-mote operation. In addition, where au-tomated sequence controls and interlocks are available, the motorized drain valves should be automated.

Install Stack Dampers. Install dampers in the HRSG exhaust to restrict convection flow through the unit and to maintain HP steam pressure as high as possible. HRSGs without exhaust or stack dampers depres-surize within a few hours after shutdown;

thus almost every restart is from cold con-ditions. On a P91 header, a cold start will cause about 20 times more fatigue damage than a well-designed hot start; on a P22 header, cold-start fatigue damage may be 30 to 40 times that caused by a hot start.

Include Inspection Access. Provide convenient access for internal inspec-tion. Fatigue cracks usually initiate in-side tubes and headers. Some HRSGs have no facility or space to inspect header in-ternals; thus, fatigue damage will not be evident until a crack propagates all the way through the header wall. If internal cracks are detected early, their growth rate can be monitored and replacement components procured in advance, keep-ing outage time to a minimum.

Change Your Shutdown Procedures. Many combined-cycle stations base oper-ating procedures on the ideal requirements for the combustion or steam turbine. Op-erators of existing HRSGs may substantial-ly lower HRSG thermal stresses simply by changing these procedures. Unfortunately, these procedures often cause severe fa-tigue damage in the HRSG.

Most operators believe that rapid start-ups are what damage HRSG compo-

nents, but shutdowns—both routine and emergency—can be more damaging. The shutdown procedure is usually intended to keep superheater-outlet steam tem-perature as high as possible to permit fast reloading of the steam turbine after an overnight or weekend shutdown. In this procedure, combustion turbine exhaust-gas temperature and steam flow are both reduced rapidly during unloading, so that when combustion turbine firing stops, only moderate reduction in superheater-outlet steam temperature has occurred and the majority of the header remains near maximum steam temperature. How-ever, as cooler air is delivered from the combustion turbine compressor during coast down and HRSG purging, condensate rapidly develops in the superheater tubes and then runs down into hotter headers, causing these sections to quench to satu-ration temperature. This leads to substan-tial thermal stresses at the inner surface of the headers.

A better procedure for normal shutdown is to ramp down the superheater outlet steam temperature during gas turbine un-loading, prior to tripping the combustion turbine. One original equipment manufac-

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turer recommends a ramp rate of 14F/min to a steam temperature of about 700F. By the time condensate begins to collect in the header, the bulk temperature of the header has been reduced further to about 60F above saturation temperature. This may extend the subsequent hot restart time after an overnight shutdown from a typical 60 minutes to 75 minutes, but it reduces fatigue damage by as much as 50%.

Rewrite Start-up Procedures, Too. A procedure sometimes used for hot starts de-liberately lowers HP steam pressure prior to the restart. This practice is intended to re-duce throttling at the steam turbine during start-up, and thereby shorten the start-up time. Nevertheless, by lowering HP steam pressure, the superheater is cooled to a lower saturation temperature, which results in a more damaging step increase—from saturation temperature up to combustion turbine exhaust temperature—immediately after steam flow is established.

To reduce thermal stresses in the super-heater during hot starts, the step change should be minimized. This can be accom-plished by maintaining pressure, thus satu-ration temperature, as high as possible in the superheater. In addition, combustion turbine exhaust temperature should be kept as low as possible when steam flow is first established. Note that combustion turbines equipped with inlet guide vanes (IGVs) tend to produce higher gas temperatures during start-up than those without IGVs. After steam flow is established, subsequent combustion-turbine ramp-up should be slow enough to maintain the temperature gradi-ents induced by the initial step change.

Inject Cost Consciousness into Valve Maintenance Program Goals of any valve program should be to reduce long-term costs of valve mainte-nance, improve valve operation and reli-ability, and improve plant operation. To achieve these goals, the program should address valve stem packing, leak detec-tion, steam-trap diagnostics, predictive operation, matching valve class with ap-plication, individual valve problems, and standardized valves. Preferably, one valve specialist should be assigned to coordi-nate the program.

Packing Improvements. Tremendous changes have occurred in valve stem pack-ing over the past decade. Opportunities for savings are numerous. Packing sets with fewer packing rows perform better than old sets with more rows because packing consolidates less over time, resulting in fewer leaks and repacks. Packing sets for high-pressure valves should be converted

to five-row sets with three active sealing rows and two containment, anti-extrusion rows. These changes to existing valve packing sets should first be made to all high-pressure valves.

Torquing the packing to calculated val-ues leads to consistently good seals on valves. Of course, torque wrenches should be checked regularly and calibrated, if necessary. Live loading—which involves installing Belvoir washers on the packing bolts to maintain the calculated preload on stem packing even when some consoli-dation occurs—should be considered for critical valves or valves that have exhib-ited problems in the past. This will allow for a considerable amount of packing con-solidation before problems occur.

Valve Leak Detection. If accurate valve leakage information is available, you can rely on valve condition monitoring and eliminate most, if not all, preventive maintenance. Thermography and acoustic devices have been used for leak detec-tion, but they are not always reliable in-dicators. Many valves were found to be in good condition when disassembled even though these techniques identified leak-age. Fortunately, new valve leak detector technology has been developed that uses acoustic signatures captured by sensors, massaged by proprietary signal processing software, followed by computer analysis. The presence of acoustic signals in a par-ticular frequency spectrum can be used as a predictive measure for steam leaks and for other failure mechanisms. The latest instruments can be added to the plant’s lo-cal area network if continuous monitoring of certain equipment is desired. This one improvement has allowed maintenance departments to plan their work much more effectively and has in many cases elimi-nated preventive maintenance.

The coordination of leak-test efforts is critical to the entire valve program. Iden-tifying and testing whole systems—which would include the boiler vents and drains, boiler feed system, auxiliary steam system, and more—is recommended. Other valves can be tested by a thorough, organized approach to the various piping systems in a plant before planned outages. Pos-sible annual saving at a comparable power plant is $250,000 to $350,000.

Steam-Trap Maintenance. Steam traps are not a high priority at many plants, typically because unit reliability is more important than plant efficiency.Steam traps are essentially valves that open and dose automatically. Many problems were experienced with high-energy steam traps because inverted steam traps lost their

prime. The prime is a water seal in the trap that keeps steam from leaking straight through. The industry has been aware of this problem for some time and suppliers are reacting. You may have to replace ex-isting steam traps with ones better suited to specific operating conditions. The valve leak detector mentioned above can be useful in identifying leaking traps or traps that are not performing as designed. For a comparably sized power plant, annual sav-ing of $80,000 to $120,000 are possible by addressing steam-trap problems.

Predicting Valve Operation. Improv-ing plant operability and reliability re-quires that personnel be able to predict whether valves will operate properly as needed and whether the valve will seal tightly against the expected pressure dif-ferential when closed.

Motor-operated-valve (MOV) diagnostic equipment and services have been used for some time in the nuclear industry. A diagnostic service provides information on the valve/operator/motor set condi-tion, and setup and assists in corrections, if necessary. When the valve and operator are in good condition and set up correctly, diagnostic systems then provide the infor-mation needed to predict reliable opera-tion and tight shutoff.

Note that the price of the diagnostic equipment and the amount of training re-quired to reliably test MOVs and stay pro-ficient in equipment use are high. If only a few valves on each unit are to be tested, contracting out this service is probably more cost-effective. Other noncritical MOVs should be stroked regularly so that the op-erations personnel are comfortable with re-lying on the valve to operate when needed.

Standardize Valves. At many plants, numerous types of valves are installed in similar service. Maintenance person-nel are often unfamiliar with procedures that apply to each type. Parts and pack-ing inventories increase and become more complicated. Personnel obtaining valves from stock become unfamiliar with the applicable temperatures/pressures of the different valves. Standardizing valves to be used in like services reduces inventory requirements, increases familiarity with valve maintenance, and streamlines main-tenance efforts. Recent (2009) changes in ASME B16.34 code have resulted in corresponding changes in the applicable pressure/temperature combinations of many valves. Some codes no longer ap-ply. Some common valves can no longer be purchased and installed unless they are upgraded to meet the new code.

—Dr. Robert Peltier, PE, editor-in-chief.

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Gridlock Continues for Grid PolicyBy Brian R. Gish

Early last year, there were promising signs that electric transmission line construction would be facilitated by the convergence of the new administration’s emphasis on de-

veloping remote renewable generation resources, proposed leg-islative provisions expanding federal siting authority, and the granting by the Federal Energy Regulatory Commission (FERC) of generous cost-of-service returns on such investments. However, the stars did not align for transmission policy in 2009 as had been hoped, and the forecast is cloudy.

Siting Issues Remain UnresolvedOne of the main disincentives to transmission line development is the long and costly siting process for new lines that have to cross multiple states, because each state has the right to stall or veto the line. Unfortunately, the U.S. Supreme Court on Jan. 19 declined to hear an appeal of a 2009 decision of the U.S. Court of Appeals for the 4th Circuit that interpreted Section 216 of the Federal Power Act in a way that diminished its usefulness for facilitating transmission siting.

Section 216, added by the Energy Policy Act of 2005, in-structs the Department of Energy to designate “national inter-est” corridors where there is transmission congestion, which it has done for a section of the eastern and southwest United States. Section 216 provides FERC with “backstop” siting au-thority for proposed transmission projects in such corridors un-der circumstances where states could not or would not grant a siting permit on reasonable terms.

The 4th Circuit’s split 2 to 1 decision construed Section 216 to forbid FERC from exercising “backstop” siting authority when a state commission denies a siting permit, while acknowledging that FERC is granted such authority when a state commission delays action or unreasonably conditions a permit. In the curi-ous decision, the majority held that Section 216 unambigu-ously withholds FERC’s authority in the case of a state denial, whereas the dissent held that the statute unambiguously grants FERC such authority.

A broad coalition of the energy industry—including the Edison Electric Institute, the American Public Power Asso-ciation, and the National Rural Electric Cooperative Associa-tion—filed a Petition for Certiorari with the Supreme Court to overturn the decision. The petition was supported by am-icus briefs by the four previous FERC chairmen and the U.S. Chamber of Commerce. Although FERC strongly disagreed with the Fourth Circuit’s interpretation, the U.S. solicitor general decided against filing an individual Supreme Court Petition on behalf of FERC.

The solicitor general’s response to the petition agreed that the 4th Circuit’s decision was “erroneous” and was potentially harm-ful energy policy. However, the solicitor general argued against the court hearing the case on several procedural grounds, includ-ing these:

The uncertain standing of the state commissions and environ-mental groups to bring the 4th Circuit challenge because they had not established that their injury was “actual or imminent.”

The uncertain ripeness of the case for the court’s consideration because FERC’s action did not command anyone to do anything or refrain from any action.

The chance that FERC could render a decision that was not consistent with the 4th Circuit’s holding in a specific state permit denial case arising outside of the 4th Circuit, thus pav-ing the way for another court of appeals to opine on the mean-ing of Section 216.

The Supreme Court’s refusal to hear the appeal says nothing about the merits of the 4th Circuit decision or any other issue, as the Supreme Court takes very few cases. However, allowing the 4th Circuit’s decision to stand may force transmission developers to consider whether they should propose costly projects if they

believe it possible that a state will reject the project and FERC has no backstop authority in that situation. Attempting to chal-lenge the 4th Circuit’s decision in another forum would take sev-eral years and great expense, with no assurance of the outcome.

Other Issues PersistMeanwhile, the legislative proposals that had been introduced in 2009 to provide FERC more specific federal backstop siting author-ity were included in the controversial climate change legislation, which has become bogged down for other reasons. In addition, some eastern states have protested legislation that would aid the building of transmission lines from midwest wind farms to their region because they fear the lines may undermine efforts to build local renewable resources. Moreover, the battle over who pays for new lines intensified during 2009 with legislative proposals to limit cost allocation to those receiving “measurable” benefits from a line. And there is an additional battle brewing as to whether transmission planning should be done at a national or local level.

Some progress is being made on developing new lines in sparse-ly populated areas. However, the same conflicting political forces that have frustrated much transmission development for the past 20 years appear likely to continue doing so, at least until the next major blackout forces compromises to be made.

—Brian R. Gish ([email protected]) is of counsel in Davis Wright Tremaine’s Energy Practice Group.

The Supreme Court’s refusal to hear the appeal says nothing about the merits of the 4th Cir-cuit decision or any other issue.

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RENEWABLES

Wind Destroyed and Now Powers Greensburg, KansasGreensburg was destroyed by an EF5 tornado on May 4, 2007. Instead of aban-

doning the Kansas town, the community quickly embraced the task of re-building it from the ground up, maximizing the use of renewable energy sources and energy efficient building techniques. Rebuilding continues, but the future of Greensburg has never been stronger.

By Lynn Billman, National Renewable Energy Laboratory

In 2007, a massive tornado touched down in the south-central Kansas town of Greens-burg, destroying 95% of the town and kill-

ing 11 people. It could easily have been the end of the 1,400-resident rural farming town that was already in decline, but instead, the disaster brought the town together in an ef-fort to make Greenburg’s future a green one.

The U.S. Department of Energy (DOE) and its National Renewable Energy Labora-tory (NREL) provided technical assistance to the community while dozens of other agen-cies and entities at all levels contributed many additional forms of support. As a result, the city of Greensburg and its many partners are rebuilding the town from top to bottom using the latest energy efficiency and renewable energy technologies. In addition to installing several ground source heat pump systems and small photovoltaic systems, the town is con-structing a wind farm that will supply enough wind energy to power every house, business, and municipal and county building.

Too Tough to DieWithin days after the tornado, experts from the DOE, NREL, and other agencies came togeth-er with state and local officials and residents to help answer the big question: What will become of Greensburg? While the town was evacuated for three months, residents scattered and businesses evaluated their losses. No one was sure how many would return to rebuild.

“The planning process that grew out of that first tent meeting just snowballed,” said Dan-iel Wallach, executive director and founder of Greensburg GreenTown, a grassroots community-based nonprofit formed after the tornado hit. “Community, family, prosperity, environment, affordability, growth, renewal, water, health, energy, wind in the built en-vironment—these were all values that were identified that would construct a framework in which to move forward for Greensburg.”

As the residents of Greensburg focused their energies on rebuilding, they kept these

values in mind, and their vision took shape. The City Council passed a resolution requir-ing all new city buildings larger than 4,000 square feet to meet U.S. Green Building Council Leadership in Energy Efficiency and

Design (LEED) Platinum certification and reduce energy consumption by 42% as com-pared to standard buildings. They set a goal of using 100% renewable energy for their new town. And they included brand-new

Before

After

Courtesy: Federal Emergency Management Agency

Courtesy: Greensburg GreenTown

07_PWR_040110_SR_Greensburg_24-29.indd 24 3/17/10 12:28:20 PM



renewables

technologies, such as light-emitting diode (LED) streetlamps, to reduce energy use.

Greensburg is becoming a net-zero-energy community with regard to its electricity—an energy efficient community that generates as much electricity from renewable energy as it uses. It sets a new standard, not just for its own citizens, but for other rural and urban communities as well (Figure 1).

First in Green LightingOne of the town’s first completed green proj-ects illuminates the downtown sidewalks and streets every night. Greensburg is the first city in the U.S. to use LED lamps for 100% of its street lighting.

By replacing the existing 303 sodium va-por lights with LED fixtures, Greensburg im-proved outdoor lighting energy efficiency by 40% and reduced the cost of related energy and maintenance by an estimated 70%.

As an added bonus, the new lamps reduce nighttime light pollution by focusing light where it is needed—on the ground rather than in the night sky.

A “Wind-Wind” SituationOne of the most remarkable aspects of the Greensburg project is the town’s commit-ment to renewable energy and, in particu-lar, wind. Far from distrusting the force

that destroyed their town, the townspeople have embraced it as the foundational build-ing block of their new community, even donning t-shirts with the phrase coined by Greensburg GreenTown: “Greensburg—A Wind-Wind Situation.”

The town is already home to a 50-kW tur-bine at the new hospital, two smaller turbines at the BTI-Greensburg John Deere dealer-

ship, and three small turbines at the 5.4.7 Arts Center. The new school also plans to install a 50-kW turbine.

Construction is also under way for the Greensburg Wind Farm, which will con-sist of 10 Suzlon 1.25-MW wind turbines with a capacity of 12.5 MW of renewable power—enough energy to power 4,000 modest homes. It is planned for completion

Green-Powered Government and BusinessesThe 95-year-old Kiowa County Courthouse (Greensburg is the Kiowa County seat), one of the few structures left standing after the tornado, has been renovated with sustainable features and is striving for LEED Gold certification—an especially

admirable goal, because the facility is being modified rather than replaced. Today, the building is one of the greenest historic buildings in the country thanks to extensive use of reclaimed materials, state-of-the-art windows, and native landscaping (Figure 2).

The courthouse uses a specialized multi-stage heat pump system that extracts both heat and cooling from the ground through a series of thirty-two 300-ft vertical wells. The ground source heat pumps are rated based on size, with an energy efficiency ratio ranging from 14.1 to 18.7 for cooling and a coefficient of performance ranging from 3.1 to 3.8 for heating. The heat pumps utilize high-efficiency motors and fans and exhaust energy recovery ventilators supply outdoor air to each heat pump.

Growing Businesses with Green PowerThe two-story SunChips Business Incuba-tor is home to temporary, low-cost office space for as many as 10 small businesses

rebounding from the tornado or starting from scratch. Like all larger structures owned by the city of Greensburg, the fa-cility is built to LEED Platinum standards. A 6.8-kW photovoltaic system supplies approximately 10% of the building’s total energy needs. The Business Incubator also features a specialized ground-source heat pump system that extracts both heat and cooling from the ground through 21 ver-tical well shafts, 340 feet deep each. As in the courthouse system, heat pumps are rated based on size; their energy efficiency ratings range from 14.1 to 18.7 for cool-ing while coefficients of performance range from 3.1 to 3.8 for heating.

High-performance building materials provide maximum insulation and protection from high winds. Natural light illuminates most of the interior space, which minimiz-es the need for artificial lights. Water from sinks and showers is recycled and used to flush toilets. The recycled water (gray wa-ter) is supplemented by rainwater, which is collected and stored during rainstorms.

2. Better than new. The Kiowa Coun-ty Courthouse, originally built in 1914, was one of the few buildings not destroyed by the tornado. However, its glass-block win-dows were broken, the roof was blown off, and the interior was extensively water dam-aged. The tornado also picked up a vehicle from the nearby police impounds lot and crashed it through the roof. The building has since been completely renovated. Courtesy: Kansas Geological Society

1. Plan for the future. A Greensburg master development plan was developed to guide the city’s recovery and growth over the next 20 years. Source: City of Greensburg, Kansas




renewables

in the spring of 2010. The town expects to consume about a quarter of the electricity produced by the wind farm for its homes, businesses, and government buildings; the rest will be sold to the Kansas Power Pool, which is purchasing power from the project (Figure 3).

With its 40 member cities and strong in-terest in increasing renewable energy in its generation mix, the Kansas Power Pool was a natural partner for the city of Greensburg. When the wind isn’t blowing and the turbines can’t generate electricity, the Kansas Power Pool will energize the town with as much clean power as possible from other sources, including hydropower, to work toward the community’s goal of being powered entirely by renewable sources. Greensburg will also own all the renewable energy credits from the electricity used by the city.

Other Greensburg Wind Farm partners include John Deere Renewable Energy, the owner and operator that led the project and provided an equity investment. It will also maintain the wind farm.

Native Energy, a Vermont-based com-pany, furnished a portion of the upfront fi-nancing as part of its mission to help finance sustainable power projects that benefit fam-ily farms, community-based operations, and Native American projects. Native Energy is selling the renewable energy credits from the project so that anyone can “own” part of the Greensburg Wind Farm (see www. nativeenergy.com).

The total cost of the wind farm is pro-jected to be $23.3 million. The remainder of the project financing is coming from the U.S. Department of Agriculture (USDA). In October 2009, Secretary Tom Vilsack announced a $17.4 million loan to the proj-ect through the USDA Rural Development program. John Deere Renewable Energy an-ticipates that the system will be paid off in under 12 years.

“This project will not only enhance our country’s long-term energy security by producing clean, renewable energy, but will also create green jobs and generate in-come in the local community,” said Vilsack. “Greensburg stands out as an example of the promise and potential in communities throughout the country.”

Vilsack isn’t the only administration of-ficial fond of the project. In his first address to a joint session of Congress, President Ba-rack Obama said, “Greensburg . . . is being rebuilt by its residents as a global example of how clean energy can power an entire community—how it can bring jobs and businesses to a place where piles of bricks and rubble once lay.”

Economic DevelopmentIn addition to powering the town, wind en-ergy has become an important economic de-velopment strategy for Greensburg. Take, for example, Kelly and Mike Estes, owners of the BTI-Greensburg John Deere dealership, a prominent local business. The Estes brothers used a wind turbine to power the construction site when rebuilding their business, which now includes two wind turbines (4.2 kW and 1.9 kW) that provide electricity to the facil-ity, offsetting an estimated 8% of the building load (Figure 4).

The Estes brothers had such a positive experience with Endurance Wind Energy, the Canadian company that built their larger turbine, that they saw a new busi-ness opportunity. BTI Equipment became the exclusive North American distribu-tor for Endurance and formed BTI Wind Energy. In their first nine months of busi-ness, they built a North American dealer network across 32 states and four Cana-dian provinces, resulting in 120 new wind-related North American jobs (including wind specialists, service technicians, and installers). Nearly 300 existing sales rep-resentatives are learning the new business of wind energy.

“In the ag business we are pretty reliant on weather and crop for our survival,” Kelly Estes said. “If we lose a crop or freeze or drought, then it’s real hard for our type of business to survive, so we were looking for something sustainable. You can harvest the wind pretty well year round.”

Green Buildings in GreenburgGreensburg residents have taken sustain-ability to heart, hearth, and home. Busi-

3. Harness the wind. Greensburg is using wind-generated electricity to supply much of the city’s needs. The city’s goal is to become electricity self-sufficient. Excess wind power generated is sold to the Kansas Power Pool. Courtesy: Joah Bussert, Greens-burg GreenTown

High-Performance School of the FutureIn 2007, the year of the tornado, the Greenburg high school received the Governor’s Award for ranking as one of the top 5% of the state’s schools. The new high-performance school building will be worthy of the stu-dents’ high academic performance.

Projected for completion in time for the school year starting in September 2010, the two-story, 120,000-square-foot facility will consolidate grades K-12 in a single campus designed to be the state’s first LEED Platinum school. It will include state-of-the-art classrooms, a library, an interac-tive learning center, science labs, two gyms, a cafeteria and kitchen, art and music areas, courtyards, two playgrounds, a football stadium, plus track and field facilities.

