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Vol. 159 • No. 11 • November 2015

Our 2015 Nuclear Top PlantAward Winners

Controlling Unwelcome Critters

Coping with Boiler Load Cycling

Coal Dust Combustion Lessons Learned

BUSINESS & TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRY SINCE 1882

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Established 1882 • Vol. 159 • No. 11 November 2015

ON THE COVERPalo Verde Nuclear Generating Station,

located in the Sonoran Desert west of

Phoenix, uses 100% recycled municipal

wastewater for cooling its condensers.

The plant’s on-site treatment facility aer-

ates the reclaimed water as part of the

treatment process. Courtesy: Arizona

Public Service

SPEAKING OF POWER

Fuel Guidelines, Fuel Consumption, and Climate Change 6

GLOBAL MONITOR

New Options for Solar PV 8

India Refocuses Coal Future 9

THE BIG PICTURE: Levelized Cost of Electricity 10

Power Giants to Get Federal Funds to Develop Large-Scale Carbon Capture Pilots 12

AREVA’s Next-Gen BWR Fuel Is Tested in the U.S. 12

South Africa Puts First Large IPP Project Online 14

POWER Digest 16

FOCUS ON O&M

Smart Access Planning Enables Efficient Cooling Tower Maintenance 18

LEGAL & REGULATORY

FERC’s Enforcement Priorities After 10 Years Under the EPAct 22 By Carlos E. Gutierrez, counsel, Davis Wright Tremaine

COVER FOCUS: NUCLEAR TOP PLANTSThe fate of nuclear fleets depends on where they are located. Countries gener-

ally are following one of three paths: widespread shutdowns, ramp-up in new

builds, or diligent maintenance of existing units. Our 2015 Top Plant Award

winners in the nuclear category demonstrate how varied the experience of

these plants can be.

Central Nuclear Néstor Kirchner (Atucha II), Lima, Argentina 24The U.S. isn’t the only country to have seen work begin on a nuclear unit only

to halt for many years before being taken up again. In spite of what some-

times seemed like insurmountable odds, Atucha II represents not just new

capacity but also the revitalization of Argentina’s nuclear industry.

Palo Verde Nuclear Generating Station, Wintersburg, Arizona 28This desert-sited nuclear plant, the largest power generator in the U.S., proves

that with superior operation and maintenance, a nuclear plant can be a record-

setter even as it moves into its “second lifetime” as a relicensed plant.

12

24

CONNECT WITH POWER

If you like POWER magazine, follow us online for timely industry news and comments.

Become our fan at facebook.com/POWERmagazine

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Join the LinkedIn POWER magazine Group and the Women in Power Generation

Group

www.powermag.com POWER | November 20152

THE FIRST

THE NEXTGENERATION OF ADVANCEDNUCLEAR PLANTS

TO INNOVATE

SPECIAL REPORT— OPERATIONS & MAINTENANCE

Wildlife and Power Plants: New Solutions for Animal Problems 32From the birds and the bees to invasive aquatic species, power plants around

the world struggle to cope safely and economically with unwelcome crea-

tures. But cope they must, because failing to stop these trespassers can result

in massive damage to plants and potential injury to people.

OPERATIONS & MAINTENANCE

Load Cycling and Boiler Metals: How to Save Your Power Plant 38As cycling former baseload units becomes the new normal, concerns about

cycling’s effects on equipment mount. You can minimize damage by under-

standing how it happens and which strategies mitigate undesired effects.

FUNDAMENTALS

Ensuring Reliable Boiler Operation Through Proper Material Analysis 42Many coal-fired units around the world are reaching middle age but still need

to run reliably. This article gives you suggestions for diagnosing and predict-

ing boiler health to ensure optimal operation for years to come.

SAFETY

Minimizing Coal Dust Combustion Hazards: Lessons from Laramie River Station 46Two coal dust combustion incidents in May 2013 resulted in injuries to two em-

ployees and damage to two units. Rather than quietly taking mitigating actions

and sweeping the experience under the rug, plant operators are sharing their

lessons learned and new best practices so others can adopt them and stay safe.

FUEL SUPPLIES

Marooned: How Island Power Systems Keep the Lights On 51Isolated and small, island power systems face unique challenges, but the so-

lutions they deploy—both in terms of technology and fuel choices—some-

times signal new options for larger, interconnected systems.

