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BUSINESS AND TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRY
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Vol. 152 • No. 3 • March 2008www.powermag.com
How to make friends for a new plant
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COVER STORY: PROJECT MANAGEMENT
28 How to make a power plant a welcome neighborFaribault Energy Park’s developers were able to avoid the controversy that is often associated with power plant siting, construction, and operations. Their experience could help you build your next plant on time and on budget.
SPECIAL REPORTS
WATER TREATMENT
36 Maintaining water sample panels improves plant availabilityOperators who rely only on manual water grab samples instead of data from on-line sample panels run the risk of missing warning signs that the old technique just can’t provide.
INFORMATION TECHNOLOGY46 Wireless technologies connect two LCRA plants
Integrating the O&M staffs of two plants required developing a plan for how they’d communicate. A combination Wi-Fi/WiMAX solution achieved that goal and so much more.
FEATURES
VALVES
52 Desuperheating valves take the heatSelecting hydraulic actuators instead of pneumatic actuators for critical desuperheat-ing valve applications is one way to address cycling-related problems. It can also dramatically reduce start-up times.
WATER MANAGEMENT
60 Benefits of evaporating FGD purge waterEvaporation can completely separate all dissolved species from flue gas desulfuriza-tion purge water. Plus, if the high-quality distilled water produced by the process is reused in the plant, the result is zero discharge of wastewater to the environment.
COMBINED-CYCLE RELIABILITY
64 Extend EOH tracking to the entire plantEquivalent operating hours tracking is the key to enhancing both the maintenance and reliability of all key combined-cycle systems. Try it. Your heat-recovery steam generator will thank you.
EVENTS
68 ELECTRIC POWER celebrates 10th anniversary in BaltimoreUse this preview to begin planning your trip to the can’t-miss event for all players in the power generation industry.
DEPARTMENTS
6 SPEAKING OF POWER
8 GLOBAL MONITOR 8 DOE scraps FutureGen10 U.S. nuclear plants have record year10 Westinghouse wins TVA contract 11 UniStar Nuclear to file for COL 11 AEP ranks second in U.S.
construction 12 China moving to the driver’s seat14 New solar cycle poses risks14 Dutch favor power from natural gas16 POWER digest16 Corrections
18 FOCUS ON O&M18 New CIP standards leave
questions answered21 Solving common analyzer problems24 Qualifying rebuild shops
26 LEGAL & REGULATORY
72 NEW PRODUCTS
80 COMMENTARY
Established 1882 • Vol. 152 • No. 3 March 2008
On the coverYoungsters enjoying a new power plant fish-ing hole are proof of a successful partnership between the developers of Faribault Energy Park and the citizens of Faribault, Minn. By including local residents at each stage of this project and considering site aesthetics, these developers have provided a model for future successful greenfield projects.
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SPEAKING OF POWER
Conservation and the law of the jungle
Ever wonder why many utilities receive so little respect from the public? In America, open competition requires every business to earn customers’ trust before making a sale.
Unfortunately, many utilities exploit their monopoly position to avoid the hazards of competition, including losses. It’s no wonder that public utilities, as a whole, routinely rank near the bottom of surveys that measure consumer trust in U.S. indus-tries. Their low rank is typically a result of questionable business practices and lack of transparency. If this sounds a little harsh, read on.
The challenge of conservationIn my opinion, the most pressing challenge facing utilities these days isn’t the rising cost of nuclear reactor construction or fall-ing pollution limits on fossil-fueled plants. Nor is it the aging workforce, high natural gas prices, or looming carbon controls. Although construction, compliance, and fuel costs are daunting, they are usually rolled into retail rates and life goes on.
The power utilities’ most pressing challenge is the public’s growing interest in energy conservation as a cultural and moral imperative.
It’s axiomatic that when customers of any company start using less of its products, the company must either cut prices to make the products more appealing, develop better products with more features, or both. Firms that are slow to respond to nimbler competitors die a quick death at those competitors’ hands. The law of the jungle means you are either well-fed or on the menu.
Many utility executives believe this law doesn’t apply to them. Some have responded to their customers’ efforts to use less energy by requesting rate hikes to replace revenues lost to conservation—in effect, treating customers as competitors. Such actions only reinforce the public’s perception of utilities as greedy and hypocritical. But if you sell only one, fungible product—electricity—you can’t recoup lost revenues by cutting its price and increasing sales volume, or by developing better electrons. The solution, in utility executives’ minds, is to charge customers for the privilege of using less electricity. That “logic” is beyond comprehension.
Money for nothingHere’s a good example of twisted thinking, utility style. Duke Energy has asked regulators in North Carolina, South Carolina, and Indiana to compensate the company for the effects of its “Save-A-Watt” energy conservation program. Similar rate re-quests are expected in Ohio and Kentucky later this year. The program itself is laudable; it’s the funding approach that needs rethinking.
The Duke Energy Carolinas filing describes Save-A-Watt as a “new regulatory approach to energy efficiency programs . . . that fundamentally changes . . . the way energy efficiency is perceived.” The company suggests that energy efficiency is a
“fifth fuel” that should be considered part of its portfolio of re-sources for sale at a price “for the benefit of . . . customers.” The application argues that Duke should be “compensated similarly for meeting customer demand, whether through saving a watt or producing a watt. The company [should] be compensated for the results it produces.”
There’s another axiom in the business world: The pigs get fat while the hogs get slaughtered. Duke would like rate-increase compensation of truly porcine proportion: 90% of the predicted profits from building generation capacity equivalent to the pre-dicted reduction in demand that conservation would cause. Bear in mind that both predictions are Duke’s. Utilities have been poor predictors of demand, and there’s no reason to believe Duke is better at predicting demand reduction.
I say it’s time for Duke to widen its narrow perspective and use universally accepted business practices to fund its conserva-tion program. The rate cases ask for payment for not pouring concrete. Although the requested surcharges are only tenths of a cent per kilowatt-hour, they’ll be on enough volume to generate for Duke Energy Carolinas an estimated $300 million over the first four years of the conservation program. No customer will avoid the bump; even ratepayers with a five-star, totally green home won’t be able to opt out of Save-A-Watt.
No risk, no rewardBy law, Duke could roll out Save-A-Watt today as an unregulated business venture without waiting for regulatory approval. Few utilities would consider making such a bold move because they are risk-averse and lack the experience to avoid being eaten alive in the unregulated world, where ratepayers can’t backstop poor business decisions.
Duke is entitled to ask for a fair share of the savings that con-servation projects it invests in would produce. In this respect, the company is making an investment similar to that made by a property owner who expects lower electric bills to amortize the cost of buying and installing rooftop solar panels. But in both cases, the investment decision should stand solo, and the rate of return should be based on realistic projections of future savings. That’s how the real world works. Regulators should hold Duke’s conservation projects to the same investment standard that ap-plies to any business: Bad investments reduce shareholder value; good ones produce shareholder profits.
As electric rates have risen nationwide, more private compa-nies have found that investing in energy conservation pays off. It’s time for self-styled “forward-thinking” utilities to walk the talk. They should show some leadership by modernizing their approach to the “business threat” of conservation, rather than insisting on use of the old funding paradigm that does little to protect ratepayers. When a hammer is the only tool you have, every problem looks like a nail. ■
—Dr. Robert Peltier, PEEditor-in-Chief
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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
DOE scraps FutureGenWhat a difference a month makes. No sooner did the FutureGen Alliance an-nounce its long-awaited decision about the location of the zero-emissions dem-onstration plant than the DOE did an abrupt about-face and dropped out of the project, ostensibly due to its rising cost (Figure 1). There is no joy in Mattoon, Ill., these days.
The DOE attempted to soften the blow by noting that the department has de-cided to spread (hedge?) its investment dollars over a broader playing field by fo-cusing on support of the carbon capture and storage (CCS) technology portion of several commercial integrated gasification combined-cycle (IGCC) plants now under development. The aim of the so-called “re-structured” FutureGen remains the same: accelerate the commercial deployment of CCS technology—seen as crucial to the continued use of coal under an economy-wide CO2 cap—at IGCC plants.
The estimated cost of the original Fu-tureGen rose from $1 billion when the project was first announced in 2003 to $1.8 billion today, although the DOE’s cost-share commitment rose “only” from $800 million to $1.1 billion. The depart-ment said it “anticipates” that up to $1.3 billion will be available for the restruc-
tured project, subject to congressional ap-propriations from fiscal year 2007 through fiscal year 2020.
Taking a different path. The DOE quickly released a formal request for information (RFI) seeking expressions of interest from plant developers who would consider par-ticipating in the revised initiative. The RFI notes the restructured program “will help shape a competitive Funding Opportunity Announcement in the second quarter of the year.”
The goals for the new projects remain the same: demonstrate the feasibility and viability of the IGCC-CCS system but “at a commercial scale of at least 300 MW per unit plant power train, per demonstra-tion.” Qualifying projects will be required to demonstrate approximately 90% CO2 capture and storage and the ability to store 1 million metric tons of the gas an-nually in a saline aquifer. However, for these new projects, the DOE will contrib-ute “not more than the incremental cost associated with CCS technology.”
Insulating the department from a re-prise of the inevitable cost escalation of such projects, the RFI stipulates that, “Since under this approach FutureGen is focused on a commercial power train, the project recipient will be responsible for absorbing project cost growths with the
remainder of the plant as it would in any other commercial venture.”
Qualifying plants must be capable of 99% sulfur removal and 90% mercury re-moval. They also must have a nitrogen oxides emission rate of less than 0.05 lb/mmBtu and a particulate emission rate of less than 0.005 lb/mmBtu. In addition, qualifying projects must help establish standardized technologies and protocols for the deployment of IGCC-CCS, including those for CO2 monitoring, mitigation, and verification. Furthermore, the DOE wants projects to demonstrate that IGCC-CCS plants meet commercially accepted oper-ability and reliability standards and can accurately quantify the CO2 storage poten-tial of possible underground reservoirs.
Congress unhappy with decision. The reaction on Capitol Hill was unsurprising. “After our meeting today, it is clear that Secretary of Energy Sam Bodman has mis-led the people of Illinois, creating false hope in a FutureGen project which [the DOE] has no intention of funding or sup-porting,” Sen. Richard Durbin (D-Ill.) said in a written statement. “In 25 years on Capitol Hill, I have never witnessed such a cruel deception.”
Not helping Bodman sooth all those ruffled political feathers was C.H. “Bud” Albright, a DOE undersecretary. During
1. The FutureGen that never will be. It looks as if an artist’s conception may be all we’ll ever see of FutureGen. The DOE abruptly backed out of the project and is now looking to invest in the carbon capture and sequestration portion of several commercial IGCC projects. Source: FutureGen Alliance; modification: Leslie Claire
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a conference call with supporters of Fu-tureGen after the DOE’s retreat from the project, he said the federal government isn’t interested in “building Disneyland in some swamp in Illinois.” Albright’s written apology followed quickly after Sen. Dick Durbin and Rep. Timothy Johnson, R-Ill. excoriated Albright for insulting the Land of Lincoln.
Mickey and Goofy were unavailable for comment.
U.S. nuclear plants have record yearU.S. nuclear power plants posted all-time record highs for electricity production and efficiency in 2007, according to pre-liminary figures released by the Nuclear Energy Institute. U.S. nuclear plants gen-erated approximately 807 billion kWh in 2007, exceeding by more than 2% the previous record high of 788.5 billion kWh set in 2004.
The 104 nuclear plants operating in 31 states also achieved a record-setting aver-age capacity factor of 91.8%, surpassing the 2004 record of 90.1%, according to preliminary figures. For example, Exelon Nuclear’s 17 generating units produced a
total of 132.3 million MWh in 2007—the highest annual production ever for the na-tion’s largest operator of commercial nu-clear reactors. Exelon’s fleet also achieved an average capacity factor of 94.5%—an all-time record for the company and the fifth consecutive year the number has been over 93%.
The industry’s average electricity pro-duction cost—encompassing expenses for uranium fuel plus operations and mainte-nance—also set a record last year. Aver-age production cost was 1.68 cents/kWh in 2007, besting the previous low of 1.72 cents/kWh set in 2005, according to pre-liminary data.
Attesting to the affordability of nucle-ar energy, 2007 was the ninth straight year that the industry’s average electric-ity production cost has been below two cents/kWh and the seventh straight year that nuclear plants have had the lowest production costs of any major source of electricity, including coal- and natural gas–fired power plants.
Electricity production from nuclear power plants was bolstered by the refur-bishment of Browns Ferry 1 in Athens, Ala., which returned to service in May 2007. Tennessee Valley Authority (TVA) completed the 1,155-MW project within its five-year schedule at a cost of about $1.8 billion. The industry also implement-ed plant “uprates,” or power production capacity increases, at two plants: a 55-MW increase at Browns Ferry 1 (Figure 2) and a 13.7-MW increase at Progress Energy’s Crystal River reactor in Florida. Uprates pending for 2008 include 15% power up-
rates for each of the three Browns Ferry units. Approval for them is expected this fall. A total of 912 MW of uprates at 11 individual units are pending approval in 2008, according to the Nuclear Regulatory Commission.
Final figures on the industry’s 2007 per-formance are expected this spring.
Westinghouse wins TVA contractWestinghouse Electric Co., a group com-pany of Toshiba Corp., has won a contract valued at approximately $200 million in support of the completion of Tennes-see Valley Authority’s (TVA’s) Watts Bar Nuclear Plant Unit 2 (Figure 3), located near Spring City, Tenn. When completed, the plant will produce approximately 1,200 MW of power. The TVA estimates the 54-month refurbishment will cost about $2.49 billion.
Westinghouse’s scope includes the up-grade and replacement of most instrumen-
2. New and uprated. The Nuclear Regulatory Commission approved a 5% power uprate for Browns Ferry 1 restart, and Tennessee Valley Authority has an application for 15% power up-rates pending for all three Browns Ferry units. Approval is expected in the fall. Courtesy: TVA
3. Finish what you start. Westing-house will supply reactor components for TVA’s 54-month-long restart of Watts Bar Unit 2. Courtesy: TVA
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tation and control systems, supply of new reactor coolant pumps, steam generator services, crane replacement and upgrades, nuclear steam supply system plant design engineering services, drive rods, licensing services, and safety analysis.
The TVA-planned project duration is 54 months. Commercial operation of the unit is scheduled for early 2012.
Watts Bar Unit 2, originally a West-inghouse pressurized water reactor, was approximately 80% complete when the utility halted construction in 1985, cit-ing a projected decrease in electricity demand. In 2007, TVA announced that it would complete Unit 2 and that Bechtel Power Corp. would lead the engineering, procurement, and construction work.
UniStar Nuclear to file for COLUniStar Nuclear Energy (UNE), a strategic joint venture between Constellation En-ergy and the EDF Group, announced that it has notified the Nuclear Regulatory Commission (NRC) of its plans to submit a combined construction and operating license (COL) application in late 2008 for a potential advanced-design nuclear re-
actor at Constellation Energy’s Nine Mile Point Nuclear Station in upstate New York.
UNE submitted a letter on Feb. 8 to the NRC formally selecting Nine Mile Point as the site for a potential “U.S. evolutionary power reactor” (EPR) (Figure 4). UniStar noted that it has yet to make a final deci-sion to build a new reactor at Nine Mile Point.
“We are working to be in a position to make a decision to break ground for a new reactor at the Calvert Cliffs site at the end of 2008, depending upon the outcome of several issues, including economics and federal loan guarantees,” said Michael J. Wallace, chairman of UniStar and executive vice president of Constellation Energy.
In addition to advanced-design reac-tors in New York and Maryland, UniStar is also working with PPL and AmerenUE, as well as emerging energy companies such as AEHI and Amarillo Power, to develop potential U.S. EPRs in Pennsylvania, Mis-souri, Idaho, and Texas.
AEP ranks second in U.S. constructionAmerican Electric Power’s aggressive pro-gram to install emissions-reduction equip-ment on its existing plants and build new generation facilities has grown to become
4. New NY nuke. UniStar Nuclear has announced its intent to file a combined con-struction and operation license based on the U.S evolutionary power reactor design (shown here in an artist’s rendering) for its Nine Mile Point Nuclear Station. Source: NRC
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the largest in the utility industry and the second-largest in the nation. Those rankings are based on capital invested, according to a November 26, 2007, report in Engineering News-Record. Only Alcoa had more construction in progress last year. In 2007 alone, AEP completed installation of advanced emissions-control equip-ment on 3,500 MW of coal-fueled generation and started and finished construction of a 340-MW gas-fueled power plant.
AEP’s capital investments for generation and environmental retrofits in 2006 and 2007 totaled more than $3.8 billion. A significant portion of that total was committed to installing emissions-reduction equipment on AEP’s generating fleet in West Virginia and Ohio. In West Virginia, the company completed in-stallation of flue gas desulfurization systems, or scrubbers, to reduce SO2 emissions and a selective catalytic reduction (SCR) system to reduce nitrogen oxide emissions on 1,600 MW at the company’s two-unit Mitchell Plant in Moundsville. AEP also in-stalled a scrubber on its 1,300-MW Mountaineer Plant in New Haven.
In Ohio, AEP completed installation of a scrubber on a 600-MW generating unit at the Cardinal Plant in Brilliant. The Cardinal Unit 2 scrubber and associated projects totaled approximately $285 million. Cardinal Unit 2 is owned by Buckeye Power but is operated by AEP. AEP is finishing a second scrubber on Cardinal’s Unit 1 that will be operational this spring. Cardinal Unit 1 is owned and operated by AEP.
AEP’s newest power plant, the Harry D. Mattison Plant, located in Tontitown, Ark., also came on-line in 2007. Two of the four simple-cycle, natural gas–combustion turbines were operational in July 2007. Two additional units came on-line in December 2007. The $131 million plant was completed nearly a year ahead of schedule.
AEP’s construction program will continue in 2008 as the com-pany moves forward with work already in progress to install emissions-reduction equipment at three additional plants. AEP is installing scrubbers on three generating units at Amos Plant in St. Albans, W.Va. (Figure 5). It also has begun work on a third scrubber at Cardinal Plant and is installing a new scrubber, upgrading an existing scrubber, and installing an SCR system at the Conesville Plant in Conesville, Ohio. The Conesville Unit 6 scrubber upgrade will be completed in 2008. The new Conesville
Unit 4 scrubber and SCR should be on-line in 2009. The Amos scrubbers will be completed in 2009 and 2010, and the third Cardinal scrubber will be operational in 2010.
Additionally, AEP will complete 340 MW of new simple-cycle, natural gas–fueled generation in Oklahoma in 2008: 170 MW at its Riverside Plant in Jenks and another 170 MW at its Southwest-ern Plant near Anadarko. The company also will begin work on a 480-MW, combined-cycle natural gas–fueled plant in Shreveport, La., and initiate completion of the 580-MW combined-cycle natu-ral gas Dresden Plant in Dresden, Ohio. Both plants are scheduled to be on-line in 2010.
AEP anticipates finalizing approvals and beginning work on its proposed 600-MW baseload coal-fueled plant in Hempstead County near Texarkana, Ark., in 2008. The company recently re-ceived construction approval from the Arkansas Public Service Commission for the plant. Other regulatory approvals are pend-ing. AEP continues working to obtain approval to build two 630-MW integrated gasification combined-cycle plants: one in New Haven, W.Va., and the other in Great Bend, Ohio.
China moving to the driver’s seatA new study of worldwide technological competitiveness sug-gests China may soon rival the U.S. as the principal driver of the world’s economy—a position the U.S. has held since the end of World War II. If that happens, it will mark the first time in nearly a century that two nations have competed for technology leader-ship as equals.
The study’s indicators predict that China will soon pass the U.S. in the critical ability to develop basic science and technol-ogy, turn those developments into products and services, and then market them to the world. Though China is often seen as just a low-cost producer of manufactured goods, the new “High Tech Indicators” (HTI) study done by researchers at the Georgia Institute of Technology clearly shows that the Asian powerhouse has much bigger aspirations (Figure 6).
“For the first time in nearly a century, we see leadership in basic research and the economic ability to pursue the ben-efits of that research—to create and market products based on research—in more than one place on the planet,” said Nils Newman, coauthor of the National Science Foundation (NSF)–supported study. “Since World War II, the U.S. has been the main driver of the global economy. Now we have a situation in which technology products are going to be appearing in the
5. Billions and billions. Scrubbers are being added to each of the three units at AEP’s John E. Amos Plant in St. Albans, W.Va., as part of the utility’s record-breaking investment in power plant environ-mental upgrades. Amos Units 1 and 2 are rated at 800 MW each; Unit 3 is a 1,300-MW unit. At a total of 2,900 MW, Amos Plant is the largest power plant on the AEP system and one of the largest in the country. Courtesy: AEP
6. Downhill slide for the U.S. The change in the technological standing of these nations is dominated by one feature: a long and con-tinuous upward line that shows China moving from “in the weeds” to world technological leadership over the past 15 years. Source: Georgia Tech Technology Policy and Assessment Center
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marketplace that were not developed or commercialized here. We won’t have had any involvement with them and may not even know they are coming.”
Georgia Tech has been gathering the high-tech indicators since the mid-1980s, when everyone wanted to know which country would be the “next Japan”—a competitive producer and exporter of technology products. The current HTI 2007 information was gathered for use in the NSF’s biennial report, “Science and En-gineering Indicators,” the most recent of which was released January 15.
Georgia Tech’s “High Tech Indicators” study ranks 33 nations relative to one another on “technological standing,” an output factor that indicates each nation’s recent success in exporting high-technol-ogy products. Four major input factors help build future technological standing: national orientation toward technologi-cal competitiveness, socioeconomic infra-structure, technological infrastructure, and productive capacity. Each of the indicators is based on a combination of statistical data and expert opinions.
The 2007 statistics show China with a technological standing of 82.8, compared with 76.1 for the United States, 66.8 for Germany, and 66.0 for Japan. Just 11 years ago, China’s score was only 22.5. The U.S. peaked in 1999 with a score of 95.4.
Recent statistics for the value of tech-nology products exported—a key com-ponent of technological standing—put China behind the U.S. by the amount of “a rounding error”: about $100 million. If that trend continues, Newman noted, Chi-na will soon pass the U.S. in that measure of technological leadership.
On the input indicators calculated for 2007, China lags behind the U.S. In “na-tional orientation” China scored 62.6, compared with 78.0 for the U.S. In “so-cioeconomic infrastructure,” China rated 61.2, compared with 87.9 for the U.S. In the other two factors China also was be-hind the U.S., scoring 60.0 versus 95.5 for “technological infrastructure” and 85.2 versus 93.4 for “productive capacity.”
China has been dramatically improv-ing its input scores, which portends even stronger technological competitiveness in the future.
“It’s like being 40 years old and play-ing basketball against a competitor who’s only 12 years old—but is already at your height,” Newman said. “You are a little better right now and have more experi-ence, but you’re not going to squeeze much more performance out. The future clearly doesn’t look good for the U.S.”
New solar cycle poses risksNational Oceanic and Atmospheric Admin-istration (NOAA) scientists have reported that a new 11-year cycle of heightened solar activity showed signs of beginning when the cycle’s first sunspot appeared in the sun’s Northern Hemisphere. Increased solar activity increases risks for power grids; critical military, civilian, and airline communications; GPS signals; and even cell phones and ATM transactions.
“This sunspot is like the first robin of spring,” said solar physicist Douglas Bie-secker of NOAA’s Space Weather Prediction Center (SWPC). “In this case, it’s an early omen of solar storms that will gradually increase over the next few years.” SWPC is the nation’s first alert for solar activity and its effects on Earth.
A sunspot is an area of highly organized magnetic activity on the surface of the sun. The new 11-year cycle, called Solar Cycle 24, is expected to build gradually. The number of sunspots and solar storms is expected to reach a maximum by 2011 or 2012, though devastating storms can occur at any time (Figure 7).
During a solar storm, highly charged material ejected from the sun may head toward Earth, where it can bring down power grids, disrupt critical communi-cations, and threaten astronauts with harmful radiation. Storms can also knock out commercial communications satel-lites and swamp GPS signals. Routine ac-tivities such as talking on a cell phone or getting money from an ATM machine could suddenly halt over a large part of the globe.
The new sunspot, identified as #10,981, is the latest visible spot to appear since NOAA began numbering them on January 5, 1972. Its high-latitude location at 27 degrees north, and its negative polarity leading to the right in the Northern Hemi-sphere are clear signs of a new solar cycle, according to NOAA experts. The first ac-tive regions and sunspots of a new solar cycle can emerge at high latitudes while those from the previous cycle continue to form closer to the equator.
Dutch favor power from natural gasNews from the Netherlands tells us that the Dutch are very busy building new, high-efficiency gas-fired power stations all over the country (Figure 8). Given Netherland’s extensive natural gas fields in the North Sea, a gas pipeline infra-structure more than 6,300 miles long (in a country less than half the size of New Jersey), and the fact that the country is a net exporter of natural gas to the Eu-ropean Union, its choice of fuels makes perfect sense. Consider the latest three project announcements.
