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BUSINESS AND TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRY
May 20
08 • Vo
l. 152 • No
. 5
Vol. 152 • No. 5 • May 2008www.powermag.com
Can wind power be a dispatchable resource?
Options for monitoring cation conductivity
Xcel moves on Smart Grid City plans
Riding the ocean power wave
PdM systems sweat the small stuff
©2008 Exxon Mobil Corporation. The Mobil logotype and the Pegasus design are trademarks of Exxon Mobil Corporation or one of its subsidiaries.
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We can take wind turbines to new heights.
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COVER STORY: RENEWABLES
20 Regulating wind power into a dispatchable resourceBuyers of renewable energy may soon be able to purchase the intermittent resource even when the wind’s not blowing. New California guidelines may allow a utility “banking” the RECs associated with wind power production to use those certificates to “buy” new, not necessarily renewable, energy when demand peaks.
SPECIAL REPORTS
MERCURY CONTROL
26 Future of national mercury rule now uncertainNow that a federal appeals court has ruled that mercury must be treated as a hazard-ous air pollutant, new coal-fired power projects may need to reevaluate their mercury control technology approach.
WATER TREATMENT
32 Cation conductivity monitoring: A reality checkMeasuring cation conductivity remains one of the most sensitive, simple, and reliable tools for detecting small amounts of contamination in feedwater and steam. To help understand why some operators find it difficult to interpret the readings, it’s impor-tant to know what cation conductivity is and what it is not.
FEATURES
PREDICTIVE MAINTENANCE
36 Making PM systems sweat the small stuffPreventable outages can cost millions. Being able to spot a sick piece of equipment—whatever its size—and fix or replace it before it degrades or fails is priceless.
TRANSMISSION
42 Boulder to be first “Smart Grid City”Much of the technology needed to modernize the electric transmission grid and to ra-tionalize supply and demand already exists. It’s deploying that technology on a large scale and assembling the pieces in a way that makes everyone happy that’s the trick. Xcel Energy is trying to pull it off.
RENEWABLES
48 A new wave: Ocean powerDecades of research and development have yielded several innovative ways of using oceans to produce electric power. Now, the tide finally may be turning on the ability of businesses and governments to make dreams of ocean power come true.
DEPARTMENTS
4 SPEAKING OF POWER
8 GLOBAL MONITOR 8 National Grid divested of
Ravenswood
8 GE to sell Baglan Bay plant
8 From prairie grass to power
9 Renewables experience 40% growth
9 The sustainable city
10 Solar recharger for developing countries
10 Seeking CCS solutions
10 Hoover Dam could stop generating
10 Japan turns to fossil fuel
11 U.S. reactors produce record power
11 POWER digest
13 FOCUS ON O&M Retail competition
18 LEGAL & REGULATORY
56 NEW PRODUCTS
64 COMMENTARY Smart Grid requires clearing mental
gridlockBy Mike Carlson, Xcel Energy’s execu-tive in charge of smart grid initiatives.
On the coverThe Windy Point Project in Klickitat County, Wash., aggregates the output of 130 wind turbines from Siemens Power Generation. Each turbine is rated at 2.3 MW and has a blade diameter of 93 meters (305 feet). Rated power is produced when the wind reaches about 30 mph. The project was developed by Cannon Power Corp. Photo courtesy: Windy Point Project
Established 1882 • Vol. 152 • No. 5 May 2008
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SPEAKING OF POWER
Guns and Moses
Charlton Heston’s legacy will surely rest on his iconic perfor-mance as Moses in The Ten Commandments and his unwaver-ing support of the Second Amendment. I had the privilege
of watching a classic Heston performance at the 2000 National Rifle Association convention in Charlotte, N.C., when he raised a handmade Brooks flintlock above his head and warned then-presidential candidate Al Gore that he could remove it only “from my cold, dead hands.”
Focusing only on these two images misses the real measure of the man. Heston walked a picket line in front of a whites-only restaurant in 1961 in Oklahoma City to repeal “Jim Crow” discriminatory laws; he marched with Dr. Martin Luther King, Jr. on Washington in 1963 to promote civil rights; and he served as a gunner on bombers during WWII. No one can deny that Heston was a man of strong principles who used his star power to focus the public’s attention on issues he considered vital to the nation.
What about the Fourth Amendment?Issues involving individual rights are still in the news, but many now concern technology’s impact on personal privacy. The most recent flap was over Google’s addition of 360-degree views to its online street maps, because some photos show in great detail property clearly marked private.
Privacy rights will also have to be considered by government programs designed to curb peak power consumption. For ex-ample, the advent of smart transmission and distribution grids (p. 42) does more than confirm that utilities are interested in adopting new technology. It also raises questions about how far beyond the home meter regulators should reach in the name of energy efficiency.
Advanced “smart” meters and computer-controlled appliances have the potential to better match demand to supply without human interaction (see p. 64). The key question is this: Whose finger should be adjusting the thermostat? Some state regulators began with what Contributing Editor Ken Maize calls the “nanny-
state approach to energy conservation: the utility knows best.” In my opinion, this license is a fundamental intrusion into our personal privacy rights that should be resisted. To paraphrase Heston, “You’ll have to pry my toasty warm fingers from my ther-mostat this winter.”
California yields to privacyAn early victory went to supporters of privacy this January when the California Energy Commission (CEC) retreated from plans to include programmable communicating thermostats (PCTs) in its proposed 2008 energy-efficiency standards for buildings. Had PCTs been left in, new buildings would have been required to have a data connection to let utilities control at least the air conditioning and heating system during power emergencies. In-dustrial and commercial users would have gotten a price break for selecting a rate plan that allows utilities to shed their load during grid emergencies. The CEC never entertained similar cost breaks for homeowners, at least in public.
The public outcry was predictable to everyone except CEC regu-lators who proposed the scheme. In response, the CEC blinked—twice. It first revised the rule to enable customers to override utility control of the PCTs, which were still required. Then, as the blowback continued, the CEC announced that it was removing PCTs from this year’s proposed building-efficiency standards. CEC spokeswoman Claudia Chandler quickly made the commission’s mea culpas, noting that in the future the commission will work with utilities to craft voluntary programs that customers could opt into.
I trust that the CEC and other regulators now understand the unwritten 11th Commandment of the utility industry: Tell me the time-based cost of energy and I’ll make the consumption deci-sions. It’s none of your business how much, when, and for what purpose I use the power I purchase. I think Charlton Heston would agree. ■
—Dr. Robert Peltier, PEEditor-in-Chief
Welcome our new editors!I’m pleased to announce that POWER has added two experienced members to our editorial staff as we continue expanding our in-depth coverage of the worldwide power generation industry.
Senior Editor Angela Neville has been covering the environmental issues of the energy and other industrial sectors since 1995. She served as the editorial director of the magazines Environmental Protection and Water & Wastewater News from 1995 through 2007. Angela’s columns on environmental law topics earned her one national award and four regional awards for editorial excel-
lence from the American Society of Business Publication Editors. She has bachelor’s degrees in both journalism and English and a
law degree from the University of Texas at Austin. Angela’s first contribution to POWER is an inside look at Xcel Energy’s plans to build the first smart grid in Boulder, Colo.
Staff Writer Sonal Patel will be work-ing on several aspects of print and online content delivery for POWER, COAL POWER, and POWERnews, as well as on a variety of other POWER-branded efforts. She has worked as a technical writer, as a free-lance news and feature writer for British Petroleum, and as the editor of an avant-garde South Asian women’s magazine/
webzine. Sonal jumped right into her new position with her article on ocean power in this issue.
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To learn more about how GE Energy’s quick, reliable and efficient solutions can help keep you ahead of the demand curve, visit www.ge.com/energy today.
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GLOBAL MONITORGLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR GLOBAL MONITOR
National Grid divested of Ravenswood London-based National Grid plc will sell Ravenswood Generating Station (Figure 1), a facility in Queens, N.Y., that provides more than 20% of New York City’s overall peak load, to TransCanada Corp. for $2.9 billion this summer. Ravenswood Generat-ing Station was a 2004 POWER Top Plant (July/August 2004, p. 32).
National Grid was obligated to divest itself of the 2,840-MW facility to fulfill a condition of the New York Public Ser-vice Commission (NYPSC) order approving the company’s $7.9 billion acquisition of KeySpan LLC, a New York utility, in August 2007. The gross asset value of Raven-swood in KeySpan’s last audited accounts was $1.2 billion at Dec. 31, 2006. The sta-tion reported an operating income of $138 million for 2006.
The Ravenswood acquisition by Trans-Canada is subject to regulatory approvals from the Federal Energy Regulatory Com-mission and the NYPSC, and to clearance
under U.S. anti-trust and foreign invest-ment laws. Approvals from these bodies are expected in the next few months.
In addition to Ravenswood’s vital supply, TransCanada will own, or have interests in, over 10,200 MW of power generation in Canada and the U.S. The company’s activities in the U.S. North-east include hydroelectric generation as-sets of 567 MW on the Connecticut and Deerfield Rivers in New England, and Ocean State Power, a 560-MW gas-fired combined-cycle power plant in Rhode Is-land. TransCanada is also currently vested in a proposed 132-MW wind energy proj-ect in western Maine.
The Ravenswood Generating Station, which began operating in 1963, is primar-ily fueled by natural gas. Its multiple units employ steam turbine, combined-cycle, and combustion turbine technology.
GE to sell Baglan Bay plantGE Energy’s mammoth Baglan Bay gas-fired station, near Port Talbot in South Wales, will also be up for sale by the end of the year (Figure 2).
GE Energy plans to put an estimated price tag of $986 million on the 500-MW plant so it can concentrate on plans to build and operate proposed nuclear sta-tions in Britain, according to the Western Mail, a Welsh publication. GE has not yet issued a public statement regarding the planned sale.
The Baglan Bay Power Station was rec-ognized as one of POWER’s Top Plants of 2003 for its first launch of GE’s 50-Hz Frame 9H system (see POWER, July/August 2003, p. 45). It was the first gas turbine combined-cycle system capable of break-ing the 60% fuel efficiency barrier. Hailed for increasing thermal efficiency by using steam from the bottoming cycle to cool the hot gas path parts without relying on
film cooling, the H system recently sur-passed 24,000 hours of service.
Since 2003, three 50-Hz systems gas turbines have been installed at the Futtsu Thermal Power Station in Japan. They are scheduled to enter commercial operation this year. GE has also installed its first 60-Hz version of the technology at the $500 million Inland Empire Energy Cen-ter in southern California. The two 107H combined-cycle systems are expected to produce a total of 775 MW when the plant comes on-line this summer.
From prairie grass to power Alliant Energy Corp. and Prairie Lands Bio-Products Inc. are jointly assessing ways to create a commercially viable mar-ket for switchgrass, corn stalks, and simi-lar agricultural products for use as fuel. The energy services provider expects that the products will constitute up to 10% of the fuel source for a proposed 630-MW hybrid plant in Marshalltown, Iowa, cutting substantially into coal burned at the facility.
Prairie Lands, a nonprofit organization whose 60 members are switchgrass grow-ers, is evaluating potential environmen-tal, economic, and agricultural benefits of switchgrass (a tall native North American grass used for hay and forage) and other such products. The organization is also identifying cost-effective and efficient methods to harvest, aggregate, process, and deliver alternative fuel stocks to the power plant.
The assessment will build upon success-ful switchgrass test-burn demonstrations conducted during the Chariton Valley Bio-mass Project, a 2006 venture funded by Alliant and the Department of Energy. That project investigated and demonstrated the technical feasibility, environmental ben-efits, and potential business viability of
1. Sold! Ownership of Ravenswood Gen-erating Station in Queens, N.Y., will pass from National Grid to TransCanada this summer. Courtesy: National Grid plc
2. For sale. The Baglan Bay station in-stalled the first GE 50-Hz Frame 9H system. Courtesy: General Electric Power Systems
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GLOBAL MONITOR
cultivating switchgrass to replace a portion of the coal fuel sup-ply at a similar Iowa plant.
According to Alliant’s web site, one of the greater benefits of burning switchgrass is improved air quality due to a natural process: The plant collects CO2 emissions during the growth pro-cess and sequesters the greenhouse gas in the ground through its roots.
Alliant supposes that a commercial project of 35 MW would require as much as 200,000 tons of biomass from 50,000 acres and that it would involve as many as 500 farmers.
The proposed plant, Sutherland Generating Station Unit 4, is expected to be operational by 2013. Alliant is considering incor-porating an additional 19-MW equivalent of steam cogeneration in the project for use by nearby industries.
Renewables experience 40% growthClean energy powers on—and is projected to escalate exponen-tially—in spite of a sluggish economy. According to a new report from Clean Edge Inc., revenues for the renewables industry surged 40% in 2007, with returns for solar photovoltaics, biofuels, and wind surpassing the $20 billion mark for the first time.
Global revenues for solar photovoltaic products, wind power, biofuels, and fuel cells collectively shot up from $55 billion in 2006 to $77.3 billion in 2007. Of the four energy markets, wind power (new installation capital costs) earned the highest rev-enue—$30.1 billion, while the fuel cell and distributed hydrogen market, the lowest—but newest—of the four, saw returns of $1.5 billion. In 2007, $25.4 billion worth of biofuels were produced: 13 billion gallons of ethanol and 2 billon gallons of biodiesel. Solar photovoltaics, including modules, system components, and installation, totaled $20.3 billion last year, and worldwide sys-tem installations stopped just shy of 3,000 MW.
The Clean Energy Trends 2008 report projected that growth for the four sectors will more than triple over the next decade, to $254.5 billion by 2017. Global installed solar photovoltaic ca-pacity is expected to increase eightfold to 22,760 MW, and wind power capacity is expected to reach to 75,781 MW (Figure 3).
The largest growth rate is expected in the nascent fuel cell and distributed hydrogen market, which is projected to increase tenfold to $16 billion. Comparatively, the rate of growth for solar photovoltaic, wind, and biofuels is projected to slow to 13.8% annually from the 50% average sustained over the past four years.
This year, the renewables industry will see continued growth, however, with five trends contributing to it: the growing partici-pation of overseas companies in the U.S. wind power market, a renaissance for geothermal energy, the launch of electric vehicles
by small start-up companies (as opposed to large automakers), the use of clean technologies for ocean-faring ships, and the design and construction of new sustainable cities.
The sustainable cityRealization of a zero-carbon, zero-waste, and car-free city may seem futuristic—but it has already begun. In February 2008, the government of Abu Dhabi in the United Arab Emirates broke ground on Masdar City. The 2.3-square-mile district on Abu Dha-bi’s outskirts (Figure 4)—which the Abu Dhabi government hopes
$0 $25 $50 $75 $100 $125 $150 $175 $200 $225 $250
Biofuels
Windpower
Solarpower
Fuelcells
Total $254.5
$81.1$25.4
$83.4$30.1
$20.3$74
$16$1.5
$77.3
2007 2017
$US (billions)
3. Global green energy growth. Clean Edge Inc. projects considerable revenue growth for renewables over the next 10 years. Courtesy: Clean Edge Inc.
4. Zero-carbon city rising. An aerial view of Masdar City in the United Arab Emirates. Courtesy: Foster & Partners
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GLOBAL MONITOR
will someday be occupied by 1,500 busi-nesses and 50,000 residents—is entirely designed for sustainable living.
Skylights and breezeways are incorpo-rated into architectural designs, and the city aims to utilize only power from re-newable sources. In addition to zero emis-sions, the city will rely on sustainable materials, food, and water. It will also house the Masdar Institute of Science and Technology, a graduate university dedi-cated to renewable energy. The $22 billion project will be built in seven phases and is expected to be completed and fully func-tioning by 2015.
Solar recharger for developing countriesBecause they live in developing or emerg-ing countries that cannot or do not set up a permanent power supply network, an estimated 1.6 billion people around the world still rely on traditional oil lamps to perform nightly tasks.
Around Lake Victoria in Kenya, about 30 million people stave off darkness by burn-ing kerosene lamps. Not only is it harmful to their health, according to Siemens sub-sidiary and lighting manufacturer, OSRAM, burning kerosene for light emits 67 tons of CO2 each year in Africa—almost equal to Finland’s annual CO2 emissions. Globally, the figure swells to 190 million tons.
To alleviate this problem, OSRAM constructed an off-grid kiosk-like solar station called an “Energy Hub” (Figure 5). The project was piloted in Mbita, a small town on the banks of Lake Victoria, which is easily accessible by locals who need to charge electrical appliances such as rechargeable lamps and cell phones inexpensively. The project’s success has prompted OSRAM to open three more En-ergy Hubs in the region.
Seeking CCS solutionsOn a larger scale, the North American coal-fired generating industry has been scram-bling for economically viable ways to retrofit existing infrastructure with carbon capture and sequestration (CCS) solutions. Power producer TransAlta Corp. recently announced it will partner with technology developer Alstom on a project to develop an extensive CCS facility in Alberta, Can-ada. The company anticipates a reduction of CO2 emissions from its coal-fired plants of 1 million tons per year.
Calgary-based TransAlta plans to pilot Alstom’s proprietary chilled ammonia pro-cess by 2012 at one of its coal-fired gen-erating stations west of Edmonton. The first phase of the five-year project will begin this year. It aims to advance and improve understanding of CO2 capture and storage technology. The overall project is expected to cost $12 million.
TransAlta has also partnered with ex-perts at the Institute for Sustainable En-ergy, Environment and Economy, part of the University of Calgary, to quantify CO2 sequestration potential in the Wabamun area west of Edmonton. The results, due in January 2009, will provide a scientific as-sessment of potential sequestration sites in the area surrounding several power plants, including their capacity and security.
Alstom has signed contracts with sev-eral U.S. and European companies to test its CCS technologies. The first pilot proj-ect that uses chilled ammonia to capture CO2 from coal-fueled power plants was launched in late February this year at We Energies’ 1,224-MW Pleasant Prairie Power Plant in Wisconsin (see POWER, February 2008, p. 38 for a technical description of the pilot process). The year-long demon-stration project is a joint effort with the Electric Power Research Institute (EPRI) and We Energies. EPRI will conduct an en-gineering and environmental performance and cost analysis during the project. Al-stom said that more than 20 organizations representing coal-fueled utilities in the U.S. are committed to project.
Hoover Dam could stop generatingA new study concludes that within a de-cade, growing water demand in the West and reduced runoff due to drought may deplete waters feeding the 2,080-MW Hoover Dam, a facility that generates power for more than a million people in Arizona, Nevada, and Southern California (Figure 6).
Researchers at the Scripps Institution of Oceanography found that these fac-
tors are causing a net deficit of nearly one million acre-feet of water per year in the Colorado River system, which includes Lake Powell and Lake Mead. The study es-timates a 50% chance that Lake Mead, already operating at a deficit, could drop too low for power production. Addition-ally, the Scripps researchers predict that there is a 50% chance that by 2021, Lake Mead could run dry if water demand is not curbed and climate changes continue as expected.
Japan turns to fossil fuelsSince Asia’s largest utility, Tokyo Electric Power Co. (TEPCO), shut down its Kashi-wazaki-Kariwa nuclear power plant (Figure 7) following a major earthquake last July, Japan’s nuclear-generated output has plummeted—and will stay low. Reuters reported that TEPCO’s nuclear output was 79.2% lower this February than last year, and the Hokuriku Electric Power Co. an-nounced recently that it expects to keep its sole nuclear plant closed for the busi-ness year ending in March 2008.
So to meet swelling demand, the country that once derived 30% of its power needs from nuclear generation has offset that de-cline with fossil-fueled generation.
Japan’s 10 main utilities have gener-ated record-high amounts of electricity for seven months straight compared with last year. Thermal generation was up 37.6% from February 2007, and last month, a Re-uter’s survey found that the country’s 10 utilities will rely on 141 million barrels of oil in the business year starting April 1—a 50% increase from the volume purchased two years ago.
The Kashiwazaki-Kariwa plant has the fourth-largest generation capacity in the world, its seven reactors producing 8,212 MW collectively. Before its shutdown, the plant supplied 6% of Japan’s total power needs.
5. Power station. This solar-powered “Energy Hub” will allow Kenyans near Lake Victoria to recharge small electrical appliances and reduce their dependence on kerosene. Courtesy: OSRAM
6. Dry dam ahead? Drought and in-creased demand could be threatening Hoover Dam’s ability to produce hydro power. Source: U.S. Bureau of Reclamation
May 2008 | POWER www.powermag.com 11
GLOBAL MONITOR
The plant was shut down after the July 16, 2007, offshore earthquake (whose epicenter was only 11 miles away) caused a fire within and destroyed a transformer building. The Japanese trade ministry or-dered plant operations halted indefinitely for ongoing safety checks.
U.S. reactors produce record powerThe Japanese earthquake, combined with aging facilities in the UK and unplanned outages in Germany, caused a general slump in global nuclear generation in 2007 of 3.6%, from 2.8 billion MWh in 2006, according to Nucleonics Week.
U.S. reactors, on the other hand, set a record for output, surging to 843 mil-lion MWh and utilizing an average 91% of reactor capacity. National total nu-clear generation was 2.4% higher than in 2006 and 2.3% higher than in the previous record year, 2004. Though the total number of operating U.S. com-mercial reactors (104) remained below 1990 levels, generation was 40% higher
than the 577 billion kWh produced in that year.
The South Texas Project’s South Tex-as-1 in Bay City, Texas (Figure 8) gen-erated the largest output of any reactor in the world—12.36 MWh. Constellation Energy’s Calvert Cliffs-1 in Maryland per-formed the best against promised output levels, exceeding capacity level all year.
Seven units closed down in 2007: Bulgaria’s Kozloduy-3 and -4, Slovakia’s Bohunice-1, and the UK’s Dungeness A-1 and -2 and Sizewell A-1 and -2; only four reactors were added: India’s 220-MW Kaiga-3 , China’s 1,000-MW Tianwan-2 VVER, and Romania’s 706-MW Cernavoda-2 Candu unit. The four reactors added 3,100 MW to the grid. The Tennessee Val-ley Authority also returned to service the 1,155-MW Browns Ferry Unit 1 after 22 years. (See POWER, November 2007, p. 30 for details on the restart of Unit 1.)
Last year also saw construction of the most nuclear power reactors in recent years. Five units were officially launched: the 650-MW Qinshan II-4 and the 1,000-MW Hongyanhe-1 in China, the 1,000-MW Shin Kori-2 and Shin Wolsong-1 in South Korea, and the 1,650-MW Flamanville-3 in France.
POWER digestNews items of interest to power industry professionals.
Siemens to build combined-cycle plant in Portugal. Siemens Energy is to build two turnkey combined-cycle units for ElecGas S.A. at Central Termoeléctri-ca do Pego in Abrantes, northeast of Lis-bon. ElecGas S.A. is a joint venture of the independent power generation company International Power plc and the Spanish utility Endesa S.A.
Following the units’ start-up, tenta-tively set for 2011, Siemens will also as-sume responsibility for maintenance of the power train for a period of 25 years. The order, including the long-term ser-vice agreement, is valued at about $947 million.