This new school will replace the total square footage of all the pre-vious school buildings, combining all grade levels in a single facility. It will serve up to about 375 stu-dents (the school currently is serv-ing about 220 students), allowing for the town’s future growth.

Key green features include the ex-tensive use of daylighting (natural light) to ensure that artificial lighting is seldom necessary in most rooms. Heating and cooling will be handled by geothermal heat pumps that take advantage of the difference between the earth’s and the air’s temperatures. The pumps circulate water from below the earth’s surface to warm interior air in winter and cool it in summer. An onsite wind turbine will meet about 25% of the facility’s electric-ity needs and will be backed up by a hydrogen-powered fuel cell. Rain-water is transported through the roof lines, stored in cisterns, and used to irrigate the grounds.

When completed, the school will be a great improvement over the one permanent campus structure—known as the “caf-a-gym-atorium”—and the temporary classrooms that the students have been in since the 2007–2008 school year.



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nesses like banks, car dealerships, and funeral homes, along with churches and a lodge have rebuilt using environmentally friendly materials and are saving energy and water. Per capita, the city has the high-est concentration of LEED Gold and Plati-num buildings in the U.S.

As noted earlier, the city of Greensburg passed a resolution that all city-owned buildings over 4,000 square feet would be certified LEED Platinum. Completed in May 2009, the city’s Business Incubator not only achieved LEED Platinum status with greater than 50% energy savings, but it also became the first LEED Platinum–certified municipal building in Kansas (Figure 5).

Other public and commercial buildings, such as the Greensburg School and the Ki-owa County Memorial Hospital (see side-bars), are striving for LEED Platinum status; if awarded, the hospital will be the first criti-cal access hospital in the nation to achieve the LEED Platinum rating. Greensburg is also home to the 5.4.7. Arts Center, the first LEED Platinum building in Kansas.

Greensburg’s business community is rebuilding with a major focus on energy efficiency and green building principles as well. The new John Deere dealership is a LEED Platinum building and has become the model for all future John Deere deal-erships across the nation. In addition, the town’s grocery store, banks, churches, car dealership, senior center, and many other buildings are rebuilding green.

Of the 180 new homes that received build-ing permits between May 2007 and March 2009, the designs of 95 were evaluated and should use 40% less energy on average than

standard homes built to the International En-ergy Conservation Code (IECC) 2003 (with 2004 Supplement). This is an outstanding level of energy efficiency, especially consid-ering that most were built by individual home owners and builders.

Two multi-family projects for afford-able housing were also in the range of 40% to 50% energy savings. Prairie Pointe Townhomes, a new 32-unit complex for low-income renters, was awarded the first residential LEED Platinum rating in Kan-sas. Wichita, Kansas–based Mennonite Housing Rehabilitation Services, which helps low-income individuals build afford-able, single-family homes with so-called

sweat equity, built 20 highly energy effi-cient homes and plans to build 30 more us-ing design recommendations from NREL.

Children Today, Greensburg’s Leaders TomorrowIf anything can forecast the lasting success of Greensburg’s bold vision, it’s the way the town’s young people envision their own futures. Greensburg’s enthusiasm for re-newable energy and energy efficiency has inspired young people, fed by extensive education and outreach efforts at several levels to give youth the opportunity to un-derstand, embrace, and champion the alter-natives to petroleum.

4. Deere wind. BTI-Greensburg, the local John Deere dealership, uses two wind turbines (4.2 kW and 1.9 kW) to provide about 8% of the facility’s electricity requirements. Courtesy: BTI-Greensburg

Clean, Green Medical CareSlated for completion in March 2010, Greenburg’s new hospital facility combines all medical services in a single, highly en-ergy efficient structure that is striving to be the first critical access hospital in the country to meet LEED Platinum standards.

The whole building has high R-value insulation and features a dual ventila-tion system that prevents the exchange of air between the emergency and isola-tion rooms and the rest of the hospital, along with seamless floors and coun-tertops that make cleaning easier and more thorough.

Highly efficient T5 fluorescent and compact fluorescent luminaires maximize energy efficiency without sacrificing vi-

sual comfort or patient care. LED sources for accent lighting, exterior walkways, and parking lot lighting provide energy efficient illumination, while light-sensing dimmers and motion sensors minimize ar-tificial light use. Daylighting in common spaces, corridors, patient rooms, and ad-ministration areas illuminates 75% of the interior. High-performance, low-E, double-glazed windows allow natural light to off-set electrical lighting.

An onsite, grid-tied, 50-kW wind tur-bine generates 220,000 kWh annually to partially offset the hospital’s energy use. A rain filtration and storage system sup-plies recycled (gray) water to irrigate the property and flush the building’s toilets.

5. Energy efficient building de-signs. As part of the Greensburg master de-velopment plan, all city-owned buildings over 4,000 square feet must be LEED Platinum in design and construction, including Greens-burg’s new City Hall building, shown here under construction. The new building design also integrates photovoltaic panels, geother-mal technology, reclaimed brick, and recycled wood and other materials. Courtesy: City of Greensburg, Kansas




renewables

In addition to being designed to LEED Platinum standards, the K-12 campus and school building in Greensburg will become teaching tools. The school is expanding its curricula on energy and green technologies with hands-on educational experiences to help students understand the real world of energy and sustainability. The town is also encouraging youth to take leadership roles: under the sponsorship of Greensburg GreenTown, the community’s high school students operate a Green Club.

Seeing Green for the Long TermRight after the tornado, one of the local vi-sionaries, Daniel Wallach, started the non-profit organization Greensburg GreenTown to assist the city with its green vision and advocate for sustainable rebuilding and growth. Nearly three years later, Greensburg GreenTown is still a major spark plug in keeping the vision alive and growing. Along with its precedent-setting policies and heroic efforts to embrace sustainability, Greensburg has high hopes for how others will respond to the community.

“We’d like to see Greensburg become the ecotourism capital of the world,” said Mayor Bob Dixson. “Companies can bring their cus-

tomers here to see sustainable building prod-ucts and all kinds of eco-friendly businesses. We want to be a living laboratory.”

Greensburg also hopes to attract companies that can draw on the resources of the prairie for a variety of green purposes, from research to entrepreneurial manufacturing. The town might very well meet its goals: Greensburg’s hard work and small-town values have struck a chord with both the national and interna-tional community.

And what did this do for the American taxpayers who funded the DOE and NREL to help Greensburg? First, NREL and its subcontractors provided unique and valu-able assistance to influence, design, and implement energy aspects of the overall community direction and dozens of indi-vidual projects. This included all aspects of energy: energy portions of the new community master plan; energy efficiency strategies and tactics for residential and commercial buildings; specific informa-tion and design assistance for many in-dividual buildings and homes; feasibility studies and recommendations for using wind, solar, and biomass technologies within the community; analysis and rec-ommendations on advanced vehicles and

fuels for transportation; and assistance with outreach and community education.

Second, this extensive effort was well documented publicly and within the DOE and NREL so that the lessons learned in the first three years of building a green Greensburg could be applied to similar communities across the U.S.—and per-haps the world. —Lynn Billman ([email protected])

is a senior project leader for the National Renewable

Energy Laboratory.

For More Information U.S. Department of Energy Greens-

burg website: www.eere.energy.gov/buildings/greensburg

Greensburg Sustainable Building Data-base: http://greensburg.buildinggreen .com

Greensburg GreenTown: www.greensburg-greentown.org

City of Greensburg: www.greensburgks .org

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COFIRING BIOMASS

OPG Charts Move from Coal to BiomassIn response to Ontario’s provincial regulatory mandates to phase out the use

of coal by the end of 2014, Ontario Power Generation (OPG) is explor-ing its capability to employ biomass feedstocks to displace coal in some units within the OPG thermal fleet. The primary fuels employed during the respective trials at its Nanticoke and Atikokan Generating Stations have been agricultural by-products and commercial grade wood pellets. The Canadian utility has learned valuable lessons about fuel supply and logis-tics, and the technical challenges of safely handling and firing high levels of biomass.

By Les Marshall, Chris Fralick, and Daryl Gaudry, Ontario Power Generation

As part of its strategy to reduce green-house gas emissions, the Ontario provincial government adopted a

regulation in 2007 that will phase out the generation of electricity from coal in On-tario Power Generation’s (OPG) coal-fired generating stations by Dec. 31, 2014. The government has also identified interim tar-gets that will limit carbon dioxide (CO2) emissions from OPG’s coal-fired fleet to two-thirds below 2003 levels by 2011.

OPG has an installed capacity of 21,748 MW, consisting of a diversified generation mix in 2008 of 45% nuclear, 34% hydro, and 21% fossil-fueled electricity. OPG operates five fossil-fueled stations (four coal-fired and one gas/oil) with an installed capacity of 8,177 MW and co-owns two other gas-fired stations.

In 2007, OPG installed a direct injec-tion system for agro-biomass with a capac-ity of 50 MWe at its 3,640-MW Nanticoke Generating Station (GS). However, much of the success of the current program has entailed the use of the dedicated mill con-cept, in which wood pellets are processed through the existing coal pulverizers, without coal, and are subsequently con-veyed to the furnace with the existing fir-ing systems.

In 2008, proof-of-concept testing was conducted at OPG’s Atikokan GS to assess the feasibility of operating the 227-MW lignite boiler with various percentages of biomass, specifically pelletized wood. The Atikokan program also employed the dedi-cated milling concept. This article discusses the lessons learned from the projects at both plants and what OPG’s future aspirations are as far as converting from coal to biomass as its major fuel source.

Regulatory EnvironmentAt the federal level, the Canadian govern-ment has indicated an intention to regulate greenhouse gases on an intensity basis. It has also indicated that it will align with the U.S. system, which is likely to be a cap-and-trade system.

In February 2009, the Ontario government also announced its Green Energy Act (Bill 150), aimed at expanding renewable energy generation and strengthening the province’s commitment to energy conservation. The new procurement mechanism for new renew-able energy will be delivered through a feed-in tariff, modeled after the successful policies of Germany and France.

Since 2005, OPG and, in particular, the

Nanticoke GS, have been investigating the use of biomass as a coal offset option. How-ever, as a result of the recent regulatory direc-tive to phase out coal, the replacement of coal with biomass in some of its coal units has be-come the focus of OPG’s biomass program at its coal-fired generating stations.

Compared to some renewable energies such as wind and solar, biomass has the added benefit of being dispatchable, which means that it is capable of responding to the changing load demand when needed. Other benefits related to a large-scale biomass in-dustry in Ontario are the synergies with agri-culture and forestry sectors and the favorable economics of using existing provincial assets (the coal plants).

1. Leading the way. The Nanticoke Generating Station is located on the north shore of Lake Erie. Both it and its sister facility, the Atikokan Generating Station, are pioneering the use of bio-mass as a renewable energy source for their operations. Courtesy: Ontario Power Generation

08_040110_SR_CofiringBiomass_p30-37.indd 30 3/16/10 2:50:36 PM



COFIRING BIOMASS

The guiding principles for OPG’s biomass testing program are as follows:

OPG does not use food products fit for hu-man consumption.

OPG only uses biomass extracted using sustainable practices (as defined by the United Nations Framework Convention on Climate Change).

OPG intends to maximize the use of exist-ing assets.

Nanticoke’s Early Biomass ProjectThe Nanticoke Generating Station (Figure 1) is equipped with eight units, each with a nominal rating of 500 MW. The boilers are of the opposed-fired configuration, originally designed to fire a mid-sulfur bituminous coal. Currently, the Nanticoke boilers fire a furnace blend of 80% (by energy) Powder River Ba-sin subbituminous coal with 20% low-sulfur eastern bituminous coal (see table). The units are equipped with five 10E10 ball-race pul-verizers. All five mills are required for full load.

In 2005, Nanticoke was approached by the Ontario Ministry of Agriculture, Food and Rural Affairs and the Ontario Millers’ As-sociation regarding the possibility of displac-ing some portion of its coal-fired generation with biomass. In 2006, Nanticoke conducted its first proof-of-concept biomass injection test using wheat shorts, a by-product of the milling of wheat to flour (see table). A single truckload of wheat shorts was brought to the site, and the integrated compressor on the truck was used to convey the biomass into the outlet pipes of a single pulverizer (mill 4E). This configuration was very rudimentary, but

the results were encouraging enough to merit a series of follow-up tests in 2007, using a pair of blower trucks, each injecting wheat shorts into one of the two mill outlet lines of pulverizer 4E.

The initial test program provided the first results to OPG regarding the impact of bio-mass use on the firing systems and acid gas emissions. However, due to the nature of the truck unloading method (compartmentalized biomass, gravity fed to an onboard blower), it was difficult to control the biomass injection rate and avoid line pluggage. In addition, this mode of operation was limited in both capacity and duration. The need for a larger, engineered system was recognized in order to better dem-onstrate the potential of biomass at Nanticoke.

Nanticoke’s Direct Injection SystemThe direct injection system was placed into service in 2007. The facility consists of two dedicated injection systems, each with a stor-age silo, screw feeder, rotary air lock, injec-tion blower, and transport lines (Figure 2). The biomass transport lines are 8-inch pipes that connect to the pulverizer outlet lines of mill 4E. As before, the use of biomass is in-tended to specifically displace bituminous coal. The capacity of each silo is 69 mega-grams (Mg) and the maximum injection rate of each system is 16 Mg/hour. The total bio-mass input of 32 Mg/hour can produce up to 50 MW of electrical output. The installation includes fundamental safety systems—elec-trical grounding for truck unloading, dust collection, and explosion venting—and the operation of the injection is interlocked with the target mill and boiler protections.

The blower serving each injection line

provides about 6 Mg/hour of transport air to convey up to 16 Mg/hour of granular bio-mass. During testing, the associated mill is operated in manual mode, at 50% of its nor-mal coal feed rate. The primary air (PA) to this mill is also placed in manual to allow for additional primary airflow to properly trans-port the coal/biomass mixture downstream of the pulverizer. Relatively high airflows have been employed to provide a level of margin against saltation (dropout) when conveying the coal/biomass mixture in the burner lines.

The blend of 50% bituminous coal (by en-ergy) and 50% biomass input on this burner row produces stable burner flames without the need for auxiliary gas support. In addition to the net reductions in CO2 emissions, the larg-est impacts have been in the area of acid gas emissions. The reduction in the total fuel sul-fur content—by displacing bituminous coal with biomass—resulted in the expected drop in SO2 emissions. For the Nanticoke case, with a 10% wheat shorts input, corrected SO2 emissions were seen to drop by approximately 10%. NOx production is a much more com-plex issue. Previous utility experience with biomass cofiring has produced both increases and reductions in NOx emissions.

A number of technical issues were encoun-tered with the direct injection system. First, operational sustainability proved to be more difficult to achieve than anticipated. This was primarily due to the design reliance on blower trucks to provide a continuous supply

Parameter UnitsPowder River

BasinEastern

bituminous Wheat shorts Wood pellets

Ultimate analysis (as-fired)

Carbon % 51.18 72.57 41.82 50.50

Hydrogen % 3.49 4.98 5.46 6.00

Nitrogen % 0.66 1.22 2.59 0.15

Sulfur % 0.23 0.85 0.21 0.01

Oxygen % 12.70 5.70 32.88 40.50

Ash % 4.51 8.59 4.24 0.33

Moisture % 27.20 6.00 12.80 5.52

Proximate analysis (as-fired)

Fixed carbon % 37.50 53.00 17.88 12.50

Volatile matter % 30.80 32.41 65.08 81.65

Ash % 4.50 8.59 4.24 0.33

Moisture % 27.20 6.00 12.80 5.52

Higher heating value

MJ/kg 20.50 30.20 16.70 19.30

Btu/lb 8,800 12,400 7,200 8,297

2. Dedicated injection systems. The direct injection system, which uses granular agricultural biomass as a fuel source, was placed into service in 2007. The facility consists of two dedicated injection systems, each with a storage silo, screw feeder, rotary air lock, injection blower, and transport lines. Courtesy: Ontario Power Generation

A comparison of cofired fuels. Source: Ontario Power Generation




COFIRING BIOMASS

of biomass. Availability of blower trucks and variability in the condition of the onboard blower proved to be significant impediments. Second, the system is not equipped with mill-ing capability and can therefore not process pelletized fuel.

As the biomass program evolved, it be-came more apparent that developing the capability to handle pelletized fuel was es-sential. Fuel supply economics and flexibil-ity as well as higher generation levels (vs. cofiring) required pelletized fuel.

Nanticoke’s Direct Milling ProgramDirect injection biomass systems are among the most effective way to employ significant volumes of biomass via cofiring. However, it is expected that commercial operation will require that the biomass is densified in some form to facilitate long-distance transportation. The Nanticoke team examined ways that com-mercial grade wood pellets (see table) could be directly used within the existing systems. This review determined that several European utili-ties possessed experience with handling wood pellets in modified coal pulverizers. OPG re-fers to this technique as the dedicated milling concept to differentiate it from the more famil-iar co-milling of biomass and coal.

In the dedicated milling concept, pure wood pellets are handled with the existing coal-handling systems (conveyors, bunkers, and gravimetric feeders) and are introduced into the pulverizers on a pure basis—without coal. The trials to date at Nanticoke have been conducted on unmodified pulverizers. However, the method does require at least two significant operational changes. First, the PA employed for wood milling must be relatively cold, as biomass releases volatile matter at significantly lower temperatures than coal. The Nanticoke trials used a tar-get mill inlet temperature of 65C to address this issue. The second change relates to the required minimum primary airflow that can both effectively fluidize the wood dust in the mill and provide stable pneumatic transport downstream in the burner lines.

This aspect of the Nanticoke program commenced with a proof-of-concept test on one pulverizer, using a single truckload (35 Mg) of commercial grade wood pellets. The initial unloading of the truck into an emer-gency reclaim hopper produced a significant quantity of dust, most of which appeared to have been generated during transportation to the site. Downstream of this point, the pellets were conveyed by the existing coal-handling systems without any major issues.

The mill required a longer time period (about 30 minutes) to stabilize, and the final mill differential pressure was higher (similar to full mill load on coal). The temperature dif-

ferential across the pulverizer was about 20C, confirming that only a modest level of drying was necessary with the relatively dry pellets.

The test proceeded uneventfully until the delivered wood pellet supply was consumed. At this point, a standard pulverizer cleaning cycle was started. At Nanticoke, this mill-clearing cycle involves a full 20 minutes of operation with maximum cold primary air-flow in order to blow the mill clear. In prac-tice, this typically only requires between 5 to 10 minutes. However, following a wood pel-let test, this clearing operation was seen to require more than 60 minutes. It is thought that there was insufficient lift velocity in the mill body to effectively remove the larger wood particles from the mill. This has obvi-ous impacts on the flexibility of the unit and may also represent a potential safety concern if the recirculating wood dust in the mill be-gins to generate heat via friction.

The effective throughput of a mill handling wood pellets is limited by the available cold PA capacity. The Nanticoke PA system oper-ates at 15 kPa, but the mills are equipped with relatively small tempering air ducts. Modifi-cations to reduce the mill differential and to expeditiously transport the wood particles from the mill are currently under study.

Nanticoke’s Testing Shifts away from Cofiring with CoalWith the adoption of the coal phase-out regulation in 2007, OPG’s testing program changed from focusing on cofiring with coal to determining generation capability without the use of coal. A series of wood pellet tests had been conducted at the Nanticoke GS on different mill configurations and with various throughputs and test durations. In 2008 all of the Unit 4 mills were individually tested with pellets to confirm and address any anomalies with the equipment. In November 2008, Nan-ticoke conducted the first test of a full boiler operating on biomass fuel.

This larger trial was conducted at a load of 175 MW with initial operation on coal. A transition to wood firing was made over the course of the test as the coal in the bunkers was exhausted. As before, the gas igniters were maintained in service for wood firing. The low load point was chosen, as the team expected that PA capacity would be the first limit encountered, and this was indeed the case. With all five mills in service on wood pellets, the maximum total biomass furnace input was 104 Mg/hr. Note that the gas ignit-ers provided a significant quantity of energy at their minimum (default) settings. In this case, wood energy represented some 82% of the total furnace input with the balance from natural gas. In simple terms, prorating these inputs yields electrical outputs of about 145

MW from wood and 30 MW from gas.High hot reheat steam temperatures were

observed, especially at lower loads. It was necessary to intentionally depress the main steam temperature setpoint in order to bring the reheat temperatures under control.

The impact on the air heaters was much more dramatic. The use of cold PA in all of the mills created a significant energy imbal-ance at the PA heater. This has an obvious negative impact on boiler fuel efficiency, but, more importantly, the elevated temperatures are approaching the limits of some down-stream components in the electrostatic pre-cipitator (ESP) and the stack.

NOx emissions were basically unchanged from the base case with coal (at lower excess air). The test data indicate that there is cer-tainly room to lower excess air with wood firing, but the current controls configuration does not allow this due to a low windbox pressure limit.

Management of dust levels during pel-let unloading and conveyance to the coal bunkers was a significant health and safety concern. Through the dedicated milling tri-als, we found that different wood pellets have very different dusting propensities, despite similar chemical properties. Consequently, a number of measures were implemented to mitigate the health and safety concerns from dust, including:

The application of a light steam to the pel-lets at transfer points. Management of the dust with typical coal dust suppression was a challenge due to the fact that the pellets needed to be kept dry to avoid pluggage.

The use of vacuum trucks at coal transfer chutes as a rudimentary dust extraction tool.

Limiting access to the coal conveyor gal-lery and the use of respirators and personal air quality monitors (O2, CO, and CH4) for required personnel.

The use of area dust monitoring through-out the pellet transfer process.

Atikokan Generating Station’s Test ProgramFollowing the lead of the Nanticoke GS, the Atikokan GS began setting up its own test program related to using pelletized biomass as a fuel source.

The Atikokan GS is located in northwest Ontario and is equipped with a single Bab-cock & Wilcox natural circulation boiler of the opposed-fired design. Five MPS 75G roll-race pulverizers supply fuel to a total of 15 dual-register low-NOx burners. The boiler is equipped with a single regenerative sec-ondary air heater and a dedicated PA heater. Two cold side ESPs provide particulate capture. The unit is rated at 227 MW with



COFIRING BIOMASS



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COFIRING BIOMASS

main steam and hot reheat temperatures of 538C. Low load steam temperature control is facilitated by flue gas recirculation. The Atikokan GS fires lignite coal from western Canada, delivered by rail and received at a rotary car dumper.