Alstom. Alstom Power won an or-der worth over $580 million from Dutch utility company Electrabel Nederland to build an 870-MW turnkey combined-cycle power plant in Lelystad, located in the center of the country. Flevocentrale will be the first GT26-based combined-cycle power plant built by Alstom in the Neth-erlands. Alstom has been a key player in the Dutch power generation market for a long time; 60% of the electricity gener-ated in the country is being produced by Alstom equipment.
Alstom will design and build a fully in-7. See spot run. The first official sunspot belonging to the new Solar Cycle 24 is shown in the northeast quadrant of Earth’s sun. The large sunspot region just south of the equator is part of the waning Solar Cycle 23. Source: NOAA
8. Dutch treat. Substantial North Sea natural gas resources and extensive infra-structure for moving gas make the fuel a natu-ral for power generation in the Netherlands. Source: About.com, Geography
March 2008 | POWER www.powermag.com 15
tegrated plant and provide the main power plant components, in-cluding two GT26 gas turbines and associated equipment such as steam turbines, turbogenerators, and heat-recovery steam gen-erators (HRSGs). Worldwide, 81 Alstom GT24/GT26 gas turbines are in commercial operation.
Siemens. Siemens Energy Sector will build a turnkey com-bined-cycle plant—a 430-MW facility called Rijnmond II—at the Vondelingenplaat industrial and port facility, approximately two miles south of Rotterdam. The purchaser is the international in-dependent power producer InterGen, headquartered in Burling-ton, Mass.
The scope of supply includes an SGT5-4000F gas turbine, a water-cooled generator, a steam turbine, plus all electrical and instrumentation and control equipment. Following the start of commercial operation, scheduled for mid-2010, Siemens will as-sume responsibility for plant services over a period of 12 years. The order for Siemens, including a long-term service agreement, is worth over $460 million. The entire project is estimated to cost approximately $700 million.
Rijnmond II is the third order for a combined-cycle power plant posted by Siemens since liberalization of the Dutch power market in 2000. The company had already supplied key components for the 820-MW Rijnmond I plant, which began commercial opera-tion in 2004. In early 2007, Siemens secured the contract for the Sloecentrale combined-cycle power plant in Vlissingen Ost.
Mitsubishi. Mitsubishi Heavy Industries (MHI) has received a full turnkey order from Nuon N.V., a major Dutch energy company, for three power trains of natural gas–fired gas turbine combined-cycle (GTCC) systems. Each is rated over 430 MW, for a total of approximately 1,300 MW to be installed at the Nuon Magnum Plant. The GTCC order is Nuon’s second submitted to MHI. The first was the Ijmond blast furnace gas-fired combined-cycle sys-tem delivered in 1997. The new plant is scheduled to produce power in 2011.
Nuon Magnum will be built in Eemshaven in the northern prov-ince of Groningen. The company plans to convert Nuon Magnum to an IGCC plant in the future, which would allow it to be fueled by coal and biomass.
Each train will consist of an M701F4 gas turbine, a steam turbine, generators, an HRSG, and other balance-of-plant com-ponents. MHI will manufacture the gas and steam turbines; Mit-subishi Electric Corp. will manufacture the generators.
POWER digestNews items of interest to power industry professionals.
GE sends four LMS100s to Latin America. GE Energy has re-ceived contracts from three companies totaling over $142 million to supply four 50-Hz LMS100 simple-cycle gas turbines. These are the first sales of the 50-Hz version of this new turbine package that boasts of 44% thermal efficiency.
Pampa Energia purchased the first 50-Hz LMS100 for its Pampa Guemes project expansion in the province of Chubut, Ar-gentina. Commercial operation is expected in the third quarter. Following this purchase, Inversora Ingentis S.A., a special-pur-pose company created by Emgasud and Pampa Holding, purchased two LMS100 units as part of a 500-MW development project that will ultimately generate 400 MW of turbine and 100 MW of wind power.
The Chilean power company Colbun S.A. also recently pur-chased an LMS100 gas turbine unit. Its system will be commis-sioned mid-year at the Los Pinos project near Charrua in Region VIII outside of Santiago, Chile. Colbun has been a power pro-ducer in Chile since 1986 and has both hydro and thermal power
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generating assets. The LMS100’s fast 50-MW-per-minute ramp rate will complement Colbun’s hydro generation in meeting fluc-tuating power demand.
The Chilean power market is very simi-lar to that in deregulated U.S. states in terms of its use of nodal prices and spot markets. Santiago is located in the Central Integrated System (SIC) and has a total capacity of 8.4 GW and a peak demand of 6.1 GW. The SIC power market is supported by roughly 70% hydroelectricity and 25% natural gas and is in need of nearly 600 MW of new capacity annually to meet firm reserve margin needs.
RWE Power to develop new power storage system. RWE Power has signed a memorandum of understanding (MOU) with GE for the joint development and validation of a zero-emission storage technology (advanced adiabatic com-pressed air energy storage or AA-CAES) with higher efficiency than is currently available. The development project is aimed at finding alternative paths for large-scale energy storage in an effort to better align supply and demand.
“The highly fluctuating power input is expected to increase in the future, if only because of the planned massive ex-
pansion of wind energy,” explained Dr. Johannes Lambertz, CEO of RWE Power AG, Fossil-Fired Power Plants portfolio. “Therefore it is important to address this challenge and develop concepts for effi-cient storage in due time.” He continued, “RWE Power and GE will initially conduct a joint feasibility study to be completed by end of 2008. Based on the findings of this study, a first demonstration plant is scheduled for 2012.”
AA-CAES is a zero-emission storage technology with higher efficiency than cur-rently available energy storage solutions. A major challenge will be to develop a compressor technology that can withstand high temperatures during compression and ensure high availability of compressed air energy storage (CAES) for power plants. To prevent this heat from being lost, it is ex-tracted from the compressed air, before the latter is stored in a cavern, and directed to a separate thermal energy storage facility.
“We’re excited about this project be-cause we believe that thanks to GE’s vast experience in compressor technology, we have the capability to study and propose unique solutions as an alternative to the current state of art,” said Claudi Santi-ago, president and CEO of GE Oil & Gas, which will study the compressor technol-ogy required.
Foster Wheeler awarded two CFB boiler contracts. Foster Wheeler Ltd. has been awarded a contract by Harbin Power Engineering Co., Ltd. (HPE) for the de-sign of two CFB steam generators for the second phase of the Cam Pha Power Plant Project in Cam Pha, Vietnam. Commercial operation of the new boilers is scheduled for third quarter 2010.
Foster Wheeler has received a full no-tice to proceed on this contract to design two 150 MW-class CFB steam generators for HPE, a subsidiary of Harbin Power Plant Equipment Group Corp. The two boil-ers are designed to burn waste anthracite and slurry.
Foster Wheeler was also selected to supply two 75 MW-class CFB steam gen-erators for Sinochem Quanzhou Petro-chemical Co. Ltd., located in southeast Fujian Province in the People’s Repub-lic of China. This coke-fired circulating fluidized bed project is part of a major residue processing project by the petro-chemical company. Commercial operation of the new boilers is scheduled for the fourth quarter of 2009.
Pakistan opens new desalination/power generation plant. President Pervez Musharraf inaugurated the Defence Hous-ing Authority’s (DHA) water desalination
and power generation project in mid-Feb-ruary. The project produces 90 MW of pow-er and 3 million gallons of water per day. The power is sent to the distribution sys-tem of Karachi Electric Supply Corp. and the water is for DHA’s needs. The plant’s approximate cost is $115 million.
Siemens Pakistan, Siemens AG Ger-many, and Sweden’s Alfa Laval provided technical assistance. Alfa Laval provided the desalination units, and Siemens Ger-many provided the combined-cycle power plant. The plant consists of a gas turbine, heat-recovery boiler, steam turbine, and two desalination units that produce desal-inated water through the thermal evapo-rative process.
The combined fuel cycle uses exhaust steam from the steam turbine through condensation and distillation. The desali-nation plant uses modern multi-effect de-salination evaporation technology, which makes operation highly efficient.
SWEPCO’s Harry D. Mattison Units 1 and 2 go commercial. American Electric Power’s Southwestern Electric Power Co. (SWEPCO) began commercial opera-tion of Units 1 and 2 of the new Harry D. Mattison Power Plant at Tontitown, Ark., in early January.
Two simple-cycle, natural gas–fired combustion turbines were declared in commercial operation Dec. 28, 2007. For immediate service, the units have an ini-tial combined capacity of 150 MW.
SWEPCO began commercial operation of Units 3 and 4 on July 12, 2007. Those two simple-cycle, natural gas–fueled com-bustion turbines also had an initial com-bined capacity of 150 MW. After testing is completed on each of the two pairs of units in the spring of 2008, the capacity of each pair of units will increase by 20 MW to a combined capacity of 170 MW. When complete, the four units in the $131 million project will have a total capacity of 340 MW.
“The fast-track efforts that brought Units 3 and 4 on line in time for the sum-mer of 2007 have continued in our work to have Units 1 and 2 ready for the sum-mer of 2008,” said Venita McCellon-Allen, SWEPCO president and chief operating officer.
“In less than seven months, the site was transformed from a pasture to an op-erating 150-MW power station, and now all four units are operating and will be ready at full strength of 340 MW for the summer of 2008,” McCellon-Allen said. Wood Group Power Solutions provided project management and construction services for the project. ■
CorrectionsIn our December 2007 issue’s Top Plant article on the Steel Winds Project, p. 53, we should have stated that “wind turbine ratings have gone from 700 kW to more than 2 MW over the past decade.”
In that same issue, on p. 65 in “De-veloping wind projects in California—or anywhere” we lost a decimal point. The Production Tax Credit is 1.9 cents/kWh. Kathryn E. George, a senior economist at Princeton Energy Resources Interna-tional in Rockville, Md., kindly pointed out that the “inflation-adjusted, 10-year, 1.5 cents per kWh [PTC] credit was increased to 2.0 cents per kWh for 2007 for wind energy plants, per Notice 2007-40 of the Internal Revenue Service (May 2007).”
The January 2008 Global Monitor CWA 316(b) conference report provided an incorrect web address for Tetra Tech, which contributed the report. The cor-rect web address is www.tetratech.com.
POWER regrets the errors.
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GRID RELIABILITY
New CIP standards leave questions answeredThis January, the Federal Energy Regu-latory Commission (FERC) issued Order No. 706 approving a set of eight reli-ability standards for critical infrastruc-ture protection (CIP) developed by the North American Electric Reliability Corp. (NERC). The CIP standards require re-sponsible entities (REs) at certain users, owners, and operators of the U.S. bulk power system to comply with specific requirements to safeguard critical cyber assets. In many ways, they are the cen-terpiece of the larger set of NERC reli-ability standards that apply to modeling, protection systems, and facility ratings, among other areas.
Though NERC’s CIP standards are not as stringent as those of the National Institute of Standards and Technology (NIST)—indeed, some consider the latter superior—complying with them could be more costly than complying with other grid reliability standards now in effect. Although, in many cases, the other stan-dards require a more granular and specific documentation procedure for activities, they are more operationally directed and already part of an RE’s routine business. The CIP standards, however, are new to
almost everyone and require a retooling of business practices that could raise costs considerably.
Pay a little now, or a lot later. REs would be wise to pause and think a mo-ment before decrying the potential ad-ditional compliance costs. One can argue that the costs to power genera-tors, transmitters, and distributors pale in comparison with those caused by the 2003 Northeast blackout, a scenario that many fear could be repeated if a substan-tial breach in the security of intercon-nected grid controls were to occur. Even the estimated $8 billion to $12 billion total cost of the 2003 blackout is min-iscule compared with the effect on na-tional security that a widespread service outage would have (Figure 1).
The new CIP standards are a subset of NERC/FERC reliability standards, and the keystone of the CIP group is CIP-002-1 for critical cyber asset identification. As a first step in establishing a list of their critical cyber assets, REs must assess the risk to the integrity of the interconnect-ed grid that their systems’ vulnerabilities represent. The methodology to be used by such a risk-based assessment was to be completed by December 31, 2006. Any user of the bulk electric system that had not developed a methodology by that date was technically out of compliance,
even though the CIP standards were not enforceable at that time.
We can reasonably expect CIP surveys from the REs in the near future. Perhaps FERC itself will gauge an entity’s reli-ability readiness using milestones laid out in its implementation plan for cyber security standards CIP-002-1 through CIP-009-1. Any response to the survey questions that implies an RE was not actively preparing to comply with the standards because it was waiting for the standards to become mandatory is likely not a good strategy.
Who decides what’s critical? Iden-tification of critical cyber assets contin-ues to be the most controversial aspect of the CIP standards. If an RE complies with CIP-002-1 by assessing its system vulnerabilities and the assessment deter-mines that they are not critical to CIP, then CIP-003 through CIP-009 do not apply to the RE. All that remains is to re-run the criticality tests every year and meticulously document having done so.
What remains controversial is the assessment’s methodology. Questions and complaints about it were raised in comments to the notice of proposed rule-making (NOPR) that preceded the Janu-ary final rule. Some commenters said it would be difficult or impossible to meet the assessment requirement of CIP-002-1 when provided with little or no guid-ance on how to do so. Others stated that only an entity with a broad view of the interconnected system could make such a determination, and they asked FERC to have a third party, such as a regional transmission organization, make the call for them.
In paragraph 253 of Order No. 706, FERC responded to the requests for ad-ditional guidance on developing assess-ment methodologies as follows:
The Commission believes that the comments affirm that responsible en-tities need additional guidance on the development of a risk-based assess-ment methodology to identify critical assets. While we adopt our CIP NOPR proposal, we recognize that the ERO [NERC] has already initiated a process to develop such guidance. The CIP NOPR proposed to direct that NERC modify CIP-002-1 to incorporate the guidance. However, we are persuaded by commenters that stress the need
1. Lesser of two evils. The costs to comply with new, mandatory FERC cyber security standards are insignificant compared with those of an outage as widespread as the August 2003 Northeast blackout. Courtesy: NREL
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for flexibility and the need to take ac-count of the individual circumstances of a responsible entity. Thus, we mod-ify our original proposal and in this Fi-nal Order leave to the ERO’s discretion whether to incorporate such guidance into the CIP Reliability Standard, de-velop it as a separate guidance docu-ment, or some combination of the two. A responsible entity, however, remains responsible to identify the critical assets on its system.
Two key points stand out in that pas-sage. The first is that guidance is needed, and that FERC is leaving NERC to decide whether to provide it within CIP-002-1 itself or in what may end up as a refer-ence document. The second point is that the responsibility for identifying critical assets remains with REs.
This second point is more important, for two reasons. First, considering the substantial cost of complying with the entire set of CIP standards, allowing one wholesale market participant to identify the critical assets of a competitor and thereby raise his costs would be an op-portunity that would be hard to resist. Second, leaving the responsibility for identifying critical assets with owners and operators of systems or facilities ensures their engagement in the grid reliability maintenance process. Decisions related to CIP should not be farmed out to a re-gional entity or utility. Ultimately, REs will likely realize that FERC has done them a favor by disallowing another entity from imposing a critical asset identification on
them (Figure 2). Though smaller REs may need help with the wide-area views and base-case modeling that risk-based as-sessments require, such assistance can come from service providers they hire to crunch their numbers in spreadsheets.
Cascading asset outages. Embedded within any risk-based assessment will be some version of the definition of risk noted in Order 706. If one accepts that Risk = Frequency x Consequence, and if Consequence is essentially infinite in the case of a major disruption to the electric grid and associated services, then any Frequency greater than 0 equates to in-finite Risk.
Some have argued that because the grid was designed to withstand an N-1 contin-gency (the loss of any one element), no single generator or transmission element can be operationally critical. In paragraph 256 of Order 706, FERC put this concept to rest with the following language:
While the N minus 1 criterion may be appropriate in transmission plan-ning, use of an N minus 1 criterion for the risk-based assessment in CIP-002-1 would result in the nonsensical result that no substations or gener-ating plants need to be protected from cyber events. A cyber attack can strike multiple assets simultaneously, and a cyber attack can cause damage to an asset for such a time period that other asset outages may occur before the damaged asset can be returned to service. Thus, the fact that the system was developed to withstand the loss of any single asset should not be the basis for not protecting that asset.
Vectors of vulnerability. Close read-ing of the CIP standards and Order 706 gives rise to an intriguing question that REs evidently must answer themselves. The final rule defines critical assets as follows: “Facilities, systems, and equip-ment which, if destroyed, degraded, or otherwise rendered unavailable, would affect the reliability or operability of the Bulk Electric System.” In turn, critical cyber assets are defined as “cyber as-sets essential to the reliable operation of critical assets.”
The theory is that identification of critical assets will lead to identification of those cyber systems that support the critical asset and thus need the protec-tion of the measures of CIP-003 through 009. A key phrase that appeared in the FERC staff’s December 2006 preliminary assessment of NERC’s then-proposed CIP
2. Change in the air. Many respon-sible entities are unsure how to identify their critical cyber assets and are understandably loath to allow others to do so. Courtesy: NREL
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standards, but that is missing in the final rule, is “vector of vulnerability.” Here’s the context of that phrase, as stated in the staff assessment: “It is not the size of an entity that is critical but rather the potential for an entity to become a vector of vulnerability to the security posture of interconnected control systems.”
This raises the question, Can one have a critical cyber asset without having a critical asset? The simple answer is no, because the (operationally) critical as-set must be identified first; then its as-sociated cyber assets can be identified. This begs the question of whether an individual computer (which per se is not a critical asset because it is not used in the day-to-day operation of the inter-connected grid) can be a critical cyber asset. However, the computer—even if it is a lowly laptop that is seldom turned on—could be used to access the local utility’s SCADA controls via the Internet. Destruction of this particular computer would have no impact on the operations of either the RE or the interconnected system. But should the computer still be considered a critical cyber asset because it represents a vector of vulnerability into the grid’s control systems?
This is perhaps an extreme example of the questions remaining to be asked and answered about the CIP standards. Yet REs still must clarify such ambiguities when making their required risk-based assessments.
Fresh air is healthy. Discussions on the development and modifications of all NERC reliability standards take place in an open, public forum designed to solicit comments and address concerns of the stakeholder community. Paragraph 253 of Order No. 706 directs NERC to modify CIP-002-1 to incorporate guidance on risk-based assessment methodology. Ac-cordingly, stakeholders should be atten-tive to publicly posted changes in the standard. They also should either partici-pate in the process by attending drafting team meetings or monitor and comment on developments using NERC’s web site (www.nerc.org).
The CIP standards and their require-ments may have the largest impact of all NERC standards on the integrity of the interconnected system and on the opera-tions and budgets of the system’s users as well. While adoption of the standards will bring huge changes to the industry, it’s important to realize that those changes are not being instigated in a “smoke-filled room” at NERC’s headquarters in Princeton, N.J. They are born in the full
light of day, so REs need only look to see what changes are proposed and comment on whether they would be good for them, CIP, and grid reliability.
—Jim Stanton ([email protected]), POWER contributing editor and director
of NERC compliance for ICF International.
WATER TREATMENT
Solving common analyzer problemsMany plants have common problems with the same kinds of water sample panels
and on-line analyzers. Although every site and sample panel is unique (Figure 3), there are some basic tips and tricks that can be used to address many of those problems. (For the larger context of this issue, see the special report on p. 36.)
High-purity pH analyzer drift. High-purity water (condensate, boiler feedwater, demin water) has low ionic strength. On-line high-purity pH analyz-ers often use salt bridges or reservoirs to boost a sample’s ionic strength. Fig-ure 4 shows one popular high-purity pH analyzer configuration that includes a
4. Worth its salt. A high-purity pH analyzer equipped with a salt reservoir. Courtesy: Nalco
3. Where the action is. The back of a typical sample panel. Courtesy: Nalco
www.powermag.com POWER | March 200822
FOCUS ON O&M
salt reservoir. It’s important to replace salt bridges/reservoirs before they are exhausted. Most manufacturers recom-mend replacing them annually.
It’s also important to remember that most high-purity pH and conductivity analyzers provide more-accurate and -re-peatable readings than wet tests of the same high-purity sample. But this sensi-tivity has a downside: Contact with air changes the pH and conductivity of high-purity samples.
In addition, bench-top pH meters must be calibrated specifically for high-purity water pH measurement. Ensure that your meters either are calibrated with low-ionic-strength buffers or that an ionic-strength booster is added to samples before analysis. It’s best to use two bench-top pH meters: one for high-purity waters and one for low. The high-purity instrument should never be used to measure the pH of low-purity water.
High cation conductivity. Exhausted resin is the most common cause of high cation conductivity (Figure 5). Solving the problem is as simple as replacing the resin before it’s depleted. Plants should maintain a full set of replacement resin on site that’s ready for use. The best
Max
2.0
1.8
1.6
1.4
1.2
1.0
0.8
0.6
0.4
0.2
0.003/23 03/23 03/23 03/24 03/24 03/24 03/25 03/25 03/27 03/27 03/28 03/28 03/28 03/30 03/30 03/30 03/31 03/31
Date 03/23/06 to 03/31/06
Catio
n co
nduc
tivity
5. Shoot the moon. High cation conductivity caused by exhausted resin. Source: Nalco
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FOCUS ON O&M
practice is to maintain the same number of replacement resin sets (or resin volume) in inventory as there are installed cation columns.
Most of the cation conductivity resins in use are sup-posed to change color as they exhaust. Plant maintenance and chemistry personnel rely on this color change to indicate when the resin needs to be replaced. Unfortunately, some-times the color change is subtle, or masked by the effect of a contaminant. For example, iron fouling can make a resin dark enough to obscure the change in hue. Other foulants can cause the resin to stop exchanging even if it’s not exhausted, again masking the color change. If the color of a resin does change, it should be replaced while at least 10% of the resin remains unexhausted.
As a rule of thumb, replace the cation resin any time the cation conductivity consistently reads higher than 2 μS/cm (microSiemens/centimeter). Cation conductivity should never consistently read greater than this value. Finally, for accurate readings of degassed cation conductivity, ensure that the heat-ers are energized or that nitrogen is flowing any time that sample is flowing through the cation column. The degassed reading is supposed to eliminate interference caused by carbon dioxide, but that’s only the case if the small reboiler heaters are energized or if the scrubbing nitrogen is being fed.
Unreliable or highly variable ORP. Oxidation-reduction potential (ORP) analyzers are some of the most difficult to calibrate and maintain, for several reasons. First, the probes themselves are subject to fouling and age rapidly. Most probe manufacturers recommend annual or biannual replacement even if the probe appears to be working correctly. Probe response
tends to slow with age, and periodic replacement minimizes this problem.
Probe response can be verified by monitoring trends closely to ensure that the analyzer’s readings change as expected. Does ORP increase when dissolved oxygen increases? Does ORP de-crease when dissolved oxygen decreases or when a reducing agent (like a passivator) is added?
To calibrate an ORP analyzer, carefully follow the manufac-turer’s recommendations. ORP analyzers should not be offset to agree with dissolved oxygen data or other ORP readings. Off-setting ORP readings tends to throw off the calibration rather than improve accuracy. Instead, instrumentation and control personnel should perform a full calibration if an analyzer’s ac-curacy is suspect. Again, using the proper calibration procedure is essential. Calibration reagents can actually destroy the probe if they’re not properly applied and rinsed.
Finally, evaluate new technologies. New probe designs are in the pipeline and should be available within a year. The newer probes can actually monitor ORP without first cooling the sam-ple. They promise significant improvements in responsiveness and accuracy.
Large deviations in low-range silica readings. This problem doesn’t occur at all plants, but it has at several. Many sample panels use the Hach 5000 silica analyzer for continuous analysis. This model is generally reliable, but it is calibrated with a 500-ppb standard—the lowest-level standard that Hach can supply. The problem is that most high-purity streams have less than 10 ppb of silica, so calibrating the analyzer with a 500-ppb standard would lower its low-end resolution. Some plants see negative silica readings or poor agreement between the wet test results and the on-line analyzer.
Fortunately, there’s a way to address this problem. Plants can create a custom standard (50 ppb is common) by diluting the standard Hach 500-ppb standard with good-quality demin water. Once the custom standard has been created, its concen-tration must be verified using a laboratory spectrophotometer to perform an ultra-low-range silica test on it. Perform the test at least three times and verify that the results read within 5% of each other. If they do, then average the three readings and write this value on the standard bottle. The Hach 5000 accepts custom standards; refer to the manual for the procedure. Enter the value of the custom calibration standard and ensure that the instrument is set for automatic calibration. The unit will calibrate using the new, lower standard and will provide better low-end resolution.
If readings continue to show high deviation with wet test results, closely inspect the reagent tubes for plugs or cracks and check the “pinch” valves for proper operation. The Hach manual provides detailed troubleshooting procedures.
Sodium analyzer calibration drift. Calibrating sodium ana-lyzers can be very difficult. Because many plants lack the under-standing or knowledge to do so, most makers of sodium analyzers offer calibration training. The written calibration procedure pro-vided with the instrument is sufficiently convoluted to stymie even the most-experienced technician. Nalco and Calpine advise plant managers to pay for annual OEM training of operators and techs on the proper calibration of sodium analyzers; it can sig-nificantly improve the reliability and accuracy of readings.