PROJECT SITING

Turning Brownfields into Greenfields: From Coal to Clean Energy 55 From a little-known Environmental Protection Agency program that assists

in giving abandoned coal mine sites second wind, to a scheme for bundling

carbon credits with coal to create a “compliant fuel,” new options for coal

country are being deployed.

NUCLEAR TECHNOLOGY

On the Nuclear Frontier: New Designs Aim to Replace LWRs 60The quest to replace light-water reactors (LWRs), which dominate today’s nu-

clear generating fleet, with cheaper-to-build reactors that promise additional

benefits continues, but the pace is slow and the challenges daunting.

COMMENTARY

Reduce Ozone When and Where It Matters Most 68By Valerie Thomas, Paul Kerl, et al., Georgia Institute of Technology

■ GE Announces Digital Power Plant as Component of the Industrial Internet

■ China to Limit Support for High-Carbon Projects, Begin Nationwide Carbon Cap-and-

Trade by 2017

■ U.S. Nuclear Plants Are Operating Better than Ever

■ Xcel to Retire Two Units at Its Largest Coal-Fired Plant

■ EPA Finalizes Steam Electric Power Plant Effluent Guidelines

■ EPA Issues Final NAAQS Ozone Rule at 70 ppb [UPDATED]

■ Georgia Power to Close All Coal Ash Ponds in Response to EPA CCR Rule

ICYMI: TIMELY NEWS POSTED EACH WEEK ON POWERMAG.COM

32

38

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SPEAKING OF POWER

Fuel Guidelines, Fuel Consumption, and Climate Change

See if you can fill in the blanks: “A debate has been created after a paper was published in the BLANK Journal,

suggesting the new BLANK Guidelines . . . are biased and based on an incomplete survey of current studies.” That quote from Digital Journal, referring to the British Med-ical Journal and the U.S. Dietary Guidelines, could just as plausibly have been about a different journal and the Clean Power Plan (CPP). Arguments over revised U.S. Dietary Guidelines (due the end of this year) are getting as heated as those over greenhouse gas (GHG) regulations affecting power gen-eration. Both sets of guidelines (the offi-cial designation for the CPP) concern the fuels we consume, and the development of both raised issues of how that consumption is related to climate change.

Although most adults can choose the food they eat, they cannot, for the most part, decide what fuels are used to generate their electricity. In the U.S., utility commis-sions as well as state and federal agencies represent individuals in matters concerning what types of generation are allowed to be developed. But whenever there’s any sort of regulation, even “guidelines,” there are those who argue against the specifics—or against regulation in general. I’m not in the latter camp; the Volkswagen emissions-testing “defeat” mechanism is just the lat-est example of why we cannot simply trust the market or corporations to always do what’s safe or legal. But in some respects, the details of government guidelines may not always matter as much as critics claim.

The Sustainability IssueOne argument against the CPP is that the Environmental Protection Agency is misusing the Clean Air Act to compel GHG emissions reductions. A similar argument was raised with regard to U.S. Dietary Guidelines.

These guidelines are updated every five years, and this time around, there was discussion about whether sustainability should be a consideration in what foods were recommended. When the Dietary Guidelines Advisory Committee proposed earlier this year that Americans eat a less-resource-intensive diet, the North Ameri-can Meat Institute (NAMI) fought back,

arguing that, pound for pound, meats, though they require large amounts of land and water to grow grains for feed, deliver more nutrition and calories than grains and fruit—an argument similar to the one that fossil fuels have higher energy den-sity than wind and solar energy.

In the end, sustainability was left to other government programs and initia-tives. Had it been included, the debate would quickly have reached the boiling point, as it would have pitted the meat and dairy industries against grain and vegetable producers. That’s because dif-ferent foods require different amounts of resources and result in different environ-mental consequences, from water pollu-tion to GHG emissions. The production of all foods, even organic ones, has environ-mental effects. (The same dynamics are true of electricity sources.)

Water consumption is an obvious exam-ple. A single almond, according to NAMI, can require up to 2.8 liters of water (which sounds more dramatic than when expressed as 0.74 gallons); but that’s still less, on a per-calorie comparison basis, than what’s needed for beef production. Then there are the direct and indirect GHG emissions—from the obvious emissions of methane from cat-tle to emissions resulting from tilling fields used for vegetable and grain production.