The natural gas–firing units have a tar-geted efficiency of over 58% and a com-bined installed capacity of 830 MW. The full turnkey scope of supply encompasses two gas turbines, two steam turbines, two generators, and all electrical plus in-strumentation and control equipment.
After Tapada do Outeiro and Ribatejo, which each comprise three units, Pego is the third power plant project handled by Siemens Energy in Portugal. The nation’s power demand is expected to increase by 3% annually up to 2010. The plants, with
a combined capacity of 3,000 MW, will generate enough electricity to meet ap-proximately 40% of Portugal’s demand.
RWE’s construction of twin-unit hard-coal power plant approved. The Arns-berg regional government has approved German utility RWE Power’s planned construction of a new 1,600-MW twin-unit hard coal power plant in Hamm.
The government found that the pro-posed plant’s estimated efficiency rate of 46% and “capture ready” capability was in accord with the German Federal Emission Control Act. The new hard-coal twin unit is anticipated to reduce CO2 emissions by 2.5 million tons annually compared to older plants with the same output.
RWE is already preparing the construc-tion site. The power plant’s first block will be put into service in mid-2011 and the second block in early 2012.
RWE will invest $3.16 million in the project. Twenty-three municipal utilities from four different German states are part-ners in the new plant. The utilities have formed a cooperative known as GEKKO (Gemeinschaftskraftwerk Steinkohle) that will hold a 350-MW share in the venture.
Nordic Windpower to manufacture wind turbines in Idaho. Nordic Wind-power Ltd., the maker of two-bladed utility-scale wind turbines, announced that it will site its new turbine-manufac-turing facility in Pocatello, Idaho.
The company plans to create more than 160 new technical, engineering, and administrative jobs at the new facil-ity. Additional positions will be opened at the company’s operational centers in California and the UK.
Volume production is expected to com-mence for turbine delivery in November 2008. Production is anticipated to grow to at least 20 turbines monthly by Sep-tember 2009.
Foster Wheeler wins CFB contract. Global Power Group, a subsidiary of Foster Wheeler Ltd., has been awarded a contract by Entergy Louisiana, LLC, a subsidiary of Entergy Corp., for the de-sign and supply of two circulating fluid-ized-bed (CFB) steam generators.
The two CFBs will be a part of the 538-MW Little Gypsy 3 Repowering Project in Montz, La. Unit 3 will have the capabil-ity of using petroleum coke, an abundant and inexpensive refining byproduct, as well as coal to produce electricity. Com-mercial operation of the plant is sched-uled for the first quarter of 2012.
SCE&G and Santee Cooper apply for COL. South Carolina Electric & Gas Co. (SCE&G) and Santee Cooper, a state-
8. Record holder. In 2007, South Texas-1 in Bay City, Texas had the largest output of any reactor in the world: 12.36 MWh. Source: Nuclear Regulatory Commission
7. No nuke. The post-earthquake shut-down of Japan’s Kashiwazaki-Kariwa plant is requiring a shift to fossil-fueled generation. Courtesy: Tokyo Electric Power
www.powermag.com POWER | May 200812
owned electric and water utility in South Carolina, have submitted an application to the Nuclear Regulatory Commission (NRC) for a combined construction and operat-ing license (COL). If approved, the license would authorize the companies to build and operate up to two new nuclear gener-ating units at their existing V.C. Summer Nuclear Station site in Jenkinsville, S.C.
The utilities have been developing their application since 2006. The NRC will now begin an approximately three-to-four-year review process. If the commis-sion issues an approval, likely in 2011, the utilities plan to begin construction shortly thereafter and anticipate an in-service date of as early as 2016 for the first unit.
SWEPCO Arkansas coal plant ap-proved. The Louisiana Public Ser-vice Commission (LPSC) has approved a Southwestern Electric Power Co. (SWEPCO) request to construct a 600-MW coal-fueled power plant in Hemp-stead County, southwest Arkansas. The plant will cost about $1.34 billon. SWEPCO will hold a 73% investment, owning 440 MW of capacity.
The plant will be the first of its type in the U.S to use “ultrasupercritical” ad-vanced coal combustion technology. It will feature low-sulfur coal and state-of-the-art emission control technologies, including a design that allows for the retrofit of carbon dioxide controls.
The LPSC’s approval requires that SWEPCO, a unit of American Electric Power (AEP), submit a study identifying the potential for implementing cost-ef-fective energy-efficiency and load man-agement programs for the company’s Louisiana customers.
The company is awaiting a ruling on an air permit, expected this summer, from the Arkansas Department of Environmen-tal Quality before construction can begin. Construction will take approximately 48 months; the operation date is set tenta-tively for late summer in 2012.
The company garnered approval from the Arkansas Public Service Commission in November last year. The commission subsequently declined a third-party re-quest for a rehearing in December. The intervenors have since appealed the case to the Arkansas Court of Appeals, where it is pending.
The baseload plant is part of SWEPCO’s previously announced plans to meet the region’s energy needs. The company has completed a 340-MW natural gas–fueled peaking plant at Tontitown in northwest Arkansas. The company also plans to
build a 500-MW combined-cycle natural gas–fueled plant at its existing Arsenal Hill Power Plant in Shreveport, La.
Go-ahead granted to Appalachian Power in West Virginia. Meanwhile, AEP’s operating unit, Appalachian Pow-er, has been authorized by the Public Service Commission of West Virginia to build a 629-MW integrated gasification combined-cycle (IGCC) electric gener-ating plant in West Virginia. The $2.23 billion plant, which will require approxi-mately 48 to 54 months to complete, will be located beside the company’s exist-ing Mountaineer Plant near New Haven, W.Va.
In addition to the West Virginia filing, Appalachian Power has filed with the Vir-ginia State Corporation Commission (SCC) for approval to recover the Virginia share of carrying costs associated with the plant. The company also filed for an envi-ronmental permit from the West Virginia Department of Environmental Protection. The Virginia SCC is expected to rule on the IGCC plant in April.
AEP announced in August 2004 that it intended to build approximately 1,200 MW of commercial-scale IGCC generation to meet baseload needs of the seven-state eastern portion area it serves. In addition to the Mountaineer IGCC unit, AEP had planned to build a similar 629-MW IGCC unit in Meigs County, Ohio. That project has been halted, following an Ohio Supreme Court decision in March.
AEP responds to Ohio Supreme Court IGCC decision. The Ohio Supreme Court unanimously ruled that $23.7 million of start-up costs for AEP’s Meigs County plant project charged to Ohio customers violated provisions of an electric choice law signed in 1999. The court said that construction of the plant falls into the generation portion of the company’s op-erations that the Ohio Legislature dereg-ulated under the law.
A Public Utilities Commission of Ohio (PUCO) ruling in April 2006 permitted two AEP subsidiaries to recover precon-struction costs between July 2006 and 2007 for the $2 billion plant in Meigs County. Those costs were for the first of three planned phases for the plant. The ruling sent the case back to the PUCO for reconsideration.
AEP reaffirmed its commitment to IGCC generation but indicated that the com-pany will wait for clarity about the future of electricity generation in Ohio before it determines if it can build the IGCC plant in that state. ■
—Compiled by Sonal Patel.
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May 2008 | POWER www.powermag.com 13
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FOCUS ON O&MTRENDS
Retail competitionThis “nuts and bolts” department doesn’t usually feature a conference report. But the one we’re including in this issue is about a unique conference: KEMA’s annual Executive Forum.
Change in the power generation in-dustry is occurring at an unprecedented rate. POWER’s mission is to keep you apprised of the trends driving those changes, and events like KEMA’s con-ference tend to shed light on the big picture. For plant operators, the impact of today’s trends will be on tomorrow’s plant O&M practices.
Finding KEMA. Some readers may ask, “Who is KEMA?” KEMA is a big Neth-erlands-based consulting firm that pro-vides technical and management services to the global energy industry. It was formed in 1927 as a testing laboratory, much like Underwriters Labs (UL) in the U.S. In fact, in Holland and many parts of Europe, there still exist appliances with a KEMA label certifying that they passed the company’s safety tests.
Later, KEMA started providing consult-ing services to European and Asian utili-ties. It opened shop in the U.S. during the 1970s. Today, with 700-plus consul-tants dedicated to the global power and natural gas industries, KEMA’s Retail En-ergy Markets advisory service is a lead-ing source of business intelligence and market analysis to the competitive retail energy industry.
KEMA’s 19th annual Executive Forum brought to Dallas about 300 energy exec-utives to discuss and debate the outlook for competitive retail electric markets. Currently, 20 states and the District of Columbia allow customer choice to some degree (Figure 1).
According to Kristie Deiuliis, manager of KEMA’s Retail Energy Markets service, last year about 10% of all electricity sold in the U.S. was consumed by cus-tomers who had switched to competitive providers. In 2006 the figure was 9%.
At first glance, retail choice would seem to have a small “market share.” But as Taff Tschamler, director of KEMA’s Re-tail Energy practice, underscored at the forum, that 10% represents more annual consumption than all UK consumption. Competitive retail electricity sales in the U.S. are also larger than sales in all
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1. Clusters of competition. Twenty states and the District of Columbia currently let customers choose their power provider. Source: KEMA
2. Choosing choice. Estimated retail competitive power sales, in terawatt-hours, from 2001 to 2007. Source: KEMA
3. Pent-up demand. These were the fastest-growing markets for competitive power last year. Source: KEMA
www.powermag.com POWER | May 200814
FOCUS ON O&M
of Africa. Internationally, the U.S. com-petitive market ranks eighth, behind In-dia’s and ahead of Brazil’s and France’s. America’s consumption of power bought on competitive markets has grown at an average annual rate of 20.8% since 2001 (Figure 2). The biggest percentage gains for competitive power during 2007 were in Connecticut and Illinois (Figure 3).
Without excluding other markets, the KEMA Executive Forum focused on the unique ERCOT market of Texas, where competition is exceptionally intense in all three sectors: industrial, commercial, and residential.
Most experts agree that customers within ERCOT have a greater choice of electricity providers than anywhere else in the U.S. The price for residential elec-tricity in ERCOT is actually lower today than it was in 2001. If you consider that inflation has devalued the dollar 22% since 2001 and that the price of natural gas has risen 90% over the past seven years (and that 69% of ERCOT’s generation capacity is gas-powered), proponents of competition can justifi-ably claim that their theory works in practice.
So why aren’t other states copying the Texas model? Two reasons:
■ A perception in many parts of the U.S. that “deregulation” is bad public pol-icy and that U.S. business in general needs to be more closely regulated.
■ Fear of “rate shock” when price caps are removed from a market that has been bottled up while fuel costs (gas, coal, and uranium) have escalated sharply.
Winners and losers. The forum’s keynote address—by Jim Burke, CEO of TXU Energy—focused on retail com-petition in ERCOT. In 2007, TXU Corp. was transformed from a publicly held company to a privately owned business with three discrete operations: Oncor, a regulated “wires and poles” (trans-mission and distribution) business; Lu-minant, responsible for operating and procuring generation capacity; and TXU Energy, a competitive retail electricity provider.
By the end of 2007, TXU had lost about 40% of the residential and small busi-ness customers that it had served prior to the arrival of competition in ERCOT in 2002. That’s a statistic that Burke wants to reverse. Without a doubt, the gloves have come off in the fight for customers in ERCOT.
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4. To know it is to love it. Awareness of and support for retail electricity competition are high in Texas. Will that support improve elsewhere? (The underlying survey was con-ducted in January 2008. It used random-digit telephone calls to contact households in these three areas. The sample size was 250 households per area.) Source: TXU Energy
5. Exercising their right. Since 2002, 80% of eligible Texans have opted for a different power provider or rate plan. Source: TXU Energy
6. No second thoughts. Most Texans are satisfied with their electricity provider. (The numbers come from a survey conducted in February 2008 that used random-digit telephone calls to contact households in all competitive areas of Texas. The sample size was 121 house-holds per area.) Source: TXU Energy
May 2008 | POWER www.powermag.com 15
FOCUS ON O&M
For confirmation, visit a web site run by the Public Utility Commission of Texas: www.powertochoose.org. In the prized regions of metro Houston and Dallas, no fewer than 27 retail providers are slug-ging it out for residential customers. A customer can choose fixed rates for one or two years forward, rates that fluctu-ate monthly with changes in fuel prices, electricity that is sourced only from renewable generation, and rates that include frequent-flyer program airline miles credits. According to a TXU survey (Figure 4), 90% of residential custom-ers in ERCOT are aware of their ability to choose their electricity provider and more than 80% support choice.
Retail choice at the residential level in Texas has been phased in since 2002. On January 1, 2007, Texas electric com-panies in deregulated regions were re-leased from the last part of government regulation involving the “price-to-beat.” All electricity prices now are determined by supply and demand. Since the resi-dential power market was opened to competition in Texas, more than 80% of customers have either changed their rate plan or provider at least once since being offered choice (Figure 5), and 77% are very satisfied with their current provider (Figure 6).
The consensus of several speakers in plenary sessions was that:
■ Customers are smart.■ Customers will pay for value.■ Customers want to be able to fire their
electric company and hire a new one.
Love the price, hate the company.However, while calling customers smart and cost- and quality-conscious, several speakers also said customers are often hard to understand.
For example, considering the rev-elation from TXU’s survey that Texas ratepayers are happy to have electric-ity competition, another survey by Fox News in Austin produced a surprising result. One of the questions it asked residential customers was, “Do you favor re-regulating utility companies?” More than half of respondents (54%) said yes, 25% said no, and 21% were unsure. Ex-plaining this paradox may get down to focusing on the words. Consumers seem to want competition and choice, but they are far less keen on deregulation, at least as a concept.
One thing is sure about customers: Few know that most retail electricity providers are operating with gross mar-
gins of just 5% to 10% for residential customers and even less for commercial accounts. But even though the two big incumbents (TXU and Reliant) continue to lose market share, no new entrant has found the secret recipe for becoming the Southwest Airlines of the Texas retail electric market.
However, there may be an 800-pound gorilla on the horizon: Wal-Mart. Texas Retail Energy, LLC, a wholly owned sub-sidiary of Wal-Mart, currently provides
electricity to all of the company’s stores in ERCOT with the option to choose their provider. Wal-Mart is essentially acting as an aggregator for its own stores and is not currently offering electricity to any other customers. The audience roared with laughter when the moderator of a panel discussion ended his introduction of a Wal-Mart representative with the fol-lowing request, “Please don’t ask Chris Hendrix the question that you all want to ask.”
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FOCUS ON O&M
Cause and effect? In one forum session, Jim Ajello, a senior VP at Reliant, drew an interesting analogy between the deregulation of U.S. air-lines and the utilization of industrial capacity. Since deregulation, the air-lines have greatly improved their as-sets’ overall capacity utilization rate. Compared with airlines, refineries, and companies in other major industries,
utilities are much less efficient in this regard (Figure 7).
Can we expect that competition will make utilities more efficient users of their generation fleets? With or without competition, adoption of plug-in hybrid vehicles will surely boost off-peak sales as customers recharge their cars over-night. The real question is, How long will it take for a meaningful percentage
of America’s automobile fleet to become hybrid or pure electric? Projections of 20% by 2020 do not seem out of the question.
But let’s circle back to Texas. Not all Texans have the freedom to choose their electricity provider. The geographic re-gions of Texas outside of ERCOT are still regulated. In addition, within ERCOT there are 77 municipally owned power companies and another 76 electricity cooperatives. Nueces Electric Coopera-tive Inc., which serves the Victoria-Cor-pus Christi region, is the only publicly owned power company in ERCOT to offer retail choice. Nueces not only lets its incumbent customers choose their pro-vider, it also has set up a retail division to sell power to customers anywhere in ERCOT.
Co-ops and competition. POWER discussed several aspects of retail power sales and customer choice with Sarah Fisher, communications manager for Nueces Electric Co-op (NEC):
POWER: A year ago, the incumbent Nueces territory had nine competitive retail electric providers for commercial and indus-trial customers and two representatives for
Capa
city
util
izatio
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100
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0Airlines (pre/post
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44%
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Product is storable No/limited product storage
Post-regulationimprovement
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7. Using their assets. Here are the average capacity utilization rates of various indus-tries, 1997–2006 (the rate for power is for 2007). Source: Reliant Energy
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residential customers. How many competi-tors do have on your home turf today?
Fisher: Twelve altogether, although only two, Texas Power and NEC’s Retail Division, are actively seeking residential consumers.
POWER: A year ago, Nueces had not lost many customers to competitors: only nine households and 113 small commer-cial accounts. What are these numbers today? What are your industrial, com-mercial, and residential meters’ market shares on your home turf?
Fisher: Sixty-six residential users (of 14,695 active residential services) and 155 small commercial users (of 2,109 active small commercial accounts) have chosen a non-incumbent provider.
POWER: Your retail division had 11,651 customers outside of Nueces service ter-ritory one year ago. What is your retail customer count today?
Fisher: Nueces Retail Division now serves 16,109 active services custom-ers outside its traditional distribution territory.
POWER: Does Nueces own any genera-tion assets? If you do, has their utili-zation rate increased during the last
year, and do you attribute any of this increase to the expansion of your retail division?
Fisher: Nueces does not own genera-tion assets but is a member of South Texas Electric Cooperative [STEC], head-quartered in Nursery. So indirectly, Nuec-es has increased the utilization rate of STEC’s generation assets.
POWER: I heard that Nueces has ex-panded its coverage to all competitive choice regions within ERCOT. Is that true? Are there any regions in ERCOT open to customer choice that Nueces does not serve?
Fisher: NEC Retail has applied to ERCOT to serve customers in every competitive market in Texas. Presently, it actively mar-kets its services only in the AEP Central and NEC distribution areas. They include the Rio Grande Valley, Corpus Christi, and Victoria markets.
POWER: Are the two decisions by Nueces—to allow customer choice in its incumbent region and to set up a retail division—regarded as successful by the company’s management and customers? For that matter, have you gathered customer satisfaction data to quantify “success”?
Fisher: NEC’s decision to offer retail choice has been a success in that we are able to offer an at-cost, customer-owned co-op provider option throughout the competitive areas of Texas. In ad-dition, customers in NEC’s distribution area now can choose from 12 providers. Unfortunately, ongoing compliance with [the rules of] ERCOT’s competitive retail market continues to increase our cost of doing business. We hope in time that there will be economies of scale that can lessen the impact of these additional costs on our members.
POWER: There are 77 munis and 76 co-ops in Texas. Why do you think that none of these entities has joined Nueces by of-fering choice to its customers?
Fisher: Electricity cooperatives gener-ally have the highest level of customer satisfaction of all utility types. If con-sumers are being taken care of, they may not necessarily demand “choice.” Electricity co-ops and munis also realize that it is expensive to make the transi-tion to competitive markets, as we’re ex-periencing to maintain compliance with ERCOT. ■
—Mark Axford, contributing editor
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LEGAL & REGULATORY
Steven F. Greenwald Jeffrey P. Gray
Until very recently, common wisdom held that the price of renewable energy would fall as legislative procurement mandates ensured its long-term demand. The resulting
growth in supply and sales would spur investment in the field, create economies of scale, and accelerate progress down the technology learning curve.
Something unexpected, however, happened along the way. Though more than half of U.S. states have adopted renewable portfolio standards (RPS) that require utilities to meet specific generation targets, and investment in green projects and tech-nology development has increased significantly, recent data suggest that the price of green electricity has risen and will continue to spiral upward. What happened?
The curse of the visible handThe economic Achilles heel of current state RPS programs is that they carve out a portion of the larger energy market and unbalance it by imposing legislatively determined demand. In the pre-RPS era, utilities aligned their resource planning with demand forecasts largely irrespective of generating technology. Procurement decisions were based primarily on need, price, and “fit” (dispatchability and “black start” capability). As a result, coal, gas-fired, nuclear, hydro, and renewable energy plants com-peted against each other for a piece of the utility demand pie. The overall market benefited from the increased competition, which—to some extent—also provided a hedge against raising fuel costs. For instance, if biomass prices rose, utilities could procure more gas-fired generation.
In stark contrast, the RPS regime mandates specific renewable procurement targets, generally a percentage of a utility’s over-all load. Legislatively imposed capacity targets—and penalties for failing to meet them—often obligate market participants to subordinate their own (and their customers’) economic interests to the desires of states. Utilities must purchase RPS-compli-ant power even if its price cannot otherwise be justified. The economic consequences for utilities seeking to be RPS-compli-ant include higher costs for facility sites, fuel, and generating equipment.
Moreover, although in theory there is competition among different renewable technologies, external forces (such as sit-ing and transmission constraints) effectively limit the avail-ability of resources that can meet a utility’s needs—as well as the benefits that competition can provide consumers. Leg-islative directives that artificially increase demand will also increase prices when supply cannot keep pace. The net result is a skewed market in which power produced from renewable resources commands a price premium just for being “green,” irrespective of the benefits of the project that generated it.
Upward price pressure on RPS-compliant power is further sus-tained by fast-approaching RPS compliance deadlines. In Cali-
fornia, for example, utilities are currently scrambling to procure significant amounts of renewable resources in order to meet the state’s 20% target by 2010. In such a market, rising prices should be no surprise: Prices rise when demand exceeds supply, regardless of the reasons for the imbalance.
In economic theory, competition enables markets to respond with an “invisible hand.” When the movements of a market are precipitated by government fiat, they are subject to a visible and very heavy hand.
Let’s get real Wind farms are feasible only where it’s windy, and photovol-taic arrays only where it’s sunny. Access to fuel similarly lim-its potential sites for geothermal and biomass projects. Though these geographic realities should be evident, overly ambitious RPS programs such as California’s suggest a failure by regulators to meaningfully assess whether regional renewable energy “re-serves” are sufficient to meet RPS-imposed demand.
The shortage of viable in-state resources has prompted utili-ties to look to neighboring states to meet RPS requirements. But extending the search for renewable power beyond state borders can have negative consequences for both the consuming state (higher prices resulting from increased transmission costs) and the producing state (the energy that could be delivered locally at the lowest price is exported).
The bottom line: Although governmental edicts to increase demand promise some short-term benefits, long-term gains won’t be possible unless RPS targets are based on a realistic as-sessment of available supply—not simply on au courant political correctness.
All is not lost . . . yetFostering the development and use of green generation is good policy that should be continued for several reasons. If imple-mented wisely, RPS programs can significantly benefit both con-sumers and the environment by reducing dependence on foreign oil, diversifying generation fuels, cutting greenhouse gas emis-sions, and ultimately by lowering the overall cost of power.
If they are ill-conceived, however, RPS programs create artifi-cial market demand that does not reflect real-world limitations on renewable project development. The net effects could be much higher electric bills and a likely public backlash. If policy makers do not carefully consider the possible downsides of their fervor to make power generation less of a contributor to global warming now—whatever the cost—history may remember RPS as yet another expensive “green” façade. ■
—Steven F. Greenwald ([email protected]) leads Davis Wright Tremaine’s Energy Practice Group.
Jeffrey P. Gray ([email protected]) is a partner in the firm’s Energy Practice Group.