The Atikokan pulverizers are of the roll-race design, originally designated MPS 75G. These mills have a baseline coal capacity of 40.8 Mg/h when grinding coals with a Hard-grove Index of 50 to a bulk fineness level of 70% passing 200 mesh. All of the Atikokan mills are equipped with the original static classifiers. Over the course of this test pro-gram, some of the mills were retrofitted with rotating throats. These modifications from the original static throats were conducted as part of a maintenance upgrade but also result-ed in additional valuable observations.

Atikokan’s Dedicated Milling ConceptA small team was organized to assess the ability of the Atikokan boiler to handle pel-letized biomass via the dedicated milling concept. Coal pulverizers have been modified to handle wood pellets on a commercial basis in at least three cases: Hasselby (Sweden), Avedore 2 (Dong Energy, Denmark), and Amer 9 (Essent, Netherlands). The Atiko-kan team incorporated the observations from these projects as well as their own internal experience with this technique at the OPG Nanticoke GS.

When using roll-race or ball-race pulver-izers to grind biomass pellets, the utility op-erator must consider three critical issues:

Limited size reduction. Coal pulverizers depend on fracture mechanics to grind coals to particle sizes in the 75-micron neighborhood. However, the fibrous na-ture of biomass materials does not lend itself to this mechanism. The grinding elements in a traditional coal mill can be expected to reduce the biomass pellet back

into its constituent dust. It is critical that the dust used to form the biomass pellets is of a suitable particle size distribution to allow for stable pneumatic transport and efficient combustion.

Higher primary air requirements. It is reasonable to assume that the much larger wood particles—in the 1 to 3 mm range—will require higher line velocities than are employed for pulverized coal to avoid dropout in the burner lines. OPG has em-ployed the Rizk correlation to determine the saltation velocity limits for a variety of fuel/air ratios and a range of particle sizes.

Cold primary air. Biomass has been shown to release significant quantities of volatile matter at temperatures as low as 200C. At Atikokan, it was decided to use cold PA to avoid the issue of early volatile matter release. Mill inlet temperatures are held in the 50C to 70C range for dedicated mill-ing of wood pellets. This has been found to be more than adequate to perform the limited degree of drying necessary with processed wood pellets.

Atikokan’s First Proof-of-Concept Test In January 2008 the first proof-of-concept test at Atikokan was conducted. This test employed only a single truckload of com-mercial grade wood pellets. Approximately 26 metric tons of pellets were delivered to the site in “super sacs.” A simple cutting tool was used to empty the pellets into a reclaim hopper, where they were processed using the existing coal-handling system without any issues (Figures 3 and 4).

This first test was conducted at a wood pellet flow of 5 kg/s (18 Mg/h) with a cold primary airflow of 20 kg/s. The pulverizer differential pressure while operating with wood was observed to be much higher than that for lignite, and the period for stabiliza-tion was also longer. The PA header pressure was increased from 10.5 kPa to 11.5 kPa to maintain the target airflow.

Given the very low sulfur content of wood, a significant reduction in SO2 emissions was observed, as expected. However, it is notable that the full benefit of the lower-sulfur fuel blend did not become apparent until the mill fully stabilized on wood.

The final key observation from this initial short test was the relatively long clean-out cycle required to clear the mill of wood dust at the conclusion of testing. This phenom-enon had been previously observed during dedicated milling trials at the Nanticoke GS. This represents a potential safety concern over the long term if friction within this large recirculating bed were to generate enough heat to pose a fire hazard.

Atikokan’s Process OptimizationThe next single mill test series in March 2008 had three main objectives:

Complete displacement of coal on a single burner row—such as a 20% furnace en-ergy input level.

Operation without the need for natural gas support for flame stability.

Assess the sensitivity of NOx emissions to the higher burner nozzle velocities associ-ated with the firing method.

The larger fuel demands of this test re-quired that the wood pellets be delivered by rail. To protect the pellets from the elements, covered grain cars were used to deliver pel-lets to the site. As a result, the normal rotary dumper could not be used (Figure 5).

This larger delivery of wood pellets al-lowed for a longer test at the target feed rate. Mill #3 was operated with a throughput of 6.8 kg/s (24.5 Mg/h) for this test—equivalent to 20% of the furnace energy input. Cold pri-mary airflow was again maintained at a base value of 20 kg/s. Mill differential was very stable under these conditions.

3. Pellet power. Wood pellets are shown being unloaded at the Atikokan Generating Station during the initial test, which occurred in January 2008. Courtesy: Ontario Power Generation

4. A long climb. The wood pellets are moved at the Atikokan facility on the tripper belt. Courtesy: Ontario Power Generation

5. Baptism by fire. This photo shows the unloading of the wood pellets via the bottom hoppers of the grain cars. After being unloaded at the Atikokan Generating Station, the pellets underwent wood firing as part of a test pro-gram. Courtesy: Ontario Power Generation



COFIRING BIOMASS


COFIRING BIOMASS

In general, the flame conditions on the burners firing wood were observed to be bright but somewhat detached from the burner nozzle. With the mill stabilized, the operations staff began to make stepwise ad-justments to the airflow and spin vane set-tings on these burners.

The final objective considered during this test involved NOx emissions. Previous cofir-ing trials in the U.S. and Europe tend to show a modest but repeatable reduction in NOx emissions when cofiring with wood. Further-more, the level of the NOx reduction tends to increase with an increase in the wood energy input.

However, the observations with wood co-firing at the Atikokan GS are that for biomass input levels in the 20% range, NOx emissions are mostly unchanged when compared with the baseline lignite performance, with one exception. Corrected NOx emissions did drop approximately 10% with a 10% reduction in the primary airflow to the dedicated wood pulverizer in conjunction with operational adjustments to the associated burner row. A single burner row represents about 20% of the furnace energy input.

Atikokan’s Attempts at 100% Wood FiringIn July 2008, a series of tests were conducted at the Atikokan GS with the ultimate objective of assessing the unit’s potential to operate on 100% wood pellet fuel. A number of significant observations were made during this program and are discussed in the following sections.

Startup with Wood. During the previ-ous single mill trials, boiler load was always carried with the remaining four mills oper-ating with coal. The July 2008 test program included trials with all five mills firing wood pellets, making the transition from coal to wood firing rather challenging. The test team determined that starting the unit on wood fuel (following initial firing on natural gas) would solve these logistical difficulties and provide important information as well. The mill coor-dination curves were modified for future tests to allow for better control during both start-up and stable operation.

Air Heater Mass/Energy Balance. The use of cold PA on a single mill has a notice-able impact on the heat transfer performance of the primary air heater (PAH). With all five mills operating on essentially cold PA, system performance was seen to degrade dramati-cally. Operating at unit MCR on pure wood, the PAH gas outlet temperature was seen to increase by more than 40C, to approximately 200C, and then stabilize at this level follow-ing adjustment of the gas-balancing damper. The additional gas flow to the secondary air heater (SAH) caused the outlet gas tem-

perature to increase to almost the same level. Long-term operation with such elevated tem-peratures might create issues for induced fan shaft growth and the integrity of the stack liner and associated components.

Wood Pulverizer Trip and Restart. An-other key issue when considering a complete fuel conversion of this type regards the impli-cations of a pulverizer trip on wood fuel. Mill #3 was tripped from very high load (8.6 kg/s) and subsequently restarted with a deep bed of wood dust around the grinding elements. Aside from a brief spike in the mill mo-tor current (this also occurs during a restart with lignite) the restart proceeded smoothly and the mill returned to normal operation on wood without any further issues.

Steam Temperatures. The previous tri-als at relatively modest levels (<20%) of wood input did not result in significant im-pact on the boiler’s thermal performance. However, at wood energy input of 67% and 100%, both the main steam and hot reheat steam temperatures were observed to be well below their design values on coal. This is the expected trend for the fuels involved, but the magnitude of the temperature depression was rather surprising.

Primary Air System Limitations. The capacity of the existing PA system was found to be marginal at full unit load on 100% wood pellet firing. The cold primary airflow available to each mill was approximately 18 kg/s—some 10% below the target value.

Pulverizer Throats. As part of an existing maintenance upgrade program, Atikokan GS has been replacing the original equipment manufacturer static throats in the pulveriz-ers with a third-party rotating throat design. In general terms, those mills with rotating throats operate with about half the pulver-izer differential of a static throat. The rotat-ing throat also appears to stabilize faster, and there is a small benefit in a reduced time for the clearing cycle.

NOx Emissions. As noted previously, the various cofiring trials at Atikokan yield-ed fairly flat results with respect to NOx re-ductions. NOx was shown to be sensitive to the high transport velocities used in the test program, but the final results were gener-ally similar to those for the base lignite coal. However, operation with higher levels of co-firing and with 100% wood firing resulted in a definite change in NOx performance—from 0.79 kg/MWh to 0.53 kg/MWh. The baseline NOx rate for Atikokan firing lignite at MCR is 1.50 kg/MWh. The value of 0.53 kg/MWh is equivalent to other OPG units with selective catalytic reduction technology installed.

Heat Rate. Low final steam temperatures and elevated flue gas exit temperatures both have an obvious negative impact on the heat

rate of the unit. The expected degradation in heat rate is on the order of ~4%.

Challenges Related to Complete Conversion from Coal to WoodThe Atikokan biomass test program has in-cluded operational trials with up to 633 MJ/s of wood input. This is a remarkable achieve-ment for an unmodified pulverized coal (PC)-fired boiler, but a number of issues will require attention and investment to enable safe, com-mercial operation. Any fuel conversion might require physical equipment modifications in addition to changes in operation. The complete conversion from coal to wood for a utility PC-fired boiler is expected to result in a number of unique challenges, discussed below.

Safe Material Handling. Later in 2008 the Atikokan plant experienced a dust explosion while bunkering wood pellets in preparation for further tests. Review of this incident has lead OPG to conclude that major modifica-tions to coal-handling systems must be made in order to ensure the safe handling of bio-mass fuels. Specific findings include these:

Receiving systems should include the capability to screen deliveries of pellets to remove dust and fines that might have been generated during transportation.

Fire and explosion detection and suppres-sion systems are needed.

A thorough review of the design and limi-tations of existing bunkers, conveyors, and transfer points is necessary.

In addition to the dusting risks associated with use of coal conveyor systems, other techniques used for the bulk solids handling of a fuel like wood pellets are quite different from those traditionally used by utility sites with coal. Possible considerations include the following:

The need to protect the pellets from the elements during transportation to the site and during long-term storage.

Including provisions for significant cov-ered storage in the site design.

Firing Systems. In addition to the man-datory retrofit of additional safety systems, several other areas of operation would require further attention to fully employ the dedicated milling concept on a commercial basis:

Modifications that promote the expedi-tious removal of wood from the mill and reduce the volume of recirculating product in the pulverizer.

Further study into the minimum safe ve-locity required for effective pneumatic transportation.




COFIRING BIOMASS

Modification or complete replacement of the burners.

Corrosion. Corrosion—via KCl forma-tion—is a known concern for pure wood com-bustion. Much of the current research on this topic involves the lack of sufficient sulfur to pro-mote formation of the less-aggressive K2SO4. It may prove to be sufficient to merely “dope” the pellets with a sulfur-bearing compound.

Boiler Performance. Changes to the superheater/reheater tube banks may be

necessary to improve steam temperature performance (possibly including a materi-als upgrade to address corrosion). The air heater mass imbalance will need to be ad-dressed, but it may not be feasible to simply convert the existing PA heater into a second SAH.

Emissions Controls. The SO2 and heavy metal emissions related to wood fir-ing are naturally very low. The NOx per-formance observed during the Atikokan trials is also very encouraging, possibly

eliminating the need for additional NOx controls. The OPG experience at Atikokan regarding wood ash collection in a cold side ESP has been good.

Looking ForwardOPG’s biomass test program at the Nanti-coke and Atikokan Generating Stations is part of the overall development of biomass as a fuel to replace coal in some of its coal-fired generating units.

To further develop the business case for the biomass option, OPG’s biomass program is focused on the following:

Determination of unit conversion modifi-cations (including all safety measures) and unloading and storage facilities required for commercial scale operation.

Assessment of different biomass fuels (energy crops, agricultural by-products, wood), including analysis of balance-of-plant combustion-related issues through pilot scale experiments.

Fuel supply chain analysis, including bio-mass availability (both agricultural and wood-based) and transportation logistics.

Analysis of the complete economic model associated with the development of the biomass option (including capital costs and revenue structure).

Complete greenhouse gas life cycle anal-yses of biomass (both agricultural and wood-based) compared to coal.

Stakeholder involvement through continu-ing to work closely with the various gov-ernment sectors (Ministry of Energy and Infrastructure; Ministry of Northern De-velopment, Mines, and Forestry; Ministry of Agriculture, Food, and Rural Affairs; and Ministry of Environment) and an ex-tensive stakeholder network.

The development of a biomass industry in Ontario represents an exciting opportunity for OPG’s coal fleet. The biomass program has the potential to contribute to the expan-sion of Ontario’s renewable energy portfolio by contributing dispatchable, renewable bio-mass energy.

—Les Marshall ([email protected]) is the senior technical officer at Ontario

Power Generation (OPG) in Nanticoke, Ontario, Canada. Daryl Gaudry (daryl.

[email protected]) is the production su-pervisor of operations at OPG’s Atikokan Generating Station in Atikokan, Ontario.

Chris Fralick ([email protected]) was formerly the manager of chemical and

environmental services at the Nanticoke Generating Station and is currently pro-duction manager at OPG’s Thunder Bay

Generating Station.

NOTE: Images are hires ready. Trim: 4.5625” x 7.5” _POWER MAG 4C

GEOTHERMAL • SOLAR • BIOMASS • WASTE HEAT • WIND

©Solutia Inc. 2008. Therminol®, TLC Total Lifecycle Care® and Solutia and INFINITY LOGO® are trademarks of Solutia Inc, registered in the U.S. and in other countries. *Available only in North America.

PUT THE POWER Of THE THERMINOL® PERfORMANCE CREW TO

WORK fOR ALTERNATIVE ENERGY.In the heat transfer fluid race the competition can get pretty heated. That’s why you need the Therminol® Heat Transfer Fluid Performance Crew working for you. From start to finish, the Therminol TLC Total Lifecycle Care® team of seasoned professionals is ready to support you with everything you need to win. For your people, we provide start-up assistance, operational training and a technical service hotline. For your facility, we offer system design, quality Therminol products, sample analysis, flush fluid & refill and a fluid trade-in program*. We provide everything you need to keep your heat transfer system at peak performance throughout its lifecycle. So join the winning team. In North America call 1-800-426-2463 or in Europe 32.10.48.15.47. You’ll see no other heat transfer fluid delivers more proven comprehensive performance than Therminol.

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ELECTRIC INDUSTRY’S #1 EVENTElectricity issues make national news every day. Federal initiatives and economic stimulus funds are directed toward renewable energy, transmission expansion, smart grid, carbon capture and storage, energy efficiency and electric vehicles. Climate and energy continue to be discussed in Congress. All of these issues and more are on the agenda for the Edison Electric Institute’s Annual Convention in Hollywood, FL, June 13-16.

• Targettheindustry’smostimportantstrategictopicsattheCriticalIssueForums.

• Hearheadline-makingspeakersattheGeneralSessions.

• Stayonthecuttingedgewiththelatesttechnologies,productsandservicesattheExpo.

• Networkwithindustryleadersandyourpeers.• EnjoyaspectaculareveningofFloridafunand

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Get a clear view of the electricity issues transforming the nationAttheCriticalIssueForumswithindustryexecutives,you’llgetaclearviewoftheelectricityissuestransformingourenergyfuture.Lastyear,morethan50CEOsandseniorexecutivesaddressedtheforums.Thisyear,topicsyoucanexploreinclude…

• TheSmartGridToday• EnergyStorageOptions• SolarEnergySuccessStories• ElectricVehicleImpacts• CarbonCaptureandStorage

• IntegratingRenewableEnergy• EnergyEfficiencyasaBusiness• ElectricIndustryPartnerships• MovingForwardonNuclear• AssessingElectricBusinessOptions

Join other leaders as they address America’s electric future!For convention and hotel registration, discount flights, and programming updates— as well as information on exhibiting and sponsoring, visit…

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COFIRING BIOMASS

Host Company:

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ELECTRIC INDUSTRY’S #1 EVENTElectricity issues make national news every day. Federal initiatives and economic stimulus funds are directed toward renewable energy, transmission expansion, smart grid, carbon capture and storage, energy efficiency and electric vehicles. Climate and energy continue to be discussed in Congress. All of these issues and more are on the agenda for the Edison Electric Institute’s Annual Convention in Hollywood, FL, June 13-16.

• Targettheindustry’smostimportantstrategictopicsattheCriticalIssueForums.

• Hearheadline-makingspeakersattheGeneralSessions.

• Stayonthecuttingedgewiththelatesttechnologies,productsandservicesattheExpo.

• Networkwithindustryleadersandyourpeers.• EnjoyaspectaculareveningofFloridafunand

seafoodattheGrandEvent.

Get a clear view of the electricity issues transforming the nationAttheCriticalIssueForumswithindustryexecutives,you’llgetaclearviewoftheelectricityissuestransformingourenergyfuture.Lastyear,morethan50CEOsandseniorexecutivesaddressedtheforums.Thisyear,topicsyoucanexploreinclude…

• TheSmartGridToday• EnergyStorageOptions• SolarEnergySuccessStories• ElectricVehicleImpacts• CarbonCaptureandStorage

• IntegratingRenewableEnergy• EnergyEfficiencyasaBusiness• ElectricIndustryPartnerships• MovingForwardonNuclear• AssessingElectricBusinessOptions

Join other leaders as they address America’s electric future!For convention and hotel registration, discount flights, and programming updates— as well as information on exhibiting and sponsoring, visit…

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A global leader in generation technologyAnsaldo Energia supplies and services complete power plants, as well as components including gas turbines, steam turbines, and generators

Ansaldo Energia SpA, a Finmeccanica company, is Italy’s leading producer of

thermoelectric power plants. Ansaldo has an installed capacity of over 177,000 MW in

more than 90 countries.The company’s main business areas are:

• turnkey thermal power plants and compo-nents (coal and gas, including single and combined cycle);

• power plant service;• nuclear power; and• renewables and distributed generation.With the ending of previous licensing agree-ments, Ansaldo now offers its own line of gas turbines – the AE64.3A, AE94.2, and AE94.3A – with improved flexibility and maintainability. They feature a new combus-tion system known as VeLoNOx, based on a partially premixed pilot configuration. The burner, which can achieve less than 15 ppm NOx on a wide load range, has been tested for several years on the V/AE94.3A gas tur-bine. A second generation of VeLoNOx now provides the same low emissions at higher combustion chamber temperatures.

Ansaldo Energia has considerable experience with opportunity fuels, includ-ing both refinery off-gases with very low heating values and gases containing high proportions of hydrogen.

In a recent reorganization the compa-

ny’s Dutch and Swiss subsidiaries, working in the Original Service Provider (OSP) ser-vice business, have changed their names to Ansaldo Thomassen (ATH) and Ansaldo ESG (AESG) respectively. A subsidiary of the Dutch company, Ansaldo Thomassen Gulf, is opening a new enlarged shop in Abu Dhabi to support all service and maintenance activities in the Middle East area.

Service offerings cover spares, repair, maintenance, repowering, requalifications, monitoring and diagnostics, and LTSAs.

ATH, ATHG and AESG continue as centres of excellence for GE gas turbines and Alstom steam turbines technologies, respectively. Steam turbine production covers power rat-ings of 80–1,200 MW.

Generator production comprises air-, hydrogen- and water-cooled models for cou-pling to all turbines supplied by Ansaldo.

Traditional subsidiaries of Ansaldo Energia remain Ansaldo Fuel Cells, recently expanded to cover more renewables, and Ansaldo Nucleare. Ansaldo maintains a profitable cooperation with Westinghouse in developing plants based on the AP1000 reactor. www.ansaldoenergia.com

Ansaldo Energia offers its own range of improved low-NOx gas turbines

Italy: a case study in creating diversityOnce heavily dependent on imported oil for its power, Italy has moved successfully into gas and renewables, plans to re-start its nuclear program, and is converting back to coal

Italy is not rich in minerals. There is natu-ral gas in the Po Valley and offshore in

the Adriatic Sea, but little coal or oil. The country also has had no nuclear power of its own since shutting down its two working reactors shortly after the Chernobyl acci-dent in 1986.

As a result, Italy imports around 86 per-cent of its energy needs, including 93 per-cent of its oil, 91 percent of its gas and 15 percent of its electricity (2006 figures). This reliance on imports makes Italian elec-tricity around 45 percent more expensive than the EU average.

As late as the 1990s, Italy obtained around 20 percent of its electricity from oil-fired plants. Now, the power mix stands at around 50 percent gas, 20 percent renewables, 15 percent coal, and 15 percent

Modern gas: E.ON’s 800 MWe combined-cycle plant at Livorno FerrarisContinued on p40

SIE

MEN

S

We are Energy.Our engineers build tailor-made plants to generate energy

that is safe, clean and always available. Reliable Service activities provideeven more guarantees for Customers who strive, like us, to achieve total quality.

www.ansaldoenergia.it

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We are Energy.Our engineers build tailor-made plants to generate energy

that is safe, clean and always available. Reliable Service activities provideeven more guarantees for Customers who strive, like us, to achieve total quality.

www.ansaldoenergia.it

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imported nuclear – this last, at 6.5 GW, making Italy the world’s biggest importer of electricity. Total annual power consumption in 2007 was 309 TWh, and installed gener-ating capacity is around 80 GWe.

Since 2005, Italian power company Enel has held stakes in French and Slovak nuclear plants, giving Italy access to nuclear power without having to site reactors within its own borders. In July 2009 the govern-ment announced a renewed commitment to Italian nuclear power, with new plants scheduled for startup around 2020.

A typical recent gas-fired project is the 400 million, 800 MWe Livorno Ferraris CCGT plant in the northern region of Piedmont. Built as a turnkey contract by Siemens, the plant is owned and operated by a joint venture by E.ON Italia and Berner Kraftwerke FMB. Careful attention to visual appearance, including underground cabling, distinguishes the outside of the plant. Inside, the two Siemens SGT5–4000F gas turbines, two heat-recovery steam genera-tors (HRSGs) supplied by STF SpA, compact Siemens SST5–5000 steam turbine and air-cooled condenser together achieve a ther-mal efficiency of nearly 57 percent.

Another notable new CCGT project is the 800 MWe plant at Gissi, in central Italy, operated by Abruzzoenergia SpA. With its two Alstom GT26 gas turbines, the plant can

operate within emission limits at capacities down to 25 percent of full load, allowing it to run overnight without shutting down.

Italy’s dash for gas has been tempered by a large proportion of renewable energy. Most of this comes from hydropower: thanks to the Alps, Italy is a European leader in hydro, with resources comparable to those of France and Sweden.