There is, however, a significant differ-ence between establishing GHG emissions guidelines for already-regulated industries, on matters where individuals have limited power of choice, and making GHG reductions or other sustainability goals a criterion for dietary guidelines whose primary purpose is to encourage individual humans’ health. Reducing the environmental impacts of our food choices may be a worthy goal, but it’s more appropriately addressed as an educa-tional (and perhaps moral) issue.

Personal Choice Overrides GuidelinesTelling Americans what they should or should not eat is far more likely to prompt a response than guidelines shaping how fu-els are used in power generation. (Google Bloomberg soda.) For some, including chil-dren who eat school-provided meals, those

choices are already curtailed. One mother I know was aghast this fall when her eldest, just starting kindergarten, was being fed breakfast items far higher in sugar than anything she would have served at home. Yet, the school system dietician’s choices are based on U.S. Dietary Guidelines.

School menus aside, for the majority of Americans, dietary guidelines are less pow-erful than they seem. Freedom to choose what we eat can be as personally mean-ingful as one’s choice of music. Although I know individuals who actually are gluten-intolerant, and those who have food aller-gies or medical reasons for avoiding certain foods, many have adopted low-carb/high-fat or vegan or raw diets for purely personal reasons—whether they be weight loss, reli-gious beliefs, or philosophical positions.

Most days, my attitude toward dueling di-etary choices is to live and let live. In a world where millions still lack sufficient access to nutritious food, most arguments about food choices seem like shallow “First-World prob-lems.” Whatever happened to “everything in moderation”? That sounds a lot like the “all of the above” energy plans put forth by both federal and state leaders. Just one example: New Mexico’s Republican governor recently endorsed an all-of-the-above energy plan for her fossil fuel–rich state, which also is rich in solar and wind resources.

Regardless of dietary guidelines, most adults will continue to follow their own paths—from paleo to vegan to locavore. Their choices will be shaped by a stew of sci-ence, guidelines, marketing, doctor’s orders, beliefs, and taste buds. The story’s not much different for power. When given a choice—which is becoming more common with dropping prices for renewables and battery storage—consumers large and small will opt to consume specific fuels based on a mix of price, convenience, marketing, beliefs, and self-image, so it shouldn’t be surprising that increasing numbers are choosing renewables for climate-change reasons.

As for me, I’m in the omnivore, all-of-the-above camp, provided everything is in sensi-ble portions and produced as sustainably as possible. Now, it’s time for my mid-afternoon apple, almond, and chocolate break. ■—Gail Reitenbach, PhD is POWER’s editor. PCL.com/PICCo

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New Options for Solar PV The global market for solar photovoltaic (PV) panels shows no signs of slowing down, with cumulative installed capacity expected to reach 700 GW and annual de-mand to pass 100 GW by 2020, according to GTM Research. This booming market has spurred manufacturers to introduce a va-riety of innovations intended to increase panel efficiency and reduce manufactur-ing, installation, and ancillary costs.

South Korean firm LG Electronics intro-duced a new version of its NeON PV cells at the Solar Power International (SPI) conference in Anaheim, Calif., in mid-Sep-tember. The NeOn 2 makes several breaks with traditional silicon PV cell design (Fig-ure 1). First, rather than employ the usual two- or three-ribbon approach across the cell to gather the electric charge, the NeON 2 uses an array of 12 wires.

LG says this design offers a number of advantages. First, by dividing the current among a larger number of conductors, the electrical loss through each wire is greatly reduced. Second, the use of round wires in place of flat ribbons means light entering the cell is scattered more efficiently and less is reflected out. Finally, because each cell has more conductors, microcracks and other defects that develop in the cell over

time have far less effect on output be-cause there are many more paths for the electric current.

In addition, the NeON 2 cells are bifa-cial, able to absorb light from both sides. This makes them more efficient when sun-light strikes the cells at less-than-ideal angles during morning and evening hours. LG says the 320-W, 60-cell NeON 2 pan-els are able to generate more power than conventional 72-cell panels and offer up to 3% higher efficiency than the first-generation NeON design.

