power international november 2013

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Vol. 157 • No. 11 • November 2013

Top Plants: Three Exemplary Nuclear Plants

South Korea Works to Meet Supply Challenges

V.C. Summer Construction Update

Water Management Plans Have Multiple Benefits

01_PWR_110113_Cover.indd 1 10/14/13 7:18:17 AM

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November 2013 | POWER www.powermag.com 1

ON THE COVERFuel channel and calandria tube replacement at Bruce Nuclear Generating Station in On-tario—the “detube-retube” project—was deemed critical path and set the pace for the restart project. First-of-a-kind remote-controlled tooling was used to cut out the original components, which were radioactive from years of service. The new components were installed manually by workers inside the reactor vaults. These fuel channel assemblies, approximately 12 meters long, hold the reactor’s uranium fuel bundles during operation. Courtesy: Bruce Power

COVER STORY: NUCLEAR TOP PLANTS24 Bruce Nuclear Generating Station, Kincardine, Ontario, Canada

With refurbishment of Units 1 and 2, Bruce Power completed the return to full opera-tion of the Bruce Nuclear Generating Station—largest operating nuclear plant in the world. Along the way, it successfully logged numerous first-of-a-kind engineering accomplishments and transformed its workforce through new hiring and training.

26 Turkey Point and St. Lucie Nuclear Plants, FloridaThe most recent nuclear capacity addition to Florida Power & Light’s fleet was to Unit 4 at its Turkey Point plant, capping a four-unit, five-year, ~$3 billion dollar uprate pro-gram that added 500 MW of capacity. It is arguably the largest U.S. nuclear project to be completed in recent history.

30 Waterford 3 Steam Electric Station, Killona, LouisianaA steam generator replacement project at a nuclear plant is a major undertaking—one that Entergy carefully planned for. In spite of equipment delivery, weather, and workforce challenges, the work was completed safely and under budget.

SPECIAL REPORT: POWER POLICY32 South Korea Walks an Energy Tightrope

Extensive power development and 100% electrification have made South Korea a powerful trading nation. Recently, however, dangerously low reserve margins, scan-dals involving safety-related nuclear plant parts, and somewhat conflicting goals of generation expansion and green growth have put the nation’s ability to remain a strong economy in jeopardy.

10/2/2013 9:13:26 AM

Established 1882 • Vol. 157 • No. 11 November 2013

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More Online You’ll find fresh stories throughout the month on powermag.com, including news stories and other digital-only content. In case you missed them, here are the stories that went out in the September/October COAL POWER Direct eletter:

Electrical Area Classification in Coal-Fired Power Plants• EIA: Four U.S. Coal Companies Supplied Over Half of 2011 • U.S. CoalWorld Coal Association Promotes Practical Steps to Combat • Climate ChangeCarbon Dioxide and the Fundamentals of Heat Transfer• Federal Court Orders EPA to Move on Final Coal Ash Rule• AEP Opts to Retire Tanners Creek 4 in Lieu of Refueling With • Natural Gas

02_PWR_110113_TOC_p1-5.indd 1 10/14/13 9:47:54 AM

www.powermag.com POWER | November 20132

FEATURES NUCLEAR42 V.C. Summer Nuclear Station Construction Update

The two new nuclear units being built in South Carolina represent roughly half of the new nuclear capacity currently under construction in the U.S., so the excitement over major progress there is understandable.

48 Luminant Tests First Nuclear Industry Large-Scale Wireless Monitoring SystemGet the details on a pilot program to evaluate a wireless, automated, remote diag-nostic system to monitor generation-critical machinery at Luminant’s Comanche Peak Nuclear Power Plant that could point the way to the next industry best practice.

WATER MANAGEMENT52 Why Your Power Plant Needs a Water Management Plan

Most generators are keenly aware of water flows into and out of their power plants. But closer attention to water flows within your plant can also have multiple benefits. Here’s a simple plan for gaining greater insight into in-plant water use.

COAL PLANT O&M54 Reducing Bottom Ash Dewatering System Maintenance

When an Xcel Energy plant struggled with time-consuming and productivity-sapping maintenance problems with its bottom ash dewatering system, it looked for and found a solution that is saving money, time, and headaches.

DEPARTMENTS SPEAKING OF POWER6 Are All Your Eggs in One Basket?

GLOBAL MONITOR8 France to Fund Nuclear Reduction with Carbon Tax8 Giant Wind Power Sockets Installed in the North Sea10 First Megawatt-Scale Isothermal CAES Completion 12 THE BIG PICTURE: Reactor Outages 14 Study: Wind Power Curtailment More Cost-Efficient Than Storage16 POWER Digest

FOCUS ON O&M18 New Design Solves Scaling Problems on Geothermal Control Valves

LEGAL & REGULATORY22 Beyond the Renewable Portfolio Standard

By Thomas Overton, JD

57 NEW PRODUCTS

COMMENTARY64 Natural Gas Is Ready Now to Power Emerging Markets

By Paul Smith, senior director of infrastructure, America’s Natural Gas Alliance

Connect with POWERIf you like POWER magazine, follow us online (POWERmagazine) for timely industry news and comments.

Become our fan on Facebook Follow us on Twitter

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SPEAKING OF POWER

Are All Your Eggs in One Basket?

As we announce Top Plant award win-ners in the nuclear category this month, the global nuclear power

industry is at an unusual point in its his-tory: mired in controversy and caution, yet championed by an unexpected group of new fans.

Even while many are rightfully con-cerned about avoiding another disaster on the scale of the Fukushima nuclear ac-cident, others see nuclear power as the world’s best available control technology for addressing climate change concerns. In fact, that was a major theme of a re-cently released movie.

Pandora’s PromisePandora’s Promise consists largely of interviews with a handful of individu-als who have shifted from holding an-ti-nuclear views to pro-nuclear ones, essentially because they now see climate change resulting from fossil fuel use as a larger threat than the potential threat of any danger resulting from carbon-free nuclear power generation. I saw the movie, and though it is a welcome coun-terbalance to more typical anti-nuclear movies, it, too, suffers from a one-sided message that, for example, minimizes the costs involved and long-term waste storage challenges.

Ironically, just when many “tradi-tional” environmentalists are backing nuclear as a climate-saving generation technology, it appears that economics (which are chilling for existing and fu-ture U.S. plants), safety scandals (cov-ered in Associate Editor Sonal Patel’s special report on South Korea in this issue, as well as previous articles on safety lapses involving Japanese reac-tors), and power policies (most recently, in Germany and France) are pushing in the opposite direction.

The Sole-Source PromiseWhile some enviros are bullish on nucle-ar power, others remain firmly opposed to fission. The end of August brought a press release to my inbox from members

of the European Delegates’ Assembly of EUROSOLAR, who had adopted and signed a resolution calling not just for “a European renewable energy framework” but also a policy focused on “achieving an energy future entirely founded on renewable energy sources” consisting of “wind, sun and biomass.” Aside from the fact that one should always take statements from industry groups with a large grain of salt, the final state-ment—“The EU must end its practice of exporting obsolete fossil and nuclear technologies”—struck me as particularly impractical. Unlike automobiles overtak-ing horse and buggy, fossil and nuclear power generation technologies are far from obsolete and are still needed to back up intermittent renewable genera-tion in most places (the press release made no mention of energy storage or even baseload geothermal energy).

Despite what the most strident lobby-ists for each generation fuel and tech-nology would have the public believe, no single fuel can solve all of our global energy problems, and no energy technol-ogy is completely environmentally be-nign. A balanced generation portfolio, on the other hand, can both optimize benefits and mitigate risks. What con-stitutes “balance” will vary over time and by location. Today, for example, the balance for very small islands might consist of wind and solar plus energy storage, with diesel generators for emer-gency backup.

Avoid Broken EggsPresident Obama has been maligned by all sides for his “all of the above” comments about energy sources, and to some, the administration’s policy looks like “none of the above” for power gen-eration (except maybe natural gas). However, there is merit to the concept, and the president’s energy slogan is one long used by the financial services in-dustry. When it comes to retirement sav-ings, you shouldn’t put all your eggs in one basket, especially not in the stock

of a single industry or company. Simi-larly, the history of the power industry shows that grids that are overly reliant upon a single fuel can be especially vul-nerable when disaster strikes, as Japan has learned.

Just as we all should have a somewhat diversified retirement portfolio—with holdings in different proportions based upon our age as well as other personal factors—so too, most nations and re-gions benefit when they have a diversi-fied generation fleet. That’s why even in my windy and sunny part of New Mexico, neighbors with solar panels on their property remain connected to a grid fed by a mix of fuels. ■

—Gail Reitenbach, PhD is editor of POWER. Follow her on Twitter @GailReit

and the editorial team @POWERmagazine.

Meet Our New Associate EditorAaron Larson joined the POWER team in late September as an associate editor. Having worked at commercial nuclear, biomass, and coal power plants, he gained significant operations, mainte-nance, safety, financial, and manage-ment experience. He has also served in the U.S. Navy. Though Aaron will be mostly focused on plant operations and maintenance stories, he will be involved with a wide variety of topics and tasks on all of our platforms. You can reach Aaron and all the editors at [email protected].

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03_PWR_110113_SOP_p6-7.indd 7 10/14/13 10:10:57 AM


Westinghouse AP1000 plant under construction in Sanmen China

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France to Fund Nuclear Reduction with Carbon TaxFollowing the election of President Fran-cois Hollande in 2012, France has engaged the public in a series of regional and web-based debates to pin down key tenets of its so-called “energy transition.” The country—which lacks indigenous energy resources and derives more than 75% of its electricity from 58 nuclear reactors—is considering capping nuclear’s share in its new energy mix at 50% and vastly increas-ing the share of renewables.

But, though the transition plan is publicly popular, a French parliamentary commission has warned that the coun-try risks being exposed to a power price shock if it too speedily reduces its reli-ance on nuclear. This September, during a two-day conference that concluded public debate, Prime Minister Jean-Marc Ayrault acknowledged the energy transition could prove costly. However, France is currently spending $5.4 billion per year to fund re-newables and $1.3 billion on energy ef-ficiency measures, he said. The remainder, he announced, would be funded by a new carbon tax on fuel consumption that was expected to amount to $1.3 billion per year by 2016 in addition to an unspeci-fied contribution from profits gained by the country’s nuclear plants.

The new tax to be levied on all fossil fuels in proportion to the emissions they generate, called the “climate contribu-tion,” is expected to be adopted under the 2014 energy and finance act. At the same time, France’s Economic, Social and

Environmental Council (ESEC) has pro-posed to lower the value added tax (VAT) to lighten the country’s tax burden, which some observers say is already stretched to the limit.

“Everything will be done to lower production costs” for wind and solar, President Hollande told attendees at the September conference. Though he did not elaborate on how the country will embark on reducing nuclear’s share, beyond the planned shuttering of the Fessenheim plant, he said renewables should be in-centivized so that “every euro paid by consumers is the most efficient possible and will favor the creation of national in-dustrial champions.” Hollande also noted that feed-in-tariffs “can lead to a waste of public funds, profit-taking and specu-lative behavior.”

Meanwhile, documents published by ESEC charting the energy transition be-tween 2020 and 2050 call for “an electric-ity service with lower production costs in the mix,” one that will take into account “all energy sources.” After 2020, ESEC calls for the attachment of a “meaningful price to carbon” and “clarity and transparency” of the carbon tax. The country should also invest and expand research and develop-ment in other clean technologies, includ-ing the exploration of all options for the “recovery and conversion of carbon diox-ide, including capture and storage.”

Giant Wind Power Sockets Installed in the North SeaA tremendous amount of offshore wind capacity—from 100 MW to 13,000 MW—is expected to play a major role in Ger-many’s transition to sourcing 80% of its power from renewables by 2050. However, Energiewende—the country’s energy trans-formation—has often been hampered by disruptions to the connection of offshore wind parks in the North Sea, stemming from delays in planning and building. This August, to the relief of grid operator Ten-neT, which bought the 11,000-kilometer-long grid network from E.ON in 2011 and has been tasked with connecting all wind parks in the North Sea, the infrastructure for connecting offshore wind farms has fi-nally begun to take shape.

On Aug. 26, ABB installed the DolWind1 offshore wind connector platform—what it says is the “world’s highest-voltage off-shore converter station” in the North Sea.

The 320 kV station has an 800-MW power transmission capacity and will convert al-ternating current from three wind farms off the coast of Germany into high-voltage direct current (HVDC) for transmission to the mainland. And on the same day, Sie-mens Energy finished installing the 576-MW HVDC HelWin1 offshore platform, also in the North Sea, to link two offshore wind farms—Nordsee Ost and Meerwind—to the mainland (Figure 2).

The projects stem from separate con-tracts awarded in 2011 to the companies by TenneT: ABB received a $1 billion or-der, and Siemens a $710 million order. Sie-mens and Prysmian are also implementing a number of other connection projects: HelWin2 off of Helgoland, BorWin2 off of Borkum, and SylWin1 off of Sylt. For ABB, delays to DolWin1 led to charges of $50 million last year. The company is mean-while readying the DolWin2, a 900-MW offshore connection, for commissioning in 2015.

The installation of both platforms was challenging. ABB says the 9,300 metric ton DolWin 1 platform, including the con-verter station, was transported offshore by barge 75 km around the German coast. Then it was lifted by the world’s largest crane vessel, Thialf, and positioned on top of the already installed jacket. “Putting such a huge platform in place is one of the most delicate operations in the delivery of an offshore transmission link, requiring

1. Vessel of change. France has em-barked on a transition to reduce the share of nuclear power in its electricity mix from the current 75% to 50% by 2050. It is unclear if the country will proceed with plans for new reactors. One much-watched project is the construction of an AREVA 1,650-MW EPR unit at an existing two-unit plant at Flaman-ville, Normandy (shown here), which recently received its reactor vessel. Courtesy: AREVA

2. A marine socket. When HelWin1, the first offshore converter platform in the North Sea goes online in 2014, it will link the offshore Nordsee Ost and Meerwind wind farms and convert power from up to 576 MW of capacity at offshore wind farms to direct current (DC) and transmit it via submarine cable to the German mainland about 85 ki-lometers (km) away. The DC power will then be converted back into alternating current at a converter station on land. The floating jack-up platform weighs about 11,000 tons and was towed around the northern tip of Denmark in a seven-day journey that covered 990 km. Courtesy: Siemens

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strong cooperation between the many stakeholders involved” said Brice Koch, head of ABB’s Power Systems division.

For Siemens, transport of the HelWin1 platform took seven days, plus four additional days to install it 22 meters above sea level to protect it against giant waves. The 75-m by 50-m surface of the platform features a helipad, and it has seven decks to ac-commodate 16 cabins for crew members. Both projects are now expected to be fully commissioned in 2014.

First Megawatt-Scale Isothermal CAES Completion SustainX in September completed construction of what it says is the world’s first megawatt-scale isothermal compressed air energy storage (ICAES) system. The system at the company’s headquarters in Seabrook, N.H. (Figure 3), essentially takes electricity from the grid and uses it to drive a motor that compresses air and stores it isothermally, or at near constant temperature.

The project marks an important development for compressed air energy storage (CAES). Since commissioning of the only two existing CAES plants in the world—the 290-MW Huntorf plant in north Germany in 1978 and the 110-MW Alabama Electric Corp. plant in McIntosh, Ala., in 1991—CAES developments have been rare. One reason for this is that setting up a CAES facility is pricey and requires finding a geologic formation that can support it. For example, both the German and Alabama plants store compressed air in mined salt caverns.

CAES plants work like big batteries. Electric motors drive com-pressors that compress air (at perhaps 1,100 psi) into an un-derground geologic formation during off-peak hours. When the

electricity is needed most, the precompressed air (essentially replacing the compressor in a traditional combustion turbine) is used in modified combustion turbines to generate electric-ity. Natural gas or other fossil fuels are still required to run the turbines, but the process is more efficient because it uses up to 50% less natural gas than standard production, according to Sandia National Laboratories. However, the efficiency of the 320-MW plant in Huntorf is about 42% and that of the McIntosh plant is 54%—20 percentage points lower than conventional pumped storage plants.

What lowers the efficiency of those plants is that the air that heats up during compression must be cooled down to ambient temperature before it can be stored. Then, the cold air must be reheated for discharge of the storage facility because it cools tre-mendously when expanding in a turbine for power generation.

That is why CAES technology developers have been assessing how to best develop approaches to store that heat generated during compression, which can considerably improve the efficiency of the system if it is used during expansion. Germany’s RWE, for example, is developing an “adiabatic” process for its ADELE-Stassfurt project, which is in its initial one-year project phase. That project compress-es air at times of high electricity availability and places resulting heat in an interim heat-storage facility while injecting the air into subterranean caverns. The heat-storage facilities are up to 40-me-ter-high containers with beds of stones or ceramic molded bricks through which the hot air flows. A demonstration plant expected to have a storage capacity of 360 MWh could probably go online in 2016 at the earliest, says RWE, which is backed by the German Aerospace Centre and the federal ministry for economics.

SustainX’s ICAES system takes another approach. The sys-tem essentially captures the heat produced during compression, traps it in water, and stores the warmed air-water mixture in pipes. When electricity is needed back on the grid, the process

3. CAES in point. New Hampshire–based utility-grade energy storage technology firm SustainX in September started up its 1.5-MW isothermal compressed air energy storage (CAES) system, which uses power from the grid to drive a motor that compresses air to store it isothermally, or at near-constant temperatures. Courtesy: SustainX

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Average full outage hours per operating

reactor (2012)Note: Includes reactors shut down during 2012

(11 units).

Worldwideoperating reactors

by type (2012)

Type of full outage (2012)

Planned

Unplanned

External

At the end of 2012, 436 reactors were connected to the grid, according to the International Atomic Energy Agency's (IAEA's) PRIS database. Operating reactors had an average 2,239 full outage hours per reactor in 2012; about 15% of that time represented unplanned outages, caused by a variety of factors. Source: IAEA; Notes: BWR = boiling water reactor; FBR = fast breeder reactor; GCR = gas-cooled reactor; LWGR = light water cooled graphite moderated reactor; PHWR = pressurized heavy water reactor; PWR = pressurized water reactor. —Copy and artwork by Sonal Patel, associate editor

PWR BWR LWGRPHWR GCR FBR

<600 MWe

2,64

3

1,97

5

4,93

3

3,25

5

1,28

0

1,31

8

2,06

1

1,49

71,

540

Direct causes and energy lost (%)

during full outages globally

(2008 to 2012)

22347 10 74 26 23 15 17 1

Refuelling without maintenance

Major back-fitting, refurbishment or upgrading activities without refuelling

Major back-fitting, refurbishment, or upgrading activities with refuelling

Inspection, maintenance, or repair without refuelling

Other

Testing of plant systems or components

Inspection, maintenance, or repair with refuelling

Fire

Other

Fuel management limitation

Human-factor related

Regulatory requirements

Plant equipment problem/ failure

UNPLANNED FULL OUTAGES389 TWh lost

PLANNED FULL OUTAGES2,782 TWh lost

4%

62%1%

1%

6%

6%20%

1%8%

90%

<1%<1%

<1%

PWR FBR

PHWR

LWGR

GCR

BWR

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reverses and the air expands, driving a generator. According to the company, the isothermal gas compression is thermodynami-cally ideal—that is, it requires the least possible work—and by definition avoids temperature extremes. An isothermal expansion process is also ideal, recovering the most possible work from the compressed air.