In 2008 Italy was the world’s seventh-largest producer of wind power, with installed capacity of 3.7 GW. The country has also invested heavily in solar photovol-taics (PV), and is a pioneer of smart grids. Geothermal heat has been exploited on a small scale for many years, and the Tuscany region aims to become a global centre of excellence in this technology.

The government’s long-term plan is for 50 percent gas, 25 percent renewables, and 25 percent nuclear – but coal-fired genera-tion is not going away any time soon. Facing high oil and gas prices, rising demand before the current recession, concerns over energy security, and a delay before new nuclear capacity comes on line, Italy has joined a European trend to burn more coal. Over the next few years, Italy will more than double its current reliance on coal, to around 33 percent.

Enel is going even further, with a plan to get 50 percent of its power from coal. The company is currently converting a 2 GWe

plant at Civitavecchia, near Rome, from oil to coal, and says it will do the same with the 2 GWe Porto Tolle plant in the Po delta.

Enel is Italy’s largest power producer, with around 40 GWe of capacity in Italy, plus almost as much again in other countries. Originally the monopoly generator and distributor, Enel is now one-third owned by the state.

With around 12.5 GWe of generating capacity, Edison takes second place behind Enel. Half of this capacity comes from Edison’s 50 percent stake in Edipower, whose assets were sold off (as Eurogen) by Enel in 2000. Italy’s Fiat and EdF of France own a majority stake in Edison.

Eni is a vertically integrated energy giant in which the state has a 30 percent interest. Its EniPower subsidiary has around 5.5 GWe of gas-fired capacity.

Electrabel, part of the Gaz de France/Suez group, has 3.3 GWe of generating capacity in Italy.

Terna, originally a wholly-owned subsid-iary of Enel, is responsible for most of Italy’s national grid. Acea is the second-largest grid operator.

Among engineering companies in the power sector, the largest is Ansaldo Energia. The company builds gas turbines, steam turbines and generators, and also operates in the nuclear sector.

Charles Butcher

Continued from p38

Envisioning the power plants of the futureFabricator STF supplies HRSGs, industrial boilers, heat transfer products, and environmental systems, while its subsidiary BWE builds boilers for the power industry

Since its establishment in 1937 STF SpA has steadily improved both engineering

solutions and manufacturing processes for combustion technology. To continue this evolution the company continues to invest heavily in its more than 300 employees, as well as in capital equipment.

Strategically located close to Milan, STF is capable of handling the whole proj-ect life cycle: from conceptual and detail design, through manufacturing in its own workshops, installation, and servicing. The company offers some 20 systems and products, including complex turnkey sys-tems, for power plants and other industrial applications.

STF’s mission is to work with the world’s largest generating companies to gener-ate one of our most precious assets: clean energy. Environmental protection plays an important role in STF’s product line, and the company offers a full range of air pollution control technologies.

In 2002, STF extended its reach through the acquisition of Burmeister & Wain Energy (BWE A/S), based in Copenhagen, Denmark. BWE, with its 150 engineers, is a global

leader in the design and supply of ultra-supercritical boilers – in which it boasts the world’s highest combustion efficiency – low-NOx burners, air preheaters, and abatement systems for SOx and NOx.

BWE was founded in 1843 when a young and enterprising engineer, Hans Heinrich Baumgarten, was awarded a royal license to establish a machine shop in Copenhagen. In 1846 he went into partnership with Carl Christian Burmeister.

Baumgarten was succeeded in 1865 by an Englishman, William Wain, who entered the business as a partner. Burmeister & Wain was founded seven years later and became Denmark’s largest and most impor-tant enterprise in the iron industry, as well as a company of international note.

Today BWE sets the benchmark in terms of efficiency and clean burning of the world’s most widely-available fuel: coal. The company carries out complex international engineering projects and delivers high-pressure steam boilers for oil, gas, coal and biomass combustion, as well as auxiliary processing and flue gas cleaning plants.

BWE engineers, manufactures and

erects boiler plants for private and public utility companies and industrial manufac-turers, and trains their staff. www.stf.it

Between them, STF and BWE cover a wide range of technologies for combustion and emissions control

MAGENTA (MI) - ITALYvia Robecco, 20Tel. +39 02 972091 Fax +39 02 9794977e-mail: [email protected] www.stf.it

BURMEISTER & WAIN ENERGY A/SDK - 2820 Gentofte.Denmarkjaegersborg Alle 164Tel. +45 39 45 20 00 Fax +45 39 45 20 05e-mail: [email protected] www.bwe.dk

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MAGENTA (MI) - ITALYvia Robecco, 20Tel. +39 02 972091 Fax +39 02 9794977e-mail: [email protected] www.stf.it

BURMEISTER & WAIN ENERGY A/SDK - 2820 Gentofte.Denmarkjaegersborg Alle 164Tel. +45 39 45 20 00 Fax +45 39 45 20 05e-mail: [email protected] www.bwe.dk

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BENCHMARKING

Benchmarking Nuclear Plant StaffingThe EUCG Nuclear Committee has collected benchmarking data of U.S. nuclear

plant staffing for many years. A summary of this highly desirable data was gleaned from EUCG databases and is now, for the first time, made public through an exclusive agreement with POWER.

By Dr. Robert Peltier, PE

Electricity consumption in the U.S. has decreased during each of the past two years—the first time that has hap-

pened since 1973–1975, according to U.S. Energy Information Administration (EIA) data. Historically, electricity consumption has correlated well with the nation’s gross domestic product (GDP), although electric-ity used per unit of GDP has been halved since 1970. Surprisingly, this trend seems to explode the long-held tenet that there is a strong statistical link between GDP growth and electricity consumption. The statistical correlation may have weakened, but a cer-tain and economic source of electricity is undoubtedly an essential ingredient for fu-ture economic recovery (Table 1).

The relationship between today’s eco-nomic doldrums and electricity consump-tion patterns remains unclear to analysts planning for future plants. Do the electricity generation data merely reflect this country’s recent reduced industrial production, or do they reflect accelerated adoption of energy efficiency measures, and if so, how much? Have electricity prices, rising more rapidly than wages, forced short-lived conservation on some classes of electricity users? Has the recession inequitably affected electricity-in-

tensive industries, such as concrete and alu-minum (down about 17% in 2009 alone), to skew the electricity consumption data? Has outsourcing manufacturing overseas per-manently reduced demand in some regions of the U.S.? Resumption of electricity con-sumption growth will be an early indicator of renewed economic growth, regardless of how elastic the relationship might be.

Give Proper CreditReduced electricity usage over the past two years has had an interesting impact on the mix of generation resources. Offsetting a reduction of 7.6% in coal-fired generation during the 12 months prior to October 2009 was an increase in hydroelectric generation over the same period caused by well-above-average rainfall. Low natural gas prices also

YearTotal generation, thousand MWha

Percentage change from prior year

U.S. GDP (billions of constant 2005

dollars)b Percentage change

from prior yearb

2004 3,970,555 2.25% 12,263.80 3.6

2005 4,055,423 2.14% 12,638.40 3.1

2006 4,064,702 0.23% 12,976.20 2.7

2007 4,156,745 2.26% 13,254.10 2.1

2008 4,110,259 –1.12% 13,312.20 0.4

2009c 3,950,250 –3.89% 12,988.70 –2.4

Notes:a. U.S. Energy Information Administration (EIA).b. Bureau of Economic Analysis, U.S. Department of Commerce.c. Author’s projection using actual generation through October 2009 reported by the EIA.

Table 1. Electricity use closely tracks GDP, although more loosely than in the past. Sources: U.S. Energy Information Administration and the Bureau of Economic Analysis

Table 2. Nuclear power remains the leader. Nuclear electricity production has remained rock-solid while other electricity genera-tion technologies have experienced wide production variation. The nuclear industry average capacity factor has remained stable, above 90% for the past several years, far exceeding all other technologies while still maintaining the lowest busbar cost in the industry. Sources: EIA, Nuclear Energy Institute

Year

Nuclear generation,

thousand MWha

Percentage change from

prior year

Coal generation,

thousand MWha


prior year

Natural gas generation,

thousand MWha


prior year

Hydro generation,

thousand MWha


prior year

2004 788,528 3.25% 1,978,301 –0.27% 710,100 9.26% 268,417 –2.68%

2005 781,986 -0.83% 2,012,873 1.75% 760,960 7.16% 270,321 0.71%

2006 787,219 0.67% 1,990,511 –1.11% 816,441 7.29% 289,246 7.00%

2007 806,425 2.44% 2,016,456 1.30% 896,590 9.82% 247,540 –14.42%

2008 806,182 –0.03% 1,994,385 –1.09% 876,948 –2.19% 248,085 0.22%

2009b 804,000 –0.27% 1,800,000 –9.75% 910,000 3.77% 265,000 6.82%

Notes:a. U.S. Energy Information Administration (EIA).b. Author’s projection using actual generation through October 2009 reported by the EIA.

10_PWR_040110_Benchmarking_p42-45.indd 42 3/16/10 2:58:45 PM



Benchmarking

added operating hours to combined-cycle plants that have seen limited service during the past few years. Both hydroelectric and gas-fired plants cut into coal-fired genera-tion in 2009, as did off-peak wind generation in some regions of the U.S. In the midst of this uncertainty, nuclear power steadfastly re-mained the industry’s lowest-price generator and most reliable source of baseload electric-ity (Table 2).

One key reason for the solid performance of the nuclear power industry over the past decade is the quality of the plant staffs and their dedication to the safe use of nuclear en-ergy to produce electricity. There is no single statistic available to compare the quality of employees across the nuclear industry, or any industry for that matter, so benchmarking plant staffing is the next best statistic. It’s a numbers game with the winner being those plants that can most efficiently use their lim-ited pool of talent.

A New Set of Benchmarking DataOur first nuclear benchmarking article, “Benchmarking Nuclear Plant Operating Costs,” was published in the November 2009 issue of POWER with the cooperation of the EUCG Nuclear Committee (see side-bar), and we promised more would follow. In that article we introduced the EUCG Nu-

clear Committee as an association of utility professionals representing all 104 nuclear plants in the U.S. as well as those located in China, Canada, France, Japan, Romania, and Spain. The committee’s primary goal is to benchmark plant metrics for nuclear plant operating cost, staffing, and perfor-mance data. Having previously reported on plant operating cost benchmarks, this article continues with U.S. nuclear power industry staffing benchmarks.

Before jumping into the data, a few ca-veats are required. POWER has exclusive access to the EUCG nuclear committee da-tabase, but that access has limitations. For example, the data presented do not differ-entiate between nuclear power technologies, such as pressurized water or boiling water reactors. Also, none of the data have any uniquely identifying information and are as

submitted by each plant. Finally, plant staff-ing data in this article are limited to three categories of workers, although the database has a much more comprehensive breakdown of job categories.

Each of the 104 U.S. nuclear power plants is a member of the EUCG, so if your com-pany is a member, the detailed benchmarking data are available to you through your com-mittee representative. The detailed database is a rich repository of benchmarking data and information that can be sliced and diced as your data needs require. The database also has the tools to help you carve out an appro-priate peer group of plants for much more detailed benchmarking studies.

Plant Staffing TrendsAverage plant staffing at U.S. nuclear power stations peaked in the 1970s and 1980s with

EUCG Nuclear Commit-tee Meets in AprilThe nuclear committee of the EUCG meets twice a year to share data and industry practices collected through membership surveys. The extensive peer network gives members the opportu-nity to raise questions or survey other member utilities on key issues between meetings. Standard benchmarking re-ports are made available to members beginning with the “Early Exchange,” a high-level view of industry cost trends released in January of each year. That report is followed by plant and unit performance and by nuclear operating costs, capital, and staffing reports re-leased throughout the year.

The next committee meeting is sched-uled for April 11–14, 2009, in St. Louis, Missouri. For more information about the EUCG and the meeting’s agenda, con-tact Executive Director Pat Kovalesky at 623-572-4140 or Chair of the Nuclear Committee David Ward ([email protected]), or visit www.eucg.org.

Num

ber o

f FTE

sta

ff

Year

70,000

60,000

50,000

40,000

30,000

20,000

10,000

02004 2005 2006 2007 2008

Baseline contracters Utility off-site employees Utility on-site employees

Aver

age

FTE

wok

ers

per p

lant

Year

1,200

1,000

800

600

400

200

0

2004 2005 2006 2007 2008


1. Total U.S. nuclear industry average staffing by plant (2004–2008). Staffing includes on-site and off-site employees and baseline contractors. The split between worker groups has remained reasonably constant over the past five years of reported data. Source: EUCG

2. Industry average number of workers at U.S. nuclear power plants (2004–2008). Average plant staffing, including on-site and off-site employees and base-line contractors, has changed less than 1% over the past five years of reported data. Source: EUCG



http://www.eucg.org




Benchmarking

1,500 workers or more per unit. Coinciden-tally, the then-moribund industry reported average plant capacity factors hovering around 60% through much of the 1980s. Since 2000, the industry average capacity factor has remained close to 90% following a renaissance in construction and operating and maintenance process improvements im-plemented in the 1990s. Nuclear refueling outages are also extremely manpower-inten-sive. In 1991, the industry’s average refuel-ing outage duration was 106 days. By 2000, the length of a typical refueling outage was reduced to 44 days; it dropped further, to 38 days, in 2008.

Left unanswered is the question of whether staffing at nuclear plants has been cut beyond what was economically justi-fied—to the point where key capabilities have been compromised. One recent indica-tor of this latter trend is the rise in the num-ber of worker fatigue incidents since 2000. Because fatigue degrades workers’ critical skills and abilities, the Nuclear Regulatory Commission (NRC) has taken steps to ad-dress worker scheduling, the needs of an ag-ing workforce, highly variable workloads, and factors related to specific tasks in new guidelines covering specific work hour and break limits and minimum day off require-ments. The guidelines—NEI06-11, “Man-aging Personnel Fatigue at Nuclear Reactor Sites” and NRC RG 5,73, “Fatigue Manage-ment for Nuclear Power Plant Personnel”—went into effect on October 1, 2009.

Another significant trend in the U.S. nu-clear power industry is consolidation of a large number of plants under a single operat-ing company. This approach allows the shar-ing of best practices and a centralized staff of technical experts while cutting costs.

Most plants also endured a period of “right sizing” in the 1990s to reduce plant nonfuel operating costs, about 50% of which

are staffing costs. The operational achieve-ments of the nuclear industry over the past decade are all the more remarkable given that average plant staffing has been reduced by a third or more since 2000.

As the total number of nuclear plant work-ers (Figure 1) and average plant staffing lev-els (Figure 2) have remained constant over the past few years, outages to replace steam generators and other major plant equipment

have increased, as have outages for plant power uprates (see “Nuclear Uprates Add Critical Capacity,” May 2009). The staffing distribution for all nuclear plants by category is shown in Figure 3. Plant quartile staffing levels are shown in Table 3. Note that all the data reported in this article are calculated as full-time equivalent (FTE) workers.

The downside to merely counting FTEs is that this metric does not account for worker

3. Full-time equivalent staffing at each U.S. nuclear power plant in 2008. Source: EUCG

Worker groups 1st quartile 2nd quartile 3rd quartile

Total of on- and off-site employees and baseline contractors

757 913 1,131

On-site employees 600 723 977

Off-site employees 34 62 83

Baseline contractors 27 113 201

Table 3. Statistical distribution of classes of workers per plant at U.S. nuclear power plants in 2008. Each statistic is calculated independently, thus the columns may not sum to the column total. Source: EUCG

1st quartile 2nd quartile 3rd quartile 4th quartile

Minimum plant $212,473 $291,901 $354,466 $411,654Maximum plant $291,008 $352,960 $396,938 $577,121Average plant $259,218 $319,507 $377,271 $468,129

Tota

l gen

erat

ing

cost

($/F

TE)

700,000

600,000

500,000

400,000

300,000

200,000

100,000

0Plant

Num

ber o

f pla

nt F

TE w

orke

rs

3,000

2,500

2,000

1,500

1,000

500

0


1st quartile 2nd quartile 3rd quartile

On-site employees 600 723 977

Off-site employees 34 62 83

Baseline contractors 27 113 201

Plant

4. Total U.S. nuclear industry generating cost per full-time equivalent worker in 2008. The statistics are calculated by summing the cost categories of plant sup-port and other costs, fuel, and capital; that total is then divided by the number of full-time equivalent workers at each nuclear plant (Figure 2). Total generating cost is the sum of plant support and other related costs, plus fuel, plus capital costs, divided by the plant’s FTE workers. Source: EUCG




Benchmarking

1st quartile 2nd quartile 3rd quartile 4th quartile

Minimum plant 213,737 292,348 325,277 366,584Maximum plant 291,384 323,030 365,583 520,180Average plant 264,244 309,482 343,063 408,313

Aver

age

gene

ratin

g co

st, 2

006-

2008

($/F

TE)

600,000

500,000

400,000

300,000

200,000

100,000

0

Plant

5. Average generating cost of each U.S. nuclear power plant per full-time equivalent employee (2006–2008). The statistics are calculated by summing the cost categories of plant support and other costs, fuel, and capital; that total is then divided by the number of full-time equivalent workers at each nuclear plant (Figure 2). Source: EUCG

FTE/

MW

inst

alle

d ca

paci

ty

1.80

1.60

1.40

1.20

1.00

0.80

0.60

0.40

0.20

0.00


1st quartile 2nd quartile 3rd quartile

On-site employees 0.45 0.55 0.74

Off-site employees 0.03 0.05 0.06

Baseline contractors 0.02 0.09 0.16

Plant

productivity. The best metric for overall worker productivity must be the quantity of electricity generated by a plant. For the purposes of this discussion, total generating costs are defined as the sum of plant support and other costs, fuel, and capital costs in a year. This definition is consistent with that used in the prior benchmarking article.

To calculate the staff productivity met-ric, the total generating costs are divided by the FTE at a particular plant. Data were then arranged into industry quartiles. Figure 4 illustrates the nuclear industry’s staffing productivity for 2008; Figure 5 illustrates the staffing productivity trend over the past three years. The names of the plants in each quartile of these two figures are different and are available only from the original data set provided to the sponsoring orga-nizations. The staffing productivity for all nuclear plants by worker category is shown in Figure 6. Plant quartile staffing levels are shown in Table 4.

The data indicate that the productivity of the bottom two quartiles of plants slipped in 2008 while that of the top-quartile plants has remained constant over the reporting period. This trend may show that the large nuclear operating companies have a built-in staff pro-ductivity advantage over the smaller nuclear utilities that is growing. In 1991, 101 indi-vidual utilities had some ownership interest in a nuclear power plant. Today, the top 10 nuclear utilities own more than 70% of the U.S. nuclear capacity, according to the World Nuclear Association.

—Dr. Robert Peltier, PE is POWER’s editor-in-chief.

6. Annual full-time equivalent staffing at each U.S. nuclear power plant per unit of installed capacity in 2008. Source: EUCG

Table 4. Benchmarking worker productivity. Statistical distribution of classes of nuclear workers per unit of installed capacity at U.S. nuclear power plants in 2008. Each statistic is calculated independently, thus the columns will not sum to the column total. The data are shown in FTE workers per MWh of electricity produced. Source: EUCG

Worker groups 1st quartile 2nd quartile 3rd quartile

Total of on- and off-site employees and baseline contractors

0.54 0.72 0.93

On-site employees 0.45 0.55 0.74

Off-site employees 0.03 0.05 0.06

Baseline contractors 0.02 0.09 0.16




SYSTEM PLANNING

A Primer on Optimizing Fleet OperationsThe power industry needs a straightforward definition of “fleet optimization”

and a game plan to achieve the promised economic gains of optimizing. This need has become more urgent because integrating nondispatchable renewable resources requires more complex optimization strategies. The bottom-up approach presented here applies well-understood optimiza-tion principles and techniques that will help power producers minimize their fleetwide cost of production, independent of the technologies used to generate electricity.

By Tom Snowdon, Emerson Process Management

If your utility, company, municipality, coop-erative, or government agency owns or op-erates one or more power generating units,

then it has a fleet operating in a market. A ver-tically integrated utility is in essence a market unto itself; its interties with other utility grids, regional transmission organizations (RTOs) and independent system operators (ISOs) can be modeled as virtual units in the utility’s fleet. Each of the competitive wholesale markets run by RTOs and ISOs in the U.S. is also defined as a market with a fleet of generating units competing to supply the demanded energy. Therefore, a company that owns units in PJM and in ISO New England has two fleets. In ad-dition, a unit with more than one owner may be part of many fleets, one for each owner, but each unit typically competes in only one mar-ket. For the purposes of this discussion, please assume that our demonstration fleet operates in a single market, such as PJM or MISO.

Focus on Lowest CostOptimization is the process of minimizing or maximizing some quantity, given a set of rela-tionships between variables and a set of con-straints that must be satisfied. Together, the set of relationships and the set of constraints is called an optimization problem. This is a somewhat theoretical definition, but it is a very powerful tool. It means that if you are not seeking to minimize or maximize some quan-tity, then you are not optimizing. This may seem to be a silly distinction, but it turns out to be important in every optimization problem because of the trade-offs that are inherent in the set of relationships between variables.

As an example, consider that you can re-duce the amount of NOx produced in a boiler’s furnace by reducing the amount of excess air used for combustion (Figure 1). As excess air is reduced, a coal-fired boiler produces more un-

burned carbon in the ash. More unburned car-bon in the ash means the heat rate has increased or the combustion efficiency has decreased. Therefore, we can tune the combustion to mini-mize NOx or we can tune the combustion to minimize unburned carbon, but we can’t mini-mize both at the same time. Optimization tools provide us with a methodology to balance com-peting plant operating practices, such as mini-mizing NOx and unburned carbon, to achieve

the overall lowest cost to a particular boiler and, eventually, to the entire fleet of plants.