Though they have garnered far fewer sales and less attention than crystalline silicon PV cells, thin-film copper-indium-gallium-selenide (CIGS) panels have main-tained a market niche (around 7% in 2015, according to research firm IHS) because of certain advantages they have over crys-talline silicon–based panels, mainly that they are lighter, thinner, more flexible, and have a reduced visual footprint.

Taiwanese CIGS manufacturer Hulk En-ergy Technology (Hulket) and Italian firm ENERGYKA Electrosystem debuted a new product at SPI that combines Hulket’s CIGS panels into a flexible multi-panel module (Figure 2). The Prometea modules are available in outputs from 100 watts to 500 W. They are foldable, portable, and can be installed with far less effort and additional equipment than crystalline sili-con PV panels.

Finally, San Jose–based Silicor Ma-terials has developed an alternative to traditional polysilicon that is produced through a proprietary metals-based pro-cess requiring two-thirds less energy but still achieving conversion efficiencies in line with traditional materials. Silicor an-nounced at SPI that it has secured $105 million in equity capital agreements to support the construction of its first com-mercial-scale manufacturing operation in Grundartangi, Iceland. The company has already secured sales commitments equal to approximately 75% of the plant’s an-nual production capacity, it said.

Silicor CEO Terry Jester told POWER that the process is based on tradition-al aluminum smelting, where silicon is viewed as an impurity. Basing their fac-tory in Iceland—where aluminum smelt-ing is a major industry due to the island’s cheap hydroelectric power—allows them to reduce costs by partnering with local aluminum companies. Unlike traditional silicon production, which relies on hydro-chloric acid and trichlorosilane, Silicor’s process requires no toxic chemicals—a major criticism that has been leveled at the solar PV industry as its footprint has grown. Jester said Silicor expects to break ground on the factory next year and begin production in 2018.

—Thomas W. Overton, JD, associate

editor1. Neon light. LG’s NeON 2 solar photo-

voltaic cells use an array of narrow wires to

gather power across the cell instead of the

traditional ribbons. Courtesy: LG Electronics2. Solar accordion. The multi-panel Prometea CIGS module (2.2 m x 1.4 m x 4 mm) is

ideal for installation in areas with difficult topography or where traditional mounting approaches

are problematic. Courtesy: Hulk Energy Technology/ENERGYKA


India Refocuses Coal

Future

India, the world’s most coal-dependent nation, has over the last few months very publicly shifted its stance on coal power.

In October, the country announced its commitment for the upcoming COP21 global climate talks in Paris, pledging to improve the carbon emissions intensity of its gross domestic product (GDP) by 33% to 35% below 2005 levels by 2030. That com-pares to China’s recent pledge to reduce the intensity of its GDP by 60% to 65% during the same period. The Indian government, which introduced the plan with much fan-fare, said the target would allow India and its carbon-intensive industrial neighbor to have almost the same emission intensity levels by 2030.

Perhaps more noteworthy, however, is that India also pledged to increase the share of electricity produced by non-fos-sil fuels to an impressive 40% by 2030. While that isn’t a steep increase for the country whose current power mix in-cludes 30% renewables, including hydro, it is detrimental to its coal sector, which it depends on to produce about 60% of its power (Figure 3).

Plant Closures

The central government’s strategy to boost power capacity yet cut carbon emis-sions and utilize coal efficiently is novel: It wants to close coal plants with a to-tal generation capacity of 36 GW that are more than 25 years old and replace them with newer supercritical units. The driv-ing factor for this approach is scarcity of resources like land, water, and coal.

In a comprehensive review with states held this September, the Central Electricity Authority (CEA) pointed to

proposed supercritical coal power ca-pacity additions of 84.6 GW in its 13th Five Year Plan (2017–2022) and direct-ed utilities to explore possible options to use existing land and other facilities more efficiently. The CEA will also re-quire states to submit plans for the re-tirement, replacement, and renovation of aging plants. Several states—includ-ing Maharashtra, Haryana, Rajasthan, Gujarat, Madhya Pradesh, Tamil Nadu, and the newly created Telangana state—have already chosen to kick-

3. Coal giant. Bharat Heavy Electricals Ltd. (BHEL) this August commissioned the 500-

MW Unit 13 of the Vindhyachal Super Thermal Power Station in Vindhyanagar in Singrauli district

of Madhya Pradesh. This is the seventh 500-MW unit commissioned by BHEL at the plant.

