Powermag200711 Dl

BUSINESS AND TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRYVol. 151 • No. 11 • November 2007www.powermag.com

Top Plants: Four remodeled nuclear plants

Upgrade BWR recirc pumps with adjustable-speed drivesDigital plant data networksSuccessful nuclear I&C upgrade projects

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November 2007 | POWER www.powermag.com 1

www.powermag.com Established 1882 • Vol. 151 • No. 11 November 2007

On the coverOmaha Public Power District replaced Fort Calhoun Nuclear Generating Station’s two steam generators, reactor vessel head, and coolant system pressurizer in perhaps the most complex plant upgrade project in the history of the industry.

DEPARTMENTS 4 SPEAKING OF POWER

6 GLOBAL MONITOR 6 NRG applies for first COL 8 TVA green-lights Watts Bar 2 8 Southern Co. and Florida muni

launch IGCC project 10 UK approves wave energy “hub” 12 New Jersey–New York HV system

launched 12 Membrane strips CO2 from methane

faster 14 POWER digest

18 FOCUS ON O&M 18 The NERC auditors are coming 18 Winning encore for on-line

pH monitoring 24 Using balloons as temporary

barriers 25 How data logging can cut

power bills

28 LEGAL & REGULATORY

84 RETROSPECTIVE

86 NEW PRODUCTS

96 COMMENTARY

COVER STORY: NUCLEAR TOP PLANTS 30 Browns Ferry Nuclear Power Plant, Alabama

It’s probably the most written-about nuke in history, but that’s because its story is in many ways the story of U.S. nuclear power generation. After a massive upgrade and restart, Browns Ferry begins yet another chapter.

36 Comanche Peak Steam Electric Station, TexasThis modernization project shattered the record for fastest replacement of aging components at a nuclear power plant. Doing so required creative methods to recruit and retain the required craftsmen.

40 Fermi 2 Power Plant, MichiganSome outside-the-concrete-box thinking led to a unique and previously untested one-piece installation approach to replacing a pair of moisture separator reheaters that accomplished this first-ever task under time and with impressive financial results.

46 Fort Calhoun Nuclear Generating Station, NebraskaIf nuclear renovation were an Olympic event, this plant would win for undertaking the routine with the highest degree of difficulty.

INDUSTRY TRENDS52 Map of U.S. nuclear power plants

SPECIAL REPORTS PLANT INFRASTRUCTURE54 Plantwide data networks leverage digital technology to the max

It’s high time for the power generation industry to recognize that digital control and communications systems deserve to be linked by a plantwide data network.

NUCLEAR UPGRADES60 Upgrade your BWR recirc pumps with adjustable-speed drives

Exelon Nuclear details the operational and design considerations that led to choos-ing the appropriate ASD for upgrading the recirculation pump drive system at its fleet of boiling water reactors.

68 Defined scope, experienced team essential to nuclear I&C upgrade projectsAn instrumentation and controls contractor offers case studies in rebuttal of our January story on the trials and shortcomings of I&C upgrade projects. As usual, the lesson is that “proper planning prevents poor performance.”

FEATURES INSTRUMENTATION72 Accurately measure the dynamic response of pressure instruments

Measuring the dynamic response of nuclear power plant pressure sensors and their associated sensing lines has been a challenge, but the noise analysis technique has proven to be simple and effective. Tests using the technique can even be run without interrupting the demand for high nuclear plant capacity factors.

PROJECT MANAGEMENT80 Milestones on the road to commercial operation

A carefully negotiated EPC contract balances risks for the contractor and the plant owner. Understand the elements of a good contract and its milestones to avoid dis-putes and their resolution.

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www.powermag.com POWER | November 20072

Now incorporating and

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SPEAKING OF POWER

Do the math

The eyes of Texas—and the rest of the world—are upon NRG Energy after its September application for licenses for two new reactors at South Texas Project (see p. 6). The filing

was the first of its kind in nearly three decades and the first of up to 30 like it expected over the next few years. However, most industry observers—including yours truly—expected a nuclear utility to be first out of the gate, not a company that emerged from bankruptcy less than four years ago.

How will NRG stand up under the heightened scrutiny? It de-pends on how well it solves a certain equation.

Perception is realityPeter Sandman (www.psandman.com) was a professor of jour-nalism specializing in media coverage of environmental issues in March 1979, when Three Mile Island Unit 2 suffered a par-tial meltdown, ending orders for new reactors in the U.S. The Columbia Journalism Review asked him to go to the site and “cover the coverage” of the TMI disaster. Years later, Sand-man wrote a series of articles based on his findings there and elsewhere, recommending ways for nuclear utilities to improve their public communications during crises. It’s my observation that his advice applies equally well to utilities looking to in-vest billions in advanced nuclear units.

In the late 1980s, Sandman coined the formula Risk = Hazard + Outrage in an effort to quantify the public fear caused by a nuclear power mishap. For example, although there was no chance that the molten core of TMI Unit 2 would breach the containment below and create a real public hazard, the public’s outrage—fanned by poor communications and exacerbated by release of the movie The China Syndrome just 12 days earlier—heightened the perceived risk of such an event. Conversely, the full meltdown of Chernobyl Unit 4 in Ukraine seven years later was extremely hazardous, yet the outrage it generated in the U.S. paled in comparison.

Sandman’s formula can be likened to the International Nuclear Event Scale developed by the International Atomic Energy Agency in 1990 to standardize reporting of nuclear events to the public. The scale runs from zero (an event with no safety significance) to a Chernobyl-like seven. On this scale, TMI was a five. A 1980 level-four accident in France passed without notice in the U.S., while the corrosion discovered at the Davis-Besse nuclear station in 2002 rated a three—though its outrage factor was much higher.

Equation proofsSandman’s equation makes clear that risk can be minimized only when hazard and outrage are both at a minimum. Utilities consid-ering adding new nuclear resources would be wise to heed a few of the PR pointers Sandman developed in the wake of TMI. They’re still fresh, and applicable to any company with a public image.

Pay attention to communication. Few citizens understand nu-clear power technology. Yet the general public’s voice of dissent (informed or not) can bring a project to a jarring halt. Free and

open communication channels are vital to discussions of a new nuclear plant. The public must feel it is part of the conversation, and nay-sayers cannot be ignored.

Metropolitan Edison’s bungling of press relations during the TMI accident only increased the outrage factor. Then-Pennsylvania Governor Dick Thornburgh ordered an evacuation of school children near the plant even though MetEd maintained that radiation levels did not justify it. MetEd was right, but for the wrong reason.

Err on the side of pessimism. After MetEd’s initial public pro-nouncement minimized the importance of the event, the compa-ny’s PR people later had to admit that, “it is worse than we first thought.” It would have been better had they been able to say, “it is better than we first thought.”

For today’s utilities, the lesson here is that rosy predictions of the cost, schedule, and community impact of a proposed plant can come back to haunt you. Experienced nuclear utilities with a track record of safe and efficient operations begin the permitting process with lots of public credibility. Miss that first milestone or raise the cost estimate before breaking ground, and you squan-der much or all of that cred.

Don’t lie, and don’t tell half-truths. Making statements that are technically accurate but designed to mislead is still lying. At the height of the TMI crisis, MetEd issued a press release that said the plant was “cooling according to design.” Translation: The safety margins and plant automation are working correctly, even though the plant is self-destructing.

Another case in point: This July, Tokyo Electric Power Co. found several drums of very low-level radioactive waste spilled on the basement floor of its huge Kashiwazaki-Kariwa plant fol-lowing a powerful earthquake. Reporters flogged that non-story for weeks, but who can blame them? They remembered that in 1999 the utility admitted that it had falsified safety records for years and had covered up an incident in which operators lost control of a reactor.

New mathHow does NRG rate so far on Sandman’s criteria? Picking the operator of South Texas Project as its partner was a plus, and se-lecting the already-approved advanced boiling water reactor de-sign was inspired. David Crane, NRG’s CEO, says his firm arranged for Toshiba to build the new reactors because “the Japanese have built four of [them] already, on time and on budget.” NRG also has mitigated cost and completion risk by making Hitachi and Toshiba equity participants in the project. Doing so may al-low NRG to tap Japanese government guarantees as well as those offered by the U.S. Department of Energy.

NRG’s chutzpah, backed by the nuclear expertise of Japan Inc., might be just what’s needed to kick off America’s second act on the world’s nuclear power stage. Just don’t forget your math lessons in the days ahead.

—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

NRG applies for first COLThis September, NRG Energy Inc. and South Texas Project Nuclear Operating Co. filed the first-ever combined construction and operating license (COL) application with the U.S. Nuclear Regulatory Com-mission (NRC). The two firms would like to build two new 1,350-MW nuclear units on the grounds of the South Texas Project (STP) nuclear power station (Figure 1) and bring them on-line in 2014 and 2015.

The submittal was the first application for a license for a new U.S. nuclear unit in 29 years.

This July, Constellation Energy Group and UniStar Nuclear—a consortium of Constellation, the French reactor vendor Areva, and the French utility Électricité de France—filed a partial COL application for a potential third reactor at Constellation’s two-unit Calvert Cliffs nuclear station on Chesapeake Bay. But the submission cov-

ered environmental issues only. Under NRC rules, the consortium must file the rest of the application for Calvert Cliffs within six months. Since July, Constellation/Unistar has supplemented the original application twice, but has not yet completed it.

The new units in Texas—to be called STP 3 and 4—are being developed as part of an NRG repowering initiative to add about 10,000 MW of clean and efficient capacity to its 23,000-MW North American portfolio. The initiative’s goals are to bet-ter leverage NRG’s existing infrastructure, to diversify its fuel mix while reducing its dependence on foreign sources, and to implement technologies that reduce the company’s carbon footprint.

STP Nuclear Operating Co., which op-erates Units 1 and 2, would operate STP 3 and STP 4 as well. Units 1 and 2 are owned by NRG Energy (44%), CPS Energy (40%), and Austin Energy (16%).

The 12,220-acre STP site in Matagorda County, Texas, is considered one of the best sites in America for nuclear expan-sion. Its 7,000-acre cooling reservoir was sized to serve four units. The two new units would be built adjacent to Units 1 and 2 (Figure 2).

NRG has chosen advanced boiling wa-ter reactor (ABWR) technology developed by General Electric Co. for the new units because it combines the best features of current BWR designs with enhancements that improve safety, performance, and longevity. ABWR technology is certified by the NRC and has impressive construc-tion and operational track records, includ-ing the shortest time to build a reactor and the completion of many units within their budget.

Four ABWR units are already on-line in Japan, and another three are under construction in Taiwan and Japan. Tokyo Electric Power Co., which has more than a decade of experience using the technol-ogy, said it will share its expertise to sup-port STP’s planned expansion.

POWER Contributing Editor Tim Hurst explored the ABWR fast-track construc-tion methods employed by Hitachi in this magazine’s May 2007 issue. In “Transfer ABWR construction techniques to U.S. shores,” Hurst wrote that the “construc-tion practices honed in Japan aren’t just impressive; they’re also eminently suit-able for the fleet of new units planned for the U.S.”

Because ABWR technology and con-

1. Room to grow. An aerial view of the sprawling South Texas Project nuclear plant site. Courtesy: South Texas Project

2. Bigger and still CO2-free. What the site would look like after the addition of Units 3 and 4, in the foreground. Courtesy: South Texas Project

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POWER | November 20078

GLOBAL MONITOR

struction techniques are well-understood, NRG’s choice seems an excellent one for the first nuclear unit to be built in the U.S. in a generation. “We have chosen NRC-certified, operationally proven tech-nology and the best possible, most expe-rienced team to build STP 3 and 4,” said David Crane, NRG’s president and CEO. “We expect to build these facilities on time, on budget, and to the exacting standards that will guarantee excellence in safe and reliable nuclear operations.”

It took NRG a little over one year to follow up its letter of intent to build STP 3 and STP 4 with the COL application. STP Nuclear Operating Co. and a contracting team led by a joint venture of Hitachi and GE, and including Bechtel Power Corp., helped prepare the latest submittal.

The filing of the COL application kicked off an NRC internal process for formally accepting it that will likely take two months. After that, another agency pro-cess of detailed review will begin and last up to 42 months. It will include staff discovery, site visits, company responses, public hearings, and the filing of environ-mental impact statements.

If all goes well, NRG could receive li-censes for STP 3 and 4 and begin con-struction in 2010. If not, the company could qualify for $1 billion ($500 million per reactor) in “standby support,” or in-surance against regulatory delays, includ-ed in the Energy Policy Act of 2005.

TVA green-lights Watts Bar 2Bechtel Power Corp. has announced that it has been chosen by Tennessee Valley Authority (TVA) to lead the effort to com-plete Unit 2 at the Watts Bar Nuclear Plant (Figure 3) in Spring City, Tenn. Work on the original 1,200-MW unit was stopped in 1985 when it was two-thirds complete. The new, $2.5 billion project will take

five years to finish and bring Unit 2 up to all contemporary engineering and safety standards.

TVA, the nation’s largest public power provider, selected Bechtel after a com-prehensive competitive bidding process. Bechtel recently contributed engineer-ing, start-up, and other technical servic-es to the successful May 2007 restart of TVA’s Browns Ferry Unit 1 (see p. 30), the first nuclear unit to come on-line in the U.S. in more than a decade (since Watts Bar Unit 1 in 1996). The contractor also worked for TVA on the restart of Browns Ferry Units 2 and 3 in the 1990s, and re-placed the steam generators of Watts Bar 1 and of TVA’s Sequoyah Nuclear Plant, Unit 1.

“We are honored to be selected by TVA for this historic assignment,” said Jim Reinsch, president of Bechtel’s nuclear power business. “This cost-effective project will provide clean, safe, and reli-able power for TVA’s customers and dem-onstrate the importance of nuclear power as a contributor to meeting America’s en-ergy needs in the coming decades.”

Southern Co. and Florida muni launch IGCC projectWith some hefty financial assistance from the U.S. Department of Energy (DOE), Southern Company and the Orlando (Flor-ida) Utilities Commission have become the first U.S. utilities to begin building a power plant based on an advanced inte-grated gasification combined-cycle (IGCC) technology.

The DOE is subsidizing the project, in Orlando, under its Clean Coal Power

Initiative to demonstrate new clean coal combustion technologies such as IGCC. Energy Secretary Samuel Bodman joined David Ratcliffe—Southern’s chairman, president, and CEO—and Orlando offi-cials at the groundbreaking of the 285-MW coal gasification plant, to be built on the grounds of the Orlando Utilities Commission’s Stanton Energy Center (Figure 4).

The plant will be powered by Transport Integrated Gasification (TRIG) technology developed by Southern at its Power Sys-tems Development Facility in Wilsonville, Ala., in partnership with the DOE and the engineering contractor KBR Inc. According to Southern, TRIG is a superior, proven, and practical method of gasifying coal to produce power, chemicals, and transporta-tion fuels with less environmental impact than conventional IGCC technologies. The company says it can easily handle the high-moisture, high-ash coals that ac-count for more than half of the world’s reserves of the fuel.

The Orlando plant also is expected to produce 20% to 25% less CO2 than a typi-cal coal-fired power plant. However, cur-rent plans for the project do not call for capturing any carbon released by its coal combustion.

The gasification project is valued at $844 million, including the costs of per-mitting, design, construction, and start-up, and four and a half years of O&M and evaluation expenses. The DOE will con-tribute $294 million of that total, with Southern Company and Orlando’s muni funding the remainder. Commercial opera-tion is scheduled for June 2010.

3. Bechtel inside. Watts Bar, TVA’s third nuclear plant, is on the shore of Chickamauga Reservoir in Sprint City, Tenn. Major construc-tion began in 1973, and the plant began com-mercial operation on May 27, 1996. Courtesy: Tennessee Valley Authority

Proposed gasification project

Planned facility expansions

Six-cellcooling tower

Coal conveyor

Gasifier structure

285-MW combined-cycle unit Gas cleanup processesand rotating equipment

ExistingStanton Unit A

4. New breed. Southern Company and the Orlando Utilities Commission have broken ground on the first next-generation IGCC plant in the U.S. It will be built on the grounds of the latter’s Stanton Energy Center. Courtesy: Southern Company




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GLOBAL MONITOR

UK approves wave energy “hub”The British government has approved construction of the most ambitious ocean energy facility proposed to date—the $56 million Wave Hub, a deep-sea electricity “socket” that will sit on the seabed 10 miles off the Cornish coast and link as many as 30 wave energy machines to the UK electricity grid.

The project, to be located in waters about 150 feet deep, will enable wave energy developers to “plug in” and test the efficiency and durability of their ma-chines, which convert the kinetic energy of waves to electricity.

Plans call for the Wave Hub (Fig-ure 5) to be connected to the UK grid by a 15-mile undersea cable that will come ashore at a substation at Hayle, in southwest England. All told, Wave Hub could deliver up to 20 MW of electricity, enough power to meet 3% of Cornwall’s electricity needs, according to the South West of England Regional Development Agency (Southwest RDA), the project’s main backer.

Despite broad political support in Brit-ain for Wave Hub as a clean energy in-

novation, the project encountered some rough waters in the form of protests by local surfers that the deployment of its wave machines, which ride on the sur-face, might flatten out swells. However, a noted surfers’ group, Surfers Against Sew-age, endorsed the project after scientists concluded that that was unlikely.

Four wave energy developers have been chosen for the initial deployment of Wave Hub: Oceanlinx, Ocean Power

Technologies Ltd., Fred Olsen Ltd., and WestWave. The last is a consortium led by E.ON AG and Ocean Prospect Ltd. that would use the Pelamis technology of Ocean Power Delivery Ltd. The Wave Hub project will cover an area measuring 2.5 miles by 1 mile; each early developer will be given a 5-to-10-year lease for a space in that area.

Ocean Power Delivery and Ocean Power Technologies are two of the early lead-ers in the wave energy field. The former company won the world’s first contract to develop a commercial wave power farm by convincing a consortium led by Enersis to let it install 31 Pelamis machines off the coast of Portugal.

Meanwhile, Ocean Power Technologies will be supplying its PowerBuoy technol-ogy to a major wave power project off the Oregon coast. This June, the com-pany, which says it has a backlog of or-ders worth $6.9 million, received a $1.7 million contract from the U.S. Navy to provide an autonomous PowerBuoy in connection with an ocean data gathering system known as the Deep Water Acous-tic Detection System.

However, wave energy developers still

5. Current from currents. The UK has approved construction of this “Wave Hub,” which will link up to 30 wave energy plants expected to be built off the country’s south-west coast. Courtesy: South West England Wave Hub Project


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face significant technical challenges. Among them are proving that their ma-chines can withstand long periods of sub-mersion in the harsh ocean environment and maintain their output despite vari-able wave conditions.

The British government will subsidize the offshore Cornish project to the tune of $9 million. Southwest RDA, which has already spent more than $4 million on permitting, has approved $43.4 mil-lion for Wave Hub, with half of that sum expected to come from the European Regional Development Fund.

New Jersey–New York HV system launchedAt the formal dedication of the Neptune Regional Transmission System this sum-mer, officials of the Long Island Power Authority (LIPA) said that the first 100 days of operating the new, 65-mile un-dersea and underground transmission link between “the island” and New Jersey saved it an estimated $20 million. They expect the $600 million system to deliver more than $1 billion in net benefits to LIPA and its 1.1 million customers over the next 20 years.

The system (www.neptunerts.com)—currently the largest underwater HVDC (high-voltage direct current) system in America—gives LIPA access to 660 MW of reliable, competitively priced electricity from the 13-state PJM energy grid, one of the most diverse wholesale power markets in the U.S.

After taking and culling competitive bids from prospective suppliers in 2004, LIPA began building two converter sta-tions and the 65-mile cable in July 2005. The transmission system commenced operations this June, ahead of schedule and within budget. More than 50 miles of the cable are buried beneath the Raritan River, New York Harbor, and the Atlantic Ocean. The cable brings power from Sayre-ville, New Jersey, to Long Island (which is chronically short of generating capacity), where it comes ashore near Jones Beach (Figure 6).

“The Neptune project is an example of how this type of HVDC technology can bring much-needed electric power and transmission infrastructure to densely populated areas in a cost-effective and environmentally friendly way,” said Edward M. Stern, president and CEO of Neptune Regional Transmission System LLC. “Many American cities that face growing demand for energy would be well-served by imple-menting projects such as Neptune.”

The Neptune cable is the first 500-kV

submarine cable to use mass-impreg-nated, paper-insulated technology from Prysmian Cables and Systems USA LLC (www.prysmian.com) that makes it all but invulnerable to external damage. Ac-cording to Prysmian, the installation was done using equipment it engineered to have minimum environmental impact.

A converter station in New Jersey trans-forms alternating current (AC) power to direct current (DC) power for transmission to Long Island. There, another converter station (Figure 7) transforms the DC pow-er back to AC form for distribution to LIPA customers. The power can move in both directions. Siemens Power Transmission & Distribution Inc. designed, engineered, built, and installed both converter sta-

tions and will operate them for the next five years.

Neptune Regional Transmission System LLC—the developer, owner, and operator of the link—is responsible for its plan-ning, permitting, financing, and construc-tion. Affiliates of Energy Investors Funds and Starwood Capital Group Global are the principal equity investors in the firm.

Membrane strips CO2 from methane fasterA modified plastic material promises much more efficient separation of CO2 from nat-ural gas, according to scientists at The University of Texas at Austin who have analyzed its performance.

Like a sponge that only soaks up cer-

0 1.25 2.5 5

Project NeptuneConverter stationExisting substationHVDC transmission lineU.S. Army Corps of Engineers channel

N

6. Island-hopping. This 65-mile underground and undersea HVDC transmission line is now bringing needed power from New Jersey to Long Island. Courtesy: Neptune Regional Transmission System

7. AC/DC rules. A bird’s-eye view of the Long Island Power Authority’s Duffy Avenue con-verter station, as of May 2007. Courtesy: Neptune Regional Transmission System


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tain chemicals, the new plastic lets CO2 or other small molecules pass through hour-glass-shaped pores within it, while im-peding natural gas (methane) movement through them (Figure 8). The thermally rearranged (TR) plastic appears to be four times more efficient than conventional membranes at separating carbon dioxide using pores.

Dr. Ho Bum Park, a postdoctoral student in the chemical engineering laboratory of Professor Benny Freeman, found that TR plastic membranes also work more quickly, by permitting CO2 to move through them several hundred times faster than through conventional membranes. As part of the process, they also keep natural gas and most other substances from traveling through the pores, improving separation efficiency.

“If this material were used instead of conventional cellulose acetate mem-branes, processing plants would require 500 times less space to process natural gas for use because of the membranes’ more efficient separation capabilities, and would lose less natural gas in their waste products,” said Freeman. He noted that, pound for pound, natural gas contributes much more to global warming than does carbon dioxide.

If commercialized, the plastic could also be used to isolate natural gas from decomposing garbage, the focus of sev-

eral experimental projects nationally. The TR plastic described in the current issue of Science also could help recapture CO2 being pumped into oil reservoirs in West Texas and elsewhere to aid in extracting residual oil.

Park initially engineered the membrane while at Hanyang University in Korea. As a research assistant, he investigated whether plastics made of rings of carbon and certain other elements would be effi-cient separators of CO2 from power plants’ flue gases. Separation of the greenhouse gas from other flue gases usually must be done at temperatures high enough to de-stroy plastic membranes.

Park not only found that the TR plastic could handle temperatures above 600F, but also that the heat transformed the material into a membrane that breaks a performance barrier thought to affect all plastic membranes.

“I didn’t expect that the TR plastic would work better than any other plastic membranes because thermally stable plas-tics usually have very low gas transport rates through them,” Park said. “Every-one had thought the performance barrier for plastic membranes could not be sur-passed.”

Park said, “These membranes also show the ability to transport ions since they are doped with acid molecules and therefore could be developed as fuel cell mem-branes. However, a lot of research still needs to be done to understand gas and ion transport through these membranes.”

POWER digestNews items of interest to power industry professionals.

Big run-of-river hydro project advanc-es. In a big step forward for one of the largest of a new breed of environmentally sensitive hydroelectric plants, a small re-newable energy company and GE Financial Services have awarded a $500 million fixed-price contract to Peter Kiewit Sons Co. to build a 196-MW run-of-river hy-dropower facility on two rivers in British Columbia.

Officials of Vancouver-based Plutonic Power Corp. said the engineering, pro-curement, and construction contract would help finalize financing for the Toba-Montrose project, comprising two power generating stations on the East Toba River and Montrose Creek. At press time, Plutonic said it expected to com-plete the financing package from lenders by the end of October 2007. The total cost of the project, which includes a 90-mile transmission line, is $660 million. Both

stations are expected to be operational by the end of 2010.

The run-of-river hydro project is one of the biggest launched to date. Unlike traditional “storage” hydro facilities, run-of-river plants do not require dams or impoundments that block fish migration or lead to silt buildup or other ecosystem changes. Rather, the plants divert water to riverside powerhouses that produce electricity while minimally disrupting river flow.

General Electric has pledged to invest up to $110 million to acquire a 49% eq-uity stake and a 60% economic interest in the Toba-Montrose project, 118 miles northwest of Vancouver.

Plutonic has proposed an ambitious plan to harness British Columbia’s ample hydropower resources by building 34 run-of-river plants with a total capacity of 1,700 MW.