There are costs associated with creating NOx in a boiler and unburned carbon in the ash. Those costs may come from purchasing or maintaining NOx emission allowances, buying ammonia for selective catalytic re-duction (SCR), or limiting a unit’s power output to stay under a NOx cap or rate limit (Figure 2). Quantifying the universe of costs

10.510.410.310.210.110.09.99.89.7H

eat r

ate

(mill

ion

Btu

/MW

h)

Excess O2 (%)0 1 2 3 4 5

0.510.5

0.490.480.470.460.450.440.430.42

NO

x (lb

/mill

ion

Btu

Excess O2 (%)0 1 2 3 4 5

1. Characterize the test data. The first step is to characterize the important data used to define unit performance. In this example, the amount of excess O2 in the boiler furnace determines the plant heat rate (left) and NOx production (right). Note that it’s impossible to mini-mize the plant heat rate and NOx emissions at the same furnace excess O2. Source: Emerson Process Management

2. Find the incremental cost. The same variables used in Figure 1 can be used to deter-mine the fuel cost (left) and the incremental additional cost of NOx, including the cost of allow-ances, as a function of excess O2 in the boiler furnace. Source: Emerson Process Managemen

26.226.025.825.625.425.225.024.824.624.4

$/M

Wh

Excess O2 (%)0 1 2 3 4 5

4.00

3.75

3.50

3.25

3.000 1 2 3 4 5

$/M

Wh

Excess O2 (%)

11_PWR_040110_FleetOptimization_p46-50.indd 46 3/16/10 6:07:44 PM



SyStem Planning

related to NOx production, for example, may be easy or extremely difficult, but there is no question that system operating costs increase as more NOx is produced (Figure 3). Simi-larly, there is a cost associated with unburned carbon. The more carbon that is thrown out with the ash, the more it costs in fuel for each megawatt-hour produced.

The process of optimizing these compet-ing requirements to the benefit of the entire fleet requires minimizing the total costs asso-ciated with NOx and unburned carbon while satisfying all the NOx emissions limits appli-cable to the unit. The dollar is the conversion factor that allows us to find the sweet spot in this trade-off.

A very complicated set of mathematical re-lationships encompassing many variables (such as NOx production or unburned carbon in the ash) ultimately determines all the costs associ-ated with making electricity at a plant or in a fleet. There is also an extensive set of process constraints (such as annual NOx production lim-its) that must be satisfied in any optimization problem. In the short term, fleet optimization is a matter of formulating and solving the optimi-zation problem to minimize short-term or vari-able costs while satisfying all the constraints. In the midterm, there may be other fixed costs as-sociated with short-term optimization. Midterm optimization is the process of minimizing all costs, accounting for these fixed costs in com-bination with the variable costs.

Use the Existing EMS SystemIn tackling the fleet optimization problem, begin with a bottom-up approach that lever-ages one optimization tool that every fleet already has at its disposal. The utility’s or ISO’s energy management system (EMS) now dispatches all the power generation re-sources, regardless of whether they are used in a nonmerchant utility fleet or in a competi-tive wholesale market.

The EMS utilizes a rigorous solution method that guarantees least-cost dispatch of the fleet, given the relationship between cost and load for each unit and a set of constraints describing the minimum load, maximum load, typical ramp rate, start-up time, and a host of other constraints applicable to each unit. In sum, the fleet achieves the minimum cost of production when each unit has opti-mized to its minimum cost and the fleet as a whole can change its output as required by the changing demand of customers while main-taining a minimized cost dispatch solution. To maintain a combination of operating units (or purchased power) that produces the lowest possible energy cost while following a daily load demand curve is a valuable capability.

To illustrate, consider a fleet supplying electricity into a market during a period of rising demand. If a low-cost-of-energy unit cannot keep up with the increasing demand, then a higher-cost-of-energy unit must gener-ate more energy than the least-cost ideal ar-rangement for the fleet, in order to balance energy supply with demand at every instant in time. Thus, the total cost of energy for the fleet is higher than it would have been if the low-cost unit could keep up with the rate of change of demand.

One important observation from this dis-cussion: The fleet can be optimized only when each unit in the fleet is locally opti-mized throughout its operating range.

Short-Term Unit OptimizationWe begin optimizing an individual unit based on short-term operating goals. This approach requires definition of all of the relationships between variables that determine plant vari-able operating costs, within the required operating constraints. For most units, these variable costs of producing electricity in-clude commodities that are either purchased or otherwise procured. Examples include:

Fuel NOx allowances SCR or selective noncatalytic reduction r

agent (ammonia or another reagent) SO2 allowances Flue gas desulfurization (FGD) reagent

(limestone, lime, or other chemical con-sumables)

Some units have variable costs associated with the purchase of water used for cooling water and FGD slurry water. The portion of that water that represents a variable cost is typically what is evaporated or otherwise con-sumed as a function of plant energy (MWh) production. Some locations also inject re-agents such as activated carbon to reduce mer-cury emissions, so those costs should also be

included, if applicable. Future carbon cap-and-trade regulations may also create a significant variable cost in the cost to produce electricity.

Calculations are further complicated for units located in states that do not have trad-able allowances but that do place limits on emissions. The variable or incremental cost to replace power lost when a unit runs up against a NOx limit (whether hourly or daily) is the virtual value of the NOx allowances used.

For example, consider Unit #1, which gen-erated 600 MWh over the past hour but would have generated 800 MWh had it not been for a NOx limit. Suppose that Unit #2, with an addi-tional incremental cost of $5.25/MWh, gener-ated the 200-MWh difference. Also, Unit #1 would have made an incremental three pounds of NOx per MWh for a total increment of 600 lb of NOx during the hour. Thus, the ability to emit NOx from Unit #1 is valued as:

$5.25/MWh * 200 MWh/600 lb NOx = $1.75 per pound of NOx, or $3,500 per ton of NOx

In the optimization of Unit #1, a cost of $3,500 per ton of NOx would be used to find the “sweet spot” in the combustion optimiza-tion trade-off.

Continuing with Unit #1, there are many adjustments that an operator or a control sys-tem can make to produce the lowest possible cost of electricity, such as damper positions, fan speeds, and burner tilt, to name a few. In the language of optimization science, these are called “manipulated variables.” Changes in the manipulated variables change the plant “depen-dent variables,” such as flue gas oxygen con-tent, steam temperatures, heat transfer surface cleanliness, and the like. Changes in dependent variables usually result in changes to other dependent variables and so on, down a long chain of relationships that ultimately produce a change to the cost of electricity production.

The total cost of electricity production is the ultimate dependent variable, and our ob-jective is its minimization. Other “disturbance variables” such as ambient temperature and humidity, condenser cooling water inlet tem-perature, and water content of the fuel also produce effects on the dependent variables, and those effects must be characterized in or-der to achieve our optimization objective. The combination of all the mathematical charac-terizations of each of these variables is called the “objective function.” The solution of the objective function yields settings for all of the manipulated variables so that the cost to pro-duce a MWh is minimized (Figure 4).

The Importance of Data HandlingAny plant performance engineer who tried to tackle unit optimization prior to about 1992

30.0

29.0

29

28.5

28

27.50 1 2 3 4 5

$/M

Wh

Excess O2 (%)

3. Find the optimum settings. With the data from Figure 2, an equation for the to-tal cost of production as a function of excess O2 is possible. The minimum production cost defines the optimum setting as 2.26% O2 in the boiler furnace, resulting in a total produc-tion cost of $28.01/MWh. Source: Emerson Process Management




SYStem Planning

will testify that the multitude of functional relationships between the variables and the continuous data stream required was over-whelming. Fortunately, we now have the computing power necessary, at an affordable cost, to characterize the responses of the de-pendent variables to changes in the manipu-lated and disturbance variables, to develop the objective function as a set of mathematical expressions, and to perform the mathematics required to solve these complex equations to determine settings for the manipulated vari-ables every few seconds.

In order to minimize the total variable cost, detailed information about the cost of the commodities listed above must be supplied to unit optimization programs. The programs that collect the data and develop the charac-terizations are called “neural networks” or “artificial intelligence” or some variation on that theme. A neural network is a program that gathers data, characterizes responses to manipulations and disturbances, and then uses those characterizations to produce the ideal desired result. In effect, the computer program “learns” how to respond to com-plex situations based on historic data. Some newer programs add the capability to recog-nize when something about the process has changed. When a process variable changes, the program immediately develops new char-acterizations of the data that are used to “im-munize” the optimization problem against that change going forward.

Short-Term Fleet OptimizationEven using state-of-the-art optimization com-puter programs, characterizing a unit and pro-ducing a bulletproof optimizer is not a trivial exercise. However, it is possible—and even

reasonably economical—today, since robust computer tools are now available. Having characterized the settings (the manipulated variables) required to minimize real-time total cost of production for each unit, the character-ization of cost as a function of unit load can be supplied to the fleet EMS (Figure 5).

Traditionally, the cost of fuel across the load range has been the only commodity rep-resented in this characterization. With the ad-vent of emissions cap-and-trade systems and the cost of emissions reduction reagents used in SCRs and scrubbers, this one-dimensional approach is no longer adequate. A properly configured unit optimization system should output, or at least provide access to, the necessary information to produce near-real-time characterizations of cost as a function of load that includes all variable costs. Once the settings for the manipulated variables are determined, the EMS then takes care of dis-patching each unit at the load necessary to minimize the total real-time cost of the fleet.

The first challenge in fleet optimization (as distinct from unit optimization) is to up-date the EMS with fresh characterizations of the units, whenever it’s appropriate. This means that each unit optimizer must be able to recognize when something about its objec-tive function has changed enough to cause a change in the unit characterization used by the EMS. Almost any change in the perfor-mance of any power plant equipment will cause the objective function to change. Ex-amples include a stuck overfire air damper, a change in boiler feed pump efficiency due to wear, and a leak in a start-up drain valve.

Any change in the cost of any of the vari-able cost commodities also causes the ob-jective function to change. Because these quantities change frequently, the EMS must have near-real-time updates of each unit’s cost characteristics. Unit optimizers or con-trol systems that automatically feed near-real-time cost characteristics to an EMS are uncommon in the industry, but it’s impor-

Manipulated variables damper positions pump speeds valve positions fuel flow rate etc.

Disturbance variables ambient temp. humidity fuel heating value fuel moisture etc.

Constraints NOx limits temp. differences boiler air requirements etc.

Dependent variables excess O2 steam pressure steam temperature steam flow NOx production SO2 production etc.

Dependent variables load point boiler efficiency turbine efficiency ammonia required lime required etc.

Dependent variables $ for fuel $ for NOx allowances $ for ammonia $ for SO2 allowances $ for lime $ for etc.

4. The objective is to minimize cost. The mathematical approach to fleet optimization is to define an objective function that is cost-minimized. In addition, the program must characterize each dependent variable as a function of manipulated, disturbance, and other dependent variables. The constraints must also be defined as part of the analysis. Source: Emerson Process Management

Objective function

Commodity prices

Energy management

systemIncremental cost curve

Equipment performance

5. Grade on the curve. Once commodity prices and actual equipment performance are included in the analysis, each unit’s incremental cost curve defines the true cost of production by unit. That data can then be used by the fleet EMS to dispatch the units. Source: Emerson Process Management

Plant of the Year: IllInoIs

MarMaduke award: netherlands

toP Plant, Gas: ItalY

toP Plant, Coal: IndIa

toP Plant, nuClear: south CarolIna

toP Plant, renewables: nevada

The Power Plant of the Year award will be presented to a plant that leads our industry in the successful deployment of advanced technology—maximizing efficiency while minimizing environmental impact. In short, the Power Plant of the Year, featured in the August issue of POWER, is the best of class over the past year.

Nominations are due May 24, 2010.Read about all the 2009 winners and download entry forms from www.powermag.com (under “Also from POWER Magazine”).

If you know of a plant that’s worth bragging about, nominate it for one of POWER magazine’s annual awards. Plants anywhere in the world have three chances to win!

Award finalists and winners will be selected by the editors of POWER based on nominations submitted by you and your industry peers—suppliers, designers, constructors, and operators of power plants.

The Marmaduke Award, named after the legendary plant troubleshooter whose exploits have been chronicled in POWER since 1948, recognizes operations and maintenance excellence at existing power plants. The Marmaduke Award winner will also be profiled in the August issue.

Top Plants Awards recognize the best in class over the past year in each of four generation categories: combined-cycle (September), coal-fired (October), nuclear (November), and renewable (December).

NomiNate Your PlaNt for a Award



Plant of the Year: IllInoIs

MarMaduke award: netherlands

toP Plant, Gas: ItalY

toP Plant, Coal: IndIa

toP Plant, nuClear: south CarolIna

toP Plant, renewables: nevada

The Power Plant of the Year award will be presented to a plant that leads our industry in the successful deployment of advanced technology—maximizing efficiency while minimizing environmental impact. In short, the Power Plant of the Year, featured in the August issue of POWER, is the best of class over the past year.

Nominations are due May 24, 2010.Read about all the 2009 winners and download entry forms from www.powermag.com (under “Also from POWER Magazine”).

If you know of a plant that’s worth bragging about, nominate it for one of POWER magazine’s annual awards. Plants anywhere in the world have three chances to win!

Award finalists and winners will be selected by the editors of POWER based on nominations submitted by you and your industry peers—suppliers, designers, constructors, and operators of power plants.

The Marmaduke Award, named after the legendary plant troubleshooter whose exploits have been chronicled in POWER since 1948, recognizes operations and maintenance excellence at existing power plants. The Marmaduke Award winner will also be profiled in the August issue.

Top Plants Awards recognize the best in class over the past year in each of four generation categories: combined-cycle (September), coal-fired (October), nuclear (November), and renewable (December).

NomiNate Your PlaNt for a Award




SYStem Planning

tant to realize that fleet optimization is per-formed by the EMS, so real-time, accurate unit incremental cost curves must be pro-vided. A unit that is dispatched by an EMS using an inaccurate incremental cost curve loses money in the market and increases the fleet’s aggregate cost.

Midterm Fleet OptimizationHaving successfully achieved short-term fleet optimization, we turn our attention to optimization in the midterm. The goal here is to understand how changes in operating procedures might change a unit’s objective function for the better, or might change some operating constraint in a way that produces a lower-cost result from the EMS. The typical trade-off is a rising cost of unit maintenance. A good example is a potentially costly side effect of combustion optimization.

Recalling our earlier example, reducing excess O2 can reduce the amount of NOx pro-duced, and we optimized the unit by pushing that benefit until the cost of unburned car-bon balances the benefit of reduced NOx. A midterm consequence of this short-term op-timization can be an increase in tube wastage caused by alternating oxidizing and reducing atmospheres in the furnace (Figure 6). Some units have experienced a significant increase in tube leaks that increase tube repair main-tenance costs and reduce the operating reli-ability of the entire unit. Also, when a unit is forced offline to repair a tube leak, it misses the opportunity to generate revenue in the market, thereby increasing the fleet’s “reli-ability costs.” These costs are incremental to the cost of operations and maintenance in-curred when running with higher O2.

Midterm fleet optimization then can be an exercise in the minimization of the costs resulting from short-term optimization added to any incremental maintenance and reliabil-ity costs resulting from the short-term opti-mization. Of course, the main difficulty with midterm optimization is that it takes a while to measure the effects of a given decision.

Continuing with our tube leak example, suppose we start with a unit whose water walls are expected to remain serviceable for 30 years of baseload operation, at 3% mini-mum economizer O2. Suppose further that our efforts at short-term optimization indi-cate that operating at 2.3% O2 would result in NOx allowance and fuel savings amounting to $850,000 per year. Assume that we know that an outage to replace all of the degraded tubes would cost $12,000,000 in material, labor, replacement power, and all the other associated costs. A hypothetical wastage rate curve allows us to estimate the cost per MWh of the tube wastage as a function of excess O2 (Figure 7).

With this relationship added to the short-term optimization problem, we will now con-trol O2 at the point that minimizes the total of the short-term costs of fuel and NOx al-lowances plus the midterm costs of tube re-placement events. A “conservative” approach in terms of protecting the boiler would be to estimate a high rate of tube wastage, driving the optimization solution away from 2% and closer to 3% O2, at the risk of leaving NOx allowance or fuel money on the table.

A more aggressive approach would be to estimate a less “conservative” wastage effect, driving the solution toward the short-term op-timum. Then, taking a short outage every year to perform ultrasonic testing and characterize the wastage rate would provide the informa-tion needed to adjust the wastage relationship, leading to a better characterization of tube re-pair costs and a lower total cost optimum. This sort of process is the essence of a continuous improvement program, approached from a per-spective that combines business and engineer-ing sciences. It is applicable to any number of operations versus maintenance trade-off situ-ations, including reduction of minimum load, unit load ramp rate, and cycling operations.

With a clear understanding of midterm cost characteristics, the variable cost curves of each unit in a fleet can then be adjusted to reflect both short-term and midterm costs. The update ensures the appropriate unit dis-patch order to minimize fleet cost of produc-tion over the midterm.

This approach also addresses one of the most difficult issues between plant management and dispatch or trading management. Commonly, either the plant gives the dispatcher whatever he wants and then blames “erratic dispatch” for a high forced outage rate, or the plant constrains dispatch in an effort to minimize damage to the equipment but leaves big money on the table in terms of the ability to minimize fleetwide ag-gregate cost of production. Midterm fleet opti-mization offers the mechanism through which

the fleetwide lowest total cost set of constraints and operating settings are used by the unit opti-mizers and the EMS.

Some companies have rejected short-term optimization, fearing that the resulting midterm costs might become too high. To reject short-term optimization on that basis is to reject the no-tion that there is room to improve the operating economics of the fleet. Midterm optimization provides the means to replace this fear-based decision-making with knowledge-based or at least reason-based decision-making.

—Tom Snowdon (thomas.snowdon@ emerson.com) is a performance consul-

tant with the Power & Water Solutions di-vision of Emerson Process Management.

70

60

50

40

30

20

10

0Ye

ars

betw

een

tube

re

plac

emen

t eve

nts

O2 at high load (%)0 1.0 2.0 3.0 4.0

0.90.80.70.60.50.40.30.20.1

0

$/M

Wh

Excess O2 (%)0 1 2 3 4 50.5 1.5 2.5 3.5

6. Include long-tem effects. Short-term optimization of variable costs often ignores the longer-term effects, such as boiler water wall tube wastage that takes place over years. Operating at low boiler furnace O2 levels accelerates tube wastage (left) and the resultant cost of replacement on an incremental cost basis (right). For this analysis, the tube replacement cost was estimated as $12 million on a 600-MW unit operating at 75% capacity factor. Source: Emerson Process Management

30.029.829.629.429.229.028.828.628.428.228.0

$/M

Wh

Excess O2 (%)0 1 2 3 4 5

7. Combine long- and short-term costs. The optimum boiler furnace O2 set-point can now be determined by summing the short-term unit optimization data that mini-mized variable O&M cost (Figure 3) with the midterm fleet optimization that consider fixed O&M costs (Figure 6). Doing so results in an overall production cost optimization strategy that encompasses furnace O2, NOx, and tube wastage. In this example, the optimum fur-nace O2 is 2.48% at a cost of $28.10/MWh. The estimated interval between tube replace-ments is 18.43 years. This analysis shows that the unit will save $494,000 per year against the boiler manufacturer’s suggested 3% furnace O2 setpoint by minimizing the total costs of fuel, NOx allowances, and tube replacements. Source: Emerson Process Management






PLANT DESIGN

Enhanced Condenser Tube Designs Improve Plant PerformanceEnhanced condenser tube designs can significantly improve the heat rate and

performance of fossil and nuclear plants. Using the optimum number of tubes and replacement tube sheets will cost more than simply replacing plain tubes. However, the investment’s simple payback is measured in only weeks, which builds a strong case for using an enhanced tube design as part of your next condenser overhaul.

By Dr. Ralph L. Webb, Penn State University

The vast majority of electric utility plants operate with the Rankine cycle, which uses a turbine-generator to produce elec-

tric power. One of the limitations of this cycle is that the condenser cooling water temperature di-rectly affects plant efficiency and the power gen-erated. Colder water during the winter months yields a higher power output and, conversely, plant output is reduced when the condenser water temperature rises during the summer. In addition, plant output is more sensitive to high turbine backpressure (in summer months) than to low backpressure (in winter months).

As you will see shortly, the effect of con-denser water inlet temperature is strongly influenced by the shape of the “turbine back-pressure curve,” as shown in Figure 1. Note that the smallest incremental improvement occurs at the lowest backpressure, where the curve is reasonably flat. Conversely, the great-est incremental improvement will occur at the higher condenser inlet water temperature con-ditions. Therefore, fossil and nuclear plants experience the greatest benefit of reduced condenser water temperature in the summer months during peak demand season.

In addition to lower cooling water temper-atures, advanced technology condenser tubes with special surface geometries on the inner and outer surfaces will yield a higher over-all heat transfer coefficient (U) than a plain tube condenser, increasing the heat transfer between the steam and cooling water, and thereby increasing power output and reduc-ing plant heat rate. Such a special surface ge-ometry tube is called an “enhanced tube.”

There are practical and commercially available enhanced condenser tube geom-etries that will yield a U-value increase of approximately 40%. These tubes are avail-able to any power plant that operates on the Rankine cycle using condenser water from any source (lake, river, or cooling tower). An increased U-value means that a lower turbine backpressure factor (Figure 1) is re-

quired for a given condenser water tempera-ture, resulting in higher plant efficiency and power output.

Enhanced Condenser TubesA special enhanced tube called a “corrugated tube” was used in the U.S. to re-tube existing utility steam condenser bundles at several Ten-

nessee Valley Authority plants in the 1990s. The corrugated tube has a single helix configu-ration. The specific tubes tested are known as Korodense and were manufactured by Wolver-ine Tube (Figure 2a). This tube results in a 1.80 factor water-side heat transfer enhancement, 2.25 friction factor increase, and 30% steam side enhancement, relative to a smooth tube.

Turbine backpressure (mm Hg abs)

Turb

ine

heat

rate

cor

rect

ion

fact

or (%

)

Turbine backpressure (inches Hg abs)

40 60 80 100 1203

2

1

0

–11 2 3 4 5

Heat rate at 3 in Hg absNuclear 10,040 Btu/kWh (2.942 kW/kW)Fossil 7,988 Btu/kWh (2.341 kW/kW)

Nuclear plant

Fossil plant

1. Changes with temperature. This turbine heat rate correction factor curve specifies 3 in. HgA as the standard performance condition. A turbine heat rate factor must be applied when the turbine backpressure changes as a reaction to condenser cooling water tempera-ture changes. Note the differences between the response of a typical fossil and nuclear plant. Source: Dr. Ralph L. Webb

12_PWR_040110_PlantDesign_p51-55.indd 51 3/16/10 6:11:43 PM



plant design

In an article written in 1984, “Enhanced Tubes in Electric Utility Steam Condensers in Heat Transfer in Heat Rejection Systems,” published by the Heat Transfer Division of the American Society of Mechanical Engineers, I wrote about a simulation analysis of re-tub-ing an existing plant with various enhanced condenser tube geometries. This analysis included a corrugated tube, and other geom-etries, whose performance was theoretically estimated. The analysis defined the perfor-mance and economic benefits of condensers using enhanced tubes. The analysis was per-formed using the turbine performance data

from Arkansas Nuclear One (ANO-1) Unit 1. The results of that analysis showed that en-hanced condenser tubes were economically justified in fossil and nuclear plants.