Also bear in mind that sodium analyzers are notorious for losing accuracy during cycling operation or whenever they lose sample flow. Using demin water to maintain sample flow sig-nificantly eases maintenance.
Finally, many plants do not calibrate sodium analyzers at
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FOCUS ON O&M
the manufacturer’s recommended fre-quency. Orion analyzers, for example, generate an error message after 30 days. Many plants continue to operate the analyzer even after receiving this alarm. Calibration drift is inevitable if monoethylamine is used as the buffer-ing reagent. Drift may be minimized if diisopropylamine (DIP) is used instead. DIP is completely volatile, so there is no dilution of the reagent over time. Though this reagent change can mini-mize drift, sodium analyzers must still be calibrated at the frequency recom-mended by their manufacturer.
—Dan Sampson, ([email protected]) of Nalco Co.
PUMP MAINTENANCE
Qualifying rebuild shopsRoutinely rebuilding old centrifugal pumps to their original specs makes no sense, given advances in pump rebuild-ing technology and inevitable changes in system performance over time. A qualified independent rebuild shop with modern design tools and experienced personnel can verifiably offer high-quality upgrades that improve both uptime and efficiency consistent with current system perfor-mance requirements.
Consolidation in the pump industry (Figure 6) is another reason to consider using a rebuild shop. Some pump makers now lack the same level of engineering competence they once had. There have been instances of vendors “downsizing” or “right-sizing” their inspection depart-ment into oblivion. In these cases, the company’s customers pay the price in un-expected pump downtime and even unit outages.
The qualified pump rebuild shop has both the tools and the experience needed to define a scope of work that goes be-yond routine rebuilding or performance upgrading. It takes a lead role in defining the scope of work, and it begins by im-pressing on customers that a reasonably accurate definition will be possible only after a thorough incoming inspection. This task entails logging (on both a paper and a computer document) details such as the pump’s type and model, the location of its plant and its type of service, its direction of rotation, and all of its O&M data.
Once a shop has inspected a pump and logged its salient details, the next steps are to describe its general condition and to propose in greater detail the work needed to rebuild or upgrade it. This pro-cess is called the condition review.
Condition reviews include taking photographs of as-received equipment and close-up shots of parts and com-ponents of special interest. The sizes of end floats and lifts and other detailed measurements are placed on a dimen-sional record form both before and af-ter dismantling the pump. Components are marked or labeled, and hardware is counted and cataloged. Bearings, bush-ings, and impellers are removed. Blasting with beads or steam or another cleaning method is proposed and listed, along with an agreed-on completion date for this preliminary activity.
Nondestructive testing (NDT) is the next possible step, and it should be used whenever appropriate. A good pump re-build shop will issue a form that iden-tifies the chosen inspection method, perhaps using a liquid dye penetrant or magnetic particles. Although space limi-tations preclude a detailed discussion of NDT inspection here, competent pump re-pair shops recognize its importance and usually emphasize its necessity to pump owners.
Some pump condition reviews also include taking readings of electrical run-out at eddy current probe locations and measuring the shaft’s balance and
residual unbalance and the balance of in-dividual impellers. The responsibility for performing these inspections, acceptance criteria, condemnation limits, and other items of interest are listed on a form. Ul-timately, some inspection results also are documented on this form; others go on separate forms.
Recall that the term “form” was de-fined to include both hard-copy and com-puter documents. With this in mind, it should be clear that there will be a need to make a transition from documents that define the initial scope of work to documents that deal with material cer-tification, documentation of as-achieved (or as-built) dimensions, the service fit-ness of auxiliary components, or repair quality. Nonetheless, it should suffice to say that defining the scope of work and the incoming inspection and condition review are important first steps in the pump repair process.
In future articles, we’ll explore ac-tual case histories of pump repairs, both good and bad, and explain how to work with a repair shop to ensure that it re-turns an overhauled pump with a new lease on life. ■
—Heinz P. Bloch, PE ([email protected]) of Process Machinery Consulting.
Sulzer
Ebara
KSB
Goulds
A-C
Vogel
Dresser
I.R.
Wilson
SnyderBWIP
(United
& BJ)
Floway
Warman
Weir
David Brown
Union
Guinard
Sundyne
Kontro
HMD
Sunstrand
Textron
WeirFlowserve/IDP
ITT
6. Fewer options. Consolidation within and among major pump manufacturers contin-ues. Courtesy: Heinz P. Bloch, PE
www.powermag.com POWER | March 200826
LEGAL & REGULATORY
Steven F. Greenwald Jeffrey P. Gray
Renewable power proponents exuded great confidence as the U.S. Congress approached its near-annual end-of-year task of extending the production tax credit (PTC) for wind, solar,
biomass, and geothermal power beyond its current December 2008 expiration. The debate promised to bypass the threshold issue of simply extending the PTC. It was expected to focus on using the PTC to ignite greater and more enduring renewable energy growth by introducing a multiyear PTC extension, PTC “parity” for biomass projects, and a “fix” for misdirected IRS regulations that arbi-trarily deny PTC eligibility for certain biomass operations.
Last year’s events seemed to make it obvious that the U.S. needed to accelerate development of renewable power and extend the PTC to do so. Oil prices approaching $100 and an endless war in Iraq reaffirmed the economic and political imperatives that the nation lessen its fossil fuel addiction. Al Gore’s unprecedented win-ning of both an Academy Award and a Nobel Peace Prize evidenced that reducing greenhouse gases (GHGs) was one more reason to increase renewable power. More states enacted ever-increasing and stringent renewable portfolio standards, and California began implementing AB 32, its comprehensive GHG legislation.
Yet, 2008 began with the unthinkable—no PTC extension. A nation anticipating a Green Christmas of wind, solar, geothermal, and biomass found that congressional Santas had left only a lump of coal in its stockings.
Congress’s faulty logicCongress’s failure to extend the PTC is best rationalized as simply a reflection of our national politics, in which partisanship and parochial considerations override substantive analysis and con-travene supposed national priorities. Two “reasons” for congres-sional inaction on PTC have, however, emerged.
It costs too much. Apparently, some members of Congress de-termined that the PTC extension would “cost too much” because more and more renewable projects, particularly wind farms, are being developed. The potential total of PTC payments is theoreti-cally unlimited: The more renewable megawatt-hours are built, the more the PTC costs the Treasury. However, the idea that the PTC should not be extended because it might encourage “too much” renewable development borders on legislative lunacy. We need not fear an excess of renewables.
The basic premise of the PTC is that the societal benefits of having qualifying renewable generation replace an equivalent amount of fossil-fueled generation outweigh the cost (lower tax revenues). This positive cost-benefit ratio does not decrease even if the PTC incentive generates an infinite amount of renew-
able power. The benefits realized by the marginal unit of renew-able power should outweigh the PTC cost associated with that last unit. It could even be argued that the last increments of renewable power provide increasing benefits relative to the cost of awarding the PTC.
The fallacy of the cost defense is further exposed when the question, “Costs compared to what?” is asked. The short- and long-term consequences of continuing to rely on fossil-fueled generation overwhelm the costs of awarding incremental PTCs.
Federalism. The current 2008 PTC expiration can also be in-tellectualized as an appropriate exercise of federalism. If certain states (“Green States”) perceive the advantages of renewable power, but certain other states (“Brown States”) question its cost-effectiveness, one might argue, it is appropriate for Con-gress to defer, allowing each state to make its own economic assessment. Why should a state endowed and content with coal subsidize manure-to-electricity projects in California? If Green States want green power, their ratepayers and taxpayers should pay their own way, without citizens in Brown States subsidizing “this latest passing fancy.”
The simple response to this isolationist position is that we no longer have the luxury of framing the economic, environmental, and geopolitical challenges of fossil fuel use as local issues. Only an integrated national policy has a chance of succeeding.
Moving beyond the 2007 PTC failureThe (hopefully temporary) death of the PTC extension under-scores how difficult it is to successfully implement an energy policy that reduces fossil fuel use. Two things are necessary.
First, we need credible and consistent means of making eco-nomic choices between alternatives. To that end, costs for a program must be objectively and quantitatively compared with the costs of alternatives, including inaction; one-dimensional “it costs too much” arguments should not determine the outcome of our energy debates.
Second, Washington must embrace the political reality that energy policy is an imperative national issue that cannot be delegated to 50 state legislatures and regulatory commissions. Our success (or failure) in responding to energy exigencies has national and global consequences that Congress is singularly ca-pable of addressing.
One early lesson of the 21st century is that we need more than a convenient “union” of “Blue States” and “Red States” to fulfill the promise of this United States. Most certainly with respect to the PTC and other critical energy issues, Congress cannot abdicate its responsibilities to the idiosyncrasies of “independent” Green States and Brown States; the necessarily integrated and comprehensive national policy can only emerge from the United States. ■
—Steven F. Greenwald ([email protected]) leads Davis Wright Tremaine’s Energy Practice Group. Jeffrey P. Gray (jeffgray
@dwt.com) is a partner in the firm’s Energy Practice Group.
Congress failed to deliver a green Christmas By Steven F. Greenwald and Jeffrey P. Gray
The idea that the PTC should not be extended because it might encourage “too much” renewable development borders on legislative lunacy.
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for electricity will call for new power plants fired by reliable fossil fuels. And when it comes to building
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www.powermag.com POWER | March 200828
PROJECT MANAGEMENT
How to make a power plant a welcome neighborDeveloping power projects has become less a technical challenge and more
an exercise in developing good relationships among all the stakeholders. If a community understands the need for a new plant and is involved in its development process, the odds of a successful project increase.
By Derick Dahlen, Avant Energy, and Dave Pokorney, Minnesota Municipal Power Agency
When asked to imagine a power
plant, most people’s mental imag-
es don’t include families dangling
fishing poles into cooling ponds or kids mov-
ing among educational displays that explain
alternative forms of energy generation. But
that’s exactly the scene that’s unfolding at
Faribault Energy Park, the newly opened
combined-cycle plant in southern Minnesota
(Figure 1).
The result of such features has been a
decidedly welcoming attitude from city
officials, the citizenry, and the media in
Faribault, Minn., a town of 22,000 less than
an hour from the Twin Cities of Minneapolis/
St. Paul, which influence the town’s attitudes
and media.
The warm reception wasn’t unexpected.
As project developers, we took very specific
steps to ensure that we secured community
buy-in throughout the process. Although
our business objectives were to generate ef-
ficient, affordable power, we strongly felt
that we could do so while generating support
from the host community.
At Faribault Energy Park, we were able to
avoid the controversy that is often associated
with power plant siting, construction, and
operations. Our experience could help you
build on time and on budget.
Not in my back yardThe familiar NIMBY (Not in My Back Yard)
factor is an everyday irritant in the plant sit-
ing business and frequently stops projects in
their tracks. Everyone in the power industry
knows how opponents, contrarians, or activ-
ists from within (or beyond) the commu-
nity can affect a project either through the
courts or by tipping public opinion against
a project. Even a mild delay will decimate a
project schedule, increase construction costs,
and even cause a regulatory body to hesitate
before granting an approval. In the extreme,
project delays have been known to cause in-
vestors and owners to cancel a project.
Opponents can make life extremely un-
comfortable for facility developers. One
opponent to a plant in Ohio described the
proposed facility in memorable terms as “a
toxic millstone around the neck of the com-
munity.” A critic of a Massachusetts plant
was quoted as saying, “By its very nature,
the plant would bring harm to the city.” Op-
ponents know how to strike a blow, don’t
they? These criticisms were aimed at well-
designed, technologically advanced plants,
but hyperbole that’s not held to a standard of
truth has caused considerable delays to and
cancellations of many projects. The NIMBY
scenario has played out in every region of the
country and around the world.
Then why, in Minnesota, was our plant’s
grand opening attended by approximately
5,000 people from throughout the region?
Why were families willing to spend part of
a sunny fall Saturday at a power plant? Why
did city officials cheerfully and proudly par-
ticipate in the ribbon-cutting at a community
celebration?
First and foremost, it’s because we devel-
oped a facility with an appealing package of
environmental and community benefits. But
beyond that, it’s because we implemented
a campaign designed to communicate to
people in Faribault and throughout the Twin
Cities area that the facility would be a long-
term asset to the community and an environ-
mentally responsible good neighbor.
Not just a plant but a parkThe first step in developing the project was
our analysis in 2001 and 2002 that clearly
showed additional power was required in
south-central Minnesota, especially during
peak periods.
Site selection was next. We ticked off
1. Picture perfect. Aesthetic appeal was an important consideration in the design of Faribault Energy Park that resulted in including oversized tinted windows, stone facing, and attractive landscaping. Courtesy: Avant Energy
www.powermag.com POWER | March 200830
PROJECT MANAGEMENT
items on the standard list: access to the grid,
access to a fuel source, access to water sup-
plies, reasonable land costs, appropriate zon-
ing, and a welcoming community. But we
knew that a “welcoming community” could
not be taken for granted. Even communities
hungry for economic development can look
askance at a power generation facility.
The City of Faribault calls itself “a dy-
namic, growing city” and is situated at the
confluence of the Cannon and Straight Riv-
ers in southern Minnesota. It was an obvious
choice for a combined-cycle plant because a
natural gas pipeline and a 115-kV Xcel En-
ergy transmission line are located near the
boundary of a healthy, expanding industrial
park. (See sidebar for the plant specs.)
We knew that a community would wel-
come us only if we had a better message
than, “We’re here to build a power plant in
your town.” Avant Energy (formerly Dahlen,
Berg & Co.) brought to the board of the Min-
nesota Municipal Power Agency (MMPA)
the concept of creating the plant as a com-
munity asset. The Avant concept includes
seven rules for integrating a facility into the
community in a positive manner:
■ Look beyond power generation. The over-
arching philosophy behind the project
needs to answer the question, “What’s in
it for the community?” The answers must
deal with the obvious, such as providing
power and jobs, but they must also ad-
dress things the community cares about:
aesthetics, environmental footprint, eco-
nomic benefits, and how the plant will
support the future of the community.
■ Communicate clearly. Configure the
project to make it a true asset to the com-
munity and tell the story in an honest,
straightforward, and effective manner.
■ Treat the community as a partner and neigh-bor. Listen to what citizens are saying.
■ Recognize that choice of language is im-portant. Naming the facility was a key
consideration. Avant suggested Faribault
Energy Park because “energy park” is
symbolic of the plant’s well-maintained
and park-like appearance and its accessi-
bility to the public for walking, relaxing,
bird-watching, and even fishing.
■ Make the plant attractive. A master land-
scaping plan included attractive plantings
surrounding plant buildings, plus land-
scaped areas surrounding holding ponds
that featured walking paths and educa-
tional displays.
■ Design it to be green. Minnesota’s citi-
zens are highly sensitive to environmental
issues, so the plant had to be designed as
“green” as technologically possible. That
Faribault Energy Park profileOwner and developer: Minnesota Municipal Power AgencyDesign and construction management and operations: Avant Energy (formerly Dahlen, Berg & Co.), MinneapolisProject objective: Meet regional energy needs while serving as a model of energy efficiency, environmental stewardship, and inte-gration into the Faribault community.Construction phases: Developed in two phases to satisfy the need for peak energy during the summer of 2005. Initial simple-cycle phase became operational in May 2005, producing 165 MW. Combined-cycle phase was completed in October 2007, producing an additional 100 MW.Plant cost: $180 millionMajor equipment suppliers:■ GE Frame 7FA combustion turbine generator, dual fuel, inlet air
evaporative cooling with natural gas as the primary fuel.■ CMI/Aalborg three-pressure heat-recovery steam generator
equipped with supplemental firing of natural gas, fuel oil, or vegetable oils in duct burners and selective catalytic reduction for emission controls.
■ GE A10 steam turbine generator.
Key plant features:■ Water management includes a recovery and filtration system
that stores rainwater from the 35-acre site.■ Alternative fuel sources will be renewable, including recycled
vegetable oil, soy oil, and camelina oil.■ Number 2 fuel oil is a back-up fuel source.■ Storage for 325,000 gallons of fuel oil and 325,000 gallons of
other fuels.■ Dry low-NOx system.■ Steam turbine condenser cooled by wet cooling tower of 82,500
gpm capacity.■ The steam turbine generator has 100% steam bypass
capability.■ Architectural appeal includes striking three-story windows, ex-
terior stone facing, and first-class office, meeting, and locker room facilities.
■ Community access features include a classroom with views into the control room and plant, plus landscaped areas sur-rounding holding ponds that feature walking paths and edu-cational displays.
2. Multi-fueled gas turbine. A GE Frame 7FA combustion turbine generator being installed in Faribault Energy Park. The plant will also burn recycled vegetable oil, soy oil, and camelina oil. Courtesy: Avant Energy
March 2008 | POWER www.powermag.com 31
PROJECT MANAGEMENT
included minimizing emissions, handling
water wisely, and building in the capabil-
ity to burn renewable fuel sources, such
as vegetable oils (Figure 2, p. TK). The
plant needed to be designed in ways that
would allow a positive environmental
story to be told.
■ Communicate with the community early and often. We offered educational op-
portunities for the community and de-
signed the facility to enable school and
other community groups to tour the fa-
cility, learn about energy generation, and
enjoy the property. A Web site, www
.FaribaultEnergyPark.com, was devel-
oped to provide project information and
a link through which citizens could ask
questions.
Avant’s proposal resonated with the
MMPA board, which comprises city officials
and utility managers from 11 communities in
south-central Minnesota—people who could
identify their own cities with Faribault.
Openness from day oneA facility of this nature must be well-
designed, with the community in mind, in
order to be accepted by a host city. A key el-
ement of getting the plant built on time and
on budget was anticipating community con-
cerns and addressing them in advance.
Those of us in the power generation busi-
ness aren’t necessarily born to be erudite
spokespersons for a project. We’re practical
people—focusing on technology, engineer-
ing, and the bottom line. But when we’re
bringing a high-impact project into a com-
munity, we need to learn to be communi-
cators as well. Early in the process—after
identifying Faribault as the optimum loca-
tion for the facility—we decided to seek the
expertise of communications professionals.
They helped us take several steps:
■ We created a communications plan so that
we could make an orderly, logical entry
into the community. Communications
were to always be honest, forthright, and
transparent.
■ We translated our engineering-speak into
well-written, convincing messages to help
us tell our story to the community.
■ We sought out and identified likely advo-
cates and allies for the plant and we then
met these people individually and in small
groups.
■ We met very early in the process with
editors and reporters from the city’s
daily newspaper and clearly laid out our
plans for the project. We talked about the
community benefits and favorable envi-
ronmental profile of the plant. We also
explained the need for more power gen-
eration in the region.
■ We anticipated possible objections from
the community and environmental activ-
ists and developed articulate and well-
thought-out responses.
Push the envelopeThis up-front work wasn’t always easy. It’s
not necessarily natural for those of us who
are engineers and business people to put our-
selves in front of members of the commu-
nity, risking criticism for what we know to
be a smart, responsible plan of action. But it
was worth it.
Our open communication with the commu-
nity was also part of our regulatory approval
strategy. Demonstrating a quantifiable need
and presenting a responsive and responsible
plan for addressing it made gaining regula-
tory approval a relatively smooth process.
Above all, we became comfortable with
articulating our vision: that we could build
much more than a power plant. We were
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www.powermag.com POWER | March 200832
PROJECT MANAGEMENT
building an energy park that would be a long-term asset for the peo-
ple of the community as well as a source of needed power. And, in
the bargain, we could produce power that is efficient and affordable
in an environmentally friendly manner.
Telling the environmental advantages of combined-cycle technol-
ogy was an important part of our Faribault Energy Park message.
The environmental story became a compelling one, consisting of:
combined-cycle efficiency, low emissions, renewable fuel capabil-
ity, quiet operation, efficient water management, and an appealing
wetlands area accessible to the public.
When you are telling the story of your new plant to the public, it’s
important to catalog all the environmental advantages—and perhaps
create some new ones, such as environmental education—to be able
to assemble a credible, compelling environmental story.
Constructing the plantAvant Energy was also the construction manager, which helped us
maintain consistency from the site selection and design processes.
We knew that the good relationships built with the Faribault com-
munity during the preconstruction stage could be lost or damaged if
we didn’t live up to our word to be a good neighbor during construc-
tion. Several actions helped us preserve a positive relationship with
the community:
■ We hired a veteran construction project manager to be the on-site
trail boss of this project.
■ We went to the Minnesota construction trade unions and let them
know we were committed to utilizing the quality and reliability pro-
vided by the local trades. The result was a positive working relation-
ship among all the trades throughout all phases of construction. The
trades exhibited a remarkable degree of collaboration and contrib-
uted greatly to the project meeting its objectives (Figure 3).
■ We maintained a flow of communication with the community. We
3. Construction team. Workers and tradespeople who built Faribault Energy Park gathered with their families for a group picture at the grand opening. Courtesy: Avant Energy
CIRCLE 18 ON READER SERVICE CARD
X_ award08 ad.indd 1 2/25/08 7:51:38 AM
Plant of the Year: Iowa
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IS YOUR PLANT A WINNER?You won’t know unless you nominate it for POWER magazine’s annual awards. Plants anywhere in the world have three chances to win!
The Power Plant of the Year award will be
presented to a plant that leads our industry in the
successful deployment of advanced technology—
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X_ award08 ad.indd 1 2/25/08 7:51:38 AM
www.powermag.com POWER | March 200834
PROJECT MANAGEMENT
offered to speak at community functions,
we joined and participated in Chamber of
Commerce meetings, and we invited city
and legislative leaders to tour the site. We
were open to the media and let them know
of important construction milestones. We
continued to talk about the economic and
environmental attributes of the project.
And we listened.
■ We ran a clean, safe site. Sloppiness was
not tolerated. If not for a minor injury a
week before completion, we would have
had no lost-time accidents. And remember
that construction was undertaken in two
phases from 2003 through 2007.
■ We made it clear to our on-site team that
they were ambassadors for all of Faribault
Energy Park, its designers, and develop-
ers. As such, they were responsible for
maintaining positive relationships in the
community.
■ We bought locally whenever possible,
generating as much economic activity in
the community as we could.
■ When questions about noise from the plant
were raised in 2005 after the initial phase
was up and running, we placed decibel
meters in several homes surrounding the
property and reported on the results.
In short, we went about the business of
keeping our promises.
Celebrating successThe grand opening celebration was some-
thing to behold. Based on the food tickets
distributed, we estimate that approximately
5,000 people entered Faribault Energy Park’s
gates on a beautiful October afternoon last
fall (Figure 4). The Faribault Daily News reported the next day that “The only hitch
in Saturday’s grand opening of the Faribault
Energy Park was that the fish weren’t biting.
But countless Faribault residents took the
bait Saturday, turning up north of town to
check out the environmentally friendly power
plant.” The Minneapolis StarTribune also re-
ported that “In addition to power generation,
the 35-acre park will serve as an educational
facility about environmentally friendly pow-
er generation. Visitors can view the control
room, steam turbine operations, oil storage
and water collection systems from internal
and external observation decks.”
Faribault Mayor Charles Ackman summed
up the feelings of the community in his
grand opening ceremony remarks by noting,
“Faribault Energy Park is a welcome addition
to our community. It is providing good jobs
along with amenities you’d never imagine
from a power facility, including tours, public
use of their park-like wetlands area [Figure
5], and the educational displays.”
Crossing the finish lineWe know that maintaining a positive repu-
tation in the community is a daily task. A
key manager at the site, Mark Tresidder, has
responsibility to sustain communications
with the community. He acts as the human
connection to the facility, schedules tours,
and is an active participant in community
affairs.
Soon, we will report to the community on
our experimental burns of renewable, or bio-
mass, energy sources such as recycled vege-
table oil, soy oil, and camelina oil. And as the
ground thaws, educational displays demon-
strating alternative energy sources including
hydro, solar, and wind energy will emerge in
the facility’s 20 acres of wetlands. ■
—Derick Dahlen ([email protected]) is president of Avant
Energy in Minneapolis, which designed and managed construction of Faribault
Energy Park and today manages opera-tions. Dave Pokorney (dpokorney
@chaskamn.com) is chairman of the Minnesota Municipal Power Agency and the owner/developer of Faribault Energy Park. Pokorney is also city administrator
for the city of Chaska, Minn.
4. Grand-opening crowd. Thousands of local residents attended the grand opening of Faribault Energy Park in October 2007. Courtesy: Avant Energy
5. Local fishing hole. Youngsters drop a line into one of several ponds on the Faribault Energy Park property. The ponds are accessible to the community and are stocked with bass and bluegills. Courtesy: Avant Energy
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CIRCLE 19 ON READER SERVICE CARD
www.powermag.com POWER | March 200836
WATER TREATMENT
Maintaining water sample panels improves plant availabilityEven comedian Rodney Dangerfield got more respect than many plant water
sample panels do. But power plants ignore sample panels at their peril. Those sample panels, and readings of the on-line analyzers they support, identify when multi-million-dollar systems have a problem that demands immediate attention.
By Dan Sampson, Nalco Co.