However, while “perfectly isothermal” compression or expan-sion is not practical, the company says, a gas can be expanded or compressed near-isothermally if heat exchange occurs quickly enough relative to density change. That’s why the company uses an aqueous foam-based heat exchange in its ICAES system. The patented two-phase heat transfer process enables near-isother-mal gas expansion and compression between 1 atmosphere and 200 atmospheres with only two stages and at scales and speeds appropriate for large-engine reciprocating machinery, it says. “Rapid heat exchange between liquid and air has allowed de-velopment of a megawatt-scale compressor/expander with [more than] 95% isothermal efficiency over a large operating range and at large-engine stroke speed, keeping the temperature change of the liquid-air mixture to under 50C across the full operating range of the system,” it claims.

SustainX’s isothermal process was developed by the Thayer School of Engineering at Dartmouth College in 2007 with funding from the National Science Foundation Small Business Innovation Research Program plus equity investments from Polaris Venture Partners, Rockport Capital, and General Electric, as part of its GE Ecomagination Challenge.

Study: Wind Power Curtailment More Cost-Efficient Than StorageA new study from Stanford University suggests that, if the over-all amounts of fuel and electricity required to build and operate energy storage technologies are factored in, grid-scale batteries make sense for storing surplus solar energy, but not for wind.

The study published in the online edition of the journal En-ergy and Environmental Science compares the energetic costs of building and maintaining several emerging technology systems, including five battery types: lead-acid, lithium-ion, sodium-sul-fur, vanadium-redox, and zinc-bromine. In a previous study con-ducted by lead author Charles Barnhart, a postdoctoral scholar at Stanford’s Global Climate and Energy Project (GCEP), found that lead-acid batteries have the highest energetic cost and lithium-ion the lowest. “We calculated how much energy is used over the full lifecycle of the battery—from the mining of raw materials to the installation of the finished device,” Barnhart said. “Batteries with high energetic cost consume more fossil fuels and therefore release more carbon dioxide over their lifetime. If a battery’s en-ergetic cost is too high, its overall contribution to global warm-ing could negate the environmental benefits of the wind or solar farm it was supposed to support.”

What’s more, while wind turbines and photovoltaics were both found to deliver more energy than it takes to build and main-tain them, the scientists’ calculations showed that the overall energetic cost of wind turbines is much lower than that of con-ventional solar panels, which require energy from fossil fuels for processing silicon and fabricating other components. And when the energetic costs of curtailment—the practice of shutting down solar panels and wind turbines to reduce the production of surplus electricity on the grid—were compared to the energetic cost of grid-scale storage, the scientists found that the amount of energy required to create a solar farm is comparable to the

energy used to build each of the five battery technologies. The researchers’ calculations were based on a formula known as “en-ergy return on investment”—the amount of energy produced by a technology, divided by the amount of energy it takes to build and maintain that technology.

However, the results were quite different for wind farms (Figure 4). The scientists found that curtailing wind power reduces the energy return on investment by 10%. Storing surplus wind-gener-ated electricity in batteries results in even greater reductions—from about 20% for lithium-ion batteries to more than 50% for lead-acid batteries, they found. “Therefore, it would actually be more energetically efficient to shut down a wind turbine than to store the surplus electricity it generates,” said GCEP postdoctoral scholar Michael Dale, a coauthor of the study.

One way to improve the energetic performance of storage tech-nologies is to increase the cycle life of a battery, the scientists found. Conventional lithium-ion batteries last about four years, or 6,000 charge-discharge cycles. Lead-acid batteries only last about 700 cycles. To efficiently store energy on the grid, batteries must endure 10,000 to 18,000 cycles, said Barnhart. Another option is to use pumped hydroelectric storage. “Pumped hydro is used in 99% of grid storage today,” Barnhart said. “It works fantastically from an energetic perspective for both wind and solar. Its energy return on investment is 10 times better than conventional batter-

4. Stashing wind. Stanford scientists find in a new study that curtailing wind power reduces the energy return on investment by 10%, but storing surplus wind-generated power results in even greater reductions—from about 20% for lithium-ion batteries to more than 50% for lead-acid batteries. This image shows AES Energy Storage’s 2011-inaugurated Laurel Mountain energy storage project in Belington, W.Va., which provides frequency regulation in the PJM market to help manage the rapid rate of change in output that can occur with fluc-tuations in wind conditions. The Arlington, Va.–based company in Sep-tember began operation of a 40-MW grid storage resource at Dayton Power and Light’s gas-fired Tait Generating Station in Moraine, Ohio. Courtesy: AES Energy Storage

04_PWR_110113_GM_p8-17.indd 14 10/14/13 10:31:20 AM

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ies. But there are geologic and environmental constraints on where pumped hydro can be deployed.”

Meanwhile, according to Dale, storage is not the only way to improve grid reliability. “Energy that would otherwise be lost dur-ing times of excess could be used to pump water for irrigation or to charge a fleet of electric vehicles, for example,” he noted.

POWER DigestRusHydro Completes First Stage of New Far East Hydro Project. The RusHydro Group on Oct. 3 announced it had of-ficially completed the first stage of the 570-MW Ust’-Sredneka-nskaya hydropower plant on the Kolyma river in the Magadan region in the Far East of Russia. Ust’-Srednekanskaya plant is the second in the cascade of hydropower plants on the Kolyma River. With the first phase of two units (142.5 MW each) operat-ing with temporary Francis runners completed, construction that began in 1991 continues and is slated to wrap up in 2018. The next stage consists of increasing the water head from current to project level of 260 to 276.5 meters and commissioning of the third hydro unit. The plant is expected to provide energy for the developing mining operations in the region and to diversify power resources to the isolated region. About 95% of the region’s power demand was previously covered only by RusHydro’s Kolym-skaya hydropower plant.

Turkey Completes Privatization of Distribution Companies. Turkey in September completed privatization of its power distribu-tion sector, following the transfer of distribution company Toroslar Elektrik to the private sector. Finance Minister Mehmet Şimşek

said a total of $12.7 billion was gained by the government after the country’s 18 state-run companies were privatized. Enerjisa, a joint venture of Sabanci and Germany’s E.ON, acquired the two larg-est distribution grids, Ayedaş, which operates on the Asian side of Istanbul, and Toroslar Elektrik, operating in the Adana region in southern Turkey, for a total $3.457 billion. İşkaya Doğu paid $387 million for the acquisition of Dicle Elektrik (which operates in the southeastern provinces of Turkey), while Türkerler won the $188 million tender for Van Gölü Elektrik (Van Lake region).

Brazil Supreme Court Reverses Suspension of 1.8-GW Hydro Plant. Brazil’s Supreme Court in October reversed a Sep-tember 2013 decision by a federal court that suspended con-struction on the 1,800-MW Tele Pires hydropower project by Companhia Hidreletrica Teles Pires (CHTP). One of five large dams planned for the Teles Pires River, a major tributary of the Tapajós River in the heart of the Brazilian Amazon, the $2 billion Tele Pires hydropower project is now on track to come online by 2015. The federal court’s decision, issued in response to civil lawsuits filed by Brazil’s Federal Public Prosecutors’ Office, cited “unforgivable failures” in the environmental licensing of the dam. Judge Ricardo Lewandowski of the Supremo Tribunal Federal ruled in October, however, that CHTP had not breached the conces-sion rules and that delaying the project could cause significant economic damage to Brazil’s Mato Grosso and Para states. CHTP is a consortium of Neoenergia (50.1%), Eletrobras-Eletrosul (24.5%), Eletrobras Furnas (24.5%) and Odebrecht (0.9%).

Spain Plans New Centralized Nuclear Waste Storage Fa-cility. ENRESA, Spain’s state-owned company charged with the safe management, storage, and disposal of radioactive waste, in October said it would begin the construction of a new central-ized temporary storage facility (Almacén Temporal Centralizado, or ATC) in 2014. The installation will be located in Villar de Ca-ñas—a site preferred over Asco or Vandellos—and would have a storage capacity of 12,816 cubic meters. The company has set aside $120 million for the project, which could be commissioned in 2018. Spain has seven nuclear reactors that generate a fifth of its electricity. A general plan approved in 1999 to deal with ra-

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Lots of Energy in Comments About RenewablesThomas Overton’s article for GAS POWER Direct, “Renewable Intermittency Is Real” generated several online comments last month. It was also the most shared story for a time, proving yet again that although in 2012, according to the Energy Information Administration, wind provided just 3.46% and solar provided 0.11% of total U.S. generation, the very existence of those energy sources continues to generate a disproportionately high level of commentary—both pro and con.

04_PWR_110113_GM_p8-17.indd 16 10/14/13 10:32:44 AM


dioactive waste is based on nuclear power plant lives of 40 years and addresses the need to manage almost 200,000 cubic me-ters of low- and intermediate-level wastes and 10,000 cubic meters of spent fuel and other high-level wastes. ENRESA’s low- and intermediate-level waste storage facility is at El Cabril, Cordoba, and has operated since 1961.

Eskom Officially Reopens Coal Plant Mothballed Decades Ago. South African power utility Eskom on Sept. 24 officially reopened the six-unit coal-fired Grootvlei Power Station, which it had mothballed more than two decades ago when South Africa had surplus electricity capacity. The 1,200-MW Grootvlei plant in Mpumalanga is necessary because demand for power in South Africa has continued to soar over the years, Eskom said. The return to service of the Grootvlei plant began in 2004. After re-furbishment and reassembling, all the plant components were started up and returned to running condition. In July 2007, Groot-vlei’s Unit 1 was for the first time success-fully synchronized with the grid since it had been mothballed in August 1988. The other units were brought into commercial operation at intervals after that, and the station’s last unit to go into commercial operation was Unit 5 in July 2011.

USC Coal Plant Takes Shape in Morocco. Morocco’s Office National de l’Electricité et de l’Eau Potable (ONEE) and Safi Energy Co. (SAFIEC) in mid-Septem-ber entered into a 30-year power purchase agreement for the 1.3-GW Safi coal-fired power project. The project includes the construction and operation of a 2 x 693-MW ultrasupercritical coal-fired power plant in the Safi region. Construction started in April 2013 and commercial operation of the plant is expected to start in 2017. SAFIEC is owned by a consortium of GDF SUEZ (35%), Nareva Holding (Morocco, 35%) and Mit-sui (30%), which won the project after an international open tendering process.

First Exported Chinese Reactor to Be Sited in Pakistan. Pakistan on Sept. 12 picked the China National Nuclear Corp. (CNNC) to build its planned Karachi Coastal Nuclear Power Project on a turnkey basis. The Karachi nuclear project includes two 1,100-MW ACP-1000 units—the first in-stallation of the Chinese reactor design outside China—to be built near Paradise Point in Sindh province. Construction of the $9.6 billion project is expected to begin in 2014. Pakistan currently has three opera-tional nuclear reactor, a 125-MW PHWR in Karachi (Kanupp) and two 300-MW PWR units at Chashma in the Punjab province.

The country has plans for two more 300-MW units at Chashma (the capacity of the existing units could also be increased) and for two 1,100-MW units (Karachi Coastal).

Toshiba, Westinghouse, Exelon Part-ner to Win Saudi Arabia Nuclear Plant Bids. Toshiba, Westinghouse, and Exelon Nuclear Partners (ENP) on Sept. 10 signed a memorandum of understanding to create a joint proposal for the construction of nu-clear power plants for King Abdullah City for Atomic and Renewable Energy (K.A.CARE),

the government body established to de-velop alternative energy sources in Saudi Arabia. Toshiba and Westinghouse will pro-vide expertise related to their advanced reactors, while ENP will provide operations and associated services for the project.The consortium will target winning multi-ple orders for nuclear power plants in Saudi Arabia, which has plans to build as many as 16 nuclear power reactors by 2032. ■

—Sonal Patel is a POWER associate edi-tor (@POWERmagazine, @sonalcpatel).

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New Design Solves Scaling Problems on Geothermal Control Valves

Scaling is one of the most frequently oc-curring problems in geothermal power plants and can prohibit the control of well flow if it builds in the well or wellhead. At HS Energy on the Reykjanes Peninsula in Iceland, the problem was minimized utilizing a design developed by a vet-eran plant worker. The solution could not have been implemented without an open-minded leader who was ready to listen and push forward with the remedy. In this par-ticular case, Erlendur Guðmundsson’s idea required the backing of HS Energy Vice President Albert L. Albertsson to get the ball rolling.

The solution that was developed is a new valve, referred to as Elli-valve, which allows for better flow control and easier cleaning. It also has been shown to have economical advantages over other valves on the mar-ket. This solution could be useful in other geothermal power plants dealing with sim-ilar issues, but it also demonstrates how the ingenuity of the people most familiar with an issue, such as the plant workers, can be used to provide effective solutions to problems in any plant.

The Reykjanes Geothermal FieldOn the Icelandic Reykjanes Peninsula, HS Energy operates two geothermal power plants, Svartsengi and Reykjanes. Svartsengi currently produces 46.4 MWe and 150 MWt. The high-temperature area stretches over 2 square kilometers. The Svartsengi geothermal power plant was constructed in small phases beginning in 1974 and stretching out to 2000. Reyk-janes geothermal power plant went into production in 2006. It currently operates two 50-MW dual-flow turbines delivering approximately 100 MWe. Both plants are relatively close to the ocean, which results in brine rich in Na, Cl, K, SiO2 and SO4. A detailed description of the brine can be found in Table 1.

At Svartsengi, the average flow rate is approximately 226 kg/s (as reported in a 2000 study) where steam is 32% of the flow at 5.5 bar separation pressure, and temperatures have been shown to be around 240C. At Reykjanes, temperatures typically run between 250C and 320C.

Studies have shown that the chemical

composition of the brine increases certain problems in the control valves. (Interest-ingly, the scaling problem experienced in the control valves at HS Energy has not been seen at such magnitude at other geothermal power plants located relatively nearby in Iceland, namely Hellisheidi and Nesjavellir—likely because the chemical composition of the brine is very different at those other locations.) Previous studies conducted on surface pipes in the Reyk-janes area, operating at pressures of 20 and 5 bar-g, have recorded scale forming at a rate of 0.1 to 0.5 mm in 30 days or roughly 1.2 mm to 6 mm per year. Scaling eventually leads to difficulties in control-ling the flow from the well.

Types of Valves A geothermal wellhead assembly con-sists of many different valves with vari-

ous functions. Most of the valves are not operated regularly. Many valves are used only when necessary to divert the flow from the collection pipe system, close the hole if it is not used in pro-duction, or when isolation is necessary for repairs.

The control valve is regularly oper-ated, however, where its purpose is to control the flow of steam and brine from the well. Controlling the flow from the well is essential for efficient operation of a geothermal power plant. Choosing the right control valve is therefore of great importance.

Issues with Geothermal Control ValvesThe problem of scaling is hard to avoid. Because it can hinder efficient operation of the power plant, it warrants special at-tention. During the early operational years at HS Energy, a butterfly valve, which had been modified to compensate for the harsh geothermal environment, was used to control the well flow manually. A but-terfly valve is not well suited to throttling and is simply a disk that can be rotated on an axis to control flow (Figure 1).

The bearing house of the butterfly valve was normally cooler than the brine that flowed around it, which led to scal-ing on the bearing house and the bear-ings. Once the scale formed, control of

mg/kg Reykjanes Svartsengi

pH/C° 5.9/275 4.91/238

SiO2 601 440

Na 9,470 6,487

Cl 18,900 13,011

K 1,410 953

SO4 18 26.7

Al 0.0809 0.138

F <0.2 0.192

B 7.7 6.6

Ca 1,600 1,054

As 0.0824 -

Ba 8.93 -

Fe 0.0447 0.051

Zn 0.0196 -

Cu 0.000635 -

Mg 0.486 0.321

Pb <0.00414 -

Ni <0.000587 -

Cd <0.000011 -

Cr 0.000156 -

Hg <0.000002 -

Sr 9.4 -

Mn 2.01 -

H2S 23 10.5

CO2 1,060 470

Table 1. An example of the brine chemical composition at Reykjanes and Svartsengi. Source: HS Energy

1. A fully opened butterfly valve. Courtesy: Reynir S. Atlason

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the valve was compromised, which forced the staff to deal with less-than-optimum operating conditions. The valve also proved difficult to clean, which meant that after a certain period of operational time, staff faced the problem of cleaning the scales, as well as repairing or replacing the bearings.

After operating the butterfly valves for several years, it was decided to abandon them and convert to fixed blend disks. The disks could be removed and cleaned without too much effort, but they did not allow for the flow to be controlled in any way. Therefore, the flow required from the wells was approximated when the disks were installed. Disks with different diameters were installed on different wells, depending on their flow rate. Such disks, because of their fixed nature, did not allow the op-timum amount of brine and steam to the power plant, which led to steam being wasted in the production process.

Neither the butterfly valve nor the fixed blend disks were considered acceptable for long-term operation, so the com-pany continued to search for alternative solutions. Because it is almost impossible to alter the chemical composition of the brine to avoid scaling, the valves needed to adapt to the conditions.

Using Old Concepts to Develop New Designs The Giffard’s injector was invented as a replacement for the me-chanical pumps used to supply boilers with feedwater. Patented in 1858 by Henri Gifford, its simple design and efficient operation made previously used forced pumps almost obsolete. In essence, it controlled the flow of the fluid or gas with a cone. A section view of a Giffard injector can be seen in Figure 2. The Elli-valve can be considered a derivative of the Giffard injector. This type of valve has not been used under geothermal conditions before.

The Elli-valveAn employee who operated the steam equipment on a daily basis developed the idea. The Elli-valve allows a cone, which can be controlled remotely, to regulate the brine and steam flow through a blending seat. The valve consists mainly of three parts. First is the cone, shown as number 1 in Figure 3. The cone can be adjusted to allow for the required flow from the well to the separators. The cone is manufactured out of steel with a Stellite hard facing. (Early designs had problems with vibration in the cone head, and it would eventually become loose, but that problem was solved by strengthening the attachments between the cone and the cyl-inder it is attached to.) Figure 4 shows cones ready for use in the valve.

Second is the seat, shown as number 2 in Figure 3. Adjusting the relative opening between the seat and the cone controls the

Hydraulic control

Fluid control cone

Diffuzer throat Outlet

2. A section view of the Giffard injector. Courtesy: Reynir S. Atlason

3. A 3D model of the Elli-valve. The arrows indicate the flow direction. The model has been cut to show the moving cone. Courtesy: Reynir S. Atlason)

2

1

4

3

4. Cones ready for installation. These cones produced by Renniverkstaedi Jens Tomassonar ehf and Framtak ehf are used for flow regulation in the Elli-valve. Courtesy: HS Energy and Reynir S. Atlason

5. A section view of the Elli-valve in a fully closed position. Courtesy: HS Energy

Inlet of fluids or gases



flow through the valve. In this design, the seat has a tendency to collect scale. By allowing for easy removal of the seat, it can be cleaned relatively quickly or replaced. This feature shortens the overhaul time for the valve. The seat is manufactured out of Hardox 400 steel.

The third part is the hydraulic jack, which is also manufactured domestically, shown as number 3 in Figure 3. The jack allows for remote operation of the valve. Standard parts are also used, such as the T-pipe, shown as number 4 in Figure 3. Figure 5 is a sec-tion view of the valve in its closed position; Figure 6 shows the final assembly.

This design has gone through refinements since the day the idea surfaced at HS Energy. The main advantage over the butter-fly valve is the relative ease of cleaning and good access. Scale is removed using high-pressure washing.