Between 1990 and 1992, additional re-search under sponsorship of the Electric Power Research Institute and the U.S. De-partment of Energy resulted in specific en-hanced tube geometries for application to electric utility steam condensers. These tubes had enhancement on both the steam and wa-ter side. The tubes were designed in partner-ship with Wieland-Werke AG and Wolverine Tube, which manufactured the prototype tubes for testing. Figure 2 shows the tubes that were manufactured and tested for steam- and water-side performance.

The previous work has shown that certain enhanced tubes can provide performance and economic benefits for electric utility plant condensers. A recent update of that 1984 analysis using the same ANO-1 data once again illustrates the advantages of enhanced tubes in fossil and nuclear condensers. The following analysis uses data for the Wieland NW-16 tube (Figure 2b). The calculation procedure is included so a plant engineer could reproduce the analysis for a particular plant that might be considering the use of en-hanced condenser tubes.

Nuclear Plant AnalyzedThe analysis was performed for a 946-MWe nuclear plant using design specifications provided by Gilbert Commonwealth Associ-ates (GCA). The plant specification rated the plant at 946.3 MW with 3.0 in HgA turbine backpressure (Psat). The curve “nuclear” in Figure 1 is the backpressure correction curve used in this analysis. As shown in Figure 1, the rated heat rate (HR = Qh/W) is 2.942 kW/kW, where Qh is the heat supplied to the reac-tor and P is the rated plant output. For a fossil plant, the ratio would represent the fuel heat input in equivalent kW units divided by the rated plant output.

The condenser used for the example calcu-lations is the ANO-1 condenser, but config-ured with 23,150, 28.6-mm OD stainless steel tubes 13.4 m long. The condenser water flow rate at the rated condition is 30.65 m3/s based on the GCA design data. The design water ve-locity is 2.29 m/s. The ANO-1 condenser was originally built with 28.6-mm OD admiralty tubes having 19,608 tubes per condenser shell. The condenser was re-tubed in 1999, which involved complete reconstruction of the four condenser tube bundles that served the two low-pressure turbines. This condenser recon-struction used 25.4-mm OD titanium tubes that were 13.5 m long. However, the stainless steel tubes assumed in this case study are rep-resentative of the condenser tubes now used

by many nuclear and fossil plants in the U.S.

Calculation Procedure The following sections outline the step-by-step calculation procedure shown in Table 1 for calculating the potential plant efficiency and output that may be obtained from using enhanced turbines in this plant condenser.

Turbine Output and Condenser Load. Using the heat rate correction factor found in Figure 1 at the plant rating condition, first cal-culate Qh = 2.942 * 946.3 = 2,784 MW. This heat input is assumed to be constant for the pres-ent calculations, where the plant is operating at different condenser saturation pressures (Psat). Calculating the heat rate (HR) at other values of Psat is easily performed using the heat rate cor-rection factor (HRC ) given in Figure 1.

Tsat is then found from the steam tables and added to line 2. The condenser heat rejection (Qc) is given by Qc = Qh – W, where W is the turbine output power (line 3 in Table 1). At the rated condition 76.2 mm Hg (3 in. Hg), Qc = 2,784 – 946.3 = 1,837.7 MW. At any known turbine backpressure, the HR = 2.942 * (1 + HRC/100). Using this HR with Qh = 2,784 MW, one may calculate the turbine output (W) and the condenser heat rejection (Qc = Qh – W) (line 4).

Objective Function and Constraints. The calculations are performed for two cas-es: a tube-for-tube replacement and a bundle replacement having NeLe/NpLp = 1 with fixed condenser flow rate where N = the number of condenser tubes, L = the length of the tubes, the subscript p represents the original plain or smooth tubes, and the subscript e repre-sents the enhanced, replacement tubes. For both cases, the constraints are:

Fixed heat input to turbine (Qh). Fixed pumping power (P) and condenser

water flow rate ( ). The analysis assumed that the re-tubed

condenser uses titanium tubes of the same OD as the original plant design and 0.7-mm wall thickness.

By replacing the plain tubes with en-hanced tubes, the UA value of the condenser is increased, where A is the heat transfer area and U was defined previously as the overall heat transfer coefficient of the tubes. Because the enhanced tubes have a higher friction fac-tor, and some have a smaller cross-sectional flow area, the balance point on the circulat-ing water head versus flow curve (Figure 3) will occur at a reduced water flow rate for a tube-for-tube replacement.

Using the friction factor versus Reynolds number characteristic of a given enhanced tube, the total system friction head (pressure) versus flow characteristic was developed

2. Enhanced condenser tube op-tions. A number of horizontal integral-fin tubes have been developed for steam conden-sation. Some notable examples are (a) stain-less steel Wolverine Korodense, (b) stainless steel Wieland NW-16, (c) copper-nickel Wie-land 11-NW, (d) UOP attached particle tube, and (e) Yorkshire MERT (Multiply Enhanced Roped Tube). Courtesy: Dr. Ralph L. Webb

a.

b.

c.

d.

e.




plant design

(Figure 3). The pump head versus flow char-acteristic was curve-fitted to a polynomial. Simultaneous solution of these two equa-tions yielded the condenser water flow rate through the enhanced tube condenser. These figures show the system characteristic for the smooth tube condenser design and the friction head characteristic of system, less the head loss in the condenser tubes. Examination of the pump curves for the two plants shows that the percentage of the total head loss that oc-curs in the condenser tubes is 45%.

Water-Side Heat Transfer Coefficient. After calculating the cooling water flow rate, the heat transfer coefficient (hp) on the waterside coefficient of the plain tubes is calculated using the well-accepted Petuk-hov correlation for plain tubes. The water-side coefficient of the plain tubes is based on test results and is given as the smooth tube value multiplied by an enhancement factor (Ehi = he/hp). Most heat transfer refer-ences will provide details on calculating hp. The tube supplier can provide data on he. A value of Ehi = 1.55 is used for the Figure 2b Wieland NW-16 tube.

Water-Side Fouling Factor. A value of Rf = 4.4 * 10–5 m2-K/W (0.00025 hr-ft2/Btu) was used in the calculations. This corresponds to a “cleanliness factor” of 0.70.

Condensation Coefficient. The HEI Standard for Steam Surface Condensers (1995, 2002) outlines a method for calculat-ing the overall single-tube heat transfer coef-ficient (U) for steam condensation in electric utility steam condensers. The calculated U is in close agreement with that calculated using the horizontal tube Nusselt equation for the steam condensation coefficient, as given in many texts on heat transfer:

The titanium alloy used here is ASTM B338, having 21.6 W/m-K thermal con-ductivity.

Condensing Temperature (Ts ). The inlet cooling water temperature is known for each month of the year at ANO and therefore the condensing temperature (Tsat) can be determined. The condenser heat re-jection (Qc) rate at any Psat is given by

where HRC is the heat rate correction factor (%) obtained by curve-fitting the correction factor (Figure 1) as a function of Psat.

Condenser Thermal Parameters. The heat exchanger thermal effectiveness (ε) is calculated by ε = 1 -e-NTU where

Condenser water flow (m3/min)

Hea

d (ft

wat

er)

Hea

d (m

wat

er)

Condenser water flow (gal/min x 104)

200 400 600 800 1,000 1,200 1,400 1,600 1,800

0

40

30

20

10

00 10 20 30 40 50

16

14

12

10

8

6

4

2

0

Pump curve900 MW nuclear plantA=Condenser tubes (smooth)B=External friction

A

B

Line Item Units

January April and October July

Plain tube Enhanced tube Plain tube Enhanced tube Plain tube Enhanced tube

1 Tw,in (condenser water inlet temp) C 7.8 7.8 19.4 19.4 31.7 31.7

2Tsat (found using the steam tables at Psat, condenser pressure at Tw,in)

C 40.3 34.7 49.4 44.8 61.8 56.2

3 Qc (condenser heat rejection) MW 1,835 1,832 1,846 1,837 1,898 1,862

4 W (turbine output) MW 949 951 937 946 885 921

5 Wp (pump power) HP 851 851 791 791 742 742

6 ΔEnet (= W – Wp) MW 948 950 937 945 885 921

7 ΔEg (= ΔEg,e – ΔEg,p) MW NA 3.2 NA 9.3 NA 36.8

8 N (number of tubes) 23,150 28,575 23,150 28,575 23,150 28,575

9 Ne /Np (no. tubes ratio) NA 1.23 NA 1.23 NA 1.23

10 Le /Lp (tube length ratio) NA 0.81 NA 0.81 NA 0.81

Note: NA = not applicable.

Table 1. Comparison of enhanced vs. plain tube condenser (bundle replacement). Source: Dr. Ralph L. Webb

3. System performance curves. The design pump and system head versus water flow rate for Arkansas Nuclear One, Unit 1 is illustrated. Note that the enhanced tubes have a higher friction factor (caused by a smaller diameter) that reduces the cooling water flow should like numbers of tubes be replaced. In this figure, the original design system friction balance point is off the right side of the figure, at about 600,000 gpm. With a tube-for-tube replacement, the condenser water flow will decrease to approximately 480,000 gpm. Therefore, to maintain like condenser pump system performance, additional enhanced tubes must be added to the con-denser. Source: Gilbert Commonwealth Associates




plant design

The condenser heat rejection is given by

where Tw,in is known for each month of the year. The calculation procedure requires iter-ation of Qc and Tsat (which is a direct function of Psat —found in the steam tables). To obtain annual average values, this calculation is per-formed for each month of the year using the known Tw,in for each month of the year.

Condenser Pumping Power. Because of the different balance point on the pump curve, the pump power changes. The con-denser pumping power (line 5) is given by

Increased Net Generation. Using the calculated values of W and Qc, the incre-mental generation rate ΔEg (MW) made possible by the enhanced tube geometries is determined using the calculated val-ues of turbine output (W) and the pumping power (Wp). The new generation output is Wnet = W – Wp, assuming the main steam flow is held constant (line 6).

The net increased generation rate provided by the enhanced tube condenser (relative to the plain tube condenser) is ΔEg. The ΔEg = We – Wnet,p, where subscripts e and p refer to the enhanced and plain tube respectively (line 7).

Calculated ResultsCalculations were performed for two cases: a tube-for-tube replacement with fixed pump-ing power and a bundle replacement having NeLe/NpLp = 1 with fixed condenser flow rate and pumping power, as discussed earlier.

Tube-for-Tube Replacement. The analy-sis showed that the tube-for-tube replacement will provide significantly lower ΔEg than the bundle replacement. This is because the tube-for-tube replacement results in a reduced condenser water flow rate. For the Figure 2b

NW-16 tube, the flow rate reduction is 19%. This reduced flow rate causes the condenser to operate at higher thermal effectiveness, which degrades the condenser performance, relative to the second case, which holds water flow rate constant. For the NW-16 tube, the resulting annual average ΔEg is 9.87 MW.

Tube Bundle Replacement. In this case, the total length of all tubes in the enhanced tube condenser is the same as for the plain tube design. However, the design maintains the total water flow rate the same as for the plain tube design by using more tubes (of a shorter length) in the enhanced tube condens-er. For the NW-16 tube design, the enhanced tube condenser has 23% more tubes than that in the plain tube condenser (lines 8, 9, 10).

Also remember that the condenser inlet wa-ter temperature changes for each month of the year. In this analysis, results were calculated for four representative months: January, April, July, and October. These results were then used to obtain the annual average values.

The calculated results are shown in Table 1 in the order of the calculation procedure just described. Calculated results are shown for January, April and October (combined because the cooling water inlet temperatures are the same), and July for both the plain and enhanced tube condenser designs. The key performance number shown in Table 1 is ΔEg, which is the increased net generation rate provided by the enhanced tube condenser design. The greatest ΔEg occurs in July at 36.8 MW. The smallest ΔEg occurs in January and is 3.2 MW. The reason the January ΔEg is so small is because the heat rate curve (Figure 1) is relatively flat at the low condensing pressure (Psat) of January. Hence, the warmer the condenser water inlet temperature, the greater the benefit of enhanced tubes.

Table 2 summarizes the annual average values of the performance parameters derived from Table 1 for the different seasons.

Economic EvaluationThe greatest economic benefit to the plant will occur if the entire tube bundle is replaced

using the same total lineal tubing length as is used in the plain tube design (Table 2). However, the enhanced tube bundle will have about 25% more tubes and will provide the same condenser water flow rate as the plain tube design. The full potential of enhanced tubes can only be obtained with a new con-denser bundle design. A tube-for-tube re-placement results in reduced water flow rate, which diminishes the performance potential.

This evaluation assumes that the only cost affected is the cost of the tube bundle; the cost of the condenser shell is not included in the analysis. The capital benefits of the enhanced tube condenser are described by a simple payback analysis. This analysis calcu-lates the simple payback based on:

The capital value of the increased genera-tion rate, assuming a value of $2,000/kW (= 2 × 106 × ΔE).

The increased tube cost of the enhanced tube design, relative to the plain tube de-sign given by

Table 3 shows the results of the payback analysis. Line 1 shows the increased genera-tion capacity for the enhanced bundle design. The second line shows the capital value of the increased generation capacity (Ccap). Line 3 shows the total tube cost of the plain and enhanced tube bundles (Ct). The cost of plain and enhanced titanium tubes was based on data provided by Plymouth Tube, a manufac-turer of titanium tubes. The present analysis is for 28.6-mm OD, 0.7-mm wall titanium tubes. It was also assumed that two-thirds of the tube cost is material and one-third is fabrication. The material costs were then adjusted by mul-tiplying by the diameter ratio (28.6/25.4).

Table 3 shows that the material content cost is $10.35/m (or $36.85/kg) at the time this analysis was completed in late 2009. The plain tube fabrication cost was assumed to remain constant. It is conservatively assumed that the fabrication cost of the enhanced tubes is 75% greater than for the plain tubes. This resulted in tube costs of $14.93/m and $18.37/m for the plain and enhanced tubes, respectively.

Using the values given above, the tube bun-dle cost increment for the enhanced condenser tubes, relative to plain tube design (ΔCt), is

This value is shown on Line 4 of Table 3. The simple payback on the increased gen-

eration cost for the tube-for-tube replacement is 0.036 years and 0.024 years for the “new bundle”—or just a matter of weeks (line 5). Note that the ΔE value in Table 3 is the net

Table 2. Annual average plant performance improvement for NW-16 tubes. Source: Dr. Ralph L. Webb

Item Units PlainTube-for-tube replacement

New bundle with NL = constant

Number of tubes 23,150 23,150 28,575

Qh (steam heat input) MW 2,940 2,940 2,940

HR correction factor % 2.12 1.06 0.54

Heat rate (actual) kW/kW 3.00 2.97 2.96

Qc (actual condenser load) MW 1,857 1,847 1,842

W (turbine output at Psat) MW 927 936 941

Wnet (less pump power) MW 926 935 9,409

ΔEg (increase net over plain tube) MW 0 9.87 14.65




plant design

increase in turbine generator power over the plain tube design with the condenser water pumping power charged to the plain tube condenser. This is because the enhanced tube condenser has the same condenser water pumping power as the plain tube design. A tube-for-tube replacement will provide only 67% of the economic benefits (Ccap) of the entire tube bundle replacement.

Korodense Tube BundleA similar analysis was also performed for the Wolverine Korodense tube (Figure 2a). It is interesting to compare the performance and

economics of the Korodense tube condenser with that of the NW-16 tube condenser. Com-parison with the NW-16 tube condenser is done for the same number of tubes (28,575) and tube length shown for the “new bundle” with NeLe = constant, as shown in Tables 2 and 3. The Korodense tube has 20% and 40% higher tube side heat transfer coefficient and friction, respectively, than the NW-16 tube (at the same Reynolds number). However, the steam side enhancement is 25% smaller than provided by the NW-16 tube.

The analysis shows that the Korodense tube results in a lower water flow rate for the

same pumping power as the NW-16 and plain tubes. This flow rate reduction reduces the thermal performance. For a Korodense tube condenser with 28,575 tubes, the water flow rate is reduced 8%, relative to the NW-16 and plain tube condensers. The annual average value of ΔE is 24% below that of the NW-16 tube condenser, and the simple payback is 0.048 years. For the tube-for-tube replace-ment case, the annual average value of ΔE is 53% below that of the NW-16 tube condens-er, and the simple payback is 0.12 years.

Not included in the economic analysis is the cost of plant replacement power during an outage that may extend longer than the outage time required to merely replace plain tubes. However, with the simple payback on the investment measured in weeks, the economics of using enhanced tubes remains exceedingly strong. Seriously interested con-denser designers will likely use their own economic analysis to determine the benefits of using enhanced condenser tubes.

—Dr. Ralph L. Webb (ralph.webb@psu .edu) is professor emeritus in the Depart-

ment of Mechanical and Nuclear Engi-neering at Penn State University. Webb is

also the editor-in-chief of the Journal of Enhanced Heat Transfer.

Table 3. Summary of economic benefits of the NW-16 tube condenser. Source: Dr. Ralph L. Webb

Line Item Units Plain tubeTube-for-tube replacement

New bundle with NL = constant

1ΔE (incr. generation over plain tube design)

MW 9.87 14.65

2Ccap (capital value of in-creased generation)

$ 19.7 x 106 29.3 x 106

3 Ct (total tube cost) $ 4.63 x 106 5.69 x 106 5.70 x 106

4 ΔCt (enhanced-plain tubes) $ 1.068 x 106 1.068 x 106

5Ct/Ccap (simple payback on increased generation)

years 0.054 0.036

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Water treatment

Sub-Sea Water Treatment System Provides Reliable Supply for the Huarun Power PlantRiver deltas experience extreme seasonal changes in water quality that perplex

conventional water treatment systems. Industrial development in China, including new power plants, has spurred the development of desalination processes that have tamed these brackish water sources to provide a vir-tually unlimited supply of boiler-quality water.

By Echo Zhao, Dow Water & Process Solutions; Yu Fangbing, Huarun Thermal Power Plant; and Yasushi Maeda, Dow Water & Process Solutions

The rapid development of an industrial-ized China has quickly increased the de-mand for pure water. In fact, the demand

for industrial pure water a decade ago was 1,139 million m3 (300,892 million gallons) per year, and the Chinese government predicts that 1,839 million m3 per year will be required by 2030. The rising demand for industrial water has overstressed conventional supplies, push-ing China to develop desalination technolo-gies to meet its quickly increasing pure water needs. Today, China is a leading user of water desalination technology on a grand scale.

River water supplies in the delta regions of China, Vietnam, and Bangladesh and island nations like Singapore and Malaysia have de-cidedly inconsistent quality. It is common for river delta water to have a total dissolved solids (TDS) content that fluctuates from 80 mg/l to 12,000 mg/l due to the seasonal seawater re-filling. This water is generally categorized as high-salinity brackish water (Table 1).

Given the interest of these delta regions in developing marginal water resources, a new category of supply water was established. The high-salinity water supplies that lie between freshwater (less than 500 mg/l) and standard sea-water (35,000 mg/l) is called “sub-sea” water.

The salinity of the rivers in this part of Asia is highly seasonal. River water salinity is af-fected by rainfall, especially near the seashore, because of water runoff. However, in the dry seasons, the river water level will fall only to be refilled by seasonal sea or ocean tidewa-ter that pushes up the river’s average salinity. The typical salinity range of a sub-sea water resource is between 2,000 and 8,000 mg/l. An-other characterization of sub-sea water: high chloride levels due to refilling that further complicates the water treatment processes.

These salinity fluctuations render tradition-al ion exchange (IX) water treatment processes

incapable of stable and reliable operation. Typical IX processes have a very narrow TDS operating band of 10 mg/l up to perhaps 600 mg/l. Reverse osmosis (RO) technology has successfully treated brackish water with salin-ity in the range of 1,500 mg/l to 5,000 mg/l with high salt rejection (SR). IX also suffers

from other operational drawbacks, such as using acid and caustic chemicals for resin re-generation and post-treatment of those wastes, more water for regeneration, and a large area of plant floor space. As a result, RO is now the favored technology in 90% of Chinese indus-trial desalination plants (Figure 1).

Distillation

Seawater RO membranes

Brackish water RO membranes

Low energy BW RO membranes

Reverse osmosis (RO)

Electrodialysis

Ion exchange

20,000

8,000 50,000

12,000

50,000

2,000

10,000

50

50

50

300

60010 100,000Raw water salt concentration (mg/l)

Table 1. Water quality definitions by TDS level. Source: China Water and Rivers Commission, June 2000

Water type TDS range

Freshwater Less than 500 mg/l (good quality)

Marginal water500–1,500 mg/l (over 1,000mg/l may have excessive scaling, corrosion and unsatisfactory taste)

Brackish 1,500–5,000mg/l

Saline More than 5,000mg/l

Hypersaline More than 50,000mg/l

1. Processes for treating water. Main desalination processes. Source: Dow Chemical

13_PWR_040110_WaterTreatment_p56-60.indd 56 3/16/10 6:18:22 PM



Water treatment

Treating Sub-Sea Water The two-step process for sub-sea water treatment is pretreatment to remove sus-pended solids followed by desalination to remove dissolved solids in the raw water (Figure 2). Specifically, there are two stag-es of pretreatment. First, the raw water is pumped into a clarifier. After reacting with flocculants, such as polymerized aluminum chloride (PAC), the suspended solids in the water are reduced to less than 5 mg/l. In the second stage, the water is fed into the second stage of pretreatment, starting with two multimedia filters (MMF) in series to further remove residual impurities, such as suspended solids, colloids, and organics so that the effluent’s Silt Density Index (SDI) is less than 5. Before the filters, 2 mg/l to 5 mg/l of sodium hypochlorite (NaClO) is added to control bacteria growth.

However, if there is not enough budget, or if there is limited space for water treat-ment equipment, hollow fiber ultrafiltration (UF) may be another effective option in the second-stage pretreatment to protect the RO membranes from suspended solids, bacteria, and nondissolved organics. The SDI of ef-fluent from UF can reach less than 3 mg/l.

After the second stage of treatment (fil-tration or UF), sodium bisulfite (NaHSO3) and an antiscalent are added to remove any residual free chlorine and to avoid scaling of the RO membranes. The water is then fil-tered to 5 microns, typically in a cartridge filter, and then pumped to the RO units for desalination.

In a typical RO unit, 95% to 98% of salt and other solved organics, colloids, and bac-teria are removed in the reject water. If the water is for potable use, two or three stages of single-pass RO are used to obtain water of the specified quality. If higher purity water is required for industrial purposes such as boiler water, then a two-pass RO or a two-pass RO followed by IX mixed bed and/or continuous electrodeionization (CEDI) will be required.