Why RPS programs may raise renewable energy pricesBy Steven F. Greenwald and Jeffrey P. Gray
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RENEWABLES
Regulating wind power into a dispatchable resourcePerhaps the biggest shortcoming of wind power is its unreliability. Uncon-
cerned with human needs, Mother Nature has decided that the wind usually blows strongest at just the wrong times, when electricity demand is lowest. However, using savvy negotiations to exploit a new provision in California’s renewable energy regulatory regime could make wind power more dispatchable during peak-demand periods and increase the capacity of wind farms at the same time.
By Robert D. Castro, University of Southern California, and Fernando Pardo
“As California goes, so goes the na-
tion” is one way to describe how
the Golden State often sets trends
in pop culture and the larger culture. It also
applies to the likelihood that new provisions
in California’s scheme for regulating—and
promoting—the development of renewable
energy resources may be copied elsewhere.
Like many other states (Figure 1), Cali-
fornia has imposed renewable portfolio stan-
dards (RPS) on its utilities to force them to
become “greener.” Renewable electricity
typically has two components: the power it-
self, measured in kilowatt-hours, and renew-
able energy credits (RECs), also known as
green tags or tickets. One REC is earned for
every MWh generated by a renewable energy
plant. If a utility generates more than enough
green power to meet its annual RPS require-
ment, it can sell its excess RECs on the open
market at their going price. If it can’t (or
doesn’t choose to) meet the mandate with its
own production, the utility has to buy RECs
earned by others. RECs represent the envi-
ronmental benefits of generating power from
renewable resources, as opposed to produc-
ing electricity by burning nonrenewable re-
sources such as fossil fuels.
Two camps have different views of the
best way to use RECs to meet environmen-
tal and resource planning goals. The more
conservative camp believes that regulatory
regimes should never allow RECs to be sold
separately from the energy that generated
them because such separation gives utilities
that purchase RECs to meet their RPS a “li-
cense to pollute.” The other camp—the REC
trading camp—feels that renewable energy
development will benefit more if RECs and
1. Crazy quilt. As of March 2008, 29 states and the District of Columbia had enacted some form of renewable portfolio standard. Each percentage represents the minimum share of a utility’s capacity powered by renewable resources. The utility may own that capacity or pur-chase it, and associated renewable energy certificates, from independent power producers. Source: DOE’s Database of State Incentives for Renewables & Efficiency
MN: 25% by 2025(Xcel: 30% by 2020)
ND: 10% by 2015MT: 15% by 2015
*WA: 15% by 2020
OR: 25% by 2025 (large utilities)5%–10% by 2025 (smaller utilities)
*NV: 20% by 2015
CA: 20% by 2010
AZ: 15% by 2025
NM: 20% by 2020 (IOUs)10% by 2020 (co-ops)
HI: 20% by 2020
CO: 20% by 2020 (IOUs)*10% by 2020 (co-ops and large munis)
TX: 5,880 MW by 2015
IA: 105 MW
IL: 25% by 2025
MO: 11% by 2020
NC: 12.5% by 2021 (IOUs)10% by 2018 (co-ops and munis)
WI: requirement varies by utility; 10% by 2015 goal
ME: 30% by 200010% by 2017—new RE
NH: 23.8% in 2025MA: 4% by 2009+1% annual increase
RI: 16% by 2020CT: 23% by 2020
NY: 24% by 2013
NJ: 22.5% by 2021PA: 18%1 by 2020
MD: 9.5% in 2022
*DE: 20% by 2019DC: 11% by 2022
*VA: 12% by 2022
State RPS
State goalSolar water heating eligible
Minimum solar or customer-sited RE requirement
*Increased credit for solar or customer-site RE1PA: 8% Tier I/10% Tier II (includes non-renewables)
VT: RE meets loadgrowth by 2012
May 2008 | POWER www.powermag.com 21
RENEWABLES
their associated energy are allowed to be
sold separately. The REC trading camp con-
tinues to gain adherents as transmission re-
sources are unable to keep pace with growth
in renewable generation.
Firming and banking wind powerOne of the services available to both camps
is the ability to “firm” wind energy. Utilities
that generate lots of wind power frequently
offer buyers the option of smoothing out the
delivered product by averaging its capac-
ity on an hourly basis. A typical example is
“hour-ahead firm” energy; if weather and
wind forecasts indicate that a wind farm will
generate 25 MW over the next hour, the util-
ity guarantees that 25 MW will be delivered
from its generation portfolio during that
hour, regardless of the wind farm’s actual
generation. Given wind’s inherent variabil-
ity, which can cause operational and stabil-
ity headaches, paying an extra $15/MWh for
firm energy is attractive to some buyers.
A further service that may soon be offered
to utility purchasers is the ability to “bank”
wind energy. This concept envisions a utility
storing the RECs associated with wind power
production until a more advantageous time for
the recipient, and then releasing them for sale
along with new, not necessarily renewable,
energy. Although this scheme would only
work for those in the REC trading camp, it
does provide a big benefit: delivery of “wind
power” during peak-demand periods.
The impetus for this banking service is
found in the newest (third) edition of the
California Energy Commission’s Renew-ables Portfolio Standard (RPS) Eligibility Guidebook (download from www.energy.
ca.gov/renewables/documents/index.html).
In Section D of Part II, the guidebook states
that “Electricity may be delivered into
California at a different time than when the
RPS-certified facility generated electricity.
. . . Further, the electricity delivered into
Heavy lift. The Judith Gap Energy Center is a 135-MW wind farm located in central Montana, about 100 miles east of Helena. The project uses 90 GE wind turbines rated at 1.5 MW each. Courtesy: Invenergy
Top billing. Power generated by the Judith Gap Energy Center is sold to North-Western Energy under a 20-year power purchase agreement. The project began commercial operation in December 2005. Courtesy: Invenergy
Site to behold. Windy Point Project is near Goldendale, Wash., on about 25 miles of ridgeline property overlooking the Colum-bia River on the Washington-Oregon border. Courtesy: Cannon Power Corp.
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www.powermag.com POWER | May 200822
RENEWABLES
California may be generated at a different
site than that of the RPS generated facility
. . . out-of-state energy may be “firmed” or
“shaped” within the calendar year.”
This language allows those in the REC
trading camp to bank the renewable energy
for delivery at some later time, and other
sites to provide the energy that is ultimately
delivered to the receiving utility. Presum-
ably, these sites can deliver nonrenewable
energy (“brown energy”), but it will be con-
sidered “green” as long as the RECs created
by the renewable power production are cred-
ited exclusively to the delivered energy.
Take it to the bankThe ability to bank wind energy has mul-
tiple and far-reaching implications. Opera-
tionally, the major effect is to set a value
on wind power capacity. One of the major
shortfalls of using wind as a source of elec-
tricity is that wholesale-market dispatchers
cannot rely on wind capacity being avail-
able to meet load (see “Loss of wind forces
Texas to brink of blackout”).
Wind is typically assigned a capacity val-
ue of about 10% of total installed wind farm
capacity. That is, for every 100 MW of wind
turbines installed, the utility’s energy control
center typically expects about 10% to be on-
line at any given time. Some utilities do not
assign any capacity value to wind; they use
spinning reserve or fast-start generation to
compensate for any shortfalls. For example,
in Texas, ERCOT purchases these as “ancil-
lary services.” Others use wind power to store
energy for later use as on-peak capacity, for
example by pumping water into a storage fa-
cility and then dispatching the hydroelectric
energy during peak-demand periods.
Economically, the benefits of banking
wind energy are enormous. Wind is capri-
cious, but in most places it is stronger, and
therefore capable of producing more power,
at night, an off-peak time. Its value to a util-
ity ranges from $15/MWh to $50/MWh.
But in California, where wind speeds are
higher than average, the typical wind energy
price of over $70/MWh often causes nega-
tive cash flow for a utility. Even account-
ing for the value of RECs (whose prices are
estimated to climb as high as $30/MWh), a
50% loss per MWh would not be atypical.
To compare the economics of banked
energy versus unbanked wind energy, let’s
see what firming wind energy would cost.
Currently, the market is charging about
$20/MWh to bank wind energy. So, if we
purchase the wind energy for $75/MWh and
then add $15/MWh to firm it and $20/MWh
to bank it, we’re looking at $110/MWh as the
total cost of wind energy. However, banked
wind energy is more like solar power in that
it is renewable energy that can be received
on-peak. In fact, banked wind energy’s dis-
patchability makes it more valuable than so-
lar because its capacity is much firmer.
Banked wind energy can be used on-peak;
during the hottest summer days, it is worth
$80/MWh to $300/MWh. Even taking into
account the $30/MWh cost of a REC, buy-
ing wind at $110/MWh would be beneficial
to most utility bottom lines.
Contractually, the acquisition of wind en-
ergy will change drastically due to the bene-
Loss of wind pushes Texas to brink of blackoutThe Electric Reliability Council of Texas (ERCOT) narrowly missed a blackout on February 26 by activating the second stage of its emergency electric curtailment plant (EECP) and curtailing indus-trial loads to compensate for a steep drop in wind power capacity and a drop in frequency on the ERCOT grid just as the evening demand was increasing.
According to an ERCOT press release issued the following day, wind production dropped more than 1,700 MW in the middle of the afternoon of February 26 to 300 MW by early evening, when ERCOT activated its demand response procedures. Within 10 min-utes, industrial customers shed 1,100 MW of load, helping ERCOT avoid having to shed more load or to initiate rolling blackouts to avoid a broad system failure. Most of the interruptible loads were restored after roughly 90 minutes.
“Preliminary reports indicate the frequency decline was caused by a combination of events, including a drop in wind energy production at the same time the evening electricity load was in-creasing, accompanied by multiple power providers falling below their scheduled energy production,” the statement said.
Bad timingA 2007 study of the ERCOT system by General Electric concluded that the daily behavior of wind is “anti-correlated” with load, meaning that wind drops off sharply as the morning load builds, and builds up strongly as the nighttime load falls. This effect is most pronounced in late spring and summer, the study said.
The GE analysis, which relied on ERCOT data, also concluded that adding wind generation to the Texas grid increases the need to boost the percentage of overall power plant capacity set aside to provide ancillary services, which ensure that voltage levels and other reliability factors are maintained at optimal levels.
The report, which modeled scenarios assuming differing levels
of installed wind capacity, found that if Texas were to install 15,000 MW of wind capacity, more than 75% of it would be avail-able for use only 10% of the year.
“It’s obvious around here that the wind blows when we don’t need it as much, and that at peak times it’s not something we can rely on,” said ERCOT spokeswoman Dottie Roark the day after the grid emergency. “Wind works best in conjunction with other generation.”
Transmission troubleERCOT reported in January that wind provided only 2.9% of the 307 million MWh the state consumed in 2007. Wind’s share of the total Texas energy mix continues to climb, however. In 2006, wind met 2.1% of demand, while in 2005 wind energy amounted to 1.4% of the total MWh consumed in the state.
Texas, the nation’s wind generation leader, currently has 4,300 MW of installed wind capacity; projects totaling an additional 3,400 MW in capacity have signed contracts with prospective transmission providers. However, the state has only 5,000 MW of transmission capacity available to bring wind energy from west Texas—where virtually all of the wind capacity is located—to load centers in the eastern part of the state.
“Our biggest issue with wind is transmission congestion,” Roark said. “Obviously, we already have more installed capacity available than transmission capacity, and we have more than 40,000 MW of proposed wind projects in the queue.”
Though no one in ERCOT expects all of the 40,000 MW will be built, Texas clearly has a pressing need to build transmission to meet the growing demand for power in the state.
—By Chris Holly ([email protected]), a reporter with POWER’s sister publication,
The Energy Daily (www.theenergydaily.com).
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RENEWABLES
fits of banking. Some utilities, like Southern
California Edison (SCE), are willing to pay
a premium for power delivered on-peak but
much less for off-peak energy. For example,
if SCE secures a wind deal for $100/MWh,
the utility’s pro forma contract structures
payments so they average $100/MWh over
the year but are $328/MWh during the sum-
mer peak and $65/MWh during off-peak
periods and winter months. The acceptance
of energy banking by state energy regulators
will enable contracts to be restructured to
eliminate premium payments.
Connect the plantsBecause they are powered by an intermittent
resource, wind farms have an average capac-
ity factor that rarely exceeds 40%. This has
three negative and related consequences:
■ Much of the transmission capacity built
to deliver wind power to grids is under-
utilized.
■ Transmission must be overbuilt to de-
liver wind-generated electricity.
■ The cost of transmitting wind power is
two to three times that of transmitting the
production of conventional power plants.
However, if the wind energy is banked,
it can be transmitted as a firm resource, al-
lowing all of its transmission capacity to be
leveraged. Assuming a $7/MWh cost for
transmission and the usual wind power ca-
pacity factor of 33%, banking wind energy
and transmitting it later (raising the capacity
factor to 100%) would produce a potential
transmission savings of $14/MWh.
However, banking wind energy does pose
some challenges to transmitting it. Wind
farms are usually sited in remote areas where
the wind is strongest, so hundreds of miles
of transmission lines are typically needed
to bring their output to load centers. While
firm transmission is an increasingly scarce
commodity, transmitting wind energy in real
time has been less problematic because wind
speeds are usually higher during off-peak pe-
riods. At those times, transmission capacity
is readily available, although mostly as non-
firm, day-ahead scheduling. Banking wind
energy for on-peak consumption requires that
on-peak transmission be available to move it
to load centers. Since on-peak transmission is
harder to come by, other steps must be taken.
Members of the REC trading camp would
suggest that a utility do the following: Buy
the wind energy at one location, spin off its
RECs, and sell the wind energy as “brown
energy” locally. The utility can then combine
the RECs with brown energy at a second lo-
cation that has better transmission access.
Many in the camp believe that this legisla-
tive “sleight of hand” can help address the
need for green energy by making the short-
age of on-peak transmission moot. State
regulators may impose some restrictions on
how the trick is accomplished. For example,
the California Energy Commission’s guide-
book stipulates that the control area opera-
tor doing the firming and banking must be
part of the Western Electricity Coordinating
Council (WECC).
Guaranteeing generationOne of the obstacles preventing wind plants
from becoming a first-rate electricity re-
source is the inability of wind farm own-
ers and developers to accurately predict
and guarantee wind energy delivery. Wind
energy resource assessments typically use
several years’ worth of wind data. These
assessments typically develop estimates of
long-term mean wind speeds based on on-
site anemometer data or on reference an-
emometer data from a nearby location.
Once estimates of wind speeds have been
made, they can be used to create power curves
that estimate the electrical energy that wind
turbines would produce at each speed. The
resulting forecast, based on both estimates, is
a probability-based energy production level
for a wind farm. For example, “P99 energy”
is the term used for the annual amount of en-
ergy predicted to be available at a point of
delivery with a probability of 99% or greater.
“P50 energy” describes the (larger) amount
of annual energy expected to be available at
a probability of 50% or more.
Since P99 energy has a 99% probability
of meeting the expected energy production
level each year, it typically becomes the
“annual guaranteed energy” expected of a
particular wind farm. Accordingly, a wind
farm’s P99 level is calculated and certified
by an industry wind assessment expert. Per-
formance damages are sometimes sought if
the plant fails to deliver the guaranteed gen-
eration. Sometimes, a “failure to perform”
clause in a contract is triggered at a certain
percentage of the P50 level or of another P
level. It all depends on the negotiations be-
tween the utility customer and the owner of
the wind farm.
Probability-based energy production lev-
els also affect the building of wind farms
because, as part of their financing, the level
of expected revenues is based on substanti-
ated generation numbers. If a wind farm’s
guaranteed generation is from P99 wind,
any revenues from additional sales of wind
power with a lower P level are not used to-
ward capital recovery or to meet investors’
return on investment targets. For this reason,
the price of wind power at other P levels is
usually substantially less than that of P99
wind. Since the only real costs incurred
by the seller are incremental operation and
maintenance costs, the prices paid for wind
energy at levels other than P99 are typically
60% of that paid for P99 wind.
This bracketing combination of minimum
annual energy guarantees and lower prices
for non-P99 wind encourages wind farm de-
velopers to accurately present the generating
capability of their plants. If the guaranteed
generation is set too low, then more energy
would be sold at the discounted rate each
year. Conversely, if the guarantee is set too
high, performance obligations might not al-
ways be met and could possibly result in the
assessment of costly damage payments.
In planning their renewable resource
portfolios, utilities typically choose suppli-
ers willing to guarantee wind energy gen-
eration with low levels of uncertainty. The
ability of wind farm developers to offer and
meet an annual level of guaranteed genera-
tion is a significant milestone for an industry
on the cusp of maturity.
Guaranteeing availabilityAs wind power becomes more important
to more utility resource portfolios, so does
the availability of wind farms. Some utili-
ties address the issue by specifying in their
contracts with wind farms a target mechani-
cal availability for the project, such as 98%
for smaller wind turbines or 95% for the
megawatt-size turbines. This, along with an-
nual generation guarantees, enables them to
more effectively establish the reliability of
wind power resources. The two guarantees
work hand-in-glove, because it is conceiv-
able that a wind farm could meet its annual
guaranteed generation level with poorly
performing wind turbines. Typically, guar-
anteed generation is an annual target, while
mechanical availability is based on quarterly
turbine performance statistics.
The main objective of requiring mechani-
cal availability is to ensure that a wind farm
is properly maintained and operated. But it
also ensures that a minimum amount of en-
ergy is generated over a given period if the
minimum mechanical availability number
of the wind turbines is met. If this mini-
mum production is not achieved, an energy
shortfall will be declared and the wind farm
owner will have to find a way to make up the
difference that would have been generated
had the turbines been fully available.
Calculating the guaranteed generation of
a typical wind plant for a given period of
time (usually one quarter of a year) illus-
trates these points. Guaranteed generation is
calculated using the following formula:
GG = EQE x MAF = EQE x MAR x AH/TH
May 2008 | POWER www.powermag.com 25
RENEWABLES
Where: GG is guaranteed gen-
eration.
EQE is the expected quarterly en-
ergy generated.
MAF is the mechanical avail-
ability factor. (Wind turbine manu-
facturers typically guarantee the
mechanical availability of their units
for two to five years following instal-
lation. After this period, it is up to the
wind farm owner/operator to perform
the maintenance necessary to ensure
their required availability.)
MAR is the mechanical availabil-
ity requirement (a percentage usu-
ally around 97%).
AH is actual hours—the number
of hours in the given period, less
two hourly sums. They are the total
hours during the period that turbines
are not operational because (1) they
are being maintained, (2) there is a
major power system emergency, or
(3) wind conditions are too weak or
strong.
TH is total available hours—the
number of hours in a given period
during which a wind farm’s turbines
are physically capable of producing
electricity.
Example calculationConsider a 50-MW wind farm with an an-
nual 35% capacity factor and turbines
whose required mechanical availability is
97% for a given quarter. Now assume that,
during a 90-day quarter, the wind farm has
30 hours of scheduled maintenance, 10
hours of power system emergency, and 40
hours when wind speeds are above or below
the turbines’ operating range. Further, as-
sume that during that quarter the wind farm
generated 34,800 MWh.
For this quarter, the AH of the turbines is
calculated as:
AH = (24 hours/day x 90 days/quarter) – (30 hr + 10 hr + 40 hr) = 2,080 hrSince there are 2,160 hours in a calendar
quarter, the turbines’ MAF during the same
quarter would be:
MAF = 0.97(2,080/2,160) = 0.9341The wind farm’s GG for this quarter
would be the product of its EQE and MAF.
In this case, the EQE would be the product
of 50 MW, the number of hours in the quar-
ter, and the projected capacity factor. Using
our definitions, EQE would be 50 MW x
2,160 hours x 35%, or 37,800 MWh.
As a result, the wind farm’s GG for this
quarter is 37,800 MWh x 0.9341, or 35,309
MWh. Because only 34,800 MWh are de-
livered to the meter, there would a short-
fall of 509 MWh that the wind farm owner
would have to make up.
Utilities typically buy wind energy us-
ing a power purchase agreement that may
include an option to purchase the wind farm
later as well, after its tax credits have ex-
pired (usually 10 years after its commission-
ing). In such cases, mechanical availability
guarantees take on even more importance.
Obviously, the utility would prefer the wind
farm to have a high availability when it takes
ownership. The operator, on the other hand,
would be financially motivated to let turbine
maintenance slip the last few years of opera-
tion. Guarantees of mechanical availability
give wind farm operators an incentive to be
conscientious about maintenance right up to
the turnover date. ■
—Robert Castro ([email protected]) teaches graduate level power
classes at the University of Southern California and negotiates wind gen-
eration contracts for a local utility. Fernando Pardo ([email protected]) is a
supervisor of renewable energy development at a local utility.
www.lincolnelectric.com
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www.powermag.com POWER | May 200826
MERCURY CONTROL
Future of national mercury rule now uncertainThis February, a federal appeals court tossed out the Clean Air Mercury Rule
and its cap-and-trade program and ordered that mercury be regulated more stringently as a hazardous air pollutant. Adding insult to injury, the court made its ruling effective one month later. While the EPA regroups, state energy and environmental regulators will have an opportunity to look closely at recent power plant permits for guidance. This article reviews the technology options and regulatory approach for mercury control used on recently permitted and currently operating coal-fired plants.
By Christopher Wedig; Dr. William Frazier, PE; and Ethan Begg, PE, The Shaw Group
As the baseball great Yogi Berra once
said, “It’s déjà vu all over again.”
On February 8, the U.S. Court of
Appeals for the D.C. Circuit dismissed the
Clean Air Mercury Rule (CAMR). The U.S.
Environmental Protection Agency (EPA)
wrote the CAMR assuming that mercury
should be regulated under Clean Air Act
(CAA) Section 111, which sets national emis-
sion standards for new stationary sources.
But the court reinstated a more stringent re-
gime under CAA Section 112, which governs
hazardous air pollutants (HAPs). Section 112
regulation of mercury requires meeting maxi-
mum achievable control technology (MACT)
standards—and eliminating the mercury cap-
and-trade program.
In the wake of this decision, coal-fired
power projects currently in their planning
or permitting phases may need to reevaluate
whether their mercury control technology ap-
proach complies with their state’s standard.
New federal regulations under Section 112
aren’t expected for several years.
The EPA lost a fight with 15 states, which
convinced the U.S. Court of Appeals for
the Washington, D.C., circuit that both the
CAMR and an EPA rule removing power
plants from the list of sources of HAPs (plac-
ing them beyond the jurisdiction of Section
112) violate the CAA. On February 8, the
court issued a decision that vacated both
rules effective March 14, 2008. This leaves in
place the original December 2000 judgment
by the EPA that electric utilities should be
regulated under Section 112. A case-by-case
MACT for HAPs may be required for new
solid-fuel facility permits.
The EPA is currently reviewing the deci-
sions and evaluating their possible impacts.
Many anticipate the new regulatory regime
will require major new sources of HAPs,
including power plants, to conduct case-by-
case preconstruction reviews of their mer-
cury control strategies until a new MACT
standard is developed and promulgated.
States take center stageAt least 21 states have proposed, finalized,
or implemented mercury limits or alloca-
tion procedures that are more stringent than
the CAMR. In addition to the CAMR and
state-specific rules, consent decrees between
certain sources and regulatory agencies also
have affected the mercury control technology
landscape.