Vindhyachal is a 4.7-GW pithead power plant. Courtesy: NTPC



THE BIG PICTURE: Levelized Cost of Electricity

VARIA

BLE

REN

EWA

BLE

S

Levelized cost of electricity ** ($/MWh)

0 100 200 30050 150 25025 75 125 175 225 275 325

BA

SELO

AD

350

Coal

Nuclear

Solar PV—Residential

Solar PV—Commercial

Solar PV—Utility-scale

Onshore wind

Offshore wind

375

Natural gas CCGT

The notion of a levelized cost of electricity (LCOE) has become a handy one for comparing unit costs of different technolo-

gies over their economic life, but it varies widely among countries. Those variations can typically be explained by changes

in discount rates*; fuel, carbon, or construction costs; operation and maintenance costs; and even load factors and plant

lifetimes. Source: "Projected Costs of Generating Electricity," International Energy Agency/Nuclear Energy Agency (2015). For

more, see POWER's in-depth analysis of that report at http://goo.gl/fyyJhY.

—Copy and artwork by Sonal Patel, a POWER associate editor

R

CCGT

3% discount rate

7% discount rate

10% discount rate

KEY

Notes: *Discount rate = return on capital for an investor in the absence of specific market or technology risks; data is limited mostly to Organisation for

Economic Cooperation and Development (OECD) countries. **The International Energy Agency calculates average lifetime levelized costs on the basis of the

costs for investment; operation and maintenance; fuel; carbon emissions; and decommissioning and dismantling of 181 plants in 22 countries. These include

selected OECD member countries: Austria, Belgium, Denmark, Finland, France, Germany, Hungary, Italy, Japan, South Korea, Netherlands, New Zealand,

Portugal, Slovak Republic, Spain, Switzerland, Turkey, UK, and U.S. Flags represent the highest- and lowest-cost OECD countries for each scenario.

South Korea

Japan

Portugal

UK

U.S.

Denmark

Austria

Belgium

Germany

France

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start the replacement of older plants, seeking environmental clearances from the Ministry of Environments, Forests, and Climate Change (MoEFCC).

Strict New Environmental Rules Are ComingFinally, the government is committed to curbing air pollution from coal-fired pow-er plants.

This May, MoEFCC proposed the first-ever federal standards for sulfur dioxide (SO2), nitrogen oxides (NOx), and mercu-ry. The rule proposes to require the na-tion’s fleet of plants larger than 500 MW to meet SO2 limits of 200 milligrams per normal cubic meter (mg/Nm3), and NOx limits of 300 mg/Nm3. New plants com-missioned after 2017 will be required to have flue gas desulfurization to cut SO2 emissions to 100 mg/Nm3, and they would need to meet NOx norms of 100 mg/Nm3.

According to the Center for Science and Environment (CSE), a New Delhi–based public interest research and advocacy group, the limits would imply cuts in SO2 emissions of 80% for existing plants and about 15% in NOx emissions.

The rule would also limit mercury emis-sions (achieved via pollution controls and coal washing) to 0.03 mg/Nm3, the same as China’s. (Comparatively, the U.S. limit is 0.0017 mg/Nm3.) Then, they would substantially tighten particulate emission standards—India’s only federally mandat-ed air pollution standards—to between 50 and 150 mg/Nm3. That’s “quite relaxed compared to global norms of 30 mg/Nm3,” notes CSE, but still effective. Earlier this year, the group estimated that almost two-thirds of India’s coal fleet doesn’t meet existing limits.

And, as stringently, the rule calls for water consumption limits. Once-through cooling system–based plants would need to convert to cooling towers and cut wa-ter draw to 4 m3/MWh from the current average of around 150 m3/MWh. “New plants would need to cut water use to 2.5 m3/MWh, which is equal to the av-erage water use of Chinese plants,” says CSE. “A global best cooling tower based plant has water consumption as low at 1.6m3/MWh.”

Power Giants to Get Federal Funds to Develop Large-Scale Carbon Capture PilotsThe U.S. Department of Energy (DOE) wants GE to plan and propose a large-scale pilot

test of a carbon dioxide capture solution that uses a class of amino silicone com-pounds used to soften hair or clothing.