As an example, Yuhuan Water Treatment Corp.—located in Yuhuan Town, Wenzhou City, Zhejiang, China—owns and operates a desalination potable water plant. The town’s sub-sea water TDS is about 2,800 mg/l to 3,800 mg/L at a temperature ranging from 12C (54F) to 17C (63F). During one 101-hour operating period, the water feed TDS changed from 5,500 µS/cm to 7,000 µS/cm (measuring TDS based on conductivity rath-er than weight). The TDS of the RO permeate or product water also changed from 120µS/cm to 300µS/cm. Here, the RO permeate water meets the requirement of the Chinese Standards for Drinking Water Quality of less than 1,000 mg/l TDS. The U.S. TDS limit for

potable water set by the Environmental Pro-tection Agency is 500 mg/l.

RO Makes Power Plant Makeup Water The Huarun Power Plant (HPP) entered com-mercial service in 2007 with two pulver-ized coal boilers each producing 260 tons/hr (573,000 lb/hr) of steam used to generate 360 MW in a pair of like-sized steam turbines. The plant is located in Huangge Town in the Nansha Development Zone, an important hub port at the Pearl River Delta south of Guang-zhou City, Guangdong Province, China.

HPP’s makeup water comes from the Xiao HuLi River, which is close to the South Sea entrance, hence the river water’s TDS, chloride, and conductivity increase as a result of seawater refill during the dry sea-son. An RO system was supplied by Nanjing Zhongdianlian Co. designed to produce the necessary boiler makeup water for the two power generation units from the available sub-sea water supply.

In Table 2, the TDS record of Xiao HuLi River’s water shows wide TDS variation, from 80 mg/l to 14,000 mg/l in 2006, and chemi-cal oxygen demand (COD) that ranged from 4.92 mg/l to 39.1 mg/l. The boiler makeup water specification requires water quality of 15 MΩ/cm at 25C (equal to 0.067µmhos/cm), which is more rigorous than the normal boiler makeup water standard (0.15 µmhos/cm); hence, a two-pass RO and CEDI or IX mixed bed was required for this water treat-ment system (Table 3).

Underwater pump

PAC dosing

Clarifier Pretreatmenttank

Raw water boost pump

NaCIOdosing

Mechanicalfilter

Demineralizedwater tank 1st pass and

3-stage reverse osmosis

High-pressure pump

Cartridge filter (5 micron)

NaHSO3 & antiscalant dosing

2. Removing water hardness. A typical sub-sea water desalination treatment process. Source: Zhejiang Hydrotechnics, June 2006

Table 2. Xiao HuLi River’s aver-age water quality record from 2004 to 2006. Source: Dow Water & Process Solutions

Measurement Data range

pH 6.92–7.69

Temperature (C) 15–35

Total hardness (mmol/l) 0.3–46

COD (Mn), mg/l 4.92–39.1

BOD5 (mg/l) 2.58–10

TDS (mg/l) 80–14,000

Silicon (mg/l) 2–13

Cl–(mg/l) 9–7,000

Dissolved oxygen (mg/l) 3.27–4.78

SO42- (mg/l) 19–307

Ca2+ (mg/l) 21.2–62.44

Na+ (mg/l) 2–7,000

Mg2+ (mg/l) 3.31–65.25

Table 3. Boiler makeup water re-quirements of Huarun Power Plant. Source: Dow Water & Process Solutions

Constituent Requirement

Hardness (µmol/l) ≈0

Sodium (µg/l) <100

Resistance (MΩ/cm @ 25C)

≥15

SiO2 (µg/l) <15




Water treatment

Water Treatment ProcessesThe plant began service in December 2006 with city water transitioning to treat Xiao HuLi River water in February 2007. The wa-ter treatment plant is now operated and main-tained by Hanchuang (Hubei) Power Plant, a partner company of HPP. The capacity of HPP’s water treatment plant is 182 m3/h (~800 gpm) of makeup water.

To reduce the first cost of the RO system, a brackish water RO element instead of the sub-sea RO elements were specified. HPP plans to maintain the raw water TDS below 3,000 mg/l because of limitation with the feed high-pressure pump (1.50 Mpa or 217 psi) and the anticorrosion limits of the RO system. However, even after dilution, the highest chloride level still can reach 1,300 mg/l. Therefore, the raw water makeup to the HPP is prepared by a freshwater and sub-sea water mixing system.

In this RO design, a Filmtec BW30-365 element is the standard brackish water RO element with 34 m2 (365 ft2) of active mem-brane area, a nominal permeate flow of 36 m3/d (9,500 gallons/day), and a stabilized salt rejection of 99.5%.

Figure 3 shows a flow diagram of the HPP water treatment facility and its water volume balance. The water treatment system consists

of two steps of pretreatment and two steps of desalination.

Step 1. The first pretreatment step occurs when raw water is pumped into a clarifier settling tank to remove 90% to 95% of sus-pended solids, colloid, chroma, and turbidity. Meanwhile, 10 ppm to 15 ppm of PAC are added in the front of the clarifier to help co-agulation and flocculation. The clarified wa-ter then flows to a pretreatment storage tank.

Step 2. The second pretreatment process is a series of refined filtration steps. First, 2 ppm to 5 ppm of PAC and 5 ppm of NaClO are dosed to achieve completed flocculation and control bacteria growth. Next, the clarified water is fed into an MMF for further filtration to ensure the effluent’s qualified turbidity (≤1 NTU) and SDI (≤5). Subsequently, the water is filtrated by a cartridge disk filter (CDF) with an average pore size of 100 µm (Figure 4) be-fore flowing into the pressurized hollow fiber UF system (Figure 5) that has a total recovery of 90% of entering water. The internal diam-eter of the pressurized hollow fiber UF is 0.7 mm, and the maximum molecular weight cut-off is 80,000 Dalton. At this stage, the water SDI is controlled to less than 3.

Step 3. The desalination process begins when the water is dosed with 3 ppm to 4 ppm of antiscalent and 2 ppm to 3 ppm of NaHSO3,

Raw water

10 t/h

2–5 ppm PAC5ppm NaCIO

Clarifier settling tank

Pretreatment storage tanks

NaOh

Multimedia mechanical

filter

ARKAL SPIN KLIN cartridge disk filter

(100 μm)

Pressurized hollow

fiber UF

UF tank

10–15 ppm PAC18 t/h

2–3 ppm NaHSO3

3–4 ppm antiscalant

1st pass RO permeate

tank

109 t/hRecovery 75%

146 t/h

High-pressure pump

Cartridge fiter (5 μ,)

Boost pump

1st pass RO: 2X109 t/h (17X6:9X6)

Recovery 85%

119 t/h

High-pressure pump

2nd pass RO: 2X101 t/h (7X6:4X6)

101 t/h 2nd pass RO permeate

tank

Concentrate water recirculation

C-cell boost pump

101 t/h91 t/h

Concentrate water recirculation

Point of use

Demineralized pump

Demineralized water tank

C-cell recovery: 90%

Cartridge fiter (5 μ,)

Ammonia

3. Four-step process. Huarun Power Plant water treatment flow diagram. Source: Dow Chemical

4. The cartridge disk filter. Courtesy: Dow Water & Process Solutions

5. The pressurized hollow fiber ul-trafiltration system. Courtesy: Dow Water & Process Solutions




Water treatment

and then is fed through a 5-µm cartridge filter before being pumped to the RO skid. There are two passes of RO with each two-stage design.

The first-pass RO system consists of two independent trains, each with a per-meate design flow rate of 109 m3/h (~480 gpm) at a recovery of 75% to 80% (Figure 6). Each train has two stages with 17 and 9 pressure vessels, respectively, and each vessel houses six elements. There are 156 Filmtec BW30 elements installed in the RO 1 train. The designed system salt re-jection is 97%. Next, the water is sent to the first RO permeate tank.

The permeate water from the first-pass RO is dosed with sodium hydroxide (NaOH) to adjust the pH to 8.0 to 8.8 and then is pumped into the second-pass RO (Figure 7). The second-pass RO (Figure 7) also consists of two independent trains, each with a permeate flow rate of 101 m3/h (~440 gpm) at a recov-ery of 85%. Each train has two stages with seven and four pressure vessels, respectively, that can be filled with six elements each. The salt rejection from the system is designed as 95%. Afterward, the water is sent to the second-pass RO permeate tank.

Step 4. The second step of the desali-nation process—with the water entering

two independent CEDIs with 90% to 92% recovery (Figure 8), and finally, the efflu-ent of CEDI (15 MΩ/cm at 25C)—is sent to the demineralized (DI) water storage tank. To meet HPP’s boiler water makeup pH re-quirement of 9.0 to 9.6, ammonia is added to the demineralized water. Meanwhile, all concentrated water from the second pass RO and CEDI will be respectively recycled into the UF tank and the first-pass RO permeate tank for recycling.

Operational Results Are ExcellentOperational data of the first-pass RO were recorded from February 2007 to July 2007 and normalized by Dow’s FTNORM pro-gram to evaluate the performance of the Filmtec BW30 elements (see sidebar). Dur-ing the test period, the raw water makeup varied widely, from 92 mg/l to as high as 2,617 mg/l; approximately one-third of the time the water TDS ranged from 520 mg/l to 2,617 mg/l (Table 4). According to the definition of sub-sea water, Xiao HuLi’s water became the sub-sea water type (TDS level of 2,000 mg/l to 8000 mg/l) on the days of seawater refilling during March 16 to 28, April 14 to 20, and April 22 to 29. At the same time, the temperature changed

7. The second pass of RO unit 1. Courtesy: Dow Water & Process Solutions

8. The continuous electrodeioniza-tion (CEDI) system. Courtesy: Dow Wa-ter & Process Solutions

Measurement Data

pH 6.95–7.72

Temperature (C) 19–33

TDS (mg/l) 92–2,617

Cl– (mg/l) 28–1,300

COD (Mn), mg/l 7–32

Table 4. Raw water data record, February to July 2007. Source: Dow Water & Process Solutions

Normalizing RO Performance DataA reverse osmosis (RO) system is designed to produce a certain permeate or prod-uct water flow when supplied by a given feedwater source water quality and a giv-en feed supply pressure. Unfortunately, operating conditions are seldom stable, so RO membrane performance isn’t easily measured, because comparing permeate flow and salt passage data at the same conditions is vital. Because this is not al-ways possible, converting the actual data conditions to a set of selected normalized conditions is necessary.

To determine if the membrane system’s performance has changed over time, nor-malizing the data is needed to translate performance data measured under actual and varying conditions into theoretical performance data under defined and sta-ble reference conditions. A plot of these normalized performance data will then show the trend of the membrane perfor-mance independent of changing operating conditions. It is also useful to determine the cleaning requirements and to judge the system performance with respect to the design values.

For example, for best long-term per-formance we recommend cleaning the membrane when the normalized flow has declined by 10% or the normalized salt passage decreased by more than 5%. ASTM D4516, Standard Practice for Standardizing Reverse Osmosis Performance Data, defines the process of normalizing RO performance data for comparison purposes.

However, in practice, most plants are operated not at constant pressure but at constant flow rate. Therefore, it might be more useful to calculate the normalized salt passage with reference to a constant system flow rate rather than to a constant pressure. This way, the result is directly proportional to the salt permeability of the membrane and does not depend on operating parameters.

Dow offers a spreadsheet-based pro-gram, FTNORM, that provides automatic standardization of operating data. Charts are created showing standardized per-meate flow, standardized salt passage/salt rejection, and differential pressure. The program is free to download at www .dow.com.

6. The first pass of RO unit 1 and unit 2. The water flows from the front to the back of the photo. Courtesy: Dow Water & Process Solutions


http://www.dow.com


http://www.dow.com


Water treatment

from 19C to 33C and the COD level ranged from 7 mg/l to 32 mg/l.

Three key results were observed during this testing:

The normalized permeate flow was very consistent, even with such high variation in the TDS feed conditions (Figure 9). Upstream, the water feed TDS fluctuated, as did the RO 1 driving pressure from the end of February to the end of April be-

cause of seawater refilling. After April, we observed the temperature of the feedwater increased from 25C to 33C, the seawater refilling became weak, and the permeate flow of both trains became stable. The RO 1 system operated at 78% to 80% water recovery, meaning that 80 gallons of good product water were produced for every gallon of raw water supplied.

Pressure drop (PD) is the signal that indi-cates how much contamination is present

in the RO system. Low PD tells the op-erator that the feed space is smooth or all the contamination was backwashed out by concentrate water. High PD indicates that there is some fouling present in the RO system that must be removed. Chemi-cal cleaning is recommended to remove the fouling contamination if the PD level is 10% higher than normal value. The normalized pressure drop of RO 1 was measured and recorded during the test period (Figure 9). The initial PD of RO 1 was 1.3 bar. Even with the increase in water temperature and operating hours, RO 1 PD remained stable in the 1.3 bar to 1.4 bar pressure drop range during the test period.

The performance of normalized salt pas-sage (SP) and salt rejection (SR) are plotted in Figure 10. The SR remained a conservative 97% during the test period. Both trains’ SR basically met the required 97%, except the raw water was of the sub-sea water type from March 16 to 28, April 14 to 20, and April 22 to 29.

During the periods of seawater refilling (March 16 to 28, April 14 to 20, and April 22 to 29), the sub-sea water’s TDS was in the range of 2,023 mg/l to 2,617 mg/l, and the SR of each of the two trains was lower than in other periods. Hence, similar to the trend of the permeate flow rate, both first-pass RO SRs kept fluctuating until May.

The initial SR of RO 1 was 98.32%. Af-ter contamination of the sub-sea water, the TDS during the period (2,500 ppm to 2,700 ppm from March to April) in the RO 1’s SR declined. After May, the two RO trains’ SR returned to higher than 97.5% when the raw water TDS decreased. By the end of July, the average normalized SR for RO 1 was 98.4%.

The integrated membrane process water system at the Huarun Power Plant con-tinues to reliably produce boiler-quality water from river and sub-sea raw makeup water. Lesser-quality water sources will only become more common as high-qual-ity water resources around the world are stressed to supply the needs of the world’s population. The Huarun Power Plant water treatment design illustrates that desalina-tion is a viable option for industrial water supplies in the future. —Echo Zhao([email protected]) is regional

applications development leader, Asia Pacific, Dow Water & Process Solutions.

Yu Fangbing is water treatment plant manager, Huarun Thermal Power Plant. Yasushi Maeda ([email protected]) is an applications specialist for Ultrapure

Water, Dow Water & Process Solutions.

3,000

2,500

2,000

1,500

1,000

500

0

13

12

11

10

9

8

7

6

5

4

3

2

1

0

1-Jan-00

11-Jan-00

21-Jan-00

31-Jan-00

10-Feb-00

20-Feb-00

1-Mar-00

11-Mar-00

21-Mar-00

31-Mar-00

10-Apr-00

Feed TDS Net driving pressure filmtec RO1 Normalized pressure drop

TDS

Pres

sure

(bar

)

Operation time (days)

10

9

8

7

6

5

4

3

2

1

0

100

99

98

97

96

95

94

93

92

91

90

Salt

pass

age

(%)

Salt

reje

ctio

n (%

)

Salt passage filmtec RO1 Salt rejection filmtec RO1

3-Fe

b-07

9-Fe

b-07

18-F

eb-0

728

-Feb

-07

10-M

ar-07

22-M

ar-07

3-Apr

-07

14-A

pr-0

720

-Apr

-07

28-A

pr-0

79-

May

-07

Operation time (days)

17-M

ay-0

725

-May

-07

2-Ju

n-07

14-Ju

n-07

20-Ju

n-07

27-Ju

n-07

4-Ju

l-07

13-Ju

l-07

20-Ju

l-07

25-Ju

l-07

9. Normal system performance. Normalized net driving pressure and pressure drop of the RO 1 system confirmed that the system was performing as expected. Note the variation of the total dissolved solids in the incoming water. Source: Dow Water & Process Solutions

10. Salt adverse system. Normalized salt rejection of RO 1 is a measure of the reverse osmosis system performance. Source: Dow Water & Process Solutions






Transmission & DisTribuTion

Smart Grid: On the MoneyHow much will a smart grid cost? It’s a question that has gained importance in

light of massive cost overruns for one highly touted U.S. project. By Gail Reitenbach, PhD

The U.S. grid, like almost all national grids, requires expansion and upgrad-ing to serve growing electricity de-

mand, accommodate increased renewable generation sources, improve prevention of and response to outages and security threats, and maximize the efficient transmission of electricity. The cost of improving the grid to meet these goals is high—somewhere in the neighborhood of $65 billion to $165 billion over the next decade or two. The cost of do-ing nothing is higher.

Take, for example, reliability, which tends to decrease as demand on the grid increases and variable renewable generation increases. A June 2001 Electric Power Research Insti-tute (EPRI) report, “The Cost of Power Dis-turbances to Industrial & Digital Economy Companies” estimated that the annual direct cost of power outages and power quality dis-turbances for all sectors (not just those in the survey) was between $120 billion and $188 billion. In its 2003 report, “Grid 2030,” the Department of Energy (DOE) noted that “it is estimated that power outages and power quality disturbances cost the economy from $25 [billion] to $180 billion annually.”

A more recent 2006 study by Lawrence Berkeley National Laboratory researchers, “Cost of Power Interruptions to Electricity Consumers in the United States,” found that, “based on publicly available data and subject to the limitations discussed . . . the economic cost of power interruptions to U.S. electricity consumers is $79 billion annually.” Their ca-veat: “Our analysis of the uncertainty in this estimate suggests that the costs could be as high as $135 billion or as low as $22 billion based on the particular sensitivity assump-tions we employed.”

As end users discover new uses for elec-tricity—from iPads to plug-in hybrid electric vehicles to the manufacturing of solar mod-ules—the cost of grid disruptions is likely to move higher. And those are just the direct monetary costs of a less-than-optimal grid.

Minimizing those costs by building a more robust and “smarter” grid seems like a good idea to many people. But even setting aside the gnarly political, regulatory, and jurisdictional issues that make grid projects a nightmare in the U.S. in particular, there’s another big hairy concern: paying for an improved grid.

Not-So-Smart Budgeting for SmartGridCityAs a concept without definitive definition (unlike the molecular description of an element like carbon), the smart grid can mean what its users stipulate that it means in a given context. That’s not necessarily a bad thing nor the sign of a conspiracy. It’s just that the smart grid is even more com-plex in its entirety than the Internet. But it does mean that policy makers and the pub-lic need to be aware that one utility may use “smart grid project” as a way to make business-as-usual transmission and distri-bution upgrades sound more cutting-edge while another utility may use the phrase to describe an experimental research and de-velopment (R&D) project that may or may not deliver the desired results. Xcel Ener-gy’s SmartGridCity is a case in which the implications of large-scale deployment of what is being described as an R&D project are just now coming to light.

Xcel’s SmartGridCity project costs have ballooned from an initial estimate of $15.3 million to $42.1 million. Although the Col-orado Public Utilities Commission (PUC) approved a Jan. 1 rate increase affecting all Colorado Xcel customers to cover capital, operation, and maintenance costs of the Boulder, Colo., project (plus a new coal-fired generating plant), it’s still unclear

where all $42.1 million are going to come from.

In response to the latest cost news, the PUC has required the utility to file for a post-facto certificate of public convenience and necessity, which would give the PUC authority to regulate the smart grid project. It seems this requirement wasn’t triggered earlier because Xcel initially described the project as being supported by a consortium of technology and service vendor-collabora-tors. How much skin any of those vendors actually has in the game is still unclear. In the meantime, Xcel neglected to apply for the first round of smart grid funds made available under the American Recovery and Reinvestment Act of 2009 (ARRA) and was left without a Plan B when the DOE can-celled round two of ARRA smart grid fund-ing opportunities.

The Boulder paper, The Daily Camera, cites this explanation for the cost increases from the utility: “ ‘The company had to in-stall far more underground fiber than ini-tially projected, substantially increasing the cost . . .’ Xcel officials wrote in a document filed with the utilities commission last May. ‘We also ran into unexpected construction conditions such as having to drill through granite with diamond-tipped drill bits and remove large boulders with cranes and dump trucks. . . .’”

1. Cloudy outlook for smart grid acceptance in SmartGridCity. Boulder, Colorado—which typically enjoys more than 300 sunny days per year—has lately been taking a dimmer view of smart grid project activity and costs than it did when the idea was originally rolled out by Xcel Energy. Though all project implementation costs were expected to be funded by the utility’s vendor partners, costs have begun to be passed on to customers via increased rates. Courtesy: Gail Reitenbach

14_PWR_040110_SmartGrid_p61-63.indd 61 3/16/10 6:21:31 PM




You read correctly: unexpected “boulders” in “Boulder,” which hugs the abrupt uplift of the Rocky Mountains.

The Daily Camera quotes Xcel spokes-man Tom Henley as saying, “SmartGridCity has always been a research and development process, . . . It’s a living and breathing labo-ratory, and we’ve always said all along that there’s parts that will work and parts that won’t work.”

To be fair, that’s true of any new technol-ogy. What customers may be less willing to

accept is that they, rather than shareholders and project technology partners, are now be-ing asked to cover those experimental R&D costs (Figure 1).

A New Approach to Estimating Smart Grid CostsThough there may never be a way to estimate the full cost of unforeseen circumstances, a new cost estimate framework may help the entities funding projects large and small compare costs and benefits using a common

methodology. In January, EPRI released a re-port, cofunded by EPRI and the DOE, whose goal “is to present a comprehensive set of methods for estimating the benefits and costs of Smart Grid projects.”

It’s important to note that “Methodologi-cal Approach for Estimating the Benefits and Costs of Smart Grid Demonstration Projects” does not itself offer a new estimate for total U.S. smart grid costs. The closest it comes to a grand total is its citation of a 2004 EPRI report that estimated smart grid costs over 20 years at $165 billion.

But if $165 billion sounds like a lot, consider that the 2008 report citing that now-six-year-old figure (S. Pullins, “Smart Grid: Enabling the 21st Century Economy”) pegged the value of smart grid benefits over 20 years at $638 billion to $802 billion. Not a bad return on investment (ROI).

Also note that this proposed framework is for estimating the benefits and costs of “Smart Grid Demonstration Projects.” It is tackling cost and benefit projections for small parts of that elephantine “smart grid” that no single U.S. entity can create on its own.

The meat of the report focuses “on the definition of benefits and a sequential, logi-cal process for estimating them. Beginning with the Smart Grid technologies and func-tions of a project, it maps these functions to the benefits they produce.” The goal is that “The methods developed in this study will help improve future estimates—both retro-spective and prospective—of the benefits of Smart Grid investments. These benefits, including those to consumers, society in general, and utilities, can then be weighed against the investments. Such methods would be useful in total resource cost tests and in societal versions of such tests. As such, the report will be of interest not only to electric utilities, but also to a broad con-stituency of stakeholders.”