Sample and analysis panels are on the
front lines of the constant battle to de-
tect power plant water chemistry prob-
lems. However, at many plants, operators
have low confidence in the reliability of on-
line analyzers, so they “default” to wet tests
alone to monitor and control steam cycle
chemistry. That’s risky. Relying exclusively
on wet tests significantly reduces the number
and type of water chemistry problems that
can be detected and solved. That, in turn, puts
plant equipment in danger. Just because you
can’t see damage to steam generator tubes
doesn’t mean there isn’t a problem.
The best intentionsMany new plants start off on the right foot
by establishing maintenance schedules for
sample panels and training operators in their
use and maintenance procedures. But often,
these schedules are abandoned early in com-
mercial operation because keeping air-qual-
ity analyzers and instrumentation and control
(I&C) systems on-line is given a higher prior-
ity, or perhaps because operators’ experience
with early-model analyzers was poor. Facing
problems elsewhere in the plant, I&C techs
sometimes put off maintaining sample pan-
els that they are unfamiliar with and whose
problems they haven’t been trained to fix.
(See “Solving common analyzer problems,”
p. 21.) Regardless of why these instruments
don’t get the respect they deserve, it may be
time for a short refresher course in why on-
line analyzers are critical to reliable plant op-
erations and why good maintenance practices
might just restore your trust in them.
Ignoring your analyzers usually reduces
the efficiency of steam cycles and limits the
effectiveness of the panels themselves. The
negative effects are most pronounced at cy-
cling plants, where it’s hard to keep on-line
analyzers operating accurately and reliably.
Starts and stops of sample flow allow the
probes to dry out and rewet, increasing their
wear and shortening their useful life. In ad-
dition, iron and other contaminants liberated
during cycling can clog or foul sample lines,
pressure-reducing valves, rotometers, and
probes. Unfortunately, most sample panel
maintenance tasks can be performed only
when the plant is operating and producing
sample flows. And it’s hard to develop trust in
an instrument that is not properly maintained.
For these reasons, water-quality analyzers
are often abandoned or ignored while sample
panels are relegated to obtaining only grab
samples. The readings they produce may still
be entered into the plant’s distributed control
system (DCS), but if alarms aren’t active, the
readings are ignored.
One way to illustrate the importance of
sample panels to water chemistry analysis is
to review two case studies where perceived
monitoring problems resulted in a forced
outage or steam cycle damage. In both cases,
the downtime and damage could have been
eliminated or minimized if the sample panel
had been functional or the readings trusted.
Case study # 1: “Those new analyzers won’t work.” The following series of incidents occurred over
several months at a new 3 x 1 combined-cycle
cogeneration plant in a southern state. After its
initial start-up, the plant routinely performed
wet chemistry tests but did not maintain its
sample panels. Several water chemistry up-
sets occurred during the first several months
of operation, including both low- and high-pH
events. Data from the plant’s new on-line ana-
lyzers (which operators didn’t trust) clearly
showed all of both kinds of events, but many of
them were not detected by the wet tests. None
of the sample panel analyzers was alarmed to
the plant’s DCS.
The root cause of the events, which were
relatively short in duration, was diagnosed
as instrument condensate contamination.
Operators got into the lazy habit of feeding
caustic when drum pH was low and securing
chemical feed and blowing down when the
pH was high. They had several opportunities
to use the new on-line analyzers to detect
problems, but because the instruments were
poorly maintained and untrusted, their read-
ings were disregarded. The lack of functional
alarms contributed to the lack of situational
awareness—only two of the six on-line pH
analyzers were in service.
The six pH analyzers monitored the high-
pressure (HP) and intermediate-pressure
(IP) drums of the plant’s three heat-recov-
ery steam generators (HRSGs). The two op-
erating analyzers clearly showed severe pH
depressions or elevations as host condensate
quality varied. Because the plant was rely-
ing only on wet test data, operators neither
saw these excursions nor appreciated their
significance.
As you’d expect, the tubes of this plant’s
HRSGs began to overheat and fail after
only six months of operation. But the tube
failures were only the first signs of a seri-
ous water chemistry problem. Another was
the formation of iron deposits in the lower
Ignoring your analyzers usually reduces the efficiency of steam cycles and limits the effectiveness of the panels themselves. The negative effects are most pronounced at cycling plants.
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CIRCLE 20 ON READER SERVICE CARD
www.powermag.com POWER | March 200838
WATER TREATMENT
bends of the tubes (Figure 1), detected by
an initial inspection. This particular plant is
especially vulnerable to iron deposition be-
cause it uses high levels of duct firing on its
HRSGs, which increases the heat flux across
their tubes. Subsequent inspections also
showed significant material loss throughout
the tubes (Figure 2), not just at bends.
Because four on-line analyzers were out
of service and the other two were not trust-
ed by the operators, the plant addressed the
problem’s symptoms, rather than its root
cause. It did so by chemically cleaning the
HRSG tube sections that had remained un-
affected and replacing those with holes or
heavy deposits.
Those repairs cost millions of dollars, and
during the outages needed to make repairs,
the plant lost millions more in production
revenue. Equipment life was considerably
shortened because the analyzers didn’t per-
form due to slack O&M training and pro-
cedures plus poor alarm management—not
because “those new analyzers didn’t work.”
Case study # 2: “Don’t believe those readings.” The following series of incidents occurred at a
two-year-old 3 x 1 combined-cycle merchant
plant in a western state. One day, the plant’s
steam turbine tripped as HRSG #2 was be-
ing started up. The plant recovered from the
trip and HRSG #2 resumed starting up. Wet
chemistry tests (performed in the plant’s lab
on schedule, shortly after recovery from the
trip) indicated a low pH (about 7.5) in the HP
drums of HRSGs #1 and #3.
Like many plants, this one assigns water
chemistry duties to junior operators. The ju-
nior operator in the chemistry lab, who had
never seen drum pH this low, didn’t believe
his eyes. He did what any good junior opera-
tor would do—he called a senior operator to
ask about the low readings.
Because HRSG #2 was in start-up mode,
it took the senior operator over an hour to get
to the lab. He and the junior operator checked
the drum pH readings again, and they were
even lower than before, at about 5.5.
Seeing isn’t believing. Both operators
were certain that the bench-top pH analyzer
producing the readings had failed because
they assumed that the plant’s on-line pH ana-
lyzers weren’t working. But after they cali-
brated the bench-top analyzer, it generated an
even-lower pH reading—4.5. Still sure that
the lab analyzer was the culprit, the operators
next replaced its probe and calibrated it again.
Still no luck: The instrument continued to in-
dicate a very low drum pH. Frustrated, the
operators looked around the lab for another
pH analyzer to use but couldn’t find one.
By this point, the bench analyzer indicat-
ed that the drum pH readings of HRSGs #1
and #3 had stabilized at around 4.0, but the
operators remained certain that these were
“bad” readings. An additional factor added to
their confusion: The same analyzer appeared
to produce “good” readings from other grab
samples. The operators next tested the pH of
the plant’s feedwater, condensate, and demin
water, and those results were well within the
normal range of values. By then, HRSG #2
had completed start-up and was operating at
low load.
Finally, both operators contacted the con-
trol room supervisor to ask if another bench-
top pH analyzer was available anywhere.
Two hours after he relayed the request to the
plant’s chemist and operations supervisor
and got “no” for an answer, the control room
supervisor shut down the plant.
All told, the two operators wasted about
six hours believing that they needed another
bench-top pH analyzer. In fact, the one they
were using had been working properly the
entire time. It took another two hours to be-
gin shutting down the plant, a process that
2. Going deep. Abnormal loss of material from an HRSG tube, detected by a boroscope inspection. Courtesy: Nalco
1. Ironed out. Iron deposition in HRSG tubes reduces the tubes’ life expectancy as well as unit generating capacity. Courtesy: Nalco
March 2008 | POWER www.powermag.com 39
WATER TREATMENT
required the plant’s chemist, operations supervisor, and manager to
concur that the low pH event was, in fact, real. A subsequent exami-
nation of on-line analyzer data showed that the pH in the drums of
HRSGs #1 and #3 had indeed fallen quickly to around 4.0 and re-
mained there for the duration of the incident.
Wasting away. Though this plant’s forced outage could not have
been prevented, the resulting HRSG corrosion could have been. One
tube section from the HP drum of HRSG #1 was removed six months
after the incident and tested. A deposit weight density (DWD) analy-
sis indicated 16 grams/ft2 of buildup after only one year of commer-
cial service. Such a level is more consistent with seven to 10 years of
operation. As in the first case study, significant iron deposition oc-
curred as a result of this event, so the HRSG will require chemical
cleaning sooner rather than later. The full extent of the damage is still
unknown. Hydrogen damage also certainly took place, but the plant
has not yet seen HRSG tube failures as a consequence.
Low-pH events can cause several problems, including corrosion
fatigue, hydrogen damage, and deposition of corrosion products. We
can’t say that a tube failure initiated by low pH will occur within a
month, a year, or even within 10 years. We can only conclude that one
or more tubes will fail sooner than they would have had the event not
occurred. The adverse impact of the event is roughly proportional to
its duration. Based on data recorded by the one working on-line pH
analyzer at this plant, the plant operated with low pH in the drums of
two of its three HRSGs for six to eight hours.
The low-pH event was initiated when material in the HRSGs’ con-
densers came loose and struck tubes, damaging them and causing
them to leak. Among the factors that made the leak(s) more difficult
to detect were the lack of reliable on-line pH indication (a sample
panel maintenance and design issue), the absence of specific or cat-
ion conductivity measurements upstream of chemical feeds (a sample
panel design issue), and reliance on wet tests alone to identify water
chemistry problems.
Wrong number. Like the plant described in the first case study,
this one had on-line pH analyzers installed on all three of its HRSG
drums. But in this case, only one analyzer was working, and opera-
tors’ lack of confidence in the instruments led them to believe that wet
chemistry analysis was the only way to detect pH excursions. Plant
management knew about the analyzers’ reliability problem but had
failed to address it after one year of commercial operation.
Although the plant also was equipped with an on-line specific
conductivity analyzer, its poor placement made it useless for accu-
rate leak detection: The flow sampled by the analyzer is downstream
of the point where boiler feedwater chemicals (a passivator and an
amine) are added. Both chemicals increase condensate conductivity
in direct proportion to the amount added. Accordingly, changes in
condensate flow rate will cause a change in condensate conductivity
even if the chemical feed rate remains constant. Because of this inher-
ent variability, small condenser leaks may be masked by the noise of
variable condensate conductivity.
As this example proves, even small leaks can quickly cause a low
pH upset in HP HRSG drums. Plant personnel were confused because
condensate conductivity appeared to be normal.
A cation conductivity analyzer would have been immune to the in-
terference caused by the chemical feed and would have accelerated de-
tection of condensate contamination. It should go without saying that
the specific conductivity analyzer should have been installed where
it would receive samples of condensate prior to any chemical addi-
tion. Had that been the case, the variability in condensate conductivity
caused by the chemical feed would not have been a problem. With this
variability removed, it becomes easier to detect small increases in con-
ductivity that are indicative of an incipient condenser tube leak.
Once again, poor plant O&M practices meant key on-line analyzers
were unavailable during start-up, and readings from the one operating
analyzer were distrusted. Also, senior techs seemed to be instilling poor
O&M habits in younger techs, which made the problem an institutional
one. Apparently, the plant manager didn’t believe in investing in the
immediate repair of these instruments, thereby reinforcing the mistrust.
What this plant has is a leadership problem, not an analyzer problem.
Squared-away sample panels In these two cases involving either rare upsets in condensate quality
or condenser tube leaks, a technician’s mistrust of an instrument—
due to prior reliability problems or poor O&M practices and train-
ing—caused additional damage to plant equipment especially during
chemistry upsets during cycling operation. Such upsets are the re-
sult of overfeeding or underfeeding treatment chemicals just prior to
unit shutdown or immediately after start-up—conditions that on-line
monitoring would detect.
It’s always more difficult to control the chemistry of a cycled plant,
but ignoring or not maintaining your on-line analyzers just exacerbates
the problem. Chemical feed systems may fail during the shutdown pe-
riod. Pumps may become air-bound or otherwise cease to function. If
on-line analyzers are missing, not working because repairs aren’t a pri-
ority, or not trusted, the chemistry upsets caused by these failures may
not be detected until the first grab samples of the cycle are taken. For
this reason, many plants operate with no chemical feed (or too much
chemical feed) for the first several hours following start-up.
Time is moneyMany plants perform wet tests that do little to protect equipment.
If a plant’s sample panel is reliable, wet tests need to be performed
only to verify the continued accuracy of the on-line analyzers. In
CIRCLE 21 ON READER SERVICE CARD
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WATER TREATMENT
the absence of reliable analyzers, wet tests
become the first line of defense.
Because wet tests should be performed ev-
ery four to six hours, operators who depend
on them spend a lot of their time monitoring
water chemistry, during which other prob-
lems go undetected (causing more upsets).
Lowering chemistry’s priority on the task list
is no solution, because doing so produces the
same result.
At most plants, sample panel maintenance
is very time-intensive and entails weekly or
biweekly calibration of on-line analyzers by
the maintenance department. However, if
more than one instrument shows some drift
after it is returned to service, it’s not uncom-
mon for operators to believe that all of the
analyzers need to be recalibrated or have
their probes replaced. They then write work
orders that maintenance fills, which starts the
cycle again. In the end, maintenance spends
as much time “fixing” working analyzers as
operators do on chemistry.
Improved maintenance, operating, and de-
sign practices will solve many problems that
are unjustly blamed on analyzers. Here are
some suggestions that will keep your sample
panel running in tip-top condition.
Delivering accuracy and reliabilityOperators, because they are the primary us-
ers of the plant’s sample panel (Figure 3), are
best qualified to determine if it needs main-
tenance. Taking the following steps ensures
that on-line analyzers read reliably and are
repaired when they don’t.
Ensure analyzer accuracy and stan-dardization. As with any sampling system,
some assumptions must be made regarding
the conditions that must be met to ensure ac-
curacy and reliability. For pH instruments,
the sample conditioning equipment (es-
pecially the temperature-controlling unit)
must maintain a constant sample tempera-
ture that meets the manufacturer’s specs.
In addition, wet tests used to verify on-line
analyzer accuracy must be performed using
temperature-compensated probes. Because
sample temperature has a large impact on pH
readings, any deviation in temperature will
produce a deviation in pH that is not due to
calibration or instrument error.
The plant’s chemistry trending software
should be modified to add a set of calcula-
tions called “analyzer deviations.” These al-
gorithms operate on the differences between
the results of wet test samples and those of
the on-line analyzers. Typical pH probe/ana-
lyzer combinations are accurate to about 0.1
pH unit. That being the case, some deviation
between analyzers (on-line or bench-top)
should be expected. An analyzer should be
considered accurate as long as the deviation
is within expected limits.
The analyzer deviation calculations also
help determine the need for analyzer calibra-
tion or replacement. Each deviation calcula-
tion represents a ratio of a wet test reading
divided by an on-line analyzer reading. For
example, the deviation would be 1.00 if the
wet test and sample panel readings were iden-
tical. For pH analyzers, the control limits are
0.95 to 1.05 (5% deviation). No standardiza-
tion is required if the wet test result and on-line
analyzer pH readings are within 0.2 pH unit
of each other, or if the calculated deviation is
between 0.95 and 1.05. For conductivity, the
limits are 0.90 to 1.10 (10% deviation).
Operators should take responsibility for
this important calibration check, which
should be performed at least weekly. Opera-
tors should be trained to standardize any ana-
lyzer whose calculated deviation exceeds the
limit specified for it.
Standardization is relatively quick and
easy. Operators don’t actually calibrate the
analyzer—they offset its current reading by
the amount of deviation determined by a wet
test/on-line analyzer comparison. The proce-
dure can be hard-coded into most chemistry
monitoring software. Most chemistry trend-
ing programs can be configured to display an
alarm with a link to the standardization pro-
cedure if a deviation is greater than the limit.
Flag out-of-service analyzers and equipment. Frequent high deviations or
standardization failures may mean that an
on-line analyzer needs to be replaced. If ei-
ther is the case, operators should describe the
problem on the work order so maintenance
staff will examine the analyzer in detail.
If an operator generates a work order for
an on-line analyzer, he or she should indicate
having done so on a white board in the water
chemistry lab (or use some other method) to
flag that it is out of service. Operators typi-
cally mark the analyzer’s reading on the shift
log sheet as “OOC” (out of commission) or
“OOS” (out of service) so operations man-
agers can see at a glance what’s not work-
ing. It’s absolutely critical that operators
be trained to believe an analyzer’s readings
unless it is flagged as OOC or OOS. There
should be no second-guessing.
If a reading from a working analyzer is out
of range, operators should take immediate
action: a single retest, but no more. Two in-
dependent readings (from an on-line analyzer
and a wet test) should be used to confirm that
the parameter is out of range and that correc-
tive actions should be taken.
For an out-of-service analyzer, operators
must increase the frequency of wet tests for
any reading that it supplies. For example, if
the pH analyzer for an HRSG’s HP drum is
out of service, operators should increase the
frequency of wet testing that drum’s pH to
once every four hours. Similarly, if a silica
analyzer is out of service, operators must
wet-test all of the systems sampled by it
once every four hours. This approach accom-
plishes two goals. First, it provides increased
protection if an analyzer is out of service.
Second, it creates some urgency on the part
of the operators to get the analyzer back up
and running (since their workload increases
when the analyzer is out of service).
At most plants, shifting primary respon-
sibility for sample panel maintenance to the
operator decreases overall maintenance costs.
Under such a regime, analyzers are calibrated
3. Water works. A typical sample panel with separate dry and wet sections. Courtesy: Nalco
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CIRCLE 22 ON READER SERVICE CARD
www.powermag.com POWER | March 200842
WATER TREATMENT
on an as-needed basis rather than every week,
typically saving about four I&C man-hours per
week. The frequency with which pH and ORP
(oxidation-reduction potential) probes are re-
placed decreases from about once every six
months to about once a year. Another benefit
of this approach is that conductivity probes no
longer need to be replaced as a step in the pre-
ventive maintenance program. Replacing the
probes only if they fail will generate net sav-
ings averaging about $18,000 per year per site.
Sites that do not maintain their sample panel
will obviously see their overall maintenance
costs rise after implementing this philosophy.
But usually the increase is more than offset by
the higher unit availability made possible by a
reliable and accurate steam sample panel.
Figure 4 confirms the tangible positive ef-
fects of changing a sample panel maintenance
strategy. The graph shows how one plant’s
average analyzer deviation ratio, discussed
earlier, fell precipitously with a shift in main-
tenance philosophy. The correlation between
wet test results and sample panel readings
was extremely low before the change but
much higher after it. The improvement in the
accuracy and reliability of on-line analyz-
ers allowed operators to decrease their wet
testing frequency to once per day. Figure 5
shows typical, much lower analyzer devia-
tions several weeks after the change.
Make alarms active in the DCS. Critical
parameters should be alarmed on the plant’s
DCS, and these alarms should be received
in the control room. EPRI provides specific
recommendations for DCS alarms in the pub-
lication, “Cycle Chemistry Guidelines for
Fossil Plants.” Nalco’s recommendations for
the critical alarm parameters include:
■ All pH readings
■ All specific conductivities
■ All cation conductivities
■ All sodium analyzers
■ All silica analyzers
■ All dissolved oxygen analyzers
In addition to DCS alarms, most plants
have access to chemistry-trending software,
the plant data historian, or both. These data
should be examined often to verify that steam
cycle chemistry is within required limits.
Operators should review the last 24 hours
of sample panel trend data (at a minimum),
just as they review DCS data for the turbine.
In many cases, the trend data can be used to
detect changes or upsets even if the analyzer
providing the reading is in need of repair or
maintenance.
Clean and preserve during down-time. As mentioned earlier, cycling opera-
tion makes it extremely difficult for on-line
analyzers to operate accurately and reliably.
2.0
1.7
1.4
1.1
0.8
0.5
Anal
yzer
dev
iatio
n ra
tio
02/02 03/10 04/08 05/09 06/13 07/14 08/11 09/09 10/09 11/11 12/10 01/06 02/03 03/03 03/30 04/28 05/26 06/23 07/22 08/18 09/16 10/13 11/10 12/07 01/05 02/01 03/01 03/28 04/25 05/23 06/22 07/21 08/17
Date (2002–2005)
HP drum HP steam IP drum
1.1
1.0
0.9
Anal
yzer
dev
iatio
n ra
tio
02/20 02/21 02/22 02/23 02/24 02/25 02/26 02/27 02/28 03/01 03/02 03/03 03/04 03/05 03/06 03/07 03/08 03/09 03/10 03/11 03/12 03/13 03/14 03/15 03/16 03/17 03/18 03/20 03/21
Date (2006)
Cooling water Boiler feedpump Condensate Rotary air cooler
5. Great expectations. Typical analyzer performance after the maintenance strategy change shows only minor deviations in readings. Source: Nalco
4. Settle down. On-line analyzer deviations before and after a change in sample panel maintenance strategy. Source: Nalco
www.powermag.com POWER | March 200844
WATER TREATMENT
The intermittent sample flow allows ana-
lyzer probes to dry out and rewet, increas-
ing wear on them and shortening their life.
These problems can be minimized if probes
are cleaned with demineralized water and if
demin water or condensate is routed through
idle sample points.
If its probes are coated with corrosion
products, an on-line analyzer will be sluggish
and inaccurate. Taking advantage of a cycled
plant’s downtime to clean and preserve
probes can increase analyzers’ accuracy and
extend probe life after operation resumes.
Idle probes should be removed at least
monthly and cleaned with demin water and a
lint-free cloth. After flushing the sample “T”
with demin water, refill the probe header, and
re-insert the probe. Remember to restore the
flow of demin water to idle sample points af-
ter the probe has been cleaned.
Most sample panels have several differ-
ent locations where the demin water tie-in
could be made. One good location is on the
downstream (cool) side of the sample cool-
ers. There’s usually an existing union on all
of these sample points that could be used to
introduce demin water. This retrofit would re-
quire the installation of a block valve on the
cooler effluent, to prevent both the backflow
of demineralized water through the sample
lines and the simultaneous flow of normal
sample and demin water through the sample
panel. A quick-disconnect and “T” can be in-
stalled downstream of this new block valve.
Demin water would then enter the idle sam-
ple point through the quick-disconnect and
flow through the sample point via the “T.”
Figure 6 shows one possible arrangement for
each sample point.
This arrangement provides several advan-
tages. First, it preserves analyzers by main-
taining flow through them even when the
plant (or an HRSG) is shut down. Second, it
minimizes sample line fouling because the
continuous demin water flow during shut-
down will tend to flush corrosion products
that accumulate in the sample lines dur-
ing operation. Third, it allows sample panel
maintenance to be performed regardless of
plant status.
Plants that have made this retrofit have
reaped substantial benefits. But before you
follow suit, here are two caveats. First, you
must devise a way to distinguish whether a
sample point is receiving demin water or a
normal sample. One plant did so by creat-
ing engraved nameplates with “Demin wa-
ter” on one side and “Sample” on the other.
The plaques hang on a chain on the front of
the panel around the block valve for each
sample point. Operators simply turn the
plaque around to read the sample point’s
status.
The second caveat is to take care to ensure
that demin water and normal samples are
not fed to the same sample point at the same
time. Mixing the two creates several poten-
tial problems and should be avoided. Sample
point shutdown and start-up procedures can
be modified (or created) to address this po-
tential problem. ■
—Dan Sampson ([email protected]) is a power industry technical consultant
for Nalco Co. He authored “Fleetwide standardization of steam cycle chemistry”
in the March 2006 issue of POWER.
Cooler inlet Block valve
Deminwater to
quick-disconnect
To sample panel
6. Keep it clean. A simplified schematic of a demin water flushing system for a sample panel. Source: Nalco
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INFORMATION TECHNOLOGY
Wireless technologies connect two LCRA plantsLower Colorado River Authority recently put two separate plants at its Lost
Pines Power Park under one functional management system. The project has already deployed a layered wireless infrastructure that allows the two plants to communicate at a fraction of the cost of a wired solution while providing a platform for optimizing work processes and reducing operat-ing costs. What’s not to like?
By David Runkle, LCRA
Lower Colorado River Authority’s
(LCRA’s) Lost Pines Power Park (LPPP)
is located in central Texas, 30 miles
southeast of Austin. The site hosts two sepa-
rate facilities that provide distinctly different
services to the Electric Reliability Council of
Texas (ERCOT) generation market. One is the
Sim Gideon Power Plant (SGPP, Figure 1), a
three-unit, 650-MW natural gas–fired steam
plant whose forte is ancillary (load-regulation)
services; the other is the Lost Pines 1 Power
Project (LP1, Figure 1), a conventional 545-
MW gas-fired combined-cycle plant.
POWER, in its June 2007 issue, profiled
the control system upgrades of the three
SGPP units that made them among the fastest
responders in ERCOT despite their advanced
ages: 35, 39, and 42. LP1, a 2 x 1 plant, be-
gan generating and selling electricity in May
2001. GenTex Power Corp., an LCRA affili-
ate, built the Lost Pines facility in an equal
partnership with Calpine Corp. in 2001. Two
years later, LCRA purchased the remaining
half of the facility, becoming its sole owner.