Moving from Concept to ProductionThe invention of the valve can be traced back to 1996, when the initial idea surfaced. According to the staff member who designed the valve, it was the dedication of the vice president of the company that fast-tracked the development process. The worker was allowed to produce a prototype of the valve, which was then operated for a year. By using the valve design, the flow to the separators became more efficient because it could be con-tinuously controlled remotely.

After the prototype had been constructed and tested, a lo-cal machine shop was consulted to gain their expertise. That input was valuable for the valve manufacturing process. In-volvement at this stage of the development process also gave the machine shop a thorough knowledge of the components, resulting in a fluid production stream for parts and mainte-nance supplies.

After getting positive operational experience from the valve, the company began producing them for the majority of its wells. Today, the valve has been operated for more than 15 years, with constant refinements being made over that period.

Cooperation between engineering firms, machine shops, and energy companies is becoming more prevalent in Iceland and is expected to grow with the mutual platform cluster “Iceland Geothermal.” The initiative is based on defined projects that the cluster members have agreed to work on. Members meet and ex-change ideas in an effort to further development and growth as well as to identify key skills that can add value within the cluster.

The fruit of this initiative is yet to be fully enjoyed because the platform is relatively young, but it is hoped that information will flow more fluidly, pushing for innovations such as the valve described in this article.

Part of the Elli-valve success can be attributed to the fact that the staff member who designed the valve was involved throughout the development process, from the initial idea, through prototyping, and final manufacturing. The process did not take off until the vice president became involved and pushed for further development though. This example shows that devotion to innovation by corporate leaders does not only fast track and push innovative solutions at individual plants, but it also fosters an innovative spirit within the com-pany. This experience has led employees at HS Energy to pro-pose several other ideas, which have also been developed to some extent.

The Elli-valve has effectively combatted the scaling problem experienced at plants on the Reykjanes Peninsula. Scale does still accumulate in the valve, but due to the valve design, it is relatively easy to disassemble the valve and remove the scale. The cone design allows remote and more precise control of the flow of steam and brine to the separators, continuously allow-ing for a better utilization of the resource. This valve has now become a standard valve for geothermal power plants on the Reykjanes Peninsula.

By looking to the Icelandic experience, scaling problems can be addressed at other plants experiencing similar issues. ■

—Contributed by Reynir S. Atlason and Runar Unnthorsson, University of Iceland, Dept. of Industrial Engineering, Mechanical

Engineering and Computer Science.

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6. The Elli-valve after an overhaul, ready for installa-tion. Courtesy: HS Energy and Reynir S. Atlason



Beyond the Renewable Portfolio StandardThomas Overton

Renewable portfolio standards (RPSs) have been remarkably successful in boosting renewable generation, especially in the western U.S., where most states enjoy large areas of

prime wind and solar potential (and, to a lesser extent, geother-mal). Of the 11 western states, eight (Arizona, California, Colo-rado, Nevada, New Mexico, Oregon, Montana, and Washington) have RPS mandates. Utah has a voluntary standard, while Idaho and Wyoming have no RPS. The mandates range from 15% (Ari-zona and Montana) up to 33% (California). Most have deadlines of either 2020 or 2025 (Montana’s is in 2015).

Most discussion surrounding RPSs in the U.S. has focused on the resources and regulations that are necessary to meet them. Some experts, however, have begun thinking about what happens after these standards are met and the deadlines have passed.

There are good reasons to look beyond the current RPS ap-proach. In several western states, such as Arizona, momentum for boosting RPSs beyond their current levels has stalled, and pressure has even begun in some quarters for reversal (see “The Lurking Threat to State RPSs” in the August issue of POWER).

But there is another reason to think that the future of RPSs in the western U.S. is likely not to be continued ratcheting up of state-level mandates but rather a broader regional solution. The problem is that meeting the current RPSs in several states, most notably California, will require developing most or all of the eas-ily exploited solar and wind resources in those areas, and going beyond existing mandates will require developing more expen-sive, less-efficient resources, or facilitating large-scale imports from elsewhere in the West.

This dilemma is the subject of a report from the National Re-newable Energy Laboratory (NREL), “Beyond Renewable Portfolio Standards: An Assessment of Regional Supply and Demand Con-ditions Affecting the Future of Renewable Energy in the West,” published in August. NREL began by assuming that all RPSs in the western U.S. would be met by 2025 and calculated what prime renewable potential was likely to be unexploited after that. (It defined “prime-quality” resources as wind with annual capacity factors of at least 40%, solar with direct normal insolation of at least 7.5 kWh/m2/day, and all geothermal.)

The study had several notable findings:

■ Western states will collectively need 127 TWh to 149 TWh of renewable generation annually to meet current RPSs; California accounts for nearly 60% of this.

■ Colorado, Montana, Nevada, and New Mexico will have sur-pluses of prime renewable resources after meeting their RPSs. Wyoming and Idaho will also have large undeveloped prime resources.

■ California, Oregon, Utah, and Washington have already devel-

oped most or all of their prime in-state resources and will need all of it and more to meet RPS-related demand.

What this suggests, the study says, is that future renewable de-velopment in the West is likely to involve transmission corridors from prime resource areas inland to demand centers on the West Coast. The authors then worked from current cost projections for generation and transmission to determine how competitive this imported power would be compared to new combined cycle gas turbine generation after 2025. Notably, the study assumed that the production tax credit and investment tax credit would not be extended beyond their current expiration dates. It also based competitiveness on a hypothetical doubling of current transmis-sion costs in order to maintain a conservative approach.

While geothermal was not competitive with gas under any of the transmission scenarios, the results were different for wind and some solar. Wind from Wyoming and New Mexico to California and Arizona—and from Montana and Wyoming to Oregon, Washington, and California—was competitive with gas, again, without any as-sumed subsidies. The same was true for solar from Nevada to Ari-zona and California. Though transmission from Wyoming to coastal demand centers would be expensive given the long distances, the state’s wind potential is high enough to keep it competitive. In-deed, the report found that Wyoming wind could generate 37.3 TWh annually at a delivered cost of $69/MWh to $81/MWh purely by building out those areas with a 40% capacity factor or better.

The figures for New Mexico were not quite as good, but the higher generation cost was offset by lower transmission costs due to closer proximity to Southern California. (The picture was not so rosy for Colorado; its large wind surplus would be handicapped by prohibitively high transmission costs over the Rockies.)

What this study suggests is that future renewable resource planning may need to focus less on fixed generation numbers and more on how to get the generation where it needs to go. That will also require a move beyond state-level planning to regional and federal cooperation in facilitating large-scale interstate trans-mission—always a complicated prospect.

How all this transmission would be paid for is not clear, es-pecially given that the large majority of renewable generation in the West operates on a merchant basis, with costs being recov-ered via power purchase agreement rather than a rate base. That suggests that transmission would not be built without market signals favoring renewable generation over other sources. That may come from clear cost competitiveness, if the NREL study is accurate, but history suggests that regulatory incentives may be necessary along the way. ■

—Thomas W. Overton, JD is POWER’s gas technology editor. Follow him on Twitter @thomas_overton and @POWERmagazine.

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TOP PLANTS

Bruce Nuclear Generating Station, Kincardine, Ontario, CanadaOwner/operator: Bruce Power

According to Duncan Hawthorne, president and CEO of Bruce Power, 2012 was one of the most successful

years in the company’s history. The $7 bil-lion investment to revitalize four dormant CANDU Bruce A units (1 through 4) while extending the operating life of the four Bruce B units (5 through 8) made it the larg-est operating nuclear power facility in the world. The current 6,300-MW capacity sup-plies one-quarter of Ontario’s electricity and provides enough replacement power for the province to achieve its goal of shuttering all coal-fired plants by 2014.

For successfully completing numerous first-of-a-kind engineering accomplishments through innovation, transforming its work-force through new hiring and training, and positioning the site for long-term stability to achieve the province’s environmental goals, Bruce Generating Station is recognized as a 2013 POWER Top Plant.

The Home Stretch: Units 1 and 2 RefurbishmentBruce Power is a business partnership con-sisting of Cameco Corp., Trans-Canada

Corp., BPC Generation Infrastructure Trust, the Power Workers Union, and the Society of Energy Professionals. When Bruce Power took over the plant site on Lake Huron in May 2001, only half of the eight CANDU reactors were generating electricity. After re-turning Units 3 and 4 to service in 2004 and 2003, respectively, the company pursued full refurbishment and recommissioning of Units 1 and 2 in October 2005—an effort that was ranked as one of the 100 biggest infrastruc-ture projects in Canada. In the August 2010 issue, POWER reported on this ambitious restart project (“Bruce A Proves There Are Second Acts in Nuclear Power”), as both units had been out of service for over a de-cade and a half.

After Bruce A was laid up in the 1990s, fos-sil generation increased from 12% in 1995 to 29% in 2000. In the past 10 years, with the return of Bruce A units, coal use has dropped by 90% and will be phased out entirely next year. Consequently, since 2005, summer smog days in the Greater Toronto Area have fallen from 45 to 12. (For more on the province’s coal phase-out, see the May 2013 cover story, “Ontario Goes Coal-Free in a Decade.”)

The multibillion dollar project to restore Units 1 and 2 to service involved numerous contractors involved with the installation, replacement, or overhaul of several compo-nents (Table 1). Details on some of the proj-ects and specific accomplishments follow.

Fuel Channel and Calandria Tube Re-placement. The “detube-retube” project for both units was deemed critical path and set the pace for the restart project. First-of-a-kind remote-controlled tooling was deployed to cut out the original compo-nents, which were radioactive from years of service. The new components were installed manually by workers inside the reactor vaults. These fuel channel assem-blies, approximately 12 meters long from end-to-end, hold the reactor’s uranium fuel bundles during operation. Twelve bundles are inserted into each channel for a total of 5,760 bundles. Horizontal calandria tubes house the center section, the pressure tube portion of the fuel channel assembly. Af-ter much preparation, work to replace 480 fuel channel assemblies and 480 calandria tubes for both units was declared complete in April 2011.

Bringing four units back online and extending the life of four sister units has made the Bruce Nuclear Generating Station the largest operating nuclear plant in the world. The investments to bring the plant back to full power have also helped enable the province’s phase-out of all coal generation.James M. Hylko

Courtesy: Bruce Power

07_PWR_110113_TP_Bruce_p24-25.indd 24 10/14/13 11:00:27 AM


Feeder Tube Segment Replacement. Corroded from years of use, the lower seg-ments of the 960 feeder tubes in both units were removed early in the restart project. Feeder tubes connect the reactor’s fuel channel assemblies to the heat transport system, which circulates heavy water coolant from the reactor through the steam generators and back again. The first new feeder segment was installed in Unit 2 on Feb. 4, 2011. Work crews were chal-lenged throughout the program by tight fit-up and stringent weld requirements, but by Oct. 14, 2011, feeder tube installation was complete in both Units 1 and 2. Final clearance adjust-ments were made in 2012 during commission-ing of the heat transport systems.

Turbine Generator Inspection and Overhaul. Major turbine-generator work included maintenance, spindle blade re-placement, and valve restoration, as well as installation of new governor and excitation systems. In addition, work on Unit 2 includ-ed the installation of a spare generator stator. The Unit 2 turbine generator was overhauled and ready for commissioning by mid-June 2010. New low-pressure spindles were in-stalled in Unit 1 during the latter part of 2011 to prepare the unit for restart in 2012.

Valves, Maintenance, and Special Projects. Project management crews looked after the maintenance of equipment and valve restoration in both units for the dura-tion of the project. In 2009, when it became evident that valve repairs were holding up other aspects of the project, a specific team was formed to take charge of all remaining valves on the project. In all, more than 3,600 valves were replaced or restored during the refurbishment.

Specialized work that went beyond nor-mal maintenance was assigned to a Bruce Power special projects crew. This work was associated with adverse legacy conditions from years of operation, and it frequently in-

volved high-hazard tasks. Some of the jobs included the removal and replacement of a broken shutdown rod guide tube, installation of new neutron flux detectors, fabrication and installation of new suspension floors over the reactivity decks, restoration of the south fuel-ing trolley, and replacement or repair of thou-sands of pipe hangers throughout the units.

Return to Operations and RestartComponents and systems all had to be tested to verify performance and to demonstrate correct operations under normal and abnor-mal operating conditions. With heavy water in the reactor system, operators placed the Unit 2 reactor in an over-poisoned guar-anteed shutdown state on June 28, 2011. The Canadian Nuclear Safety Commission (CNSC) granted permission to manually load fuel four days later. On Mar. 16, 2012, the CNSC granted permission to lift reactor shut-down guarantees and begin start-up. Critical-ity was achieved on Apr. 10 for the first time in 17 years. Unit 1 synchronized to the grid on Sept. 19, 2012, followed by Unit 2 on Oct.

16, 2012. Table 2 lists efficiency improve-ments during the project.

Don’t Forget About Units 3–8Unit 3 originally returned to service in Janu-ary 2004 after being laid up in 1998 by former operator Ontario Hydro. Seven years after its restart, the unit underwent a six-month “West Shift” outage, one of the most innovative pro-grams in CANDU history. The $300 million investment allowed crews to adjust fuel chan-nels after they had been lengthened by years of high temperatures, radiation, and pressure. The program is expected to extend the life of Unit 3 through the end of the decade.

Unit 4 has also performed well since re-turning to service in October 2003 after its 1998 layup. In 2012 it set a post-refurbish-ment long-run record of 570 days before going into a maintenance outage mid-year for additional life extension. That unit came back online in April 2013.

Additional improvements to Bruce B are also noteworthy. For example, through a pro-cess known as “core re-ordering,” which in-volves changing the direction in which fuel is inserted into the reactor, all Bruce B units have been increased from 90% to 93% reactor power. Combining all four Bruce B units, this resulted in a 100-MW increase in generation. Additionally, Unit 6 was the top performing CANDU reactor in the world at year’s end 2012 with a perfect 100 score on the World Association of Nuclear Operators’ Nuclear Performance Index. Units 5–8 ran so safely and reliably in 2012 that they finished the year with a capacity factor of 95% (factoring in surplus baseload generation and transmis-sion constraints)—a significant jump from the 2011 capacity factor of 88.5%.

Preparing for the FutureOne area of focus for Bruce Power is ensur-ing that knowledge from experienced em-ployees is transferred to the next generation of nuclear workers. In 2001, when Bruce Power was formed, succession planning was not in place, and only 10% of employees were 35 or under and almost 50% were over 46. Since then, when 234 new people were hired in 2012, over 32% of employees were 35 and under, while an equal number were between 46 and 55.

By building on the experience gained over the past 10 years, renewing its nuclear infrastructure, and applying knowledge man-agement to maintain a trained and qualified workforce, Bruce Power continues to invest in all eight CANDU units, while providing the province with a reliable baseload source of electricity. ■

—James Hylko is a POWER contributing editor.

TOP PLANTS

Bruce Nuclear Generating Station, Kincardine, Ontario, Canada

Project component Vendor

Bulkhead installation and manufacturing new steam generator vessels

Babcock & Wilcox Canada

Fuel channel and calandria tube replacement Atomic Energy of Canada Limited (AECL)

Steam generator replacement SNC-Lavalin Nuclear, Comstock Canada, Mammoet Crane

Feeder tube segment replacement E.S. Fox Ltd.

Turbine generator overhaul Siemens Canada

Valves Comstock Canada

Balance of plant SNL-Aecon, a partnership between SNC-Lavalin and Aecon

Fire protection and secondary control facility integration

ALSF, a joint venture of Hatch-Acres, Sargent & Lundy, and E.S. Fox Ltd.

Safe shutdown components RCM-Fox, a joint venture of RCM Technologies and E.S. Fox Ltd.

Table 1. Contractors supporting the Bruce A refurbishment/restart project. Source: Bruce Power

ProjectEfficiency

improvements

Steam generator replacement 57%

Cleaning and preparation of the reactor

53%

Removal of calandria tubes 77%

Removal of pressure tubes 8%

Installation of pressure tubes 42%

Electric system refurbishment 50%

Table 2. Innovation and improve-ment. Bruce A refurbishment entailed a number of first-of-a-kind projects and demon-strated significant efficiency improvements, without compromising safety. All activities were carried out on Unit 2 first, followed by Unit 1. Source: Bruce Power

07_PWR_110113_TP_Bruce_p24-25.indd 25 10/14/13 11:00:42 AM


TOP PLANTS

Turkey Point and St. Lucie Nuclear Plants, FloridaOwner/operator: FPL

F lorida Power & Light (FPL) announced the afternoon of April 17, 2013, that its Turkey Point Unit 4 had completed its

planned outage and was resynchronized to the grid earlier in the day. That event signaled the successful completion of a four-unit, five-year, ~$3 billion dollar nuclear plant uprate program that has added 500 MW of nuclear capacity to the FPL grid at modest cost to consumers.

The program, characterized by FPL as “the largest U.S. nuclear project in recent history,” involved equipment modernizations to Units 3 and 4 at the Turkey Point Nuclear Power Plant, located in Miami-Dade County near the southern tip of Florida (Units 1 and 2 are fossil-fueled steam plants), and to the two

units at the St. Lucie Nuclear Power Plant, located in St. Lucie County on the eastern shoreline about midway down the coast. The NextEra Energy subsidiary completed the three earlier uprate programs in 2012.

“With consistently low fuel costs, zero emissions and the ability to operate around the clock, nuclear power is a critical component of our state’s energy mix today and tomorrow,” said FPL President Eric Silagy when Turkey Point 4 uprates were completed. “By increas-ing the amount of power that our nuclear plants can generate, this investment added the equivalent of a new, medium-sized power plant to Florida’s generation fleet, without having to build one.” FPL estimates that 148 MW was added at St. Lucie Unit 1, 132 MW

at St. Lucie Unit 2, and between 115 MW and 123 MW at each Turkey Point unit, about 30% more than the expected 399 MW.

Uprates Are PopularUtilities have embraced plant capacity up-grades since the 1970s, when interest in the construction of new plants was dissipating. The Nuclear Regulatory Commission (NRC) approved the first uprate in 1977 as a 5.5% power increase for Calvert Cliffs Units 1 and 2. Since then, the NRC has approved 148 up-grades totaling 20,586 MW thermal or 6,862 MW of new capacity, approximately equal to almost seven new nuclear plants, but at much lower cost.

Not all upgrades are created equal, howev-

Courtesy: FPL

Adding nuclear capacity doesn’t require constructing a new plant. A few aging plants are in the process of retirement, but much of that capacity will be replaced with new plants under construction in the future and by upgrades of existing plants today. Florida Power & Light recently completed a series of four major nuclear plant upgrades that have added 500 MW of capacity to its fleet.By Dr. Robert Peltier, PE

08_PWR_110113_TP_FPL_TurkeyPoint_p26-29.indd 26 10/14/13 11:08:04 AM

Courtesy: FPL




Top planTs

er. The NRC classifies nuclear plant uprates as falling into one of three categories. First, a “stretch” uprate generally means making more power from the existing equipment, such as with the Calvert Cliffs uprates, and usually does not involve major plant modifi-cations. All 46 uprates approved through 1999 were stretch uprates, and a total of 76 have been approved to date. Second, “measure-ment uncertainty recapture” (MUR) uprates entail using more accurate means to measure reactor power, usually replacing analog with modern digital sensors and control systems. More accurate instrumentation reduces mea-surement error so that the actual reactor ther-mal power can be increased while ensuring the plant stays below its operating license maximum. Comanche Peak Unit 2 in 1999 was the first of 54 MUR uprates approved by the NRC. Finally, the NRC has approved 28 “extended” uprates that usually involve ex-tensive plant upgrades that take years to plan and complete but can provide an increase in rated power output of 20% or more. The first extended uprate was approved for Monticello in March 1998.