AEP, MidAmerican look to build grids nationwide. Expanding a partnership that began in the booming Texas electric-ity market, American Electric Power Co. (AEP) and MidAmerican Energy Holdings Co. have formed a joint venture to build and own high-voltage transmission assets in other states.

The 50-50 joint venture, Electric Trans-mission America LLC (ETA), combines AEP’s expertise in power line construction and operation with the deep pockets of privately held MidAmerican, the energy investment vehicle of Warren Buffett’s Berkshire Hathaway. This August, POWER named MidAmerican Energy’s Walter Scott, Jr. Energy Center Unit 4 its 2007 Plant of the Year.

The two companies said they intend to invest only in transmission projects that cost at least $100 million. Candidates will be chosen by a board that will in-clude two representatives of Ohio-based AEP and two from MidAmerican, which is headquartered in Iowa.

The companies plan to launch their first project during the first half of 2008, with AEP acting as project manager to de-velop and build the transmission lines and facilities for ETA.

AEP deploying grid batteries to boost reliability. In a move that it said will en-hance reliability and facilitate wind farm development, AEP said it plans to deploy three large sodium-sulfur batteries as the first step of an effort to add 1,000 MW of “advanced” storage capacity to its huge grid within 10 years.

AEP said two of the batteries will be installed in West Virginia and Ohio, and that it was working with wind power

8. Carbon traffic cop. A new polymer membrane has pores that mimic those natu-rally occurring within cell membranes. The pores’ unique hourglass shape effectively segregates gaseous molecules on the basis of shape. The separation of carbon dioxide (gray and red) from methane (gray and white) is illustrated. Courtesy: Commonwealth Sci-entific and Industrial Research Organization


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developers to identify a third location within AEP’s 11-state service territory. Using batteries to store electricity helps offset the intermittent nature of wind generation.

The first two batteries each will have a capacity of 2 MW. The one planned for West Virginia will be installed near Milton, to enhance local reliability and support continued load growth. The mis-sions of the Ohio battery, to be installed near Findlay, Ohio, will be to improve reliability, bolster weak sub-transmission systems, and avoid equipment overload.

Japan’s NGK Insulators Ltd. and Tokyo Electric Power Co. developed the batter-ies, which will be delivered in the spring of 2008. According to AEP, it will spend $27 million to buy and install the three batteries and their control systems.

AEP chairman, president, and CEO Michael Morris said the company hopes to have at least 25 MW of battery capac-ity in place by the end of this decade. In 2006, AEP installed the first megawatt-class sodium-sulfur battery on a U.S. distribution system, at a substation near Charleston, W.Va., operated by AEP sub-sidiary Appalachian Power.

Barnwell radwaste disposal site to close. In a move that will reduce the nation’s already limited capacity for dis-posing of low-level radioactive waste, EnergySolutions LLC has announced it will not seek to keep its Barnwell landfill in South Carolina open to waste genera-tors from all states after June 2008. The decision reflects growing opposition to radwaste storage by state lawmakers, as well as a new controversy over groundwa-ter contamination at Barnwell that has drawn the concern of South Carolina’s at-torney general.

EnergySolutions officials said they will not try to change a current South Carolina law that requires Barnwell to stop accept-ing deliveries of nuclear waste from states other than South Carolina, Connecticut, and New Jersey—the three members of the Atlantic interstate compact for low-level radioactive waste disposal.

Barnwell’s closing will leave most utili-ties and other low-level radwaste genera-tors only two commercial disposal options: a facility in Clive, Utah (also operated by EnergySolutions), and a landfill in Rich-land, Wash., managed by a subsidiary of American Ecology Corp. under the trade name U.S. Ecology. The Washington site only accepts deliveries of low-level rad-waste from states belonging to the North-west and Rocky Mountain waste disposal compacts.

Barnwell, the nation’s oldest low-level waste disposal site, began operation in 1971 and has since taken in about 28 million cubic feet of waste. The 235-acre site is now 90% full. In recent years, envi-ronmentalists have ratcheted up their op-position to Barnwell, saying its disposal practices do not meet modern standards, as evidenced by the burial of some waste in containers with holes in the bottom.

EnergySolutions officials said their de-cision on Barnwell was largely dictated by political realities in South Carolina. In particular, they noted that the Agriculture Committee in the South Carolina House of Representatives voted 16-0 this April to defeat a proposal that would have kept Barnwell open to all states for another 15 years. The unanimous vote was somewhat surprising because the state government has typically received more than $10 mil-lion annually from Barnwell to support education programs—revenues that will doubtless be curtailed by the restriction of access to the landfill.

We Energies transfers ownership of Point Beach Nuclear Plant to FPL Energy. On October 1, We Energies announced completion of the sale of its two-unit Point Beach Nuclear Plant to FPL Energy. On that day, FPL assumed management and operation of Point Beach from Nuclear Management Co., which had operated the plant for We Energies since 2000.

FPL Energy bought the plant, its nu-clear fuel, and associated inventories for $924 million. With final closing adjust-ments, the deal also will release to We En-ergies decommissioning trust investments worth more than $482 million. All told, the sale will yield more than $882 million of proceeds for the benefit of We Energies’ customers—about $57 million more than originally projected.

The Point Beach plant is located near Two Rivers, Wis. Its first unit entered com-mercial service in 1970 and is licensed to operate until 2030. The second unit came on-line in 1973 and has an operating li-cense that expires in 2033.

The sale includes a long-term power-purchase agreement that requires FPL Energy to sell 100% of each unit’s pro-duction to We Energies until its current license expires. We Energies also has the option to purchase power resulting from any capacity uprates, as well as an option to invest in and own up to 40% of any new generation built at the site.

Australian CO2 reduction project breaks ground. Alstom has hired Inter-national Power (Technologies) Pty Ltd. to design, engineer, and build a dem-

onstration plant at its Australia & New Zealand subsidiary’s 8 x 200-MW lignite-fired Hazelwood Power Station. The proj-ect will showcase technologies capable of dramatically reducing the plant’s CO2 intensity.

The scope of the project includes dem-onstrating a new lignite drying tech-nology, developed by Alstom and RWE of Germany, for reducing the moisture content of brown coal from over 60% to 12%. The retrofit will require modifying one of Hazelwood’s eight boilers to re-duce its CO2 emissions intensity by 20%, increase its capacity by 10%, and extend its life to 2030. The project also will en-tail augmenting the unit’s fuel heating system and upgrading its steam turbine-generator.

The project, called Hazelwood 2030, has received strong public support in the forms of a $50 million grant from the Australian government’s Low Emissions Technology Development Fund and a $30 million grant from the government of Vic-toria State as part of its Energy Technol-ogy Innovation Strategy.

Contracts also have been finalized with Alstom for the supply of all equipment and technology. The project will now move into the detailed design phase. Ground-breaking is scheduled for 2008.

The Hazelwood 2030 project also calls for construction of a pilot carbon capture plant by late 2008. Designed to capture 16 to 25 tons of CO2 per day from one of the facility’s generating units, the pilot plant will be one of the world’s biggest. The capture technology to be used will use a solvent solution injected into the flue gas to absorb CO2.

Innovative solar thermal plant planned for Florida. FPL Group says it plans to build what may become a 300-MW solar thermal power plant in Florida. If the project pans out, the plant would be the state’s first commercial facility of its kind.

FPL will begin by building a prototype 10-MW facility using technology from Ausra Inc. that employs flat arrays of Fres-nel lenses to focus the sun’s heat. Most solar thermal plants use parabolic mirrors to perform that function, which has not yet been proven commercially viable.

According to FPL, the capacity of the pilot plant will be scaled up to 300 MW only if the Ausra technology meets its cost and performance goals. In a related announcement, FPL said it also plans to develop 200 MW of solar thermal power plants in California over the next seven years. ■


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FOCUS ON O&M

SYSTEM RELIABILITY

The NERC auditors are comingThe persons responsible for reliability (re-sponsible entities) at utilities and other participants in the U.S./Canadian bulk power industry are preparing to have their companies’ compliance with the North American Electric Reliability Corp.’s (NERC’s) mandatory reliability standards audited by teams from NERC Regional Entities (REs). The audit schedule for 2008–2010 should have been posted on NERC’s web site (www.nerc.com) by the end of October.

Transmission operators, balancing au-thorities, generator owner/operators, and the other functional responsible-entity categories are gathering documentation and other evidence to demonstrate their compliance with the reliability standards to the audit teams. NERC REs will notify entities of the date of their audit and which standards it will address. NERC posted Reliability Standards Audit Work-sheets for 40 different reliability-related activities on its web site this May, ahead of the June 1 effective date of the stan-dards. The site visit will conclude with an exit presentation by the audit team and the passing out of an audit evaluation form to be filled out by audit team mem-bers and the audited entity.

New compliance challengesAs responsible entities vet the standards applicable to their category, they are find-ing that, in most cases, compliance is be-ing achieved. Their next challenges are to ensure that all internal departments know which activities they must perform and document and that proof of compliance is readily accessible in a convenient for-mat. For many participants, the challenge of compliance has become a question of “how” and “where,” rather than “if.”

Responsible entities are preparing for the audits in various ways, from insisting on electronic documentation, to planning to record or transcribe the audit itself, to arranging for their lawyers to be present. Some are making plans to have consultants on hand for pre-audit preparation, for the audit itself, and for post-audit activities such as evaluation, settlement of alleged violations, and contributing to records needed to support litigation, if needed.

Complicating these efforts is the fact

that the structure, intent, and target of some standards remain unclear and ques-tionable. Many of the mandatory standards were adapted from voluntary standards written when most utilities were vertically integrated and housed separate functions such as balancing authority, transmission owner, transmission operator, load-serv-ing entity, and generator owner/opera-tor under one roof. Because deregulation unbundled many of these functions, some reliability standards and their require-ments now are difficult to apply to dis-crete responsible entities.

In some cases, the complications re-sulting from unbundling even extend to registration of functional entities. For example, in some instances competitive retail power providers are being cast in the role of load-serving entities, required to account for demand-side management programs and load forecasting. NERC says it is in the process of realigning the func-tional model that serves as the basis of registrations. But that is little comfort to the responsible entities at new partici-pant categories that were not part of the old industry structure. They are being told that they must comply with the new stan-dards even as their scope of applicability is being revised.

Dazed and confusedUntil discrepancies like these are re-solved, confusion and anxiety in the in-dustry will continue to grow and threaten to undermine the intent and acceptance of mandatory reliability standards. Here’s hoping that NERC auditors do not stub-bornly insist on evidence of compliance from those responsible entities who are unsure even of which data to access to meet their requirements.

On the other hand, there’s no doubt that NERC and its overseer—the Federal Energy Regulatory Commission—have succeeded in raising the industry’s aware-ness of the standards, not to mention the penalties for failing to comply with them. Through its Work Plan, NERC will eventu-ally resolve the questions of applicability and ambiguity. Until it does, audited en-tities should feel free to press their audit team on issues they feel are unclear or unsustainable under the current language of the standards.

Assuming they have prepared adequate-ly, and made themselves aware of both

the spirit and letter of the new reliability laws, responsible entities should be able to approach their audit with confidence, anticipating an active exchange with the audit team. Ideally, audits—an essential part of compliance enforcement—will enhance, rather than detract from the overall reliability of the North American bulk power system during this early phase of transition from voluntary to manda-tory standards. With common-sense ap-plication of standards and the industry’s continued participation in refining them, that is an achievable goal.

—Jim Stanton ([email protected]), POWER contributing editor and director of

NERC compliance for ICF International.

INSTRUMENTATION

Winning encore for on-line pH monitoringOn-line pH monitoring is a quick and ac-curate way to determine if a high-purity boiler feedwater system has become con-taminated. If impurities in the system volatize into steam in the boiler, they can end up as scale on tubes. If the impurities make it to the turbine, they can end up as scale on blades. Besides causing O&M

1. Intruder alert. The new owner of Huntley Power Station, near Buffalo, N.Y., installed Hach pH/oxidation reduction poten-tial panels specifically designed for accurate, reliable operation of its high-purity feedwater system. The panels address CO2 intrusion and static buildup problems that conventional pH meters have a hard time handling. Cour-tesy: Hach Co.

018 O&M.indd 18018 O&M.indd 18 11/5/07 4:17:33 PM11/5/07 4:17:33 PM



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FOCUS ON O&M

problems, scale promotes corrosion—the culprit in about half of boiler outages and the majority of tube failures.

Although process pH instruments are to-day commonly used to monitor steam water circuits to safeguard against contamina-tion, technicians at Huntley Power Station in Tonawanda, N.Y., had long relied solely on daily “grab” sample measurements be-cause the facility was not equipped with accurate on-line instrumentation.

The 1999 acquisition of the Huntley plant by NRG Energy (www.nrgenergy.com) brought numerous positive changes to the station. One was the addition in November 2006 of on-line pH and con-ductivity sensors and other advanced water-chemistry analysis instrumentation for monitoring key points in the station’s boiler water circuits. The new sensors and instruments (Figure 1, p. TK) have sig-nificantly improved the accuracy of the plant’s on-line water-chemistry monitor-ing program, which helps drive critical process control decisions. For example, data logging and trending of key process parameters have given the Huntley plant’s water chemistry techs new insight into the operation of the water treatment system.

Easy act to followHuntley, a coal-fired baseload plant just north of Buffalo, is a key player in the western New York energy market and one of the lowest-cost producers in the state. The plant’s two 200-MW units operate at 2,550 psi and superheat temperatures in excess of 1,000F. Surface water from the Niagara River is the plant’s source of raw water. It is treated first by precipitation, then filtering, and finally by ion-exchange demineralization. The treatment plant produces about 300,000 gallons of high-purity feedwater daily.

Technicians monitor pH, conductiv-ity, chlorides, silica, iron, and copper at various points in the plant’s water/steam cycle. The boiler water’s pH is maintained between 9.0 and 9.4, while its conduc-tivity is kept below 5 microsiemens per centimeter (µS/cm).

On-line water chemistry analyzers had been installed at Huntley in the mid-1990s, but their performance was never reliable, according to Ray LaMarca, the plant’s chief technician. “We didn’t be-lieve the analyzers’ readings,” LaMarca says. “We looked at them every day, but they never agreed with the results from

our chem lab. As a result, we never trusted the analyzers enough to rely on them.”

Looking for a good pH meterUnable to trust the instrumentation, op-erators were forced to rely exclusively on grab sample analysis—a poor situation for a baseload plant. With better on-line instruments available and NRG willing to invest in them, the decision was made to install reliable, accurate on-line feedwa-ter analysis gear.

Selecting an on-line pH analyzer is challenging. It’s difficult to accurately read the pH of high-quality makeup water because its inherently low solution con-ductivity creates several problems that can lead to gross measurement errors. For example, intrusion of CO2 from the atmo-sphere can acidify samples of pure water, lowering their apparent pH below 7. An-other common problem is static buildup, which occurs because pure water is a poor conductor of electricity. Buildups create static charges when they flow past non-conducting materials in a pH sensor and generate stray currents in the solution that may cause large errors.

Huntley Power Station ultimately se-

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lected Model 8362sc pH/oxidation reduc-tion potential (ORP) panels from Hach Co. (www.hach.com) because they are spe-cifically designed for high-purity water treatment systems. For example, the pan-els’ design addresses the problems of CO2 intrusion and static buildup that conven-tional pH metering system designs have trouble dealing with. The panels’ housing is completely sealed to prevent carbon di-oxide intrusion, and it and the sampling chamber are made of conductive materials that minimize static charges and the po-tential for stray currents (Figure 2).

New home for the systemThe new Hach system was installed in a new sample room (Figure 3), where it monitors the boiler water, feedwater, and hotwells of both generating units. Conductivity also is monitored on-line at several points of each water/steam circuit using separate controllers. In addition, two other sensors monitor cation con-ductivity in both hotwells and feedwater lines. The new pH and conductivity probes also monitor temperature, which can play a significant role in chemical changes and their interpretation.

The pH and conductivity units plug into the controllers, each of which can receive data from up to two sensors simultane-ously. The two sensors need not be for the same parameter (a controller unit can ac-cept conductivity, pH/ORP, dissolved oxy-gen, and turbidity probes). Huntley Power Plant installed eight controllers to serve six pH panels and 10 conductivity probes. The units have built-in data loggers that can collect measurements at user-defined intervals from 1 to 30 minutes, along with calibration and verification points, alarm histories, and instrument setup changes covering six months. At Huntley, the con-trollers are configured to send 4- to-20-milliamp signals to the plant’s distributed control system (DCS).

Tough audienceAfter having negative experiences with the previous on-line monitoring instruments, Huntley station technicians understand-ably were skeptical about the accuracy of the new system’s measurements. But their assessments to date have been quite sat-isfactory, according to LaMarca.

“When we compare the pH readings of the new panels to those obtained in our lab, the two sets of readings are always very close,” reports LaMarca. “They’re not identical, but they’re typically within 0.10. We’ve also found that the new units have very little drift. PH measurement is

very difficult in our kind of application, and the new instruments have been good to us so far.”

LaMarca is also pleased that the new system has required little maintenance to date. Much of the maintenance entails periodically cleaning the flow cells and doing monthly calibrations, which can be accomplished easily and automatically us-ing panel touchscreens. No repairs or re-placements have been required.

The addition of data logging and real-time data monitoring capabilities has al-lowed technicians to respond to problems much more proactively. “The data are up-dated every 6 minutes on my DCS screen,” LaMarca says, “and that’s great for trend-ing and watching the effect of changes in treatment timing.

“For example, we control pH by feeding an amine into the hotwell. The continu-ous monitoring and data feed from our

2. A well-instrumented system. Conductivity and pH units plug into controllers that each can receive data from two sensors simultaneously. Huntley Power Plant now has eight controllers serving six pH panels and 10 conductivity probes. Courtesy: Hach Co.

3. New sample room. The units have built-in data loggers that collect measurements at user-defined intervals and send analog signals to the plant’s distributed control system. Courtesy: Hach Co.


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FOCUS ON O&M

pH meters allow us to quickly detect the changes produced by its addition. Case in point: after a shutdown of one of our units, we immediately saw a significant drop in the pH in the hotwell of the other unit, which was still on-line. As it turned out, someone had inadvertently left a tie valve on the off-line left open, allowing its feed of amine to enter the operating unit. The valve was finally closed during shutdown procedures, prompting the pH drop. Thanks to the new meters, I was quickly made aware of the situation. After I corrected it by making a series of adjust-ments to the amine feed rate, I was able to watch the pH of the on-line unit rise on my DCS screen.”

—By Phil Kiser ([email protected]), Hach’s industrial applications manager.

PLANT MAINTENANCE

Using balloons as temporary barriersMaking repairs to cooling water intake pipes suffering from flow-accelerated corrosion, erosion, or even zebra mussel infestation is critical to plant reliability. Maintaining the integrity of 12- or 13-foot-diameter pipes

4. Put this in your pipe. Ershigs Inc.—a designer, manufacturer, and installer of corro-sion-resistant, fiberglass reinforced plastic fluid-handling structures and piping systems—used duct balloons to prevent styrene fumes from escaping the work area during a recent intake-pipe relining project at FirstEnergy’s Perry nuclear plant. Courtesy: G.R. Werth & Associates Inc.

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FOCUS ON O&M

during the fixes always requires specialized experience, and oc-casionally some unorthodox repair methods as well.

FirstEnergy recently hired Ershigs Inc. (www.ershigs.com) to reline the intake pipes of its Perry Nuclear Power Plant near Cleveland in-situ with a fiberglass material to protect them. The first phase of the project targeted 400 feet of pipe. The bond-ing improves if the inside of the pipe is clean and the work is performed at an ambient temperature above 60F. So before the relining work began, temporary barriers of wood and plastic sheeting were constructed on-site and placed inside the pipes to provide for dust and temperature control—the usual tactic.

Building a 12-foot-round wood barrier can be very time-con-suming. What’s more, variations in the geometry and condi-tions of a pipe’s inner wall make it almost impossible to create a good seal between the barrier and the wall. After this “wagon wheel” wood frame has been constructed, plastic sheeting is then attached to it. Sometimes, holes are cut in the sheeting to allow for the passage of ventilation tubes for evacuating styrene fumes and supplying fresh air to the work area.

After the piping has been relined, the wood frame and plastic barriers typically are removed and thrown in the trash. That’s what Ershigs did on the first phase of the FirstEnergy project. Unhappy with the ineffectiveness and waste of this homemade barrier method, the utility asked the contractor to devise a better scheme for isolating pipes during their repair.

The second phase of the project called for relining 200 linear feet of pipe. This time, Ershigs used inflatable bulkheads—also known as duct balloons—manufactured by Scherba Industries Inc. and distributed exclusively by G.R. Werth & Associates, Inc.

The duct balloons (Figure 4) are made of a heavy-duty, tear-resistant material that conforms to any imperfections in the in-ner diameter of a pipe. Each balloon is equipped with a 120-V high-pressure blower system that remains on at all times to keep the balloon fully inflated, even in the event of a small hole or cut. Should more extensive damage occur, it can be repaired quickly using the supplied patch kit.

To meet the needs of the second phase of the Perry project, Scherba and Werth supplied two duct balloons—one 12 and the other 13 feet in diameter. Each included a 6-foot by 3-foot access door with Velcro closure flaps to allow workers to pass through the balloon while it remained fully inflated. Each balloon also was equipped with a 20-inch-diameter access hole with Velcroed flaps (Figure 5) to facilitate passing a vent line through it.

A duct balloon weighs less than 50 pounds and inflates in under 2 minutes. A large deflation zipper enables it to be re-moved from service in less than 1 minute. Grab handles make it easy to put a balloon in place, and anchor rings provide tie-down points to prevent it from being moved by positive pressure inside the pipe.

—For more information, visit www.ductballoon.com or contact Gary Werth ([email protected] ) of G.R. Werth at 630-564-7471.

ENERGY EFFICIENCY

How data logging can cut power billsOne of the greatest challenges facing building owners and facili-ties professionals today is finding ways to reduce energy costs. The challenge can be even greater in factories full of electricity-hungry production equipment.

Air compressors, for example, are often a factory’s largest en-ergy consumers. According to the U.S. Department of Energy, the majority of compressed-air systems at small and midsize indus-trial facilities have energy-efficiency opportunities.

Concerned about its factory’s high and rising electric bill, a New York–based metal products manufacturer recently hired Power Concepts LLC (www.powerconceptsllc.com), a Manhattan-based consulting engineer, to conduct an energy audit at its plant. Specifically, the company wanted to monitor the run times of a number of air compressors in the factory to better under-stand their consumption patterns and pinpoint where energy-saving opportunities existed.

5. Easy in, easy out. A side view of a Scherba Industries duct balloon, showing the access door in the front. G.R. Werth & Associ-ates Inc.



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FOCUS ON O&M

First, do an auditBetsy Jenkins, director of Power Concepts’ energy field team, led the audit. She explains, “our client believed that air compressors were consuming most of the factory’s energy. They wanted us to confirm that by calculating precisely how long several operated over a typical period. With that information in hand, we would then be able to recommend steps the client could take to cut the factory’s power consumption.”

To monitor the compressors’ run times, Jenkins chose HOBO State (on/off) data loggers from Onset Computer Corp. (www.onsetcomp.com). She did so as a result of her experience, as well as the units’ excellent reputation. “In our line of work, we have to make sure that our recommendations are based on accurate data,” Jenkins says. “That’s where HOBOs really shine, and it doesn’t hurt that they’re very reliable and inexpensive, too.”

HOBO State loggers (Figure 6) are compact, battery-powered devices used to track changes in the operating status of a piece of equipment. In practice, a unit does just one job: recording every time that, say, a motor or compressor turns on or off, as well as the direction of the transition. For this customer, Jenkins’ team attached one HOBO to each of the factory’s three main compressors and then let it monitor changes in status over a two-week period (Figure 7).

After two weeks’ worth of data had been recorded, the infor-mation was uploaded to a PC and analyzed using Onset’s HOBO-ware Pro graphing and analysis software. The analysis indicated that compressor run times were unusually high, verifying the customer’s gut feeling.

Then, apply the resultsJenkins and her team then performed a second, more in-depth evaluation of the factory while it was shut down, during lunch hour. They detected several places where compressed air was leaking out of fittings. In one case, they noted a compressed air nozzle whose actuating handle had been taped open to disperse fumes.

“Because we conducted our site survey when the building was quiet, we were able to hear hissing sounds that no one had noticed before,” Jenkins explains. “We also discovered that one operator was using a compressor nozzle as a fan to blow fumes away from his welding machine. He had no idea that doing so was costing the company a ton of money. He could have had the fumes dispersed much more cheaply by asking his boss to have a small fan mounted near the machine.”

According to Jenkins, the data loggers also were instrumen-tal in helping her client understand that a large portion of the factory’s power consumption was attributable to several leaks in air compressors. “Before conducting the audit, our client didn’t realize how often the compressors were running. Now he does, and we expect that our recommended energy conservation mea-sures—plugging those leaks, for example—will save him a tidy sum,” concludes Jenkins. ■

—Contributed by Onset Computer Corp. (www.onsetcomp.com).