Until this or some other cost/benefit cal-culation method becomes standard, it will be difficult to compare the ROI of any two pro-posed or implemented projects for customers (aka, the ultimate cost-bearers), utilities, gov-ernment grants, or the environment.

The EPRI report identifies four catego-ries of benefits: economic, reliability and power quality, environmental, and security and safety. Here are some of the benefits that would accrue to power generators in particular:

“Optimized Generator Operation: Better forecasting and monitoring of load and grid performance would enable grid op-erators to dispatch a more efficient mix of generation that could be optimized to reduce cost.

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Reduced Generation Capacity Invest-ments: Utilities and grid operators ensure that generation capacity can serve the maximum amount of load that planning and operations forecasts indicate. The trouble is, this capacity is only required for very short periods each year, when demand peaks. Reducing peak demand and flattening the load curve should re-duce the generation capacity required to service load, and lead to cheaper electric-ity for customers.

Reduced Ancillary Service Cost: Ancil-lary services including spinning reserve and frequency regulation could be re-duced if generators could more closely follow load. Ancillary services are neces-sary to ensure the reliable and efficient operation of the grid. The level of ancil-lary services required at any point in time is determined by the grid operator and/or energy market rules. The functions that provide this benefit reduce ancillary cost through improving the information avail-able to grid operators.”

It will be interesting to see how quickly the use of this approach is adopted and whether or not the DOE uses it to hold grant recipi-ents accountable.

Governments Pouring Money into Smart GridsThe U.S. government isn’t the only one lend-ing a hand to “smart” national grid projects. According to a Jan. 27 report by Zpryme, China is already outspending the U.S. in terms of federal dollars devoted to smart grid projects. Here’s its ranking of 2010 invest-ments (in US$ millions):

1. China: $7,3232. U.S.: $7,0923. Japan: $8494. South Korea: $8245. Spain: $8076. Germany: $3977. Australia: $3608. UK: $2909. France: $26510. Brazil: $204

Granted, China is starting with a blank slate in many respects, whereas the U.S. has a head start. The flip side of that dynamic: The very presence of any existing transmis-sion and distribution infrastructure creates a larger hurdle for grid improvements because it can create a false sense that the status quo is just fine.

Meanwhile, U.S. companies are taking note of where R&D and project imple-mentation opportunities lie—beyond U.S.

borders. Zpryme notes that “Just recently, GE aligned itself with Yangzhou, China to construct a smart grid demonstration cen-ter. Similar steps forward are being echoed from industry-leading players such as Cisco, Accenture, Hewlett-Packard, ABB, Westinghouse, and Oracle—which are buying into a generous stake of China’s smart grid market. What’s more, Business Week recently reported that IBM expects at least $400 million in smart-grid revenues in China over the next four years. Fitting

testimony as IBM remains the only cor-poration that provides hardware, software and consulting for smart grid infrastruc-ture projects in China.”

Demonstrated Benefits of Smart Grid Costs For details about costs and benefits of one of the most comprehensive smart grid roll-outs, in Italy, see this February interview with Livio Gallo, director of Enel’s Infra-structure and Networks Division: http://tinyurl.com/yhejhk5. Enel invested €2 billion (roughly US$2.7 billion) in its six-year deployment of 32 million electronic meters. Among the benefits to date: a 62% reduction in minutes of service interrup-tion per customer and a 61% reduction in distributor meter management costs per customer.

A November 2009 BusinessWeek story re-ported that the Italian utility is saving $750 million per year as a result of the project. Furthermore, “improved data on consumers’ electricity habits permit Enel to run its power plants more efficiently.”

Needless to say, this story is far from the final word on smart grid costs. Stay tuned.

—Gail Reitenbach, PhD is POWER’s managing editor.

More on Smart Grid Definitions and DevelopmentsFor smart grid definitions and overviews of smart grid project activity in the U.S. and around the world, see these stories in our January 2010 issue:

U.S. Smart Grid Forecast: Flurries of Activity

What Do Customers Expect from the Smart Grid?

Which Country’s Grid Is the Smartest?

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energy revolutionGet ready for the new

T h e T u r b o C a r e M a g m a ™ 5 0 0 0 g e o t h e r m a l r e - r a t e a b l e s t e a m t u r b i n e p r o v i d e s t h e f l e x i b i l i t y t o a s s u r e a s s e t p e r f o r m a n c e a n d v a l u e t h r o u g h t h e l i f e o f y o u r g e o t h e r m a l p l a n t .

PowerMag_TC_March10.indd 1 3/3/10 9:48:00 PM



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new products to power Your BusIness

Stainless Triplex Plunger PumpsCAT PUMPS recently introduced two new stainless steel triplex plunger pumps featuring a 316 stainless steel liquid-end for corrosion resistance. The 7CP6111 and 7CP6171 are designed for pumping liquids like seawater in small seawater reverse osmosis installations, demineralized water for misting, or hot water and sanitizers for sterile cleaning systems. The 7CP stainless steel pumps offer the flexibility of either belt-drive or direct-drive bell housing mounting. Both pumps provide a compact, space-saving footprint and deliver 10.5 gpm of up to 2,000 psi.

The 7CP6111 pump (shown here) features a single-shaft, direct drive 1,750 rpm, while the 7CP6171 features a single-shaft belt drive of 1,450 rpm. Preassembled motor pump units are also available with either a 10-hp or 15-hp motor. (www.catpumps.com)

Rugged Servo InclinometerUK-based Sherborne Sensors has introduced the LSI series of closed-loop gravity-referenced servo inclinometers to the North American market. The family of inclinometers is specially designed to withstand severe shock and vibration inputs for precise measurements in demanding environments.

The series incorporates a unique, flexure-supported torque-balancing system that is rugged enough to withstand shock inputs of up to 1,500 g, but which still provides accuracy and repeatability over a wide operating temperature range. Sensor components and associated electronics are contained within IP64 environmentally sealed housing. Units are available in ranges of ±14.5 degrees, ±30 degrees, and ±90 degrees and offer a high-level, 5-volt analog DC-output signal, proportional to sine of the angle of tilt. LSI series models are fully self-contained and can connect to a DC power source and a readout or control device to form a complete operating system. (www.sherbornesensors.com)

Microprocessor-Based Vibration AmplifierSensing and monitoring systems supplier Meggitt PLC launched the Endevco model 6634C, a microprocessor-based vibration amplifier that has been designed to condition and display rotating machinery data in simultaneous outputs, such as broadband, acceleration, velocity, and displacement.

Model 6634C is designed to accept inputs from a single-ended, differential piezoelectric or ISOTRON (IEPE-type) accelerometer, velocity coil, or remote charge converter. Full-scale AC and DC output ranges, as well as sensitivity, are user-programmable in selectable engineering units, representative of acceleration, velocity, or displacement. Programming is accomplished from the front panel keyboard or optional RS-232 computer interface. Units also have an optional six-pole filter, which may be programmed from the front panel. Up to 10 unique setups can be stored and recalled from the nonvolatile memory, while two TTL-compatible latched alarm outputs provide both warning and alert functions. An optional 19-inch mounting rack from Meggitt Sensing Systems can accommodate up to six units. (www.endevco.com)


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NEW PRODUCTS

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

Encased High-Speed Imaging CamerasHigh-speed imaging systems manufacturer Photron introduced hardware to extend the normal operating temperature range of the Fastcam SA5 and Fastcam SA2 high-speed cameras. The Range Version (RV) is a new sealed case design that makes the camera models impervious to dirt, dust, and sand. Photron’s RV option includes two serviceable external fans that direct cooling air over the sealed camera body. This keeps the operating temperature stable and makes it ideal for high-speed imaging in harsh environments. Photron’s Fastcam SA5 camera provides up to 7,500 frames per second (fps) at megapixel resolution (1,024 x 1,000), while its SA2 camera delivers up to 1,000 fps at full-pixel resolution (2,000 x 2,000). The cameras are available with an optional DC battery pack and a remote keypad with a built-in LCD viewfinder. (www.photron.com)

DC Power Sources for High-Production Welding ESAB Welding & Cutting Products’ LAF series of three-phase, fan-cooled DC welding power sources are designed for high-productivity mechanized submerged arc welding or high-productivity GMAW welding. Made for use in combination with ESAB’s A2-A6 equipment range and the A2-A6 Process Controllers (PEK or PEI), LAF welding power sources offer excellent welding characteristics throughout the entire current and voltage range, with particularly good starting and re-ignition properties.

These power sources demonstrate good arc stability at both high and low arc voltages, and they can be adjusted and monitored from the front panel of the process controller for easy adjustment of all welding parameters. The welding current range can be extended by connecting two power sources in parallel for the most demanding applications. The power sources are also designed to be used with the fully digital PEK controller for maximum functionality or with the PEI controller with basic functionality for less-demanding applications. Each power source is prepared for communication using most standard protocols, including TCP/IP (LAN), Anybus, Profibus, CAN, or even straight communication with a PLC. (www.esab.com)

Universal Input/Output TransmittersHoneywell has added universal input/output (I/O) transmitters to its family of XYR 6000 wireless products. The transmitters allow manufacturers to wirelessly monitor more plant points with fewer devices. The company says that by transmitting signals from up to three different types of inputs—including measurement devices with a high-level analog, temperature or milli-volt, or contact-closure switch input—the XYR 6000 Universal I/O transmitters can help plants save up to 30% in costs over similar devices that can transmit signals from only two inputs.

This XYR 6000 family of transmitters is ideal for applications such as wirelessly monitoring level switches, pump status, and system alarms. The devices also carry intrinsically safe approvals from FM Global and the Canadian Standards Association for use in hazardous areas. (www.honeywell.com/ps/wireless)


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Don’t miss PRB Coal Users’ Group Annual Meeting Co-located with ELECTRIC POWER 2010

10th Anniversary 2001-2010


Snapshot of PRB Annual Meeting TopicsCoal Handling System: Fire Case Study An explosion and resulting fire in a take-up tower and conveyor prompts review of all coal han-dling procedures and practices.

Coal Tunnel ExplosionA devastating explosion rips through an under-ground coal reclaim tunnel resulting in extensive damage. The response, the analysis, and infor-mation on prevention will be shared.

Combustible Dust Update A summary of the latest Combust Dust rulemak-ing efforts.

Teachable Moments When unplanned events occur and the analysis of the event is complete, others may learn how to prevent similar occurrences if the openness to create “teachable moments” exists. Here’s a few:

Flyash silo fire »Coal feeder flash fire »Combustible dust flash during housekeeping »Coal pipe (flash) fire »Coal conveyor fire »“PAC” (activated carbon) silo fire »

NFPA Standards in the Utility Coal IndustryNFPA 850 is a recognized standard addressing fire protection and loss prevention for electric generating plants. Learn about the changes and how NFPA helps you in preventing fires and losses.

Risk Tool: Safety & Health, Fire Protection An overview of a “tool” intended to enhance the understanding of, and provide direction for, the safe handling and burning of PRB coals.

Combustible Dust Compliance Strategy Case study of an utility using a combination of employee training and involvement, procedures, and existing risk management approaches to raise awareness and effectively manage dust.

Respirable Dust “Stop the continuation of health hazards at cur-rent levels” through a discussion that connects combustible dust and EPA compliance expecta-tions to enable a comprehensive and coordinat-ed approach towards safety and health.

www.prbcoals.com

May 18-20, 2010 • BaLTImORE, mD Baltimore Convention Center

In 2003, the Chemical Safety Board (CSB) launched investigations of three major industrial explosions involving combustible powders. These explosions—in North Carolina, Kentucky, and Indiana—cost lives and caused numerous

injuries and substantial property losses. The CSB responded by launching a nationwide study to determine the scope of the problem and recommend new safety measures for facilities that handle combustible powders. The PRB annual meeting is framed to start with an explanation of the driving reasons for increased rulemaking. Dust explosions kill and injure American workers, destroy jobs and businesses, and shatter communities. This presentation will draw on lessons learned from recent investigations of accidents involving dust. It will also share the CSB’s findings and recommendations for the prevention of future dust accidents.

PRB Keynote: The Honorable John S. Bresland

Chairman and CEOU.S. Chemical Safety Board

Learn what’s currently on OSHA’s agenda, what they’re working on to protect workers, and how it may impact the electric power generation industry. Hear their perspectives on combustible dust. A leader from OSHA will address

current safety & health issues, offer their perspectives, including a renewed emphasis on enforcement and what new frontiers they may explore.

Combustible DustFailure to realize its potential yields

explosive results!

David Michaels, PhD, MPHAssistantSecretary of Labor Occupational Safety & Health

The HonorableJohn S. BreslandChairman and CEOU.S. Chemical Safety Board

In 2003, the Chemical Safety Board (CSB) launchedinvestigations of three major industrial explosionsinvolving combustible powders. These explosions—inNorth Carolina, Kentucky, and Indiana—cost lives andcaused numerous injuries and substantial propertylosses. The CSB responded by launching a nationwidestudy to determine the scope of the problem andrecommend new safety measures for facilities thathandle combustible powders. The PRB annual meetingis framed to start with an explanation of the drivingreasons for increased rulemaking. Dust explosions killand injure American workers, destroy jobs andbusinesses, and shatter communities. This presentationwill draw on lessons learned from recent investigationsof accidents involving dust. It will also share the CSB’sfindings and recommendations for the prevention offuture dust accidents

Learn what's currently on OSHA's agenda, what they'reworking on to protect workers, and how it may impactthe electric power generation industry. Hear theirperspectives on combustible dust. A leader from OSHAwill address current safety & health issues, offer theirperspectives, including a renewed emphasis onenforcement and what new frontiers they may explore.

OSHa TodayDavid Michaels, PhD, MPHAssistant Secretary of Labor Occupational Safety & Health

Tuesday, May 18, 2010Look Who’s Speaking

to register, contact JiLL DeAn, 713-343-1880, [email protected]

or visit www.electricpower.com

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Don’t miss PRB Coal Users’ Group Annual Meeting Co-located with ELECTRIC POWER 2010



Snapshot of PRB Annual Meeting TopicsCoal Handling System: Fire Case Study An explosion and resulting fire in a take-up tower and conveyor prompts review of all coal han-dling procedures and practices.

Coal Tunnel ExplosionA devastating explosion rips through an under-ground coal reclaim tunnel resulting in extensive damage. The response, the analysis, and infor-mation on prevention will be shared.

Combustible Dust Update A summary of the latest Combust Dust rulemak-ing efforts.

Teachable Moments When unplanned events occur and the analysis of the event is complete, others may learn how to prevent similar occurrences if the openness to create “teachable moments” exists. Here’s a few:

Flyash silo fire »Coal feeder flash fire »Combustible dust flash during housekeeping »Coal pipe (flash) fire »Coal conveyor fire »“PAC” (activated carbon) silo fire »

NFPA Standards in the Utility Coal IndustryNFPA 850 is a recognized standard addressing fire protection and loss prevention for electric generating plants. Learn about the changes and how NFPA helps you in preventing fires and losses.

Risk Tool: Safety & Health, Fire Protection An overview of a “tool” intended to enhance the understanding of, and provide direction for, the safe handling and burning of PRB coals.

Combustible Dust Compliance Strategy Case study of an utility using a combination of employee training and involvement, procedures, and existing risk management approaches to raise awareness and effectively manage dust.

Respirable Dust “Stop the continuation of health hazards at cur-rent levels” through a discussion that connects combustible dust and EPA compliance expecta-tions to enable a comprehensive and coordinat-ed approach towards safety and health.

www.prbcoals.com

May 18-20, 2010 • BaLTImORE, mD Baltimore Convention Center

In 2003, the Chemical Safety Board (CSB) launched investigations of three major industrial explosions involving combustible powders. These explosions—in North Carolina, Kentucky, and Indiana—cost lives and caused numerous

injuries and substantial property losses. The CSB responded by launching a nationwide study to determine the scope of the problem and recommend new safety measures for facilities that handle combustible powders. The PRB annual meeting is framed to start with an explanation of the driving reasons for increased rulemaking. Dust explosions kill and injure American workers, destroy jobs and businesses, and shatter communities. This presentation will draw on lessons learned from recent investigations of accidents involving dust. It will also share the CSB’s findings and recommendations for the prevention of future dust accidents.

PRB Keynote: The Honorable John S. Bresland

Chairman and CEOU.S. Chemical Safety Board

Learn what’s currently on OSHA’s agenda, what they’re working on to protect workers, and how it may impact the electric power generation industry. Hear their perspectives on combustible dust. A leader from OSHA will address

current safety & health issues, offer their perspectives, including a renewed emphasis on enforcement and what new frontiers they may explore.

Combustible DustFailure to realize its potential yields

explosive results!

David Michaels, PhD, MPHAssistantSecretary of Labor Occupational Safety & Health

The HonorableJohn S. BreslandChairman and CEOU.S. Chemical Safety Board

In 2003, the Chemical Safety Board (CSB) launchedinvestigations of three major industrial explosionsinvolving combustible powders. These explosions—inNorth Carolina, Kentucky, and Indiana—cost lives andcaused numerous injuries and substantial propertylosses. The CSB responded by launching a nationwidestudy to determine the scope of the problem andrecommend new safety measures for facilities thathandle combustible powders. The PRB annual meetingis framed to start with an explanation of the drivingreasons for increased rulemaking. Dust explosions killand injure American workers, destroy jobs andbusinesses, and shatter communities. This presentationwill draw on lessons learned from recent investigationsof accidents involving dust. It will also share the CSB’sfindings and recommendations for the prevention offuture dust accidents

Learn what's currently on OSHA's agenda, what they'reworking on to protect workers, and how it may impactthe electric power generation industry. Hear theirperspectives on combustible dust. A leader from OSHAwill address current safety & health issues, offer theirperspectives, including a renewed emphasis onenforcement and what new frontiers they may explore.

OSHa TodayDavid Michaels, PhD, MPHAssistant Secretary of Labor Occupational Safety & Health

Tuesday, May 18, 2010Look Who’s Speaking

to register, contact JiLL DeAn, 713-343-1880, [email protected]

or visit www.electricpower.com

Additional topics related to boiler & combustion, coal handling, fire & safety can be found online at www.electricpower.com or www.prbcoals.com



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Commentary

Rethinking the Power Industry’s Dash to GasBy Bert Kalisch

During a recent meeting of state utility commissioners, the CEO of a Fortune 500 electric power company said natu-ral gas prices promise reliability but “always break your

heart.” What breaks my heart is the electric power industry’s ongoing love affair with natural gas. Using natural gas for gen-erating electricity is not the best or highest use for this clean, green, and domestically abundant resource.

Focusing on the Best Use for Natural Gas Our energy system will always require some natural gas to be made into electrons. Today 22% of electricity is generated by natural gas. But any engineer will tell you that the most efficient and carbon friendly way to use natural gas is piping it directly into homes and businesses. Policy makers should seek to design policies that incentivize our reliable energy supplies being put to their highest and best use at reasonable costs. Direct use of natural gas does just that.

It is indisputable that for every 100 molecules of methane produced at the wellhead, more than 90 are delivered directly to the stove’s burner tops in my Virginia home. On the other hand, electrons generated from fossil fuels are less than 30% efficient. Basic physics tells you that converting energy reduces Btus. In fact, former U.S. Energy Secretary Samuel Bodman said that “burning natural gas for electric generation is like washing dishes with a good scotch.”

An Abundant, Clean Energy SourceIn the past decade, many electric utilities have dashed to natu-ral gas for its flexibility and cleaner-burning properties in an-ticipation of a carbon cap. Natural gas is over 50% less carbon intensive than coal. Almost 90% of the U.S. power generation capacity that has been added since 1998 is natural gas–fired. Today there are more than 1,700 power plants in the U.S. that generate electricity from natural gas. According to the U.S. En-ergy Information Administration (EIA) 2010 Short-Term Energy Outlook, over 50% of the expected 23,475 MW of new generation capacity planned in the U.S. will be natural gas–fired additions.

There is certainly ample gas to meet our future needs. In 2008, the joint government-industry-academic Potential Gas Commit-tee published its highest-ever estimate of domestic natural gas reserves: 2,074 trillion cubic feet (Tcf). This estimate was 35% higher than two years earlier and 77% higher than the estimate made in 1990. The committee reported that approximately 600 Tcf (29%) of the estimated 2,074 Tcf is gas produced by unlock-ing shale formations.

Going forward, the EIA projects that natural gas production from U.S. unconventional resources such as shale will increase 35%, or 3.2 Tcf, through 2030. Our collective goal should be to put these new supplies to their most efficient use and be mindful of overreliance on gas to generate electrons.

Growing Storage CapacityThe ability to store those new gas supplies is increasing, which lessens the need to use the fuel immediately for elec-tric generation. The U.S. has the largest capacity for under-ground storage of natural gas in the world. Natural gas supply is injected and stored in more than 425 facilities across the country in geologic settings including depleted oil and gas

reservoirs, aquifers, and salt caverns (bedded salt forma-tions). Operational underground working gas storage capac-ity increased by about 100 billion cubic feet (Bcf) from the spring of 2008 to April 2009. In fact, the new total of more than 3.8 tcf was essentially filled prior to the 2009–2010 winter heating season, resulting in the largest inventory of working gas ever recorded.

A very cold start to winter in December 2009 and January 2010 attested to the value of growing storage. Utilities draw 15% to 20% of all gas consumed during the period of November to March from working gas. This flexibility is crucial to meeting heating load peak demands by local gas utility customers, and all customers for that matter.

The dash to gas has also led to concern that the infrastruc-ture will not be adequate to handle the increasing demand. Investment in natural gas pipeline infrastructure continues to grow steadily while the industry maintains a strong record of safety. In 2008, an estimated $11.4 billion was invested to complete 84 pipeline projects, adding 44.6 Bcf per day of capacity to the pipeline grid. These figures represent a nearly threefold increase over 2007, when $4.3 billion was spent to complete 50 projects that added 14.9 Bcf per day of capacity to the network.

The Better Option: Direct Use of Natural GasAmple indigenous gas resources, record gas storage, and flexible and reliable pipelines all help to make the natural gas system one of the most efficient energy systems in the U.S. We should build on this system by dashing to more direct use of natural gas in homes and businesses. Gas should be a building block of a secure energy future for America—not a bridge.

—Bert Kalisch ([email protected]) is president and CEO of the American Public Gas Association in Washington, D.C.

The dash to gas has also led to concern that the infrastructure will not be adequate to handle the increasing demand.

16_PWR_040110_Commentary.indd 72 3/16/10 6:28:13 PM



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