FPL’s four-unit uprate program began with seeking the approval of the Florida Public Service Commission and the NRC in 2010. The NRC staff carefully reviewed the util-ity’s engineering and safety analysis of each unit and determined that the power output of each reactor could be safely increased and the remainder of the plant systems could ac-commodate the increased power levels. The NRC’s safety evaluation of the plant’s pro-posed power uprate focused on several areas, including the nuclear steam supply systems, instrumentation and control systems, electri-cal systems, accident evaluations, radiologi-cal consequences, fire protection, operations and training, testing, and technical specifica-tion changes.

Turkey Point 3 and 4 (approved by the NRC in June 2012) and St. Lucie 1 (approved in July 2012) and 2 (approved in Sept. 2012) projects are classified as extended uprate projects that uniquely included power and

MUR uprates. Turkey Point 3 and 4 was authorized by the NRC to perform a 13.0% power uprate and a 1.7% MUR, and St. Lucie 1 and 2 were each authorized a 10.0% power uprate and a 1.7% MUR (Figure 1).

A key element of the uprate program is Florida’s pay-as-you-go cost recovery frame-work, also known as “construction work in progress” or CWIP. This approach to funding major capital projects has the advantage of lowering the overall cost to Florida consum-ers by gradually increasing electric rates to pay for project development and interest costs when the project commences. This approach avoids consumers paying compounded inter-est that would be due were rates not changed until the project was completed, in this case five years after the start of the program.

FPL’s nuclear uprate program is a case study in how CWIP advantages customers. The entire uprate program added only about five cents per day to the average residential consumer, reducing to about two cents per day in 2014. The fossil fuel savings accru-ing due to the uprate program is estimated as $100 million per year that would otherwise have been passed on to consumers.

Difficult DesignAn extended uprate is complex because it touches every component, safety system, and operating procedure of the plant. Reactor up-grades may produce additional thermal out-put, but each downstream item of equipment must also be able to reliably operate within its established design parameters. The FPL uprate program on each of the four units in-volved pipe replacement, the addition of large motor-operated valves, heat exchangers, and many pumps. In addition, steam turbines and other portions of the steam and condensate system were replaced or upgraded.

The magnitude of the uprate program re-quired an average of about 3,500 workers each throughout 2012, most times working 24/7 to complete each project on time. More than 22 million man-hours were expended, in-cluding approximately 4 million engineering

mhrs. When completed, the work included in-stallation of 38,000 feet of electrical conduit, 288,500 feet (more than 50 miles) of electri-cal cable, and 16,000 linear feet of pipe. The equipment upgrades were completed during scheduled refueling outages.

The Turkey Point units are pressurized wa-ter reactors of the Westinghouse three-loop design. Commercial operation commenced for Unit 3 in December 1972 and Unit 4 in September 1973. The reactor licenses run through July 2032 and April 2033, respec-tively. The unit upgrades included a high-pressure turbine replacement with improved turbine technology in order to pass the ad-ditional volumetric steam flow produced. In addition, new turbine digital controls and electro-hydraulic control systems were added, as were new moisture separator reheaters and main condenser tube bundles and waterbox-es. The condensate pumps and the feedwater pump rotating assemblies were also replaced to accommodate the increased condensate flow requirements and to improve the plant’s operational margin. To handle the additional ~125 MW produced by each unit, the elec-tric generator stators, replacement generator rotors, and the hydrogen cooling systems were upgraded. These upgrades allowed the main generator to be rerated from 894 MVA to 1,032 MVA. Four disconnect switches as-sociated with the main transformer tie lines were also replaced with new switches with higher ratings.

The St. Lucie units are also pressurized water reactors, provided by Combustion En-gineering. Commercial operation of Unit 1 began on March 1, 1976, followed by Unit 2 on June 10, 1983. The operating licenses for the reactors expire on March 1, 2036 and April 6, 2043, respectively. The upgrades to the St. Lucie units were similar to those completed at Turkey Point, although the low-pressure steam turbine flow path (two per unit) was replaced and the generator rotors were rewound rather than replaced. Siemens provided the high-pressure and low-pressure turbines, the generator modernization, and field services for all four units.

In many ways, upgrading existing plants is much more complicated than designing and constructing a plant from scratch, particu-larly the work completed within the plant’s radiation protection boundary. FPL has dem-onstrated that these massive plant upgrades are not only major feats of engineering and construction but also economically practical. Congratulations to the FPL and Siemens team on the completion of the uprate program that will pay dividends to its customers for many years to come. ■

—Dr. Robert Peltier, PE is POWER’s consulting editor

1. St. Lucie upgraded. As part of a five-year nuclear uprate program, FPL’s St. Lucie Nuclear Power Plant has been upgraded with new steam turbines, generators, and other com-ponents that have added about 280 MW to the plant output for many years to come. A photo of Turkey Point is shown at the top of the article. Courtesy: FPL

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TOP PLANTS

Waterford 3 Steam Electric Station, Killona, LouisianaOwner/operator: Entergy Corp.

The Waterford 3 Steam Electric Station has been providing power to the Gulf Coast since 1985, when Entergy—then

Louisiana Power & Light—first brought the plant online along the Mississippi River in Killona, La., about 25 miles west of New Or-leans. The single-unit plant employs a two-loop Combustion Engineering pressurized water reactor rated at 1,159 MW net. The plant has been a key element of the area grid, having managed an admirable 100% capac-ity factor in 2010, according to the Nuclear Regulatory Commission.

But in the mid-2000s, after more than 20 years of operation, the time had come to make arrangements to replace the plant’s two aging steam generators. Entergy contracted with SGT, a URS/AREVA joint venture, to supply management, engineering, and con-struction for the project, which would also involve replacement of the reactor vessel

closure head. SGT was brought in as a result of its experience in performing more than 20 similar operations worldwide.

Project planning began in the mid-2000s and continued after the Louisiana Public Service Commission confirmed in 2010 that replacement of the steam generators was in the public interest. Though replacing nuclear reactor steam generators is a well-understood and standard operation, it is far from being without risk. It is typically the most chal-lenging event plant owners will go through, and the risks can extend all the way up to complete loss of the plant. Though the large majority of such operations go successfully, several recent steam generator replacements in the U.S. have not.

The worst example is surely Progress Energy’s Crystal River 3 plant in Florida, which began a steam generator replace-ment in 2009. Progress took the unusual

step of trying to manage the operation it-self, but when workers cut a hole through the containment building to remove the old steam generators, the concrete of the build-ing began to delaminate. After a series of unsuccessful repairs and a four-year outage that cost hundreds of millions of dollars, new owner Duke Energy finally gave up on the plant earlier this year. The San Onofre Nuclear Generating Station in California also closed in 2013 following an ill-fated replacement in 2010, in which a flawed computer model was used to design the new steam generators.

Gearing UpWith these and other risks in mind, Entergy and SGT formed an integrated team dedi-cated to a safe and successful operation. The team developed a set of project-specific en-vironmental, safety, and health procedures

Courtesy:Entergy Corp.

Nuclear plant steam generator replacements are difficult in the best of circumstanc-es. Entergy had to face component delays, staffing shortages, and even a hurricane while upgrading its Waterford 3 plant. Sterling teamwork and project management brought the operation to a successful conclusion.Thomas Overton

09_PWR_110113_TP_Waterford_p30-31.indd 30 10/14/13 11:16:16 AM


Top planTs

to address the hazards associated with the project and the scope of a major component replacement. The plan addressed all elements of safety—industrial, nuclear, and radiologi-cal—early in the project. SGT collaborated with Entergy’s training staff to ensure that incoming personnel understood all safety aspects of the job before being released to the field. Throughout the project, there were numerous vendors who visited the site to pro-vide specialized training to the team. The re-placement would be among the largest SGT had ever attempted, as the new 720-ton, 65-foot-long steam generators were two of the heaviest SGT had ever worked with.

The project included extensive pre-outage work. Marine operations consisted of levee upgrades and offloading and transporting the replacement steam generators from the Mississippi River to a temporary on-site storage location.

The outage was originally scheduled for early 2011, but three months before work was to begin on the plant, the proj-ect had to be deferred 18 months because of delays in delivering the new steam generators. In addition to requiring a revi-sion of the project budget, this schedule change posed some substantial logistical challenges. Multiple major modifications (among them replacement of a coolant pump motor and radiography around the reactor vessel) had been scheduled to oc-cur during the next outage after the steam generator replacement. The delay of the steam generator delivery meant that these

modifications now needed to occur at the same time. Incorporating these modifica-tions into the steam generator replacement schedule required extensive coordination between SGT and Entergy personnel.

There was another challenge from the deferment: The delays caused the outage to occur simultaneously with several other nuclear plant outages nationwide, including other steam generator replacements. This meant careful planning and coordination was necessary to ensure sufficient staffing and re-sources would be available to complete the work on time.

An Ill WindThen, in the fall of 2012, just seven weeks from the scheduled start of the outage, a new challenge began bearing down on the site: Hurricane Isaac. When it became clear that the plant was in the path of the storm, Entergy and SGT assembled an emergency team to prepare the site. The plant itself was shut down as the hurricane approached, and major equipment and temporary structures that had been built for the project were either removed or safely secured. The emergency team remained on the site during the storm to ensure safety of the plant.

Though Waterford suffered only minor and mostly superficial damage from the storm, the evacuation, cleanup, and repairs meant a two-week loss in the pre-outage schedule. But rather than push the outage back again, personnel worked additional overtime and the project team added a second shift to re-

main on track. The outage began on Oct. 17, 2012, as scheduled.

To remove the old steam generators and install the new ones, a 34-foot by 33-foot opening was cut in the containment building using hydrodemolition. A temporary work platform was built alongside the building to support the operation. The opening had to be cut in close proximity to the dry and wet cooling towers, which meant very care-ful crane operations were necessary to move the 179-ton block of concrete out of the way.

The old reactor vessel closure head was removed at this point so that the removal of interferences around the old steam genera-tors could begin. Substantial elements of the main steam tower frames had to be removed, and a specialized rigging scheme had to be built inside the containment building to lift out the old generators and remove them safely. Among other equipment, an entire portable crane was rigged through the open-ing into the containment building to support the operation.

With the old steam generators out, the pro-cess was then conducted in reverse to move the new steam generators into place (Figure 1). A key challenge in installing the new steam generators was meeting the required fit-up tolerances of the primary coolant sys-tem piping. The replacement steam generator fit-up was optimized to include the secondary side large bore piping, lower steam generator support system, and upper steam generator support system, which included a complex snubber assembly.

Finally, the new reactor vessel head was in-stalled, and the temporary opening in the con-tainment building was closed. The component replacements were completed in just under 48 days, and the entire outage, including refuel-ing, was completed in 93 days. Waterford 3 returned to operation on Jan. 18, 2013.

On-site project manpower, both staff and craft, peaked at approximately 1,400. The project sustained no OSHA recordable or lost time accidents despite more than 500,000 man-hours worked during the re-placement work in the outage. Over the life of the project, the team completed more than 1.3 million man-hours with only one OSHA recordable injury. The project team received multiple safety awards from the National Safety Council, including the Million Hour Award, Perfect Record Award, and Occupa-tional Excellence Achievements Award.

For completing such a critical opera-tion successfully, safely, and under budget despite multiple setbacks and challenges, Waterford 3 is a well-deserving POWER Top Plant. ■—Thomas W. Overton, JD is POWER’s gas

technology editor.

1. A tight fit. Precise engineering and meticulous planning were necessary to move the new steam generators—which weighed more than 700 tons each—into place. Courtesy: URS

09_PWR_110113_TP_Waterford_p30-31.indd 31 10/14/13 11:18:38 AM


Power Policy

South Korea Walks an Energy TightropeSouth Korea’s difficult power supply issues have been aggravated by an ongo-

ing documentation scandal involving its essential nuclear plants, and the future of its economy depends upon efforts to balance energy security and environmental concerns.

Sonal Patel

South Korea, the world’s eighth-largest trading nation, whose trade volume has surpassed $1 trillion for two

straight years, barely avoided blackouts be-tween June and August this summer after the country’s nuclear regulator was com-pelled to temporarily shut down or suspend resumption of six of its 23 reactors.

The cause: A wide-ranging documentation scandal that has since morphed into a political firestorm of corruption allegations traded be-tween the state-owned nuclear company and the industry, and within the government itself. It began in November 2012 when investiga-tors found thousands of substandard parts with forged quality warranties installed in reactors. This May, further scrutiny uncovered control cables used in emergency shutdown that failed safety checks but were still installed in several reactors with fake warranties.

And as temperatures rose this June, grid operator the Korea Power Exchange warned that reserve margins had dipped precariously low, and it was forced to slash power use by 6 GW to counter debilitating electricity sup-ply shortages. The country’s energy ministry at the time also demanded that local con-glomerates curb power use by 15% to avoid a grid failure. The problem now stands to worsen over the coming winter and through next summer, putting the country’s booming economy on hiatus.

It was not the first time this country of 49 million people has suffered sporadic power shortages due to an increasing strain on the grid. South Korea last suffered rolling blackouts in September 2011, when unexpectedly warm temperatures boosted power consumption, and it narrowly averted another crisis in November 2012 when the first two reactors were impli-cated in the documentation scandal.

Evidently, this member of the Organisation for Economic Cooperation and Development (OECD) that is poor in natural resources has been struggling to match its booming rise in

energy demand with an associated invest-ment in power plants. Observers point out that as power consumption by industries has skyrocketed along with a rise in income lev-els, so have applications that rely on the grid, attributable to artificially depressed power prices that are the lowest in the OECD. At the same time, construction of new power plants has been limited by delays stemming from environmental concerns and civil complaints. The country’s reserve margin has been grad-ually pinched to a slim 3.8% as recently as 2012—and it shows no sign of recovery until at least 2015 and as late as 2018, according to current investment scenarios.

The long term looks no better. The documentation scandal has eroded public confidence in the country’s lofty nuclear expansion aspirations, which had been seen as the best means to achieve long-term en-ergy security and environmental goals. In this post-Fukushima age, that means South Korea is walking a tightrope to future en-ergy security.

Unsustainable Power PricesWhat’s causing the dangerous disparity be-tween power supply and demand? The con-sensus is that South Korea’s power market is skewed. Retail prices are controlled in South Korea, and generators depend heavily on gov-ernment subsidies to cover increased costs. Un-derscoring supply issues is that investment for power capacity expansions in recent years has fallen short because the market “is not provid-ing sufficient incentives,” Finnish equipment firm Wärtsilä says in an in-house analysis. “The Korean electricity market provides a system marginal price (SMP) for each hour, which should stimulate new investments if the supply side is scarce,” it explains. “However, because the country’s generating companies cannot receive the full SMP for their existing assets, and because retail prices are regulated and are currently below the SMP, there is no

incentive to invest in new capacity.”The biggest loser is none other than state-

controlled monopoly Korea Electric Power Corp. (KEPCO), which controls 100% of the transmission and distribution market and 93% of total power generation. KEPCO has posted annual losses for the past five years.

In August, the company’s net loss deep-ened to $1.58 billion compared to a year earlier, even as sales increased by nearly 17%. The company attributed the loss to surging costs of oil, gas, and coal. Though the company has been seeking higher tar-iffs, the government has only allowed the company to hike electricity prices by an average of 4.9%—much less than the 10.7% hike requested in July. South Korea therefore continues to have some of the lowest electricity prices (both residential and industrial) among the world’s devel-oped countries.

According to the International Energy Agency (IEA), market reform will be the most critical remedy for South Korea’s economy-crippling power shortages. The process should entail “greater restructuring of [KEPCO] and revisiting the design of the wholesale market; and strengthening the in-dependence of the sector regulator to enable fair competition, including the removal of barriers to new entrants and third-party ac-cess to network infrastructure, and creating clear roles for publicly owned and private entities,” it says.

The IEA notes that reform of energy mar-kets is a “process not an event,” stressing that the government must clearly articulate goals for reform that take into account the coun-try’s “green growth” ambitions, its nuclear expansion program, its targets for new and renewable energy, and the new emissions trading scheme.

Teetering “Green Growth” Complicating the country’s overwhelming sup-

10_PWR_110113_SR_SouthKorea_p32-41.indd 32 10/14/13 11:23:35 AM


Power Policy

ply issues is a planned transition toward a low-carbon, sustainable energy future. South Korea is a signatory of the United Nations Framework Convention on Climate Change and the Kyoto Protocol. In line with the first National Energy Master Plan (2008–2030), the country in April 2010 passed the Framework Act on Low Car-bon Green Growth. A key aspect of that “green growth” strategy is balancing energy security with resource efficiency and measures to miti-gate climate change.

Significantly, the act establishes an ambi-tious target to reduce national emissions of greenhouse gases (GHG) by 30% in 2020 below a business-as-usual scenario and re-quires the government to operate a GHG emissions trading system that will cover major power generators and industrial and manufacturing entities.

Following passage of the Enforcement De-cree of Allocation and Trading of Greenhouse

Gas Emissions Allowances Act (the ETS Act) by South Korea’s cabinet in November 2012, the ETS is now slated to begin in Janu-ary 2015, overseen by the Ministry of Envi-ronment. Data from 2011 shows that 76% of the country’s emitted GHGs came from only 10 major entities—including KEPCO, which generated about 93% of the country’s power and accounted for 39% of the nation’s total GHG emissions.

Essentially, the green strategy has forced the energy-hungry nation to stake its long-term future disproportionately on an expansion of nuclear power and renewable capacity.

That approach could work, say experts. Planned builds of low-carbon generation are expected to reduce the average emis-sions per megawatt-hour of power genera-tion by more than 10% between 2010 and 2020. However, others contend that South Korea will, during its transition, be forced

to rely on coal-fired generation over more expensive gas-fired generation (gas must be imported at a premium as liquefied natural gas [LNG]). They also assert more than the planned nuclear and renewable capacities may be needed to meet long-term goals for energy security, and that this may be despite energy efficiency priorities set by the coun-try’s “green growth” strategy, which include a $2.2 billion investment in industrial en-ergy efficiency and standards set for appli-ances and lighting.

Meanwhile, the country is, in addition to the cap-and-trade program, considering a car-bon tax that would range from about $0.0012/kWh for thermal generation to $0.0062 per liter of heavy fuel oil. If approved, the car-bon tax could come into effect in January 2016. Though it would draw in trillions of revenue for the government, “fear of double regulation for businesses in addition to the

Asia’s BeaconDespite its current power supply troubles, South Korea boasts a 100% electrification rate, and it continues to serve as a beacon of development for many Asian countries—including neighboring China and Japan, which share many of Korea’s power short-age woes.

Since 1887, when the first electric bulb was lit in the royal court in Kyung Bok Pal-ace and three 7-kW steam power genera-tors (procured by special dispatch to the Edison Electric Co.) created the Hansung Electric Co., the country’s power sector has resiliently survived a number of political, economic, and regulatory barrages.

Between 1910 and 1945, the Korean Pen-insula was occupied by Japan, from which it regained its independence after World War II. The division of the peninsula along the 38th parallel and ensuing Korean War (1950–1953) resulted in an armistice that created a border between the communist north and the democratic south (though South Korea, also known as the Republic of Korea, did not have its first free, direct presidential election until 1987). A few years later, in 1961, the Korea Electric Co. (KECO) was born through the integration of an existing power company and two distri-bution firms. As the country saw rapid eco-nomic growth fueled by chaebols, massive family-owned conglomerates that enjoyed a close relationship with the government, KECO became a wholly government owned

entity in 1982, being renamed the Korea Electric Power Corp. (KEPCO).