6. On the job. A Hobo State unit monitoring transitions of an air-operated valve. Courtesy: Power Concepts LLC

7. Big iron, small plastic. Another kind of Hobo, riding the rails of a compressor motor. Courtesy: Power Concepts LLC

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LEGAL & REGULATORY

Steven F. Greenwald Jeffrey P. Gray

Can FERC deliver transmission?By Steven F. Greenwald and Jeffrey P. Gray

This May, the Arizona Corporation Commission (ACC) reject-ed a proposal by Southern California Edison (SCE) to build Devers-Palo Verde No. 2 (DPV2)—a 230-mile-long, high-

voltage transmission line connecting California and Arizona. The line, approved by the California Public Utilities Commission (CPUC) four months earlier, would enable SCE to import addi-tional low-cost electricity from Arizona. The ACC’s rejection of DPV2 highlights a significant challenge for state and regional resource planners—weighing state interests against the regional benefits of interstate electricity commerce.

State v. stateAlthough it unanimously approved DPV2, the CPUC found that the project has several significant unmitigable environmental im-pacts. Nevertheless, it also determined that DPV2 would “provide significant economic benefits . . . , increase the reliability of the interstate transmission network . . . [and provide] . . . an eco-nomic hedge” against transmission and generation outages and natural gas price hikes. Given these benefits, the CPUC concluded that the environmental impacts of DPV2 would be acceptable.

The ACC, by contrast, rejected DPV2 as a California “power grab”—both literally and figuratively. Commissioner Kris Mayes scorned the line as a “230-mile extension cord into Arizona . . . [that] . . . would come at the expense of Arizona ratepayers, Ari-zona air quality, Arizona land, Arizona water, and Arizona wildlife.” Commissioner Jeff Hatch-Miller called on California “to step up to the plate and begin building its own generation—in California.”

The ACC’s rejection places the future of DPV2 in serious doubt.

Overruling the statesThe Energy Policy Act of 2005 (EPAct) directs the U.S. Department of Energy (DOE) to pinpoint transmission congestion problems and authorizes the secretary of energy to designate as “national interest electric transmission corridors” geographic areas where such problems “adversely affect consumers.” Once an area has been designated a national interest corridor, the federal govern-ment—specifically, the Federal Energy Regulatory Commission (FERC)—can approve any proposed transmission project within the area for which state regulators have “withheld” approval for more than a year. In a 2006 rulemaking, FERC interpreted the meaning of the word “withheld” in EPAct to include “denied.” So, in effect, FERC can overrule a state’s rejection of any trans-mission project in a designated congested region simply by find-ing that it would ease the congestion.

Last month, the DOE designated areas of Arizona and southern California—including some that DPV2 would pass through—as the Southwest national interest corridor, presenting SCE the op-portunity to have FERC reverse the ACC decision. It remains un-

clear, however, whether the utility will take it. SCE has stated that it will continue to work with the CPUC and ACC on DPV2 permitting issues.

Back to square oneSCE’s initial reluctance to involve FERC suggests that the util-ity believes it may be cheaper and quicker to try to work things out with Arizona. Asking FERC to intervene requires a project’s sponsor to file an application, essentially restarting the entire approval process. The application would be (as at the state level) subject to protest—an inevitability for any large transmission project. As part of any application proceeding, FERC would also conduct a full environmental review and evaluate “alternatives.”

SCE filed its DPV2 application at the CPUC in April 2005. Now, more than two years later, it finds its only two options are to address the ACC’s concerns or to begin again at FERC. Although FERC’s history of approving virtually every application it has re-ceived for natural gas transmission pipelines suggests it offers a “friendlier” venue, pursuing either option will delay the project and increase its cost.

A road to nowhere?In designating the Southwest corridor, the DOE—noting grow-ing demand for power—explained that, “now, more than ever, we must look at electricity generation from a regional and na-tional perspective.” However, the designation by itself neither overturns the ACC’s ruling nor guarantees that any new trans-mission lines will be built in the corridor. Indeed, given the considerable time and cost needed to secure a FERC decision overruling a state decision, using the national corridor process to change jurisdiction may not prove to be a practical alterna-tive to the state project approval processes that EPAct clearly intended to reform.

As the need for new generating capacity (particularly capac-ity powered by renewable resources) grows, states must work together to develop regional transmission solutions. Wind in Wyoming, solar in Arizona, and hydro and biomass in the Pacific Northwest all require a network of interstate facilities to bring power from remote areas to load centers.

Accordingly, transmission needs should increasingly be as-sessed through a regional lens. Whenever the political and pa-rochial interests of a state impede the development of a needed project, a practical alternative must be available. National inter-est transmission corridors could be the answer, but at first blush, they may not offer one. ■

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

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TOP PLANTS

Browns Ferry Nuclear Power Plant,Athens, AlabamaOwner/operator: Tennessee Valley AuthorityTVA’s 1,155-MW Browns Ferry Unit 1 returned to service on May 22 after sitting

idle since 1985, when all three units were shut down to address manage-ment and operational concerns. Units 2 and 3 returned to service in 1991 and 1995, respectively, after extensive upgrades to controls, electrical sys-tems, pumps, motors, and more. The return of Unit 1 began in 2002 with a five-year $1.8 billion restart plan to make all three units essentially identi-cal, and that goal was accomplished in style. Welcome back, Unit 1.

By Kennedy Maize

The Tennessee Valley Authority (TVA) would be entirely justified in renam-ing its Browns Ferry Unit 1 nuclear

power plant the “Phoenix” power plant. Not for geographic reasons (the plant is located in Alabama, not Arizona). Rather, the name would be an appropriate nod to the mytho-logical Egyptian bird that repeatedly dies in fire and is reborn from ashes to conquer the sky. The 1,200-MW General Electric boiling water reactor powering the unit has twice

crashed in ashes—first literally and then figuratively—during its 40-year history, and been reborn. It has earned its title as the ulti-mate comeback reactor.

What’s old is new againThe latest return of Browns Ferry Unit 1 to service this year results from a massive upgrading and restart of an existing reac-tor—one that had not run since 1985, when a regulatory shutdown of TVA’s entire five-

reactor fleet idled this elderly unit. Over the years, TVA returned the two younger Browns Ferry boilers and the two Sequoyah Westing-house pressurized water reactor (PWR) units to service. Finally, it commissioned the Watts Bar Unit 1 PWR plant in 1996.

The Watts Bar start-up marked the last commissioning of a new nuclear plant in the U.S., emptying the nuclear construction pipe-line that began to dry up in the mid-1970s.

But Browns Ferry Unit 1 (Figure 1) re-mained in stasis. Not dead, but in a deep ad-ministrative coma.

In 2002, TVA decided that, given current and anticipated load growth, it needed to get the nuclear unit back in service. Restarting (and massively refurbishing) the aged nuke, the TVA board concluded, was less costly overall than building new generation. Five years and $1.8 billion later, the geriatric plant is up and running again, flexing its up-graded muscles and looking very much like a new unit.

The U.S. nuclear industry, always putting an optimistic face on its long-lasting exile from the generating market, has billed the Browns Ferry restart as the first new nuclear plant of the 21st century. That’s understand-able hyperbole, but not entirely accurate. TVA first broke ground on Browns Ferry in 1967. The plant that went back into service in 40 years later in 2007 surely isn’t the same one that started generating electricity in the early 1970s.

Browns Ferry Unit 1 isn’t the first U.S. unit of the 21st century; it’s the last unit of the 20th century—after being one of the first.

1. Successful restart. Browns Ferry Unit 1 was restarted in May of this year after a five-year, $1.8 billion overhaul. It had been idled since 1985, when it was shut down because of plant management and operations concerns. Courtesy: TVA

030 TP_Alabama.indd 30030 TP_Alabama.indd 30 11/5/07 4:49:42 PM11/5/07 4:49:42 PM



TOP PLANTS

Unit 1’s storied historyThe history of Browns Ferry Unit 1 illustrates the complexities of nuclear power economics and politics and the futility of making broad futuristic claims based on limited data. That the plant exists at all today is remarkable. It is a testament to the fundamental GE design and the modern management of TVA. It is also a reminder of TVA’s earlier history and its longest-serving, autocratic chief, Aubrey “Red” Wagner, who ran the federal power agency from 1961 to 1978 (Figure 2).

Nobody in America in the 1960s was more enthusiastic about the promise of nuclear power than Wisconsin farm boy Red Wagner. A civil engineer trained at the University of Wisconsin, he joined TVA in 1934, shortly after its birth at the hands of President Franklin Delano Roosevelt’s po-litical midwifery. Roosevelt, as governor of New York, had previously created the Power Authority of the State of New York, which became the TVA prototype.

A talented engineer, Wagner rose through TVA ranks. In 1961, President John F. Ken-nedy named Wagner to head the regional power and economic development agency. By 1965, Wagner had concluded that nuclear power was the future of electric generation, particularly for the TVA region. He had moved the TVA system away from the hy-dropower resources that had formed its gen-erating basis on the Tennessee River toward

the plentiful coal resources in the region—a recognition that hydro had just about used up its potential in the region.

But Wagner didn’t want to be vulnerable to volatile coal prices and the possibilities of air pollution control costs. TVA was the largest utility consumer of coal in the 1960s and 1970s. For more than a decade it fought federal air pollution control regulations, ar-guing that, as a federal government agency,

it was exempt from the Clean Air Act gov-erning other generators. Even TVA lawyers didn’t really believe that argument, though they argued it in federal courts. They ulti-mately lost.

Nuclear reactors promised a generating technology indifferent to fuel prices and with no emissions of sulfur dioxide and oxides of nitrogen; Wagner was sold. A TVA biogra-pher accurately said of Wagner, “He oversaw the construction of the agency’s last dams and its first nuclear reactors.”

Nuclear reactor salesmen regarded Wag-ner as an easy mark. One of them told me the 1980s, “You could pitch a new nuclear technology at Red and after a hour, he’d say, ‘I’ll take two units.’ ” Indeed, at one point, TVA agreed to buy 17 nuclear units—includ-ing boiling water reactors (BWRs), pressur-ized water reactors, and high-temperature gas-cooled reactors—from five different vendors.

Ultimately, after expenditures of billions of dollars, five units got built: three BWRs, including Browns Ferry Unit 1, and two PWRs at Sequoyah. A final PWR went into service at Watts Bar in 1996. The TVA board voted this year to resume construction on a second Watts Bar unit that’s been mothballed for more than a decade. When Watts Bar Unit 2 is completed, it will supplant Browns Ferry Unit 1 as the final nuclear plant of the 20th century (Figure 3).

2. Hard charger. Aubrey “Red” Wagner was responsible for transforming TVA from a hydro and coal utility into a nuclear utility. Courtesy: TVA

3. Double play. TVA’s board authorized completion of the 1,180-MW Watts Bar Unit 2 on August 1 of this year. Construction of Unit 2 was about 80% complete when work was suspended in the early 1990s. The project is expected to cost $2.49 billion and be finished by 2013. Unit 1 began operating in 1996 and is the last commercial nuclear unit in the U.S. to begin operation. Courtesy: TVA



TOP PLANTS

The last shall be firstBrowns Ferry was TVA’s first nuclear unit; the reactor order was placed in 1966. The Atomic Energy Commission—within a de-cade to be eviscerated by creation of the U.S. Nuclear Regulatory Commission (NRC)—licensed the plant to operate in 1973, near Decatur, Ala., at a place that was historically a well-known ford of the Tennessee River, widely commemorated in folk songs.

In fact, these lines from a traditional Ala-bama blues tune (author unknown) ring true for the nuclear plant as well: Hard luck pop-pa standing in the rain/If the world was corn he couldn’t buy grain/Lord Lord got those Brown’s Ferry Blues.

The first Browns Ferry unit entered com-mercial service on August 1, 1974. It was at that time the world’s largest nuclear power plant. The 1,200-MW GE boiler with a Mark 1 “donut and lightbulb” containment struc-ture was also decidedly state of the art.

The two GE BWRs that followed at the site were also state-of-the-art reactors, with upgraded pressure-suppression contain-ments. Units 2 and 3, as of March 1, 1975, and March 1, 1977, made Browns Ferry by far the largest nuclear power station in the world at the time. (Japan now has the largest nuclear station at Tokyo Electric Power Co.’s Kashiwazaki-Kariwa station. Its seven units produce 8,200 MW of electric power.)

When the first Browns Ferry unit went into service, said a report by the Union of Concerned Scientists, “The few dozen oper-ating nuclear power plants in the U.S. pro-duced barely more energy than the nation derived from firewood.”

Missing fire-stopsDespite its promise and initial quality per-formance, Browns Ferry Unit 1 had some important safety vulnerabilities that were un-anticipated by the industry, the utility, or the newly created NRC. Those were the early days of nuclear regulation, before regulators recognized the full complexities of nuclear generation.

One unforeseen vulnerability was fire. On March 22, 1975, during a plant modifi-cation, as Unit 1 was in its seventh month of successful operation and Unit 2 had just begun commercial operation, two workers were trying to detect air leaks where elec-trical control cables were entering the Unit 1 reactor building. The workers, apparently uninstructed by their supervisors, were us-ing candles to find air leaks where the cables entered the reactor building wall. This was, it turned out, equivalent to using cigarette lighters to find a natural gas leak.

The physical results of holding candles in the nuke weren’t as explosive as attempt-

ing to find a gas leak with an open flame, but they were at least as economically cata-strophic. The flames ignited polyurethane foam insulation in the cable penetrations. Then the plant literally went up in flames. Unexpectedly, the fire spread quickly and rendered the plant’s major safety equipment useless. The emergency core cooling system, expected to be the chief line of defense in a reactor accident, couldn’t function.

Fortunately, level-headed plant operators were able to use other, manual systems to get the reactor cooling process under control as the plant went out of service. It took a year to repair the damage and bring the plant back to where it could generate power.

The fire quickly fueled the U.S. antinu-clear movement, which had been smoldering for some time. Not long after the fire, which made the front pages of the nation’s news-papers and the nightly news broadcasts of the three national television networks, many critics were questioning whether nuclear power was a wise investment.

While conventional wisdom says the March 29, 1979, loss-of-coolant accident and nuclear fuel meltdown at the Three Mile Island (TMI) nuclear plant pulled the trig-ger on the end of the 1970s nuclear power boom, a more nuanced analysis suggests that it might have been the Browns Ferry fire.

A sign of future growth?TVA accomplished a major feat in turning a somewhat rudimentary, albeit fundamen-tally robust, early 1970s nuclear generating plant into a modern machine. It’s 20th to 21st century, analog to digital, primitive to modern. So far, the plant is operating with impeccable performance charactistics, and there’s no reason to suspect it won’t continue to behave well.

Will the return of Browns Ferry Unit 1 last May mark the beginning of the U.S. indus-try’s long-anticipated renaissance for nuclear power? That’s not yet discernable. The ques-tion may not be answerable. The Nuclear Energy Institute (NEI) and other nuclear industry interests clearly have their glowing fingers crossed in hopes that this restart will be the harbinger of more, and much newer, nuclear plants.

Skip Bowman, a retired nuclear Navy admiral, now heads the NEI, the industry’s Washington lobby. (Is it possible to run the NEI without having been a nuclear Navy veteran?) Bowman said in a written state-ment, “We believe this project will mark the beginning of nuclear energy’s rejuvenation in the United States.” He added the latest talking point of nuclear generation advo-cates: Nuclear power plants “supply more than 70% of all U.S. electricity that comes

from sources that do not emit greenhouse gases or any of the pollutants covered by the Clean Air Act.” However, nukes provide only about 20% of U.S. electricity genera-tion. Coal is still king, and likely to remain so for a long time.

Bucking the trendThe record shows that no nuclear plants or-dered in the U.S. after 1974 got built and that there were no new plant orders prior to March 1979, the time of the TMI meltdown. That was probably a function of economics: The U.S. entered at prolonged period of “stagfla-tion,” a combination of low economic growth and high inflation, in the early 1970s. New nukes went into slow-motion death, long before anti-nuke protesters stared marching and complaining. By the late 1970s, nuclear plant builders were taking out construction loans with interest rates in excess of 20% per year in order to finish their plants.

Nor did the U.S. fleet of nuclear reactors have a good operational record. In 1985, un-der intense political pressure from Congress and the NRC, TVA voluntarily shut down its entire nuclear fleet. In part because TVA was a federal agency and easily subjected to scru-tiny, TVA’s plants became the poster fleet for poor nuclear performance and a casual atti-tude toward safety.

By 1985 new orders had dried up. U.S. plants ran at low levels of reliability and capacity. Operation and maintenance costs were high. The credibility of the nuclear in-dustry was in the radioactive toilet.

That soon changed—under the leadership of Duke Power’s charismatic CEO, the late Bill Lee—following the 1986 Chernobyl nuclear power plant explosion in Ukraine. The industry dedicated itself to improved performance and safety. Under Lee’s prod-ding, the industry reversed its course, pledg-ing productivity and quality performance at its plants and creating industry institutions to ensure quality.

Over the next decade, the industry de-livered. Plant capacity factors increased significantly; scrams (involuntary reactor shutdowns) decreased. The nation’s nuclear fleet became a stellar performer.

That industry reversal led directly to the restart of Browns Ferry Unit 1, as the TVA board accepted the internal criticism and made its decision to restart the long-idled plant and to meet and exceed the industry’s new goals for quality and safety.

The result: another rebirth of Browns Ferry Unit 1. Call it “Phoenix.” F. Scott Fitzgerald was wrong when he said, “There are no second acts in American lives.” Browns Ferry Unit 1 is in its third act, and is looking spry. ■


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TOP PLANTS

Comanche Peak Steam Electric Station,Glen Rose, TexasOwner/operator: LuminantA Luminant-Bechtel team completed replacement of four steam generators

and the reactor vessel head—plus almost 200 other work packages—in a short, 55-day outage at Comanche Peak Unit 1. Matching or exceeding this schedule will become the goal for those who follow.

By Dr. Robert Peltier, PE

Comanche Peak, Luminant’s (formerly TXU) only nuclear plant, has two 1,150-MW pressurized water reactors

(PWRs) that went into service in April 1990 and April 1993, respectively. Bechtel Power Corp., working with Luminant, completed a modernization project on Comanche Peak Unit 1 in April 2007 that shattered the record

for fastest replacement of aging components at a nuclear power plant.

Bechtel’s long experience with steam gen-erator (SG) replacements prepared it for per-haps its most ambitious project to date. As the prime contractor, Bechtel replaced four SGs and a reactor vessel head in Unit 1 dur-ing an outage that lasted just 55 days—eight

days less than the previous record for a PWR SG replacement outage alone and 10 days under the original aggressive goal set when the project was awarded to Bechtel in 2004.

It’s a small worldLogistical support for nuclear plants is not a U.S.-centric business these days, and the

1. Hold on tight. Riggers attach slings to one of the four steam generators being replaced inside Comanche Peak Unit 1’s containment structure. Courtesy: Bechtel

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world’s few nuclear-capable manufacturing facilities have plenty of business. Luminant made its purchase of new steam generators in Spain, transported them by barge to Hous-ton, and then delivered them to the plant by a specially equipped train. Train tracks to the plant were upgraded to handle the loads be-cause they had not been used since the plant was built. The new reactor vessel head, also fabricated in Spain, was outfitted with new control rod drives in Pennsylvania, trans-ported by barge to Houston, and then trucked to the site.

The upgraded design of the new steam generators required installation of rerouted main feedwater piping, along with new seis-mically designed hangers, snubbers, and whip restraints. Rerouted feedwater piping interfered with existing containment build-ing ventilation ductwork, so that ductwork also required rerouting and new seismically qualified hangers. The new steam genera-tors’ instrument tap locations required that new instrument tubing as well as new hang-ers be installed. The project work scope for the new reactor head also included providing new cabling, new cable trays, and a new air-handling unit with all new ductwork.

Open wideSpace is always at a premium in the design of a power plant, but it seems lack of ma-neuvering room for steam generator replace-ment is something every nuclear plant has in common. Comanche Peak is certainly no exception. Perhaps the biggest challenge fac-ing the project team was the lack of access to the existing steam generators, each of which measured about 70 feet long and 15 feet in diameter and weighed about 400 tons (Fig-ure 1). During original plant construction, the containment structure around the nuclear steam supply system was completed after the steam generators were installed—leaving no panels or hatches that could be used for re-moving and replacing the steam generators.

Lack of access meant the first order of business was to locate an appropriate spot for an opening in the containment wall large enough for SG removal and replacement. Given the configuration of the containment vessel, internal crane access, and equipment arrangement, the opening had to be posi-tioned approximately 100 feet straight up the wall and directly above the containment building’s only equipment hatch.

Sharing work space among multiple task crews tends to reduce productivity during an outage, but extensive planning and coordina-tion allowed the crews to open—and subse-quently close—the side of the containment structure without hindering the flow of tools and equipment through the equipment hatch.

Hatch actHydrodemolition was used to remove the concrete for the containment alternate ac-cess, or opening, in the containment building (Figure 2). Hydrodemolition uses a water jet at 20,000 psi flowing at 300 gpm through four 3/8-inch rotating nozzles to surgically slice through the reinforced concrete. The robotically controlled water jet made short work of the concrete demolition. Workers manually marked, cut, and dressed each layer of rebar when exposed by the water jet and then removed 400-pound sections using ropes, pulleys, and muscle.

Tanker trucks brought in about 1.5 million gallons of water for the 12 diesel-powered 475-hp pumps that fed high-pressure water to the water jet. The wastewater was collected and properly disposed of as specified in the various permits that were required. Luminant properly elected to import the water for the water jet rather than siphon water from Squaw Creek Reservoir, which provides cooling wa-ter for the plant. Renovating a nuclear plant is one thing, but messing with the best bass fishing in the area is quite another.

Lift and shiftThe team’s next challenge was to devise an outside lift system (OLS) to raise the steam generators more than 100 feet into the air— by far the tallest OLS ever used for replacing a nuclear steam generator (Figure 3). Their difficulty was compounded by the presence of safety-related gear located un-der the OLS. A belt and suspender approach

3. Out with the old. An old steam generator exiting the containment building. Courtesy: Bechtel

2. Good housekeeping. Exposed rein-forcing bars and a clean concrete cut are all that’s left after hydrodemolition of a contain-ment alternate access. Courtesy: Bechtel



TOP PLANTS

was used that rigidly attached the OLS di-rectly to the containment wall rather than leaving it freestanding. The OLS was then tested with concrete block weights total-ing 500 tons—10% above the weight of the largest lift—to ensure that the assembly met code requirements.

Six Kevlar slings were used during a SG lift to prevent components from falling in the unlikely event that a tornado might strike at an inopportune time. A strand jack system was also used instead of the traditional chain jack used by Bechtel on all of its previous SG replacement projects. The advantage: The strand jack cut the transport time from the ground to the opening from nearly six hours to under two (Figure 4).

Big-league challengesThe biggest problem encountered during the project occurred on the first day of the out-age, February 24, when north-central Texas experienced its worst dust storm in more than 20 years. Sustained winds reaching more than 50 miles per hour darkened the sky,

and vapor pouring from the hydrodemolition equipment created a surreal scene. Almost all of the project’s equipment, including cranes and man lifts, had to be secured for the day. The only equipment qualified to operate that first day were the OLS and the hydrodemoli-tion robots.

Staffing with qualified tradesmen and technicians is always a challenge these days. More than 1,300 workers were required to perform the tasks associated with replacing the steam generators and the reactor pressure vessel head. Some 900 craft workers were hired either directly or through specialty subcontractors to complete the work. Dur-ing a typical nuclear plant outage, subcon-tractors usually handle cutting, machining, and welding of coolant piping; cutting and welding the liner plate; and insulation work. Approximately one-third of the outage work scope was originally assigned to permanent staff but was later shifted to subcontractors or new hires to the plant staff.

A tight and specialized job market re-quires creative methods to recruit and retain

the number of qualified craftsmen required to complete a plant outage on time. One approach was to allow workers to custom-ize their working hours as long as the 24/7 schedule was fully staffed at all times. A week before the outage started, the project switched to two, 12-hour shifts, giving work-ers time to acclimate to the rigorous outage schedule and providing an opportunity to sort out other logistical problems that occur dur-ing shift change, such as parking and badge checkout. Every worker was given one day off in seven, even though the outage sched-ule was 24/7.

Luminant closed Unit 1’s breaker on April 20, 2007, completing its record-breaking SG replacement project in just 55 days—a full 10 days fewer than the original plan called for. Of equal importance, the team completed the million-man-hour outage with no lost-time accidents while never ex-ceeding the 72-hour-per-week work sched-ule rule per employee. This sustained level of superior performance makes Comanche Peak a POWER Top Plant for 2007. ■

4. And in with the new. A new 400-ton steam generator begins the long trip to its cubicle inside the containment building. Courtesy: Bechtel

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TOP PLANTS

Fermi 2 Power Plant,Newport, MichiganOwner: DTE EnergyOperator: Detroit Edison

Detroit Edison teamed with Washington Group International to complete a first-of-its-kind nuclear retrofit project: replacing two moisture separa-tor reheaters during a single 35-day outage with a perfect safety record. POWER recognizes this significant accomplishment by naming Fermi 2 Power Plant a 2007 Top Plant.


The 1,150-MW Fermi 2 Power Plant, located on the shore of Lake Erie, con-sists of a single operating unit based

on the GE boiling water reactor design. The plant entered commercial service in January 1988, making it one of the last nuclear power plants to enter service in the U.S.

Fermi 2 may be young when compared with the other 103 U.S. nuclear plants, but age is relative; upgrades and renovations of operating plants to extend their lives have become the norm. In the case of Fermi 2, during the system analysis conducted as part of the plant’s recent power uprate evaluation, DTE Energy concluded that the plant required upgraded moisture separator reheaters (MSRs). Sounds simple on paper, but removing two 300-ton, 115-foot-long vessels in one piece and replacing them

with new MSRs is much more difficult in practice. In fact, it had never been done.