The agency’s National Energy Technol-ogy Laboratory (NETL) said in September it will award the company $1 million in Phase I funding to test the solution at the CO2 Technology Center at Mongstad (TCM) in Norway (Figure 4).

As GE explained, at temperatures of around 105F, the amino silicone mate-rials attach to CO2 gas. When the heat is increased by another 100 degrees F, the materials release the carbon and can then be reused to capture more. While it sounds unremarkable, the process holds a major advantage over competing ap-proaches because it does not require water. That “substantially reduces the energy required to capture the carbon,” the company said.

GE’s proposal was among six projects that will receive federal funding for large-scale pilots to reduce the cost of carbon capture and sequestration (CCS). South-ern Co. will get about $700,000 to test improvements to the CCS process using an existing 25-MW, amine-based CO2 cap-ture process at Plant Barry in Alabama. NRG Energy will get $1 million to test Inventys’ VeloxoTherm post-combustion project, which will process a 10-MW slip-stream of coal flue gas to separate CO2,

likely at NRG’s Petra Nova W.A. Parish plant near Houston (where it is already retrofitting a CCS system). The University of Illinois will also get about $1 million to capture 500 metric tons per day of CO2 with a 90% capture rate from existing coal-fired boilers at the Abbott Power Plant on its Urbana-Champaign campus, using Linde/BASF’s amine-based absorp-tion system.

Meanwhile, alongside GE, the Universi-ty of Kentucky Center for Applied Energy Research (CAER) will receive about $1 million for a pilot facility at TCM that will use micro-algae to capture carbon from power plant CO2 emissions. Alstom Power will, at the same time, conduct a three-year pilot program at TCM to implement several concepts for improving and low-ering the overall cost of Alstom’s chilled ammonia process.

Only two of the six projects will qualify for Phase II funding, the DOE expects. The Phase 2 awards for construction and ex-ecution of pilot testing are anticipated by mid-2016.

AREVA’s Next-Gen BWR Fuel Is Tested in the U.S. AREVA has installed the first-ever boil-ing water reactor (BWR) assemblies in the U.S. that features an 11x11 fuel rod ar-

4. Capture facility. The Norwegian government began developing—but then canceled in

September 2013—a full-scale carbon-capture project at the CO2 Technology Center at Mong-

stad, in Norway. The state-of-the art research facility got a boost this fall, however, when the

U.S. Department of Energy said it will grant three entities millions of dollars in federal funds to

develop large-scale pilots to reduce the cost of carbon capture. Courtesy: TCM


ray, the French nuclear giant revealed this September.

The new fuel design, the ATRIUM 11, has been used to produce power at two nuclear plants since April, though AREVA declined to name the reactors. However, the company told POWER that to date a total of 40 lead fuel assemblies are oper-ating in five reactors in four countries. In-cluding the two in the U.S., they have also been installed in Switzerland, Finland, and Germany since 2012.

AREVA—a company that has designed and manufactured fuel for both BWRs and pressurized water reactors (PWRs) for 40 years, but which also suffered record losses in 2014—is determined to return to profitability by refocusing on its core nuclear power business. The announcement marks a major milestone for its fledgling lead fuel assembly de-sign, which it says will provide higher intrinsic safety margins. AREVA is also developing the GAIA fuel assembly de-

sign for PWRs in parallel with the ATRI-UM 11. There is substantial interest in both designs in Europe and in the U.S., the company said.

AREVA said that the fuel design im-proves safety by reducing fuel operating temperatures and peak cladding stress under operation. “When engineers balance the uranium loading and enrichment, the economic benefit is a bonus,” said AREVA spokesperson Curtis Roberts in September. Additionally, the new design offers better operational flexibility, which is valuable for plants that have implemented power uprates or optimized capacity factor oper-ating strategies, he said.

“Since it has the same external dimen-sions, the ATRIUM 11 fuel design is installed identically to the existing fuel design oper-ating in each reactor,” Roberts explained. “The fuel burns typically for three cycles and, following each cycle, post-irradiation examinations have been completed show-ing expected performance.”

The 16 lead fuel assemblies installed at the two unnamed reactors were manufac-tured at the company’s Richland, Wash., facility (Figure 5). “The completion of these real-life tests will allow delivery (in full-scale quantities) of the ATRIUM 11 de-sign in 2017 in Europe, and 2019 in the U.S.,” said Roberts.