Some coal-fired power plants recently
have been issued air permits that limit their
emissions of mercury. In most cases, the lim-
its were established prior to the February rul-
ing. For some permits, the limits were based
on recently updated New Source Perfor-
mance Standards (NSPS) for electric utility
steam generating units that in turn are based
on the unit’s generating technology and fuel.
In other cases, the limits were established as
part of a MACT evaluation for mercury.
Several new coal-fired power plant proj-
ects currently in their permitting phase are
now assessing the implications of the recent
court ruling. Some of the recently issued air
quality permits call for the use of a specific
mercury control technology. Many specify
the injection of a sorbent such as activated
carbon or halogenated activated carbon for
mercury control.
Mercury projects continueMercury control technologies currently
available for use by utilities have evolved
from numerous laboratory, pilot, and demon-
stration-scale test programs completed in the
mid-to-late 1990s and tested at various levels
in the field since 2001.
Much of the full-scale mercury control
technology testing has been sponsored by the
DOE’s National Energy Technology Labora-
tory (NETL). NETL’s program is currently
focused on slip-stream and full-scale field
testing of mercury control technologies at
operating coal-fired power plants. The lab’s
longer-term goal is to develop advanced mer-
cury control technologies capable of 90% or
greater capture for commercial demonstra-
tion by 2010. Many of the field tests spon-
sored by NETL were conducted at full scale
for short periods of time.
For example, during Phase I of the NETL
program, testing conducted in 2001 and 2002
evaluated the mercury capture efficiency of
activated carbon injection (ACI) at four coal-
fired power plants. The 14 projects selected
for Phase II of the NETL program fall into
two general categories of mercury control:
sorbent injection and oxidation enhance-
ments. Mercury oxidation enhancements
are intended to improve mercury capture of
conventional ACI or downstream air quality
control systems (AQCS) by converting mer-
cury to a more oxidized state. The 14 Phase
II projects sponsored by NETL include 37
field tests performed at 30 different generat-
ing units.
This program evaluated a wide range of
coals, including coals from the Powder River
Basin (PRB); low-, medium-, and high-sulfur
bituminous coals; North Dakota lignites; and
blends of PRB coal and bituminous coal and
Texas lignite. Although the field tests cov-
ered numerous types of AQCS, most were
performed on cold-side electrostatic precipi-
tators (ESPs), the most common AQCS used
by existing coal plants.
May 2008 | POWER www.powermag.com 27
MERCURY CONTROL
In addition to the NETL Phase I and II field
tests, the DOE, under its Clean Coal Demon-
stration Program, is sponsoring a commercial
demonstration of the Toxecon process. (See
POWER’s special October 2004 issue for a
detailed description of it and other technol-
ogy options for mercury control.) Toxecon
is an EPRI-patented process. It relies on the
injection of sorbents (including powdered ac-
tivated carbon for mercury control, and other
sorbents for NOx and SOx control) into the
flue gas downstream of an existing particu-
late control device and the collection of the
resulting compounds by a new particulate
control device, typically a pulse-jet fabric fil-
ter or baghouse (BH).
Trends in compliance technologyAs mentioned, many new coal-fired power
plants have specific mercury control technol-
ogy identified in their air permit (Table 1).
Many of the new plants will use spray dryer/
absorbers (SDAs) and BHs to control SO2
and particulate matter, and selective catalytic
reduction (SCR) systems for NOx control.
Variations abound. For example, the AQCS
configuration at one station is a BH followed
by a wet flue gas desulfurization (FGD)
system and a wet ESP. At another plant, the
configuration is a dry ESP followed by a wet
FGD system and a wet ESP.
There are many other new plants not listed
in Table 1 whose air permit specifies a mer-
cury emission limit but not a particular con-
trol technology. In these cases, the project
developers will need to consider whether the
co-benefit mercury removal provided by the
AQCS chosen for SO2, NOx, and particulate
matter control (using the design fuels) will be
adequate to meet the permitted mercury lim-
it. In some instances, project developers may
elect to install an ACI system—even though
it is not required by the air permit—to ensure
meeting the permitted mercury emission lim-
its. Although the incremental capital cost of
an ACI system is relatively small compared
to that of the entire plant, the cost of the ac-
tivated carbon needed to operate the system
can be significant.
The Institute of Clean Air Companies
(ICAC) maintains listings of commercial
mercury control systems ordered by electric
utilities for both new plants and retrofit ap-
plications. Table 2, which was updated this
February, summarizes the control technol-
ogy bookings for new plants. According
to the ICAC, the regulatory driver of all 17
bookings listed is the project’s construc-
tion permit. Significantly, there was a big
increase in bookings since the last update
of the database in September 2006. Table 3
summarizes the ICAC’s data on retrofit mer-
cury control projects.
Parameter Observation
Number of bookings 17
700 MW (median)
West—2
South—3
Southwest—2
East—2
Canada—1
Prime OEM contractors
Five different process supplier teams
Bituminous—5
Lignite—3
Canadian subbituminous—1
ESP/WFGD/wet ESP—3
FF/WFGD—5
CFB boiler/FF—1
Mercury control technology
ACI—17
Notes: ACI = activated carbon injection, BH = baghouse, CFB = circulating fluidized-bed boiler, ESP = electrostatic precipitator, FF = fabric filter, SDA = spray dryer/absorber, WFGD = wet flue gas desulfurization system.
220–860 MW (range)Unit size
Midwest—7Location
PRB—8Coal type
SDA/FF—8Air quality control system configuration
Table 2. Commercial mercury con-trol technology bookings for new coal-fired utility plants. Source: Insti-tute of Clean Air Companies
Parameter Observation
Number of bookings 65
90–880 MW (range)
460 MW (median)
Midwest—33
West—3
South—4
Southwest—10
East—11
Northeast—4
Prime OEM contractors 15 different suppliers
PRB—43
Bituminous—14
Bituminous/biomass—1
Lignite—3
Western bituminous/subbituminous—4
Activated carbon injection—64
Powerspan’s ECO process—1
Consent decree—9
State rule—35
Construction permit—7
DOE demonstration—1Voluntary
regional emission abatement plan—8
Clean Air Mercury Rule—5
Regulatory driver
Unit size
Location
Coal type
Mercury control technology
Table 3. Commercial mercury con-trol technology bookings for retro-fit utility mercury control projects. Source: Institute of Clean Air Companies
Unit StateMercury control
technologyHg emission
limit
Plant A Georgia 2 x 645 PRB and central Appalachian
Halogenated ACI 15 lb/106 MWh
Plant B Nebraska 660 PRB Sorbent injection 18 lb/106 MWh
Plant C Wisconsin 600 PRB Sorbent injection 1.7 lb/1012 Btu
Plant D Nevada 200 PRB ACI 20 lb/106 MWh
Plant E Montana 116 PRB ACI or equivalent
Based on demonstration period
Plant F Texas 800 PRB Halogenated ACI 20 lb/106 MWh
Plant G Montana 2 x 390 Western bituminous
ACI or equivalent
1.5 lb/1012 Btu or 90% control
Plant H Illinois 250 High-sulfur bituminous
ACI (if not 95% removal)
95% removal without ACI, or use ACI
Plant I Illinois 2 x 750 High-sulfur bituminous
ACI (if not 95% removal)
95% removal without ACI, or use ACI
Plant J Nevada 3 x 530 PRB Halogenated ACI 20 lb/106 MWh
Plant K Colorado 750 PRB Sorbent injection 20 lb/106 MWh
Plant L Texas 2 x 860 Lignite Treated ACI 9.2 lb/1012 Btu
Plant M Iowa 790 PRB ACI 1.7 lb/1012 Btu
Notes: ACI = activated carbon injection, Hg = mercury, PRB = Powder River Basin.
Capacity(MW)
Primarycoal supply
Table 1. Examples of new coal-fired facilities whose air permit specifies a mercury control technology. Source: Shaw Group
www.powermag.com POWER | May 200828
MERCURY CONTROL
Many options availableTable 4 lists 10 of the many significant ret-
rofit full-scale mercury control projects in
the U.S. currently in the design, construc-
tion, and/or initial operation phase. As the
right column shows, not all make use of ACI;
some projects achieve mercury reduction as
a co-benefit of the operation of their AQCS
devices, in any of several configurations.
Co-benefit mercury removal (Table 5)
is defined as the reduction of mercury con-
centration in flue gas by an AQCS device
primarily designed to control emissions of
another parameter such as SO2, SO3, NOx,
particulate matter (PM), or CO2. Although
the level of co-benefit mercury removal may
be incidental, there are ways to design and/or
operate an AQCS to improve its Hg removal
NameUnit size
(MW, nominal) Primary coal supply AQCS configuration Mercury control process
Trona injection for SO2 control (retrofit)
FF for control of SO2, Hg, and PM (retrofit)
Trona injection for SO2 control (retrofit)
FF for control of SO2, Hg, and PM (retrofit)
ESPs for flyash control (existing)
Lime SDA for SO2 control (retrofit)
FF for control of SO2, Hg, and PM (retrofit)
ESPs for flyash control (existing)
Wet LSFO FGD system for SO2 control (retrofit)
Clean-side SCR system for NOx control (existing)
Clean-side SCR system for NOx control (existing)
Lime SDA for SO2 control (retrofit)
FF for control of SO2, Hg, and PM (retrofit)
FF for control of Hg and PM (retrofit)
ESP for flyash control (existing)
Lime SDA for SO2 control (retrofit)
FF for control of SO2, Hg, and PM (retrofit)
ESP for flyash control (existing)
Wet LSFO FGD system for SO2 control (retrofit)
ESPs for flyash control (existing)
Lime SDA for SO2 control (retrofit)
FF for control of SO, Hg, and PM (retrofit)
Notes: ACI = activated carbon injection, AQCS = air quality control system, ESP = electrostatic precipitator, FF = fabric filter; FGD = flue gas desulfurization, Hg = mercury, LSFO = limestone forced-oxidation, PM = particulate matter, SCR = selective catalytic reduction, SDA = spray dryer/absorber, SNCR = selective noncatalytic reduction.
SNCR for NOx control (retrofit)Plant A 100 PRB ACI between trona injection and FF (retrofit)
SNCR for NOx control (retrofit)Plant B 200 PRB ACI between trona injection and FF (retrofit)
High-dust SCR system for NOx control (retrofit)Plant C 250 Low-sulfur coal ACI between SDA and FF (retrofit)
High-dust SCR system for NOx control (retrofit)Plant D 335 Bituminous coal Retrofit LSFO FGD also removes ionic Hg
ESP for flyash control (existing)Plant E 350 Low-sulfur coal ACI upstream of existing ESP
ESP for flyash control (existing)Plant F 350 Bituminous coal ACI between SDA and FF (retrofit)
ESP for flyash control (existing)Plant G 400 Low-sulfur coal ACI upstream of FF (retrofit)
High-dust SCR system for NOx control (retrofit)Plant H 610 Bituminous coal ACI between SDA and FF (retrofit)
High-dust SCR system for NOx control (existing)Plant I 635 Bituminous coal Retrofit LSFO FGD also removes ionic Hg
High-dust SCR system for NOx control (retrofit)Plant J 650 PRB ACI upstream of SDA (retrofit)
Table 4. Some retrofit mercury control projects in which Shaw Group has been involved. Source: Shaw Group
AQCS device Removal process
SCR system Neutral Hg to ionic Hg.
Existing ESP or BH Removes some Hg-particulate and flyash (flyash LOI can lower concentrations of Hg2+ and Hg0).
SDA + FGD Adsorption of Hg in lime by-product solids at cool temperatures, with PM and solids removed in baghouse.
Wet FGD Ionic Hg and PM absorbed in FGD slurry at cool temperatures. Additives used to minimize re-emission of Hg0.
Multipollutant processes Ionizer reactors achieve Hg oxidation, followed by Hg absorption at cool temperatures in a wet FGD, with further removal in WESP.
Notes: AQCS = air quality control system, BH = baghouse, ESP = electrostatic precipitator, FGD = flue gas desulfurization system, Hg = mercury, LOI = loss-on-ignition, PM = particulate matter, SCR = selective catalytic reduction, SDA = spray dryer/absorber, WESP = wet ESP.
Table 5. Co-benefit mercury removal is possible from several air-qual-ity control devices that were primarily designed to limit emissions of another pollutant. Source: Shaw Group
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CIRCLE 16 ON READER SERVICE CARD
www.powermag.com POWER | May 200830
MERCURY CONTROL
efficiency. The degree of co-benefit Hg reduction depends on both the
type of AQCS device being used as well as its process parameters.
These variables include:
■ The use of an ESP or baghouse to reduce flyash loss-on-ignition.
■ The oxidation of neutral Hg to ionic Hg by an SCR system.
■ The presence of a dry FGD system (an SDA, a BH, and a circulat-
ing dry scrubber with sorbent injection).
■ The existence of a wet FGD system (with or without additives, to
minimize conversion of ionic Hg to neutral Hg).
■ The use of a multipollutant control process based on ionizer reac-
tors, absorbers, and wet ESP(s).
■ The use of ACI with an ESP, BH, or SDA (influences SO3 reduc-
tion levels).
■ The use of brominated ACI with an ESP, BH, or SDA.
■ The use of a demonstration- or R&D-phase mercury oxidation
catalyst.
■ Use of a fuel additive or boiler chemical injection to convert neutral
Hg to ionic Hg.
Table 6 presents examples of typical co-benefit mercury removal
efficiency levels for various AQCS devices. Co-benefit mercury con-
trol using wet and dry FGD systems is a function of the following
parameters:
■ The coal’s type and its concentrations of Hg, chlorine, bromine,
fluorine, and sulfur.
■ The level of mercury speciation (ionic, elemental, particulate).
■ The extent to which the SCR’s catalyst oxidizes mercury.
■ Required levels of mercury reduction and stack emissions.
■ The extent to which both wet and dry FGD systems reduce the
concentration of mercury in flue gas.
■ The level of mercury capture by the FGD system.
An FGD system can remove several compounds from a flue gas
stream. They include SO2 and SO3, nitrogen dioxide (NO2), PM, mer-
cury (in its ionic form), other trace elements (selenium, lead, arse-
nic, etc.), ammonia (NH3), hydrogen chloride (HCl), and hydrogen
fluoride (HF). On some FGD projects, guaranteed trace species co-
removal has been requested. Fortunately, both wet and dry FGD are
compatible with ACI.
Finally, every utility coal-fired boiler has unique design issues that
must be addressed as part of any mercury control program. For plants
with existing FGD systems, upgrading the FGD system for increased
mercury co-removal is an option that could pay huge dividends. The
benefits may go well beyond reducing the bare cost of mercury re-
moval to include:
■ Increased SO2 removal (producing valuable credits).
■ Increasing the amount of flue gas scrubbed.
■ Increasing mercury removal efficiency.
■ Allowing the plant to use a higher-sulfur coal or pet coke or fuel
oil.
■ The use of a limestone forced-oxidation FGD system to yield wall-
board- and/or cement-grade gypsum.
■ The ability to test larger atomizer drives in an existing SDA/FGD.
■ Increased reliability of an existing FGD system.
■ The ability to repair severe corrosion of FGD system materials. ■
—Christopher Wedig ([email protected]) is a senior technology specialist with the Power Group of
The Shaw Group. Dr. William Frazier, PE ([email protected]) is an
executive environmental consultant for Stone & Webster Management Consultants, Inc., a Shaw Group company.
Ethan Begg, PE ([email protected]) is a client program manager with the
Environmental & Infrastructure Group of Shaw Group.
Table 6. Comparing the mercury removal efficiencies of various AQCS processes. Source: Shaw Group
AQCS processTypical mercury
removal efficiency Comments
SCR oxidation 10% to ~ 90% oxidation of neutral Hg to ionic Hg
Level depends on coal’s type and chlorine and bromine content and on SCR system’s catalyst type, space velocity, and gas temperature.
Existing ESP or FF without ACI
5% to ~ 30% total Hg typical with higher values
Level depends on LOI of flyash, coal’s chlorine and bromine content, and ESP’s specific collection area.
Dry FGD with FF; lime SDA without injection of PAC
Up to ~ 80% to 90% ionic Hg removal in SDA/FF
Level depends on coal’s chlorine and bromine concentration and flue gas temperature, among other factors. Eastern bituminous coal typically has more oxidized Hg in its combustion products than does PRB coal.
Wet FGD; LSFO FGD without a WESP or injection of PAC
Up to ~ 90% ionic Hg removal
May require additives in wet FGD to reduce Hg reemission.
Multipollutant processes (with reactor/FGD/WESP) without PAC injection
Up to ~ 90% total Hg removal
Level depends on designs of reactor, FGD, and WESP.
Notes: ACI = activated carbon injection, AQCS = air quality control system, ESP = electrostatic precipitator, FF = fabric filter; FGD = flue gas desulfurization, Hg = mercury, LSFO = limestone forced-oxidation, PAC = powdered activated carbon, PM = particulate matter, PRB = Powder River Basin, SCR = selective catalytic reduction, SDA = spray dryer/absorber, WESP = wet ESP.
CIRCLE 17 ON READER SERVICE CARD
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www.powermag.com POWER | May 200832
WATER TREATMENT
Cation conductivity monitoring: A reality checkThe ability to detect contaminated feedwater or steam before it can corrode the
internals of a turbine or HRSG and cause a forced outage is worth millions. One knock against cation conductivity monitoring—still the most com-mon technique for the early detection of contamination—is the difficulty of interpreting conductivity readings when the plant’s makeup contains significant levels of organics or CO2. Here are the pros and cons of cation conductivity monitoriting and some alternative monitoring methods.
By David G. Daniels, M&M Engineering Associates Inc.
The operators of a new combined-cycle
plant being run in two-shift mode (on
16 hours, off 8) had become used to the
cation conductivity sample of the condensate
pump discharge being in alarm for a while
following each day’s start-up. Normally, after
a few hours of operation, the reading dropped
to an acceptable limit. So, when cation con-
ductivity didn’t drop as usual and the alarm
never cleared, a problem wasn’t caught in
time. Scratching their heads over the high
reading, the operators guessed, “Maybe the
cation column needs to be replaced.”
Weeks later, what had been a small con-
denser tube leak suddenly became big enough
to contaminate the plant’s heat-recovery
steam generator (HRSG) and steam turbine.
Although the large leak was quickly detected
and the plant shut down, it took nearly three
months to clean up and recondition the tur-
bine. Despite the repairs, the long-term dam-
age done to the expensive new turbine is
still really anybody’s guess. Had the opera-
tors not ignored the high cation conductivity
reading at the condensate pump discharge,
they would have known they had a problem.
Locating and plugging the leaking condenser
tube would have been easy and would have
avoided the repair costs and millions of dol-
lars in lost generation revenues.
Unfortunately, this kind of story has be-
come commonplace. A change in cation con-
ductivity has been the first indication of many
problems, but it has been ignored until major
contamination occurs. Nevertheless, some
operators have said that it is unnecessary
(and, in some cases, impossible) to strictly
follow ASME, EPRI, or a turbine manufac-
turer’s guidelines for cation conductivity.
Their comments might suggest to some that
the parameter is no longer important.
To be sure, some conventional fossil fuel–
fired boilers and combined-cycle plants have
operated for many years with the cation con-
ductivity of feedwater or steam at levels well
above what is considered normal. Indeed,
one combined-cycle plant has been run for
more than 15 years with cation conductivity
more than an order of magnitude higher than
the recommended limit of 0.25 μS/cm (mi-
croSiemens per centimeter) without causing
corrosion or cracks in its turbine. Here’s why
this plant has avoided problems. Because its
water supply has significant concentrations
of naturally occurring organic compounds, it
adds both organic amines and a carbon-con-
taining oxygen scavenger (a reducing agent)
when preparing makeup.
Another case of unexpected immunity
occurred at an older plant that recently pur-
chased its first cation conductivity analyzer.
Following installation, the unit immediately
indicated a high level in feedwater, and the
cation resin columns were exhausting in a
few days. This plant’s condensers have stain-
less steel tubing that has never leaked. I have
regularly inspected the boilers, deaerators, and
other equipment at this plant for several years.
The steam drum and tubing are in excellent
condition. Every time the turbine is inspected,
there are no signs of cracking or pitting. As at
the other plant, the additions of amine and the
CO2 picked up by the condensate drive feed-
water and steam cation conductivity high.
Useful or not?Is cation conductivity so important that
high values justify taking a unit off-line? Or
should the parameter be ignored in favor of
other analytical chemistry tools?
Based on the experience of M&M Engi-
neering Associates, measuring cation con-
ductivity remains one of the most sensitive,
simple, and reliable tools for detecting small
amounts of contamination in feedwater and
steam. Working in concert with sodium and
other monitoring, cation conductivity moni-
toring can confirm that your feedwater is
clean enough to be turned into steam that
won’t damage your turbine. However, many
operators find it difficult to interpret cation
conductivity readings, particularly at plants
whose steam generators use water contain-
ing either naturally occurring or purposefully
added organic compounds.
To understand the difficulty, it’s important to
know what cation conductivity is and is not.
Actually, “cation conductivity” is a misno-
mer. A more precise name would be “cation-ex-
changed conductivity,” because it is a measure
of the conductivity of a solution after it has been
passed through a strong acid cation exchange
resin. This resin exchanges all the cations in
the sample for hydrogen ions. In high-purity
samples (such as of condensate, feedwater, or
steam), the cation exchanged is primarily am-
monium ions. What passes through the resin un-
scathed are all the anions in the sample. These
are primarily anions of dissolved carbon diox-
ide (bicarbonate), the anions of any organic ac-
ids such as formate or acetate, and (it is hoped)
traces of chloride and sulfate.
Because the ammonium ion is removed and
exchanged for hydrogen, the pH of the water
1. Scaled up. Proper attention to cation conductivity monitoring might have prevent-ed this damage to turbine blades. Courtesy: M&M Engineering Associates
May 2008 | POWER www.powermag.com 33
WATER TREATMENT
exiting the column is more acidic than it was en-
tering. This has led some to use the term “acid
conductivity” to describe cation conductivity.
Chloride and sulfate are known to con-
tribute to corrosion fatigue in turbine blades,
particularly those in the final rows of the
low-pressure section. It is chloride and sul-
fate contamination that cation conductivity is
really intended to detect. Early detection of
this contamination can allow a plant time to
correct contamination before it causes depos-
its and corrosion on the turbine (Figure 1).
What cation conductivity is not is a reflec-
tion of a single parameter, as in the case of
sodium or silica analysis. Similar to specific
conductivity, cation conductivity represents
the sum of the conductivities of all the an-
ions that remain in the solution, with a small
contribution from hydrogen ions. In fact, if
cation conductivity measurements of steam
represented the level of a single parameter,
such as chloride, they would not be suffi-
ciently sensitive to be of much value.
The theoretical cation conductivity of a
2-ppb chloride (hydrochloric acid) solution
is 0.063 μS/cm, barely above the theoreti-
cal minimum of 0.055 μS/cm. Most turbine
manufacturers call for the chloride level in the
steam to be below 2 ppb under normal con-
ditions. The steam’s chloride concentration
would have to rise to nearly 20 ppb before the
resultant cation conductivity would exceed the
generally accepted normal cation conductivity
limit of 0.2 μS/cm. Steam entering a turbine
with a 20-ppb chloride concentration would
be considered grossly contaminated.