Long-term teamsThat Fermi 2would take on this challenge is a testament to a strong partnership. Washing-ton Group International has been providing nuclear support services through an alliance with DTE Energy for more than 15 years. The alliance provides DTE Energy with engineer-ing expertise and construction resources for major capital improvement projects; in re-turn, Washington Group receives incentives for developing unique design solutions that reduce construction costs and for delivering other value enhancements for plant operating improvements.

Scott Reeder, vice president-DTE Alli-ance for Washington Group, outlined the

scope of the arrangement: “Our contract under the alliance ties our financial success to the successful operation of the plant. As a result, our employees have continually dem-onstrated exceptional ownership of the Fer-mi plant’s performance results and, together with the employees of Detroit Edison, have demonstrated exceptional teamwork. The planning and execution of the MSR replace-ment project are evidence of this effective teamwork.”

A team consisting of representatives of the Fermi 2 staff and Washington Group was formed to manage the MSR replacement project upon its approval in January 2003. Pre-outage work at the plant began in Sep-tember 2005. The MSRs arrived on site in December 2005 (Figure 1) and were lifted to the turbine deck elevation by a heavy-lift

1. Oversize load. A new moisture separator reheater (MSR) arrived at the project site during freezing winter temperatures. It spanned two rail cars. Courtesy: Dave Mitchell, DTE Energy photographic services

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TOP PLANTS

tower that spanned the railroad tracks (Fig-ure 2). They then were transferred to the plant by overhead bridge cranes and moved to in-plant staging locations (Figure 3). Out-age work began on March 25, 2006, and was completed on May 2. The MSR project was a part of a large refueling outage during which Washington Group undertook a number of other challenging projects.

Weather conditions also presented a chal-lenge. Construction of the heavy lift tower and movement of the vessels occurred in un-usually cold and windy conditions, with tem-peratures in the single digits and the wind chill well below zero.

Create a new critical pathThe MSR separates moisture from high-pres-sure turbine exhaust and reheats the steam for the low-pressure turbine. At Fermi 2 the MSRs are located deep within a concrete shielding structure and are highly integrated with the plant’s piping network. That meant the team’s first order of business during the planning process was to determine how the old MSRs would be removed and the new ones shoehorned into place.

The traditional approach to extracting and replacing original equipment MSR vessels requires extensive removal of plant equip-ment and structures and an extended plant

3. Bird’s eye view. The turbine deck with the old moisture separator reheater (far right) and the new MSRs on each side of the generator. Courtesy: Dave Mitchell, DTE Energy photographic services

2. Heavy hitter. One of the two new MSRs being lifted to the temporary construction access panel and onto the turbine deck for staging. Courtesy: Dave Mitchell, DTE Energy photographic services



TOP PLANTS

outage—not an option the team would con-sider. The standard approach—and the one used during original plant construction—was to install each of the MSRs in two half-sec-tions, join the two sections by welding, and then install piping to fit. The team was sure a faster and cheaper procedure was possible.

However, in considering its options, the team realized it was time- and cost-prohibi-tive to remove existing piping and that the existing MSRs were housed inside reinforced concrete structures. The project was further complicated by the fact that these compo-nents were within the radiological-controlled boundary of the plant and thus inaccessible when the plant was operating. Finally, the di-mensions of the access area constrained the size of the new MSR. Tolerances were tight no matter which option was considered.

A little outside-the-concrete-box think-ing led to a unique and previously untested one-piece installation approach that was the team’s best opportunity to stay within its 35-day outage window. The plan also would save over $10 million in replacement power costs—the penalty for extending the outage, as was originally thought necessary.

Executing the plan, however, required the team to make a series of carefully choreo-graphed moves: move the MSRs from the fabrication facility in Oklahoma to the plant

site in Michigan, move these large compo-nents within the plant with access clearances of less than 2 inches (Figure 4), and then move the vessels to their final resting place within a 1/8-inch tolerance.

Virtual toolboxThe plan was innovative and certainly cost-effective, but the obstacles to success were formidable. The team required months of painstaking planning for every step of the project. For example:

■ First, the as-built status of existing plant equipment was meticulously mapped us-ing laser surveying technology.

■ That data was then translated into a 3-D design software package to enable the team to plan vessel movements within the allowable tolerances.

■ A virtual construction plan was developed with 3-D animation that simulated the heavy rigging path.

■ Next, design data and laser surveying tools were used to determine the exact dimensions required for the new vessels, including nozzle locations for piping up to 48 inches in diameter. The same virtual tools were used to confirm that the ves-sels could be maneuvered around existing plant equipment.

Finally, the team was convinced that a one-piece replacement approach was, in fact, possible.

The outage began with removal of the old vessels, which required cutting and ma-chining dozens of piping connections and removing structural platforms. The vessels were then jacked from their foundations and removed from their cubicles by two rail and hydraulic slide systems.

Close tolerancesInstallation of the new vessels required a full array of specialized equipment not normally encountered during a typical plant outage. For example, a special rail car was adapted to move the new vessels from Oklahoma to Michigan; a modular lift tower and integrat-ed slide system was designed and erected at the site to move the new vessels from the rail car up to and inside of the power plant; and a unique cantilever lifting beam was used to remove large concrete wall sections to pro-vide access for the new vessels. In addition, a specially engineered rigging path addressed the available 2-inch clearance and the need to lift the new components over the top of the generator.

Once the MSRs were inside the plant, the same hydraulic slide system used to remove

4. Tight squeeze. A new MSR begins its trek through the reinforced concrete wall with only 2 inches of clearance. Courtesy: Dave Mitchell, DTE Energy photographic services


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TOP PLANTS

the old vessels was used to ease the new ones into their cubicles to the exact location re-quired. The vessels were a perfect fit with the existing plant piping, and the 800 pipe welds were completed without incident (Fig-ure 5). Structural platforms were modified or replaced, and instrumentation and pipe insu-lation was installed. Plant shielding was then restored. Finally, the construction opening was repaired.

A tight team“Washington Group is a valuable partner at our Fermi plant,” said Douglas Gipson, who is recently retired but was executive vice president and chief nuclear officer for Detroit Edison during the project. “The core values of our two organizations are well aligned. The Washington Group site team has delivered best-in-class safety results and has demonstrated outstanding owner-ship of our business results. Together we have employed exceptional teamwork in support of the plant.”

During the outage Washington Group employed more than 950 craft and staff workers. The MSR project was completed with no lost-time and no OSHA recordable injuries. This is just about the only time a

score of 0.0 means you are a winner. That’s a safety record any contractor or plant man-ager would envy.

This project demonstrated that excep-

tional planning and teamwork, plus a little innovation when challenged with a first-of-its-kind project, will achieve best-in-class results. Kudos to the entire project team for

5. Perfect zero. The MSR project was completed early and with a perfect safety record. Courtesy: Dave Mitchell, DTE Energy photographic services

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TOP PLANTS

Fort Calhoun Nuclear Generating Station,Omaha, NebraskaOwner/operator: Omaha Public Power DistrictJust under a year ago, Omaha Public Power District completed perhaps the

most complex nuclear power plant renovation in the history of the in-dustry in a scant 85 days—five fewer days than the original plan called for. POWER recognizes Fort Calhoun Nuclear Generating Station as a Top Plant for packing more work into one outage than was thought possible, and then executing the plan ahead of schedule and below budget.


The nuclear industry consistently re-duced its plant outage durations over the past decade to the point where a 30-

day refueling outage now is considered the norm. Enhanced outage planning skills were put to the test when Omaha Public Power

District’s (OPPD) Fort Calhoun Nuclear Generating Plant embarked on perhaps the most complex nuclear renovation project in the history of the industry.

Located on the shore of the Missouri River, about 20 miles north of Omaha, Fort Calhoun has a single generating unit with a capacity of 478 MW. The plant, based on the

Combustion Engineering pressurized water reactor (PWR) design, first went on-line on August 9, 1973. The plant’s operating license was recently renewed for another 20 years (through 2033), although OPPD understood that many upgrades would be required to en-

sure safe functioning of the plant’s systems over the next 25-plus years.

Planning for Fort Calhoun’s 25th refuel-ing outage and replacement project began in the spring of 2006 with schedule reviews conducted with all the contractors and sta-tion personnel. Bechtel Power, with more than 30 nuclear renovation projects under

its belt, was engaged by OPPD to manage the project, which included more than 5,000 individual scheduled activities. Work was scheduled 24/7, so contingency plans and materials were developed for all major work packages to ensure their success.

Past projects were studied, especially those that had entailed two replacement outages, in an effort to identify the best practices that typically make the second replacement more efficient than the first. Both formal and infor-mal team-building sessions were conducted to fully integrate all the contractors and station personnel. To help unite the various stake-holders into a single, cohesive team, OPPD’s project slogan was “One Team, One Goal.”

Big project, big challenges The scope of work that was completed reads much like a complete plant equipment list. Inside the containment building the plant’s two steam generators, reactor vessel head, and coolant system pressurizer were re-placed. It was the first time all those compo-nents were replaced during a single outage. All were manufactured in Japan and sent by barge to the project site (Figure 1). (The main condenser and moisture separators had been replaced during a 2005 outage in preparation for this outage.)

The team also installed upgraded “rapid fueling” features, including a cable bridge, and performed asbestos abatement on the steam generators and pressurizer. Outside the containment building, the plant’s main sta-tion transformer and low-pressure turbines were replaced. In addition to routine main-tenance activities planned for every outage,

1. Ocean voyager. The new steam generators, pressurizer, and reactor vessel head were manufactured by Mitsubishi Heavy Industries and moved by barge to Fort Calhoun from Japan. Courtesy: Bechtel Power

The industry would do well to examine Fort Calhoun’s successful outage plan as a potential template for the future.

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TOP PLANTS

one-third of the fuel assemblies in the reactor core were replaced.

The project team encountered many challenges, as would be expected with a project of this magnitude. One of the more interesting was making the penetration into the containment building. As is typically the case on nuclear renovation projects, it was necessary at Fort Calhoun to cut a hole high in the side of the containment build-ing so that crews could remove and replace components. In the case of Fort Calhoun, the containment building had been installed at the end of original plant construction, effectively sealing in the components and leaving only a small equipment hatch for maintenance.

One challenge faced by Bechtel was that this containment structure is the only one in the U.S. with post-tensioned tendons ar-ranged in four layers using a helical pattern, with the tendons running in a curved diago-nal from top to bottom. To cut the 15-foot-diameter hole in the 4-foot-thick reinforced concrete wall, Bechtel had to remove (and subsequently replace) 68 tendons and deten-sion an additional 40 tendons—much higher numbers than the company had encountered on other post-tensioned containment struc-tures. The crew cut the hole in the shape of a hexagon (Figure 2) to minimize the number of tendons severed.

2. Make a carefully designed hole. Access through the containment vessel required workers to jackhammer concrete and cut rebar to prepare the hexagonal opening. Courtesy: Bechtel Power

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Ups and downsInside the containment, the project team faced more tests. The polar crane did not have the capacity to lift the steam genera-tors, and the spacing of the crane girders combined with the limited height inside the containment made it impractical to install a temporary lifting device on top of the crane girders. Instead, the team had to use a self-erecting gantry system that traveled on rails from one side of the containment to the other to lift the steam generators (Figure 3). It was the first time this method had been used on a steam generator replacement in the U.S. In addition, the steam generators and pressur-izer were covered with asbestos insulation, so OPPD had to remove the asbestos before the components could be removed.

All these circumstances—added to the significant number of pipe welds required to reconnect the systems, post-weld heat treat-ments, nondestructive examinations, and hundreds of support tasks such as design-ing scaffolding and temporary systems for power and air—made this outage the most challenging ever undertaken.

The project staffing plan was a key ele-ment in the project’s success. More than 650 OPPD employees were supplemented by more than 1,800 contract employees. OPPD staff developed “outage success teams” to handle contractor needs, from obtaining parking permits to issuing badges and safety equipment and completing initial contractor training. In previous outages, running con-tract employees through the indoctrination program had taken about 50 hours. During this outage it took only 32 hours.

Industry lessonsThe lessons learned from OPPD’s renova-tion project have far-reaching consequences for the next generation of nuclear plants. We now know that multiple major pieces of equipment can be placed in the containment structure in very short order and that the work can be controlled to meet a defined schedule and budget—assuming that project manag-ers commit to an equally detailed level of outage planning. The industry would do well to examine Fort Calhoun’s successful outage plan as a potential template for the future, when new construction schedules will need to be significantly shortened if new projects are ever to get off the drawing board.

OPPD’s rigorous planning paid off. In ad-dition to accomplishing the most challeng-ing outage in the industry, the work at Fort Calhoun was done safely with no lost-time accidents and came in some $40 million be-low the $417 million OPPD had budgeted. The project was completed on December 3, 2006—five days early. ■

3a. High-wire act. The new steam generator was raised 80 feet into the air, at the rate of 1 inch per minute, before being slid into the containment building. Courtesy: Bechtel Power

3b. Tight squeeze. The steam generator was winched into the containment building. Courtesy: Bechtel Power

3c. Hold on tight. The new steam generator was then rigged by workers and lowered into place. Courtesy: Bechtel Power


KEY QUESTION FOR THE FUTURE

Which nuclear fuel vendor is committed tozero tolerance for fuel failures?

AREVA — through our Zero Tolerance for Failure culture.AREVA is committed to delivering reliable, failure-free fuel performance. We continue to invest in equipment, design, and process changes to improve fuel performance and are actively engaged in industry efforts to reach the INPO goal of zero fuel failures in-core by 2010. Our global manufacturing centers of excellence feature the best equipment and processes available for the manufacture of PWR & BWR nuclear fuel. And it’s all driven by the industry’s most responsive personnel. www.us.areva.com

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NUCLEAR PLANTS MAP

Nuclear power plants in the United States

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NUCLEAR PLANTS MAP

Nuclear plantsby status

OperatingOperating withplanned additionsPlanned

Courtesy: Platts. Data source: Platts Energy Advantage and POWERmap. All rights reserved.

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PLANT INFRASTRUCTURE

Plantwide data networks leverage digital technology to the maxTo make the most of their digital devices and enable the sharing of data by dif-

ferent departments, new and old plants alike need a reliable digital data infrastructure.

By Timothy E. Hurst, PE, Hurst Technologies

A lthough digital technology has per-vaded industrial and postindustrial so-cieties, power plants are not yet fully

reaping its benefits. Many individual process control systems have gone digital, and even nuclear plants are beginning to apply the technology in nonsafety-related systems, but most have not reaped the full benefits of an integrated network.

In power plants, digital systems and net-works dominate, or are common in, the func-tional areas of communications, security, operator support, and environmental health and safety. However, for the most part these key pieces of plant infrastructure are used and managed by separate (and, often, dispa-rate) departments. Reason: The systems and networks were designed and implemented independently, with little if any thought to having them work in concert. Surprisingly, that’s often the case even for systems de-signed for new plants.

Case in point: At several U.S. nuclear plants, separate departments have deployed their own data networks throughout the fa-cility, at significant cost. At one plant, the health physics department and the operations group actually installed separate fiberoptic networks at about the same time. Each proj-ect cost over a million dollars.

Although fossil-fueled plants are not as prone to “silo disease,” inattention to inte-gration can lead to similar waste. More and more plant functions now can be performed better by digital systems, some with wire-

less capability. However, when different departments act unilaterally to satisfy their functionality needs, the result is multiple, in-compatible networks.

Most designers of new fossil-fueled plants have come to realize that siloed functions and piecemeal integration are short-sighted tactics that produce islands of automation, which cannot deliver all of the benefits that

digital technology offers. Segregating func-tionalities also works counter to a key goal of plant design: ensuring that data systems are robust, flexible, expandable, and upgradable well into the future.

It’s high time for the power generation industry to recognize that digital control and communications systems deserve to be linked by a plantwide data network (PDN). The PDN’s role is similar to that of the plant’s electrical distribution system: It provides the backbone and protocols to support all digital systems within the plant (and beyond, if it is part of a fleet). Just as you wouldn’t entrust your electrical buses to the corporate IT de-partment (because—if for no other reason—real-time processing isn’t IT’s strength), the PDN should be designed and managed as a plant system, not just as another tentacle of the corporate IT network.

In addition to process control (distrib-uted control systems, programmable logic controllers, etc.) and plant communications (public address, radios, cell phones, pagers, etc.), other functions that can benefit from linking to the PDN backbone include:

■ Process monitoring (vibration and tem-perature sensors, chemical monitors, pre-dictive analytics and diagnostic systems).

■ Operator support (maintenance manage-ment systems, logs of shifts and rounds).

■ Plant security (closed-circuit video cam-eras, access-control and personnel track-ing systems).

■ Supplemental monitoring/testing (nuclear dosimetery, portable radiation monitors, wireless sensors).

It’s the network!To get your mental arms around the concept of a PDN, stop thinking about traditional process control techniques and start think-ing about how other industries, such as tele-communications, use networks. The Verizon television commercial with the geeky guy in big black glasses and his crowd of network specialists following the customer around is an apt visual.

A high-speed PDN can move critical in-formation into and out of digital systems in near-real time and onto the screens of the operators and engineers able to maximize its utility. Though the capabilities of such net-works were originally designed to meet the needs of telecommunication carriers, they have since expanded considerably. As the major computer networking companies like Cisco Systems and Hewlett-Packard have upgraded the speed and refined the practical implementation of such systems for indus-trial applications, suppliers of process con-trol and plant distributed control systems to the power industry have been moving in the same direction.

The basic foundation of a PDN is physi-cal: its fiberoptic backbone (commonly called a cable plant). Higher in the hierarchy are multiple layers of physical and logical networks. The physical networks embody actual cable and wire and intelligent network switches, while the functionality of the logi-cal networks is defined by the programming of switches to effect specific types of data transfers at the right time.

In a telecom network, cell phone signals

The PDN’s role is similar to that of the plant’s electrical distribution system: It provides the backbone and protocols to support all digital systems within the plant (and beyond, if it is part of a fleet).

054 PlantInfra.indd 54054 PlantInfra.indd 54 11/5/07 4:22:34 PM11/5/07 4:22:34 PM


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jump on and off the hard-wired landline net-work as necessary. Similarly, a PDN should provide connectivity for wired devices, wireless devices and communications, and enough bandwidth for expanded capabilities in the future.

Nuclear PDNAlthough the safety systems at a U.S. nuclear plant probably won’t be linked by a PDN any time soon, designers of the nonsafety sys-tems are already taking full advantage of the technology. The figure shows a typical PDN architecture that segregates a control net-work, a performance network, and a support network (all examples of physical networks) but integrates all three via “core” switches to allow plantwide sharing of the data and func-tionality of all connected devices.

The topology shown is known as an “in-verted tree,” with the core switches serving as the trunk and the zone switches providing the limbs extending throughout a plant. Core switches are fed by redundant fail-safe pow-

er supplies, typically instrumentation-related power sources. Zone switches generally re-quire only one power supply, but they also can also be dual-powered if necessary. Com-ponents considered “mission critical” are powered by two independent supplies. Each of the three networks is itself fully redundant, with dual fiberoptic cables running between its core switches and zone switches.

Usually, devices on the control network support the real-time operation of the plant and thus are considered critical. Devices on the other two networks are deemed less im-portant. The performance network typically plays two roles: keeping track of long-term plant performance and handling monitor-ing of less-critical equipment. The support network provides two important, but less-time-critical, functions: plantwide commu-nications and integration of all the plant’s diagnostic and maintenance-related systems.

The figure illustrates only one possible PDN topology. Other architectures may be better suited to the layout of a specific plant

and/or the extent of its wireless networks. They include the STAR, point-to-point, and mesh configurations, each of which has ad-vantages and disadvantages. The PDN repre-sentation shown in the figure was included in a recent utility application for a combined construction and operating license (COL) for a new nuclear unit.

Diagnostic capabilities are inherent in modern digital networks because people and machines are increasingly dependent on the data they deliver. As traffic increases, so does the importance of availability and maintain-ing bandwidth. PDNs that use high-band-width fiberoptic cables and modular network switches are the most reliable, as well as the most scalable to meet expanded needs for data and voice (and video) in the future.

New plant to old: Can we talk?A presentation at this June’s annual ISA/EPRI Power Industry Symposium provided a peek at the promising future of PDNs at fossil-fueled plants. It describes how Lower

Desktop PCsDesktop PCsCorporate IT

Firewall(s)

Support network

Control network

Performance network

Plant site networkFirewall

Corporatenetwork

Coreswitches

Zone switches

Zone switches

Zone switches

Coreswitches

Coreswitches

Plantsystem

Video systems(O&M, health physics)

Printers

Printers

Communicationsystems

(public address, phone, maint.)

Maintenanceworkstations Process

informationservers

Wirelesscommunication

(cell, PDA, radio)(O&M, health physics)

Networkmonitoring

system

Process and equipmentmonitoring systems

Long-term historian(s)’plant data repository

Gateways(computer system

and digital equipment)Emergencyresponsefacilities

Engineeringworkstation

Controlprocessors andI/O general and

dedicated controlprocessors (CP) and I/O

Feedwaterheater levelcontrol CP

TransmittersValves

Switchgear

Fieldbus

Control roomprinters Operator

workstationsPanel-

mountedoperator

workstations

Supplementalcontrol room

displays

Can you hear me now? A layered plantwide data network for wireless communications and sharing of equipment control and perfor-mance data. Source: Hurst Technologies




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Colorado River Authority (LCRA) integrat-ed the digital control and communications infrastructures of a state-of-the-art plant it had recently acquired with those of a nearby power plant it had owned and operated for 40 years.

Three years after acquiring the two-year-old Lost Pines Power Park in 2003, LCRA in-tegrated its facilities (and staff) with those of Sim Gideon Power Plant, whose three units were commissioned between 1965 and 1972 (see POWER, June 2007, p. 22). Eventually, LCRA would like the two plants to share the same communications infrastructure, so the combined staff can conduct day-to-day op-erations at both sites.

The first step toward that goal was the in-stallation of a layered WiMax/WiFi wireless communications infrastructure covering both plants. The protocols were chosen largely to “future-proof” the system against technol-ogy obsolescence. The system—developed jointly by the asset performance manage-ment specialist Invensys Process Systems (www.ips.invensys.com) and the industrial wireless networking specialist Apprion Inc. (www.apprion.com)—is reportedly the first of its kind deployed at a large power station.

The system has the following features:

■ A 360-degree WiMax “umbrella” plant-wide wireless network accessible by the entire site. It is powered by wide- and medium-bandwidth transceivers, logical integration terminals (which physically connect to the existing fiber IT systems at both plants), and WiFi access points.

■ A wireless plant intercom system with “push to talk” capabilities. It integrates with a PBX (private branch exchange) us-ing VoIP (voice over Internet protocol).

■ The use of wireless communication badges and noise-cancelling headsets by staffers.

■ WiMax connectivity to a remote fuel oil tank farm.

Although the initial deployment simply focused on providing a common communica-tions infrastructure for the staffs of two plants of very different vintage, LCRA’s plans for future use of the wireless PDN are what make it noteworthy. The following functionalities are currently envisioned: noncritical closed-loop level controls and alarming for auxiliary plant equipment, equipment health and con-dition monitoring, and remote video surveil-lance. Others will undoubtedly follow, after the system demonstrates what it can do best.

Only the beginningWith digital systems now common in new and old power plants alike, the need to collect and communicate more information reliably continues to grow. One way to make a plant more competitive is to seek new and better ways to improve the performance of equip-ment and the productivity of personnel.

Recent history makes clear that digital controls and wireless communication are quite capable of helping plant owners achieve both goals. If they are to support the digital systems, digital networks must no longer be treated as afterthoughts by utility manage-ment; they should be designed and managed with the same care that other plant systems receive because they are equally important. Although digital networks are new by power industry standards, they are maturing quickly and now command more attention during the design and operation of both fossil-fueled and nuclear power plants. ■

—Timothy E. Hurst, PE ([email protected]) is president of Hurst Technologies

(www.hcinc.com), a consulting engineer-ing firm specializing in instrumentation

and control systems for nuclear and fossil-fueled power stations. He also is a

POWER contributing editor.

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NUCLEAR UPGRADES

Upgrade your BWR recirc pumps with adjustable-speed drivesThe U.S. is home to more than 30 boiling water reactors of BWR-3 through -6

vintage. At one time or another, all have experienced obsolescence, reli-ability, or control problems with their reactor recirculation flow control systems and components. Temporary down-powers are often required for corrective maintenance. Exelon Nuclear plans to begin upgrading the recirculation pump motor drives at its BWRs in the spring of 2009. The upgrade project’s technical design and business case were developed in great detail before the project was approved. This article presents the results of all key internal analyses.

By James W. Morgan, Exelon Nuclear

Controlling the power output of a boil-ing water reactor (BWR)—such as Exelon Nuclear’s Quad Cities Unit 1

or 2 (Figure 1)—requires changing the reac-tivity of the core by repositioning the control rods and controlling coolant flow through the core.

For a given control rod line, increasing flow causes steam bubbles (“voids”) to be re-duced, which increases the amount of liquid water in the core. With more liquid available, more neutrons are slowed down (moderated) to a speed suitable for splitting fissile fuel. More fission means more thermal power. Decreasing flow through the core has the op-posite effect on power output.