South Africa Puts First Large IPP Project OnlineSouth Africa reached a milestone this Sep-tember when it put online its first large-scale project owned by an independent power producer (IPP). The inauguration of the 335-MW Dedisa Peaking Power plant located in Port Elizabeth, in the Eastern Cape’s Coega Industrial Development Zone, marks a shift in the way electricity is pro-

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5. New nuclear fuel design. AREVA’s Ken McKeown inspects an ATRIUM

11 fuel rod assembly bundle at the compa-

ny’s fuel manufacturing facility in Richland,

Wash. Courtesy: AREVA

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duced in the power-strapped country. The plant is owned by Dedisa Peaking

Power (a subsidiary of French firm ENGIE, formerly GDF Suez), Legend Power Solu-tions, Mitsui & Co., and The Peaker Trust. Built by Italian firms Ansaldo Energia and Fata, the plant is currently an open cycle gas turbine (OCGT) peaking facility (Figure 6) that will operate on diesel for about four hours a day. Power will be sold to Es-kom Holdings, the state-owned utility that generates 95% of South Africa’s power, un-der a 15-year power purchase agreement. “In the longer term, the project’s sponsors envisage a conversion to gas-fired, com-bined cycle facility in the framework of the Department of Energy [DOE] gas mas-ter plan. The facility is designed to allow such conversion,” Dedisa CEO Arnaud de Limburg told POWER in September.

The project got its start in 2006 as Eskom realized it would face debilitat-ing power shortages if new generation wasn’t built quickly, and it called on the government to encourage a greater role for the private sector in meeting the country’s future electricity needs. Es-kom argued that the measure would re-duce the government’s funding burden, relieve the utility’s borrowing require-ments, and introduce generation tech-nologies that it might not consider part of its core function, such as distributed generation, co-generation, and small-scale renewable projects.

The DOE relented, and in August 2011—as the country battled chronic power supply issues—it issued a request for proposals, inviting IPPs to bid in a

competitive process. The open cycle gas turbine (OCGT) program calls for 1,000 MW of IPP-built power plants, of which Dedisa is the first to begin operations.

“Being the very first IPP project in South Africa, it took several years of development before execution of con-tracts with DOE and Eskom, and reach-ing financial close in mid-2013,” said de Limburg. While the DOE and Eskom have plans for more large IPP-built projects (including for coal and combined cycle gas turbines), he noted that only one other large-scale IPP-built project is under construction in South Africa: the 670-MW Avon Peaking Power OCGT proj-ect near Durban (KwaZulu-Natal).

POWER DigestDutch Court Clears Eemshaven Coal Plant for Operation. A Dutch court on Sept. 9 rejected claims that an environ-mental license issued for RWE’s 1.6-GW Eemshaven coal-fired power plant was is-sued improperly, clearing the way for the $3.36 billion plant to begin operations at full capacity. Environmental groups have opposed the plant’s location near nature reserves. Both Germany—which will soon phase out nuclear power—and the Netherlands—whose gas fields are in decline—back the hard coal project. The project involved construction of two ultra-supercritical coal-fired units, Block A and Block B, that can start up and shut down quickly. Construction began in 2008, and the plant was scheduled to begin operat-ing in 2014.

Flamanville Sees Costs Soar to $11.8B, New Delays. French state-controlled utility Électricité de France’s (EDF’s) Flamanville reactor, which began construction in northern France in 2007, won’t come online until at least 2018, the company said. Costs for the first-of-its-kind EPR reactor have meanwhile surged from €3.3 billion (2005 values) to €8 billion ($9 billion) in 2012 and €10.5 billion ($11.8 billion) in 2015. The company said in a statement that 98% of the building civil structure has been completed as well as 60% of the elec-tromechanical work. Putting in place a new organizational structure, EDF said it would now strive to complete instal-lation of the primary circuit in the first quarter of 2016 and load fuel and start up the reactor by late 2018. Startup of the much-delayed Olkiluoto 3 EPR under construction in Finland is also slated for 2018. The world’s other two EPR projects, Taishan 1 and 2 under construction in China, could come online earlier, in 2016 and 2017. EDF is also considering build-ing two EPRs in the UK.