What makes cation conductivity moni-
toring so valuable is that contamination of
feedwater or steam is rarely due to a sin-
gle contaminant. When a condenser tube
springs a leak, chloride, sulfate, carbonate,
and many other anions contaminate con-
densate and feedwater. The combined effect
will significantly raise cation conductivity
and provide the desired early warning even
when the individual contamination lev-
els are small. Of course, if there is a large
contribution from CO2 or organic acids, the
problem may not be detected until it is too
late. Carbon dioxide in steam is too volatile
to create a low-pH environment for turbine
blades and therefore cannot cause corrosion.
Whether or not organic acids can damage a
turbine is an area of active research.
Turbine manufacturers are very aware of
the long-term damage that can be caused by
even low levels of chloride and sulfate. The
simplest, most reliable way to detect such
contamination in real time has been cation
conductivity. Therefore, turbine OEMs have
set cation conductivity limits where a sig-
nificant contribution from CO2 or organic
acids cannot be tolerated.
During plant commissioning, for example,
CO2 and other organic chemicals in first steam
can raise the cation conductivity level so high
that meeting the warranty limits specified by
the turbine manufacturer(s) seems impos-
sible. This leaves the plant two unpalatable
options: invest in additional water treatment
equipment to remove the offending organic
chemicals, or use a more sophisticated tool—
such as ion chromatography—to prove the
absence of chloride and sulfate in the steam.
Turbine original equipment manufacturers
often require that, during routine start-ups,
the cation conductivity of steam be less than
1 μS/cm before it can be admitted into the
prime mover. Sampling problems and CO2
in the condensate can result in levels higher
than that, unnecessarily delaying start-ups.
“New and improved” cation conductivityBecause cation conductivity is so simple and
reliable, significant efforts continue to be
made to improve the technique by removing
interferences from carbon dioxide, in par-
ticular. The new parameter to be monitored
and analyzed goes by the name of degassed
cation conductivity. Because the pH of the
sample following the strong acid cation resin
is acidic, most, if not all, of the CO2 in the
sample is in the form of a dissolved gas. The
most common way to remove it is to drive it
off with heat using a reboiler. After the sam-
ple is passed through the strong acid cation
resin, it is heated to near boiling, cooled to
77F, and then sent to a conductivity meter.
The most common complaint about re-
boiler-style degassed cation conductivity is
unreliability. The temperature control of the
reboiler is critical—too low or too high pro-
duces unreliable results. What’s more, the
temperature of the sample after the reboiler
can affect the result.
The CO2 also can be removed by sparging
it out with nitrogen gas through an empty or
packed column. Nitrogen purge systems are
typically only used during start-ups until the
regular cation conductivity value drops to
a normal level. The systems’ nitrogen con-
sumption rate makes them impractical for
continuous use. For units that only experience
high cation conductivity during start-ups, ni-
trogen sparging may be all that is required.
A relatively new technique uses a spinning-
disk reactor and CO2-free air as the purge gas.
The air is first passed through a molecular
sieve to remove all the CO2. The water sample
passes through the cation column and then is
mixed with the CO2-free air and put through
the reactor, whose large surface area creates
air bubbles that strip the CO2 from the sample.
The reactor removes about 70% of the CO2,
so it does not completely remove the interfer-
ence. But the results are good enough to get
within the desired limits. This method does
not require heating or cooling the sample.
Seeing differently Because some plant operators and chemists
have had problems with degassed cation con-
ductivity monitoring, they have looked for
other ways to detect parts-per-billion levels
of contamination in condensate. Here are
three that we have seen used successfully.
Sodium. On-line sodium analyzers have
become more reliable and simpler to main-
tain. A number of manufacturers—including
Swan Analytical Instruments (www.swan.ch),
Thermo Fisher Scientific Inc. (www.thermo.
com), and Hach (www.hach.com)—make so-
dium analyzers that can reliably detect 0.1 ppb
of sodium. Swan’s Soditrace model claims the
industry’s lowest detection limit for sodium
ion concentrations of 1 part per trillion (0.001
ppb). Figure 2 shows Hach’s unit.
Most cooling water contains sodium con-
centrations of the same order of magnitude
as those for chloride or sulfate. Therefore, so-
dium detection in condensate, even at the 0.1
ppb level, becomes an excellent early warn-
ing system for condenser tube leaks or sodium
leakage from water pretreatment systems.
However, sodium analysis doesn’t address
chloride or sulfate concentrations directly. For
that reason, M&M strongly recommends using
both cation conductivity and sodium monitors
not only on the main steam sample but also at
the hotwell or condensate pump discharge (or,
2. How low can you go? Hach’s Poly-metron 9245 sodium analyzer boasts a sen-sitivity of 0.01 ppb. To maintain an optimum response time in low-sodium solutions, the analyzer automatically reactivates the elec-trode using nonhazardous chemicals. Cour-tesy: Hach Company
www.powermag.com POWER | May 200834
WATER TREATMENT
if there are condensate polishers, downstream
of them). Sodium monitoring is the only way
to detect caustic contamination.
Chloride. As part of its Orion line, Ther-
mo Fisher Scientific offers a chloride monitor
that can detect levels as low as 0.1 ppm (Fig-
ure 3). Though this sensitivity level is insuf-
ficient to detect contamination of feedwater,
it has been used very successfully to continu-
ously monitor chloride levels in boilers and
HRSGs. Because contamination quickly con-
centrates in steam generators, this instrument
can provide the desired early warning.
Ion chromatography. The only tech-
nique that can directly analyze for chloride,
sulfate, and phosphate with a single sample
injection is ion chromatography. If desired,
an ion chromatograph can even be config-
ured to analyze for organic acids such as
formic and acetic acid. Great strides have
been made in simplifying the technique.
However, it still requires significant dedica-
tion to set up and maintain calibration on an
ion chromatograph—particularly one that is
detecting ppb levels of contamination.
Those who make that commitment usu-
ally end up feeling it was worth the effort.
For example, lab techs at a large coal-fired
plant that for years has used an on-line ion
chromatograph from Dionex Corp. (www
.dionex.com) have been very pleased with the
results. By the way, the plant’s control room
operators still use cation conductivity ana-
lyzers to monitor feedwater purity. Why? Ion
chromatography analysis of a single sample
for chloride, phosphate, and sulfate can take
quite a few minutes. And if you’re measur-
ing multiple sample points, you may only get
one analysis per point per hour. Cation con-
ductivity measurement, on the other hand, is
essentially continuous.
Don’t drive blindWhether you monitor cation conductivity or
degassed cation conductivity alone or in com-
bination with other analytical techniques, it
is essential that your instruments be reliable,
on-line continuously, and sensitive enough
to detect contamination early enough to take
corrective action to prevent corrosion.
You would never think of operating your
car at night without headlights. Don’t oper-
ate your steam turbines and HRSGs without
the tools to see what’s coming down the road
soon enough to steer away from problems.
Like driving in the dark, the risks of operat-
ing a plant “blind” are far too great. ■
—David G. Daniels ([email protected]) is a principal
of M&M Engineering Associates and a contributing editor to POWER.
3. No moving parts. According to the manufacturer, the Orion 2117XP chloride mon-itor holds calibration up to 60 days between reagent changes. The instrument can mea-sure chloride concentrations as low as 0.1 ppm. Courtesy: Thermo Fisher Scientific Inc.
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www.powermag.com POWER | May 200836
PREDICTIVE MAINTENANCE
Making PM systems sweat the small stuffModern predictive maintenance systems can monitor the health of most plant
equipment. By sorting through the wealth of information those systems deliver, operators can discern important trends, including the early signs of a system or component failure.
By Donald S. Doan, SmartSignal Corp.
As new power plants have become
harder to permit, maintaining the per-
formance of plants that some would
consider past their prime has become more
important than ever. Like a vintage coupe at
a car show, an old plant that has been well-
maintained doesn’t show its age. Even 40-
year-old plants can deliver many more years
of profitable and reliable service—if their
equipment has a good health care plan.
Over the past two decades, plant owners
have increasingly used equipment condition
monitoring (CM) to maximize plant avail-
ability and revenue and minimize mainte-
nance costs. Among the most popular CM
systems and schemes are data historians,
digital control, trending of critical operating
parameters, vibration and oil analyses, and
infrared scans.
However, many of these methods either
focus only on whether a system is currently
operating within prescribed limits or track
only certain measures of performance. In
both cases, human analysts must then infer
overall equipment health and its direction.
Newer CM systems and techniques can ex-
trapolate readings of common plant param-
eters to evaluations of overall equipment
health in real time. By comparing past and
present readings, they can predict—fairly ac-
curately—when a system or component will
fail or begin causing problems elsewhere.
When a plant’s analytic or interpretive
methods fall short, its bottom line suffers.
Two scenarios, both undesirable, are pos-
sible. If systems are maintained according
to strict schedules, with no regard to their
actual condition, man-hours and scarce
O&M dollars may be spent on repairs that
aren’t yet needed. If the maintenance phi-
losophy is too cavalier, incipient problems
that should be addressed may not get fixed
in time (because they were detected too late)
to avert an expensive failure.
Neither too soon nor too lateImplementing predictive maintenance (PM)
techniques solves both potential problems. If
real-time readings of key parameters indicate
that a piece of equipment is continuing to op-
erate normally, a scheduled overhaul can be
delayed, along with the cost of performing it.
Conversely, slow but sure changes in readings
enable analysts to detect impending failures
early, before the equipment’s condition wors-
ens to the point of needing urgent attention.
Early awareness of a problem makes it pos-
sible to schedule repairs at a convenient time
(for example, during an upcoming planned
outage) and gives the plant’s O&M staff time
to line up the team of technicians best quali-
fied to do the work.
Although PM has become commonplace
at power plants in the developed world, the
technique is more likely to be applied to
key million-dollar systems such as boilers,
turbines, and generators than to balance-of-
plant (BOP) equipment such as motors, fans,
pumps, and air heaters. Using case studies,
this article argues that PM programs have
their greatest positive impact on plant avail-
ability and profits when they also include
BOP equipment. Comprehensive PM pro-
grams can even quantify the financial losses
avoided by optimizing maintenance sched-
ules to reflect actual equipment health.
Managed care methodologyThe case studies detail several instances
where SmartSignal Corp.’s predictive analyt-
ics software package (also called Smartsig-
nal) detected abnormal operation of main or
BOP equipment at a power plant, enabling
O&M personnel to take early corrective ac-
tion. Under a contract signed in September
2004, SmartSignal installed its real-time PM
system at the generating units of the fossil-
fueled fleet owned and operated by a large
Midwest utility.
Real-time sensor data
Personalizedempirical model
Removes effects ofnormal operation
Statistical deviationdetection
Determines ifoperations are
abnormal
Diagnosticrules
engine
Robust, real-time alertingof impending problems
Diagnosis:excessive seal
leakage
Analyst
Pager, e-mail orphone advisory
1. From raw data to actionable intelligence. Data from key sensors are collected and filtered to create an empirical model of all the normal and expected operational states of the equipment or system monitored. During live monitoring, snapshots of data are compared with the model to generate estimates and residuals. Any alerts created from too-high or too-low re-siduals are then passed through a diagnostic rules engine. If the alerts are persistent or multiple sensors are alerting in a way that fits a known fault pattern, an incident is created that is posted to a web-based watch list for the predictive monitoring analyst to evaluate and take action on. The time between the first posting of an item to the watch list and when an operator must react to an equipment problem is called the “early warning period.” Source: SmartSignal Corp.
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www.powermag.com POWER | May 200838
PREDICTIVE MAINTENANCE
Before we delve into the case studies, it’s
worth outlining how the Smartsignal system
works.
The software uses empirical models of
equipment that have been built from and
“trained” on historical data. Monitoring is
done in real time with 10 minutes between
“snapshots” of various parameters. Algo-
rithms in the Smartsignal system determine
whether any parametric behavior is question-
able and post anomalous results to a “watch
list”—a web-accessible folder of items worth
investigating (Figure 1). An analyst can then
judge whether any item represents a problem
that warrants immediate corrective action—
while the piece of equipment and its generat-
ing unit remain on-line.
Conventional CM systems compare the
readings produced in real time by pressure,
temperature, flow, speed, and vibration sen-
sors to predetermined upper and lower thresh-
olds. If a reading is higher or lower than it
should be, the system triggers an alarm, shuts
down equipment, or both. The thresholds are
carefully set by experienced operators to be
wide enough to minimize unnecessary alarm-
ing but narrow enough not to miss potential
failures that may be catastrophic. However,
because the limits must encompass the broad
range of equipment operation and states, CM
algorithms may lack the sensitivity to pick
up subtle sensor deviations from normal that
could signal an incipient equipment failure.
The CM techniques used in the Smart-
signal program are unique because they use
all sensor readings to determine the current
state of equipment. For example, the instru-
ments dedicated to independent drivers (such
as controllers, material inflow, and ambient
conditions) and those monitoring dependent
responses of the system (including exhaust
gas temperature and material outflow) are
grouped together in a single model.
During monitoring, one algorithm as-
sembles a sample snapshot from the read-
ings of all individual sensors in the model
at the exact same time. This “actual” snap-
shot is then compared to the model, which
uses data embedded in it to create estimates
of the normal readings expected to be pro-
duced by sensors with the equipment in its
current operating state.
For each operating parameter, the differ-
ence between the actual value and the esti-
mated normal value is called the residual.
Another algorithm then tests the residual to
determine whether it is reasonably small—in
other words, whether the actual value is close
to the expected normal value.
When the residual is relatively small, the
sample is considered normal. When the re-
sidual is relatively large, the sample is con-
sidered suspect and triggers either of two
actions. If only one parametric reading is
yielding a high or low residual, the system
signals an “alert” for that moment in time and
notes it on that parameter’s graphic display.
If there are persistent deviations in multiple
sensor readings that match a known fault pat-
tern, the system determines that an “incident”
is occurring and creates an item for addition
to the watch list.
Problems, large and smallNow, the case studies. As mentioned, they
detail incidents and alerts “caught” by Smart-
signal at 16 individual generating units. Table
1 lists the assets (main and BOP) monitored
and the models used at the typical coal plant.
Of the 16 units (which have a total capacity
of about 4,100 MW), eight burn pulverized
coal, seven are simple-cycle combustion tur-
bines that fire natural gas, and one is a gas-
fired combined-cycle unit.
The 16 installations, including empirical
models, were completed in December 2004,
and shortly thereafter the system began live
monitoring of the fleet at a 10-minute sam-
pling rate.
Equipment Number in unit Models
Steam turbine 1 Performance and mechanical condition of high-, intermediate-, and low-pressure section
Electric generator 1 Electrical performance and mechanical condition of exciter and rotor and stator cooling
2 each (total of 8) Performance and mechanical condition
Primary and secondary air heaters 4 Performance
Condenser 1 Performance
Boiler fans (primary air, induced- and forced-draft)
2 each (total of 6) Fan and motor performance
Coal pulverizer motors 5 to 8 each Mechanical condition
Pumps and motors (boiler feedwater, circulating water, heater drain, and condensate)
Table 1. Assets typically monitored at a coal-fired generating unit and the empirical models used to do so. Source: SmartSignal Corp.
CIRCLE 22 ON READER SERVICE CARD
May 2008 | POWER www.powermag.com 39
PREDICTIVE MAINTENANCE
Within the first few months of live monitor-
ing, Smartsignal found compelling evidence
of several potential equipment problems
at the larger coal plants and posted them to
the watch list. Following are four abnormal
conditions detected on major equipment (tur-
bines and generators):
■ At the 600-MW-class Plant A, lube-oil
temperatures of the system for cooling
bearings of the unit’s steam turbine were
behaving erratically. Technicians attrib-
uted the problem to an improperly tuned
control valve in the system’s water cooling
circuit. The early warning and subsequent
retuning avoided a potential thermal cy-
cling of the bearings.
■ At the same plant, Smartsignal detected
low hydrogen pressure in the electric gen-
erator. This early warning and subsequent
corrective action avoided a potential over-
heating of the generator.
■ The Smartsignal at Plant A also noted that
the vibration residual for steam turbine
bearing #7 was slowly rising. When the
condition appeared on the watch list on
February 7, 2005, operators responded im-
mediately by placing the bearing vibration
signal in bypass mode, to prevent the tur-
bine control system from tripping the unit
for excessive vibration. Vibration levels
continued to rise, with the residual reach-
ing 8 mils on March 7. Eventually, the vi-
bration problem was eliminated during a
planned outage. However, the generating
unit might have tripped unnecessarily had
operators not put the bearing vibration trip
signal in bypass.
■ One day, at the 800-MW-class Plant C, the
generator exciter’s field amps and volts
experienced substantial surges that were
noted by Smartsignal. The initial diagnosis
was shorted turns in the rotor. As a result
of the early warning, the exciter was in-
spected during a planned unit outage two
weeks later and was indeed found to need a
rewind. In this instance, the early warning
avoided the need for an unplanned outage.
Monitoring catches weren’t limited to ma-
jor equipment. Although BOP catches are not
as dramatic, they are just as critical to main-
taining plant reliability. In addition, they are
more impressive because fans, motors, and
pumps are usually less well-instrumented
than turbines or generators.
The BOP catches made within the first few
months of Smartsignal going live included
the following:
■ At the 700-MW-class Plant D, the in-
duced-draft fan’s shaft coupling set screw
was found to be loose and causing amps
to cycle high and low. The early warning
avoided a possible forced outage because
the lack of proper ID fan control may
have eventually caused a unit trip for un-
stable draft.
■ Smartsignal determined that the bearing of
one of Plant D’s two cooling water pumps
was starved of cooling water. A subse-
quent inspection found that the cooling
system’s operation was biased to the other
pump, causing a rise of 30 to 70 degrees F
above normal in the bearing temperature
of the first pump. In this case, the early
warning avoided potential bearing damage
and a forced outage to replace the pump’s
motor.
■ Similarly, Plant D’s secondary air heater
support bearing was found to be starved
of oil, causing bearing temperatures to rise
40 degrees F above normal. Here, too, the
early warning avoided a potential bearing
failure and an unplanned outage.
■ At Plant C, Smartsignal sounded an air
preheater alarm and added an item to the
watch list when it detected excessive pres-
sure due to erratic control of steam pres-
sure. The lack of control—which meant
that the air preheaters were not using
properly conditioned steam—reduced the
preheaters’ efficiency.
■ At Plant A, the outboard bearing of the
primary air heater motor was found to be
starved of oil.
■ One of Plant D’s pulverizer mill thermo-
couples was found to have been wired
backward during a maintenance overhaul.
Inside two catchesLet’s examine the specifics of two cases where
the use of the CM and PM methods described
above avoided an unforced outage to replace
an air heater bearing. The first catch was
made and put on the watch list for Plant D on
February 1, 2005. The residual value of the
support bearing temperature increased 10F to
40F above the expected value during the next
week (Figure 2). A SmartSignal analyst deter-
mined that the bearing was oil-starved.
The top graph of Figure 2 shows the actual
sensor value (blue) and the estimated value
(green) for the period of January 24 to Febru-
ary 8. Over most of the period, the two values
are similar, between 50F and 90F. After Feb-
ruary 1 (or around Sample 1600 shown on
the plot), the actual value rises to as high as
120F (yet is still far below the conventional
monitoring upper threshold limit of 150F),
while the estimate stays at or below 90F. The
bottom graph shows the residual value (ac-
tual minus estimate), which has a mean value
of zero and a normal range of about ±10F.
After Sample 1600, the residual rises to as
much as 40F above the zero baseline.
The problem was easily solved by adding
3½ gallons of oil to the bearing lubrication/
cooling system (of 25- to 30-gallon capacity),
Symptom: Air heatersupport bearing temperature residualincreases to 40F
Diagnosis: Bearings starved of oil
Findings/Fix: Temperature recovered after adding oil to lube oil system
2. Bearing down. This screen shows the predictive monitoring graphs of Plant D’s sec-ondary air heater B support bearing temperature from January 24, 2005 to February 8, 2005. On both plots, the y-axis shows sensor temperature and the numbers on the x-axis are sample numbers. On the top plot, the blue line indicates actual values and the green line is estimated values. On the bottom plot, the blue line shows residuals, the red line marks the zero baseline, and red Xs represent alerts. Source: SmartSignal Corp.
www.powermag.com POWER | May 200840
which quickly brought the temperature back
within spec. This air heater’s support bear-
ings have a very narrow range of acceptable
oil levels as well as a history of operating
problems. This catch led to corrective action
that avoided a possible bearing failure and an
unplanned outage for repairs.
Plant D had suffered an air heater support
bearing failure once before, on July 24, 1998.
The bearing took nine days to replace. Dur-
ing that time, according to North American
Electric Reliability Corp. data, the utility lost
138,800 MWh of generation. Because the
production cost of this unit ranges from $10
to $30/MWh, the utility lost between $1.4
million and $4 million by not having a CM
system on-line.
A second catch of abnormal air heater
bearing temperature was made at Plant A
and put on its watch list on December 10,
2005. Over the next five days, the residual
value of the guide bearing temperature in-
creased 20 to 25 degrees F above expected
values (Figure 3).
The graph shows the actual sensor value
(blue) and the estimated value (green) for the
period of December 10 to December 15. Dur-
ing most of the period, these two values are
similar, between 90F and 130F. But around
midnight on December 10, the actual oil tem-
perature increased to 145F while the expect-
ed temperature was at or below 120F. Note
that the actual value never reached the con-
ventional monitoring upper threshold limit of
150F that would cause the unit’s distributed
control system to sound an alarm.
As in the previous case, a SmartSignal an-
alyst diagnosed the problem as an oil-starved
bearing. Technicians at Plant A determined
that the lube oil pumps had tripped and cut
off the flow of oil to the air heater’s bear-
ings. Once again, the catch and corrective ac-
tion avoided a possible bearing failure and a
forced outage.
The great value of good healthAnalyzing the value of a PM system requires
making an educated guess of how much un-
planned maintenance can be shifted to planned
maintenance by having early warnings of im-
pending problems (Table 2). Each catch of
a potential equipment problem will reduce
maintenance expenses if it is determined that
it is safe to delay any needed repairs until the
next scheduled unit outage. If that is the case,
the repairs will cost less (because they will
not require overtime payments and are likely
to be less complex because the equipment
was not run until it failed), there will be no
losses of generation revenue, and there will
be no need to pay spot-market prices for re-
placement power. ■
—Donald S. Doan ([email protected]) is a senior power plant special-
ist with SmartSignal Corp., a supplier of computer-based applications for analyz-
ing and predicting the operating condi-tion of industrial assets.