When a BWR is operating on the so-called “100% rod line,” its power output can be varied from roughly 70% to 100% of maximum rating by varying the speed of the recirculation pumps or by throttling a flow control valve.

The BWRs of interest in the U.S.—the BWR-3 through -6 designs—have two re-circulation loops (Figure 2). Each loop has one pump whose flow is controlled by either of two systems: a motor-generator (M-G) set that uses large, medium-voltage induction motors to drive the recirc pumps or a flow-control valve design. Either system provides controllable recirculation flow through the reactor core.

The earlier (BWR-3 and BWR-4) designs use M-G sets. This control design allows variable adjustment of motor voltage and fre-quency and uses a voltage regulator to keep their ratio constant. The motor, operating at medium voltage, drives the generator through a fluid coupling that acts like a clutch. The speed and output of the generator rise and fall as the volume of fluid in the coupling is var-

Reactor building (secondary containment) Turbine building

Drywell(primary

containment)

Reactorcore

Recirculationpump

Torus

Jetpumps

Steam to turbine-generator

Feedwater

Controlrods

2. Gone fission. A simplified diagram of a typical BWR plant and the recirculation loops that control the thermal output of the reactor. The pumps’ flow controls were the subject of an extensive upgrade option analysis by Exelon Nuclear. Source: Exelon Nuclear

1. First in line. Exelon Nuclear’s Quad Cities Unit 1 will have its reactor recirculation flow control systems upgraded with electronic adjustable-speed drives in the spring of 2009. Cour-tesy: Exelon Nuclear

060 NucUp.indd 60060 NucUp.indd 60 11/5/07 4:52:39 PM11/5/07 4:52:39 PM



ied by changing the position of a scoop tube, or weir. As the generator’s output increases or decreases, the speed of the recirc pump follows suit. Figure 3 shows an M-G set from Quad Cities Nuclear Generating Station in Illinois.

The flow-control valve design is standard at the later BWR-5 and BWR-6 plants, which also use an M-G set to power the pump at low frequency (15 Hz) and low speed (25% of maximum). A direct connection of the pump motor to the medium-voltage source provides for a faster speed at line frequency (60 Hz). A modulating flow-control valve in the loop adjusts the recirculation flow as required.

High time to upgradeBoth control designs have exhibited prob-lems that have resulted in excessive main-tenance costs, generating inefficiencies, and enough loss of control to warrant a unit de-rate. Making matters worse, spare parts have become scarce, which has resulted in extend-ed outages for unplanned repairs.

Among the parts of both designs that have become troublesome are flywheels, scoop tubes, voltage regulators, and scoop tube positioners. Backups for those compo-nents (if available), as well as large inven-tories of M-G lubricating oils, fluid for the coupling, hydraulic fluid for control valve power units and shuttle valves, and genera-

tor brushes must be kept on the shelf. Spare parts for auxiliary lube oil, cooling water, and ventilating systems also must be kept on hand.

Within the reactor building, the primary piping and pump pressure boundaries are critical to safety, but the power and instru-mentation portions of the water recirculation systems are not. However, their fault toler-ance and obsolete components have caused reliability problems at several BWRs. Spe-cifically, the old electromechanical analog technology used to control the speed of re-circ pumps is vulnerable to hysteresis, sensi-tive to temperature, and prone to “hunting” due to mechanical dead bands and a limited range of output frequencies. Any of these conditions can reduce a unit’s capacity fac-tor, a key measure of its performance.

Cheaper by the dozenSolid-state static power converters—also known as variable-frequency drives or ad-justable-speed drives (ASDs)—represent the state-of-the-art technology suitable for replacing the M-G sets. Like M-Gs, ASDs generate a signal whose voltage and fre-quency are continuously adjustable at a constant ratio, but they do so with no mov-ing parts (with the exception of small pumps and fans for a closed-loop cooling water

3. Long in the tooth. A typical M-G set for controlling a BWR-3 recirculation pump. Courtesy: Exelon Nuclear

Exelon Nuclear’s U.S. BWR fleet. Source: Exelon Nuclear

Plant name Location Capacity (MW)

Clinton Nuclear Generating Station Illinois 1 x 1,043

Dresden Nuclear Power Plant Illinois 2 x 912

La Salle County Nuclear Generating Station Illinois 2 x 1,140

Limerick Nuclear Power Plant Pennsylvania 2 x 1,200

Oyster Creek Nuclear Generating Station New Jersey 1 x 656

Peach Bottom Nuclear Generating Station Pennsylvania 2 x 1,093

Quad Cities Nuclear Generating Station Illinois 2 x 870

NUCLEAR UPGRADES



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NUCLEAR UPGRADES

system). The beauty of this recirc pump up-grade option is that the recirc pumps, mo-tors, and motor cables should not require modification.

Exelon Nuclear’s design philosophy is “Design Once, Install Many.” Accordingly, a key goal of the process of choosing a re-placement for the M-Gs was to select an ASD system design and product compatible with similar medium-voltage applications across its fleet. Doing so would minimize costs by allowing the sharing of spare parts and O&M experience. Across Exelon Nu-clear’s fleet of 12 BWRs (see table), the design voltages of existing M-G sets, rat-ed from 5,770 hp to 8,900 hp, range from 4,160V to 6,900V.

Although the recirc pump speed control system is not critical to safety, it is essential to production and therefore requires high reliability and minimal points of single failure. Exelon Nuclear evaluated three ba-sic system design concepts, each of which assumed that a single-train ASD will have either a very low probability of failure or inherent redundancy:

■ Two ASDs with redundant power trains, one for each of the two recirculation pumps (Figure 4a).

■ Two primary ASDs with a swing drive that can pick up the load from one of the primary units in the event of a trip (Fig-ure 4b).

■ Two single-train ASDs (Figure 4c).

The basis of the redundant power train concept is that the two parallel power cell trains would share the recirculation pump’s electrical load. If a power cell in one of the trains were to fail, the remaining train would pick up the full load, satisfying the “minimal points of single failure” criterion. However, such a system was ruled out be-cause it would have been unique in the U.S. nuclear industry. Note also from Figure 4a that eight large circuit breakers or vacuum contactors would have to be added as part of the design, and they would consume a lot of floor space. The design has one upside: It would allow on-line maintenance of the power cells.

The swing-drive concept would require use of a complicated scheme to “swap over” to the swing ASD (Figure 4b, center) the pump driven by a failed primary ASD while it was coasting down. The speed lost by the affected pump would depend on how long it took to make the swap. During the design evaluations, it was suggested that it would take between 200 msec and 3 seconds, but that range was never verified by testing.

Like redundant power trains, the swing-

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a. Redundant power train drive concept

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Some designs may use redundant breakers

Existingbreaker

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Notes: NC = normally closed, NO = normally open. Cell bypass circuitry can maintain full operation of the drivesystem, with up to two power cells out of service. Bypassing additional cells would require de-rating.

NC NCNO NO

c. ASD with bypass feature concept

4. Choose your weapon. Three conceptual options for upgrading recirc pumps with adjustable-speed drives. Source: Exelon Nuclear



NUCLEAR UPGRADES

drive concept had never been implemented in a nuclear power plant. It had the same upside—allowing on-line power cell main-tenance—and a similar downside: A lot of plant floor space or a large power dis-tribution center would be required for the installation of three drives. However, the swing-drive configuration also was ruled out for a very good reason: Failure of any of the eight breakers in the system (six new and two existing) would cause the swap to fail.

The dual single-train ASD system (Fig-ure 4c), using solid-state power trains with a statistically low failure frequency, would be more reliable than the existing M-G set design. Its big downside is not allowing on-line power cell maintenance. However, such maintenance should not be needed if the cell’s mean time to recovery is reasonably short (one shift or less).

Even though the twin ASDs would be more efficient and require less preventive maintenance and consumables than an M-G set, engineers decided that the basic design was insufficiently robust. They then ad-dressed that shortcoming by insisting that the drives have a cell bypass feature to maintain their voltage output even if one or two power cells were to fail.

And the winner is . . . The design concept shown in Figure 4c was the final choice for its simplicity, relative compactness, and high reliability. The ASD selected was the Robicon Perfect Harmony, Model WCIII, medium-voltage (2,300V to 14,400V) drive from Siemens Automation and Drives (www.siemens.com/medium-voltage-converter). As specified, the drive’s patented power cell bypass feature allows full operation of the recirculation pump with one or two power cells failed and by-passed. The WCIII nomenclature signifies that the drive (Figure 5) is a water-cooled, third-generation unit.

The Perfect Harmony ASD is a modular unit with two inverters. One uses pulse-width modulation, a diode rectifier, and a DC filter inductor/link capacitor; the other is a con-ventional, multistep voltage source inverter. Insulated-gate bipolar transistors are the ac-tive components of inverter circuits.

Unlike other ASDs, this one does not require the use of input and output isola-tion transformers, input or output harmonic filters, dV/dt filters, isolation breakers, or power factor compensation. That’s because its integral transformer with phase-shifted secondaries provides 18-pulse or better in-put harmonic cancellation with an expected power factor of 0.97 under any operating conditions. One can expect the Robicon Per-

fect Harmony drive to be available between 99.99% and 99.999% of the time.

The cell bypass feature enables the ASD

to provide full power to the pump in the event of a power cell failure. When the con-trol system—a Model NxG II, also from

5. Compact recirc pump drive. The water-cooled Robicon Perfect Harmony medium-voltage adjustable-speed drive was chosen primarily for the high system reliability afforded by its cell bypass feature. The third-generation design integrates the NxG II control system, also from Siemens Automation and Drives. Source: Exelon Nuclear

Input cable cabinetInput transformer

Fuse/pre-charge/control cabinetPower cells Output cable cabinet Cooling system cabinet

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NUCLEAR UPGRADES

Siemens Automation and Drives—detects such a failure, it calculates the magnitude of the phase shift and voltage adjustment needed to keep the ASD’s reduced output balanced. The bypass circuit’s salient fea-ture is its overrating of the nominal design output voltage, which maintains the reduced but balanced output greater than the voltage required for 100% motor speed. The mo-tor current is momentarily removed during the calculation and adjustment process. By contrast, the motor speed is reduced by 10% but reapplied with the new balanced output within about 250 milliseconds.

This ASD has been used widely and suc-cessfully in the petrochemicals industry. One Perfect Harmony unit at a chemical plant operated continuously for five years without ever having to be derated. As men-tioned earlier, although the system of two single-train ASDs does not allow on-line maintenance of power cells, the need for

it should not be critical because one power cell failure will not result in a tripped or de-rated ASD.

Designed for reliabilityEach ASD in the final system design has re-dundant commutator-inverter NxG II proces-sors. Either processor can act as the primary or secondary controller because both can be configured with the ASD parameters, sys-tem control algorithms, and the controller “swapover” scheme.

Redundant supervisory controllers—Sie-mens S7-400H units—will interface the drive system to the existing reactor recir-culation flow control system (RRCS) at the plant to be upgraded. The controllers are fault-tolerant and self-diagnostic. Re-dundant power sources are required for all the control systems and control subsystems. Figure 6 illustrates a typical dual Profibus, fault-tolerant control system architecture

with redundant remote I/O suitable for such an application. An alternate design would provide dual network communications us-ing the existing RRCS. A third option would combine remote I/O and network commu-nications. It’s worth noting that these re-dundant control systems have no points of single failure.

Each ASD has a self-contained, closed-loop cooling water system. Redundant pumps and instrumentation make these sys-tems highly reliable. Other than the common cooling water piping, which has a very low probability of failure, the cooling system is single-point failure-proof.

Other design considerationsBesides reliability and the ability to adjust motor control voltage and frequency, the major considerations for upgrading the re-circ pump drive system at a particular BWR include available floor space, floor loading,

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Profibus DP

Ethernet TCP/IP Hardwired I/O

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6. Control connections. The ASD control architecture for a remote I/O system design with network communications. Source: Exelon Nuclear


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NUCLEAR UPGRADES

cable and raceway quantities, the ease of in-terfacing with existing plant systems, heat sink design parameters, and loading effects on ventilation systems and fire detection/suppression systems. If plant real estate is at a premium, a dedicated ASD outbuilding may be a viable option. The use of such a structure would minimize construction with-in an operating plant and, if it were strate-gically placed, could shorten needed cables and raceways.

Replacing existing M-G sets and their ancillary equipment presents several chal-lenges. If the outage scheduled to perform the work is long enough, and cranes and per-sonnel do not compete for laydown space, the old equipment can be removed and the new ASDs can be placed in the same gen-eral area. This would likely minimize needed quantities of new cable and raceway. It may be possible to do some of the installation work (but not tie-in or commissioning) be-fore the outage begins.

Special analyses requiredFor an ASD upgrade to a nuclear power plant, some special analyses are required to satisfy the U.S. Nuclear Regulatory Com-mission (NRC). For example, the plant owner must perform a reanalysis of licensed events to determine the effect of changing the motive sources of the recirculation pump motors from M-G sets to ASDs. The analysis must show that the effects are bounded by existing analyses; if they are not, the planned modification must be submitted to the NRC for approval prior to implementation. Exelon Nuclear anticipates that the reanalyses will show that the retrofitted systems are indeed bounded by existing analyses.

Following are some of the specific im-pacts of an ASD upgrade that would require an analysis/evaluation:

■ Unlike M-G sets, ASDs do not provide electrical inertia for pump/motor coast-down. So coastdowns will be quicker for some trip scenarios.

■ ASDs are not mechanically limited by the 25%/second fluid coupler, as M-G sets are. The effect of this freedom on tran-sient flow increases must be considered.

■ Because ASDs can deliver higher-fre-quency voltages than M-G sets do, over-frequency situations are a possibility (M-G sets use a mechanical stop to avoid them). Although software is typically used to limit ASD output frequencies, external frequency-sensing relays must be ready to step in if the program fails.

■ An ASD can apply braking action to a re-circ pump motor; an M-G set cannot. If an ASD malfunction triggers this braking ac-

tion, its negative effects should be limited to a pump trip and coastdown, or a pump seizure.

■ ASDs have motor reversing capabilities. Even the failure of an ASD that is not enabled may cause a motor reversal. Ac-cordingly, an ASD upgrade must include the installation of motor management re-lays (to trip the motors upon a phase re-versal) and the implementation of other motor protection parameters.

The M-G sets at earlier, BWR-3 and -4 plants operate over the same continuous fre-quency range (and, hence, over the same speed range) as the ASDs. However, the flow-con-trol valves at later, BWR-5 and -6 plants oper-ate (other than during transients) at only two speeds: 25% and 100%. Upgrading to ASDs will enable the recirc pump motor drives of those reactors to operate over the same con-tinuous range as their predecessors.

This change requires performing hydrau-lic analyses of recirculation flow sensing line vibrations and of dead-leg pressure oscilla-tions from side-branch harmonics (see p. 72 for more information on pressure-sensing is-sues) because the sensing lines in question are inside the reactor. Modifications to sens-ing line clamps/supports or dead legs may be required as well. The analyses and any mods should be done at least one outage prior to the outage for installing the ASD upgrade. Field surveys can provide valuable “as-built” input data for these analyses; if possible, they should be done at least two outages prior to the upgrade outage.

For fundamental guidance on the opera-tion, selection, and application of medium-voltage (2,400V to 13,800V) ASDs, refer to IEEE Standard 958-2003. Harmonics analy-sis and testing should be done in accordance with ANSI/IEEE 519: Recommended Prac-tices and Requirements for Harmonic Con-trol in Electrical Power Systems.

Finally, an ASD upgrade should be ac-companied by a torsional analysis, to identi-fy any harmful torques and vibrations on the shafts of all motors and drive equipment at all speeds under normal and abnormal con-ditions. This analysis usually is performed using a computer model containing criti-cal speed points, natural frequencies, mode shapes, steady-state operating torques over the entire speed range, oscillating component harmonics, transient torques, and stresses during acceleration and deceleration of the drive through its mechanical resonance fre-quency. Among the corrective actions that can alleviate or eliminate torsional problems are installing energy-absorbing couplings or oil lift bearings, and machining shafts to re-duce their stress levels.

Have other reactors upgraded to ASDs? The answer is yes. That’s important, because plants considering the same modification can benefit from lessons learned by the pioneers and from their operating and maintenance experience.

Specifically, Energy Northwest’s 1,157-MW Columbia Generating Station ret-rofitted load-commutated inverter-type ASDs for its recirculation pumps in the mid-1990s. Tennessee Valley Authority’s (TVA’s) Browns Ferry Nuclear (BFN) Plant also installed three Perfect Harmony Model WCII units (the predecessor of the WCIII) between 2003 and 2005 and has since ac-cumulated more than eight years of oper-ating experience on them. Siemens made about 50 changes to the WCII based on les-sons learned from the BFN installation by a TVA users’ group. Finally, Southern Nu-clear’s Plant Hatch and Progress Energy’s Brunswick Plant have purchased the Perfect Harmony WCIII drives and have begun de-signing them into systems scheduled for in-stallation in the spring of 2009.

Examine your business caseBecause the new ASDs are more efficient than M-G sets, they should reduce house loads. This reduction for Quad Cities Unit 1 is anticipated to be 2.5 MW. Although the expected improvement in system reliability from the upgrade is harder to quantify, it should be significant, as should the reduc-tion in maintenance costs. Fuel savings also should be realized because, unlike M-G sets, ASDs can deliver full flow at the end of the nuclear fuel cycle.

Exelon Nuclear has concluded that a proj-ect to upgrade from M-G sets or flow-con-trol valves to ASDs will deliver a positive net present value and a very attractive internal rate of return, with typical business case as-sumptions. How good would the economics be at your BWR? You’ll have to do your own analyses that take into account the particu-lars of your plant. But at Exelon Nuclear, the results of in-depth studies convinced corpo-rate management that adding ASDs at Quad Cities in the spring of 2009, and at the re-mainder of its BWR fleet in the future, is an excellent idea. ■

—James W. Morgan ([email protected]) is a principal engineer for instrumentation

and control with ILD Inc. (www.ildpower.com). On assignment

to Exelon Nuclear’s corporate engineering department, he is the

lead engineer responsible for Exelon’s fleetwide upgrade of reactor recircula-

tion pump flow control systems.



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NUCLEAR UPGRADES

Defined scope, experienced team essential to nuclear I&C upgrade projectsOver the past few years, U.S. nuclear power plants have begun replacing their

obsolete analog control systems with digital control systems. Many of these projects have been completed successfully, yielding a tidy return on investment in the form of increased generation. However, some have encountered difficulties, which resulted in cost overruns and schedule de-lays. This minority of projects may have eroded the industry’s confidence in digital upgrade projects, but a well-run project is still one of your best options for squeezing the last drop of performance out of your plant.

By Roy Raychaudhuri, Sargent & Lundy, and Doug Beach, Energy Northwest

The January 2007 issue of POWER included an article (“Tow nuclear power I&C out of the ‘digital ditch’ ”)

describing instrumentation and control (I&C) upgrade projects at nuclear power plants as “stalled” and “checkered, at best.” To be sure, some projects have experienced technical problems and may have missed their budget and/or schedule. But they are anomalies and are not indicative of a wide-spread problem in the nuclear industry, as the author suggests.

Fully recognizing that the article was ad-dressing unit-specific design and manage-ment issues, we would like to offer a few case studies of successful projects and invite others to do the same. In this way, we can together learn to capitalize on the real suc-cesses in the industry.

In general, a successful project begins at the highest management level at a plant with a definitive statement of the busi-ness objectives and a well-defined plan for procurement, design, testing, installation, training, and operation. It’s our position that properly organized and staffed I&C projects can be implemented successfully. This ar-ticle presents case studies of three success-ful upgrade projects at nuclear plants. Each case covers the scope, approach, and details of the project and explains why it should be considered a success (see box).

Case study #1: Turbine controls upgrade at Energy Northwest’s Columbia stationThe old digital electro-hydraulic (DEH) turbine control system at Columbia Gener-ating Station (Figure 1), a 1,250-MW boil-

ing water reactor (BWR), was obsolete and not single-failure-tolerant. Component and subsystem failures had resulted in unit trips, power reductions, load swings, and opera-

tion in manual control for extended periods of time.

To resolve these problems, Energy North-west replaced the old DEH control system

Defining successHow do we know that a nuclear con-trols upgrade project has been success-ful? Every project has specific standards that differ between plants. In baseball, a successful team is usually good at ex-ecuting the fundamentals. In the case of I&C upgrades, success derives from good management of project details. We be-lieve that any successful upgrade project needs to meet minimum quality standards and be completed within its budget and on time.

Meet minimum quality standards. Quality standards are defined by the project’s documented technical objec-tives that all stakeholders must approve. Problems will inevitably arise, but unless they are resolved, systems cannot oper-ate as designed. If systems don’t work as planned, a project isn’t meeting minimum quality standards.

Complete within budget. Generally, installation cost is the largest component of a project’s total cost and is also prone to escalation. Therefore, it is imperative that the plant owner scrutinize this area early in the process to allow total cost to be managed effectively. Among the cost-

management techniques that have proven effective are these two:

■ “Design to cost,” which requires devel-oping a target cost during a project’s conceptual stage and then checking and validating the feasibility of meet-ing that cost several times during the design phase.

■ Focusing on installation costs during the design phase, in order to minimize total project cost. For many complex projects, installation cost can be reduced by pro-viding more design details. However, providing more details incurs its own costs, making tradeoffs necessary.

Complete on time. Adhering to sched-ules—especially those for completing in-stallation and testing within the duration of the planned refueling outage—is criti-cal. Slippages adversely impact both the cost and quality of a project. Schedules must account for unforeseen delays in equipment deliveries and the time needed to resolve issues that inevitably are raised by factory acceptance and post-installa-tion tests.

068 NukeUp_Controls.indd 68068 NukeUp_Controls.indd 68 11/5/07 4:23:25 PM11/5/07 4:23:25 PM



NUCLEAR UPGRADES

with a new, state-of-the-art system that is single-fault-tolerant and can be repaired on-line. The new system employs redundant in-put signal devices, redundant digital signal processors, and redundant output devices. It also features improved control algorithms and start-up and shutdown control proce-dures, and provides additional information on turbine-generator performance to opera-tors and engineers.

On a fast track. A key objective of the replacement project was to complete it dur-ing a refueling outage scheduled to occur 13 months after the contract award to the control system vendor. Meeting such a tight schedule without compromising the quality of work was a major challenge.

Replacing the control system and related input/output (I/O) devices required making the following changes:

■ Replacing the five DEH cabinets in the main control room with four new cabinets containing the redundant control equip-ment and I/O, a new turbine overspeed protection circuit, and new digital syn-chronizing and load control equipment.

■ Replacing the switches, indicators, and recorders on the main control board with touchscreen displays.

■ Installing new turbine control system hardware and software on the existing op-erator training simulator.

■ Installing seven new speed sensors: three for speed control, three for overspeed pro-tection, and one spare.

■ Connecting the new turbine controls to the plant’s distributed control system (DCS) through a firewall.

Energy Northwest’s management team realized that executing such a large and complex project on such an aggressive time-line would require close coordination of all participants’ work. Accordingly, among the project management tools put to use were a single integrated schedule, an integrated project action tracking list, and a common weekly meeting for all organizations. The formation of a dedicated project team was followed by establishment of a formal divi-sion of work and a formal work sequence.

The controls vendor chosen was Inven-sys (www.invensys.com), which supplied its TMR (triple-modular redundant) Tricon tur-bomachinery control system for integrated turbine protection and reactor pressure con-trol. The Tricon TMR system also executes an all-new turbine trip control scheme whose inputs include digitally delivered measure-ments of lube oil parameters, thrust, vacuum, and overspeed. The Tricon system brings to-gether more than 600 critical monitoring and control system I/O points from the plant’s turbine and generator.

On this project, Sargent & Lundy (www.sargentlundy.com) provided a range of en-gineering services that included a conceptual study, specification development, bid evalu-ation, a plant modification package, proce-dural updates, installation and test support, and project management assistance.

Strategy. The project’s overall strategy was to perform as much pre-outage instal-lation work as possible within the confines of an operating plant. That work included the installation of conduits and cable pulls in areas accessible with the plant on-line. Work during the refueling outage included

the removal of existing DEH cabinets from the control room and installation of speed probes, thrust probes, pressure transmitters, and linear variable differential transformers (LVDTs). It also included installation of new cabinets in the control room and installation of operator workstations with touchscreens in the main control board and on the lead operator’s desk.

Formal test or validation procedures were developed for each phase of the project and successfully completed before moving on to the next phase. They included:

■ Factory acceptance tests of original equip-ment

■ Testing of software and touchscreens (performed on the plant simulator)

■ Modification and power ascension tests■ Site acceptance tests following installa-

tion of the complete system

Regarding the project’s speed of execu-tion, W. Scott Oxenford—vice president of technical services at Energy Northwest—noted that, “its most remarkable aspect was the timeline of design and implemen-tation. In March 2006 we issued the Lim-ited Notice to Proceed to Invensys and had our initial on-site kick-off meeting with all present. Only 10 months later, the system was installed in the simulator, ready to sup-port two cycles of operator training. Six months after that, the system was operating with precision.”

Through the use of sound project man-agement methods and tools, selection of the right project team, and remaining focused on the objectives, this complex digital up-

1. Death of DEH. Engineers at Energy Northwest’s Columbia Generating Station replaced the plant’s digital electro-hydraulic control sys-tem with a new, fully digital one that is single-fault-tolerant. Courtesy: Energy Northwest


http://www.invensys.com

http://www.sargentlundy.com

http://www.sargentlundy.com


NUCLEAR UPGRADES

grade project was successfully completed on an extremely tight schedule, during a planned outage.