When rattled by the currency market turmoil that derived from the 1997 Asian Financial Crisis, South Korea moved to re-structure its power sector. Following pas-sage of the Basic Plan for Restructuring the Electricity Industry, KEPCO was unbundled in 1999 into five thermal generation compa-nies—Korea South-East Power Co. (KOSEP), Korea Midland Power Co. (KOMIPO, Figure 1), Korea Western Power Co. (KOWEPO), Ko-rea Southern Power Co. (KOSPO), and Korea East-West Power Co. (KEWESPO)—and one company to oversee the country’s nuclear and hydropower, Korea Hydro and Nuclear Co. (KHNP). The five thermal companies were to be privatized in stages, though the government has not completed that. Today the government retains a 21% direct stake in KEPCO. The 2009-established Korea Fi-nance Corp.—a 100% government-owned quasi-sovereign financial institution—owns the majority 29.9% share in KEPCO.

Restructuring efforts also established the Korea Electric Power Exchange (KPX) to serve as the system operator and coordi-nate the wholesale electric power market. KPX continues to regulate the cost-based bidding-pool market and determines prices for energy sold between generators and the KEPCO grid. KEPCO is the main retailer and, apart from large industrial consumers, is the sole purchaser of electricity from the

pool. Since 2004, however, regional dis-tricts have been allowed to bypass KEPCO and the power pool by buying power di-rectly from independent generators.

Today, KEPCO and independent gen-erators (which produce about 8% of the country’s power) are overseen by the Ministry of Trade, Industry, and Energy (MOTIE), an entity that took on a trade policy role and replaced the Ministry of Knowledge Economy (MKE) in March 2013. MOTIE works in consultation with the Ministry of Strategy and Finance, the country’s six generation companies, and KEPCO. The country’s nuclear power sec-tor is regulated by the Nuclear Safety and Security Commission (NSSC).

1. Class operations. The Boryeong thermal power plant, the first standardized 500-MW supercritical plant that was de-signed, constructed, and completed solely by South Korean engineers, began operating in April 1993. Its owner, Korea Midland Pow-er Co. (KOIMPO), said Unit 3 recorded 5,000 days of trouble-free operations between December 1998 and September 2013—a record for the country that has a number of noteworthy plants. Courtesy: KOMIPO



POWER POLICY

proposed emission trading scheme has been expressed,” said Changmin Yoo, the director of PwC South Korea.

A Delicate Power BalanceKeep in mind that South Korea’s energy consumption has grown six-fold since the 1980s (and five times faster than other OECD countries) on the back of rapid economic growth propelled by its heavy and chemical industries. The country is today the world’s 9th-largest energy-consuming nation. Total primary energy consumption surged to 275.7 million tons of oil equivalent (TOE) in 2011 as energy consumption per capita also in-creased, from 1.1 TOE in 1980 to 5.1 TOE in 2011, according to the Korea Energy Man-agement Corp. KEPCO reported in 2012 that about 14% of net electricity generated was consumed by residential use, 31% was for commercial and public use, while about 55% was for industrial use.

South Korea’s current power portfolio is divided mostly between thermal generation and nuclear power. In 2012, total electricity consumption soared to 466.59 TWh while the total produced from 81.8 GW of installed capacity was 509.58 TWh (Figure 2).

Thermal Generation. Coal power has to date played a particularly marked role, its share in the country’s electricity mix rising dramatically from 17% in 1990 to 40% in 2010. Gas-fired generation, too, soared dur-ing that period, from 9% to 19%. Though the country’s “green growth” future strategy favors nuclear power most of all, coal will continue to play a major role, presumably to boost energy security.

The bulk of South Korea’s thermal gen-eration is produced at cities such as Dangjin, where a coal-fired power plant has been in

operation since 2000 (Figure 3). Other gen-eration in or near urban centers includes the $2.5 billion 1,600-MW Yonghungdo plant near the city of Inchon and the Hadong plant, which has eight 500-MW units.

Meanwhile, several innovative plants are under construction, including KOSPO’s $3 billion Samcheok Green Power Project. When online in 2014, that project will employ low-grade coal and supercritical circulating fluidized bed boilers. Another much-watched project is an integrated gasification combined cycle plant being developed by KEPCO sub-sidiary KOWEPO, which will use GE’s giant

7F syngas turbine for the 300-MW plant in Seoul that is slated to be completed in 2015.

Development of future coal plants will be opened to independent power producers (IPPs), and a number of players are vying for that op-portunity, including four Korean conglomer-ates: Tong Yang, Dongbu, Samsung, and SK.

South Korea is also expected to begin con-struction of LNG power plants with a com-bined output of 5 GW starting in June 2015, up from the 887 MW of LNG capacity in De-cember 2012 and a combined cycle gas-fired power plant capacity of 19.7 GW (or about 24% of the nation’s total capacity). According to giant South Korean construction firm Doo-san—which is the only player in the country with the technological capacity to produce gas and steam turbines—IPPs could secure thermal power plant projects with a combined output of about 11 GW (or nearly 74% of the nation’s thermal output in 2020).

Nuclear. Historically, nuclear power has been essential for reducing South Korea’s vulnerability to global fuel shortages. Since the 1970s, the country has carried out an ambitious nuclear power program in parallel with its industrialization policy, first build-ing power plants mostly through turnkey contracts (its first plant, Kori 1, was built by Westinghouse in 1978), and then developing a domestic sector to undertake construction, management, design, and equipment supply.

Touting “green growth”—a “new banner for an old strategy,” notes U.S.-based think tank the Council on Foreign Relations—South Korea today has 21.6 GW of nuclear

Thermal Nuclear Hydro Other renewables Wind

Power plant capacity (GW)

20.71, 25%

52.31, 64%

6.45, 8%0.48, 1%1.86, 2%

Electricity production (TWh)

150.33, 29%

342.98, 67%

7.65, 2%0.92, 0%7.7, 2%

2. Where coal is king. In 2012, South Korea’s total installed capacity was 81.8 GW, and it produced 509.58 TWh (not counting transmission losses) while it consumed 466.59 TWh. Source: Korea Electric Power Corp.

3. Burnished coal credentials. KEPCO’s coal-fired Dangjin power plant about 70 kilometers southwest of Seoul has four 600-MW units (Units 1–4) and four 500-MW ultrasu-percritical units (Units 5–8). Work is under way at the plant to complete two 1-GW units (Units 9 and 10) featuring ultrasupercritical technology by the end of December 2015 and June 2016. Courtesy: KEPCO

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capacity at 23 operating nuclear plants (com-prising 19 pressurized water reactors and four CANDU pressurized heavy water reactors) and five units under construction. All the country’s reactors, located along the southern coast, are owned by KEPCO subsidiary Ko-rea Hydro & Nuclear Power (KHNP). And it’s an admirable fleet: The country boasts that its reactors have the highest capacity factor—the proportion of time that a reactor is generating electricity—and the lowest un-planned shutdown rate in the world, at only 0.3 to 0.5 times per month, compared to 3.2 times per month in France.

However, in accordance with a 1973 nuclear cooperation agreement with the U.S.—which is due to be renewed in four years—South Korea has an open fuel cycle without enrichment or reprocessing. Spent fuel is now stored onsite at reactors until a centralized interim storage facility at Gyeo-ngju is completed (expected in 2024). One expert notes, however, that three reactor sites where spent fuel is currently stored are ex-pected to reach capacity in 2016, and con-struction of the interim repository has twice been delayed due to “weak bedrock and groundwater problems.”

Nevertheless, South Korea’s future is

staked firmly in nuclear simply because, as former South Korean prime minister Han Seung-soo acknowledged in 2011, “If we pursue clean energy, we need to accept nu-clear power as a reality until we have better options readily available.” Since the Fuku-shima disaster, therefore, South Korea has remained steadfast on a nuclear expansion, though it has emphasized nuclear safety, and even establishing the world’s first Interna-tional Nuclear Safety School to train safety experts from other countries. Plans are now under way to increase nuclear’s share from 25% to 59% by 2030, and in addition to the five reactors under construction, eight others are planned at an estimated total cost of $32 billion to $40 billion.

The country certainly has the techno-logical know-how—even if the Fukushima accident and widening documentation scan-dal have undermined public support for the country’s cheapest source of electricity. After achieving technological independence with construction of Yeonggwang 3 and 4 (Figure 4), South Korea’s first domestically designed OPR1000 reactors, Ulchin 3 and 4, entered commercial operation in 1998. Six more OPR1000 plants are now under construction at Ulchin, Shin-Kori, and Shin-Wolsong, but

South Korea is also building a domestically designed third-generation light water reactor, the APR1400, at Shin Kori 3 and 4, units that are slated for completion in December 2013 and 2014 respectively.

Korea Hydro & Nuclear Power Co. typi-cally issues corporate bonds with diversified maturities to attract national and international investors to fund the costly projects, though it says it also “works to secure a reasonable sales price for electricity and to reduce the cost of production” to maximize earnings. Meanwhile, the company has also embarked on a quest to export 80 indigenously designed nuclear reactors by 2030 to generate a total of $300 billion in sales. Though it recently ce-mented a critical deal for the supply of four APR1400 units to the United Arab Emirates, experts question the feasibility of the larger goal, noting it would require a tremendous boost in production of nuclear reactors at time when the nuclear workforce had dimin-ished. (For more on South Korea’s nuclear export efforts, see POWER’s web supple-ment to this issue, “South Korea Ramps Up Nuclear Exports.”)

Renewables. As prioritized in its “green growth” strategy, South Korea is also banking on renewables to increase

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Power Policy

its energy self-sufficiency, though as it stands today, the country’s share of renew-ables is so meager that it ranks at the bot-tom of all OECD countries, says the IEA. In 2012, it replaced feed-in tariffs (FITs) with a renewable portfolio standard (RPS) that applies to power providers with more than 500 MW in generating capacity and requires that the 13 largest public and pri-vate utilities purchase or generate renew-able energy at a rate equal to 10% of their share of total energy by 2022.

Some experts point out that in the year since the RPS was adopted, new facility ca-pacity has jumped by 620 MW—nearly half that accumulated under FITs over the past decade. Others note that despite incentives like a 5% tax credit, long-term low-interest loans, and halved import duties on renewable plant components to encourage more private firms to take a lead in the development of renewables, the fledgling sector continues to lag behind global competition.

Yet others simply point to the country’s massive potential. Only 5% of the poten-tial estimated for large-scale and small-scale hydropower has been realized—even though hydro is the country’s top renewable source, the government says. The govern-

ment also wants 15.7 GW of wind power to be generated by 2022 in addition to the existing 480 MW. South Korean conglom-erates have begun to invest significantly in offshore wind farms in the southeast part of the country, and the government has boost-ed its support by announcing a strategy to attract $8.2 billion to develop offshore wind farms with a capacity of at least 2.5 GW by 2019. Solar, far underdeveloped, will fare best in South Korea’s southern coastal area, and geothermal capacity has remained stagnant at 229 MW, notes the government. Several KEPCO subsidiaries are meanwhile focusing on biomass using pellets as a means to achieving the RPS.

Perhaps South Korea’s most promising re-newable efforts are in marine energy, where it hopes to benefit from strong tidal flows around the Korean Peninsula. Funded partly by the Korean government, the Korea Water Resources Corp. (KWRC) in 2011 put into operation the 254-MW Lake Sihwa tidal power station, a tidal barrage that uses 10 submerged 25.4-MW bulb turbines to gen-erate power (Figure 5). That project is the world’s biggest tidal power station today.

Transmission and Distribution. As of December 2012, South Korea’s transmis-sion grid consisted of three systems of 765 kV and 345 kV for trunk routes and 154 kV or 66 kV for local networks—all owned and operated by KEPCO—of over 31,622 ki-

5. Tidal power title-holder. The Korea Water Resources Corp. in August 2011 put into operation the 254-MW Lake Sihwa tidal power station in the country’s northwest Gyeonggi Province, a tidal barrage that uses 10 submerged bulb turbines that are driven in an unpumped flood generation scheme. The project’s capacity surpasses the1966-built 240-MW Rance Tidal Power Station in France, making it the world’s biggest tidal power station. Courtesy: KWRC

4. Strained supplies. South Korea suffered strained power supplies this summer, stem-ming from forced reactor shutdowns ordered last November at the Yeonggwang nuclear complex (shown here) owned by state company Korea Hydro & Nuclear Power Co., which operates the nation’s 23 nuclear reactors. The measure followed KHNP’s admission that eight unnamed firms that supplied parts had faked 60 certificates covering 7,682 nuclear power components over a period of nearly 10 years, from 2003 to 2012—affecting at least five reactors. Later in May 2013, a separate scandal involving forged documentation for safety-related control cabling prompted the shutdown of Shin Kori 1 and 2 and Shin Wolsong 1 and delayed startup approval for the newly built Shin Wolsong 2. South Korea’s government has since announced new measures responding to the quality control scandal and safety problems to include new procedures for procuring reactor parts and dealing with mechanical problems. Courtesy: Korea Yeonggwang NPP

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lometers. KEPCO is replacing most 66 kV lines as it carries out the second stage of a 765 kV power transmission link that it says will serve as the backbone of a 21st-century

smarter system. A supervisory control and data acquisition

(SCADA) system is used to remotely monitor and control substation operations. In addition

to equipment and facility upgrading, more sub-stations are being automated and built indoors to secure power supply reliability. Meanwhile, KEPCO also owns the sole distribution net-work in the country—a highly efficient one.

Notably, in December 2012, the rate of power loss in transmission and distribution was 3.69%—much less than in other coun-tries, including the U.S., whose losses aver-age about 7%.

Advanced Technologies. To its credit, South Korea ranks among the highest in the world in research and development spending, and it has over the past few years pioneered a number of fundamental tech-nologies. Also highly revered are its efforts to establish a smart grid throughout the en-tire country by 2030 with a more sophisti-cated grid and management of power peaks using automated metering infrastructure and energy storage systems.

Citing its paucity of natural resources and soaring demands of economic growth, the government enacted the Smart Grid Act in 2011 and subsequently issued a master plan, both which have paved the way for institu-tional support of smart grids. Notable proj-ects include a $65 million smart grid pilot complex on Jeju Island (Figure 6), which

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6. An island of hopes. One of South Korea’s nine provinces, the scenic but isolated 714-square-mile Jeju Province that lies in the Korea Strait, seeks to be “carbon-free” by 2030, an effort that entails replacing current diesel generation with renewables and a reliance solely on electric vehicles and a smart grid. Projects are under way to install a 2.5-GW offshore wind farm—one of the largest in the world—a 300-MW onshore wind farm, and a 100-MW solar power facility by 2030. South Korea has also tested several smart grid, energy storage, and electric vehicle charging technologies on the island, including an advanced distribution automa-tion system, a microgrid operation center, and advanced metering infrastructure. The island also includes a seawater desalination plant. Courtesy: Jeju Special Self-Governing Province



Power Policy

between 2009 and 2013 tested five sectors to improve the power system efficiency and to develop output stabilization technology for renewable energy. The project included test-ing of commercialized electric car charging stations and real-time payment systems.

On the renewables front, too, KEPCO is equipping itself with the technology and competency needed for all aspects of off-shore wind power generation, including engineering, construction, and operation, and it has ambitions to become one of the world’s top three offshore wind energy players by 2020.

Research is under way at an offshore wind farm in the Yellow Sea, and South Korea is also developing biogas turbine generators and establishing infrastructure for solar en-ergy testing facilities. An interesting project from the Korea Institute of Energy Research (KIER), meanwhile, seeks to use ammonia produced using water, air, and electricity from renewables in existing energy storage and transportation infrastructure. KIER has to date developed a vehicle whose fuel has an ammo-nia substitution rate of 70%.

Establishing a Safety NetSouth Korea’s future energy goals are out-lined in biannual power development plans based on which generation companies apply for government approvals for power plant construction. The latest installment of the so-called “Basic Plan of Long-Term Electricity Supply and Demand (BPE)” is the 6th BPE, issued this year, which covers a planning pe-riod from 2013 to 2027.

Compared to the 5th BPE (2010–2024), the 6th plan calls for a marked rise in the proportion of baseload power plants: It in-creases the share of coal-fired generation to 34.6% on a 2027 basis compared to 27.9% on a 2024 basis (Figure 7). Those plants will

be needed to meet a power consumption growth rate increase of 3.4% in the 6th plan, a figure that was revised from 3.1% in the 5th plan, and significantly, to retain a target electricity reserve margin rate of 22%, the government reasons. However, deferring a decision to build any new nuclear plants, the plan notably stops short of planning for new nuclear capacity beyond what is already ap-proved in the 5th plan (35.9 GW), given on-going safety concerns.

Analysts applauded the plan’s stance to complete six planned but uninstalled nuclear reactors from the 5th Basic Plan, which have been controversial following the procurement-related scandal at Korea Hydro and Nuclear Power. But according to credit ratings agency Fitch Ratings, if no nuclear generation is built after 2024, the share of higher-cost generation (including coal and LNG-fired power plants) will surge—and Fitch projects the govern-ment may rethink its position on nuclear en-ergy given high production costs anticipated. At the same time, it says, the government’s call for 61 new generating units (excluding renewables) by 2027 underscores the need for urgent reforms of its power sector.

Higher generation capacity and a more ex-pensive overall generation mix through 2027 will continue to burden KEPCO—which will build about 35 of those new plants—if the government does not allow for cost-reflective tariffs. Fitch also projects that KEPCO and its five generation subsidiaries could spend more than 10 trillion won ($9.3 billion) per year solely on the construction of the new coal and nuclear plants—even if the govern-ment invites more private sector participation in the generation market.

Seeking Fuel StabilityThe 6th plan, meanwhile, also contains an interesting admission by the government that

power generation costs will need to be curbed in the face of expected fuel cost rises in the mid- to long term. Though South Korea ac-counts for 2.1% of the world’s total energy consumption, it is poor in natural resources and has been forced to import a staggering 96% of its fuel needs for more than a decade. In 2012, the country spent an astounding $184.8 billion (compared to $172.49 billion in 2011) to import 96.4% of its energy—a figure that represented a third of the coun-try’s total imports.

Comprising 99% of energy imports were almost a billion barrels of oil from the Middle East (and a tiny fraction from Asia and Africa); 116 million tons of coal from Australia, China, and Indone-sia; 36.7 million tons of LNG from Qa-tar, Oman, and Indonesia; and 907.4 tons of uranium from Russia and Canada. Ef-fectively, South Korea was in 2011 the world’s third-largest coal importer. And in 2012, because it is dependent on costly oil-indexed price imports for nearly all its LNG, except for a small fraction ob-tained from its own Donghae gas fields, it became the world’s second-largest LNG-importing nation, after Japan.

Future plans to diversify imports focus on shale gas, and to that effect, the government in September 2012 announced a “Shale Gas Development and Use Strategy.” The Korea Gas Corp., an entity responsible for import-ing natural gas, has a stake in developing shale gas fields in Canada and is attempting to secure supplies offshore Mozambique. It has also more recently signed a purchase contract with Cheniere Energy’s Sabine Pass LNG facility for 3.5 million metric tons of LNG annually (making it the first U.S. LNG export project). Then the government plans to increase storage rates and add capacity from three other import terminals already in operation at Incheon, Pyeongtaek, and Tongyeong.