Maintenanceexpense reduction
Portion(%)
Portion(%)
MWh revenue improvement Total savings
Major equipment $50,000– $100,000 53 $250,000–$500,000 Up to $650,000 40
Balance-of-plant equipment
$50,000–$100,000 47 $250,000–$1,000,000 Up to $1,100,000 60
Total Up to $200,000 Up to $1,500,000 Up to $1,750,000
Note: Assumes $10/MWh production cost and $32/MWh labor cost. Also assumes that repair times are reduced by 10% by doubling up some maintenance actions, extending overhaul intervals by the same percentage.
Table 2. Estimated savings from early warnings of equipment failure at a 500-MW coal-fired power plant. Source: SmartSignal Corp.
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Where Does the Industry Find Its
Best People?Symptom: Air heater guide bearing temperature residual increases to 25F
Diagnosis: Air heater support bearing starved of lube oil
Findings: Lube oil had tripped off; no oil flowing to bearings
3. Residual effect. This screen shows predictive monitoring graphs of air heater guide bearing temperature at Plant A from December 10 to 15, 2005. On the top graph, the blue line indicates actual values and the green line estimated values. The red Xs represent alerts and the black bar (actually consisting of black diamonds grouped close together) indicates when the incident was placed on the watch list. Source: SmartSignal Corp.
PREDICTIVE MAINTENANCE
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www.powermag.com POWER | May 200842
TRANSMISSION
Boulder to be first “Smart Grid City” The next-generation power grid—enhanced by digital technologies throughout
the network to give generators, distributors, and customers greater con-trol—promises to improve efficiency and lower operating costs. This year, in the most full-scale effort yet, Xcel Energy begins introducing intelligent grid technologies that it hopes will make Boulder, Colo., the first Smart Grid City.
By Angela Neville, JD
Just as the Internet changed the way we
communicate, so will the “smart grid”
transform the way we deliver electric-
ity. The Internet’s success is largely due to
its networking capabilities. In a similar way,
the smart grid will use broadband capabilities
and high-speed computing to revolutionize
the transmission and distribution of power to
end users.
Though the notion has been around for at
least a decade, there’s no consensus about
what constitutes a smart grid. However, the
many government, industry, technology, and
policy groups that have been working to ad-
vance the idea from theory into practice (see
sidebar) do agree that, in general, a smart grid
will use digital technologies to enable inte-
grated, real-time control of all the system’s
elements, from generation to end use.
Future grid featuresIndustry observers agree that the basic way
the U.S. power grid operates has not changed
much in the past 100 years. Now, however,
as a result of electricity deregulation and
market-driven pricing in parts of the U.S.,
utilities are looking for a means to match the
consumption of electricity with its genera-
tion. Many in the industry have a vision of
a fully network-connected power grid that
identifies all aspects of the grid and com-
municates their status and the impact of
consumption decisions to automated deci-
sion-making systems.
The general definition of a smart grid,
according to a recent white paper by power
generation analysts at Xcel Energy, is an
intelligent, auto-balancing, self-monitoring
power grid that takes a variety of fuel sources
(coal, sun, and wind, for example) and trans-
forms them into electricity for consumers’
end use (heat, light, and warm water) with
minimal human intervention. They assert
that it is a system that will allow society to
optimize the use of renewable energy sources
and minimize our collective environmen-
tal footprint. A smart grid has the ability to
sense when a part of its system is overloaded
and reroute electrons to reduce that overload
and prevent a potential outage. Additionally,
it is a grid that enables real-time communi-
cation between the consumer and the utility,
allowing the utility to optimize a consumer’s
energy usage based on that person’s environ-
mental and/or price preferences.
Several utilities have run pilot projects in-
volving one or more smart grid technologies
over the past decade or so. Most common has
been the installation of advanced metering to
enable time-of-use pricing programs that are
designed to shave demand peaks. But Xcel
Energy’s plan appears to be the most all-in-
clusive one yet.
Examples of technology being tested by
Xcel Energy for future use to build intelli-
gence into the power grid are as follows:
■ Neural networks: This project creates a
state-of the art system that helps reduce
Who’s shaping the smart grid?Entities from U.S. federal labs to interna-tional consortia to individual utilities and technology manufacturers are engaged in research, development, policy, and imple-mentation projects geared toward mod-ernizing the electric transmission grid. Here are a few of them:
■ IntelliGrid (http://intelligrid.epri.com), created by the Electric Power Research Institute, focuses on “creating the tech-nical foundation for a smart power grid that links electricity with communica-tions and computer control to achieve tremendous gains in reliability, capaci-ty, and customer services. A major early product is the IntelliGrid Architecture, an open-standards, requirements-based approach for integrating data networks and equipment that enables interoper-ability between products and systems.”
■ Modern Grid Initiative (www.netl.doe.gov/moderngrid) is a joint effort of the U.S. Department of Energy, the Na-tional Energy Technology Laboratory, utilities, consumers, researchers, and other grid stakeholders to “develop a common, national vision to modernize the U.S. electrical grid.” The DOE’s Of-
fice of Electricity Delivery and Energy Reliability (www.oe.energy.gov) spon-sors the initiative and coordinates with other programs such as GridWise (www.gridwise.org) and GridWorks.
■ GridWise Architecture Council (www.gridwiseac.org) was formed by the DOE and seeks to “provide guidelines for interaction between participants and interoperability between technologies and systems.”
■ Smartgrids (www.smartgrids.eu) bills itself as a “European technology plat-form for the electricity networks of the future.”
You know an idea has reached a tipping point when there’s at least one publication dedicated to it. The Smart Grid Newsletter (www.smartgridnews.com) is sponsored by the DOE, the GridWise Alliance, Pacific Northwest National Laboratory, and other entities involved in developing a smart grid. As one article notes, “The Smart Grid will not advance unless most of the 3300 utilities in the United States adopt interoperability standards.” Until then, we may see development of multiple smart grids with different IQ scores.
May 2008 | POWER www.powermag.com 43
TRANSMISSION
boiler slagging and fouling. Boiler sen-
sors plug directly into the plant’s distrib-
uted control system. Neural networks will
model slagging and fouling by using his-
torical data to “learn” boiler behavior.
■ Smart substation: This project is retrofit-
ting an existing substation (Merriam Park)
with cutting-edge technology for remote
monitoring of critical and noncritical op-
erating data. It includes developing an
analytics engine that processes massive
amounts of data for near-real-time deci-
sion-making and automated actions. The
team will monitor breakers, transformers,
batteries, and substation environmental
factors, such as ambient temperatures and
variable wind speeds.
■ Smart distribution assets: This project
tests existing meter communication equip-
ment that can automatically notify Xcel
Energy of outages and help the utility re-
store service more quickly.
■ Smart outage management: This project
tests diagnostic software that uses statis-
tics on eight factors, including equipment
maintenance and real-time weather, to
predict problems on the power distribution
system and create an outage-cause model.
A substation feeder analysis system can
detect and predict cable and device fail-
ures on monitored substation banks.
■ Consumer web portal: This project will
allow customers to program or preset their
energy use for specified devices (such as
air conditioners or dishwashers, for ex-
ample) and automatically control power
consumption based on hourly energy costs
and environmental factors.
■ Wind power storage: This project tests
a 1-MW battery energy storage system
connected directly to a wind turbine at the
MinnWind wind farm in southwest Min-
nesota in an effort to store wind energy
and return it to the grid when it is most
needed. It is expected to demonstrate
long-term emission reductions from in-
creased availability of wind, help reduce
impacts of wind variability, and allow
Xcel Energy to meet renewable portfolio
standard requirements.
In December 2007, Xcel established the
Smart Grid Consortium, bringing together
leading technologists, engineering firms,
business leaders, and IT experts. Consortium
members include Accenture, Current Group,
Schweitzer Engineering Laboratories, and
Ventyx. The group is providing guidance,
products, and services needed to promote the
implementation of Xcel’s smart grid vision
(see sidebar).
Specifically, the consortium partners will
make the following contributions:
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Tomorrow’s grid today“The 20th century grid was built primarily from steels and wires and managed almost exclusively from the supply side. Its pri-mary goal was to deliver electricity in a reliable fashion,” said Robert Pratt, Pacific Northwest National Laboratory (PNNL) project manager for the GridWise project. “The new 21st-century grid model will use information technology to enable cus-tomer-level assets, demand response, and distributed generation and storage to play key strategic roles in creating a cleaner and more affordable energy future.” Cus-tomers will also have more control over how and when they use energy.
Michael Lamb, managing director of IT operations and strategy at Xcel Energy, sees similar contrasts between the current grid and the future grid. “The grid, as we know it today, has not changed signifi-cantly since the days of Thomas Edison,” he said. Customers’ needs and demands, however, have grown exponentially. Ac-cording to Lamb, the 21st-century smart
grid will take the old “analog grid” and create a self-balancing and self-monitor-ing “digital grid” by adding the following:
■ Information technology throughout the energy pathway to integrate power production sources, transmission/dis-tribution, and the consumer’s home or business.
■ High-speed, real-time, and two-way communications.
■ Sensors enabling rapid diagnosis and correction.
■ Dispatchable distributed generation, in-cluding plug-in hybrid electric vehicles, wind energy, and photovoltaics.
■ Energy storage. ■ In-home energy controls. ■ Automated home energy use.
“In ten years, we envision that the technologies tested in Smart Grid City in Boulder will be expanded to other areas throughout our service area,” Lamb said.
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www.powermag.com POWER | May 200844
TRANSMISSION
POwer Mag Ad 2008.eps 3/10/2008 2:49:56 PM
■ Accenture will provide guidance for best
business/consumer outreach practices and
overall IT integration consulting.
■ Current Group will provide the commu-
nications network (broadband over power
lines) to connect all the smart grid compo-
nents and allow them “talk” to each other
(interconnectivity).
■ Schweitzer Engineering Laboratories will
provide substation technology and infra-
structure such as monitors, relays, sensors,
and switches for smart substations.
■ Ventyx will provide work management so-
lutions for deploying the smart grid tech-
nologies by identifying the right tools and
sending the right crews to the right place,
when needed. It will also provide planning
and analytics for price and load forecasts
as well as decision support for connecting
customer actions to trading and invest-
ment decisions in real time.
Boulder leads the wayIn an effort to give its smart grid vision a
face, Xcel Energy has chosen Boulder, Colo.
(Figure 1), to be the nation’s first “Smart Grid
City.” When fully implemented over the next
few years, the planned system will provide
customers with a portfolio of technologies
1. Prototypically Boulder. Boulder’s highly educated residents have long been known as early adopters of progressive ideas and emerging technologies—especially those related to the environment. It’s no surprise that a city that insists on pedestrian- and bike-friendly shop-ping centers (like the recently redeveloped 29th Street Mall pictured here, whose REI store earned one of the first U.S. Green Building Council Leadership in Energy and Environmental Design [LEED] Retail certifications) would embrace the idea of a modernized grid that promises efficient resource use and enhanced customer control. Source: Xcel Energy
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TRANSMISSION
designed to provide environmental, financial,
and operational benefits. Xcel Energy antici-
pates funding only a portion of the project
and plans to leverage other sources, includ-
ing government grants, for the remainder of
what could be up to a $100 million effort.
“We realize this is an enormous task,
which is why we are taking a collaborative
approach to getting it done. Smart Grid City
can only be accomplished with assistance
from all the stakeholders involved and with
the help of our consortium partners,” Michael
Lamb, managing director of IT operations
and strategy at Xcel Energy, said in an inter-
view with POWER in March.
In addition to its geographic concentra-
tion, ideal size, and access to all grid com-
ponents, Boulder was selected as the first
Smart Grid City because it is home to the
University of Colorado and several federal
institutions, including the National Institute
of Standards and Technology, which already
is involved in smart grid efforts for the fed-
eral government.
Smart Grid City (Figure 2) could feature
a number of infrastructure upgrades and cus-
tomer offerings, including:
■ Creation of a communications network
providing real-time, high-speed, two-way
communication throughout the power dis-
tribution grid (via broadband over power
lines).
■ Conversion of substations to “smart” sub-
stations capable of remote monitoring,
near-real-time data collection and com-
munication, and optimized performance.
■ Installation, at the customer’s invitation,
of programmable in-home control devices
and the necessary systems to fully auto-
mate home energy use (Figure 3).
■ Integration of infrastructure to support
easily dispatched distributed generation
technologies (such as plug-in hybrid elec-
tric vehicles with vehicle-to-grid technol-
ogy, battery systems, wind turbines, and
solar panels).
The first phase of Smart Grid City is ex-
pected to be in place by as early as August
2008. Implementation throughout the city
will continue through 2009. The consortium
expects to begin initial assessment of the
technologies in 2009. After initial imple-
mentation and assessment, Xcel Energy will
use the results from this effort to talk with
state, federal, and regulatory officials about a
larger deployment throughout the company’s
eight-state service territory.
“We don’t yet have a full understanding of
the technical and economic challenges that
we will face while implementing the smart
grid system,” said Lamb. “That’s why the im-
plementation of Smart Grid City is so impor-
tant. Boulder will be the nation’s first fully
integrated Smart Grid City and will serve as a
test-bed for how all these technologies work
together.”
Demand-response technologies hold the keySeveral years ago, the U.S. Department of
Energy (DOE) launched an initiative called
GridWise, which promotes the agency’s
vision that in the near future information
technology will profoundly transform the
2. Xcel Energy’s concept of a Smart Grid City. It all depends on a dynamic sys-tem rich in information technology; high-speed, real-time, two-way communications; sensors throughout the grid enabling rapid diagnosis and correction; decision-making data and support for peak efficiency; distributed generation; automated “smart substations”; in-home energy control devices; and automated home energy use. Source: Xcel Energy
3. A smart house. Though many industrial users have for some time had the option of managing their energy budget by participating in time-of-use pricing and voluntary load-shed-ding programs, a smart grid could give residential customers similar—or even greater—control over their energy use. Source: Xcel Energy
Renewable distributed generationPhotovoltaics tied to the grid may even run a customer’s meter backward.
Plug-in hybrid electric carXcel Energy is studying how plug-in electric vehiclescan store energy, act as backup generators for homes, and supplement the grid during peak hours.
Smart meterReal-time pricing signals create increased options for consumers
Smart appliancesSmart appliances contain on-board intelligence that “talks”to the grid, senses grid conditions, and automatically turns devices on and off as needed.
High-speed connectionsAdvanced sensors
distributed throughout the grid and a high-speed communications network
tie the entire system together.
Customer choiceCustomers may be offered an opportunity to choose the type and amount of energy they’d like to receive with just the click of a mouse on their computers.
Smart thermostatCustomers can opt to use
a smart thermostat, which can communicate with the grid and adjust device settings
to help optimize load management. Other “smart devices” could control
an air conditioner or pool pump.
May 2008 | POWER www.powermag.com 47
TRANSMISSION
planning and operation of the power grid.
GridWise envisions a collaborative net-
work—from generation down to customer
appliances and equipment—filled with infor-
mation and market-based opportunities.
DOE’s Pacific Northwest National Lab-
oratory (PNNL) is the national lab most
involved in developing new technologies de-
signed to increase the grid’s ability to provide
energy that is reliable, affordable, and clean.
Robert Pratt, PNNL project manager for the
GridWise project, told POWER that PNNL is
helping with the formation of the GridWise
Alliance, a collection of smart grid industry
leaders and innovators who have been instru-
mental in moving demand response from a
concept to a reality.
In addition, PNNL program leaders are
conducting field demonstrations, such as the
recently completed Pacific Northwest Grid-
Wise Testbed Demonstration of advanced
demand-response network operations. This
year-long demonstration project connected
112 homes with real-time electricity price in-
formation through new advanced meters and
programmable thermostats connected via
Invensys Controls home gateway devices to
IBM software. The final results showed that
participants saved approximately 10% on
their energy bills and did not want to give up
their grid-responsive appliances.
Such demonstrations highlight the benefits
of demand-response technologies, includ-
ing the ability to mitigate peak demand and
increase reliability by making the grid more
flexible and adaptable. They show how bene-
fits could be derived even down to the distribu-
tion system level. Additional benefits include
the ability to provide frequency regulation
services that could make it easier to operate
wind power resources on the grid and thereby
help promote wind power penetration.
“Of note, the demonstrations led by PNNL
gave consumers complete control over how
much and when they participated, by provid-
ing them with simple, automated controls
that responded to real-time (5-minute) prices
reflecting the value of their response to the
grid, and literally sharing some of that finan-
cial value with them as a reward,” said Pratt.
“We feel this will be critical in gaining broad
public acceptance of smart grid technologies
as a natural part of everyday life.”
PNNL also has developed the means to al-
low even small household appliances, such as
clothes dryers and refrigerators, to help keep
the grid reliable. This is done by adding a
simple controller that autonomously senses
a grid frequency or voltage disturbance and
then drops the load for up to a minute or two
to “help out.”
According to Pratt, PNNL has shown in
a field demonstration that this simple device
is reliable and its operation is not noticed by
the consumer. Because enabling this capabil-
ity does not require communications, it can
be inexpensive enough to build it into ap-
pliances at the factory. The result, if enough
appliances were so enabled, could be a vast
safety net to help keep our grid reliable.
Smart metering is the key enabling tech-
nology for demand response. It provides the
hardware necessary to start moving the ball
forward. “Until you can provide an incen-
tive for customers or distributed resources to
collaborate with the needs of the grid, they
won’t,” Pratt said. “And, until you can mea-
sure the degree of that collaboration with
some good time resolution, you can’t offer
those incentives.”
Additionally, PNNL is developing Grid-
LAB-D—an open-source time-series simula-
tion of the smart grid from each individual
appliance all the way up to substation opera-
tions—as a platform for designing technolo-
gies and control strategies and determining
their benefits.
“We are hoping GridLAB-D becomes the
basis for extensive technical collaboration
among researchers and technology develop-
ers engaged in realizing various aspects of
the smart grid,” Pratt said. “We are also look-
ing at how these same smart grid concepts
could be applied to managing the charging
of large numbers of plug-in hybrid electric
vehicles without adding new generation or
T&D capacity.”
Challenges remainClearly, implementation of a smart grid will
force U.S. utilities to deal with several com-
plicated issues.
“First, consumer acceptance will be criti-
cal,” said Pratt. “It is important that they
maintain control and can participate in de-
mand response but do so to their own comfort
level. Nobody wants to feel like the power
company has the ability to control when you
turn the air conditioner on. We found that
even when consumers maintain control you
can engage them enough that they will play
along and reduce peak demand as much as
50% for short periods of time.”
Another looming issue is related to smart
grids’ financial viability. State regulators need
to allow utilities to earn a fair rate of return on
smart grid investments, just as they do with
the traditional grid infrastructure that smart
grid investments displace, according to Pratt.
The PNNL project manager also focused
on challenges related to the increased use of
renewable energy sources, which could nega-
tively affect the smart grid. He pointed out
that in the face of the need to manage car-
bon emissions, there is tremendous pressure
to rapidly bring large amounts of renewable
generation onto the grid. Essentially, that
means wind power in the near term, with ex-
tensive solar photovoltaics (PVs) following,
as costs come down.
“[Renewable sources] add a great deal of
complexity to grid operations. One challenge
with wind power is that it is an intermittent
resource. We can forecast wind to a degree,
but many fluctuations are very rapid, and
other generation must ramp up or down to
compensate,” Pratt said. “Those fluctuations
make a grid that is already hard to operate
that much harder.”
He gave the example that during this past
winter a fluctuation in wind output in West
Texas was so large and rapid that power
plants could not compensate. An unexpected
cessation of wind power caused the regional
transmission authority (ERCOT) to imple-
ment its voluntary load-curtailment program
(which pays industrial users for ramping
down power usage or going off-line tempo-
rarily to reduce load and avoid a blackout).
That event was a tangible example of the
complexity of using intermittent renewable
energy resources.
“One thing we can do with a digital power
grid is to use demand capability to soak up
fluctuations in wind—creating a partnership.
That will help solar, too. Unlike wind power,
solar PVs are usually connected to the grid at
a home or building,” Pratt said. “When there
are enough of them to actually push power
back up the lines toward the substation, new
dynamic schemes for voltage regulation and
short-circuit protection will be required.”
Higher grid IQ benefitsOverall, the transition to a smart grid should
be a positive one for consumers, utilities,
shareholders, and regulators. Consumers
will be able to manage their energy con-
sumption and peak demand by modifying
their electricity usage habits and lifestyle.
The PNNL demonstration project found that
participants were able to accommodate these
changes without bother. Utilities will benefit
by having more-reliable systems, which will
translate into a reduced need for building ad-
ditional capacity. In return, consumers should
get more control over their energy bills.
Customer participation in demand-re-
sponse programs will close the loop be-
tween generation and consumption that
power market economists have yearned for
for years. As a result, utilities will be better
able to manage energy demand with avail-
able resources and, thereby, create higher
financial returns for investors. Automation
and better feedback about individual con-
sumers’ demand and consumption patterns
should lead to more-efficient use of resourc-
es and lower operating costs. ■
www.powermag.com POWER | May 200848
RENEWABLES
A new wave: Ocean powerThe idea of harnessing the vast power of Earth’s oceans has tantalized humans
for more than a century. Today, the prospect of generating as much as 4,000 TW of clean energy from marine sources is fueling a resurgence of interest in a variety of technologies.
By Sonal Patel
Twice a day, 115 billion tons of saltwater
churn in and out of the Bay of Fundy,
a funnel-shaped pocket of the Atlantic
Ocean wedged between the Canadian prov-
inces of New Brunswick and Nova Scotia.
Swelling steadily through the 174-mile jour-
ney to the narrow head of the bay at Minas
Basin, tidewaters can surge to 53 feet—the
highest in the world (Figure 1). More spectac-
ular is the force harbored within these unique
waters as a result of a natural anomaly: The
sloshing effect created by tidal resonance—a
coincidence in the time taken by a large wave
to travel the length of the bay and back and
the time between the high and low tides—can
amplify these tides with enough energy to
supply most of Ontario’s electricity needs.
Despite the sheer power potential of this
region—and others worldwide, such as the
Bristol Channel in the UK, an inlet that
shares similar geographic characteristics—
only one commercial-scale power project has
been implemented in the Bay of Fundy: the
18-MW Annapolis Royal Generating Station
in Nova Scotia. That plant is the sole operat-
ing commercial tidal energy generating sta-
tion in North America, and one of only three
in the world. It shares its barrage technology
with the 1966 Rance River plant in France,
a larger installation with peak power capac-
ity of 240 MW and annual production of 600
GWh, and Kislaya Guba, a 400-kW project in
northwestern Russia. Even the Annapolis sta-
tion did not begin operation until 1984—and
only after several other efforts to construct
tidal power plants in the region had failed.
The idea to harvest tidal energy from the
Bay of Fundy extends as far back as 1925,
when Maine voters approved $100 million to
support hydraulic engineer Dexter Cooper’s
proposed construction of a power plant to
reap power from the tides racing through
Passamaquoddy Bay on the Maine coast.
Around the same time an official feasibility
study was begun for construction of an 800-
MW tidal power scheme on the Severn es-
tuary in the Bristol Channel. But while the
Severn study concluded that the project was
technically feasible, it was thought of as eco-
nomically unsound.
President Franklin D. Roosevelt thought
the Passamaquoddy project would make vi-
tal contributions to the nation’s burgeoning
power needs and granted it $10 million of
federal funding in 1935. Nevertheless, this
project, like many others in the long history
of marine energy, never materialized.