Mind meldA single plant staff was formed in Febru-
ary 2006 by merging the employees of both
plants. The first order of business: find a way
to effectively manage and efficiently operate
an integrated facility at which each plant is
operated independently. One of the principal
challenges was to bridge the gaps between
the facilities’ operator and technician experi-
ence bases (steam vs. gas turbine) and ages
(new vs. 40 years old).
Integration of the two facilities’ control
and communications networks at a funda-
mental level required not just a meticulous
look at their wires and pipes but also consid-
eration of issues such as:
■ Personnel safety.
■ How the two plants should talk to each
1. Two plants, one site. Lost Pines Power Park comprises the three gas-fired steam units of Sim Gideon Power Plant, built in the 1960s (top), and the seven-year-old Lost Pines 1 combined-cycle plant (bottom). A single staff operates both facilities. Courtesy: LCRA
March 2008 | POWER www.powermag.com 47
INFORMATION TECHNOLOGY
other and share data to support routine
O&M activities.
■ Using the integrated control network
to provide backup for the two separate
control rooms for operating and training
purposes. Overtime cost savings were the
desired benefit of leveraging operations
staff in this way.
■ Enabling operator mobility by supporting
field data logging.
However ambitious these goals appear,
the transition to a fully integrated O&M staff
began with determining the basics of how its
members were to communicate. Let’s start at
the beginning.
Integrating resourcesLCRA management began looking to replace
the public address (PA) systems of all facilities
in its Wholesale Power Services business unit
before LCRA and Calpine built LP1 six years
ago. The push-to-talk hardwired PA systems
that had been deployed across the entire gen-
eration fleet many years before were already
showing signs of technological obsolescence.
LCRA’s telecommunications department
solicited requests for proposals from various
vendors for replacement PA systems. When
the quotes came in, the combined cost of re-
placing the PA system at SGP and adding a
PA system to LP1 (which was built without
one) far exceeded the project budget. Most
of the cost was for installing new conduit and
wires throughout LP1 to accommodate a tra-
ditional hardwired system while dodging un-
known underground obstacles. Sticker shock
and other risk factors made the conventional
approach less desirable and initiated a search
for a creative solution.
In 1995, LCRA hired Invensys Process
Systems (www.invensys.com) to provide IT
infrastructure support under an agreement
that was later renewed for another 10 years.
Invensys is a leading supplier of innovative
technologies to power plants. During an
early meeting of the partners, the company
proposed using wireless technologies to inte-
grate communications and control of the two
plants at Lost Pines Power Park.
Leveraging its partnership with Apprion
Inc. (www.apprion.com), Invensys proposed
that LCRA use a wireless Wi-Fi system un-
der a WiMAX “umbrella” to provide a secure
access point for interfacing any known wire-
less device protocol to control and corporate
networks. Apprion’s vendor-neutral wireless
solution also would allow continuous moni-
toring of system health and detect intrusions
by rogue devices or cyber terrorists.
Communications system security is of par-
amount importance, given the new standards
for power generators recently introduced by
the Federal Energy Regulatory Commission
and the North American Electric Reliability
Corp. (see p. 18). Complying with these stan-
dards and with LCRA’s internal IT standards
was a major challenge, but making the effort
to do so paid off: The wireless system cost
44% less than a conventional approach using
wires and conduits.
Going wireless also “future-proofed”
LPPP by enabling additional applications to
be added at only incremental costs. LCRA
says up to 75% savings have been realized
by reducing engineering, drafting, installa-
tion, and materials costs and by minimizing
administrative and overhead costs and imple-
mentation times.
The next step in the project was to perform
a strategic assessment of LPPP’s infrastruc-
ture to determine if deploying a wireless
network within and across its two power fa-
cilities was possible.
Going wirelessThe assessment determined the optimal loca-
tion of wide- and medium-bandwidth trans-
ceivers, identified where to put the logical
integration terminals that provide the physi-
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www.powermag.com POWER | March 200848
INFORMATION TECHNOLOGY
cal connections to SGPP’s and LP1’s existing
fiber/wired IT infrastructure, and set the site-
specific requirements that potential applica-
tion vendors for LCRA’s plants would have
to meet. This work was done by Invensys
and Apprion using radio frequency spectral
analysis at strategic locations.
The assessment determined that it would
indeed be possible to implement a wireless
broadband umbrella. It would use WiMAX to
cover both plants but Wi-Fi for local-area net-
work access and to reach their remote parts,
eliminating the need to install costly Ether-
net cables. The WiMAX umbrella provides
wide-bandwidth wireless coverage through-
out LPPP and connectivity up to 25 miles
away. The WiMAX broadband connection
serves as “virtual fiber” that connects LP1 to
SGPP and enables the two facilities to share
and communicate data using the same Voice
over IP (VoIP) system. Plans are to extend
the system to LCRA’s other remote sites.
Personal communications are now virtu-
ally instantaneous because all field workers
wear a VoIP communications badge. When
a worker needs to communicate with a col-
league anywhere at LPPP, he or she voice-
activates the device with a simple command,
such as “find Bill.” Wireless communications
make an 802.11b connection through an ac-
cess point at a local mesh network. The com-
mand is sent to the VoIP server installed at
LPPP’s central management control center.
The server manages all users, security, data,
and communication.
Making it happenThe following wireless network infrastruc-
ture, components, and features are now on-
line at LPPP:
■ A sitewide wireless backbone, including
a 360-degree WiMAX wireless umbrella
covering the entire site (Figure 2).
■ A wide-bandwidth backhaul 802.16 net-
work featuring a simple antenna configu-
ration and placement.
■ Layered implementation of secure and
managed WiMAX, Wi-Fi, and other net-
working technologies.
■ Fifty-one Wi-Fi access points installed
at strategic locations throughout the plant
(Figure 3).
■ A wireless speaker system with push-to-
talk capability and an integrated private
branch exchange (Figure 4).
■ Plantwide voice communications and
loudspeaker broadcasting throughout the
facility.
■ Emergency broadcasts throughout the site.
They are used to initiate evacuation and to
notify local first responders.
An industrial wireless application network
manages the Wi-Fi/wireless infrastructure
by:
■ Monitoring all access points at both plant
areas for real-time failure detection.
■ Monitoring the network for rogue device
detection.
■ Managing the VoIP communications serv-
er and all VoIP data.
■ Controlling all device management of net-
work gateways and access points.
■ Reporting on all wireless data activity.
Leveraging the networksThe single wireless platform that LCRA de-
ployed to meet the communications and data
monitoring needs of two large plants is scal-
able, so software applications can be added
to it in the future. The company has also used
that capability to optimize and automate a
number of its work processes and to reduce
LPPP’s operating costs.
For example, the system includes a com-
prehensive wireless network support pack-
age that should be able to handle virtually
all of the site’s communications and data
needs well into the future. The package
comprises:
■ Apprion’s industrial wireless application network. Called the ION system, it includes
2. 360-degree coverage. WiMAX an-tennas are the backbone of LPPP’s wireless infrastructure. Courtesy: LCRA
3. Hot spots. Fifty-one wireless access points provide connectivity throughout Lost Pines Power Park. Courtesy: LCRA
4. Shout it out. Wireless PA speakers were added to Lost Pines 1, eschewing a much more expensive approach using cables and conduits. Courtesy: LCRA
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CIRCLE 26 ON READER SERVICE CARD
www.powermag.com POWER | March 200850
INFORMATION TECHNOLOGY
the IONosphere, a centralized application
that manages data services, workflow,
security, monitoring and maintenance,
and third-party application integration.
IONosphere management software con-
tinually monitors the health, performance,
and integrity of the overall wireless infra-
structure to ensure optimal performance of
QoS-based applications, such as voice, in a
shared data environment.
■ Apprion’s ION Services. It supports site
analysis, technology selection, infrastruc-
ture design and implementation, perfor-
mance monitoring, security management,
and continuous network administration
and optimization.
Extended benefit coverageLCRA is already reaping the benefits of its
new wireless infrastructure at LPPP. Em-
ployees of both SGPP and LP1 can now
communicate freely using the VoIP, wireless,
push-to-talk system. The infrastructure’s de-
sign enables LCRA to easily extend wireless
coverage by adding new applications in vari-
ous plant locations (Figure 5).
Next on LCRA’s agenda is extending the
wireless infrastructure to many other areas
of the two plants to leverage its communica-
tions and control capabilities. The objective
is to continue increasing worker mobility
and to find other ways to cut O&M costs
by raising productivity. Among the wireless
applications now being considered or devel-
oped are:
■ Noncritical closed-loop level controls
and alarming functions on auxiliary plant
equipment.
■ Alarming of various temperatures, lev-
els, and other key operating parameters.
Applications under development include
feedwater heater level control and alarm-
ing, and furnace video monitoring to
check burner performance and tilt and the
condition of the fireball.
■ Condition monitoring of equipment health.
Providing vibration data in real time to op-
erators helps them detect incipient equip-
ment problems early.
■ Detecting ammonia leaks and communi-
cating them in real time, before they cause
serious problems.
■ Remote tank level monitoring. Tank sen-
sors will wirelessly relay level status
information to access points and to the
plant’s main control system. Once tank
level monitoring is in place, it will be easy
to add condition-monitoring metrics (such
as pressure, temperature, and voltage) to
flesh out a complete preventive mainte-
nance system.
■ Using tablet PCs to give operators remote,
wireless access to the Foxboro and West-
inghouse control systems used by the Sim
Gideon and Lost Pines power plants, re-
spectively.
Now that it is reaping the benefits of wire-
less technologies at LPPP, LCRA is inte-
grating them into the conceptual design of a
remote, unmanned peaking plant to be built
about 24 miles away. (For more on power
plant controls technology, see the sidebar.)
The concept is to expand connectivity through
LCRA’s existing fiber network and WiMAX
technology to provide the same capabilities—
and then some—currently showcased at Lost
Pines. The new plant, tentatively called the
Winchester Power Park, will be remotely op-
erated from the Sim Gideon plant.■
Acknowledgement: Portions of this article are based on a paper by David Runkle of LCRA and Stephen Lambright of Apprion ti-tled “Wireless Infrastructure Implementation in a Power Generation Site: Lower Colorado River Authority (LCRA), Lost Pines Power Park.” It was presented at the 17th Annual Joint ISA POWID/EPRI Controls and Instru-mentation Conference.
—David Runkle ([email protected])is production manager of
LCRA’s Lost Pines Power Park.
5. Overlapping circles. Wireless umbrellas support voice, data, and control communi-cations within Lost Pines Power Park’s two plants and adjacent support facilities. Sim Gideon Power Plant is within the bottom circle, with Lost Pines 1 Power Project just above it. Areas in green have 802.11 coverage, blue has VoIP/PA coverage, and light orange has WiMAX coverage. Courtesy: LCRA
2008 POWID meeting nears
POWER is privileged to be the official publication of the 51st annual Power Industry Division (POWID) Conference/18th Annual Joint POWID/EPRI Confer-ence scheduled for June 8–13, 2008, at the Hilton Scottsdale Resort & Vil-las in Scottsdale, Ariz. The theme of this year’s conference is “The Pathway to Power Automation for the 2010 Decade.” Its agenda will cover top-ics ranging from software for fossil-fueled plants to cyber security standards compliance to advanced plant controls and wireless technologies. For more information, check out the conference program details at www.isa.org/~powid/powid_2008_%20main.htm.
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CIRCLE 27 ON READER SERVICE CARD
www.powermag.com POWER | March 200852
VALVES
Desuperheating valves take the heatHot reheat steam bypass actuators are some of the most critical, yet least under-
stood components in a typical combined-cycle plant. If you’re using pneu-matic actuators to stroke your main steam or hot reheat bypass valves in a cascading bypass system, you’re behind the times. Here’s a way to get better control of the bypass process, shorten unit start-up and train blend-ing times, and decrease your plant’s heat rate—all at the same time.
By Geoffrey Hynes, Koso America Inc.
The cascading bypass system is perhaps
the most common design for managing
high-pressure steam in a combined-
cycle plant. It is the hot reheat (HRH) bypass
valve actuator that defines the valve’s ability
to respond to system demands. That makes it
perhaps the most important component in the
steam bypass system, which in turn is one of
the most important control loops in a typical
combined-cycle plant.
HRH valves play a critical role in the main
and reheat steam loops, especially during
unit start-ups and shutdowns. If your control
loops can’t closely follow a setpoint, chances
are your plant is equipped with pneumatic
actuators—and its heat rate is higher than it
could be. Anything short of perfect control
can also cause major operational problems
that either extend start-up and shutdown
times or increase the potential for unit trips.
Both effects inevitably show up on the plant’s
bottom line.
In cascading bypass systems, steam from
the high-pressure (HP) and intermediate-
pressure (IP) drums that bypasses the steam
turbine during start-ups, transients, and shut-
downs does not go straight to the condenser
(Figure 1). Instead, HP bypassed steam goes
to the cold reheat (CRH) line on the HP
turbine’s exhaust and mixes with the output
of the IP drum. This HP steam is then sent
through the reheater and through another
bypass pressure-control valve—the HRH
valve—before going to the condenser.
Selecting the right valveHRH valve requirements are complex from
a mechanical design standpoint. The ANSI
600-lb-rated valves range from 12 to 24 inch-
es in diameter. They must tightly shut off and
be able to be throttled (conflicting require-
ments for such difficult service), and their
body and trim materials must deal with rapid
thermal transients. Noise control and extend-
ed trim life also have become very important
design requirements.
Unbalanced HRH valves are typically not
used in this application because the actuation
forces required for valves of this size would
be too large for conventional pneumatic ac-
tuators. However, because tight shutoff is a
design requirement, pilot-balanced trim is
common. This design allows for the use of
relatively low actuator thrust at full differen-
tial pressure (balanced when open), while en-
abling full unbalanced forces on the valve seat
in the closed position (installed in the flow-to-
close direction) to ensure tight shutoff.
Special materials, tolerances, body/trim/
bonnet arrangements, and flow paths (warm-
ing lines, for example) are used to address
the thermal cycling issues that HRH valves
must deal with, such as weld fatigue and
internal reliability. Many designs have for-
saken pneumatic actuators fitted with stan-
dard positioners and volume boosters to meet
stroking speed requirements in favor of smart
positioners with boosters that improve diag-
nostic capabilities and reduce overshoot.
What would be a good set of technical
requirements for a HRH valve actuator? The
use of pneumatic actuators poses inherent de-
sign challenges because air is compressible
and therefore limits the response, positioning
capability, and stability of an actuator. Nev-
ertheless, it’s still instructive to compare how
a typical pneumatic actuator and a modern
hydraulic actuator work. As long as you re-
member to include the effects of your plant’s
design in the comparison, the following dis-
cussion will point you in the right direction.
Let’s begin the comparison by considering
the following as typical HRH bypass actuator
performance requirements:
■ A stroke length between 6 and 12 inches.
■ A stroking force between 15,000 and
40,000 pounds, depending on the valve
design and the process parameters.
■ A stroke speed typically less than 5 sec-
onds between the full-open and full-closed
positions.
HPSH
IPSH
HPturbine
HPbypass
Reheater
IPturbine
LPturbine
LPSH
HRHbypass Condenser
Notes: HPSH = high-pressure superheater, IPSH = intermediate-pressure superheater, LPSH = low-pressure superheater.
1. Detours. A cascading bypass system uses an HP steam bypass valve and a hot reheat steam bypass valve to manage steam flow to the steam turbine. Source: Koso America Inc.
March 2008 | POWER www.powermag.com 53
VALVES
■ The ability of an input trip signal to stroke the valve fully closed
within 2 seconds or less.
■ High frequency response, repeatability, accurate setpoint control,
and stability.
Pumping air actuatorsBecause pneumatic actuators can provide fast stroking speeds, they
can usually be used reliably to handle steam turbine load shedding
and trips. They also can catch condenser vacuum during large set-
point changes. However, the frequency response, repeatability, and
dynamic stability of pneumatic devices are inherently limited due to
the soft, compressible nature of their motive force—air. Static friction
(“stiction”) is a key contributor to these performance limitations.
Graphite packing and seal rings are required for these high-tem-
perature applications, and they add stiction to the actuator. Consider
an 18-inch-diameter spring-opposed cylinder with a 7.5-inch stroke
and a 120-psig operating pressure (Figure 2). For the piston to move
upward, the positioner must vent air from the cylinder until its in-
ternal pressure has decreased enough to overcome the stiction. For
this example, assuming that the force differential between static and
dynamic friction is 2,200 lb (corresponding to an actuator pressure
change from 120 psig to 111 psig), we can calculate that:
■ The volume of air vented is 88.3 in3.
■ The time required to vent this volume at 80F is 1.74 seconds, which
represents the inherent lag of the actuator.
■ The piston’s “jump” (the actuator’s resolution) is 0.35 inches, or
4.6% of its span.
Such an actuator would easily cause friction hunt (due to jump)
and process limit cycling (due to lag). Friction hunts, stiction, and
limit cycling (process instability) are all well-documented phenom-
ena. They are among the biggest contributors to poor control loop
performance and destabilization of process equipment.
Since a pneumatic positioner’s flow capacity (CvF
L) will not allow
fast enough stroking speeds for the application, volume boosters must
be added. Doing so changes the lag in response as well as the over-
shoot jump values. Assuming a typical volume booster with a CvF
L
of 3.7 and a 200-ms response time, the dead time is reduced to 0.29
seconds and the jump becomes 1.09 inches, or 14.5% of span.
This lag in response and increase in jump is typical of pneumatic
actuators. The volume boosters and positioner can be set up to reduce
the use of the former for small setpoint changes. However, tight con-
trol on large setpoint changes is difficult to achieve.
Interpret the resultsHow tightly does the HRH bypass actuator need to control reheat
pressure, given these typical design values? Clearly, overshoot of this
magnitude is not acceptable for any pressure-control loop.
One option is to use a “smart” pneumatic positioner. It can sig-
nificantly reduce overshoot, using complex control algorithms for
overcoming the inherent limitations of pneumatic actuators discussed
earlier. Although overshoot can be reduced, the magnitude of the re-
duction depends on the level of stiction in the valve, which is typically
very high for large valves with graphite packing.
The downside of switching from standard to smart pneumatic ac-
tuators is that the latter take much longer to respond to control signal
step changes of 2% or less. This dead time becomes longer as the step
changes become smaller (a 1% change produces a longer dead time
than a 2% change).
Along with dead time, an additional delay before reaching the set-
point is introduced by the proportional-integral-derivative (PID) ac-
tion of the smart positioner, which must slow down in a controlled
manner to minimize overshoot. This ramp into setpoint is slow com-
pared to that of other actuator technologies. We can’t change the laws
of physics.
Control loop stability is especially sensitive to dead time, which
Cylinder Digitalpositioner
Vent toatmosphere
Air supply
Valvehydraulic
force
2. Force multiplier. A pneumatic actuator must vent compressed air, which compromises its performance. Source: Koso America Inc.
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www.powermag.com POWER | March 200854
is perhaps the most destabilizing of the time-dependent dynamics
of a control loop. Equally destabilizing is the tendency of the dead
time to vary. Pneumatic actuators tend to exhibit dead time while the
positioner transfers sufficient power air to the actuator to overcome
friction and to move the valve closure member. Often, this tendency
also is amplitude-dependent; as mentioned earlier, small step changes
produce longer dead times than larger changes.
The main cause of this destabilization, called limit cycling, is con-
troller “windup.” The lag in response to a step change in a control
signal will cause the controller’s output (the actuator’s input signal)
to continue to drift in the direction of the desired process variable
change (because no change is seen during the lag). Once the fast-act-
ing pneumatic actuator responds following the dead time, the valve
will quickly overshoot the setpoint. After the controller sends out a
corrective signal in the other direction and the dead time causes over-
shoot, the result is controller “hunting.”
Impact on the plantAcross some of a plant’s load range, oscillations caused by stiction,
overshoot, and/or dead time may not cause any operational upsets.
However, the oscillations will make associated spray valves and the
feedwater valve more active if pressure and temperature are not stabi-
lized by the HRH bypass actuator.
Steam turbine control. Even subtle changes in temperature or
pressure add thermal/mechanical fatigue cycles. Poor control of re-
heat pressure can cause significant fluctuations in IP drum levels.
Those swings can lead to gas turbine (GT) trips, safety valve trips,
and variations in steam flow to intercept control valves (ICVs) or noz-
zle valves, depending on the turbine design. The ICVs, which regulate
the steam input to the turbine, accelerate the unit, control its speed,
and synchronize and apply its load.
Before admitting steam to the turbine through the ICVs, the HRH
bypass actuator is responsible for balancing steam generation by sta-
bilizing drum pressure and steam flow. The repeatability and stabil-
ity of the actuator directly determine how quickly both parameters
stabilize. Once temperature and pressure have stabilized, the hold
period (used to allow the metal temperature of the HRSG drum to
reach equilibrium) can begin; at its conclusion, the GT can be ramped
to full load. The HP bypass actuator also plays a big role in this sta-
bilization.
Starting a second unit. The HRH bypass actuator is responsible
for matching the temperature and pressure of heat-recovery steam
generators (HRSGs) and the steam turbine when a second unit is
started in a typical 2 x 1 combined-cycle configuration. In this sce-
nario, the time that it takes to “blend” one GT/HRSG into the on-line
GT/HRSG and steam turbine depends directly on the control capabil-
ity and stability of the HRH bypass actuator.
Blending and load control of combined-cycle plants have become
increasingly important because the emissions of many plants now are
regulated during their start-up as well. Combustion turbines operated
at low loads are very inefficient and therefore produce excess NOx
and CO during start-up. Delayed start-ups produce more emissions,
not to mention lost generation sales. Until their temperature and pres-
sure are under control, stable, and matched, neither the gas turbine
nor the steam turbine can be ramped up to full load.
Condenser vacuum losses. Once a plant has been ramped up to
95% load, the HRH bypass actuators are completely closed and no
condenser vacuum is lost through the HRH valves (as long as they
remain tightly seated). But initial vacuum can be lost during start-up
and when starting a second unit, unless the vacuum is maintained by
the HRH bypass actuator. To keep condenser vacuum at the optimum
level, the actuator must respond rapidly enough to steam flow tran-
sients to control the bypass to the condenser in a way that bypasses
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CIRCLE 29 ON READER SERVICE CARD
March 2008 | POWER www.powermag.com 55
VALVES
as little excess steam as possible. Also, if the
HRH bypass valve is not stable, then more
steam than necessary will go to the condens-
er, allowing its vacuum to decay.
Steam turbine operation. A cascading
bypass system can increase the potential for
“windage” overheating of the HP turbine
during start-up and shutdown if the HP by-
pass and HRH bypass valves fail to precisely
control HP and HRH pressure.
The reheater pressure must be tightly con-
trolled at a low value, particularly during low-
flow conditions (such as during start-ups), to
keep the HP turbine’s back-end temperature
below 800F. One way to control HP turbine
exhaust temperatures is to install a start-up by-
pass system between the HP turbine exhaust
and the condenser. This expense can possibly
be avoided if the HRH bypass actuator can
control reheat pressure precisely enough.
Hydraulic vs. pneumatic actuatorsThe scenarios outlined above represent real
problems that combined-cycle power plant
owners and operators are experiencing to-
day. They will become even more common
as more plants are forced into daily cycling
service for which they were not designed.
Selecting hydraulic actuators instead of
pneumatic actuators for critical desuperheat-
ing valve applications is one way to address
cycling-related problems. Since oil is in-
compressible, performing the same response
calculations as before, but this time for a hy-
draulic actuator, yields much better results:
a dead time of just 0.00164 seconds and pis-
ton jumps in increments of just 0.00423, or
0.0564% of span.
Switching from pneumatic to hydraulic ac-
tuators virtually eliminates the lag in response
to a control signal change and reduces jump
to an insignificant level. Hydraulic actuation
systems can be tuned for very fine setpoint
control (down to 0.1% of span). In general,
they feature very fast stroking speeds, 100%
duty modulating service, unparalleled fre-
quency response (millisecond dead times),
immunity to dynamic instability and friction,
and almost immeasurable overshoot.
But there are downsides to going with
hydraulic actuators. Conventional hydraulic
Perc
ent s
pan
45.5
44.5
43.5
136.8 141.8 146.8 Time (seconds)
Control signalElectraulic actuator positionPneumatic/smart positioner actuator position
3. Out of sync. A hydraulic actuator like the Electraulic can be tuned for almost instanta-neous response. A typical pneumatic actuator has an inherently longer dead time and responds more slowly to a setpoint change. Source: Koso America Inc.
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CIRCLE 30 ON READER SERVICE CARD
www.powermag.com POWER | March 200856
VALVES
actuators have a reputation for being main-
tenance and reliability nightmares, and they
cost much more than their pneumatic cous-
ins. What’s more, hydraulic systems require
motors to run 24 hours a day, as well as an
extensive network of very high pressure
hydraulic tubing and fittings that may leak.