A Comprehensive VisionSouth Korea’s attempts to balance energy security and the environment are notable in their scope and span, but the country con-tinues to be at the mercy of several volatile factors. Later this year, the government is expected to release its second energy mas-ter plan. It remains to be seen if, as some government sources report, that plan will lay out a more flexible vision that could al-low the country to achieve the tremendous economic growth it is capable of while en-gaging a smart strategy to address climate change. ■

—Sonal Patel is a POWER associate editor. Follow her on Twitter @sonalcpatel

and @POWERmagazine.

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2015(6th)

2020(5th)

2020(6th)

2024(5th)

2025(6th)

2027(6th)

7. The demand and supply plan. The 6th Basic Plan of Long-Term Electricity Supply and Demand (2013–2027) compared to the 5th plan (2010–2024) calls on generators to maintain a constant reserve margin of 22% until 2027 in order to stabilize power demand and supply. Also urged is massive capacity expansion for nuclear, coal, and renewable generation. Source: MOTIE

Nuclear Coal LNG Renewable Others



NUCLEAR

V.C. Summer Nuclear Station Construction UpdateThe two new units at the V.C. Summer site in South Carolina are finally beginning to

take physical shape and are scheduled to be online within the next four to six years. Given the retirement plans for coal-fired generation in the same service territory, that new capacity may become available just in time.

James M. Hylko

On Mar. 30, 2012, South Carolina Elec-tric & Gas Co. (SCE&G), principal subsidiary of SCANA Corp., and

Santee Cooper, South Carolina’s state-owned electric and water utility, received approval for combined construction and operating li-censes (COLs) from the Nuclear Regulatory Commission (NRC) for the V.C. Summer Nuclear Station (VCSNS) Units 2 and 3. The new units will be constructed near Jenkins-ville, S.C., in Fairfield County, approximately 26 miles northwest of Columbia. One month earlier, the NRC had approved two COLs for Southern Nuclear’s Plant Vogtle Units 3 and 4 in Georgia (POWER, “Vogtle Gets Green Light,” May 2012).

The VCSNS process started almost four years to the day in 2008, when SCE&G sub-mitted its application in accordance with 10 CFR Part 52 (Licenses, Certifications, and Approvals for Nuclear Power Plants) for two 1,107-MW Westinghouse AP1000 ad-vanced pressurized water reactor (APWR) units. The AP1000 features proven technol-ogy, innovative safety systems, and modular construction. Activities that had to be done in a specific sequence in the past are now per-formed in parallel, similar to ship building, thus reducing the construction schedule. The NRC-certified design requires 50% fewer safety-related valves, 80% less safety-related piping, and 85% less control cable. Its sim-plified design should make the new plants easier and less expensive to build, operate, and maintain.

To support the COL, the Final Environmen-tal Impact Statement and Final Safety Evalu-ation Report were issued in April and August 2011, respectively. The total projected cost for both units is $9 billion. Unit 2 is expected to come online in late 2017 or early 2018, fol-lowed by Unit 3 about a year later. The COL is valid for 40 years and can be renewed for an additional 20 years. The application uti-lized, to the extent practical, the standard content identified in the Final Safety Analysis Report contained in Tennessee Valley Author-

ity’s Bellefonte Units 3 and 4 application. The Bellefonte application was developed by NuStart Energy Development LLC as the AP1000 reference plant application.

The Need for ElectricityThe two new units will undeniably be need-ed. Currently, SCE&G’s established reserve margin target is 12% to 18% of forecasted peak demand. If the nuclear plants are not built, the company’s reserve margin will de-cline to 2% by 2016 and –3.9% by 2019.

Contributing to this drop, SCE&G has plans to retire up to six coal-fired units at three locations by the end of 2018 as part of its annual integrated resource plan. The units range in age from 45 to 57 years and are SCE&G’s oldest and smallest coal-fired units. In addition, the U.S. Environmental Protection Agency in recent years has is-sued a series of increasingly stringent regula-tions targeting coal-fired plants. Since 2008, SCE&G has installed more than $600 mil-lion in environmental equipment at its largest coal-fired power plants, significantly reduc-ing emissions of sulfur dioxide, nitrogen oxides, and mercury. However, the company determined that adding costly environmental control equipment to these older plants to en-sure compliance with the new regulations is not cost-effective.

SCE&G is creating a diverse energy sys-tem that can perform best in the widest range of conditions over the coming decades. By adding nuclear generation, SCE&G’s genera-tion mix in 2019 will be 31% nuclear, 27% coal, 28% natural gas, and 14% hydro/bio-mass, and it will reduce carbon emissions by 54% compared to 2005 levels. SCE&G will be in a secure position if carbon taxes, cap-and-trade systems, or other regulatory mech-anisms impose costs on carbon emissions.

Adding equivalent solar and wind genera-tion was not an option. To produce as much electricity as the VCSNS, a solar-powered plant would require panels covering an area the size of Columbia, S.C. Wind generation

would require hundreds of turbines stretch-ing across the entire South Carolina coast, the only place in the state with enough wind to power them. By comparison, VCSNS takes up only a few square miles and is not dependent on the weather.

Financing strategies will minimize rate in-creases to SCE&G’s customers. Legislation passed in 2007 allows SCE&G to recover some costs during construction rather than in one lump sum at the end of the project, dra-matically reducing overall costs of the new units by about $1 billion. Estimates indicate this reduction will save SCE&G’s customers approximately $4 billion in electric rates over the life of the new units. This is a far less ex-pensive way of financing a project compared to a large rate increase at the end of the con-struction cycle.

Unit 1 Gets New NeighborsWithin the boundaries of the 3,600-acre site, the two new units will be located in a lay-down area used during the construction of the operating VCSNS Unit 1, a 966-MW three-loop Westinghouse PWR that achieved commercial operation in 1984. That unit is currently supplying 21% of SCE&G’s elec-tricity. In 2004, the NRC extended the plant’s operating license for 20 years, through 2042. Combined, the three units will be capable of generating 3,200 MW.

The existing nuclear unit, auxiliary facili-ties such as the training center, and transmis-sion line corridors occupy approximately 492 acres of the VCSNS site, and another 784 acres extend into the Monticello Res-ervoir. The Monticello Reservoir will pro-vide the water requirements for Units 2 and 3. The Monticello Reservoir was formed in 1977 by damming Frees Creek, a small tributary of the Broad River that flowed into Parr Reservoir approximately 1 mile upstream from the Parr Shoals Dam. Most of the remaining VCSNS site area is mixed forest, some of which is managed for timber production. The VCSNS site is located in a

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sparsely populated, largely rural area, with forests and small farms.

The site is not vulnerable to the natural threats that destroyed the Fukushima nuclear plant. Based on previous and existing envi-ronmental assessments, the site—primarily featuring low rolling hills—has no active or capable fault lines in the vicinity of the plant. This was demonstrated during Unit 1 con-struction and licensing the two new reactors. A tsunami is not going to be a factor because the site is 435 feet above sea level and located more than 100 miles from the ocean.

Local StaffingWith the nuclear revival in the Southeast, the region already has a strong technical college system, and two state universities have started nuclear engineering programs. South Carolina State University has an undergraduate nuclear program, while the University of South Caro-lina has a graduate program. SCE&G and par-ent company SCANA Corp. are working with Midlands Technical College on a program to train nuclear plant operators.

The construction project continues to recruit and utilize the majority of employ-ees from a skilled craft workforce in South Carolina. More than half of these local work-

ers are from Fairfield, Lexington, Richland, and Newberry counties. Approximately 1,600 Westinghouse/CB&I personnel and contractor and subcontractor personnel are employed on site. As of June 2013, SCE&G had completed hiring slightly over one-half of the operational staffing positions identi-fied as mission critical. The hiring goal for 2013 is to fill approximately 100 such posi-tions. CB&I plans to employ approximately 3,000 to 3,500 employees during the project, a number that is expected to fluctuate during different phases of construction activity.

When they are connected to the grid, the two new units will create about 800 perma-nent jobs for Fairfield County.

Site Preparation and Recent ProgressMany of the initial activities required to con-struct a nuclear power plant are not within the NRC’s regulatory authority and are grouped under the term “preconstruction.” These activities started in 2009 and consisted of clearing and grading, excavating, erecting support buildings and transmission lines, and other non-nuclear safety–related activities. These preconstruction activities can occur before, during, and after the COL application

is submitted or, in some cases, concurrently with NRC-regulated construction. Although certain preconstruction activities may be out-side the NRC’s regulatory authority, many of them can be within the regulatory authority of local, state, or other federal agencies, in-cluding certain activities requiring permits.

By 2010, for example, the 13-story mod-ule assembly building where structural modules will be assembled prior to actual installation—including administrative and office buildings, training facilities, testing labs, tool shops, and warehouses—had been completed. In addition, more than 6.5 mil-lion cubic yards of earth has been excavated in early site preparation for the power block area, the circulating water system, and the switchyard area for Unit 2. Work was also under way on fabricating the reactor pressure vessel and the steam generators, the largest and heaviest components of the AP1000.

Many suppliers are involved in this mas-sive project (Table 1) and the activities out-lined below. These status notes are based on the June 2013 quarterly report.

Plant Design Packages. As of June 30, 2013, the Units 2 and 3 plant design pack-ages issued for construction are 82.4% com-plete. SCE&G is focusing on nuclear island

Table 1. Companies supporting construction and future operation of VCSNS Units 2 and 3. Source: SCE&G

Company Contribution

Westinghouse Electric Co., LLC and CB&I Engineering, procurement, and construction contract; AP1000 provider; architect-engineer, construc-tor, testing, and startup

Westinghouse Electric Co., LLC Overall plant design, AP1000 design certification revisions, procurement of primary NSSS equipment and power block major components, including the turbine generator and plant training simulator

CB&I Site development, construction, secondary equipment procurement, module fabrication, and supply of bulk materials and commodities

Pegasus Steel Module fabrication

Newport News Industries Fabrication of shield building structural modules

Bechtel Power Corp. Program manager; prepared and published the combined construction and operating licenses

MACTEC Engineering and Consulting Inc. Geotechnical field investigations and laboratory testing

Risk Engineering Inc. Probabilistic seismic hazard analyses

Tetra Tech NUS Inc. Site investigations and preparation of the Environmental Report and portions of the Final Safety Analy-sis Report

William A. Lettis and Associates Inc. Geological, seismological, and geotechnical engineering

Pike Electric Corp. Engineering, procurement, and construction contract for approximately 250 miles of new 230-kV trans-mission lines for Units 2 and 3

Doosan Manufacturing Facility, South Korea Reactor vessels, closure heads, and steam generators

Tioga Pipe Supply Co., Inc. RCL cold and hot legs

WEC Carolina Energy Solutions Welding activities, installation of fittings and instrumentation access points

Mangiarotti Nuclear, SpA, Italy Core make-up tanks and accumulator tanks

Sungjin Geotec Co., Ltd., South Korea Deaerators

Thermal Engineering International Moisture separator reheaters

Curtiss-Wright EMD’s facility Reactor coolant pumps

Toshiba Turbine generators

Evaptech Cooling towers



Nuclear

civil structural design packages, piping de-sign packages, pipe support design packages, electrical cable routing, and conduit design delivery. Monthly oversight meetings have recognized improvements in the pace of pro-ducing these packages.

Unit 2 Containment Vessel Bottom Head. On May 22, 2013, the Unit 2 contain-ment vessel bottom head (CVBH) was set in place on its foundation in the nuclear island using the Bigge Heavy Lift Derrick (Figure 1). The CVBH is the steel bowl that forms the base of the containment vessel. With the rigging required for its lifting and placement, the CVBH weighed approximately 990 tons. The CVBH rests on a steel frame and con-crete pedestals that had been placed on the Unit 2 nuclear island basemat in April 2013.

Unit 2 Turbine Building Basement and Condenser B. Placement of the 12-foot-high east, south, and west walls for the Unit 2 turbine building basement has been completed. Backfilling around the Unit 2 turbine building was under way. Work was also nearing completion on the lower section of Condenser B, which is the first of three condensers that will be installed in the Unit 2 turbine building basement. To control vibra-tions in the turbine building, the condensers will be isolated from remaining structures in the building by a system of GERB springs.

Unit 3 Nuclear Island Basemat. By June the team had completed placement of the upper mudmat for the Unit 3 nuclear is-land. Form work, rebar installation, and the installation of drain piping and other fittings are under way to support placement of the Unit 3 basemat in 2013.

Containment Vessel (CV) Rings. Fabri-cation of Unit 2 CV Ring 1 and installation of

internal stiffeners is largely complete, with lim-ited welding remaining to the upper equipment hatch. CB&I Services has welded the seams of the first three courses of plates that will form Unit 2 CV Ring 2. The individual welds on the Units 2 and 3 CVBH and CV Rings are subject to radiographic testing for quality. Overall ac-ceptance rates remain above 99%.

Reactor Vessel (RV) and Closure Head. Hydrostatic testing of the Unit 2 reactor vessel and closure head was conducted at the Doosan manufacturing facility in South Korea, and this equipment was delivered to the site this summer (Figure 2). The Unit 2 RV and closure head, together weighing approximately 450 tons, passed through the Port of Charleston and were delivered to the site by train.

Steam Generators. Unit 2 steam genera-tors have completed hydrostatic testing and were being prepared for shipment during the second quarter, when it was decided to send the reactor coolant pump casings to South Korea for installation on the steam genera-tors at the factory prior to shipment. Welding the casings in the controlled environment of the Doosan facilities was determined to be preferable to performing the work on site. Doosan has proven capabilities to perform this work, having completed similar opera-tions for China’s AP1000 project. Machin-ing, cladding, and welding of components of the Unit 3 steam generators continues with no significant issues.

Reactor Coolant Loop Piping (RCL). The Unit 2 RCL surge lines are on site. The Unit 2 RCL cold and hot legs are currently undergoing installation of fittings and instru-

mentation access points. Work is expected to be completed in the third quarter of 2013. These pipes will then be shipped to the site. Final fabrication work on the Unit 3 RCL cold leg piping and surge lines is under way and is expected to be completed in the fourth quarter of 2013.

Core Make-Up Tanks and Accumula-tor Tanks. Fabrication and painting of Unit 2 core make-up tanks is occurring along with the successful hydrostatic testing of the Unit 2 accumulator tank. Quality assurance data package reviews are under way in prepara-tion for shipping them to the site in the third quarter of 2013.

Deaerator. During the second quarter of 2013, the Unit 2 deaerator was successfully received on site, off-loaded, and placed in storage. The deaerator is approximately 148 feet long and weighs in excess of 300 tons. It was shipped from South Korea to the Port of Charleston and then barged to a facility on Lake Marion. There it was offloaded and brought to the site by road using a special pusher-puller truck. The deaerator’s length prevented its shipment by rail (Figures 3 and 4). Fabrication of the Unit 3 deaerator is pro-gressing as expected.

Moisture Separator Reheaters. The two Unit 2 moisture separator reheaters have been received on site. The Unit 3 moisture separator reheaters are being fabricated as expected.

Cooling Towers and Cooling Water Pump Stations. As of June 30, 2013, ap-proximately 75% of the precast panels that make up Cooling Tower 2A and 25% of the

1. A strong foundation. On May 22, 2013, the Unit 2 containment vessel bottom head was set in place on its foundation in the nuclear island. Courtesy: SCANA/SCE&G

2. Special delivery. The reactor vessel and vessel head arrived at SCE&G’s V.C. Summer construction site June 30, 2013. The parts were sent from the Port of Charleston by rail and delivered using a Schnabel car—a specialized railroad freight car designed to carry heavy and oversized loads. Courtesy: SCANA/SCE&G



Nuclear

precast panels that make up Cooling Tower 3A had been set in place. Fans, fan shrouds, electrical equipment, and other equipment were being installed in both cooling towers.

During the second quarter of 2013, in-stallation of foundation pilings for Cooling Tower 2B was completed, and form work and rebar installation to support placing con-crete for the foundation and basin of Cooling Tower 2B were under way. The foundations and basins for Cooling Tower 3B were com-pleted, and the unit has been handed over to the cooling tower contractor for the precast panels to be set.

Mudmats for the Unit 2 and 3 cooling wa-ter system pump houses were placed. Form work and rebar installation were under way for the placement of the basemat for the Unit 2 pump house.

Turbine Generator. The main generator stator, high-pressure turbine casings and ro-

tors, and low-pressure turbine casings and rotors for the Unit 2 turbine generator were delivered to the site during the second quar-ter of 2013. Fabrication of the Unit 3 turbine generator components is ongoing.

Safety. The project continues to maintain an excellent safety record that exceeds indus-try expectations for projects of comparable size. The construction workforce has previ-ously attained more than 3 million manhours worked without a lost-time injury and is cur-rently approaching 2 million manhours with-out a lost-time injury.

Training and Plant Reference Simula-tor. The implementation schedule for the Plant Reference Simulator (PRS) continues to support the schedule for training and li-censing the AP1000 reactor operators that are required for the initial fuel load for Unit 2 to take place. The four teams created to oversee validation and testing of the PRS began their

work during the second quarter of 2013. In June 2013, a combined Westinghouse Elec-tric Co., SCE&G, and Southern Nuclear Co. team conducted a readiness assessment to evaluate the performance of each team and to gauge success. The results of the assessment will be available in the third quarter of 2013.

Initial Licensed Operator Training. Twen-ty-four students continue in the Initial Licensed Operator (ILO) class that began in 2012. The duration of this class is approximately two years and will culminate with an NRC writ-ten exam in August 2014 and a simulator de-monstrative exam in December 2014. During the review period, the NRC reported that all 24 students passed the Generic Fundamentals Examination, which is the first step in NRC licensing. Those students are now preparing for site-specific systems exams. A second class of 24 students began the ILO training in June 2013. A third class of 18 students is anticipated to begin in December 2013.

Non-Licensed Operator Training. Eighteen students are enrolled in the Non-Licensed Operator (NLO) program and will complete the program in July 2013. A second NLO class was to begin in August 2013.

Construction Reactor Oversight Pro-cess (cROP). While the Operating Reactor Oversight program focuses on the perfor-mance of existing nuclear plants, regulatory oversight for new reactors focuses on the construction period between licensing and initial operation. The cROP (as described in IMC 2506, Construction Reactor Oversight Process General Guidance and Basis Docu-ment) is implemented when an applicant an-nounces its intent to continue construction on a previously suspended project or submits an application for an early site permit, a limited work authorization, a construction permit, and/or a COL. The cROP remains in effect until regulatory oversight for the plant is tran-sitioned to the Reactor Oversight Process.

For example, the NRC conducted an inspec-tion of SCE&G’s quality assurance program and reported no more than minor findings. The NRC also made routine quality assurance implementation inspections at the site. Certain matters were captured in the Corrective Action Program for the site, but no violations were re-quired to be documented in any reports.

Poised for the FutureSCE&G (55% ownership) and Santee Cooper (45%) will jointly own the facility and share in the costs, output, and eventual decommis-sioning of the facility. SCE&G will retain sole responsibility for operation of VCSNS Units 2 and 3 after completing all licensing requirements. ■

—James Hylko is a POWER contributing editor.