But now, that’s all about to change.
The marine energy renaissanceIncreasing concerns about the environmen-
tal, economic, and strategic costs of relying
on fossil fuels, coupled with the widespread
success of wind and solar power, are giving
new life to hopes of capturing energy from the
oceans. Oceanic bodies—which collectively
cover a little more than 70% of the planet’s
surface—may be a potentially significant,
currently untapped reservoir of energy.
Decades of research and development
have yielded several innovative ways of us-
ing oceans to fuel power generation. They
include wave energy, ocean current energy,
salinity gradient energy, and ocean thermal
energy. Recently, with determined govern-
ments and companies in tow, several ocean
power prototypes have been tested and pilot
plants commissioned.
In 2006, for example, following a 22-year-
long power-project lull in the Bay of Fundy,
the Electric Power Research Institute (EPRI)
of Palo Alto undertook a continent-wide
study and identified four potential sites for
commercial-scale power generation. EPRI’s
list included three passages around Deer Is-
land in Passamaquoddy Bay and Nova Sco-
tia’s Minas Passage.
The study’s results immediately prompt-
ed Nova Scotia and New Brunswick to begin
the site-evaluation process, and three com-
panies secured permits to test their technol-
ogies in the Bay of Fundy. Last year, Nova
Scotia Power announced that, following the
successful installation in the Minas Basin
of a tidal demonstration project by Open-
Hydro, the manufacturer of an open-center
stand-alone turbine, the Canadian utility
plans to develop large-scale tidal farms in
the region.
In addition to being renewable, some types
of marine energy, particularly those that de-
rive generation from waves, or from tidal and
ocean currents, are predictable (which gives
them an edge over wind and solar power).
Tides, determined by lunar gravitational pull,
can be forecast years in advance, and cur-
rents can be mapped by satellite. Doing so
could help guard against blackouts.
Offshore or submerged zero-emission
turbines would also offer an added aesthetic
benefit not enjoyed by offshore wind tur-
bines: invisibility.
Among marine power’s disadvantages
are a host of environmental uncertainties
and a long list of technical hurdles, from
operation to installation. Yet, as the ensu-
ing stream of research and development
yields significant results, it can be said
with some certainty that the fledgling sec-
1. World’s highest tides. During a springtime high tide (top), waters at the head of Minas Basin in the southeastern corner of the Bay of Fundy may surge to heights of 53 feet. At low tide in autumn, much of the bay becomes exposed, appearing like a wide channel of braided rivers (bottom). Depth is in-dicated by dark blue for deep water and purple for shallower water. Source: NASA
May 2008 | POWER www.powermag.com 49
RENEWABLES
tor of marine power is about to grow up
and take off.
The remainder of this article is a survey of
the different concepts currently in use or un-
der development for the extraction and con-
version of marine energy to electricity.
Wave powerCreated when winds—which result from
the planet’s heat differentials—pass on their
energy to the oceans, waves are in essence a
concentrated form of solar energy. According
to an International Energy Agency estimate,
wave energy could supply between 10% and
50% of the world’s yearly electricity demand
of 15,000 TWh.
Several competing approaches have
emerged to convert the kinetic energy of
waves into electricity.
Pelamis. The floating snake-like Pelamis
has already evolved from prototype to oper-
ating unit. Three of these devices collectively
generate 2.5 MW at full capacity at the world’s
first wave farm in Aquaçadora, northern Por-
tugal. The device relies on vertical wave mo-
tion to move articulated joints in the body,
which then pump high-pressure oil through
generator-driving hydraulic motors. A 250-
kW prototype module is 360 feet long and
over 10 feet in diameter. Power-holding com-
pany Enersis has issued a letter of intent for
an additional 20 MW of Pelamis equipment
to expand the wave farm project, and plans are
under way to use Pelamis technology to power
an Orcadian wave farm in Scotland.
Buoy technologies. The buoy concept typ-
ically consists of modular buoy-arrays moored
several miles offshore in choppy waters.
Finerva Renewables’ AquaBuOY converts
the vertical component of waves’ kinetic en-
ergy into electricity by directing pressurized
seawater through two-stroke hose pumps into
a turbine-driven generator. The power is trans-
mitted to shore via an undersea transmission
line. Finerva is developing the first phase of a
2-MW commercial power project site using
this technology in Fiqueria de Foz in Portu-
gal. Construction of a 100-MW wave energy
plant is planned if this project is successful.
Scottish company AWS Ocean Energy
has devised an anchored underwater buoy
generator system using Archimedes Wave
Swing (AWS) technology (Figure 2). The
buoys would drive generators as they bob
with passing waves, and a pressurized gas
cylinder inside the buoy would cause a float
to oscillate based on the pressure differential
of the water depth above as the wave passes.
The AWS buoy was successful in its 2004 pi-
lot test. The company plans to facilitate com-
mercial development and deployment of the
technology using a recent £2 million grant
from the Scottish government.
Ocean Navitas’ technology, known as the
Aegir Dynamo, functions by generating elec-
trical current from wave motion in one phase
via direct mechanical conversion and the use
of a custom buoyancy vessel. Ocean Navitas
has tested a 1-MWh buoy in the Orkneys, in
Scotland, and plans to place a five-buoy array
off the Welsh coast.
Iberdrola Renewables has begun testing
an innovative U.S.-manufactured buoy called
Power Take Off (PTO), which captures and
processes wave energy for storage. The en-
ergy is later evacuated under optimum condi-
tions. The company estimates that an array of
10 PTO buoys could produce 1.24 MW.
Breakwater and shoreline technolo-gies. Voith Siemens Hydro’s Wavegen tech-
nology is integrated into a concrete power
station built on a breakwater or coastal pro-
tection project. Breakwater turbines, each
with an output of between 20 kW and 100
kW, are based on the oscillating water col-
umn (OWC) principle. Waves create oscil-
lations on the water’s surface in a partially
submerged hollow chamber that’s open at the
bottom. The oscillations continuously com-
press and decompress an air column above
the chamber. The difference in pressure con-
verts the rotational energy to electricity via
3. A breakwater turbine. Voith Siemens Hydro’s Wavegen technology employs the oscil-lating water column principle. Courtesy: Voith Siemens Hydro
One turbine per chamber
Wavemotion
Air flow
Decompression
Compression
2. One of the buoys. Buoys using Ar-chimedes Wave Swing technology enjoyed a successful pilot test in 2004. The technology recently won a £2 million ($4 million) grant from the Scottish government. Courtesy: AWS Ocean Energy
www.powermag.com POWER | May 200850
RENEWABLES
a turbine-driven generator (Figure 3). The
world’s first breakwater power station is
currently under construction in Mutriku on
the Atlantic coast of Spain.
Wavegen has also developed the Land In-
stalled Marine Powered Energy Transform-
er (LIMPET), a shoreline energy-converter
that uses an OWC to feed a pair of coun-
ter-rotating turbines, each driving a 250-
kW generator. The current LIMPET model,
Limpet-500, installed on a pilot plant on
Scotland’s Islay island, is being perfor-
mance optimized. If the pilot is successful,
LIMPET will be used to build a series of
commercial power generators.
Floating barge technologies. The Wave
Dragon is a large floating barge with dynamic
turbines that produces energy much as a low-
head hydro power station does. By facing its
outstretched collector arms toward oncoming
waves, the Wave Dragon can concentrate the
wave front toward the ramp at the front of the
structure. This increases the wave height at
the ramp—which acts like a beach, causing
the waves to break over it and into the reser-
voir behind it (Figure 4). Electricity is gener-
ated when water runs through the turbines in
the bottom of the structure. A 7-MW Wave
Dragon device tested in Pembrokeshire in
southwest Wales was commissioned in 2007
(Figure 5) and will be deployed this summer
(see sidebar).
Tidal powerThe most significant difference between
wave and tidal energy is that waves occur
only in water closest to the surface, whereas
the entire water body moves from surface to
seabed in a tide. In tides, moreover, energy
is due to a net movement of water—unlike
waves, where the water acts as a carrier for
energy. Unlike wave energy, therefore, tidal
energy is location-specific.
Although only a few regions in the world
harbor ideal conditions for tidal power, a
range of diverse devices have been designed
and are ready for testing and deployment.
The UK, notably, has surged to the forefront
of the tidal power race, propelled by a re-
cent Sustainable Development Commission
(SDE) report estimate that, considering how
geographically well-suited the islands are to
the technology, tidal energy has the potential
to generate about 10% of the UK’s power.
Barrage systems. The concept of build-
ing dams composed of gated sluices and
low-head hydro turbines across channels to
harness water-level differentials has been
proven productive by long-standing instal-
lations like the Annapolis station in the Bay
of Fundy and La Rance, in France. Costs
and environmental issues aside, research-
ers at Utrecht University in the Netherlands
have deemed the concept feasible and have
proposed that a dam constructed across the
20-mile Bab al Manab strait of the Red Sea
could generate as much energy as 50 GW
(see POWER, January 2008, p. 10).
And now, more than 80 years after the
first feasibility study, the UK government
has renewed its interest in constructing a 10-
mile-long barrage across the Severn tidal es-
tuary running between the English and Welsh
coasts, prompted by an SDE finding that a
location-specific hydroelectric barrier on the
estuary could generate 8.6 GW—meeting
5% of Britain’s power needs. Britain has al-
located £14 million ($28 million) for the fea-
sibility study, which is expected to culminate
in early 2010.
Meanwhile, to reap energy from the Bay
of Fundy, Canadian company Blue Energy
International is advancing technologies used
in tidal dam power with a “tidal fence” con-
cept—a horizontal array of stand-alone verti-
cal-axis turbines. This configuration, which
can capture energy from both directions of
a tide, has so far seen six prototypes and is
currently being assessed by the National Re-
search Council of Canada.
4. Wave Dragon. This floating barge’s de-sign increases the wave height at the ramp, which, like a beach, causes waves to break over it and into the reservoir behind it. Cour-tesy: Wave Dragon Ltd.
ReservoirOvertopping
Turbine outlet
5. Welsh wave power. This Wave Dragon device will generate enough power to supply 2,500 to 3,000 homes. Courtesy: Wave Dragon Ltd.
Moving power from the ocean to land To support the diverse portfolio of emerg-ing designs for the capture and conversion of wave energy, some companies and gov-ernment agencies are developing under-water transmission projects to facilitate prototype testing in a wide range of sea and weather conditions.
The $56 million Wave Hub, situated off the coast of Cornwall in South West Eng-land, acts like a subsea socket for offshore technologies like Pelamis and buoy wave energy converters, sending electricity 10 miles to the grid via an onshore substa-tion. When it is operational in 2009, the Wave Hub will accommodate up to 30 devices and collect and transmit enough power to meet South West England’s tar-
get of generating 15% of its electricity from renewable sources (Figure 6).
6. Taming the tentacles. The Wave Hub is designed to simplify the connection of multiple marine power–generating de-vices to land-based electricity grids. Cour-tesy: Wave Hub
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RENEWABLES
Tidal stream turbines. Making a
marked departure from the traditional bar-
rage system, tidal stream turbines are mas-
sive stand-alone turbines that work much
like wind turbines—but with a much higher
energy density, because saltwater is 850
times denser than air.
In April 2008 the first commercial-scale
tidal turbine from Bristol-based company
Marine Current Turbines, a 122-foot long
inverted windmill dubbed the SeaGen, was
installed in Strangford Laugh, a shallow in-
let in Northern Ireland where tides gush in
at speeds of up to 9 mph (Figure 7). Energy
produced by the 1.2-MW device will be pur-
chased by ESB Independent Energy, a retail
subsidiary of Ireland’s national electricity
company—and one of the first utilities to
provide tidal energy to its customers.
Deep-sea tidal farms. British tidal com-
pany Lunar Energy plans to construct two
deep-sea tidal farms. One would consist of
eight underwater turbines on the sea bottom
in Pembrokeshire, South Wales; the other
would be a colossal 300-turbine field in the
Wando Hoenggan Water Way off the South
Korean coast. The latter project, a collabora-
tion with Korean Midland Power Co., is a $1
billion scheme that extracts power from fast-
moving deep-sea tidal streams. Lunar Energy
will utilize 60-foot-tall Rotech Tidal Tur-
bines, each with a 2,500-ton frame contain-
ing a pump, generator, motor, and electronics
(Figure 8). The project entails a full resource
research and feasibility study, and if success-
ful, it will be operational by 2015.
Ocean current energyOceanic bodies are constantly in motion,
propelled by a variety of factors, including
winds, water temperature, salinity levels, and
the Coriolis force. Surface currents—which
constitute about 10% of all the water in the
oceans—are restricted to the upper 1,300 feet
of the oceans and predominantly derive their
energy from the wind and the sun.
According to the U.S. Minerals Manage-
ment Service, the world’s oceans harbor
about 5,000 GW of power, with densities
of up to 1.5 kW/f2. By some estimates, this
means that capturing just 0.1% of the avail-
able energy from the Gulf Stream—which
has 21,000 times more energy than Niagara
Falls and a flow 50 times that of the world’s
freshwater rivers collectively—could gener-
ate enough power to supply Florida with 35%
of its electrical needs.
Compared with other ocean energy tech-
nologies, the harnessing of ocean current
power is still in its infancy. A handful of pro-
totypes and demonstration units have been
developed, including Hammerfest Strøm’s
submerged wind-like turbines that capture
8. Harnessing tidal power. Each 60-foot tall Rotech Tidal Turbine consists of a 2,500-ton frame containing a pump, generator, motor, and electronics. Courtesy: Lunar Energy
The removable cassette
The gravity base
The generator module
The turbine
The duct
1MW RTT UnitDuct diameter:
15 metersDuct length:19.2 meters
Turbine diameter:11.5 meters
9. Goes with the flow. OpenHydro’s open-center turbine extracts tidal stream energy and will be used in a demonstration project in the Bay of Fundy. Courtesy: OpenHydro
7. First commercial-scale tidal en-ergy turbine. SeaGen’s 52-foot-diameter twin rotors will operate for up to 18 to 20 hours per day off the coast of Northern Ire-land, producing up to 1.2 MW. Courtesy: Ma-rine Current Turbines Ltd.
May 2008 | POWER www.powermag.com 53
RENEWABLES
energy with hydrodynamic, rather than aero-
dynamic, lift or drag. However, developers
of this technology continue to grapple with a
long list of potential problems, from complex
and costly maintenance to the potential dis-
ruption of delicate marine ecosystems.
Open-center turbine. The stand-alone
open-center turbine that features a fixed outer
disk and a rotating inner disk is thought to
suit both tidal stream and ocean current ap-
plications. Gulfstream Energy Inc.’s device is
designed to be anchored to the seafloor, 200
feet below the surface. Installed 5 miles off-
shore in Florida’s Gulfstream, where the cur-
rent flows at an average sustained speed of 3
knots, the turbine could produce an estimated
2.5 MW of power.
OpenHydro’s open-center turbine, on the
other hand, has been applied to the extraction
of tidal stream energy with such promising re-
sults that the company will engage in a dem-
onstration project in the Bay of Fundy. The
device has a self-contained rotor fitted with
a solid-state permanent magnet generator, all
encapsulated within an outer rim (Figure 9).
Salinity gradient energy It has been estimated that 2.6 TW may be de-
rived from exploiting the salinity gradient—
or salt differential—between the world’s
seawater and freshwater. The process, called
pressure-retarded osmosis (PRO), basically
involves pumping seawater at 60% to 85%
of the osmotic pressure against one side of
semipermeable membranes whose other side
is exposed to freshwater.
When freshwater, compelled by osmosis,
flows across the membranes, it dilutes the
saltwater and increases its volume—and con-
sequently, the pressure within the saltwater
chamber. A generator-driving turbine is spun
as the pressure is compensated. (For details
of the PRO process see POWER, November/
December 2006, p. 76.) PRO can be thought
of as the reverse osmosis process (used for
desalination and water treatment) running
backward and producing power from the
flow of freshwater.
A decade of collaborative research and
development by the Norwegian University
of Science and Technology and Statkraft,
a Norwegian power company, has yielded
promising results, including the development
of a high-performance membrane. In 2007,
Statkraft initiated construction on the world’s
first osmotic plant prototype. The plant, at
Tofte on the Oslo fjord, scheduled for com-
pletion by the end of 2008, will produce be-
tween 2 kW and 4 kW of power.
Ocean thermal gradient energyTides and currents aren’t the only poten-
tial energy source we can harness from the
oceans. Oceans also absorb and store tremen-
dous amounts of solar energy. According to
the National Renewable Energy Laboratory,
23 million square miles of tropical seas ab-
sorb an amount of solar radiation equal in
heat content to about 250 billion barrels of
oil—a tenth of which could supply 20 times
the power needs of the entire U.S. on any
given day. The technology for converting this
solar radiation into electrical power is ocean
thermal energy conversion (OTEC), which
exploits the ocean’s thermal gradients—tem-
perature differences of 36 degrees F or more
between warm surface water and cold deep
seawater—to drive a power-producing cycle.
Besides sourcing a clean, renewable re-
serve of energy, OTEC has the potential to
provide many useful by-products such as
freshwater, hydrogen via electrolytic process-
ing of freshwater, and lithium and uranium,
which may be extracted from deep seawater.
Despite these potential payoffs, OTEC devel-
opment has been gradual, primarily because
of competitive operation costs. The technol-
ogy was first proposed as far back as 1881
by a French physicist, and several prototypes
have been tested intermittently since the first
experimental 22-kW low-pressure turbine
was deployed in 1930.
Closed-cycle OTEC. In the closed-cycle
version of OTEC, warm seawater from the
ocean’s surface vaporizes a working fluid
with a low boiling point, such as ammonia,
which then flows through an evaporator. The
vapor expands and turns a generator-driving
turbine. The vapor is then condensed using
cold seawater pumped from deep within the
ocean. The working fluid is continuously re-
cycled within this closed system.
Open-cycle OTEC. In the open-cycle
variant of this technology, warm seawater
becomes the working fluid and is flash-
evaporated in a vacuum chamber, producing
pressurized steam. The steam then expands
through a low-pressure turbine. Cold seawa-
ter condenses the steam, and, if it remains
separated, could supply desalinized water as
a by-product.
Hybrid-cycle OTEC. A hybrid-cycle
OTEC employs features of both the closed
and open cycles (Figure 10). Warm seawater
is flash-evaporated, the steam is used to va-
porize the working fluid, and that fluid drives
a turbine. Finally, steam condenses and pro-
vides desalinized water.
Although components to test the technol-
ogy are widely available, no commercial-
scale plants—or even pilot plants connected
to a grid—exist. The most ambitious proto-
type to date was an Indian research vessel
that carried a 1-MW OTEC plant in 2002.
That effort, a collaboration with the Japanese
company Xenesys Inc. and Saga University
in Japan, was unsuccessful due to a failure of
the deep sea cold water pipe.
Xenesys is determined to power on, how-
ever. It opened a research and development
center dedicated to OTEC last November to
meet what it sees as increased demand as a
result of renewed interest. According to its
web site, the Indian government plans to con-
struct 1,000 OTEC power plants, each 50,000
kW, throughout the country. And the island
nation of Palau is planning to launch a 3,000-
kW OTEC plant; it hopes to make a complete
switch from diesel oil for power generation to
OTEC in the next 10 years. Xenesys said that
it has been receiving offers for research sup-
port and technical collaboration from more
than 50 countries, including South Korea, the
10. Hybrid model. Ocean thermal energy conversion (OTEC) takes advantage of ocean temperature gradients to generate power. In the hybrid OTEC process, warm seawater is flash-evaporated, the steam is used to vaporize the working fluid, and that fluid drives a turbine. Source: National Renewable Energy Laboratory
Steam condenser/ammoniavaporizer
Steam
Spouts
Warm seawater
Liquidammonia pump
Cold seawater
Vacuum pump
Noncondensablegases
Desalinizedwater
Power
Ammoniaturbine
Ammoniacondenser
www.powermag.com POWER | May 200854
RENEWABLES
Philippines, Indonesia, Sri Lanka, Maldives,
Cook Islands, and the United States.
Companies like U.S.-based Sea Solar
Power Inc. (SSP) have also continued to test
and develop key elements of the hybrid Ran-
kine cycle OTEC plant. SSP President James
H. Anderson Jr. penned articles for POWER
as far back as 1965 with his father, J. Hilbert
Anderson, regarding the feasibility and eco-
nomic viability of power harvested from the
ocean’s thermal gradient. The younger An-
derson asserts that the technology continues
to have tremendous potential—that the only
setback it may experience is a lack of interest
from the government.
The Andersons had estimated in 1965 that it
would cost $5.54 million to set up a floating 20-
MW “sea thermal” plant, including the instal-
lation of major equipment and auxiliaries plus
the cost of services such as engineering and su-
pervision. Today, a small but commercial-sized
floating OTEC plant of 20 MW—which could
be built in as little as 39 months—could cost
from $120 million to $190 million.
Energy islandsArchitects Dominic Michaelis and his son
Alex recently proposed in an entry to the
Virgin Earth Challenge (a competition for
solutions to combat global warming) that a
series of floating sea-faring platforms could
be effectively outfitted to reap many forms
of renewable energy. Each “energy island”
would be fitted with wave energy devices,
wind turbines, and solar panels; each could
also harbor a small OTEC plant. With the
right conditions, according to the Michae-
lises, one platform could generate as much as
250 MW of energy.
A decade ago, this idea would have been
considered fanciful. Now, considering the
advantages such a construct could provide in
support of developing renewables, the con-
cept is being taken more seriously.
Last year, Dutch electric company KEMA
and civil engineering firm Bureau Lievense
announced they have been investigating the
technical feasibility and economic viabil-
ity of an artificial “Energy Island” for stor-
ing large-scale energy off the Dutch coast
(Figure 11). The 6.2-mile by 3.7-mile island
would incorporate a fall lake, or a pumped
energy storage (PES) facility.
The method reverses the principle on
which a conventional PES facility works.
When power supply exceeds demand, seawa-
ter is pumped out of the dike-enclosed lake—
which is filled with water 105 feet to 130 feet
below sea level—and back into the surround-
ing sea; when demand exceeds supply, sea-
water flows back in, driving a generator. The
24 square-mile island would potentially store
a capacity of 20 GWh, enough to supply an
average of 1,500 MW to the onshore grid for
at least 12 hours. Several construction com-
panies have expressed interest in building
or designing the island, a project that would
cost about $4.9 billion and take six years to
complete.
Development incentivesGiven that marine energy resources have
the potential to generate 4,000 TW, as esti-
mated by the British government-funded re-
search group Carbon Trust, it is no surprise
that venture capitalists and power companies
are flooding the sector with ready money. In
spite of the fact that marine-generated elec-
tricity currently costs 10 times as much as
electricity produced by traditional sources,
and undeterred by the abundant risks faced
by marine energy firms, private investment
will continue to increase. According to one
projection, marine energy will constitute up
to 20% of Europe’s total renewable resources
by 2020—compared with the 40% projected
for wind power.
Governments, too, are lending their sup-
port to this new wave of power generation.