Case study #2: Turbine and reactor pressure control upgrades at Exelon’s LaSalle County plantSince 1986, Exelon Nuclear’s 1,120-MW La-Salle County Generating Station (Figure 2) has experienced nine reactor scrams caused by single-point failures of its GE Mark I EHC turbine control system. The most re-cent scrams occurred in 1999 and 2001.

Coincidentally, in 2001, GE announced that it would stop making spare circuit boards for the Mark I and Mark II systems. The phase-out dovetailed with Exelon’s announcement that its internal and exter-nal support services personnel for Mark I Turbine Control System would retire within five years.

Upgrading to full-digital, triple-redundant controls at the La Salle County plant would help prevent future reactor scrams and solve other peripheral problems at the station as well. Exelon Nuclear’s strategy was to part-ner with GE Energy (www.gepower.com) to engineer a control solution once and ap-ply it across Exelon’s 12-reactor fleet of GE BWRs (see related story on p. 60).

Retrofit considerations. Triple redun-dancy, on-line maintainability, nuclear expe-rience, the availability of support services, the possibility of simulator integration, and low installation cost were the primary reasons be-hind Exelon’s selection of GE’s TMR Mark VI digital control system. Among the system’s

redundancies are triplicated field sensors and field wiring and duplicated processors, power supplies, and communication interfaces with plant systems. The Mark VI system facilitates on-line maintenance and diagnostic trouble-shooting. The maintainability extends to the front standard, where a mechanical trip finger was replaced with a redundant, two-out-of-three trip module assembly.

During replacement of the control system at LaSalle, existing field instrumentation cables also were replaced because they had been degraded by heat in the low-pressure heater bays. These cables connect to the main turbine’s control, stop, and bypass valves.

Additional operational flexibility and functionality were developed to address reactor cool-down, automated turbine pre-warming, improved valve testing with fewer plant transients at higher loads, and reduced system gain from vessel pressure control.

Clear responsibilities. One key to suc-cessful implementation of the project was a clearly defined commercial and technical scope agreement between Exelon and GE, which then partnered with Sargent & Lun-dy to acquire project design services. The commercial requirements document stated milestones, payment schedules, and specific remedies over both near and long terms. The technical scope agreement established the di-vision of responsibilities and accountability of the parties.

Pre-outage prep. Pre-outage work in-cluded modification of the plant’s simulator, factory acceptance testing, task planning and scheduling, training of plant personnel, cre-

ating an equipment inventory, and installing supports, conduits, and cables.

Simulator. The simulator was updated to make it able to replicate the Mark VI con-trol system and its human-machine inter-face (HMI), the control room environment, and system responses. Mark VI simula-tion software also was provided for train-ing computers, enabling each to serve as a complete simulator with Mark VI and HMI functionality.

Factory acceptance testing (FAT). This was a 10-week program that included seven weeks of preparation and system checkout by the GE Energy team prior to the three-week formal witness test period by Exelon. During this exhaustive testing, the controls were verified and lined out to final site speci-fications. The tests used a dynamic model that simulates most of the field I/O connec-tions to allow testing of their functionality and maintainability.

Site acceptance testing. The Mark VI pan-els arrived on-site about nine months before the outage to allow for a two-month site ac-ceptance test. Upon arrival, they were wired to the actual field devices (pressure trans-mitters, servos, and LVDTs) and repowered to perform loop calibrations and additional testing. Tests of the panel and the simulator included validation of the site’s operator pro-cedures, initial lineup procedures, and future maintenance procedures.

GE performed module testing, indepen-dent verification and validation, system integration testing (pre-FAT), and factory customer witness testing. Exelon managed

2. Triple play. Exelon upgraded the reactor pressure controls at LaSalle County Generating Station to a triple-modular redundant design to prevent future reactor scrams. Courtesy: Exelon Nuclear


http://www.gepower.com


NUCLEAR UPGRADES

site acceptance, construction, modification, and power ascension testing. All testing in-cluded a comparison of functionality testing results to predefined acceptance criteria. Ev-ery control loop was tested.

Training. Courses on the new system were provided to the plant’s training staff two months prior to the system’s installation. Twenty maintenance I&C personnel were trained on-site in two classes of 10 students each. These individuals participated in the system’s start-up.

Outage work. This phase of the project comprised installation and testing of me-chanical devices and control room modifica-tions, demolition and removal of the Mark I panels, and installation and testing of the Mark VI panels, their interface to the plant’s DCS, and cable pulls and wire terminations.

The mechanical installation work targeted the following areas: front standard, mid-standard, stop, control, combined intercept, and bypass valve actuator modifications. The turbine’s permanent-magnet generator, over-speed governor, and trip solenoids also were replaced. A new, duplex, two-out-of-three trip manifold assembly was installed, as were seven new speed pickups and one spare probe. Triplicated LVDTs and triple-coil ser-vos were installed on the control valves.

Control room modifications comprised the aforementioned demolition of the ex-isting Mark I panels and installation of the new HMI computers, trip push buttons, and other hardwired controls or recorder outputs. Replacing the control panels entailed remov-ing all of the existing wiring, identifying the wires to be reused, installing the new Mark VI panels, and re-terminating the wires. The other ends of the wires were terminated concurrently at the new field devices, a step deemed necessary to meet the aggressive outage schedule.

Leveraging the experience. Lessons learned during this digital upgrade project were formally captured and discussed later among the stakeholders to further improve future project execution. For example:

■ Integration between the GE simulator and the plant models required collaboration among GE, Exelon Nuclear, and Exelon’s plant model vendor. The vendor had to update the model to make it compatible with the new TMR simulation. On later projects at Exelon’s other BWRs, GE will provide simulation software and update the simulator prior to factory acceptance testing of the control system to optimize project implementation.

■ Early inspection of supplied parts elimi-nated delays during installation.

■ Integrating wiring checks by plant per-

sonnel was critical to management of the overall project schedule. Some of these checks proved challenging due to con-fined work areas.

Thanks to the detailed upfront design engineering, the outage preplanning, and the training of I&C personnel, the GE-Ex-elon team made the conversion from Mark I to Mark VI controls in a record 15 days, from “breaker open” to “turning-gear ready.” During the 15 days that following receipt of clearance to start work, the Mark VI TMR panels, HMIs, networks, TMR field instru-ments, and cable conduits were installed; the front standard and mid-standard modifica-tions were made; and all checkout and lineup procedures were performed.

Case study #3: Feedwater control systems upgradeAnother nuclear utility located in the south-east installed a DCS in phases, two of which coincided with upgrades of each unit’s feed-water control system. The steam generators of both units had been suffering water level instabilities often enough to warrant upgrad-ing the controls.

An assessment of the controls to identify upgrade possibilities and alternatives recom-mended replacing the actuators and position-ers of the main feedwater control valves on Unit 1, both units’ feedwater control valves, and the 15% feedwater bypass control valves. The upgrade project installed an Invensys DCS upgrade that replaced two computer systems: one for digital data processing and the other for reporting significant operating experience.

The project also added a Westinghouse advanced feedwater control algorithm, and the additional I/O required automating op-eration of the feedwater valves at low loads. This modification included replacements of the steam dump to atmosphere (SDTA) con-trols, the actuators and positioners on the SDTA valves of Unit 1, the steam bypass control system controls (SBCS), and the positioners on the SBCS valves of Unit 2. The functions of the reactor cooling pump monitoring and display system in the con-trol room also were replaced by the addition of DCS functionality.

Assembling the upgrade team. As was the case with the turbine and reactor pres-sure control upgrades at Exelon’s La Salle County plant, a key to successful implemen-tation of this project was a clearly defined commercial and technical scope agreement. In this case it involved the utility, Foxboro (www.foxboro.com), Westinghouse (www.westinghousenuclear.com), Emerson (www.emersonprocess.com), and Sargent & Lundy.

The responsibilities spelled out in the up-grade project’s Plant Life Cycle Management document called for preparation of procure-ment specs for the new equipment. The plant’s Major Projects Engineering group was tasked to perform equipment acceptance reviews and provide project administration and supervi-sory support. Foxboro supplied the DCS, Em-erson supplied the positioners, Westinghouse developed the algorithms, and Sargent & Lun-dy did the system integration and created the field termination wiring diagrams.

On this project, new systems and upgrades were tested as part of a multiphase program with detailed procedures. The program spec-ified the need for factory acceptance, site acceptance tests, and post-installation tests. System mockups were built and used for op-erator input and training.

The new systems and upgrades were in-stalled by an integrated team of craft per-sonnel, plant engineers, S&L engineers, and vendor representatives. The team handled both pre-outage and outage work. The use of an integrated team facilitated early identifi-cation and resolution of issues, minimizing their negative effects on project schedules and the outage during which the project was implemented.

Happy ending. Again, detailed up-front design engineering, pre-outage and outage planning, a comprehensive testing regimen, and the integrated nature of the installation team proved essential to the project’s success.

The addition of DCS controls to the 15% feedwater bypass control valves on both units has allowed seamless operation of the entire feedwater system (from its bypass valves to its feedwater regulating valves) with mini-mal or no need for operator intervention. The addition and upgrading of systems have al-lowed both units to “ride through” feedwa-ter transients without tripping. Operators of both units report that the new system is such a great improvement over the old one that they couldn’t ask for better performance. ■

The authors would like to thank Darren Herschberger ([email protected]), product line leader in GE Energy’s Control Solutions group, for much of the information in case study #2. We also thank Dean Crumpacker ([email protected]), a manager in Sargent & Lundy’s Nuclear Power Technology group, for providing the details at the heart of case study #3.

—Roy Raychaudhuri ([email protected]) is a senior manager

in Sargent & Lundy’s Nuclear Power Technologies group. Doug Beach

([email protected]) is a project manager at Energy Northwest.


http://www.foxboro.com




http://www.emersonprocess.com









INSTRUMENTATION

Accurately measure the dynamic response of pressure instrumentsHow do you know if a pressure transmitter is giving poor results? Unless the

transmitter actually fails, most operators won’t notice a very slow loss in accuracy or response time. Fortunately, the noise analysis technique can identify such changes before they cause a problem. The technique has been used to effectively measure the dynamic response of nuclear power plant pressure sensors and their associated sensing lines. It also can be applied to any plant that relies on accurate instrumentation for control and monitoring plant performance.

By H.M. Hashemian, Analysis and Measurement Services Corp.

Nuclear power plants measure the dynamic response of their safety-related pressure, level, and flow

transmitters for one or more of at least four reasons:

■ To comply with a plant’s technical speci-fications and/or regulatory requirements regarding response-time testing.

■ In troubleshooting, to identify sensor or sensing-line problems, including block-ages, voids, and leaks.

■ To manage component aging, estimate residual life, and assess the reliability of pressure-sensing systems.

■ To establish objective sensor replacement schedules.

Why nuclear plants measure the dynamic response of pressure sensors and their asso-

ciated sensing lines is better understood than how to do the measuring. To address that problem, this article explains a noise analy-sis technique that will accurately measure these dynamic responses.

The noise analysis technique provides a passive method for dynamically testing pressure-sensing systems. It generates the response time for both a pressure transmitter and its sensing lines simultaneously. The test can be performed remotely while a plant is operating, does not require that transmitters be removed from service, does not interfere with plant operation, and can be performed on several transmitters simultaneously. Those benefits result in an attractive bottom line, because tests that can be run without in-terrupting the demand for high nuclear plant capacity factors are a big plus in today’s competitive markets.

Basic definitionsThe noise analysis technique is based on analyzing the natural fluctuations that ex-ist at the output of pressure transmitters while a plant is operating. These fluctua-tions (noise) are caused by the turbulence induced by the flow of water in the system, by vibration, and by other naturally occur-ring phenomena.

The noise analysis test has three steps: data acquisition, data qualification, and data analysis.

Data acquisition. A pressure transmit-ter’s normal output is a DC signal on which the process noise (AC signal) is superim-posed. That noise is extracted from the trans-mitter output by removing the signal’s DC component and amplifying the AC compo-nent. This is easily accomplished by using commercial signal-conditioning equipment, including amplifiers, filters, and other com-ponents. The AC signal is then digitized us-ing a high sampling rate (1 or 2 kHz) and stored for subsequent analysis. The analysis may be performed in real time as data are collected or off-line by retrieving the data from storage.

Figure 1 illustrates a 50-second record of noise data from a pressure transmitter in a nuclear power plant. For each transmitter (or each group of transmitters), about an hour of such noise data is typically recorded for use in the analysis.

Data qualification. The raw data must first be thoroughly scanned and screened before any analysis can begin. This is nor-mally accomplished using data qualifica-tion algorithms embedded in software, which check for the stationary and linear attributes of the raw data and look for other abnormalities.

-1.0

-0.6

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0.2

0.6

1.0

0 10 20 30 40 50Time (sec)

Nor

mal

ized

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1. Collect the data. A short noise data record from a pressure transmitter in an operating nuclear power plant. Source: AMS and Springer-Verlag

072 Instrument.indd 72072 Instrument.indd 72 11/5/07 4:53:26 PM11/5/07 4:53:26 PM


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For example, the raw data’s amplitude probability density (APD) is plotted and examined for skewness. The top APD in Figure 2 is perfectly symmetrical about the mean value of the data and fits the Gauss-ian distribution (the bell-shaped curve) that is superimposed on the APD. A Gaussian distribution is also referred to as a normal distribution. A skewed APD (see the lower plot of Figure 2) could be caused by any number of anomalies in the data, including the nonlinearity of the sensor from which the data are retrieved.

In addition to APD for noise data quali-fication, the mean, variance, skewness, and flatness of each block of raw data are calcu-lated and scanned to verify that no saturated blocks, extraneous effects, missing data, or other undesirable characteristics are present. Any data block that has an anomaly is re-moved from the record before it is analyzed.

Data analysis. Noise data are analyzed in the frequency domain and/or time domain. For frequency domain analysis, the noise signal’s power spectral density (PSD) is first

obtained through an FFT algorithm or its equivalent. Next, a mathematical model of the pressure-sensing system is fit to the PSD, from which the system’s response time is cal-culated. The PSDs of nuclear plant pressure transmitters have various shapes, depending on the plant, the transmitter installation and service, the process conditions, and other ef-fects (Figure 3).

For time domain analysis, the noise data are processed using a univariate autoregres-sive (AR) modeling program. This provides the impulse response (the response to a nar-row pressure pulse) and the step response, from which the system’s response time is calculated. Typically, the noise data are ana-lyzed in both the frequency domain and time domain, and the results are averaged to ob-tain the system’s response time.

A few assumptionsThe validity of the noise analysis technique for testing the response time of nuclear pow-er plants’ pressure-sensing systems depends on three assumptions:

0

0.5

1.0

1.5

2.0

2.5

-0.08 -0.04 0 0.04 0.08

0

0.5

1.0

1.5

2.0

-0.08 -0.04 0 0.04 0.08

APD

APD

Data value (bar)

Data value (bar)

Gaussian(normal)

distribution

Gaussian(normal)distribution

Normal

Data distribution

Data distribution

Skewed

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2. Manipulate the data. Normal and skewed APDs of noise signals from nuclear plant pressure transmitters. Source: AMS and Springer-Verlag

INSTRUMENTATION



INSTRUMENTATION

■ The process noise that drives the transmit-ter is “white,” meaning that it has a flat spectrum or essentially infinite bandwidth. This, of course, is ideal but not readily achievable. However, as long as the pro-cess noise’s spectrum has a larger band-width than the tested system’s frequency response, the noise analysis results will be reasonably accurate. If, however, the process noise has a smaller bandwidth than the system under test, then the noise analysis results will be dominated by the process bandwidth. The response-time results obtained from the noise analysis technique will therefore be larger than the

actual response time of the pressure-sens-ing system. This is acceptable in nuclear power plants because it produces conser-vative results.

■ The process noise should not have large resonances that can shift the noise spec-trum’s rolloff frequency to higher frequen-cies. If this assumption is not satisfied, corrective measures must be implemented when the data are analyzed or the results are interpreted; otherwise, the response-time values obtained from the noise anal-ysis technique may not be conservative.

■ The transmitter to be tested must be pre-dominantly linear. The noise analysis re-

sults won’t be valid if the response time of interest is one that can be measured with a small-amplitude test signal at a pressure setpoint that is close to the pressure at which the transmitter normally operates in the plant. Plotting the APD of the raw data as described and checking for skew-ness (Figure 4) will help verify a pressure sensing system’s linearity.

Experience has shown that these three as-sumptions are normally met for nuclear plant pressure transmitters. For transmitters whose process parameters fluctuate very little or not at all—such as containment pressure trans-mitters and water storage tank–level trans-mitters—a method known as a pink noise test can remotely measure response time.

0.1 1 10

Steam generator level

Reactor coolant flow

Pressurizer pressure

Frequency (Hz)0.01

1E+01

1E-01

1E-03

1E-05

1E-07

1E+01

1E-01

1E-03

1E-05

1E+02

1E+01

1E+00

1E-01

1E-02

1E-03

Pow

er s

pect

ral d

ensi

tyPo

wer

spe

ctra

l den

sity

Pow

er s

pect

ral d

ensi

ty

Ampl

itude

pro

babi

lity

dens

ity

PT-542

Ramp = 0.13 secNoise = 0.16 sec

-15 0 15

Ampl

itude

pro

babi

lity

dens

ity

PT-546


-3 0 3

Ampl

itude

pro

babi

lity

dens

ity

PT-505


-0.2 0.0 0.2Data value

3. Examine the data. Examples of power spectral densities of nuclear plant pressure transmitters. Source: AMS and Springer-Verlag

4. Loss of symmetry. In these am-plitude probability densities of transmitters from in-plant testing at a pressurized water reactor, note the nonlinear response of PT-505, indicating that there is a problem with the transmitter or sensing line. Source: AMS and Springer-Verlag



INSTRUMENTATION

Confirmed accuracyThe accuracy of the noise analysis tech-nique for testing the response time of pres-sure-sensing systems has been established experimentally using pressure transmitters like those used in nuclear power plants. For each transmitter, the response time was measured first using the ramp method and then using the noise analysis technique. In doing so, the reliability of the ramp test re-sults was first established in the laboratory

by ramp-testing pressure transmitters using several ramp rates and by performing re-peatability tests. Except for a few outliers, the results proved to be repeatable to better than 0.05 second, with little or no depen-dence on the ramp rate.

Next, laboratory measurements were made to examine the repeatability of the noise analysis results. As with the ramp tests described previously, the repeatability of the noise analysis results was better than

0.05 second, a few outliers notwithstanding. This is reasonable considering the potential effects that can influence the noise analysis results. From these tests we can draw the fol-lowing conclusions:

■ 79% of response-time results from the noise analysis technique fall within ± 0.05 second of the ramp test results performed on the same transmitters under the same conditions.

■ 16% of noise analysis response-time re-sults fall between 0.05 and 0.10 second (±) of the ramp test results.

■ 5% of noise analysis response-time results fall within ± 0.10 second of the ramp test results.

Based on all the foregoing data, the nu-clear power industry has concluded that the noise analysis technique indicates the re-sponse time of pressure-sensing systems to an accuracy of better than 0.10 second.

Testing techniques Response-time testing using the noise analysis technique has been performed on nuclear power plant pressure transmitters since the early 1980s. Let’s take a look at some examples gleaned from the resulting database of response-time values and re-cords of raw data, PSD plots, and observa-tions. Figure 5 shows noise-test PSDs for

2-loop PWR 3-loop PWR 4-loop PWR BWR

Pressure Pressure Pressure Pressure

Level Level Level Level

Frequency (Hz) Frequency (Hz) Frequency (Hz) Frequency (Hz)

Flow Flow Flow Flow

1E -01

1E -08

1E +01

1E -08

1E +01

1E -07

1E +01

1E -06

1E +01

1E -07

1E -01

1E -09

1E+ 00

1E -08

1E+ 00

1E -08

1E+ 02

1E -05

1E+ 02

1E -05

1E-+00

1E -05

1E +01

1E -04

0.1 1 10 100 0.1 1 10 100

0.1 1 10 100 0.1 1 10 100 0.01 0.1 1 10

0.01 0.1 1 10 0.01 0.1 1 10 0.01 0.1 1 10 0.01 0.1 1 10

0.1 1 10 100

0.1 1 10 100 0.1 10 100

5. Different strokes. Examples of typical power spectral densities of pressure, level, and flow transmitters in PWRs and BWRs. Source: AMS and Springer-Verlag

Reference

Three yearslater

1E+01

1E-01

1E-03

1E-05

1E-070.01 0.1 1 10

Frequency (Hz)

PSD

6. Time trends tell a story. The PSDs of a nuclear plant pressure transmitter were measured three years apart. Source: AMS and Springer-Verlag



INSTRUMENTATION

two-loop, three-loop, and four-loop pres-surized water reactors (PWRs) and a boiling water reactor (BWR) plant. Three PSDs are shown in each case for a pressure, a level, and a flow transmitter in each plant type.

In several plants, noise testing has been performed on more than one occasion, mak-ing it possible to examine the repeatability of the results. Figure 6 shows two PSDs for a steam generator level transmitter in a three-loop PWR plant. The tests were performed approximately three years apart. The results are essentially identical, which indicates that the noise test for this transmitter is very repeatable and that the transmitter has expe-rienced no response time changes over this three-year period.

On another occasion, two redundant transmitters of the same steam generator level signal were tested at the same time in a four-loop PWR. The PSD results are shown in Figure 7. It is apparent that one of these transmitters is significantly faster than the other (by about an order of magnitude). This is unusual because the response times of redundant transmitters are normally ex-pected to be comparable. In this particular case, the two transmitters are from two dif-ferent manufacturers, and they were prob-ably installed without considering that the two transmitters might have vastly differ-ence response times. This type of difference in response time is also seen in redundant transmitters when there is blockage in the sensing line. However, in the case shown in Figure 7, the difference is not the result of sensing line blockage.

Detect oil lossIn the late 1980s, some pressure transmit-ters in nuclear power plants from a particular manufacturer were found to be leaking sili-con oil from their sensing cells. Silicon oil is used to transfer pressure signals from the iso-lation diaphragm to the sensing diaphragm at the center of the sensing cell. Thus, if the oil leaks, both the transmitter’s steady-state (cal-ibration) and dynamic response are affected.

Figure 8 shows the responses of two flow transmitters at a nuclear power station after a reactor coolant pump trip. Note that one transmitter (FT-444) responds quickly to flow reduction as expected, but the other transmitter (FT-445) is extremely sluggish. Later analysis confirmed that the FT-445 suf-fered from the oil loss problem.

Figure 9 shows raw noise data for a nor-mal and a failed (from oil loss) transmit-ter—both used in the same service in an operating nuclear power plant. As expected, the amplitude of the noise signal from the failed transmitter is much smaller than that from the normal transmitter.

PSD

Frequency (Hz)0.01 0.1 1 10

1E -0.1

1E -0.3

1E -0.5

1E -0.7

Manufacturer A

Manufacturer B

7. Problem transmitter. These PSDs are from two redundant steam generator level transmitters in a four-loop PWR plant. Source: AMS and Springer-Verlag

120

110

100

90

80

Time 10:04 a.m. 10:33 a.m. 11:02 a.m. 11:31 a.m. 12:00 noon

Reactor coolant pump trip

FT-445

FT-444(expectedresponse)Re

acto

r coo

lant

pum

p flo

w (%

)

8. Obvious problem. The dynamic response of two transmitters during the shutdown of a nuclear power station illustrates unexpected response. Source: AMS and Springer-Verlag

0.10

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0

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-0.100.0 0.5 1.0 1.5 2.0 2.5

Normal

Failed

Time (seconds)

Pres

sure

am

plitu

de (b

ar)

9. Anatomy of a failure. These obviously different lines depict the noise output from testing of a normal and a failed transmitter in an operating nuclear power plant. Source: AMS and Springer-Verlag



INSTRUMENTATION

After learning of the oil loss problem, the author and his colleagues at Analysis and Measurement Services Corp. (AMS) devel-oped noise diagnostics for detecting the oil

loss. This involved calculating the second to the fifth moments of the noise data as well as the ratio of these moments based on noise records above and below the signal’s mean

value. The first moment of noise data is its mean value, its second moment is the vari-ance, and the third moment is skewness.

Table 1 is an example of noise diagnos-tic descriptors for four steam generator level transmitters in a PWR plant. Note that the values of the descriptors for LT528 are much different than for the other transmitters. This transmitter was later removed from the plant and sent to the manufacturer, where it was determined that the problem was caused by oil loss in the transmitter’s sensing module. This and similar cases demonstrated that the noise analysis technique can provide a useful means for diagnosing oil loss.

Fortunately, the root cause of the oil loss problem in this manufacturer’s transmitters was identified and resolved by the manu-facturer very quickly. Therefore, the nuclear industry did not suffer any adverse conse-quences. Also, because the problem was suc-cessfully resolved early, use of the noise diagnostics for detecting oil loss did not be-come routine in nuclear power plants.

Response time degrades The response time of nuclear plant pressure transmitters does degrade, but this is not as prevalent a problem for pressure transmitters as it is for resistance temperature detectors (RTDs). Conversely, calibration drift is more of a problem in pressure transmitters than it is in RTDs. Figure 10 summarizes the results of a research project to quantify the effects of normal aging on the calibration and response time of a sample of nuclear-grade pressure transmitters. It is clear that aging affects the calibration of pressure transmitters more than their response time.