3. Deaerator delivery. Because of its weight, the deaerator could not use the overpass bridge to cross highways. The shipment was taken down the entrance ramp on one side of Interstate 20, across the median, and back up the off ramp of the opposite side. These maneu-vers were carefully coordinated to minimize disruption to highway traffic and to ensure the safe delivery of the deaerator to the construction site. Courtesy: SCANA/SCE&G

4. Tight turn. Moving the deaerator through the streets of Camden required careful co-ordination with multiple parties, including local and state law enforcement and governmental agencies, to minimize disruption to traffic and ensure safe delivery of the equipment. Courtesy: SCANA/SCE&G

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Nuclear

Luminant Tests First Nuclear Industry Large-Scale Wireless Monitoring SystemComanche Peak Nuclear Power Plant is the site of a pilot program using a wireless,

automated, remote diagnostic system to monitor generation-critical equipment. The early fault detection provided by such systems could save nuclear plants staff time, trouble, and expensive repairs.

Dave Geswein

In June of this year, the global remote monitoring company Azima DLI and Luminant, the Dallas-based power gen-

eration division of Energy Future Holdings, announced the launch of a pilot program to evaluate a wireless, automated, remote diag-nostic system to monitor generation-critical machinery at Luminant’s Comanche Peak Nuclear Power Plant (Figure 1). This pro-gram represents a number of nuclear industry milestones, including:

■ The first large-scale deployment of a wireless sensing network meeting nuclear power industry guidelines.

■ The first outsourced cloud-based machine diagnostic service that utilizes automated diagnostic software.

■ The first integration of a vibration diag-nostic solution with an enterprise OSI PI process data historian and alarm manage-ment system.

Clint Carter, Luminant’s director of opera-tions services explained, “We selected Azima DLI’s WATCHMAN Service program be-cause it offers a highly sophisticated solution for frequent, automated machine data col-lection, analysis and diagnostics. The Azima DLI system is also completely integrated into our remote monitoring and diagnostic cen-ter, the Power Optimization Center (POC), enabling around-the-clock monitoring and alarming. Azima DLI is bringing us a unique approach to predictive maintenance. We have machine condition visibility like we’ve never seen before.”

The Azima DLI diagnostic software incor-porates decades of mechanical fault detection signatures gathered from many thousands of machine types and models. Azima DLI is also staffed with a deep bench of predictive technologies experts who are available to

consult with Luminant’s in-house engineers and specialists when the need arises.

The WATCHMAN pilot program should further enhance Comanche Peak’s own world-class predictive maintenance program through automated data collection, analysis, and prognostic determinations of emerging equipment issues. The automated collection capability over the plant’s wireless infra-structure enables collection and analysis of generation-critical equipment several times daily. This is a significant leap forward when compared to the traditional industry-accepted practice of monthly data collection.

“Consequently, we are able to identify emergent equipment issues much sooner,” said Carter. “We also expect that we will be able to lighten the work load on our own maintenance and engineering teams in favor

of automated monitoring. We think the value of this information only rises as we seek to improve operational efficiencies in a com-petitive environment.”

The Comanche Peak pilot program was several years in the making as Azima DLI and Luminant collaborated in the development of features considered vital and specific to the nuclear industry, such as network security, data transfer protocols, and reliability. The challenge was to develop a robust, cost-com-petitive network capable of both automated and on-demand data collection, the results of which would be readily accessible to a number of critical user groups. These include Comanche Peak plant personnel, Luminant’s POC in Dallas (which monitors performance across the entire Luminant power generation fleet), and analysts at Azima DLI. The main

1. Luminant on the leading edge. A pilot program at Comanche Peak Nuclear Power Plant to evaluate wireless, automated, remote monitoring of generation-critical assets could help the plant identify potential equipment problems more quickly. Courtesy: Luminant

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objective is fault detection sufficiently early to eliminate incipient equipment issues and unplanned downtime.

How It WorksVibration data is collected by wirelessly enabled sensors installed on 42 genera-tion-critical plant assets. The data is then transferred over a secure network to the WATCHMAN machine database hosted by Azima DLI. Personnel at Comanche Peak, the Luminant POC, and Azima DLI are alerted to the receipt of new data, to which they have immediate, fingertip ac-cess over a simple, secure web browser via Azima DLI’s WATCHMAN Reliabil-ity Portal. The data is processed by Azima DLI’s proprietary ExpertALERT software, which compares the vibration data set to thousands of fault detection signatures ar-chived within the system. These signatures are the compilation of more than 30 years of monitoring and diagnostic experience covering thousands of machine types and models across multiple industries, includ-ing the military.

Fault detections identified by ExpertALERT are automatically posted on the WATCHMAN Reliability Portal to bring them to the attention of Luminant and Azima DLI personnel. Alarms in the Luminant POC are also triggered at prede-termined conditions, 24/7, to enable immediate response by on-duty personnel. Luminant also has the ability to set user-defined parameters to trigger automated alerts that can be distributed by email and/or text messaging.

An Azima DLI analyst will promptly re-view the potential faults for accuracy and note comments, corrections, and recommen-dations. These will appear instantaneously on the WATCHMAN Reliability Portal for review by Comanche Peak and/or the Lumi-nant POC.

In rapidly evolving situations, collabo-ration between all parties takes place that shapes a follow-up action plan. This may involve a visual inspection and/or manual data collection by Comanche Peak person-nel to confirm the fault detection, or simply increasing the frequency of automated data collection to capture rapidly changing oper-ating performance that will alert operators earlier to an emergent issue.

Azima DLI also rolls up the results of all analyses and issues in a weekly manage-ment report to Comanche Peak. That report provides complete visibility into machine condition health from a vibration-monitoring perspective and provides performance trend-ing information, analytical results from a prognostic perspective, and recommenda-tions to all stakeholders.

Impact on the Luminant Power Optimization CenterThe Luminant POC relies on a number of performance monitoring and optimization software packages to maintain peak perfor-mance across the power generation fleet. These depend largely on correlations be-tween high volumes of streaming process data to detect deviations from normal perfor-mance envelopes. When the data depart from normal operating patterns, Luminant POC personnel go to work diagnosing the problem and trying to bring process parameters back into normal alignment.

Alerts triggered by process-based systems are frequently inconclusive and may call for vibration analysis to establish a more pre-cise diagnosis of mechanical faults. With the WATCHMAN program running continuous-ly in the background, current vibration data is already available to supplement process-triggered alerts, saving POC personnel criti-cal time in developing a response (Figure 2).

One important distinction between process-based performance optimization software packages and the Azima DLI WATCHMAN program is that most software programs are not supported by a team of diagnostic experts assigned to supporting customers and their plant operations. Azima’s programs are built on the premise of delivering a technology-enabled service, with more than 40 on-staff vibration analysts solely dedicated to deliv-ering timely, actionable machine diagnostics, with expertise concentrated both by industry and machine type. “Azima DLI’s deliverable has more in common with mission-critical information services than it does with hard-ware or software vendors. Our technology is vital to creating transparency around timely

actionable information,” said Burt Hurlock, CEO of Azima DLI, “but it’s the quality of the conclusions drawn by the plant mainte-nance teams, operators, and our own analysts that really counts.”

Potential Impact on the Nuclear IndustryAs an opinion leader in the nuclear indus-try, Rafael Flores, Comanche Peak’s chief nuclear officer, has long championed a cul-ture of continuous improvement through the application of leading technologies and services with a focus on nuclear safety and plant reliability.

“We view the WATCHMAN pilot at Comanche Peak as an industry-level dem-onstration of how we can apply advanced telecommunications technologies and ana-lytics to improve operational efficiencies and plant performance,” said Flores. “Anything that we can do to improve our monitoring ca-pabilities contributes to our focus on nuclear safety and our goal of providing a safe, reli-able, clean source of electricity for Texans.”

While safety, reliability, cost efficiency, and transparency are compelling aspects of Luminant’s work with Azima DLI, the un-tapped potential of the WATCHMAN solu-tion is its scalability. Nuclear power plants present special challenges to consistent, whole-plant machine health monitoring and reporting. The additional challenge to devel-oping best practices for the nuclear industry is the absence of an accessible, broad-based critical mass of information about mechani-cal faults in the nuclear setting.

“Nuclear power generation is a very spe-cial industry comprised of professionals dedicated to continuous improvement with

2. A watchful eye. The WATCHMAN program provides current vibration data to supple-ment process-triggered alerts, saving Luminant’s Power Optimization Center personnel critical time in developing a response. Courtesy: Luminant



NUCLEAR

distinct requirements,” said Ben Mays, Co-manche Peak’s vice-president of nuclear en-gineering and support and a 33-year veteran of the plant. “The way the WATCHMAN pro-gram centralizes data and makes it broadly available to all our users may have powerful implications for developing and sharing best practices, which is a time-honored tradition in the nuclear industry,” said Mays. “If we can inspire other nuclear power generators to participate, the potential exists to make a material contribution to advancing monitor-ing and maintenance practices.”

Disruption in the New World of Big DataAs remote monitoring capabilities become more widespread, and the era of big data cre-ates expectations of universal transparency and awareness, most large industrial produc-tion operations will find themselves in cul-tural transition. The traditional formula for manual data collection, review, and problem identification will become obsolete in favor of highly efficient automated systems. The re-sult will be improved economies of scale and less human investment to derive value from the process. Technology and automation also

can assist in offsetting the forecasted impact of workforce attrition and the associated loss of vital knowledge and experience as person-nel retire.

“The automated data collection and diag-nostic elements of the WATCHMAN program will never displace the onsite teams,” Carter observed, “but the information can make them a lot more powerful, save them hours of legwork in route-based data collection, and give them the visibility to get ahead of their preventive maintenance, so they can manage the work and not the other way around.”

“There’s no question that this will be a change from our traditional way of managing predictive maintenance programs.” Flores added, “but it’s the next evolutionary leap made possible by the Technology Age. Why wouldn’t we take full advantage of it if it makes us better at what we do?”

Combining ApproachesThe Comanche Peak wireless monitoring pilot project will run for six months before Luminant decides whether to make it a per-manent, integrated feature of its predictive maintenance program and determines how far it makes sense to expand the automated

service throughout the facility. The plant’s preexisting predictive maintenance program covers approximately 800 pieces of machin-ery on route-based manual data collection programs. While periodic manual data col-lection makes sense for a good portion of these machines, there may be benefit to ex-panding the automation capabilities where it makes good business sense.

“Current best practice is almost always some combination of higher frequency, au-tomated reporting with less-frequent, manual route-based reporting—a combination we support at many other customers,” Hurlock observed.

Comanche Peak, and Flores in particu-lar, pride themselves on being innovative leaders in the nuclear power industry. “This pilot program is just another step in a long-standing commitment by Comanche Peak to continuous improvement,” said Flores. “With information and diagnostic technolo-gies advancing as rapidly as they are, we simply can’t afford to stand still if these ca-pabilities can make us and our competitors more efficient.” ■

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Water ManageMent

Why Your Power Plant Needs a Water Management PlanWhether you are preparing for the impacts of future U.S. regulations, need to minimize

your water-related plant costs, or want to develop more sustainable practices, a water management plan can help you meet your goals. Here’s a blueprint for developing a relatively simple, multi-use plan.

Colleen M. Layman, PE

Recent articles in POWER and else-where have noted that all types of generating technologies are more fre-

quently feeling the pain of constrained wa-ter supplies. The limitations can come from increased regulatory requirements, water quality changes, or growing water supply costs or limitations. Given the accumulat-ing water-related pressures on power plants, having a clear understanding of how a plant manages its water and wastewater internally is becoming more important for plant opera-tors and engineers.

Proactive management of how water is used in a power plant can do more than re-duce water consumption. It can also lower operational costs and help a plant plan for a future in which it may have to deal with the onslaught of new and updated U.S. regula-tions expected over the next couple of years.

Even plants that do not expect to be af-fected by pending U.S. regulation changes can benefit significantly from a policy of increased sustainability, water conservation, and environmental awareness. Improved site water management and identification of in-creased reuse and recycle opportunities can result in lower water supply and disposal costs, decreased wastewater treatment needs, and an improved sustainability rating or good neighbor image.

Go with the FlowOne of the best ways that a plant can manage its water resources more effectively is to de-velop a plantwide water management plan. A water management plan is a comprehensive site-wide strategy for maximizing water use efficiency, minimizing wastewater discharge, and encouraging a policy of sustainability and reuse/recycle to the maximum extent practical to control a plant’s water footprint.

The first step in developing a plan is to con-struct an overall plant water balance depicting the current plant water picture. The water bal-ance should identify all water consumers and wastewater producers throughout the facility

and indicate all the flow routes and distribu-tion pathways. (See the web version of this article at powermag.com for a downloadable flow diagram depicting a water balance from a typical coal-fired power plant.)

The most difficult challenge in developing an accurate site water balance is collecting adequate data to model the plant water and wastewater streams precisely. Inclusion of seasonal and historical data and its impact on the plant water balance is desirable, such as periodic degradations in water supply qualities that reduce cooling tower operating cycles.

This water balance should include average daily usage rates as well as peak and mini-mum flows to create an accurate picture of the plant’s water footprint. Reduced load operations (if they are relevant for a unit), partial plant operations (for instance, single-unit operation in a two-unit plant), as well as other off-design operating scenarios should be evaluated, as appropriate, to determine how they will affect water consumption rates and wastewater production.

This may require that the water manage-

ment team perform its monitoring activities at several different times over the course of a year to capture the various plant operating scenarios of interest and collect the desired data. Off-design operating conditions, espe-cially at multi-unit sites with integrated water and wastewater systems, often can produce the most challenging water operating scenar-ios and can drive decisions related to equip-ment sizing.

Chart ContaminantsOnce all flows have been charted, the sec-ond step is to understand the mass balance of contaminants present in the plant water and wastewater streams. This will likely involve sampling and testing the internal streams that are not normally monitored in order to paint a true picture of:

■ Where the plant is adding contaminants to the water streams or concentrating exist-ing contaminants.

■ What contaminants are being added or concentrated.

1. Get the full picture. Portable flow monitors and sample collection devices can be used to monitor inlet and outlet flows and collect water samples from locations that are not typically instrumented to capture this data. Courtesy: HDR Inc.

13_PWR_110113_WaterMgt_p52-53.indd 52 10/14/13 1:04:19 PM


Water ManageMent

■ In what concentration the contaminants are present in each stream.

Portable flow monitors and sample collec-tion devices can be employed to monitor in-let and outlet flows and collect water samples from locations that are not instrumented to capture this data currently (Figure 1).

Tracking plant water and wastewater flows, and developing a mass balance, can be as simple as developing an Excel spreadsheet to log and analyze the data (see the web ver-sion of this article for a downloadable sample file), although a number of engineering and consulting firms have developed specialized tools to aid in this process.

The flow rates and the water quality constit-uents for individual plant water and wastewa-ter streams—such as cooling tower makeup, boiler and cooling tower blowdown, equip-ment drains and washdown, pretreatment system wastewaters, captured storm waters, strainer and filter backwash waters, dewater-ing equipment filtrate, and many other plant sources and users—are assessed and tabulated to enable tracking throughout the plant.

Once the plant water balance is devel-oped and the mass balance of contaminants is tracked throughout the plant, staff can use this tool in conjunction with the water bal-ance to assess how operational changes or stream redirection might allow the plant to reuse some internal wastewater streams and reduce its water footprint, or reduce the level of contaminants that are discharged or that need to be removed.

Obvious examples of internal recycle/re-use opportunities include recycling reverse osmosis reject as cooling tower makeup, collecting and reprocessing boiler or heat re-covery steam generator blowdown water, and recycling cooling tower blowdown as flue gas desulfurization makeup water. However, a close review of the plant water and mass balances can reveal quite a few opportunities for water reuse or water conservation. Many of these internal recycle/reuse opportunities can be inexpensive and relatively simple to implement, involving only piping and valv-ing modifications, though some may involve the addition of treatment equipment such as clarification or filtration to reprocess the wastewater streams to make them suitable for reuse. Determining the water quality of the wastewater stream contaminants, therefore, is a crucial early step in evaluating wastewa-ters for reuse opportunities and performing a cost-benefit analysis.

Development of water and mass balances will also prepare a plant to intelligently eval-uate the impact of and reaction to potential modifications to the plant water balance that may occur due to regulations changes. The

new proposed U.S. regulations may affect a plant’s cooling water systems, material-han-dling and conveyance systems, and wastewa-ter discharges. Potential changes such as the addition of wastewater treatment systems or the rerouting of wastewater streams can be simulated to assess their effects on overall plant operations.

Impoundments and Storm WaterOperators and owners tend to focus primarily on the quality of water coming into the plant and the wastewater quality going out of the plant, as required to meet their plant discharge permits. In contrast, knowing exactly what is going on within the power plant boundaries in impoundments and process sumps is not always as clear, especially in older facilities, where upgrades and plant modifications have considerably altered the plant water picture over the years.

Also, in many coal-fired power plants, coal combustion waste ponds and impound-ments are utilized for equalization and treat-ment of numerous plant wastewater streams, complicating the plant’s ability to easily as-sess the potential for reuse of each individual stream. However, with some of the proposed U.S. regulation changes, coal-fired power plants may be required to do just that. Seg-regation and separation of plant wastewaters can minimize the volumetric flow rate that requires additional treatment to meet the pro-posed regulations.

For instance, at one facility where HDR has been assisting with water and mass bal-ance activities in preparation for expected

National Pollutant Discharge Elimination System permit changes, the engineering team was able to reconfigure portions of the waste-water collection system. It segregated storm waters into contact and noncontact storm waters and separated mixed process water streams, allowing the plant to reuse a fair por-tion of its previously discharged wastewater. As a result, the facility significantly reduced the potential treatment costs associated with meeting new permit requirements and real-ized an overall cost savings.

Get PreparedEspecially in light of the upcoming regula-tion changes and the expectation that addi-tional levels of wastewater treatment will be necessary to meet some of the new discharge limits, any plant likely to be affected should explore the potential for internal recycling or reuse of plant wastewaters and minimiz-ing water waste in order to keep wastewater treatment costs as low as possible.

Starting now, evaluating the current plant water and wastewater conditions, conducting sampling and flow measurement programs, and assessing current wastewater treatment systems are key to development of a base-line and plan of attack for dealing with the impending regulation changes. Knowing exactly where your plant’s starting point is and developing a solid data history is crucial to determining what you may need to do to meet changes in regulatory requirements. ■

—Colleen M. Layman, PE (colleen [email protected]) is a technical prac-

tice director with HDR Engineering Inc.

Binz BiteIn his 9/21 blog post “The Undoing of Ron Binz,” Contributing Editor Kennedy Maize shared some of the back story on the peculiarly public and contentious nomination and vetting of Ron Binz for chairman of the Federal Energy Regulatory Commission. Ken, who has been covering FERC nominations since 1977, predicted that the pro-Binz PR campaign would come back to bite his backers. (As it did.)“The failure of the Binz nomination suggests that whoever thought it was a good idea to mount a political campaign to get him confirmed should be kept away from any future FERC nominations.”Get Ken’s blog posts while they’re fresh! You’ll find them on our homepage, powermag.com, under the POWERBlog heading.

13_PWR_110113_WaterMgt_p52-53.indd 53 10/14/13 1:04:31 PM


Coal Plant o&M

Reducing Bottom Ash Dewatering System MaintenanceKeeping equipment clean and reliable is the responsibility of a plant’s O&M staff, but

sometimes you have to change processes to avoid unnecessary work. Here’s how one plant found a cure for its bottom ash collection and dewatering system headaches.

Kevin Boudreaux

Many coal-fired power plants use water to cool and sluice bottom ash away from the bottom of the

boiler for final disposal, and then they recir-culate the water for reuse. This system is also known as a hydraulic bottom ash system. Many plants dispose of the ash-laden water to an ash containment pond, allowing evapo-ration to naturally remove the water. Other plants aren’t fortunate to have the space for, or are prohibited from using, ash ponds and must rely on a water clarification/dewatering system to speed the water removal process. Once dewatered, the damp ash is usually re-moved from the site by trucks.