Plant owners and builders tend to avoid hy-
draulic systems for those reasons, preferring
instead to specify advanced pneumatic po-
sitioner technology, regardless of its perfor-
mance limitations.
To get an idea of the benefits of retrofit-
ting, take a close look at Figure 3 (p. 55),
which compares the performance of a typi-
cal hydraulic actuator to that of a pneumatic
actuator with a smart positioner tuned for
maximum response (shortest dead time). The
test whose results are shown was performed
with actuators tuned for identical stroking
speed on valves with polytetrafluoroethylene
(PTFE) packing. A pneumatic actuator can
be adjusted for less overshoot, but doing so
increases its dead time and makes its slow-
down to setpoint begin earlier.
Another possible way to avoid cycling-
related problems is to select a digitally con-
trolled hydraulic actuator optimized for low
fluid usage. The Electraulic actuator (www
.rexa.com) is a good example of this type of
device (Figures 4 through 7). It uses 20 times
less fluid (standard motor oil) than a typical
central system; it has no separate pumping
systems, reservoir tanks, or high-pressure
hoses; no fluid maintenance or filtration is
required; and its motor(s) only operate when
a position change is required. Sounds almost
too good to be true.
Taking it to the bankBy retrofitting its pneumatic actuators to hydrau-
lics one combined-cycle plant reduced its start-
up times dramatically. It also reduced the time
needed to blend a second GT/HRSG train into
an on-line train from 2 hours to 50 minutes.
The plant decided to retrofit its pneumatic
actuators after routinely experiencing hunt-
ing oscillations in the 35% to 55% stroke
4. IP attemperator retrofit. Retrofit of a conventional hydraulic system actuator (top) to an Electraulic actuator (bottom) on the IP attemperator of a typical combined-cycle plant. Courtesy: Koso America Inc.
5. IP bypass retrofit. Retrofit of a conventional hydraulic system actuator (top) to an Electraulic actuator (bottom) in the IP bypass line. Courtesy: Koso America Inc.
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CIRCLE 32 ON READER SERVICE CARD
www.powermag.com POWER | March 200858
VALVES
range. The oscillations created enough in-
stability in reheat pressure to make it over-
shoot by 25 psi. Many efforts to tune the
actuator and system (including the installa-
tion of a smart digital positioner) yielded no
improvement.
Finally, the owner bit the bullet and re-
placed the pneumatic valve actuation sys-
tem with a hydraulic system. The retrofit did
more than eliminate the oscillations and in-
stability; it also lowered the cost of starting
up a second GT/HRSG train. The following
bullet points detail the monetary savings and
gains the plant continues to realize:
■ Running the gas turbine at no load or low
load for one fewer hour per restart saves
$4,500 in natural gas priced at $10/mmBtu.
The plant cycles one GT/HRSG train each
night and brings it back on-line the next
day during certain months. With 60 re-
starts every year, the plant conservatively
estimates the annual value of this benefit
at $270,000 in fuel savings.
■ The faster the plant can restart in response
to grid demand, the faster it can produce
revenue. For example, one more hour of
generation by the plant’s 170-MW GT (at
full load), and one more hour of genera-
tion by its steam turbine at 80 MW (full
load is 160 MW) at 5 cents/kWh adds up
to $750,000 a year in increased revenue
from power sales.
■ Shorter start-ups allow for more of them
each year, because the plant has an annual
start-up emissions cap. ■
—Geoffrey Hynes ([email protected]) is international sales manager
for Koso America Inc.
6. HP attemperator retrofit. Retrofit of a conventional hydraulic system actuator (left) to an Electraulic actuator (right) on the HP attem-perator of a typical combined-cycle plant. Courtesy: Koso America Inc.
7. HP bypass retrofit. Retrofit of a conventional hydraulic system actuator (top) to an Electraulic actuator (bottom) in the HP bypass line. Courtesy: Koso America Inc.
March 2008 | POWER www.powermag.com 59
WATER MANAGEMENT
Benefits of evaporating FGD purge waterIn the U.S. and the European Union, scrubbers are installed on all new coal-fired
power plants because their technology is considered the best available for removing SO2. A zero-liquid-discharge system is the best technology for treating wet scrubber wastewater. With the future promising stricter limits on power plants’ water use, ZLD systems that concentrate scrubber purge streams are sure to become as common as ZLD cooling tower blowdown systems.
By William A. Shaw, PE, HPD
In coal-fired power stations, flue gas desul-
furization (FGD) is used to “scrub” most
of the sulfur dioxide (SO2) from the gas.
FGD is often performed using a wet process
in which SO2 is absorbed from the flue gas by
spraying it with a slurry containing limestone
(mainly calcium carbonate, CaCO3). The
SO2 reacts to form calcium sulfite, CaSO3,
which is further oxidized to produce gyp-
sum (CaSO4 x 2H2O) by introducing air into
the scrubber. The gypsum product is often
washed and sold for various uses; otherwise,
it is disposed of in a landfill.
Scrubber wastewater chemistryWater uses in a limestone-gypsum FGD
scrubber are easily identified (Figure 1).
The gypsum has to be removed continuously
from the scrubber, and it is replaced by fresh
limestone. In addition, a certain proportion of
the circulating water is removed as effluent
to control the buildup of chloride from coal
combustion products in the scrubber water.
The circulating scrubber water also contains
other water-soluble impurities from the flue
gas and the limestone.
FGD is an evaporative process, so it con-
centrates these impurities. The wastewater
from gypsum dewatering will have a pollut-
ant content that depends mostly on the type of
coal burned, the efficiency of the unit’s elec-
trostatic precipitator (ESP), the level and type
of impurities in the makeup water, the amount
of heavy metals and impurities in the lime-
stone, and the choice of gypsum dewatering
equipment. A good understanding of these
parameters is necessary to properly design an
effective FGD purge water treatment system.
Coal is the primary source of the sulfur
and chloride in scrubber wastewater and
a contributor of heavy metals as well. The
composition of the flue gas entering the FGD
plant is closely related to the composition of
the coal and the way it is burned. It’s also de-
termined by the type of upstream particulate-
control and denitrification devices used. The
flue gas contains SO2, fine particles of flyash
and their trace elements, volatile heavy met-
als such as mercury and selenium, and hydro-
gen chloride and fluoride.
The hydrogen chloride and fluoride are
partially absorbed in the absorber and react
with the limestone to form soluble calcium
chloride and insoluble calcium fluoride. Fly-
ash residues that have not been removed by
the ESP are partially washed out in the ab-
sorber. Consequently, the amount of heavy
metals entering the wastewater with the resi-
dues depends on the efficiency of the ESP. Ni-
trogen compounds such as nitrate, nitrite, and
ammonia are also present in FGD wastewater.
Most nitrogen compounds are created by coal
combustion. The temperature of combustion
and the nitrogen content of the coal affect the
concentration of the nitrogen compounds. If a
selective catalytic reduction (SCR) system is
upstream of the FGD plant, unreacted ammo-
nia also may be present in the wastewater.
Limestone is a widely variable material. It
usually contains impurities such as compounds
of magnesium, iron, and silica and traces of
heavy metals. Dibasic acid (DBA)—a mixture
of succinic, glutaric, and adipic acids—or an-
other organic acid such as formic acid is some-
times added to buffer the pH to improve SO2
absorption. These acids affect the solubility of
calcium carbonate and also raise the biologi-
cal oxygen demand of the effluent.
The purge water contains mainly calci-
um, magnesium, and sodium cations. Small
amounts of potassium and manganese also
are present, along with traces of ammonia
and heavy metals. The main anions are chlo-
ride and sulfate. The remaining halogens
(fluoride, bromide, and iodide), sulfur com-
pounds such as dithionate and peroxodisul-
fate, sulfur-nitrogen compounds, and nitrate
are present in smaller amounts.
Treatment of FGD wastewater must take
into account that the stream has the chem-
istry above, is supersaturated with gypsum,
has a pH between 4.5 and 5.5, and contains
heavy metals, suspended solids, and a high
(30,000 to 60,000 mg/l) chloride concentra-
tion. It also may have organic content if DBA
is added to the scrubber to enhance its SO2
removal efficiency.
Conventional treatment limitationsThe traditional way to treat FGD wastewa-
ter is to discharge the liquid effluent of a
limestone-gypsum system into a natural wa-
tercourse. In this process, wastewater from
1. Water lines. This diagram shows the inputs and outputs of a typical limestone-gypsum wet scrubbing process. Source: HPD
Flue gas
Electrostaticprecipitators
Flyash
Clean flue gas
Limestoneslurry
Air
Purge water
Gypsumdewatering
Gypsum cake
Scrubber
www.powermag.com POWER | March 200860
WATER MANAGEMENT
the FGD loop is fed into a series of reactor
tanks where its heavy metals are precipitated
by hydroxide/sulfide following the addition
of lime, organosulfide, and ferric chloride.
Two precipitation/flocculation stages are
usually included due to the wide variation in
the optimum pH values for precipitation of
the metals. If selenium, nitrates, and organics
are present in the purge stream, it will prob-
ably require biological treatment prior to dis-
charge. Such treatment methods can reduce
the concentration of suspended solids and
metals, acidity, and oxygen demand, but they
do not reduce levels of chloride or total dis-
solved solids (TDS).
However, physical, chemical, and bio-
logical treatment methods may not be able
to reduce wastewater concentrations to the
parts-per-trillion levels required for dis-
charge of some chemical species such as
mercury as their discharge limits become
more stringent. When conventional treat-
ment methods cannot produce an effluent
that complies with the plant’s discharge per-
mit, evaporation of the purge stream should
be considered.
Evaporation is an appealing FGD waste-
water treatment method because, in theory, it
can completely separate all dissolved species
(benign, hazardous, or toxic) from the water,
producing a stable solid that can be disposed
of in a landfill. If the high-quality distilled
water produced by the process is reused in
the power plant, there will be zero discharge
of wastewater to the environment.
First, reduce the volumeFalling-film evaporators (also called brine
concentrators) have been used for many years
to substantially reduce the volume of waste-
water discharged from power plants. Often,
evaporative crystallizers are added to achieve
zero liquid discharge (ZLD). Such ZLD sys-
tems have historically been used to eliminate
discharges of cooling tower blowdown and
demineralizer wastes. Recently, several ZLD
systems also have been installed to eliminate
scrubber blowdown from wet FGD systems
(Figure 2).
Evaporators and crystallizers operate by
transferring latent heat from condensing
steam across a tube surface to cause a liquid
at its boiling temperature to partially vaporize.
But because the steam cycle in a power plant
is in precise balance, steam is usually not
available for use by a ZLD system. Instead,
most power plant ZLD systems use an electric
motor-driven heat pump in a technique called
mechanical vapor recompression (MVR) to
drive the evaporation process (Figure 3).
External steam, often from a dedicated
start-up electric boiler, is used only at cold
start-up to heat the equipment and bring the
wastewater to the boiling temperature. Once
the wastewater begins to boil inside the evap-
orator, an electrically driven compressor is
started. The water vapor evaporated from the
wastewater is compressed, raising its pres-
sure and temperature. The hotter compressed
water vapor flows to the heating side of the
evaporator tubes, where it condenses and
transfers its latent heat across the tube wall.
That causes more water to evaporate, com-
pleting the cycle. The condensed water evap-
orated from the wastewater is pumped from
the evaporator as distilled water (distillate).
Falling-film evaporators/brine concentra-
tors have vertical tube bundles that use some
sort of device to distribute the wastewater at
its boiling temperature as a thin film around
the inside surfaces of the tubes. This film
flows uniformly down the entire length of
the tube, and as heat is transferred across the
tube wall from the condensing steam on the
other side, the film boils. Water vapor is re-
leased into the core of the tube and mixes and
flows with the liquid film.
2. Benign effluents. This typical zero-liquid-discharge (ZLD) system at a combined-cycle plant produces only reusable water and a solid cake suitable for disposal in a landfill. Courtesy: HPD
3. Steam substitute. Mechanical vapor recompression (MVR) is used to drive the evapo-ration process in a ZLD system when an external steam supply is not available. Source: HPD
Distillate (condensed vapor)
Compressed vapor
Mechanical vaporrecompression evaporator
Compressor
Evaporatedvapor
Electricalenergy
Concentrated brineFlue gas
delsulfurizerfeed
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CIRCLE 2 ON READER SERVICE CARD
www.powermag.com POWER | March 200862
WATER MANAGEMENT
Next, separate the vaporBecause power plant wastewaters (including
FGD purge water) are often saturated with
gypsum, the brine concentrator is “seeded”
with calcium sulfate to prevent the deposi-
tion of low-solubility calcium salts on the
tube surfaces as scale. Scaling is prevented
by preferential precipitation of low-solubil-
ity calcium salts on the seed crystals rather
than on the tubes (Figure 4). In a falling-film
evaporator, a vapor separator with an inte-
gral mist eliminator is attached to the lower
end of the evaporator’s tube bundles to help
separate the water vapor from the wastewater
(Figure 5). The two subsystems ensure that
only clean, dry vapor enters the compressor,
reducing the risk of its erosion and corro-
sion by droplets of brine carried over with
the vapor. Mist elimination also ensures the
distillate’s purity. A well-designed falling-
film evaporator will produce distillate with
less than 5 ppm TDS.
The falling-film brine concentrator with
seeding and MVR can now be integrated into
a system (Figure 6). A plate heat exchanger
recovers heat from the outgoing distillate,
making it available to preheat the feed. The
feed is typically acidified to eliminate resid-
ual alkalinity, and a deaerator is included to
remove CO2 and dissolved oxygen from the
feed. That reduces the potential for corrosion
and scaling in the evaporator vessel.
Then, concentrate the solidsForced-circulation crystallizers (Figure 7)
are the type most often used in power plant
wastewater applications. Condensing steam
normally provides the energy to evaporate
water from waste brine, but in this type of
evaporator the brine is forced through the
heater tubes by a recirculation pump at high
velocity. Flooding the tubes prevents evapo-
ration from occurring inside them. The high
velocity of the brine and the suppression of
boiling in the tubes prevent scale from form-
ing on the crystallizer’s tube surfaces.
Evaporation occurs when the circulating
brine flash boils in a separate vapor body.
Nucleation and growth of salt crystals that
have exceeded their solubility also occur
there. As in the evaporator, a mist eliminator
installed in the vapor body separates droplets
of brine from the water vapor, protecting the
compressor from corrosion and erosion and
ensuring the purity of the distillate.
Depending on the TDS concentration
maintained in the scrubber, a falling-film
brine concentrator can typically concentrate
FGD purge water five to 10 times before run-
ning up against the limitations imposed by
the elevation of boiling point and the solubil-
ity limits of the sodium salts. The system re-
duces the water content of the wastewater by
80% to 90%, so for every 100 gpm of feed,
10 to 20 gpm of concentrated brine is dis-
charged and 80 to 90 gpm of distilled water
is produced for reuse in the power plant.
Ordinarily, the concentrated brine would
be sent to a forced-circulation crystallizer
to evaporate the remaining water and pre-
cipitate and dewater the solid salts. However,
the solubility of the calcium and magnesium
chloride salts that dominate the content of
FGD wastewater is so high that it is usually
impractical to try to precipitate these salts
in a forced-circulation crystallizer. It can be
done, but the boiling point of the solution is
too high to use MVR, so high-pressure steam
must be supplied. What’s more, because the
calcium and magnesium chloride are acidic
salts that are extremely corrosive at the tem-
5. Corrosion controller. Eliminating the mist from the vapor separated by a falling-film evaporator dries the input to the compressor, reducing the potential for corrosion and erosion. Source: HPD
Distribution plates
Heater
Water vapor to compressor
Entrainment separator
Feed
Concentrated brine
Recirculation pump
Water vapor from compressor
Vent
Manway
Distillate
Vapor body
4. Scale buster. Seeding a falling-film evaporator avoids deposition of calcium salts on the tube surfaces of a brine concentrator. Source: HPD
Distributor plate
Seed crystals
Tube wall
Vapor from compressor
Condensed steam(distillate)
Brine film
Heat transferacross tube
Evaporated vapor
Brine
Brine
Top tubesheet
March 2008 | POWER www.powermag.com 63
WATER MANAGEMENT
peratures and concentrations required to
crystallize them, any crystallizer equipment
that comes in contact with the brine must be
made of very expensive noble alloys such as
palladium-alloyed titanium and high nickel-
chrome-molybdenum alloys.
There are some cases in which a brine
crystallizer may not be economically fea-
sible. Some power plants have considered
evaporating their FGD wastewater by a brine
concentrator and disposing of the resulting
concentrate stream on-site either along with
ash or in a separate surface impoundment.
Others have considered using spray drying to
remove the remaining moisture from the con-
centrate, producing a dry product suitable for
disposal in a landfill or coal mine. It should
be noted that because a spray dryer will re-
quire a fuel oil or natural gas supply, it also
will likely need an air permit. In addition,
the dried salt residuals produced are strongly
hygroscopic, so they must be bagged quickly
to keep them from absorbing moisture from
the atmosphere before sending them off for
disposal. Other methods of drying the brine
concentrator blowdown are possible. They
include the use of flakers, prilling towers,
and other methods common to the production
of calcium and magnesium chloride salts.
Making salt waterMany of the challenges of designing an FGD
wastewater treatment process based on evap-
oration are related to the basic chemistry pro-
file of wastewater. Calcium and magnesium
chloride salts are difficult to crystallize and
highly corrosive.
To avoid both problems, FGD wastewater
can be pretreated using conventional lime-
soda ash softening. Slaked lime (calcium
hydroxide, Ca(OH)2) and soda ash (sodium
carbonate, Na2CO3) are used as reagents in
the pretreatment step along with small quan-
tities of ferric chloride and polyelectrolyte to
enhance the separation of suspended solids.
Adding lime slurry to the wastewater in-
creases the calcium ion concentration, which
reduces the gypsum supersaturation and in
turn the scaling potential of the wastewater.
It also raises the pH so that magnesium hy-
droxide precipitates. Soda ash is added in a
separate reaction tank to precipitate the cal-
cium as calcium carbonate. The net result of
the softening process: Sodium ions are sub-
stituted for most of the calcium and magne-
sium ions, so the softened FGD wastewater
becomes mainly an aqueous solution of so-
dium chloride.
Another possibility is to use a conven-
tional water-softening process, producing a
ZLD system similar to those currently in use
at power plants to treat cooling tower blow-
down. Sodium chloride can be readily crys-
tallized in a conventional forced-circulation
crystallizer. Although salt is corrosive, its use
requires less use of noble materials of con-
struction such as super-austenitic and super-
duplex stainless steels.
Future system design Although power plants have used evapora-
tion for decades to eliminate their discharges
of cooling tower blowdown, the evaporation
of FGD purge water is a much more recent
application with only a few installations and
very little operating experience. However,
some evaporator suppliers have experience
in evaporating calcium, magnesium, and so-
dium salts that is directly applicable to the
evaporation of FGD wastewater. Evaporation
is a treatment method that will be considered
more often in the future, given the inevitable
tightening of limits on air and water dis-
charges from all power plants, the size of the
existing U.S. coal-fired fleet, and the pros-
pects for its future expansion.
A plant’s decision about which treatment
method to use must take into account its capi-
tal and operating costs and other site-specific
factors. Due to the current dearth of ZLD
system operating experience on FGD waste-
water, plant designers, builders, and owners
considering a ZLD process should closely
examine a prospective supplier’s bench and
pilot-scale testing capabilities for calcium,
magnesium, and sodium chloride evapora-
tors. A robust system is also important to
look for. Do your homework before you buy
to avoid costly equipment failures and even
more costly losses of generation revenue. ■
—William A. Shaw, PE ([email protected]) is a senior process
engineer for HPD, a Veolia Water Solutions & Technologies company
based in Plainfield, Ill.
6. A complete ZLD system. Here, the brine concentrator evaporator of Figure 5 is integrated with seeding and MVR subsystems. The system produces concentrated brine for crystallization. Source: HPD
Vent
DeaeratorBrine concentrator
Compressor
Concentrated brineto crystallizer
Seed recycle
Recirculationpump
Leveltank
Acid
Feed
Feedpreheater
Feed tank
Recoveredwater
7. Crystal clear. A forced-circulation crystallizer with MVR and solids dewatering uses a compressor and recirculation to produce recovered water and solids for disposal. The feed at bottom left comes from the brine concentrator of Figure 6. Source: HPD
Crystallizervapor body
Noncondensablegas vent
Crystallizerheater
Recoveredwater
Concentrated brinefrom brine concentrator
Recirculationpump
Compressiondevice
Dewateringdevice
Solids todisposal
Slurrytank
www.powermag.com POWER | March 200864
COMBINED-CYCLE RELIABILITY
Extend EOH tracking to the entire plantPredicting combined-cycle system longevity and determining optimal main-
tenance intervals at the same time is difficult: It requires balancing repair costs against the risk of trying to squeeze that last bit of life out of some component before it fails. One solution to the problem is to extend cov-erage of an equivalent operating hours (EOH) preventive management program for turbines to the entire plant.
By Peter S. Jackson, PE, and David S. Moelling, PE, Tetra Engineering Group Inc.
Combined-cycle plant operators have
always recorded how long and often
their gas and steam turbines have run
and used that data to schedule overhauls and
maintenance. Whether the metric used is
equivalent operating hours (EOH) or equiva-
lent starts/hour, tracking turbine use to moni-
tor the cumulative effects of wear and corro-
sion has become the established method for
scheduling major maintenance. It only makes
sense to extend this strategy to the combined-
cycle plant’s third key system—the heat-
recovery steam generator (HRSG).
Scheduling upkeep according to key op-
erating parameters such as turbine operating
hours or starts, HRSG drum pH, or total fuel
flow since the last overhaul enhances both
maintenance and system reliability. A plant
that is started up hundreds of times annually
will have different preventive maintenance
(PM) intervals for its pumps, valves, and tur-
bine and HRSG components than a plant that
runs continuously. If PM service intervals
don’t reflect this reality, an equipment failure
will always be a surprise—a very unpleasant
surprise if it brings down a plant and prevents
it from making a big profit on a peak demand
day when spot market prices skyrocket. The
PM approach may be operator-friendly, but
addressing plant reliability by waiting for a
failure to occur and then repairing its cause is
not an economically viable strategy.
Who should apply?Tracking the EOH of systems to correlate
cumulative wear and corrosion with accumu-
lated run time began in the aerospace indus-
try. Most turbine and HRSG manufacturers
now use the process to predict how long their
systems will perform reliably with timely
maintenance, and how quickly they will
fail without it. A combined-cycle plant that
would benefit from implementing an EOH
tracking program is one that:
■ Is routinely cycled or experiences large
load changes.
■ Uses lots of supplemental firing to handle
large steam load swings.
■ Switches the fuel of its gas turbines or
duct burners.
■ Duct-fires its HRSG(s) with low-quality
fuels.
■ Is often laid up for extended periods of
time.
Tracking system EOH allows PM activi-
ties to remain consistent with plant operation.
PM intervals are shortened when the plant is
run harder, and extended when duty is less
demanding. Even developing an EOH pro-
gram is beneficial: The process identifies ar-
eas where maintenance can be improved, and
those areas can then be emphasized by other
management planning programs. However,
the results of developing an EOH program
are most important because they specify a
consistent set of data collection processes
suitable for plantwide use.
Beyond EOHAs mentioned, gas turbine vendors have long
based their maintenance recommendations
on formulas that relate cumulative compo-
nent wear and tear to proxies such as EOH,
starts, trips, and fuel switches. Indeed, most
suppliers now include these formulas in their
maintenance and service support agreements
to help their power plant customers plan in-
spection and overhaul outages.
The earliest of these calculations produced
results in terms of EOH only. Using a par-
ticular formula, an end user could equate the
negative impact on reliability of a turbine
start or trip to that of running the unit for a
specific number of hours. Today, however,
many gas turbine suppliers use formulas that
produce more than just EOH numbers. Newer
formulas also state the impact in terms such
as equivalent starts (ES) and equivalent hours
(EH), and some even calculate maintenance
intervals. The first limit reached determines
when maintenance will first be needed.
Rolling your own programUnlike turbines, most other combined-cycle
plant systems—including HRSGs—lack
manufacturer-supplied EOH formulas or
detailed PM recommendations for reliable
service. If any maintenance guidelines are
provided, they are rough, such as “overhaul
every five years.” This lack of guidance re-
quires the plant’s maintenance staff to de-
termine HRSG PM intervals based on their
personal experience or the experience of peer
plants.
Tetra Engineering Group recommends
taking the following steps to incorporate
more complex EOH-type scheduling into a
plant’s overall maintenance program:
■ Identify the systems and components to be
included in EOH calculations.
■ Identify major service-related failure
modes by component using Failure Mode
and Effects Analysis (FMEA).
■ Relate operational parameters such as
starts, trips, high/low load, shutdown time,
high/low temperatures, etc. to each failure
mode.
■ Match PM requirements to the failure
modes.
■ Determine the relationship of a system’s
operational parameters to its longevity
based on experience, analysis, or guidance
from the supplier.