Table 2 shows response time results from noise analysis testing performed on 16 transmitters over five years. The measure-ments were made using the noise analysis technique. Only one transmitter suffered response time degradation of about 30% af-ter 36 months of service, and this was later determined not to be due to the transmitter but to a sensing line blockage. This finding is consistent with the nuclear industry’s ex-perience that response-time degradation in pressure transmitters is more often due to sensing line blockages than to degradation in the transmitter itself. ■

This article is based on material summa-rized and excerpted from Chapter 9, pages 195–225 of the author’s book, Maintenance Process Instrumentation in Nuclear Power Plants (Springer-Verlag Berlin Heidelberg, 2006). Used with the kind permission of Springer Science and Business Media.

—H.M. Hashemian ([email protected]) is president and CEO of Analysis

and Measurement Services Corp.

Table 2. Trend response times. Here are typical results of trending of response time for a group of nuclear plant pressure transmitters. Source: AMS and Springer-Verlag

Failed (7%)

Moderatelyaffected (35%) Unaffected (58%)

Calibration changesFailed (4%)

Moderatelyaffected (12%)

Unaffected (84%)

Response time changes

10. Transmitter failure profile. These results are from experimental research on the performance of aging nuclear plant pressure transmitters. Source: AMS and Springer-Verlag

Tag number

LT-0011A

LT-0012A

LT-0013A

LT-0014A

LT-0021A

LT-0022A

LT-0023A

LT-0024A

LT-0031A

LT-0032A

LT-0033A

LT-0034A

LT-0041A

LT-0042A

LT-0043A

LT-0044A

Initial testing

0.36

0.38

0.45

0.43

0.41

0.39

0.44

0.46

0.39

0.43

0.45

0.45

0.38

0.44

0.43

0.45

18 months later

0.41

0.42

0.43

0.41

0.45

0.42

0.49

0.48

0.42

0.46

0.48

0.47

0.44

0.42

0.44

0.44

36 months later

0.43

0.43

0.45

0.44

0.43

0.42

0.47

0.44

0.41

0.44

0.44

0.42

0.4

0.43

0.42

0.41

48 months later

0.44

0.43

0.47

0.47

0.43

0.43

0.46

0.66

0.41

0.48

0.46

0.45

0.41

0.45

0.41

0.42

60 months later

0.44

0.43

0.41

0.43

0.42

0.42

0.43

0.41a

0.40

0.42

0.44

0.41

0.44

0.41

0.40

0.40

Note: a. Sensor’s response time degraded between 36 and 48 months of service. The problem was corrected during an outage at 48 months.

Response time (sec)

Diagnostic descriptor

Skewness 0

5th moment 0

Variance ratio 1Skewness ratio 1

5th moment ratio 1

LT518

0.02

0.07

1.031

1

LT528

0.23

2.12

1.251.06

1.21

LT538

0.08

0.7

1.091.01

1.04

LT548

0.05

0.36

1.061.02

1.06

Measured values of diagnostic descriptors

Normal value

Table 1. Diagnose oil loss from instruments. These oil-loss diagnostic results were obtained from tests in a nuclear power plant. Note the values of descriptors for LT 528. This transmitter was later removed and sent to the manufacturer, where it was determined that the problem was caused by oil loss in the transmitter’s sensing module. Source: AMS and Springer-Verlag







PROJECT MANAGEMENT

Milestones on the road to commercial operationThe electric power industry is capital-intensive, and it takes several years to

build and commission a baseload plant for commercial operation. Own-ers seek contractors who are willing—given proper incentives—to build a plant for a lump-sum price with a guaranteed schedule and performance. Matching an owner’s wants with contractors’ needs is an exercise in al-locating risk. Avoid the contract traps that can stall a project and cost mil-lions to resolve.

By Denis J. King, Asilea Resources LLC, and Arif Hyder Ali, Crowell & Moring LLP

An engineering, procurement, and con-struction (EPC) contract for a power project defines how its risks will be

allocated and the scope of work to be per-formed by both parties. This article begins by detailing several kinds of risk that are typically the subject of lengthy negotiations and concludes with two case studies of dis-pute resolution, which is needed when good contracts are poorly executed. We hope that these descriptions of construction contract risk prove helpful during your next negotia-tion for a new plant or major plant upgrade.

Carrots and sticksEPC contracts are two-way streets. Contrac-tors normally seek to have their agreements provide bonuses for beating a project’s sched-ule deadlines and/or performance standards. Such provisions balance other provisions for payment of predetermined “liquidated dam-ages” that are typically required by owners as insurance against nonperformance. Contrac-tors are liable if the plant is commissioned late or cannot operate at its guaranteed ca-pacity and heat rate at full load.

Owners are willing to reward contractors

with a share of the “bonus” revenues gener-ated by a project that comes on-line earlier than expected. For their part, contractors are willing to accept liability for liquidated dam-ages because the plant’s construction sched-ule and performance are under their control (barring legal delays or an act of God). The magnitude of the liquidated damages is usually sufficient incentive for the EPC contractor to build a plant that meets the guarantees.

Naturally, EPC contractors cover their own risk by insisting on liquidated damages

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080 ProjMgmt.indd 80080 ProjMgmt.indd 80 11/5/07 4:54:01 PM11/5/07 4:54:01 PM



PROJECT MANAGEMENT

clauses in contracts for major plant equip-ment. Equipment vendors guarantee the performance of their individual units, but it is ultimately up to the EPC contractor to tie those units together into a power generation system with a minimum capacity and maxi-mum heat rate.

Performance guarantees usually have a tolerance band, to allow an owner to provi-sionally accept a completed plant and begin selling its output. Provisional acceptance is followed by a grace period, during which the EPC contractor adjusts equipment and sys-tems as necessary to enable the plant to meet contractual performance guarantees. If the plant still cannot meet those guarantees by the time of final acceptance, the contractor normally would be required to “buy down” the shortfall in plant performance at the specified liquidated damages rate.

Typically, an EPC contract has zero tol-erance for a plant that cannot operate with-out exceeding permitted levels of air, water, and noise pollution. If it cannot meet all emissions guarantees, it cannot be accept-ed, even provisionally. Supply contracts for major equipment have their own emissions guarantees.

Similarly, there is zero tolerance for a project being late. The project schedule is a heavily negotiated item of the EPC contract. Because schedule guarantees are only par-tially backed by equipment vendors’ delivery dates, most of this type of risk is borne by the EPC contractor.

By the milestonesThe common thread in nearly all large power projects is a series of milestones that the EPC contractor must reach on the road to commer-cial operation—and final contractual pay-ments. Each milestone has checks, balances, and risks that together ensure compliance at a certain time with the terms of the EPC con-tract. These milestones are typically:

■ Mechanical completion ■ Performance testing ■ Provisional acceptance ■ Commercial operation

Mechanical completion. Mechanical completion signifies the successful comple-tion of start-up and commissioning of all plant systems. After each system is turned over from the EPC contractor to the project’s start-up organization, it is checked out, cali-brated, and commissioned. Often, the EPC contractor is also tasked with providing hands-on training to operators of the new plant. Having the operators participate in start-up gives them invaluable plant-specific experience, as well as an opportunity to iden-

tify “punch list” items to be included in the package of test and commissioning data that accompanies each system to its next stop: performance testing.

A punch list is usually developed for each system prior to its turnover. Items on the list represent jobs that need to be done by the EPC contractor but ones that are not so ur-gent that leaving them undone would affect personnel safety or the plant’s operability or permit compliance. Examples include build-ing access platforms for maintenance, touch-up painting, landscaping, and site cleanup.

Each item on a punch list is carefully considered; indeed, a single item is often the subject of long negotiations among the plant’s owner, EPC contractor, and operator to determine whether it is necessary and in-cluded in the contractor’s scope of work. The contractor can complete tasks on the punch list after performance tests are conducted and the plant is accepted by the owner.

During start-up and commissioning, the suppliers of boilers, turbines, pumps, and motors fine-tune their gear in an integrated environment, usually with units connected to the grid. This step is critical because it sets the baseline values of capacity, heat rate, and emissions metrics to be verified by perfor-mance testing.

While the plant is being tuned, fuel is con-sumed and electrical energy is delivered to the grid through the local, interconnecting utility. For bearing the risk of paying for the fuel, the owner is rewarded by the revenues generated. But because the plant may start up and shut down many times during the tun-ing phase, the grid operator must consider its output unreliable, and the plant itself not dispatchable. Accordingly, the owner is paid for kilowatt-hours at a lower, “avoided-cost” rate. Because these revenues may not fully offset the cost of fuel, it is not uncommon for a contract to stipulate that the EPC foot some of the fuel bill if the duration of tuning becomes excessive.

Mechanical completion is a critical mile-stone in the lifecycle of a power project, and not just because it precedes performance testing. It is also an opportunity for the own-er to make sure that other contractual obli-gations—training operators, and delivering O&M manuals, for example—have been met by the EPC contractor. Mechanical comple-tion often is certified by a piece of paper attesting that both the owner and the EPC agree that the plant is ready for performance testing.

The conditions required for mechanical completion status usually include the fol-lowing:

■ The EPC contractor has finished all tasks (including operator training) in its scope of work, except for the items on punch lists.

■ The work is mechanically and electrically sound, plant start-up is complete, and all systems can be operated as specified.

■ The plant can be operated in compliance with all relevant laws and permits and without damage to persons or property.

■ The plant has synchronized to the grid.■ The contractor has provided draft copies

of station manuals and O&M manuals.

Performance testing. Performance test-ing gives the EPC contractor an opportunity to prove that the plant meets performance guar-antees for capacity, heat rate, and emissions.

Performance testing entails operating the power plant at full load using normal pro-cedures while measuring its fuel consump-tion and energy and pollutant outputs over a short period of time—4 hours, for example. Ambient conditions and fuel content are also recorded, and that data is then used to ad-just the three measurements for comparison with guaranteed performance levels. In many cases, the plant is also run for an extended period—say, 100 hours—to make sure that all systems and components work properly, both individually and in concert, and to de-



PROJECT MANAGEMENT

tect “lemons” at the steep, early end of the reliability “bathtub” curve.

Successful completion of performance testing gives the EPC contractor an oppor-tunity to stop the accumulation of liqui-dated damages if the plant is finished after the guaranteed completion date, or to claim a bonus payment if the plant is completed before it.

As during fine-tuning in the mechanical completion phase, the plant owner provides the fuel for performance testing and reaps the rewards of generation revenues it produc-es. Again, the receiving utility pays for kilo-watt-hours at an avoided-cost rate, because the output is considered unreliable. At this stage, though, if revenues do not compensate for the cost of fuel, the difference is typically absorbed by the owner.

Provisional acceptance. There is usu-ally a 95% provisional acceptance level for capacity and a 105% provisional acceptance level for heat rate. As mentioned, all guaran-teed emissions levels must be met, and the plant must be operated in compliance with permits before the owner will grant provi-sional acceptance of the plant to the EPC contractor.

If capacity and heat rate are not at the 100% guaranteed performance level when first tested, but within the range for provi-sional acceptance, the EPC contractor usu-ally has until the date of final acceptance to achieve the 100% levels through tuning, ad-justments, or modifications. After that date, the contractor will have to buy down any dif-ference at the liquidated damages rate stated in the contract, as mentioned earlier.

Punch list items also have to be completed by the final acceptance date, which may be as long as one year after the provisional ac-ceptance date.

Commercial operation. Provisional acceptance occurs when the results of per-formance testing are verified. Verification may take some time because the technical data must be analyzed by the owner’s engi-neer and an independent engineer. The EPC contractor retains care, custody, control, and the risk of loss while the test results are be-ing verified. When test results verify that the guaranteed performance levels have been met, provisional acceptance is granted retro-active to the date of successful completion of performance testing.

Upon provisional acceptance, care, cus-tody, and control transfer to the owner. The commercial operation phase begins when the plant is dispatched or given a generation schedule by the grid operator, following no-tification of the interconnecting utility.

In the case of a plant that delivers energy under a power-purchase agreement (PPA),

the off-taker typically will verify results of the performance testing to confirm that the actual capacity meets the requirements of the PPA. In some cases, the off-taker is only notified that the results met the re-quirements of the PPA before commercial operation begins.

Resolving disputesShould there be any misunderstanding about any of the milestones, the first step is to re-view the dispute resolution provisions of the EPC contract. In international EPC con-tracts, the two most common forms of dis-pute resolution are an expert determination by an engineer or a dispute review board, and arbitration.

If a dispute involves technical or any other specialized issues, appointing an engineer as an impartial fact-finding and -evaluating expert can facilitate an early resolution. The engineer’s independence, which most arbi-tral tribunals value highly, can encourage both parties to narrow the issues and reach a settlement with no need for a costly arbitra-tion. The engineers’ neutral fact-finding pro-cedure can be binding or nonbinding.

A dispute review board is a private, vol-untary, and confidential procedure com-monly used in the context of an ongoing long-term relationship. The board comprises an informed standing group of experts who can quickly deal with disputes as they arise.

Dispute review boards are commonly used in the construction industry and in high-value outsourcing contracts. Their determinations may be binding or simply advisory.

Arbitration involves the adjudication of rights by a tribunal of one or several arbi-trators with the power to render a decision that is final and binding on both parties. The parties must specifically agree in writing to submit their dispute to arbitration. A pos-sible exception is when one of the parties is a sovereign state or state-controlled enterprise, in which case the parties’ consent to arbi-trate may be based on an investment protec-tion and promotion treaty or an investment law. Arbitration is a preferred alternative to dispute resolution in the national courts of one of the parties because neither party has the “home court” advantage. Furthermore, settlement of the dispute is entrusted to arbi-trators who may have significant experience resolving international power project con-tract disputes.

The two parties’ agreement to submit their dispute to arbitration can take either of two forms. One is a specific clause—an arbitra-tion clause—in the original contract between them in which they agree to resolve all fu-ture disputes by arbitration. The other is a separate contract between the parties after a dispute has arisen stating their intention to submit that dispute to arbitration The latter is called a submission agreement, or clause compromissoire.

The importance of drafting an effective and enforceable arbitration clause should not be underestimated. A properly drafted arbi-tration clause makes the method of resolving future disputes more predictable. A poorly drafted clause, on the other hand, can result in unnecessary costs and delays representing the time spent arguing about the dispute res-olution mechanism rather than the substance of the dispute itself.

It is increasingly common to find contract language that specifies arbitration for dispute resolution accompanied by clauses requiring both parties to pursue certain nonbinding ef-forts to resolve their dispute before arbitra-tion can begin. These are often referred to as “multistep” dispute resolution clauses.

Typical multistep procedures require the parties to try to settle their dispute through negotiation. They also identify the level of corporate management at which the nego-tiations should take place and set time lim-its for their completion. Should negotiation efforts fail, the clause may even call for the parties to enter into mediation or proceed directly to arbitration. If the clause calls for mediation and the parties cannot reach a settlement within the stipulated time, or if one party refuses to participate, the dispute



PROJECT MANAGEMENT

goes to arbitration.

Tell it to the judgeDispute resolution is as much art as science. Following are two case studies from the in-ternational arena that should make this clear.

Case #1: Ready—or not—for com-

mercial operation. Late in 2001, Compha-nia Paranaense de Energia Ltda. (Copel), a Brazilian mixed-capital company, stopped making monthly capacity payments under a PPA it had signed with UEG Araucaria Ltda., a joint venture of El Paso do Brasil Ltda., Petrobras, and Copel itself. At the center of the dispute was a 469-MW combined-cycle power project at Araucaria, near Curitiba in the southern Brazilian state of Parana, owned by the joint venture. Copel holds the electric-ity supply concession for the state.

In addition to arguing that the PPA itself was invalid under Brazilian law, Copel plead-ed that the plant had not been built in com-pliance with the terms of its EPC contract. Initially, Copel—the off-taker—made capac-ity payments to UEG Araucaria. Then, at the direction of the state government, it stopped, putting Copel at default under the PPA.

At this point, UEG Araucaria terminated the PPA (in compliance with its terms) and invoked its dispute resolution clause. The clause called for the parties to negotiate first and, if that failed, to submit the dispute to ar-bitration in Paris before a three-person tribu-nal under rules of the International Chamber of Commerce.

The crux of the dispute was Copel’s claim that the plant had not achieved commercial operation. In addition to being the off-taker of the plant’s output, Copel was responsible for building the plant’s natural gas supply pipeline, its water supply system, and a sub-station and transmission lines to connect the plant to the grid. Copel also was responsible for O&M of the plant and for supplying its fuel, whose specifications were spelled out in the PPA.

Two gas turbines had been purchased on the assumption that the fuel they would be supplied would meet or exceed the require-ments of the turbines’ manufacturer. The natural gas to come from a new pipeline from Bolivia was expected to meet those require-ments. But when the gas began to flow, it was of poor quality. It became evident that if Co-pel supplied that gas to the Araucaria plant, both turbines’ warranties would be voided.

At Copel’s direction, a gas conditioning system (GCS) was installed to condition the natural gas to meet the vendor’s specifica-tions. It was ready to provide compliance fuel to the turbines both when the plant was ready for performance testing and at the time of planned commercial operation in Sep-

tember 2002. However, the GCS produced by-products—natural gas liquids such as liq-uefied petroleum gas (LPG) and naphtha—that have significant value. When the power plant was ready for commercial operation, the facility for storing the LPG had not been completed, so the LPG had to be flared.

Performance testing of the power plant was successful: All capacity, heat rate, and emissions requirements were met, with the GCS supplying acceptable fuel. At this point, UEG Araucaria declared that the plant had achieved commercial operation. But Copel disagreed. When it stopped making monthly capacity payments, it claimed that the plant had not achieved commercial operation be-cause the GCS had not been completed and therefore was unsafe.

Before the parties’ dispute was resolved amicably, the Paris tribunal heard significant amounts of expert testimony from both sides on such issues as the proper functioning of the plant, the requirements for declaring commer-cial operations under the PPA, the significance of punch list items, and the size of perfor-mance bonuses and liquidated damages.

Case #2: River gets dirtier. Who

should pay to screen it? In the late 1990s, the cost of modifying a power plant’s water intake structure, incurred by an EPC con-

tractor after the owner declared commercial operation, became the subject of a dispute that ended up in arbitration. After the plant passed performance testing, the owner made that declaration (in compliance with the terms of its PPA), although significant work remained to be done on the structure in order to prevent the PPA from expiring.

This plant, in Colombia, has a net capac-ity of 220 MW in combined-cycle mode and uses once-through cooling of its steam tur-bine condenser. It was built by affiliates of a Japanese company for the owner, a joint ven-ture of the Japanese firm and an American company.

Although the plant was able to pass the performance testing mandated by the PPA, tests revealed considerable debris flowing through the intake structure that would make the condenser and the auxiliary cooling sys-tem prone to fouling. The original design of the intake structure used fixed screens and trash rakes, which proved inadequate. After the installation of traveling screens, the condenser still experienced fouling, and sand and silt continued to enter the auxiliary cooling system. To successfully complete the performance testing, the contractor had to reverse the flow through the condenser to reduce fouling of the tube sheets.

The continued fouling made it clear that significant modifications to the intake struc-ture were needed to keep debris from enter-ing the plant. Among the steps that the EPC contractor took were placing flow diverters in the river, adding a screen-washing sys-tem at the intake structure, and changing the design of the auxiliary cooling system from open-loop to closed-loop with the addition of a small cooling tower.

Naturally, the owner claimed that the mod-ifications were within the scope of work of the lump-sum contract, while the contractor considered his expense a result of changed conditions in the river. The dispute led to arbitration under the Rules of the American Arbitration Association in New York. This case also was settled amicably, but only after significant expert testimony had been pre-sented on the safe operation of power plant intake structures. ■

—Denis J. King ([email protected]) is a principal and founding member of

Asilea Resources LLC, a Maryland-based consulting firm. A Registered Professional Engineer, he also acts as an advisor to the

K&M Group of Companies. Arif Hyder Ali ([email protected]) is cochair of

Crowell & Moring LLP’s International Dispute Resolution Practice. He has

represented parties worldwide in international construction, investment,

and commercial arbitrations.





RETROSPECTIVERETROSPECTIVEThis month in POWER…

November 1884November 1884

POWER began its life in October 1882 as a tabloid-size publication originally entitled Steam. About the same time, two young Boston advertising salesmen decided to launch a new magazine about textile mill steam plants, called POWER. They bought Steam prior to publishing POWER’s first is-sue, so early issues of this magazine car-ried the flag “POWER, with which is incor-porated Steam” (Figure 1).

The editor’s introduction to the first issue of POWER established the editorial standards we continue to follow today: “It

will be aim of the Editors to make this journal an interesting and valuable practi-cal medium of instruction and of exchange


Early issues of POWER covered many of the new maritime en-gines powering the generation of luxury ocean liners that en-tered service early in the 20th century (Figure 3). A special report this month focused on the power plant of the Cunard Steamship Line Shipping Co.’s RMS Lusitania, which had re-cently successfully completed her first round trip from the UK to New York City, crossing the Atlantic Ocean in less than six days. The Lusitania, at the time of her launch, was “the most powerfully-engined vessel afloat, having some 70,000 horse-power and a guaranteed speed of 24½ knots in all weathers.

“The main propelling machinery consists of two high-pressure ahead, two low-pressure ahead, and two astern turbines of the Parson type. Owing to the immense size of

these turbines, and in order to comply with the admiralty’s requirements as to subdivision, the main propelling and auxiliary machinery are located in nine different water-tight compartments.

“There are 23 double-ended and two single-ended boilers in the ship, situated in four separate water-tight compart-ments. The forward boiler room has two single-ended and four double-ended boilers, and in each of the other rooms there are located six double-ended boilers in groups of three athwart the ship. The double-ended boilers are 17½ feet in diameter by 22 feet long.”

The Lusitania was sunk by the German submarine U-20 on May 7, 1915, off the coast of Ireland as she was com-pleting her 201st transatlantic voyage. The loss of 128 Americans on board precipitated America’s entry into the First World War.

1. “POWER, with which is incorporated Steam” was first published in November 1884.

3. The engine room of the RMS Lusitania.

2. The Ide Engine

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RETROSPECTIVE

of ideas among power users, technically accurate enough to stand the criticism of the expert, and yet so popular in style and matter as to appeal directly to the fifty thousand or more power-using constitu-ents whom it is intended to reach.

“Among the subjects treated will be how to buy, set, fire, and clean boilers; how to select, set up, run, repair, and take care of steam, gas and hot-air engines, and all other motors . . .

“The style at which we aim will be terse and clear; the matter so far as in us lies, fresh and varied. The editorial policy will be one of enterprise, through indepen-dence, and straightforwardness.

“Such a paper ‘Power’ is intended to be. It will treat only of producing and carrying power; and will reach, as far as possible, all interested in these subjects. We believe that it will be by far the best medium published, in which to advertise power generators and transmitters.”

The very first feature article reviewed a new steam engine that was prominently displayed on the issue’s cover. The edi-tors described the Ide Engine (Figure 2) as “show[ing] a most careful apprecia-tion, on the part of its builder, of the fact that an engine should deliver power with economical steam expenditure and little wear, and be convenient to erect, adjust,

run and repair. The first thing that struck us on examining the plans, was the exten-sive use of steel and gun metal on work-ing and wearing parts.

“The lower part of the frame resembles [a] box girder with cross ribs; there is a straight line vertical web . . . and a top piece straight in elevation and curved in plan, suggestive of Corliss. The bed piece has two of its bolt holes directly under the main centre, facilitating erection in level and line.”

The editors were still working out the in-evitable kinks in a new publication and in a useful equipment review; the report never stated the horsepower developed, fuel con-sumption, price, or size of the engine.


Research on the commercial use of nuclear power was a major U.S. focus in the mid-1950s because nuclear plants promised “power too cheap to meter” and simplicity of operation (Figure 5). The first U.S. com-mercial nuclear power plant—located in Shippingport, Pennsylvania, and powered by a pressurized water reactor rated at 60 MW—reached full load in December 1957.

POWER editors noted in “Nuclear Notes” that the “hard lessons of experience show

that nuclear power development is tough and costly—more than originally ex-pected. Economic and profitable atomic energy generation seems farther off in the future than first estimated; especially when compared to relatively cheap fos-sil fuels now available here. England and Europe, squeezed between growing power demands and diminishing fuel reserves, al-ready face rocketing costs of imported fu-els. This makes it easier to prove in costly nuclear power. Their needs may help keep our atomic industry going by furnishing a market for equipment while we keep push-ing development and research.” ■

5. “Do you realize how atomic power will simplify things?”


Power facilities that rely on internally generated power of-ten find that running multiple units in load-sharing mode provides the greatest economic benefit when meeting widely varying daily loads. Load sharing today is accomplished with merely a switch setting on the governor for typical engine generators or small steam turbines. That was not the case 75 years ago, when the editors reviewed the latest load-sharing design, which was based on mechanical linkages and cam-shafts (Figure 4).