The many advantages of dewatering the ash-water mixture are apparent, but there are tradeoffs. System maintenance may increase due to excursions in system makeup water quality and fouling caused by suspended sol-ids on piping and equipment. In some cases, obstructions to water flow can cause a plant shutdown due to poor boiler seal-water con-trol and excessive accumulation of bottom ash. Removing the scaling from pipe and equipment internals is expensive and time-consuming. One plant long tormented by pipe-scaling problems began its search for a permanent solution in August 2012.

Dewatering AshXcel Energy’s Arapahoe Generating Station, located south of downtown Denver, is config-ured with a hydraulic bottom ash system that removes about 240 cubic yards of dewatered ash every 10 to 14 days. Dewatering bins were installed and commissioned approxi-mately six years ago to reduce water con-sumption and the amount of waste material. After dewatering, the mixture of the mate-rial discharged to the trucks is approximately half water, which means that the dewatering system also disposes about 1,000 gallons of water over the same time period. The plant’s original discharge pond remains in service.

The dewatering system consists of two 100%-sized dewatering bins, each of which

is 22 feet in diameter, 50 feet tall, and holds roughly 62,600 gallons. The dewatering bins receive water from several sources from with-in the plant: the bottom ash hopper overflow sump, recirculated water from the high-pres-sure bottom ash hoppers, surge and settling tank sludge return pumps, and the dewatering bin area sump. In short, any water entering the bottom ash–handling system will find its way to the dewatering bins (Figure 1).

Sluice water entering the dewatering bins provides sufficient residence time for the bottom ash to settle out. The water is first decanted from the dewatering bins and sent to an ~86,500-gallon settling tank to remove any remaining ash particles, which are re-turned to the dewatering bins by sludge return pumps. Next, the high–ash content mixture remaining in the dewatering bins is removed via screens located on the tank bottom and hauled away in trucks for disposal.

Water from the settling tank and any

required makeup water is directed to an ~148,600-gallon surge tank. Closing the loop, water in the surge tank is the primary water source for the entire hydraulic bottom ash system and for housekeeping purposes, such as periodic flushing of the surge and set-tling tanks, dewatering bins, and the bottom ash overflow and dewatering bins sumps. As a backup, makeup water can also be collected from the discharge pond.

Surge tank water has two critical uses. First, a low-pressure (LP) water circuit is used to maintain the pressure seal on the boiler bottom ash system. The connection between the top of the bottom ash hopper and the bottom of the boiler seals in com-bustion gases and accommodates the verti-cal thermal expansion of the boiler (Figure 2). The pressure seal has two parts. A water trough is attached to the top of the fixed bottom ash hopper. Next, a skirt, located around a rectangular opening on the bot-

1. Dewatering system overview. A water–bottom ash mixture is sent to the bins to filter the water from the solids. The mixture is separated when it passes through screens located at the bottom of each bin. The recovered water is collected in the settling tanks before treatment and reuse. Courtesy: Nalco Co.

Surge Tank

Settling Tanks

Bins

14_PWR_110113_CoalPlantO&M_p54-56.indd 54 10/14/13 1:08:20 PM


Coal Plant o&M

tom of the boiler through which the bottom ash falls, remains continuously immersed in the 80F to 90F trough water as the boiler moves up and down due to thermal ex-pansion and contraction. A loss of trough water will result in the loss of the boiler pressure seal, furnace pressure will drop, and a boiler trip soon follows. The second critical use is to cool the refractory on the bottom of the boiler.

Water WoesSince commissioning the ash system, the plant has struggled with two areas of plant operation. First, fouling of the piping and nozzles of the LP water circuit would re-duce water flow that would cause either degradation or, in some cases, complete loss of the boiler pressure seal. When the seal is lost, city water must be used as a replace-ment. In addition to boiler operation issues, the cost of supplementing with city water is steep, and operators are pulled away from their normal work to manage the trough wa-

ter levels (Figure 3). In the words of plant management, “[It is] a major headache for the plant, with the worst case scenario being plant shutdown.”

Fouling of the center screen in the dewater-ing bins causes the second operational head-ache (Figure 4). When the screens become obstructed, excess water is entrained with the ash, thus prohibiting it by law from be-ing transported on the highway due to excess water content. The logistics of removing bot-tom ash from the plant to the disposal area can get complicated, as the timing and number of trucks required to move the waste is limited. In the worse case, the inability to process bottom ash in a timely way can cause a plant forced outage. Finding a solution to the problem of pipes fouled with bottom ash was critical for the plant to maintain efficient plant operation.

The real cost incurred by the plant with these operational problems is significant. Based on conversations with plant personnel, the dewatering system and piping required cleaning with high-pressure water every two weeks at a cost of $3,000 to $5,000 per event. To ensure a thorough cleaning, the sys-tem also required disassembly, cleaning, and reassembly—a two-day process. In all, plant staff estimate that just fees paid to a contract cleaning company related to dewatering sys-tem fouling/scaling are around $120,000 each year. That estimate would be much higher if the plant staff hourly costs and the cost of any operational limitations, particularly a forced outage, were included.

Understand the ChemistryAnalysis of the deposits found on the inner-diameter pipe walls found calcium carbonate and aluminum-hydroxide scale (Table 1). The deposit was fairly soft, probably due to the hydroxide present. Knowledge of the con-stituents of the scaling is an important factor when developing a trial treatment program.

Water chemistry experts examined the bottom ash sluice water chemical analy-ses (Table 2) and realized that minimizing fouling and scaling would be very difficult, particularly because the sluice water was relatively high in hardness given the pH of the water. The elevated pH, hardness (total dissolved solids, TDS), and total suspended solids (TSS) of the water made for a difficult selection of the proper scale inhibitor and solids dispersant. Furthermore, recall that the bottom ash loop is essentially closed with very little water loss or makeup, so any water chemistry program selected must also remain stable for extended holding times.

Based the operating conditions of the system, a chemical additive (Nalco 5200m) was selected because it is excellent in mini-mizing calcium carbonate scaling as well as

2. No way out. The seal water system keeps the combustion gases in the furnace while allowing ash to fall through a rectangular opening in the boiler bottom. The seal is a skirt around this opening that remains submerged in water as the boiler vertically expands and contracts during operation. Recycled water is used to maintain the seal. Source: Nalco Co.

3. Closed for business. The near com-plete obstruction in the seal water nozzle was due to scale formation. Periodic system out-ages to clean pipes and equipment were re-quired. Courtesy: Nalco Co.

4. Sealed tight. At the bottom of each of the bins shown in Figure 1 is a series of screens that separate the ash from the sluice water. The water passes through the screens and is recycled, and the ash collects on the screens, as shown here. When operating cor-rectly, the ash falls from the screens into a truck bed for disposal. The plant routinely ex-perienced ash deposits that required manual cleaning of the screens. Courtesy: Nalco Co.

Parameter Deposit (%)

Calcium 25

Aluminum 24

Silica 6

Iron 4

Sulfur 4

Magnesium 2

Barium 1

Phosphorous 1

Loss on ignition 33

Major compounds Calcium carbonate

Minor compounds Aluminum hydroxide

Table 1. Deposit and scale analy-sis. Source: Nalco Co.

LP nozzle from ash system

Skirt (boiler water)

Skirt (boiler water)

Seal water overflow back to ash system

Trough to maintain boiler seal



Coal Plant o&M

minimizing the potential for fouling due to aluminum and particulate matter. Once the chemistry selection was made, the volume of water in the system, water losses, and make-up source quality had to be found in order to

develop the correct dosage rate. However, the makeup to the ash-handling system is usually discharge pond water, which consists of myr-iad sources, ranging from river water to floor drains and cooling tower blowdown. There is no metering on the makeup to the ash system, so determining water loses was difficult.

The decision was made to base the ad-ditive feed rate on the total volume of the system for initial dosage purposes and then maintain chemical feed of 20 ppm of product, based on organic-phosphate re-siduals. Based on tank capacities, the total ash-handling system volume was deter-mined to be roughly 330,000 gallons. This is based on the tank capacities plus 20% for piping and the many sumps throughout the system.

The best location for injecting the addi-tive was determined to be the LP header, and a hot tap at this location was easily completed. This location was also ideal be-cause the LP circuit was of most concern, and feeding the scale inhibitor there would be appropriate from a chemical demand per-spective (Figure 5).

The metric used to determine the success of the trial was scale formation on the seal water nozzles and center screens. The plant arranged for a complete cleaning of the en-

tire dewatering system (at a cost of about $50,000) prior to the start of the trial. Once cleaned, plant staff monitored scale forma-tion and fouling by performing visual inspec-tions of the nozzles and center screens.

The trial began in August 2012, with no set end date established. If cleaning fre-quencies did not improve, the trial would be terminated. However, if the cleaning fre-quencies decreased, the trial would continue so that a proper economic analysis could be performed. If the reduced cleaning frequency justified the cost of the chemical treatment regimen, then the trial run would become a permanent solution.

Squeaky Clean ResultsOne year has elapsed since the start of the trial, and dewatering system, center screens, and seal water nozzles still do not require pressure washing. Keeping the system clean required, on average over the year, only 2.3 gallons per day of scale inhibitor. The economics of the trial were straightforward: The prior cleaning costs were approximately $120,000 per year, and the cost of chemicals was about $20,000 per year, producing a simple payback of about two months. This simplistic analysis ignores the time spent by plant staff per-forming housekeeping chores and the very high cost of plant downtime.

Perhaps as important as the monetary savings was a grateful O&M staff released from unproductive housekeeping chores to resume the jobs for which they were trained. ■

—Kevin Boudreaux (kjboudreaux@nalco .com) is a power industry technical con-

sultant for Nalco Co.’s Power Group.

Parameter (ppm as ion) Filtered Unfiltered

Calcium 510 540

Aluminum 42 52

Silica ND ND

Iron ND 0.6

Sulfate 1,300 NA

Magnesium 0.87 2.1

Barium 0.16 0.51

Phosphorous ND 0.09

Total alkalinity 110 NA

Phenolphthalein alkalinity

40 NA

Bicarbonate 31 NA

Carbonate 80 NA

pH 9.2 NA

Conductivity (umhos) 2,700 NA

Table 2. Bottom ash water analy-sis. Source: Nalco Co.

5. Feeding tube. The hot tap for the chemical injection portion is shown on the blue pipe. The Nalco 5200m is fed directly from the chemical tote. Courtesy: Nalco Co.

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new products to power Your BusIness

Scaffold- or Railing-Mounted LED LightIndustrial lighting company Larson Electronics has announced the release of a new explosion-proof LED light designed for portable mounting to ladders, scaffolds, and railings for convenient operation. The EPL-JHLP-100 LED explosion-proof LED light fixture produces 7,000 lumens. The versatile bracket-mounted LED fixture is weatherproof and comes with an adjustable aluminum ladder/scaffold mount that makes it ideal for industrial applications, maintenance, cleaning, and servicing duties. The solid state LEDs run cooler than halogen and metal halide lamps, resulting in an easier-to-handle unit and less heat in the workspace. The aluminum rail/ladder bracket can be adjusted from 26 inches to 43 inches. (www.larsonelectronics.com)

Battery-Operated Proving Unit for Two-Pole Voltage TesterMegger now offers a palm-sized, battery-operated proving unit that provides a substitute voltage source for testing a two-pole tester. The MPU690 helps to ensure that a voltage tester is capable of detecting voltage safely and efficiently. The compact, portable device is ideal for use where a live voltage-testing source is not available or where maneuverability is limited, such as when personnel are on a ladder or in a tight, confined space. The MPU690 generates stepped voltages beginning at 690 V and slowly ramps down until the device shuts off, giving an indication that the two-pole voltage tester can indicate voltages at different levels correctly. LED lights indicate individual voltage steps as well as a power display on the device. (www.megger.com)

Portable Crane Scale with Wireless RemoteA line of fully portable crane scales that can operate for up to 50 hours on a single 9 V DC battery is available from Alliance Scale Inc. of Canton, Mass. Alliance/CAS IE Series crane scales feature a wireless remote control with a 32-foot range and function keys for power, zero, tare, and hold. Offered in 100 x 0.05 lb., 200 x 0.1 lb, 500 x 0.2 lb, 1,000 x 0.5 lb, and 2,000 x 1.0 lb capacities, these portable crane scales are suitable for a wide range of weighing applications. They have a sturdy aluminum die cast case, easy-to-read 1.1-inch LCD display, and are supplied with a rugged hook and shackle for hanging. (www.alliancescale.com)

15_PWR_110113_NewProducts_p57-58.indd 57 10/14/13 1:20:59 PM


NEW PRODUCTS

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

Welding End Prep ToolA portable welding end prep tool that features air-operated clamping, which reduces cycle times for highly repetitive end prep milling, is available from ESCO Tool of Holliston, Mass. The pneumatic clamping system reduces operator fatigue and increases throughput by up to 600%. Featuring a self-centering draw rod that rigidly mounts into the tube or pipe I.D., the MILLHOG Mongoose Air Clamp welding end prep tool employs clamp ribs that retract off the mandrel automatically by simply flipping a toggle switch after milling. Designed for tubes and pipe from 5/8 inch I.D. to 3 inch O.D., this tool can bevel, face, and bore simultaneously and remove membrane. (www.escotool.com)

Bin Level SensorBinMaster Level Controls introduces the new BinMaster RL level sensor designed to provide highly reliable bin level data in challenging environments where dust levels are extremely high. The non-contact, continuous level sensor works in powders and solid materials of all types, including very low dielectric materials, which until now have been largely incompatible with non-contact devices. The acoustics-based BinMaster RL features a self-cleaning, non-stick surface that does not require routine maintenance or air purge for cleaning. This eliminates manual cleaning of the sensor and frequent climbing of bins, which is a safety hazard. It uses acoustics-based technology at very low frequencies, which allows it to penetrate dust even during filling or emptying cycles. The BinMaster RL is designed to be easy to program and simple to maintain. A quick-start guide is used to configure the RL directly from a screen on the head of the device or alternatively, from a PC. Multiple bins can be connected using a daisy chain to help save on wiring and installation costs. The BinMaster RL outputs a 4-20 analog signal for simple connection to an existing control system or display module. Users can view measurement data for one bin or all bins at once from a PC when the RL is used with MultiVision software. (www.binmaster.com)

DVM-80 Series Digital Voltmeters HDE’s DVM-80 Series digital voltmeters and phasing sets are compact, high accuracy instruments designed to measure voltages up to 80 kV. The DVM-80 series incorporates Phase Accurate Technology, which makes all voltage readings, whether made from line-to-line or line-to-ground, accurate and repeatable to within 1%. There are 3 models — the DVM-80, DVM-80T with test point mode, and the latest exciting addition to the series, the DVM-80UVM. The DVM-80UVM is a compact, high accuracy dual stick voltmeter and phasing set with capacitive test point mode and peak hold. It measures voltage from 5 V to 40 kV and up to 80 kV with a pair of optional add-on resistors. The two-stick design can be used in both overhead and underground applications. (www.HDElectricCompany.com)

15_PWR_110113_NewProducts_p57-58.indd 58 10/14/13 1:21:56 PM


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Commentary

Natural Gas Is Ready Now to Power Emerging MarketsPaul Smith

A few short years ago, our nation was scrambling to import natural gas from abroad, and an energy-secure America was little more than a pipe dream. Oh, the difference a

decade makes.Advances in energy production technologies such as hydraulic

fracturing and horizontal drilling have revolutionized the outlook for natural gas in the United States, unlocking the countless op-portunities to tap this flexible, cleaner energy source.

The result? Reserves and projected supplies of natural gas are at historic highs. Prices are forecast to remain affordable and steady for at least the next three decades. And emerging markets across the user spectrum—from power generation to manufactur-ing to transportation—are embracing this foundational fuel like never before.

Far and away, the most growth potential for natural gas is through its use for power generation. While coal remains the dominant fuel in the West, Midwest, and Northeast regions, natu-ral gas is beginning to close that gap. Natural gas captured more than a 20% market share in the Northeast in 2012, and in the Southeast, the two fuels had effectively even market shares, be-tween 30% and 40%.

In Texas, Florida, and California, the three biggest power gen-eration states, natural gas is the primary fuel of choice.

Fueling a Balanced MixWith all this impressive growth, it’s easy to get lost in the nar-rative that utilities are going “all in” on natural gas. While it is expected to make up some 65% of new capacity additions over the next several decades, it’s important to keep some perspec-tive. By 2040, the Energy Information Administration (EIA) says only 28% of our power will come from natural gas. Time will tell if EIA has it right. The larger point is that the United States is moving toward the use of more natural gas, but the shift is part of a diversified and balanced power mix.

Two major factors are driving utilities in this direction, and the first is the almighty dollar. If you look at the levelized cost of electricity, which takes into account all the costs of power over its entire life, natural gas produces the most affordable kilowatt hour. Lower than coal, nuclear, or renewables.

And thanks to new technologies that allow us to ramp up pro-duction of this vast American resource quickly, and geographi-cal diversity of production, we are able to mitigate price spikes, where we couldn’t always do that before.

The other factor is the environment. A cleaner energy future is a priority for everyone, and aside from new and tightening regulations on power plant emissions and the relative ease of getting a new natural gas combined cycle power plant approved and built, the use of more natural gas is largely responsible

for U.S. carbon emissions falling to their lowest level in 20 years. And according to a report by the environmental invest-ment network Ceres, SOx and NOx emissions among the top 100 U.S. power producers have declined by nearly 70% over that same time period.

Partners for PowerOur two industries are working through some remaining natu-ral gas/electricity interdependency issues, including how best to deliver this impressive resource to market in an efficient way, and the results of this collaboration look very promising, as evi-denced by a recent study by BENTEK Energy focusing on infra-structure availability in the Northeast.

According to BENTEK, shale plays like the Marcellus and the Utica in the Northeast region are making the transpor-tation equation much easier to solve, as the distance from wellhead to consumer shortens and pipelines are able to offer new, more flexible services to consumers. Ensuring reliability to large natural gas consumers will continue to be a top prior-ity for the industry.

Many industries use significant volumes of natural gas in the manufacturing process, including steel, fertilizer, chemical, and plastics. For some, natural gas can account for up to 40% of overall production costs. From the Gulf Coast to the Rust Belt, billions are now being invested right here in the United States by international companies looking to take advantage of an afford-able and abundant industrial feedstock.

There is also significant opportunity for demand growth in the transportation sector. Of the 15 million natural gas vehicles in use worldwide, only about 120,000 of these are currently driving on U.S. roads. But the tide is turning, and major private fleet operators like UPS and Waste Manage-ment, along with public fleets such as Los Angeles County, are converting their vehicles and finding enormous fuel cost savings, with natural gas priced on average one-third less than conventional gasoline. Combine this with growing in-terest in natural gas as a fuel for large marine, rail, and other off-road transportation as well as oil and gas services, and there is the potential to add up to 90 billion cubic feet per day in demand.

The shale gas revolution has transformed the U.S. into a global clean energy leader, rather than simply a large energy consumer. And thanks to this enormous new resource, demand is on an impressive trajectory, and the natural gas industry stands ready to meet the needs of these new markets—now, and for the fore-seeable future. ■

—Paul Smith ([email protected]) is senior director of infrastructure for America’s Natural Gas Alliance.

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