The UK government and other public-sector
organizations have invested around £15 mil-
lion ($29 million) in the creation of the Eu-
ropean Marine Energy Center, the research
facility committed to help emerging tech-
nologies evolve from prototype to the com-
mercial marketplace. And the EU is backing
the Wave Energy Centre in Portugal, a facil-
ity to provide strategic and technical support
to companies in this field.
Comparatively, U.S. support is lagging.
Despite increased interest in this emerging
sector, the Federal Energy Regulatory Com-
mission has only issued one license, awarded
to Finerva Renewables’ Makah Bay wave pi-
lot project in Washington State. So far this
year, four preliminary licenses have been is-
sued, including two to Pacific Gas & Electric
Co. wave projects off the coast of California.
Last year, though approved by the U.S.
House Science Committee, a marine renew-
able energy and development bill (H.R. 2313)
that would have appropriated $250 million
from 2008 to 2012 was seemingly abandoned
before the House vote. And, echoing the fate
of marine energy research and development
projects born in the Carter and Reagan eras
that lost their funding in the 1980s, the DOE’s
Energy Efficiency and Renewable Energy
2009 budget for its Water Power Program
proposes only $3 million—a 70% decrease
from the $9.9 million Congress appropriated
for 2008.
Marine energy’s futureIf marine energy is to thrive, the monster
hurdle that developers must overcome is the
cost factor. Following an 18-month initiative,
Carbon Trust found in a detailed study of the
cost-competitiveness and potential growth of
wave and tidal stream energy that marine en-
ergy will remain more expensive than other
forms of generation until the sector sees the
installation of hundreds of megawatts of ca-
pacity. Four routes may potentially reduce
costs: concept design developments; detailed
design optimizations; economies of scale; and
lessons learned from production, construction,
installation, operation, and maintenance.
Additionally, future growth of wave en-
ergy will be affected by a range of factors,
among them: strategic and security-of-sup-
ply considerations, the availability of financ-
ing for technology and project development,
technology and risks, electricity networks,
and environmental and regulatory factors. ■
11. Watery “energy island.” One scheme for “offshoring” energy storage uses an un-usual type of pumped energy storage that depends on a dike-enclosed lake—which is filled with water 105 feet to 130 feet below sea level. Courtesy: KEMA
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www.powermag.com POWER | May 200856
NEW PRODUCTS TO POWER YOUR BUSINESS
Upgraded flowmeters for hydroelectric generatorsUniversal Flow Monitors Inc. has upgraded its line of hydro-generation electronic meters used for processing cooling water to turbine bearings. CoolPoint vortex-shedding flow-meters now provide increased flow accuracy and repeatability to ensure consistent cool-ing. They also include a new totalizing capacity for improved process monitoring.
The flowmeters are available in pipe sizes ranging from a quarter inch to 4 inches. These provide 4-20 mA transmitter flow rates, ranging from 0.4 gallons per minute to 600 gpm. Unaffected by silt particles that can clog mechanical meters and erode their seals, the flowmeters are suited to applications where water quality is less than optimal.
Upgrades include a totalizing capability, which increases the device’s ability to measure, monitor, and control the total amount of water used in a process. A flow totalizer with reset button and six-digit LED is also offered as a special option on all CoolPoint pipe sizes. The flow totalizer features a pulse output and a display in either liters or gallons.
Flow accuracy margins of error in CoolPoint models have been reduced to 1% in ½-inch to 2-inch pipe sizes, and 2% on all other models. Flow repeatability differs within 0.25% of actual flow and is standard on all models.
Flow turndown of 20:1 is also an option on ½-inch through 2-inch pipes, up from 10:1 turndown in standard pipe sizes. (Turndown is the ratio of the maximum to the minimum flow rate that a flowmeter can measure.) The increased turndown ratio im-proves users’ capability to detect, read, and record low flow. This presents an advantage when batching and standardizing a single flowmeter model for multiple applications. (www.flowmeters.com)
Ultra-compact pressure transmittersThe new Ashcroft GC51 and GC52 gauge and differential pressure (DP)
transmitters offer the perfect economical alternative to network process transmitters when a digital protocol is not required.
The innovative design features an ultra-compact NEMA 4X/IP65 enclosure measuring only 2.65 inches in diameter. Stainless steel wetted parts accommodate either wet or dry media.
The GC51 is available in ranges up to 7,500 psig, and the GC52 offers DP ranges up to 400 inches of water. A built-in LED dis-
play and a 4-20 mA output provide both local indication and remote signaling. Ashcroft GC series transmitters are ideal for measuring fluid
levels in tanks and water towers and across DP membranes in water purifi-cation systems. (www.ashcroft.com)
O2 and CO2 in the same in-situ analyzerMRU Instruments Inc. recently introduced the OMS420 in-situ O2 and CO2 analyzer, a device that reduces O2 with increased efficiency over traditional O2 in-situ analyzers.
The OMS420 features a modern “hollow probe” design that allows sensors to be changed without removing the probe from the stack. Probes available for temperatures up to 1,200F are 18 feet long and constructed of 316 stainless steel. Probes for tem-peratures of 2,000F are 9 feet long and made of Inconel. (www.mru-instruments.com)
May 2008 | POWER www.powermag.com 57
NEW PRODUCTS
Inclusion in New Products does not imply endorsement by POWER magazine.
Wireless transceiver for point-to-point data acquisition and control The DR9031 wireless transceiver from Wilkerson Instrument Co. provides bidirectional analog and contact closure data transmission to a companion DR9031, where the data is re-covered. Analog data is recovered as two 4-20 mA outputs, and the switch data is provided by optically isolated NPN transistor outputs. The analog inputs available are dual-channel DC voltage or current, single-chan-nel RTD, or strain gauge bridge. The bridge version provides 10-VDC precision excitation for up to four 330-ohm bridges. For single-channel inputs, the two 4-20 mA outputs are both proportional to the single input.
The DR9031 gives users a choice of three radio fre-quencies: two in the 915-MHz ISM band and one in the 2.4-GHz band. All use spread-spectrum frequency-hopping technology. Each RF module offers seven hop se-quences. This allows up to 21 systems to operate in the same locale without interfering with each other. With proper antennas and installation, the 915-MHz units can function reliably over a 20-mile range. (www.wici.com)
High-temperature and high-pressure particulate sensorThe FilterSense Model PS 10 particulate sensor has ceramic insulation and a ceramic protective layer over the probe, making it suitable for harsh processes with high temperatures and high pressures. Temperature ratings of up to 1,600F and pressure ratings of up to 1,000 psi are available for applica-tions such as coal gasification, fluidized-bed reactors, and various combustion processes.
Like all FilterSense sensors, there are no active electronics in the sensor housing, which means high reliability. The sensor is mounted remotely to electronic control units with industrial temperature ratings of 160F. Applications include monitoring particulate emissions from fabric filters and particulate flow in process pipes. (www.filtersense.com)
Two-stage vacuum pump releasedGardner Denver Nash’s new liquid-ring vacuum pump, the AT3006, is a versatile industrial workhorse proven to increase dry air capacity up to 25% in the high vacuum range without an increase in power. Tests have shown that this model offers a higher operating efficiency than the AT3004. (www.gdnash.com)
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READER SERVICE NUMBER 209
Boiler Cleaning ProfessionalsExplosive Deslagging Services • Camera Assisted On-line Blasting • Detonating Cord and Overhead Hazard Blasting • Introducing On-line Video Inspection/Recording of Bundle, Pendant and Wall DepositsGrit-Blasting • Electrostatic Precipitator Field Cleaning • UT and Boiler/Vessel Overlay Preparation• On-line Radiant Recovery with “Shatter Blast” Bead Impact Deslagging“Big Water” High Pressure Washing • Air Pre-heater Baskets, Furnace + Boiler Washing• Heat Exchanger/Condenser Hydro-Laze, Pipeline CleaningVacuum Services, Wet + Dry • Fly Ash, Sludges, Silo + Vessel EvacuationNumber One In Safety and Compliance. Privately Owned and Operated 24/7 Emergency Response From Many US Locations800-866-6247 • www.naisinc.come-mail: [email protected]
READER SERVICE NUMBER 206POWEREQUIPMENT CO.
444 Carpenter Avenue, Wheeling, IL 60090
wabash
24 / 7 EMERGENCY SERVICEBOILERS
20,000 - 400,000 #/Hr.
DIESEL & TURBINE GENERATORS50 - 25,000 KW
GEARS & TURBINES25 - 4000 HP
WE STOCK LARGE INVENTORIES OF:Air Pre-Heaters • Economizers • Deaerators
Pumps • Motors • Fuel Oil Heating & Pump SetsValves • Tubes • Controls • CompressorsPulverizers • Rental Boilers & Generators
847-541-5600 FAX: 847-541-1279WEB SITE: www.wabashpower.com
FOR SALE/RENT
READER SERVICE NUMBER 203
READER SERVICE NUMBER 208
George H. BodmanPres. / Technical Advisor
Office 1-800-286-6069 Office (281) 359-4006PO Box 5758 E-mail: [email protected], TX 77325-5758 Fax (281) 359-4225
GEORGE H. BODMAN, INC. Chemical cleaning advisory services for boilers and balance of plant systems
BoilerCleaningDoctor.com
READER SERVICE NUMBER 205
READER SERVICE NUMBER 204
Want to:❖Store it in silos?❖Reclaim it easily?❖Do it safely?❖Control the flow?
The answer:❖Laidig Systems
TRONA STORAGE
www.laidig.com
Norm Harty - The First and Last Word in Professional Dynamiting, serving you since 1964. We have pioneered, perfected and proven the methods of explosive cleaning the worst of s\lag or ash out in a matter of hours—in all boiler areas. We specialize in Electric Utility work and have over 4000 jobs to our credit. Call the NUMBER ONE COMPANY for the quickest response and most efficient job for your emergency needs and scheduled outages.
N.B. Harty General Contractors, Inc.Phone: 573-624-4645 or 573-624-4588 l Fax: 573-624-4589E-mail: [email protected] l www.nbharty.com
READER SERVICE NUMBER 207
Ryan J.D. TitschPhone: 832-242-1969 Ext.: 311
Mobile: 713-202-7528Fax: 832-251-8963
POWERClassifieds
Get More Attention When You Add Color!
To inquire about Classified Advertising, please contact:
Power Plant Buyers’ Mart
0508 Power Classified.indd 60 4/22/08 2:07:21 PM
May 2008 | POWER www.powermag.com 61
Need a Thorough Mix? Ash, coal, sludges, what do You need to mix?
Get a thorough mix with:Pugmill Systems, Inc.
P.O. Box 60 Columbia, TN 38402 USA
ph: 931/388-0626 fax: 931/380-0319www.pugmillsystems.com
READER SERVICE NUMBER 212
GEGU's - 750 KW Guascor - natural gas fired - 3/60/480 volts (Qty 2)
GTGU’s - 20 MW Brown Boveri oil fired “cheap”
BOILERS - 200,000#/HR Combustion Engineering package - 600# steam pressure - gas fired
- 25,000#/HR ABCO - 150# steam pressure - natural gas and propane fired (Qty 4)
We buy and sell transformers, boilers, steam tur-bine generator units, gas turbine generator units,
diesel engine generator units, etc.
INTERNATIONAL POWER MACHINERY CO.50 Public Square - Terminal Tower, Suite 834
Cleveland, OH 44113 U.S.A.PH 216-621-9514/FAX 216-621-9515
Email: [email protected] Web: www.intlpwr.comREADER SERVICE NUMBER 211
READER SERVICE NUMBER 213READER SERVICE NUMBER 210
READER SERVICE NUMBER 214
0508 Power Classified.indd 61 4/22/08 2:08:07 PM
www.powermag.com POWER | May 200862
visit PLCANYWHERE.COM ® since 1984
from INTERNET anywhere (hotel,airport) w/ no spec software / wireless options REPORTS / maint FLEET notebooksWinCC® ,Wonderware ®, RsView ®, FIX ®201 - 612 – 6700 add live VIDEO
READER SERVICE NUMBER 218
READER SERVICE NUMBER 219
Need Cable? From StoCkCopper Power to 69kv; Bare ACSR & AAC Conductor;
Underground UD-P & URD, PILC-AEIC; Interlock Armor to 35kv; Copper Instrumentation & Control; Thermocouple
Basic Wire & caBleFax (773) 539-3500 Ph. (800) 227-4292
E-Mail: [email protected] SITE: www.basicwire.com
CONDENSER OR GENERATOR AIR COOLER TUBE PLUGSTHE CONKLIN SHERMAN COMPANY, INC.
Easy to install, saves time and money.ADJUSTABLE PLUGS-all rubber with brass insert. Expand it,
install it, reverse action for tight fit. PUSH PULL PLUGS-are all rubber, simply push it in.
Sizes 0.530 O.D. to 2.035 O.D.Tel: (203) 881-0190 • Fax:(203)881-0178
E-mail: [email protected] • www.conklin-sherman.com
OVER ONE MILLION PLUGS SOLDREADER SERVICE NUMBER 216
READER SERVICE NUMBER 217
READER SERVICE NUMBER 215
CFB Boiler • Steaming Capacity: 700,000 lb/hr of superheated steam • Pressure: 1250 psig • Temperature: 1000 °F at main steam stop outlet valve • Feedstock: PRB Coal Fabrication is partially complete. Reduce your project schedule by purchasing the rights to this CFB Boiler.
For complete details please contact: Keith Schick, 720-945-0641
For Sale
Mention Ad #300 to receive 10% off your next order
• Externally mounted• Explosion proof• High accuracy• 2 wire loop powered• No maintenance
• Safe, most economicalway to measurelevel requirements
• Low maintenance• Innovative flipper
design creates strongergauss field
• Oversized flags forvisual indication up to90 feet
Magnetic Level Gage
13960 South Wayside Houston, Texas 77048Toll Free Tel:866.240.9906
Tel: 281.240.0440 Fax: 281.240.2440www.questtecsolutions.com
Magne-Trac
MTLT-5000Magnetostrictive Liquid
Level Transmitter
READER SERVICE NUMBER 220
PRODUCT Showcase
READER SERVICE NUMBER 221
www.powermag.com POWER | May 200862
POweR PlanT BUyeRS’ MaRT
0508 Power Classified.indd 62 4/22/08 2:09:22 PM
Ashross. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63 . . . . . . . . 27 www.ashross.com
Applied Bolting Technology . . . . . . . . . . . . . . . . . . . . . . . . . .17 . . . . . . . . 12 www.appliedbolting.com
Babcock & Wilcox. . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 4 . . . . . . . . . 3 www.babcock.com
Cablesafe Hooks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 . . . . . . . . 11 www.cablesafe.com
Detroit Stoker . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11 . . . . . . . . . 8 www.detroitstoker.com
Emerson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 . . . . . . . . 26 www.emersonprocess.com
Garlock Sealing Technologies. . . . . . . . . . . . . . . . . . . . . . . .19 . . . . . . . . 13 www.garlock.com
GE Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5 . . . . . . . . . 5 www.ge.com/energy
GE Sensing & Inspection Technologies . . . . . . . . . . . . . . . .15 . . . . . . . . 10 www.ge.com/phasorxs
Hach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .41 . . . . . . . . 21 www.hach.com/power
Hitachi Power Systems. . . . . . . . . . . . . . . . . . . . . . . . .Cover 3 . . . . . . . . . 2 www.hitachi.us/hpsa
Lincoln Electric. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25 . . . . . . . . 15 www.lincolnelectric.com
Magnetrol. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23 . . . . . . . . 14 www.magnetrol.com
Membrana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .45 . . . . . . . . 23 www.liqui-cel.com
Mobil Industrial Lubricants . . . . . . . . . . . . . . . . . . . . .Cover 2 . . . . . . . . . 1 www.mobilindustrial.com
Network International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34 . . . . . . . . 19www.onesiteforequipment.com;
www.networkintl.com
Orion Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37 . . . . . . . . . 9 www.orioninstruments.com
Otek Corporation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38 . . . . . . . . 22 www.otekcorp.com
Parkline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .43 . . . . . . . . 24 www.parkline.com
Power Systems Mfg. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31 . . . . . . . . . 7 www.powermfg.com
Schmidt Industries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30 . . . . . . . . 17 E-mail: [email protected]
Siemens Power. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29 . . . . . . . . 16 www.siemens.com/us-sppa
The Shaw Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 . . . . . . . . . 4 www.shawgroup.com
Turbine Energy Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7 . . . . . . . . . 6 [email protected]
Turbocare Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55 . . . . . . . . 25 www.turbocare.com
United Brotherhood of Carpenters . . . . . . . . . . . . . . . . . . . .51 . . . . . . . . 20 www.ubcsuperintendents.com
Wärtsilä . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .35 . . . . . . . . 18 www.wartsila.com
ADVERTISERS’ INDEXEnter reader service numbers on the FREE
Product Information Source card in this issue.
Page
ReaderServiceNumber
CLASSIFIED ADVERTISINGPages 59–62, To place a classified ad, contact: Ryan Titsch, POWER magazine, 832-242-1969,
www.powermag.com POWER | May 200863
ASHROSS RUMig-Rail Car
Low profile, high speed railcar unloading system. In-ground system meant for stationary use.
ASHROSS RUM-Rail Car
Railcar unloading machine, train drives over the RUM, walks off the track by itself. Unloads anywhere, anytime with speed and efficiency.
ASHROSS RC-Reclaimer
Coal reclaimer. Use with dozer or other equipment. Moves the entire pile of coal and reclaims the coal in a fast and efficient manner.
ASHROSS 1260 C-Truck
Self-propelled, mobile, towable drive over unloading system for belly dump and end dump trailers.
ASHROSS ST-Truck
Stationary drive over unloading system for belly dump and end dump trailers.
530 South 250 West • Pleasant Grove, Utah 84062801-785-6464 • Fax; 801-785-6486
www.ashross.com • email: [email protected] Available
COAL HANDLING EQUIPMENTUnload railcars fast and inexpensively
Call today!
801-785-6464
CIRCLE 27 ON READER SERVICE CARD
www.powermag.com POWER | May 200864
COMMENTARY
In mid-2006, a Google search of the term “Smart Grid” gen-erated around 2,000 responses. The same search this past month yielded more than 500,000 hits from a wide variety of
sources. The explosiveness of the concept is especially interest-ing because there is no universal agreement on what constitutes a smart grid—much less agreement on what value a smart grid will provide to the industry and its customers.
The challenges we face in defining and constructing a smart grid are deciding if we are designing a comprehensive smart grid and determining what about our design makes it smart.
Companies pursuing smart grid strategies have defined them as everything from smart meter/advanced meter infrastructure solutions to automated distribution management or integrated SCADA systems. The components being used to build various parts of the smart grid appear to be existing technologies that could be defined as vertical solutions for any number of challenges and opportunities facing our industry. But if we are truly building a smart grid, we need to explore the entire grid, from generation through transmission and distribution—all the way to consump-tion. Further, though creating additional data and information to supplement our operating models will no doubt improve industry performance, does that really make our grid smart?
When you consider other industries and the “smartness” of their products, you look to a cell phone. It identifies where it’s located, selects its signal from multiple options to maximize connectivity performance, and can repeat that process continu-ously while changing its location in a vehicle moving at 60 miles per hour. Though we now take this capability for granted, you’ve got to consider the cell phone “smart,” especially when you look at the size of the package that performs this feat and the lack of human intervention required to accomplish it.
Smart along all dimensionsThe electric grid can’t be considered smart until the entire sys-tem is integrated and we automate everything from generation dispatch to consumption response. Shouldn’t a truly smart grid:
■ Increase reliability by automatically adjusting the system to avoid device stress and failure?
■ Extend asset life and performance by protecting the asset from wide fluctuations in operating demand?
■ Automatically adjust demand to match available supply?■ Integrate environmental, cost, and reliability impacts with
consumer demand decisions?■ Horizontally integrate the grid with real-time data that con-
stantly adjusts the entire system to optimize its performance and our consumption of its output?
Consider how a fully integrated and truly smart grid could impact the challenges we face in the next 25 years. The benefit of providing consumers with a device that automatically adjusts their consumption based on the availability of renewable gen-
eration would mean the 12,000 MW of wind generation currently available in the U.S. wouldn’t require an additional 12,000 MW of available fossil-based generation to exist on the system.
Consider how the automated integration of supply and de-mand, coupled with automated, real-time demand response, could allow the industry to adjust its spinning reserves model. By integrating real-time system monitoring and signaling with customer preferences, we should be able to adjust operation of the system to immediately respond to shifts in demand load. Rather than have system spinning reserves respond to expected consumer demand, let’s consider the possibility that consumer demand responds to system capacity based on any number of inputs, including environmental, cost, or reliability data.
Consider how technology integrated into the devices that con-sume our product would enable consumers to preselect desired consumption levels based on cost and/or environmental impact preferences. While all indicators suggest that consumers are in-creasingly aware of and want to participate in the efficient man-agement of the environment and the cost of electricity, the lack of automated real-time response capabilities and appropriate rate structures significantly compromises their ability to do so.
Smart regulationThe development, deployment, and adoption of the smart grid will also require effective regulatory structures and policies. First we need to address how to support an effective R&D model. While consumers need to be protected from nonaccountable R&D expenditures, we also need to establish effective financial models that support inno-vation that benefits our industry and, ultimately, our customers.
Second, implementation of the smart grid will shift investment dollars from steel and physical infrastructure to technology and software. Effective cost-recovery models need to be established that recognize the difference between traditional infrastructure and technology investment—but first the industry needs to demonstrate that technology investment can be effective and beneficial to our customers.
Third, regulatory models need to incent participation in effec-tive utilization and demand-response programs. Rate structures need to reflect the costs and benefits of responsible consumption and pass those benefits and responsibilities on to consumers.
A change of mind requiredLeaders across our industry are addressing its many challenges by actively embracing the concept of a smart grid, and solution partners are investing in technology to achieve that vision. Let’s not squander the opportunities of the smart grid by remaining stuck in the mental gridlock of how we operate today. Realizing those opportunities requires collaboration and exploration of how we can operate tomorrow. ■
—Mike Carlson, vice president and chief information officer of Xcel Energy, oversees the utility’s smart grid initiatives, including
its first Smart Grid City—Boulder, Colo.
Smart Grid requires clearing mental gridlockBy Mike Carlson
AQCS NUCLEAR SCR TURBINES
BOILERS
www.hitachi.us/hpsa [email protected] Power Systems America, Ltd. 645 Martinsville Road Basking Ridge, NJ 07920 Tel: 908.605.2800
... vertically integrated to meet yourtotal power and environmental generation needs.
HITACHI POWER SYSTEMS AMERICA
Visit us at
BOOTH 1017
CIRCLE 2 ON READER SERVICE CARD
We call these tangible renewable energy credits.
Consider biomass as an energy source for electric power production. Energy from biomass is dependable,dispatchable and readily available. In addition, biomass is CO2 neutral and can reduce plant emissions.
Diversify your fuel portfolio and earn renewable energy credits.
Call 1-800-BABCOCK or visit www.babcock.com.
© 2007 The Babcock & Wilcox Company. All rights reserved.
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