“Program load control has been developed to improve the operating efficiency of groups of turbine generators. . . .The application of automatic frequency or automatic load control in conjunction with program load control allows the use of the entire operating capacity of the station for regulation and maintains the minimum turbine heat con-sumption for all loads. The valve auxiliary switches (Fig-ure 4) initiate the movement of the selector switch and may therefore be considered as the ‘brains’ of the program control. The switches [are] of such a design as to permit continuous motion without excessive wear and to provide means for close adjustment. A cam-type switch meeting those requirements was designed and installed on a turbine governor. The valve linage causes an angular movement of approximately 40 deg. and gearing at one end of the cam switch multiplies this movement eight times.”

4. Turbine-valve switches actuated by the governor mechanism initiate movement of the selector switch [for parallel operation of two prime movers].

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NEW PRODUCTS TO POWER YOUR BUSINESS

Remote pipeline inspection tool QuickView, the only pipeline zoom inspection camera to of-fer distance-to-target measurement, now also measures pipe diameter and manhole depth with the push of a button. Us-ers of the patented QuickView can now instantly know the size of the line they’re inspecting as well as its distance below grade, making it an invaluable tool for rapid, afford-able infrastructure surveys.

In Pipe Measurement Mode, QuickView measures the di-ameter of any pipe whose end can be viewed within the camera’s field of view. An operator simply toggles to Pipe Measurement Mode, aligns the measurement grid that ap-pears onscreen, and presses Measure. The pipe diameter reading appears instantly onscreen. QuickView measures pipe diameters from 4 to 12 inches in 2-inch increments. With 216:1 zoom, onscreen distance measurement, and HID lamps, QuickView captures video as far as 250 feet down lines from 8 to 60 inches in diameter. (www.envirosight.com)

Free temperature sensor giveaway Moore Industries is making you an offer you can’t refuse. The company is giving away a free WORM flexible RTD or thermocouple sensor to any qualified user who wants one. The offer includes a choice of a thermocouple or RTD sensor, 24 inches of extension wire, and an installation kit with all the necessary mounting com-ponents, including a spring, spacers, and a clip. The free WORM sensor will fit into virtually all new or existing thermowells with a 0.260-in. ID.

The WORM is a flexible sensor and can fit into existing thermowells that have problems, such as caked debris, or those that are “sagging” from exposure to extreme heat. The WORM also simplifies maintenance procedures, because a WORM can be cut to fit any application. A main-tenance tech no longer has to take a dozen different rigid sensors into the field in hopes of finding one that fits; instead, he or she can take a single WORM and trim it to fit almost any length of thermowell. This feature also simplifies spare parts inventories at a plant.

“We are convinced that users will buy WORM sensors once they realize how versatile and accurate they are, and how much the WORM can save them in maintenance time and spare parts inventories,” says Scott Saunders, vice president of sales and marketing at Moore Industries. “The WORM sells it-self, once a user gives it a try. For that reason, we are offering a free WORM sensor to any customer that is interested in solving their sensor headaches.”

To obtain a free WORM sensor, go to www.miinet.com/freeworm, fill out the form, and hit “send.” (www.miinet.com)

Measure the hot spots Wahl Instruments Inc. has added a high-temperature model to its line of Wahl Heat Spy thermal imaging cameras that measure tem-peratures in the range of 392F to 1,652F. This afford-able thermal imager is light, compact, easy to operate, and designed for hand-held use. It also features a tripod mount for remote use.

The HSI3002 is fully ra-diometric and measures the temperature of every pixel. Easy Report software allows users to easily insert multiple images with data taken during a site survey to produce an inspection report. The imager features a 160 x 120 pixel, uncooled, microbolometer array, capable of displaying high-resolution, real-time, thermal images on a bright 3.5-inch color LCD display with LED backlight. The Class II laser precisely identifies the problem hot spot shown on the marked center of the display.

Two measurement cursors, movable anywhere in the image, provide tempera-ture readings at each cursor location and indicate real-time differential temperature measure-ment between the two points anywhere along the temperature range. High-quality images can be cap-tured and manipulated online, or problems can be resolved on the spot. (www.palmerwahl.com)

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http://www.miinet.com/freeworm

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NEW PRODUCTS

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

Mercury-free magnetic switch Jerguson is offering retrofit kits for its mercury-based level switches that feature a tri-magnet switch from the Clark-Reliance Instrumentation and Controls Group. Replacement kits are available to up-grade a wide variety of existing mercury switches, enabling replacement of the switch and enclosure without removal of the existing chamber.

In operation, the float or displacer drives a stainless steel–sheathed permanent magnet attached to the float rod in the glandless pressure tube. As the float rises and falls with a changing liquid level, the float assembly moves upward inside the pressure tube. A switch mechanism mounted inside the enclosure adjacent to the pressure tube is activated by the rising or falling magnet.

The vertical movement of the float magnet in the pressure tube simultaneously actuates the sec-ondary and switch magnets within the switch mechanism to operate the contacts. This three-magnet system enables the float magnet to pass the switch and actuate switch mechanisms at other levels. Switch mechanisms that are actuated will not reset until the float magnet actuates the switch mecha-nism on a falling level.

The switch mechanism is based on a unique Jerguson three-dimensional magnet design in which the snap action occurs because the same pole of two magnets will repulse each other. The magnet mounted on the float rod causes the secondary magnet to rotate as it passes up and down. The switch magnet is repelled by the secondary and snaps to the opposite side. This causes the cradle to pivot, moving the push rods that operate the switch contacts. The result is positive snap action interlock switching.

Four different switch mechanisms are available. A 10-amp mechanism is designed for general-pur-pose duties up to 480F. For high-temperature applications up to 750F and 5 amps, a high-temperature mechanism is offered. (www.clark-reliance.com)

Tighten up your LOTO procedures Lock-out/tag-out systems work on the principle of individually keyed padlocks and keys that workers can use to lock off machinery or controls. The locked machinery or controls then cannot be operated while the worker might be at risk due to their use. Usually used during machinery maintenance, this simple, reassuringly mechanical method of improving personal safety is as reliably ef-fective as it is straightforward.

Industrial safety specialist Castell Iso-Lok has developed a new Multi-Clasp padlock for LOTO procedures. The new lock features a standard fixed-width hasp shape and now sports a highly visible, safety-color-coded, polyester powder-coated finish.

The new Multi-Clasp has room for six individual padlocks to be attached, allowing multiple workers to lock off the same machine. The lock will not open until each separate padlock has been removed. This ensures that the locked-off equipment cannot be reactivated until everyone has completed their work and safe operation can resume. (www.castell.com)

Wireless machinery health transmitters Emerson Process Management recently unveiled the CSI 9420 Machinery Health Transmitter. This wireless vibration transmitter provides monitoring of mechanical equipment delivering predictive diagnostics for improved reliability and plant safety.

As a component of Emerson’s Smart Wireless solutions, the rugged industrial trans-mitter connects quickly, easily, and economically to any machine. Through Emerson’s PlantWeb digital plant architecture, the transmitter delivers vibration information over a highly reliable wireless self-organizing network for use by operations and maintenance personnel. Configuration, diagnostics, and alerts from the wireless vibration transmitter are available in AMS Suite predictive maintenance software. Vibration data are also available in data historians or any control system for trend-ing and analysis with other process parameters. In addition to measuring overall vibration, the CSI 9420 Machinery Health Transmitter includes PeakVue technol-ogy for advanced bearing diagnostics.

The wireless vibration transmitter will be available for shipment in early 2008. (www.emersonprocess.com)

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JOURNEYMAN LINEMAN

North Slope Borough Power & LightCity of Barrow, Alaska$75,000 + annually, + benefi ts

North Slope Borough Power & Light is seeking qualifi ed applicants for the po-sition of Journeyman Lineman. NSB Power & Light operates and maintains seven power plants located on the north slope of the Brooks Range. The vil-lages we serve are Anaktuvuk Pass, Atqasuk, Kaktovik, Nuiqsut, Point Hope, Point Lay, and Wainwright – approx. 1200 customers total. Diesel fi red power plants with < 2MW capacity, each. 4160/7200 and 7200/12470 volt transmis-sion systems. This position installs, repairs, and maintains high voltage electri-cal distribution systems using a work order/call out program. The Journeyman Lineman reports directly to the Power Systems Manager.

Requirements are a State of Alaska Fitness card for Journeyman Lineman or equivalent, from your state. A valid Commercial Drivers License and fi ve years of electrical lineman work as a journeyman or fi rst class lineman. Arctic experi-ence preferred.

Position is open until fi lled

Send resumes to:North Slope Borough Power & LightPO Box 69Barrow, Alaska 99723-0069

Attn: Jerry Cogdill, Power Systems [email protected]

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

Sanford Rose Associates265 Main St. Akron OH. 44308

888-333-3828 • Fax [email protected]

Best Recruiters in Power!

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Sheppard T. Powell Associates, LLC, Baltimore, MD, is seeking experienced professionals with a BS or MS degree in engineering/science for a career pro-viding unbiased water treatment consulting services to various industries. Must have a solid understand-ing of water chemistry and be highly experienced in the power and/or pulp and paper industry. Experience with fl ue gas desulfurization (FGD) systems, boiler and HRSG steam/water cycle chemistry, chemical cleaning, inspections, makeup water treatment, cool-ing water treatment, and/or wastewater treatment is preferred. Must be capable of working independently, demonstrate good verbal and written communica-tions skills and be willing to travel. Will involve internal inspections of boiler/HRSG drums, deaerators, and condensers. Must have current United States pass-port. Fax (410-327-7506) or email ([email protected]) resumes and salary requests.

CONSULTANT/ENGINEER

REQUEST FOR QUALIFICATIONSDESIGN-BUILD REFURBISHMENT OF A REFUSE

DERIVED FUEL RESOURCE RECOVERY FACILITYRFQ NO. 08-207/SB

The Solid Waste Authority of Palm Beach County, Florida (Authority) is requesting the submittal of qualifi cations for the design-build refurbishment of its 1,800 ton per day refuse derived fuel North County Resource Recovery Facility. The planned procurement consists of this Request for Qualifi ca-tions (RFQ), with a resulting pre-qualifi cation of fi rms, and a Request for Proposals (RFP) to the pre-qualifi ed fi rms. It is anticipated that pre-qualifi ed fi rms will have an opportunity to comment during formation of the subsequent RFP procure-ment document.

The RFQ document will be available Monday through Fri-day, 8:00 am - 5:00 pm, beginning on Wednesday, October 31, 2007 at the Authority’s Administrative Offi ces, 7501 North Jog Road, West Palm Beach, FL 33412. Interested fi rms may also call 561-640-4000 ext. 4527 to obtain a copy or with any questions.

There will be a non-mandatory pre-submittal conference fol-lowed by a site visit on Wednesday, November 14, 2007, 9:00 am at the Authority’s Administrative Offi ces open to all interested parties.

The Authority will receive the Statements of Qualifi cation (SOQ) at the above address until 5:00 pm on Wednesday, Janu-ary 2, 2008. Sealed submittals shall be plainly marked “RFQ No. 08-207/SB Refurbishment of NCRRF. SOQ received after said time will be returned unopened.

Minority/Women/Small Business Enterprise (M/W/SBE) fi rms are strongly encouraged to participate as prime contractors or suppliers/subcontractors to primes.

REQUEST FOR QUALIFICATIONS

Wood Harbinger, a consulting engineering firm located in Bellevue, WA seeks a Senior Level Mechanical Engineer for its Industrial Division.The candidate shall be experienced in industrial plant environments with field experience in power and thermal generation, process and infrastructure systems. Responsibilities would include conceptualizing the mechanical design solutions for major projects; planning, scheduling, and conducting mechanical engineering work; and supervising/leading the design and ongoing progress of a project, including coordinating with other disciplines.

Bachelor of Science in Mechanical Engineering and/or registered Professional Engineer 12-18 years of experience in the industry as a Mechanical Engineer/Designer Good communication skills, both written and verbalTo submit your resume, please visit:

woodharbinger.com/careers.aspxAffirmative Action/Equal Opportunity Employer

•

•

•

•

Senior Level Mechanical Engineer

POWER SYSTEMS MANAGER

North Slope Borough Power & LightBarrow, Alaska(Salary: $64,313 - $80,391 annual DOQ plus benefi ts)

North Slope Borough Power & Light is seeking qualifi ed applicants for the posi-tion of Power Systems Manager. NSB Power & Light operates and maintains seven power plants located on the north slope of the Brooks Range. The vil-lages we serve are Anaktuvuk Pass, Atqasuk, Kaktovik, Nuiqsut, Point Hope, Point Lay, and Wainwright -approximately 1200 customers total. Diesel fi red power plants with <2 MW capacity, each. Annual Enterprise Fund operating budget of $12.5 million. The division has 45 full time employees. This position is responsible for the overall management and administration functions of the division including operations, planning, fi nancial management, regulatory com-pliance and personnel. The Power Systems Manager reports directly to the NSB Utility Manager.

Requirements are a Bachelor’s degree in Operations Management, Business Administration or related fi eld; or fi ve years of work experience in related indus-try in an arctic environment; or an equivalent combination of education and/or experience. Five years of work experience with Federal, State and Local laws, regulatory and procedures relating to the Electric Power Utility industry. Ability to obtain Alaska Drivers License is required.

Send resume to: North Slope BoroughDepartment of Public WorksPO Box 69Barrow, AK 99723

Attn: John Miller, Deputy DirectorUtilities/CIPM

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

Plant DocumentationFossil/GT/CC/SCR

Rapid Turnaround, Low OverheadOperating Procedures, Turnover Sets, Training

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Classifi ed AdvertisingMyla Dixon

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http://www.powerindustrycareers.com


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READER SERVICE NUMBER 206


George H. BodmanPres. / Technical Advisor

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

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POWER PLANT BUYERS’ MART



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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,

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11-07 Power Classified.indd 9111-07 Power Classified.indd 91 11/8/07 12:07:03 PM11/8/07 12:07:03 PM

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ReaderServiceNumber

ABB Inc.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 . . . . .18 www.abb.com

Alstom Power SA. . . . . . . . . . . . . . . . . . . . . . 19 . . . . .10 www.alstom.com

Ansaldo Caldaie. . . . . . . . . . . . . . . . . . . . Cov 3 . . . . .33 www.ansaldoboiler.it

AP&M. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 . . . . . .5 www.apm4parts.com, www.apmfieldservices.com

AREVA NP . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 . . . . .26 www.us.areva.com

Babcock & Wilcox . . . . . . . . . . . . . . . . . Cov 4 . . . . .34 www.babcock.com

Bechtel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 . . . . .12 www.bechtel.com

Black & Veatch . . . . . . . . . . . . . . . . . . . . . . . . 7 . . . . . .3 www.bv.com

Cablesafe Hooks . . . . . . . . . . . . . . . . . . . . . . 20 . . . . .11 www.cablesafe.com

CD-Adapco . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 . . . . .14 www.cd-adapco.com

Coade, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 . . . . .30 www.coade.com

Day & Zimmermann . . . . . . . . . . . . . . . . . . . . 13 . . . . . .7 www.dayzim.com

Diamond Power International . . . . . . . . . . . 57 . . . . .28 www.diamondpower.com

Eimco Water Technologies . . . . . . . . . . . . . 55 . . . . .27 www.glv.com

ExxonMobil. . . . . . . . . . . . . . . . . . . . . . . . Cov 2 . . . . . .1 www.exxonmobil.com

Fisher/Emerson . . . . . . . . . . . . . . . . . . . . . . . . 9 . . . . . .4 www.fisher.com/nP

General Electric . . . . . . . . . . . . . . . . . . . . . . . . 5 . . . . . .2 www.ge.com/energy

General Physics . . . . . . . . . . . . . . . . . . . . . . . 58 . . . . .29 www.gpilearnwbt.com

Hitachi Power Systems . . . . . . . . . . . . . . . . 39 . . . . .20 www.hitachi.com

IGAPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34, 35 . . . . .19 www.investingalicia.com

Intek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 . . . . .31 www.intek.com

Luminant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 . . . . .13 www.luminant.com

Magnetrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 . . . . . .8 www.magnetrol.com

Martin Engineering . . . . . . . . . . . . . . . . . . . . 48 . . . . .24 www.martin-eng.com

Orion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 . . . . .25 www.orioninstruments.com

Power Systems Mfg. . . . . . . . . . . . . . . . . . . . 11 . . . . . .6 www.powermfg.com

ProEnergy Services . . . . . . . . . . . . . . . . . . . . 47 . . . . .23 www.proenergyservices.com

Schmidt Industries . . . . . . . . . . . . . . . . . . . . 25 . . . . .15 E-mail: [email protected]

Solvay Chemicals . . . . . . . . . . . . . . . . . . . . . 45 . . . . .22 www.solvaychemicals.us/solvair

Superbolt, Inc. . . . . . . . . . . . . . . . . . . . . . . . . 26 . . . . .16 www.superbolt.com

The Shaw Group . . . . . . . . . . . . . . . . . . . . . . 67 . . . . .33 www.shawgrp.com

United Brotherhood of Carpenters . . . . . . . 43 . . . . .21 www.carpenters.org

Westinghouse Electric . . . . . . . . . . . . . . . . . 27 . . . . .17 www.westinghousenuclear.com

Yuba Heat Transfer . . . . . . . . . . . . . . . . . . . . 17 . . . . . .9 www.yuba.com

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

Page

ReaderServiceNumber Page

CLASSIFIED ADVERTISINGPages 88-93. To place a classified ad, contact: Myla Dixon, POWER magazine, 832-242-1969,

[email protected].

Statement of Ownership, Management, and Circulation (Requester Publications Only)1. Publication Title: POWER 2. Publication Number: 0032-5929 3. FilingDate:10/1/2007 4. Issue Frequency: Monthly 5. Number of Issues Published Annually: 126. Annual Subscription Price $59. 7. Complete Mailing Address of Known Office ofPublication: Access Intelligence, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 8. Complete Mailing Address of Headquarters or General Business Office ofPublisher: Access Intelligence, LLC, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 9. Full Names and Complete Mailing Addresses of Publisher, Editor, and Managing Editor: Publisher: Brian K. Nessen, 11000 Richmond Avenue, Suite 500, Houston, TX 77042 Editor: Dr. Robert Peltier, 7253 S. Terrace Lane, Tempe, AZ 85283 Managing Editor: Gail Reitenbach, 35 Carissa Road, Sante Fe, NM 87508 10. Owner if the publication is owned by a corporation, give the name and address of the corporationimmediately followed by the names and addresses of all stockholders owning or holding 1 percent or more of the total amount of stock: Veronis Suhler Stevenson, 350 Park Avenue, New York, NY 10022 11. Known Bondholders, Mortgagees, and Other Security HoldersOwning or Holding 1 Percent or More of Total Amount of Bonds, Mortgages, or other Securities: None 12. Not Applicable. 13. Publication: POWER 14. Issue Date for Circulation Data: September 2007

Average No. of No. Copies 15. Extent and Nature of Circulation: Copies Each Issue of issue

During Preceding Nearest to12 Months Filing Date

a. Total Number of Copies (Net press run) 57,879 62,773 b. Legitimate Paid and/or Requested Distribution(1) Individual Paid/Requested Mail Subscriptions 55,039 60,050(2) Copies Requested by Employers 0 0(3) Sales Through Dealers and Carriers, Street Vendors 0 0(4) Requested Copies Distributed by Other Mail Classes 0 0 c. Total Paid and/or Requested Circulation 55,039 60,050 d. Nonrequested Distribution (By Mail and Outside the Mail)(1) Nonrequested Copies, Sample copies, Requests Over 3

years old, Requests induced by a Premium, Bulk Sales and Requests including Associate Requests. Names obtained from Business Directories, Lists, and other sources) 2,280 2,598(2) Nonrequested Copies Distributed Through the USPS by Other Classes of Mail 0 0(3) Nonrequested Copies Distributed Outside the Mail (Include Pickup Stands, Trade Shows, Showrooms, and Other Sources) 560 125e. Total Nonrequested Distribution 2,840 2,723f. Total Distribution (Sum of 15c and 15e) 57,879 62,773g. Copies not Distributed 0 0h. Total 57,879 62,773i. Percent Paid and/or Requested Circulation 95.1% 95.7%16. Publication of Statement of Ownership for a Requester Publication is required and will be printed in the November 2007 issue.17. Signature of Owner: Don Pazour Date: 10/1/07I certify that all information furnished on this form is true and complete. I understand that anyone whofurnished false or misleading information on this form or who omits material or information requested on theform may be subject to criminal sanctions (including fines and imprisonment) and/or civil sanctions (includingcivil penalties).

094 AdIndex.indd 94094 AdIndex.indd 94 11/5/07 4:54:41 PM11/5/07 4:54:41 PM

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094 AdIndex.indd 95094 AdIndex.indd 95 11/5/07 4:54:42 PM11/5/07 4:54:42 PM




LEGAL & REGULATORYCOMMENTARY

During my 30-year career at the American Public Power Association (APPA), I’ve had a front-row seat for most of the major events in our industry’s recent history. So

it disturbs me when my view of our history is 180 degrees out of phase with how others perceive it. Such was the case with the preamble to the Federal Energy Regulatory Commission’s (FERC’s) June 2007 notice of proposed rulemaking (NOPR) to improve the operation of centralized wholesale power markets run by regional transmission organizations (RTOs).

I find the commission’s view of history clouded by “compe-tition-colored” glasses. In an apparent effort to buttress its policies promoting centralized spot markets, the commission misstates history—in particular the U.S. Congress’s rationale for passing the Public Utility Regulatory Policies Act of 1978 (Purpa). In the world according to FERC, the enactment of Purpa was the first hug in Congress’s 30-year embrace of competition as national policy for bulk power markets.

Today, Congress attaches fanciful names to legislation in an attempt to convey the bill’s purpose: No Child Left Behind, for example. In the 1970s, sponsors were much more direct. Bills generally contained a statement of congressional purpose. In Purpa’s case, it was “conservation of energy supplied by electric utilities; the optimization of the efficiency of use of facilities and resources by electric utilities; and equitable rates to electric consumers.” That was in keeping with the Carter administration’s national energy policy, which emphasized en-ergy conservation and efficiency in response to the Arab oil embargo of 1973–1974.

Less than 20/20 hindsightPurpa broke the utility stranglehold on generation and spawned the cogeneration movement, but it did so to promote conserva-tion and efficiency, not competition. Purpa did include a wheel-ing (direct sales) provision that could be viewed as promoting competition at the wholesale level. However, it actually stifled it. FERC subsequently described its authority under this provision as so limited as to be “virtually ineffective.” And in allowing utili-ties to wheel power, Congress expressly prohibited any wheeling orders that would upset existing competitive relationships.

FERC’s view of history is equally skewed when it comes to more recent events. For example, the commission pointed out that by 2000, 24 states and the District of Columbia had opted for some form of electricity restructuring—without mentioning that this trend has peaked and that dozens of states are now reconsider-ing rolling back deregulation.

The commission also conveniently failed to note that both the House and Senate were poised to kill FERC’s standard market design (SMD) rulemaking in the Energy Policy Act of 2005—an extraordinary step—and dropped anti-SMD provisions only after the commission itself terminated the rulemaking. Those moves may not represent a rejection of wholesale competition, but they

should not be construed as an endorsement of competition in RTO organized markets, either.

Competition in name onlyCongress recognized what FERC does not: that the complex cen-tralized spot markets run by RTOs do not automatically foster com-petition. As APPA pointed out in its comments on the June 2007 NOPR, FERC conflates two very different things: past congressional actions it claims were intended to foster wholesale competition and the specific design of RTO-run centralized markets.

Harvard professor William Hogan, widely considered the father of RTO-run centralized markets, said in his comments to the NOPR that the basic design of the centralized RTO-run markets “assumes a workably competitive market without material monopoly power in ownership and operation of generating facilities.” Aren’t elec-tricity markets important enough to warrant reforming them on the basis of something better than assumptions like those? Now that we have several years of experience with RTO markets, we should be testing the assumptions’ validity.

APPA has commissioned research to test those and other as-sumptions about market performance. Among other things, the research has found that studies claiming that RTO markets ben-efit consumers are not credible, that some companies are making huge profits selling into the RTO markets, and that rising natural gas prices are not the sole cause of high electricity prices. Al-though all of our research was filed with FERC, none of it was mentioned in the NOPR. Can FERC really believe that higher elec-tric bills are entirely due to higher gas prices, despite clear evi-dence to the contrary?

Broaden the inquiryAll this would seem to be enough reason for FERC to launch a broad investigation into the performance of the centralized mar-kets, rather than the narrow inquiry into four specific issues that the NOPR proposes: (1) the role of demand response in organized markets; (2) increasing opportunities for long-term power con-tracting; (3) strengthening market monitoring; and (4) the respon-siveness of RTOs and independent system operators to customers and other stakeholders. At a recent PJM forum on long-term con-tracting, three state government representatives separately of-fered the same warning: The proponents of these markets need to fix them so that consumers, not just suppliers, begin to see benefits, or else states will begin taking drastic actions.

In its 2004 report, “Restructuring at the Crossroads: FERC Elec-tric Policy Reconsidered,” APPA recommended that FERC find a way to make RTOs a boon, rather than a bane, to consumers. That would be a good place to start trying to fix the centralized markets. We won’t get there if we misread our industry’s recent history and ignore the problems in our current wholesale market structure. ■

—Alan H. Richardson is president and CEO of the American Public Power Association (www.appanet.org).

Centralized markets are failing consumersBy Alan H. Richardson

096 Commentary.indd 96096 Commentary.indd 96 11/5/07 4:26:27 PM11/5/07 4:26:27 PM

http://www.appanet.org


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