■ Integrate manufacturer-supplied EOH val-
ues for the gas turbine, steam turbine, and
HRSG(s) to produce a comprehensive and
consistent EOH-based maintenance and
inspection program for the entire plant.
■ Implement EOH tracking either using an
on-line system such as OSI PI data his-
March 2008 | POWER www.powermag.com 65
torian (www.osisoft.com), a link to the
plant’s maintenance management system,
or another maintenance scheduling tool.
The weakest linksWith the exception of turbines, the HRSG is
perhaps the combined-cycle plant system that
can benefit the most from a well-designed
EOH-tracking program. Although HRSG
suppliers typically provide limited recom-
mendations for scheduled maintenance,
HRSG users must have a formal and detailed
program of inspection and cleaning in place
to avoid serious O&M problems. Such prob-
lems can be caused by daily cycling, over-
firing duct burners, large steam load swings,
tube leaks, water chemistry upsets, short- and
long-term layups, or fouling of a selective
catalytic reduction system’s (SCR’s) catalyst
(Figures 1 and 2).
1. Extreme service. This boiler tube was ruptured by cyclic fatigue. Many HRSGs designed for baseload service experience problems like this when pressed into cycling service. Courtesy: Tetra Engineering Group Inc.
2. Deposit account. These finned superheater tubes are covered by heavy deposits as a
result of burning low-Btu gas with higher-than-normal H2S content. Courtesy: Tetra Engineering Group Inc.
May 2008■ Emerging trends in plant
water treatment
■ Improve plant economics with a properly designed DG system
■ Survey of the latest advances in renewable technologies
■ Bonus distribution at ISA POWID/EPRI Conference and AWEA Wind Power
Closing Date:April 2, 2008
June 2008■ Advanced DCS systems
and virtual plant operators
■ Gas turbine design on the leading edge
■ Performance centers add value to generating assets
Closing Date:May 5, 2008
ACT NOW!Reserve Your AdContact your sales representative (listed on p. 4)
DELIVERS!
COMBINED-CYCLE RELIABILITY
www.powermag.com POWER | March 200866
COMBINED-CYCLE RELIABILITY
EOH formulas for an HRSG should be de-
veloped from a review of its design and oper-
ating history and based on a straightforward
assessment of the lifetimes of major compo-
nents. The assessment must include not just
the HRSG’s pressure parts (Figure 3) but
also all of its ancillary systems: main stream
valves and sprays, reheaters, duct burners
and supporting components, and its casing
and stack. Remember to include the post-
combustion emissions catalysts and controls
for the SCR and CO systems.
An effective EOH program should also
scrutinize other major systems and compo-
nents of the typical combined-cycle plant, as
explained below.
Valves. Large valves (bypass, stop and
check, and feedwater control valves) are
high-maintenance devices that must be in-
stalled correctly and are very sensitive to
plant operating conditions (see “Desuper-
heating valves take the heat” on p. 52). EOH
formulations are best developed from direct
experience at the plant and from the experi-
ence of similar installations at peer plants. A
systematic review of maintenance and repair
records usually provides invaluable insight
into the effectiveness and thoroughness of
previous maintenance programs.
Condensers. Steam condensers (air-
cooled condensers in particular) are suscep-
tible to corrosion, erosion, and mechanical
damage at rates that depend on the plant’s
operating profile and location. Fuel switches,
bypass steam dump operation, and changes
in steam and water chemistry all take their
toll on long-term reliability. Both experience
and analysis are required to set EOH param-
eters for condensers, and that’s also the case
for deaerators and feedwater heaters.
Pipes. Power plant piping (main steam,
reheat, and feedwater lines) is not immune
to changes in unit operation. Thermal tran-
sients can fatigue and damage pipe sup-
ports, start-ups can produce water hammer,
and load changes can increase flow-accel-
erated corrosion. Pipe stress and flexibility
reports can provide basic data about thermal
fatigue that EOH calculations can turn into
actionable information. Separately, opera-
tions reviews and analyses can provide a
wealth of data on corrosion and other dam-
age mechanisms.
Pumps. Boiler feedpumps, condensate
pumps, and circulating water and other
large pumps also are affected by cycling.
Here, experience and vendor guidance are
the best foundations on which to develop
EOH factors.
Electrical systems. Large transformers
and switchgear usually come with guidance
on overhaul intervals based on time, the ef-
fect of switching on load current, or other
measures. These recommendations can be
incorporated directly into EOH formulas.
Put it all togetherTetra Engineering Group has developed EOH
programs for many combined-cycle plants.
They range from programs that cover only
the HRSG to those that cover a complete
plant, including its gas and steam turbines. In
our experience, the best ways to reap the full
benefit of these programs are to:
■ Keep EOH formulas simple but realistic.
Develop a system that can capture signifi-
cant plant upsets without too much effort.
Avoid excessive detail, because it can re-
sult in an unworkable system.
■ Expect minimal guidance from vendors.
Be prepared to develop your own mainte-
nance bases.
■ Automate service tracking via your dis-
tributed control, performance indicator, or
similar system. Make sure the system you
use has basic data validation and replace-
ment functions. The last thing you need is
a tracking system that crashes due to the
failure of an instrument.
■ Consider renewal factors. Does overhaul-
ing a system or component make it as
good as new again, or something less?
■ Focus on the big-ticket items if your bud-
get is tight.
Leveraging the effortA good EOH program can also help justify
the replacement of substandard components
or the upgrade of an existing system (such as
for water chemistry). In addition, it can jus-
tify taking action to address water chemistry
or fuel problems reflected by higher EOH
values. Finally, the actual operating and cost
data developed by a strong EOH program are
very helpful when developing dispatch cost
and variable O&M cost studies (Figure 4) for
plants that must routinely bid into competi-
tive markets for operating hours. ■
—Peter S. Jackson, PE ([email protected]) is director of field
services, and David S. Moelling, PE ([email protected]) is chief
engineer at Tetra Engineering Group Inc.
4. Pay the freight. This chart shows a typical distribution of variable O&M costs, in $/MWh, for a combined-cycle plant. A plant-wide EOH program can make managing these costs more precise. Source: Tetra Engineering Group Inc.
Note: HRSG/SCR = heat-recovery steam generator/selective catalytic reduction system.
Condenser/cooling tower, $0.03 (1%)
Steam turbine,
$0.21(11%)
Accruals, $0.27 (14%)
Consumables, $1.00 (50%)
HRSG/SCR, $0.46 (24%)
3. Beat the drum. This HP HRSG drum had to be removed to repair damage caused by a gas explosion inside it. Courtesy: Tetra Engineering Group Inc.
March 2008 | POWER www.powermag.com 67
EVENTS
ELECTRIC POWER celebrates 10th anniversary in BaltimoreAt this juncture our industry is faced with greater uncertainty and opportunity
than ever before. That’s why you won’t want to miss all the informa-tion, ideas, and networking available at the power generation industry’s premier event in May.
By David I. Johnson
ELECTRIC POWER 2008, the world’s
most comprehensive conference cover-
ing power generation, will celebrate its
10th anniversary at the Baltimore Conven-
tion Center from May 6 through May 8. A
full agenda of preconference workshops and
tutorials is scheduled for Monday, May 5
(see sidebar, below).
The event, which is sponsored by POWER
magazine, has been programmed to meet
the information needs of power generating
companies. Programming is developed under
the direction of an industry-based advisory
committee comprising approximately 150
members from industry, government, and ac-
ademia. More than one-third of the members
are from generating companies.
The program features in-depth topics
that cover business, engineering, and plant
operations issues. More than 400 speakers
and panelists will participate in the pro-
gram, which features 16 conference tracks,
two user group meetings, the Carbon Con-
straint Conference, and 12 preconference
Best Practices workshops and tutorials. The
latest power industry technologies will be
highlighted by approximately 500 exhibi-
tors (see sidebar, p. 69).
Keynote sessionThe conference starts with a State of the In-
dustry Address by Pat Wood III, principal of
Wood3 Resources and former chairman of
Preconference workshops and tutorials add value to the conference
Although the ELEC-TRIC POWER Confer-ence and user group meetings start on Tuesday, May 6, there is a lot of activity at the convention cen-ter on Monday, May 5. A full slate of Best Practices workshops
and tutorials will be held, the Power Plant Awards Banquet will recognize the PRB Coal Users’ Group Plant of the Year, and POWER magazine’s Plant of the Year and the Marmaduke Plant of the Year. The featured speaker at the banquet is Fred Haise, com-mander of the ill-fated Apollo 13 mission in 1970. In the movie by the same name he was portrayed by actor Bill Paxton.
Preconference workshops will cover:■ Status of Biomass for Power Generation
in the Renewable Energy Portfolio■ Boiler Combustion Optimization and
NOx Reduction
■ Technologies and Economics of Simulta-neous Removal of SOx NOx, and Mercury to Achieve Near-Zero Emission from Coal-Fired Power Plants
■ PRB Best Practices (Boiler, Coal-Han-dling, and Fire)
■ Plant Managers’ Roundtable (see side-bar at right).
■ U.S. Commercial Service, Department of Commerce: Exporting U.S. Power Tech-nologies and Equipment
■ Solar Energy Business Models for Elec-tric Utilities (Organized by the Solar Electric Power Association)
■ PRB: What You Don’t Know About Con-veyor Systems
■ Practical CPM for the Contractor and Owner
■ Energy, Money, and Value: Best Prac-tices in Linking Energy Management to Business Performance (Organized by the Council of Industrial Boiler Owners)
■ Boiler Slag and Ash Workshop■ PRB Fire Protection
Fred Haise
Power Plant Manager’s RoundtableThe ELECTRIC POWER Plant Managers’ Roundtable will be presented on the afternoon of Monday, May 6—the day before the main conference begins. In-troduced at the 2007 event, this round-table was voted an event highlight by those in attendance. Admission is com-plimentary for plant managers and their management team. All types of generat-ing stations and fuels will be covered. The format is interactive. The topics are key concerns for plant managers in today’s environment:
■ Developing a Positive Plant Culture■ Staff Retention and Recruitment■ Compliance (Environmental and
Safety)■ Training■ Plant Security■ Litigation Exposure■ Maintenance Planning Systems (Lots
of Computer Systems)■ Challenges of an Aging Infrastructure■ Maintenance and Overhaul Strategies■ Successful PdM (Predictive Mainte-
nance) Case Studies. ■ Successful DCS (Digital Control Sys-
tems) Upgrade Projects ■ Have Wireless Networks Arrived at
Power Plants?■ Operating Problems with Cycling Gas
Turbine Plants.■ Sharing Lessons Learned
www.powermag.com POWER | March 200868
EVENTS
the Federal Energy Regulatory Commission.
Following his presentation will be the CEO
Roundtable, with distinguished industry
leaders candidly exploring both the oppor-
tunities and the challenges facing the power
industry. Dr. Robert Peltier, PE, POWER’s
editor-in-chief, will moderate the session.
This year’s distinguished panel features the
following industry leaders from both inves-
tor- and government-owned gencos who have
various perspectives on the industry:
■ Thomas Brooks, Vice Chairman, Execu-
tive Vice President, Constellation Energy
■ Bill Carnahan, Executive Director, South-
ern California Public Power Authority
■ Milton Lee, General Manager and CEO,
CPS Energy
■ Michael Morris, Chairman, President, and
CEO, American Electric Power
■ James E. Rogers, Jr., Chairman, President,
and CEO, Duke Energy Corp.
■ Jeffry Sterba, Chairman, President, and
CEO, PNM Resources Inc.
Following the CEO Roundtable, the
conference moves into breakout sessions.
Delegates can choose among the 16 ELEC-
TRIC POWER tracks or the two user group
meetings.
Strategic TracksFour tracks examine topics from a manage-
ment perspective.
Power industry trends. The power in-
dustry is experiencing significant change
driven by a number of long-range, complex
and often conflicting trends. What are these
forces? Where will they lead us? What will
the industry look like 15 years from now?
These sessions discuss the drivers for change
and provide a look into our future:
CEO Roundtable participants for 2008Keynote speaker
Pat Wood III Thomas Brooks Bill Carnahan Milton Lee Michael Morris James E. Rogers, Jr. Jeffry Sterba
with Platts new suite of Electric Power System wall maps for the US
New U.S. Electric Power Suite of Maps include:Megawatt Daily Pricing RegionsU.S. Electric Power System Map & CD-ROMU.S. Utilities Service TerritoriesU.S. Power GenerationU.S. Transmission SystemNortheast Electric Power SystemERCOT Electric Power SystemN. America Electric Power System Atlas & CD-ROM*WECC Electric Power System*Coming August 2007
Visit www.maps.platts.com or call the Platts sales office at 1-800-PLATTS8Priority code: JSUDI0707A
Visualize the electric power industry
March 2008 | POWER www.powermag.com 69
EVENTS
■ The Perfect Storm: Opportunity or Doom?
■ Infrastructure Security Issues
■ Logistics—Supply Chain Challenges
■ Labor/People Development for the Future
■ Electricity Delivery Models
■ Environmental Convergence
Grid power. What value does power
have if it cannot get from source to market?
None! The grid is critical for a market to
succeed. Speakers will look at current and
future trends in the transmission systems in
the Midwest and Mid-Atlantic and at how to
encourage investment.
■ The Perfect Storm: Opportunity or
Doom?
■ Infrastructure Security Issues
■ ISO Operations, Opportunities, Challeng-
es, and Risks
■ Distributed Smart Grid Technologies and
Applications
■ Electric Power Delivery Models
■ Connecting Renewable Generation
Fuel strategies—price/quality/de-livery/opportunity. Fuel represents over
70% of the costs for fossil-fueled genera-
tion, and coal is currently subject to extreme
supply and price volatility. Sessions in this
track examine the challenges and solutions
for coal supply, quality, transportation, stor-
age, and handling. This track will also look
at how the impact of coal combustion and
gasification residues becomes significant if
they are not converted to salable byproducts
and at the impact of delivery and utilization
of LNG and other gaseous fuels.
■ Impact of Market Growth on Fuel
Strategies
■ Procurement and Market Issues
■ Natural Gas, LNG, and Gasification Issues
■ Coal Quality Characterization Methods
and Applications
■ Alternative and Opportunity Fuels
■ Strategies for a Benign Environment
Fleet optimization. Sessions in this
track will focus on issues associated with
the operation of a generating fleet. Topics to
be addressed include increasing asset value,
tradeoffs between reliability and short-term
economics, managing emissions constraints,
applying intelligent controls/IT systems, and
satisfying renewable portfolio standards. All
of the above must be addressed within the
context of the operation of a fleet of units.
In addition, the asset owner must manage de-
mand and the delivery of ancillary services.
This includes fleets in an ISO-managed en-
vironment and where ISO markets have not
yet developed.
■ Economic Optimization and Maximizing
Asset Value
■ Knowledge Management: A Report from
the Trenches
■ ISO Operations, Opportunities, Challeng-
es, and Risks
■ Renewable Portfolio Standards—A Stark
Reality?
■ Fleet Maintenance Improvements
Tactical Meetings—Fuels and TechnologiesSix tracks will examine the latest develop-
ments in the power industry by fuel and tech-
nology perspectives.
Coal power plants—upgrades and new capacity. With over 50% of North
America’s electricity generated by coal-fired
power plants, coal consumption is expected
to increase. However, the industry is expe-
riencing challenges in adding new capacity
while the existing infrastructure is undergo-
ing a massive environmental retrofit program.
These sessions will explore the challenges
and proposed solutions.
■ New Coal Projects/Challenges
■ Advanced Pulverized Coal Technologies
■ Boiler Operational Issues
■ Coal-Fired Stations—New Plant
Construction
■ Material-Handling System Upgrades (two
sessions)
IGCC and other advanced coal tech-nologies. Is integrated gasification com-
bined-cycle (IGCC) the answer, or is it
coal-based substitute natural gas (SNG)?
The power generation industry, especially
the coal-to-power sector, is asking what the
next fleet of fossil-fueled power plants will
look like. Carbon capture requirements are
already occurring in some states and are
being discussed in national forums. Delays
on coal power projects may prompt a return
to natural gas combined-cycle plants. What
is happening in the gasification industry in
response to building pressure on the power
sector to site new coal power plants? This
track will examine IGCC project develop-
ment paths from design to operation, the
status of the most advanced commercial
projects, plus ongoing advanced gasifica-
tion and oxyfuel combustion demonstration
projects.
■ IGCC Projects
■ IGCC Environmental Performance and
Regulatory Issues
■ IGCC Project Development—Soup to
Nuts
■ Substitute Natural Gas
■ Advanced Coal Technology and Develop-
ments Demonstration Projects
■ Oxyfuel and Other Advanced Combustion
Technologies
Gas turbine and combined-cycle power plants. For more than a decade, gas
turbine–based power plants (either in simple-
or combined-cycle configurations) ruled the
new plant construction market. High-effi-
ciency projects using a low-polluting fuel
provided a win-win situation. However, fluc-
tuations in the cost of natural gas presented
plant operators with unexpected challenges.
These sessions examine issues related to gas-
powered plants.
The ELECTRIC POWER ExhibitionThe 10th Anniversary of the ELECTRIC POWER Exhibition will fea-ture the largest display of technology ever presented at the event. The exhibition will be a focal point for many activities, including lunch each day of the conference and complimentary receptions on the first two days.
One lucky visitor will get the keys to a Harley-Davidson motor-cycle (or at least the cash to purchase one). The exhibition allows visitors to discuss their needs with suppliers, network with old friends, and review the latest technologies developed by suppliers to the power industry.
www.powermag.com POWER | March 200870
EVENTS
■ Fast Start Technology Update
■ Power Augmentation Technologies and
Asset Optimization
■ Turbine System Upgrades
■ Combined-Cycle Optimization and
Evaluation
■ Combined-Cycle Projects—Challenges to
Success
■ Combined-Cycle Operating Experience
Nuclear power. The nuclear renaissance
is accelerating. How is the nuclear industry
supporting this renewed growth area of gen-
eration? What issues confront current operat-
ing plant owners, and how are nuclear plant
activities being managed at the same time?
This session will give perspectives on current
and future nuclear power issues.
■ New Nuclear Reactor Update—Deals,
Deals, and More Deals
■ Licensing and Regulatory: How Is It
Working?
■ Digital I&C Issues in New and Existing
Nuclear Power Plants
■ Meeting Staffing Needs for the Nuclear
Renaissance
■ Getting the Most Out of Nuclear Assets
■ Future Nuclear Technologies
■ Nuclear Suppliers—Getting in the Game
Renewable power. Thanks to increas-
ing public perception of global warming and
impending legislative actions, renewable
energy has received continued attention. In
response to this challenge, manufacturers
have focused on reducing costs and increas-
ing manufacturing capacity, thus making re-
newable power the first choice for reducing
greenhouse gases. This track will highlight
the developments being done and how re-
newables are being adopted increasingly by
the utility industry.
■ Utility Perspective—Panel Discussion
■ Concentrated Solar Power and Photovoltaics
■ Wind Energy
■ Biomass Utilization
■ State and Federal Programs and Targets to
Promote Renewables, Worldwide
■ Connecting Renewable Generation
Distributed resources. Distributed en-
ergy resources continue to gain favor as an
option for customers wanting to include
self-generation as part of their energy supply
strategy. These small, modular energy gener-
ation, energy storage, and combined heat and
power (cogeneration) technologies can not
only reduce the cost of electricity and steam
heat service to customers, but they can also
enhance power quality and provide the capa-
bility to maintain operation in the event of a
power failure. In this track, you will catch up
on the most recent advances in the technolo-
gies from leaders in the field. Also included
will be sessions on critical issues such as fuel
systems, grid interconnection, and an over-
view of the trends in the field.
■ Distributed Resources Overview
■ Energy Storage
■ Fuel Cells
■ Distributed Smart Grid Technologies and
Applications
■ Alternative and Opportunity Fuels
■ CHP—Cogeneration
Tactical Meetings—Engineering and Operating ConsiderationsFour tracks cover sections of the plant that
are not fuel-specific.
Power plant safety and security. Ef-
fective plant safety and security practices are
preached by most companies, but every year
incidents occur that cause property loss and
impact the lives of many. This track reviews
the benefits of implementing a sound, cost-
effective program.
■ Leadership for Safety Excellence
■ Arc Flash Hazards
■ What Does It Mean for the Line Organiza-
tion to Own Safety?
■ How Is Your Safety Checklist?
■ Employee Wellness—Coping with Aging
Workforce and Off-the-Job Safety
■ Industrial Incident Case Studies
Plant operation optimization and maintenance. These sessions focus on the
safe and efficient operation of power plant
assets in a world of increasingly demanding
environmental regulatory constraints. The ef-
fective maintenance of these assets will min-
imize fuel consumption, improve reliability,
and reduce exposure to unsafe plant condi-
tions, thereby reducing overall emissions and
job-related injuries.
■ Maintenance Strategies
■ Reliability Issues on Aging Electrical
Equipment
■ Asset Optimization/Heat Rate
■ Prevention and Elimination of Critical
Equipment Failures Case Studies
■ Operator Training—Improving Opera-
tions Through Training and Evaluation
■ Predictive Maintenance Case Studies
Power plant components—design and operation. These sessions focus on
the power plant’s capital equipment and
systems for efficient operations, examin-
ing the benefits of implementing the latest
technologies.
■ Operations for Today and Future Power
Plants
■ Cooling Systems
■ Case Studies
■ Technology for Turbines, Generators, and
Auxiliaries
■ Transformers
Heat rate—managing the energy conversion process. These sessions focus
on the efficient operation of power plant as-
sets in an effort to minimize fuel consump-
tion, thereby reducing overall emissions,
improving plant availability, and reducing
fuel cost.
■ Operator Controllable Losses
■ Parasitic Energy Reduction
■ Asset Optimization/Heat Rate
■ Turbine Efficiency
■ Boiler/Combustion
■ Air Heaters to Stack
■ Feedwater Heaters
Environmental TracksTwo full conference tracks are devoted to en-
vironmental topics.
Environmental regulatory issues, strategies, and technologies I and II. Operating companies continue to be
challenged by the need to comply with
more-stringent environmental standards
and uncertainties regarding the potential
for future carbon constraints. Current
environmental decisions have long-term
implications for preserving the value of
generation assets. These sessions will pro-
vide an overview of existing and proposed
environmental legislation and regulations
and will examine compliance options. Pre-
sentations will feature operating experi-
ences at existing installations as well as
new and near-commercial technologies.
■ Fleetwide Considerations for Achieving
Emissions Compliance
■ Hg Technologies I & II
■ Hg CEM and Sorbent Trap Monitoring
Systems
■ NOx Combustion Control Technologies
■ NOx Post-Combustion Control Technologies
■ CO2 Post-Combustion Capture
■ CO2 Sequestration Technologies
■ Particulate and SO3 Control
■ FGD Scrubber Wastewater
■ FGD Operation, Maintenance, Overhaul,
and Upgrades
Closing plenary session. The Confer-
ence will close with a plenary session in
which session chairs will review the confer-
ence and report on highlights of the meeting.
March 2008 | POWER www.powermag.com 71
EVENTS
User Group MeetingsThe ELECTRIC POWER Conference is also the venue for the an-
nual meeting of two influential power industry user groups: the Com-
bined Cycle Users’ Group and the PRB Coal Users’ Group. Delegates
should register for the ELECTRIC POWER Conference and upgrade
for a nominal additional fee to attend the user group sessions. This
upgrade applies to both individual registrants and those participating
in discounted group plans.
Combined Cycle Users’ Group Annual Meeting. Operators of
combined-cycle plants face a complex set of perennial and emerging
challenges that the sessions at this meeting are designed to address.
■ Steam Turbine Maintenance and Overhaul, Reliability and Perfor-
mance Improvements
■ Aftermarket Parts
■ Update on Status of GE R0 Compressor Blade Redesign
■ Workforce Development and Training
■ Issues Surrounding Carbon Management
■ Discussion of Future Developments/Operations of Combined-
Cycle Power Plants
■ Known Issues with HRSG Tubes in Combined-Cycle Duty
(speakers from HRSG vendors, specialty consultants, and owners/
users)
■ Severe Service Control Values—Issues and Solutions (speakers
from valve manufacturers and service organizations)
■ Water Conservation—Issues Relating to Minimizing Consumptive
Water Use (speakers from chemical process suppliers and manufac-
turers of air-cooled condensers, HRSG tubes, and control valves)
■ Issues with HRSG Tubes
■ Severe Service Control Valves (Steam Turbine Bypass) and
Desuperheaters
■ Water Conservation Concerns
PRB Coal Users’ Group Annual Meeting. The PRB Coal Users’
Group was formed in 2000 to meet the needs of generating companies
using, or considering the use of PRB coal. Its objective is to encour-
age the safe, economical use of the resource. The group maintains a
database of plants using PRB coal, and the board has developed a list
of recommended best practices. The highlight of the year is the annual
meeting that traditionally attracts more than 300 delegates. During the
second day of the meeting, the group offers three breakout sessions to
better serve the specific needs of the members: coal-handling, boiler
and combustion and safety, and fire and risk management. The meet-
ing has built a reputation for candid and constructive dialogue. Topics
to be covered include:
■ Chairman’s Opening Remarks
■ PRB Coal Supply
■ Coal Dust Mitigation in Railcars
■ PRBCUG Plant of the Year
■ Operating Without a Crusher
■ Removing Barriers to Reliability
Coal-handling breakout session:■ Methods of Coal Blending and Their Effectiveness
■ Conveyor Belting 101
■ Lifecycle of Coal-Handling Changes
■ Track vs. Wheeled Equipment—Cost Benefit
■ Railcar Maintenance—Southern Company and DTE’s Experience
Boiler/combustion breakout session:■ Mill Performance
■ On-Line Sampling
■ Chemical Injection for Boiler Slagging Prevention
■ Mill Inerting Best Practice
■ Oxistop
■ Successful Robust Optimization Strategies Based on Historical Data
for Existing Coal-Burning Furnace Technologies (Beyond DOE,
CFD, and Statistical Modeling)
Safety, fire, and risk-management breakout session:■ Coal Terminal Conveyor, Transfer Station, and Dust Collector
Fire
■ Stick It: Using a Piercing Rod
■ Safety and Fire Protection at TVA
■ Fire System Upgrades
■ Conveyor Safety (Guarding, Operation, Dust, Noise, Infrastruc-
ture, and Cleaning)
■ How Is Your Safety Checklist?
Thursday, May 8 will offer an open discussion with the PRBCUG
Board of Directors. Surveys from past user group meetings have
shown that representatives from operating companies want a chance
for candid discussions among themselves on issues raised during the
first two days of the conference or on topics that have been a constant
concern. This forum meets that request. This interactive forum is re-
served for gencos and plant operations staff only.
For more informationFull conference program details are available at www
.electricpowerexpo.com. Discounted group registration plans are avail-
able to companies sending multiple delegates to the conference. ■
Oh yeah? Yeah.Custom built to your tough
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reliably to whatever yourprocess dishes out.
C’mon . . .pour on the
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913-888-2630 www.sorinc.com
CIRCLE 33 ON READER SERVICE CARD
www.powermag.com POWER | March 200872
NEW PRODUCTS TO POWER YOUR BUSINESS
Upgrade your consoles Rittal Corp.’s TopConsole System is the latest addition to its line of human-machine interface (HMI) products. This system is ideal for a wide range of industrial workstation applications and provides NEMA 12 protection against dirt, dust, and splashes from noncorrosive liquids.
The TopConsole System features a modular design that delivers unparalleled flexibility, aesthetics, and functionality. The system is composed of three parts: a pedestal, desk unit, and console. These individual components can be combined to match specific customer requirements.
Significantly slimmer than many other HMI solutions, the TopConsole System is uniquely constructed to provide greater usable mounting space in an ergonomically designed platform. (www.rittal-corp.com)
See below the surface Ridgid’s new SeekTech SR-60 utility locator identifies underground obstacles and infrastructure. The company says the SR-60 is the only utility locator that can receive the full range of locatable frequencies, allowing it to be used with any preset frequency transmitter.
With the SR-60 users can locate items within a broad frequency range of 10 Hz to 490 kHz and can tune the frequency 1 Hz at a time. The unique passive search mode can be used to search all broadband passive frequencies at once, allowing for easy identification of unknown metallic lines in the target area. These features provide the necessary data for a professional locator to develop a comprehensive and accurate understanding of the underground infrastructure.
The SR-60’s innovative, easy-to-read display visually maps the signal, so users can view changes in the line direction, depth, and signal strength in real time. With the added feature that allows users to program up to 30 field-configurable, user-designated frequencies, users have maximum versatility. (www.ridgid.com)
Find dust filter leaks Auburn’s latest 24V bag leak detector is specifically designed for high-temperature
dust-monitoring applications. The new Tribo.d2 (Model 3400) is a two-wire, loop-powered emissions monitor for high- or low-temperature applications. It’s designed to detect and locate impending filter malfunctions in dust collectors large and small. These industrially hardened monitors process minute electrical currents generated when particles impact, or pass nearby, strategically located sensors within fabric and cartridge dust control collectors.
The new design makes possible the placement of triboelectric sensors in locations with temperatures as high as 1,000F, coupled with electronics circuitry
safely located remotely in less-harsh surroundings. Triboelectric monitors require no difficult-to-maintain lenses and track increased emissions activity
before catastrophic failure to facilitate orderly and efficient collector maintenance scheduling. Tribo.d2 requires no delicate sensitivity adjustments during significant mass flow
variation and displays no zero drift, therefore, no zero-drift or system drift checks are required. (www.auburnsys.com)
March 2008 | POWER www.powermag.com 73
NEW PRODUCTS
Inclusion in New Products does not imply endorsement by POWER magazine.
Corrosion-proof basket strainer A new series of plastic strainers has been introduced by Micromold that has a higher capacity than Y-strainers yet captures substantial undissolved solids. Basket strainers remove suspended or waste solids from corrosive or high-purity fluid streams to prevent damage to sensitive downstream equipment such as pumps, valves, instruments, and spray nozzles.
The strainers are made of Kynar PVDF (polyvinylidene fluoride) and are highly corrosion-resistant while allowing higher operating temperatures (up to 300F), yet they cost less than lined steel or exotic metal units. Earlier designs were not able to handle corrosive materials such as halogens and many acids, or temperatures exceeding 220F. PVDF far outperforms PVC, CPVC, polypropylene, and acetal materials used in ordinary plastic strainers. The PVDF strainers are also impervious to UV radiation and have high rigidity and resistance to creep under mechanical loads.
The Micromold design offers the advantage of a compact envelope together with a high-capacity, slant-head PTFE cartridge for lower pressure drop and long cartridge life. An easily removable screw top and drain plug, along with other elements of Micromold’s elegant and robust construction, allow easy cartridge removal and quick clean-out. Encapsulated O-ring seats prevent blow-by and external leakage in this all-fluoropolymer wetted-surface construction. (www.micromold.com )
Clean parts ultrasonicallyTovatech LLC recently announced its new line of ultrasonic cleaners, available in sizes up to 47.6 gallons in capacity. In Normal mode, the Elmasonic ultrasonic cleaners produce a stabilized frequency field, forcing the liquid to circulate and mix. Mixing, dispersing, emulsifying, and dissolving samples is most efficiently accomplished in this mode. In Sweep mode, frequencies are shifted continuously to ensure that cavitation occurs uniformly throughout the tank. Glass, metal, and plastic surfaces are most thoroughly cleaned in Sweep mode. Dissolved gas in the cleaning liquid can suppress cavitation; degasing is used to remove entrained air, thereby ensuring the most efficient cleaning.
Expanded utility is provided by having dual frequencies (25/45 kHz or 35/130 kHz) in a single unit. The lowest frequency is used for coarse particle removal; 35 and 45 kHz are used to clean grease and oils from hard surfaces; and 130 kHz is used for gentle cleaning of sensitive surfaces such as electronic parts. All units are fully power adjustable. (www.tovatech.com)
Polish your pipes The LRP 1503 Air Boa Pipe Sander from CS Unitec is an all-around polishing solution for hand rails, pipe, and tubing. It has a 1-hp motor with 20-cfm air consumption at 90 psi. The sanding arm snakes up to 270 degrees around the radius of the pipe. The operator simply rotates the Boa slightly to achieve a full 360-degree finish. This high-quality sanding arm is made of light alloy with two deflection rollers for quick progress, perfect finish, and simple operation. An additional side handle can be rotated 180 degrees in narrow spaces, such as around handrails that are fixed close to walls.
Replacement of the sanding belt is quick and easy. No tools are necessary. Spring resistance between the deflection rollers ensures that the sanding arm and belt are always uniformly tensioned. The Boa saves time finishing stainless steel and other ferrous and nonferrous pipe. It is also ideal for cleaning the pipe surface in preparation for welding.
The Boa is also available as an electric model with an 11-amp motor and variable-speed control of 12 to 40 fps. Additional belts are available in two sizes: 1½ inches wide for sanding straight sections or a narrow ¾-inch belt to reach in elbows and corners. Sanding belts come in grits of 80 to 220. Nonwoven nylon sanding fleece is available for polishing. (www.csunitec.com)
www.powermag.com POWER | March 200874
Management • Technical • ContractNuclear • Fossil • Renewable • T&D
SanfordRoseAssociates265MainSt.AkronOH.44308
888-333-3828 • Fax [email protected]
Best Recruiters in Power!
Opportunities in Operations and Maintenance,
Project Engineering and Project Management,Business and Project Development,
First-line Supervision to Executive Level Positions.Employer pays fee. Send resumes to:
POWER PROFESSIONALS
P.O. Box 87875Vancouver, WA 98687-7875
email: [email protected]
(360) 260-0979 l (360) 253-5292www.powerindustrycareers.com
Proposal ManagersThe Babcock & Wilcox Company (B&W), an international leader insteam generation and pollution control, continues to set the standardin customer satisfaction and quality. We currently have challengingopportunities for experienced Proposal Managers to lead crossfunctional teams and manage major proposals for OEM utility andindustrial boiler and environmental projects and support Sales andBusiness Development to position B&W for future opportunities.
Typical responsibilities would include:• Lead proposal teams and coordinate different functions to ensure
responsive bids.• Develop bidding strategies and partnering arrangements with Sales
and BD.• Coordinate review of specifications, development of DOW,
estimates, execution plans and customer submittals.• Conduct cost reviews, strategy meetings and management reviews.• Develop and present documentation for management approvals for
pricing, commercial and technical positions.• Manage post bid follow-up, lead clarification meetings, technical
and commercial negotiations.• Ensure smooth transition to project team.
Bachelor’s degree in Engineering or Business Management, alongwith strong commercial and technical background, organization andcommunication skills required.
Please go to our website, www.babcock.com, select Current Openings(job code 461). Submit resume via our confidential online process.Named one of the best places to work in Northeast Ohio by theEmployers Resource Council, B&W offers a competitive salary andbenefits package. An equal opportunity employer M/F/D/V.
I/O: CL22490Client: Babcock&WilcoxMedia: Power MagazineColor: b/wSize: 3.375 x 4.875Date: 02.04.08Artist: jimV: 10
PROOFINGPA:AC, Initial:AC, Final:
JWT EC - St. Louis
POWER MAGAZINE3/1/20083033803-WA97975WORBAN3.375” x 4.875”Carly Hirsch v.4
Senior Power EngineersWashington, DC
The electricity sector assistance program of the Energy Unit of the World Bank’sSustainable Development (SD) Department includes investment projects andadvisory services supporting the development of national and regional electricitymarkets in Southeastern and Central Europe, Turkey and the Former SovietUnion. The Unit is seeking two Senior Power Engineers to join the team to bebased in Washington, D.C., one with a focus on the planning, preparation andimplementation of investments and advisory work in transmission anddistribution of electricity, and the other with a focus on power generation. Bothpositions are a 3 year term.
Duties and Accountabilities:• Project management by leading or participating in multi-disciplinary task
teams, including preparation, appraisal and supervision, technical analysis,negotiations, implementation review and implementation completion reports.
• Lead and/or participate in dialogue and engagement with client governments,utilities and stakeholders on sector reforms, supply investments and energyefficiency, including through private sector participation.
Selection Criteria:• Bachelor’s degree in Engineering with power systems /electrical engineering
specialization subjects along with a Master’s degree in Engineering or anotherdiscipline like Business Administration, Finance, Economics, or Accounting.
• 8 or more years of relevant experience with a power utility, a design institute,or an engineering consulting firm.
The World Bank Group is committed to achieving diversity in terms of gender,nationality, culture and educational background. Individuals with disabilities areequally encouraged to apply. Qualified candidates may apply on-line athttp://www.worldbank.org/jobs and choose vacancy # 080268. Please notethat you will need to register before submitting your application. The closingdate is March 31, 2008.
Tagline: 82645-020608
Pub: Power
Size: 2.3125 x 3
NOTE: Please review this ad verycarefully, as well as verify thepublication, section and date this adis to run. Once you have approvedthis information, Harger Howe is notresponsible for any errors.
2008 HARGER HOWE& ASSOCIATES, LTD.
Artwork, designs, copywriting,production and creative
materials created by HargerHowe & Associates are theproperty of Harger Howe &
Associates and are not to beused, displayed, reproduced,
recreated or republishedwithout our expressed writtenconsent. We retain all rightsunder applicable copyright
laws to all materials.
PROOF
EMPOWERING CAREERS
PLANT ENGINEERING MANAGERS
ILLINOIS
Havana and Wood River sites
Apply online at:
www.dynegy.com
Dynegy is an Equal Opportunity Employer.
Ray Dauria AssociatesSpecializing in recruiting forpower sector positions with a focus on Electric Generation and Transmission
POWER PLANT POSITIONS
Progress Energy Florida has expanded its generation and is currently seeking high-ly qualified Combined Cycle Combustion Turbine Technicians to operate and maintain state of the art Combined Cycle units at Hines Energy Complex located near Bartow, Florida. For more information or to apply visit our website at:http://www.progress-energy.com/aboutus/
employment/postings/jobs.cfm keyword Bartow
0308 Power Classified.indd 74 2/22/08 4:20:03 PM
August 2007 | POWER www.powermag.com 75March 2008 | POWER www.powermag.com 75
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 206
READER SERVICE NUMBER 207
Power Plant Buyers’ Mart
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 Locations
800-866-6247 • www.naisinc.come-mail: [email protected]
READER SERVICE NUMBER 204
READER SERVICE NUMBER 205
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 201
Combustion, Energy and
Steam Specialists Ltd.
Surplus Power Plant
Specialists in the Valuation, Marketing, Sourcing, and
Relocation of Surplus Power Plant & Auxiliary Equipment
Tel: +44 (0)1856 851177 Fax: +44 (0)1856 851199 E.mail: [email protected] Web: www.cess.co.uk
READER SERVICE NUMBER 202
READER SERVICE NUMBER 203
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
PoWErEQUIPmENt Co.
444 carpenter avenue, Wheeling, il 60090
wabash
24 / 7 eMerGeNcY SerViceBOilerS
20,000 - 400,000 #/Hr.
DieSel & TUrBiNe GeNeraTOrS50 - 25,000 KW
GearS & TUrBiNeS25 - 4000 HP
WE StoCk LarGE INVENtorIES oF:Air Pre-Heaters • Economizers • Deaerators
Pumps • Motors • Fuel Oil Heating & Pump SetsValves • Tubes • Controls • CompressorsPulverizers • Rental Boilers & Generators
847-541-5600 FaX: 847-541-1279WeB SiTe: www.wabashpower.com
FOr Sale/reNT
READER SERVICE NUMBER 200
0308 Power Classified.indd 75 2/22/08 4:20:35 PM
www.powermag.com POWER | March 200876
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 210
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 209
POWER magazine has served the generation industry for more than 125 years. Now POWER is making it easier than ever for industry professionals to find career opportunities and for hiring authorities to find the best candidates for open positions. The Careers-in-POWER job board on powermag.com allows visitors to post resumes anonymously, view the latest job positions, post job listings, and set up personal job alerts.
JOB SEEKERS:Access the most recent positions available to engineers, operations and maintenance managers, and corporate and general managers at coal, nuclear, combined-cycle, and renewable power plants.
EMPLOYERS/RECRUITERS:Attract highly qualified candidates by posting open positions on the Careers-in-POWER job center.
Visit Careers-in-POWER on powermag.com to become part of the fastest growing site dedicated to connecting power generation employers and employees.
Where Does the Industry Find Its Best People?
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 208
READER SERVICE NUMBER 211
0308 Power Classified.indd 76 2/22/08 4:21:03 PM
August 2007 | POWER www.powermag.com 77March 2008 | POWER www.powermag.com 77
POWERClassifieds Ads Get More
Attention When You Add Color!
To inquire about Classified Advertising,
please contact:
Myla DixonPhone: 832-242-1969 Ext. 311
Fax: [email protected]
READER SERVICE NUMBER 214READER SERVICE NUMBER 212
READER SERVICE NUMBER 213
READER SERVICE NUMBER 215
• <6ppm NOx– With CRI Catalyst/Shell DeNOx
components
• Field Installation– On package boilers to 250,000 lb/hr
• Simple Operation– No special facilities, permits, controls
or modifications required
• Low Pressure Drop– 2" WC means no fan changes
Call 1-800-227-19661-510-490-7100
Or Visit: www.nationwideboiler.com
CataStak™
Brings Ultra Low NOx to package boilers
RentalsLeasesSales
San Francisco • Baton Rouge • Birmingham • Calgary • Charlotte • Chicago • ClevelandHamilton, Ont • Houston • Philadelphia • Seattle
Catastak.qxd:NYC1/3_605.qxd 9/5/07 9:29 AM Page 1
0308 Power Classified.indd 77 2/22/08 5:21:24 PM
www.powermag.com POWER | March 200878
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
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Tel: 281.240.0440 Fax: 281.240.2440www.questtecsolutions.com
Magne-Trac
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READER SERVICE NUMBER 216 READER SERVICE NUMBER 218
PRODUCT Showcase
READER SERVICE NUMBER 217
Visit www.powermag.com toexplore a great way to search for numerous companies, products, and services online.
● Information on hundreds of companies● Easy to navigate and use● Printed in the December issue of POWER magazine● Best of all, it’s FREE
LOOKING FOR PRODUCTS AND SERVICES?
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by visiting www.powermag.com and clicking on the Buyers’ Guide link.
0308 Power Classified.indd 78 2/22/08 4:22:58 PM
ADVERTISERS’ INDEXEnter reader service numbers on the FREE Product Information Source card in this issue.
Page
ReaderServiceNumber
CLASSIFIED ADVERTISINGPages 74–78. To place a classified ad, contact:
Myla Dixon, POWER magazine, 832-242-1969, [email protected].
March 2008 | POWER www.powermag.com 79
ABB . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cvr 2 . . . . . 1 www.abb.com
Ansaldo Energia . . . . . . . . . . . . . . . . . . . . . . . 51 . . . . 27 www.ansaldoenergia.com
Ansul Incorporated. . . . . . . . . . . . . . . . . . . . . 43 . . . . 23 www.ansulinfo.com/p3
Ashross. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 . . . . 15 www.ashross.com
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Bechtel Advertising . . . . . . . . . . . . . . . . . . . . 27 www.bechtel.com
Braden Manufacturing, LLC . . . . . . . . . . . . . 15 . . . . 10 www.braden.com
C-B Energy Recovery/Cleaver-Brooks, Inc. . . Cvr 3 . . . . . .31 www.hrsg.com
Cablesafe Hooks. . . . . . . . . . . . . . . . . . . . . . . 55 . . . . 30 www.cablesafe.com
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Columbus McKinnon . . . . . . . . . . . . . . . . . . . 54 . . . . 29 www.cmindustrial.com
E.H. Wachs. . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 . . . . . 8 www.wachsco.com
Emerson/Rosemount . . . . . . . . . . . . . . . . . . . 49 . . . . 26 www.raihome.com
General Electric . . . . . . . . . . . . . . . . . . . . . . . . 7 . . . . . 6 www.ge.com/energy
Graycor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 . . . . 14 www.graycor.com
Hach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 . . . . . 5 www.hach.com/power
Hitachi Power Systems. . . . . . . . . . . . . . . . . 61 . . . . . 2 www.hitachi.com
Houston Dynamic Services Inc.. . . . . . . . . . 53 . . . . 28 www.houstondynamic.com
HPD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 . . . . 11 www.hpdsystems.com
Hypercat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 . . . . 25 www.hypercat-acp.com
Magnetrol. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 . . . . 22 www.magnetrol.com
Plymouth Tube. . . . . . . . . . . . . . . . . . . . . . . . . 29 . . . . 16 www.plymouth.com
Power Systems Mfg, LLC. . . . . . . . . . . . . . . . 19 . . . . 12 www.powermfg.com
Rockwood Material . . . . . . . . . . . . . . . . . . . . . 9 . . . . . 7 www.rockwood.net
Schmidt Industries . . . . . . . . . . . . . . . . . . . . . 32 . . . . 18 E-mail: [email protected]
Siemens Power. . . . . . . . . . . . . . . . . . . . . . . 2, 3 . . . . . 4 www.siemens.com/us-sppa
SOR Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 . . . . 33 www.sorinc.com
STF Spa. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 . . . . . 9 www.stf.it
TDC Filter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 . . . . 17 www.gtairfilters.com
Turbine Energy Solutions . . . . . . . . . . . . . . . 39 . . . . 21 E-mail: [email protected]
Turbocare Inc. . . . . . . . . . . . . . . . . . . . . . . . . . 45 . . . . 24 www.turbocare.com
United Brotherhood of Carpenters . . . . . . . 57 . . . . 32 www.carpenters.org
Victaulic Company . . . . . . . . . . . . . . . . . . . . . 37 . . . . 20 www.victaulic.com
Wood Group Management Ltd. . . . . . . . . . . 35 . . . . 19 www.woodgroup.com/gts
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www.powermag.com POWER | March 200880
COMMENTARY
It is fashionable these days for policymakers, particularly those running for office, to somberly suggest that America needs an energy policy—thus implying that America has no energy
policy.As one of the prime architects of an energy policy that has
served America well, I could not disagree more. The fact that our collective memory seems on the verge of lapse suggests that we may be about to relearn the painful lessons of the past.
Controls created chaosThirty years ago this winter, an antiquated system of price con-trols on natural gas combined with an extended period of cold weather to prompt the first and only widespread curtailments of natural gas in our history. We watched in disbelief as factories and schools were forced to close because we had no ability to keep them warm.
These price controls, which had no basis in statutory law, but rather had been devised and extended by federal regulators, arti-ficially restricted the price of natural gas in certain markets. Not surprisingly, natural gas found its way to markets where its price
was not restricted. Not until Congress intervened and removed the artificial constraints were we able to restore heat to much of America’s heartland.
The following year the Islamic Republic of Iran imposed an oil embargo, and the mightiest nation on earth saw its citizens waiting in long lines for gasoline. The shortfalls from the em-bargo were exacerbated by a federally imposed regime of price and allocation controls. Those controls, which actually dictated the amount of oil and gasoline available to various regions of the country, created absurd situations. For example, drilling rigs in my home state of Louisiana were unable to continue operations because they lacked a federal allocation of diesel fuel.
Resist temptation to controlIn the generation since those dark days, we have had a sound, well-defined energy policy—one that has largely removed the federal government from the business of regulating the price, the transportation, or the allocation of our various energy com-modities. We have allowed markets to operate, made those mar-kets transparent, and allowed price signals to flourish. The new assumption has been that the various participants in those markets can better allocate capital, better assess and manage risk, and better supply the energy we need if government gets out of the way. For nearly 30 years, consumers have enjoyed a period of relatively cheap, relatively abundant energy.
But as the words and deeds of so many would indicate, memories are short. Recent events suggest that we may have overlearned the lessons of Enron and may be overreacting to perfectly rational price increases associated with a tightening global market for energy.
Two situations suggest that history’s lessons may be fading. One is Congress’s attempt to criminalize the charging of “uncon-scionably excessive” prices for gasoline. Another is the Federal Energy Regulatory Commission’s complicated effort to punish the failure to charge a properly “implied price” for natural gas based on a reference to derivatives markets. The first scenario is an am-bitious attorney general’s dream; the second is an energy trader’s nightmare. Both introduce new elements of post-facto regulatory risk to markets and can only inhibit the efficient function of markets and efforts to mitigate risk.
More fundamentally, these actions reflect a growing attitude that a fair and workable energy policy can only derive from the active involvement of government—a government that presum-ably knows better than the market and its sophisticated par-ticipants what prices “should” be. With all due respect, I would suggest that such notions are naive and destructive.
The record is replete with well-intended governmental efforts to control the prices paid for energy. The most common thread in these efforts is the degree to which they have distorted markets, created artificial dislocations, and ultimately failed to achieve their goal. If we have learned anything in the past 30 years, it is that regardless of government regulation, energy resources will ultimately find their way to markets where their true value is reflected and rewarded. In a global economy, those markets could well be in other countries.
We stand at the forefront of two of the most daunting issues we have faced as a nation: how to ensure our long-term energy security while rationally addressing the causes and effects of cli-mate change. If we are to confront those issues in a meaningful fashion, I suggest that more than our technology must change; our attitudes must change as well.
Meeting these challenges will require fundamental changes in human behavior. The notion of changing behavior while si-multaneously insulating consumers from the economic conse-quences of their actions is, at best, dubious. The idea that we can attract hundreds of billions of dollars in capital invest-ment for much-needed energy and environmental infrastructure while threatening the private sector’s ability to recover those funds or manage the risks associated with their investment defies reality.
We cannot hope to meet our future energy and environmental needs without harnessing the power of markets. We cannot hope to harness that power if we forget the lessons of the past. ■
—J. Bennett Johnston is the principal and founder of Johnston & Associates and former chairman of the Senate Energy and Natural Resources Committee.
Markets, not government, must set energy pricesBy J. Bennett Johnston
The record is replete with well-intended governmental efforts to control the prices paid for energy.
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