Rostov Unit 3 Reactor Begins Com-mercial Operation. Unit 3 of the Ros-tov nuclear power plant in Russia has been commissioned two months ahead of schedule and is now operational, said Russia’s state-owned nuclear entity Ro-satom on Sept. 24. Construction of that unit began in 2009. The nuclear plant is located on the bank of the Tsimlyansk Reservoir, about 14 km from Volgodonsk. It now comprises three units with VVER-1000 reactors. Unit 1 was put into com-mercial operation in 2001 and Unit 2 in December 2010. Unit 4, another VVER-1000, is under construction with opera-tions expected to begin in 2017.

Indonesia Kicks Off Coal Plant Con-struction, Island Electrification, Tidal Power Development. PT Bhimasena Power Indonesia—a joint venture of J-POWER, Adaro Power, and Itochu—on Aug. 28 kicked off construction of the 2-GW PLTU Batang coal-fired plant in Central Java, Indonesia. The $4 billion ultrasupercritical project is the nation’s first large-scale public-private partnership (PPP) project. The two-unit plant could come online by 2019.

Also on Aug. 28, Indonesia’s govern-ment implemented a program to put up 149 diesel gensets—a total of 67.8 MW—in 50 locations across 13 provinces to supply power to customers in outer islands and border areas. The provinc-es include Nanggroe Aceh Darussalam, North Sumatra, West Sumatra, Riau, Riau

6. IPP kickstart. The newly opened 335-MW Dedisa Peaking Power Plant in Port Elizabeth,

South Africa, is the first large-scale power project built in the country by an independent power

producer. Courtesy: Dedisa Peaking Power


Islands, West Kalimantan, North Kalimantan, East Kalimantan, East Nusa Tenggara, North Sulawesi, Maluku, North Maluku, and Papua.

Meanwhile, state-owned utility PT PLN signed a memorandum of understanding with marine power projects developer SBS to develop a tidal power project in West Nusa Tenggara. The $350 million tidal stream plant, which would be Indonesia’s first com-mercial-scale project, would be built in phases beginning with an initial 12-MW pilot and eventually scaled up to 140 MW.

AGL Sells Its Share in 420-MW Australian Wind Farm. Australian power generator AGL Energy on Sept. 7 sold its 50% participating interest in the 420-MW Macarthur Wind Farm joint venture to New Zealand–based investment manage-ment firm Morrison & Co. for A$532 million. The remaining 50% interest is held by Malakoff Corp. Berhad. However, AGL said it will continue to operate and maintain the Macarthur Wind Farm on behalf of Morrison & Co. and Malakoff, and it retains the rights to all Renewable Energy Certificates and electricity output until 2038. The Macarthur Wind Farm—a 2013 POWER magazine Top Plant award winner—is located in southwest Victoria. It was constructed by Vestas and Leigh-ton Contractors with 140 Vestas V112, 3-MW turbines and was completed in January 2013. “The sale of the Macarthur Wind Farm is the first step toward AGL’s target of $1 billion in as-set divestments by the end of FY17. The sale of this asset will improve the company’s capital efficiency while retaining its BBB credit rating,” the company said.

Westinghouse to Dismantle Closed German Nuclear Plant. Westinghouse Electric Co. won a contract on Sept. 8 to dismantle the reactor pressure vessel and internals at the Philippsburg Nuclear Power Plant Unit 1 in Germany. The reac-tor operated by EnBW Kernkraft GmbH was permanently shut-tered by a German government mandate in the aftermath of the 2011 Fukushima disaster in Japan. Westinghouse’s scope in-cludes planning, equipment manufacture, and on-site segmen-tation of the reactor vessel internals and the reactor vessel, including peripheral structures. The scope for the contract will be executed by a consortium comprising NUKEM Technologies Engineering Services GmbH (NTES) and GNS Gesellschaft für Nuklear-Service mbH under the lead of Westinghouse Electric Germany GmbH. The work will be carried out under the direction of EnBW when the decommissioning license is granted by the Ministry of the Environment, Climate, and En-ergy of Baden-Württemberg.

Statkraft Opens 172-MW Hydro Plant in Peru. Norwe-gian energy group Statkraft in late August opened the 172-MW Cheves hydropower plant in Peru. The plant, 130 kilometers north of the capitol Lima in the Huaura River, consists of two aggregates and exploits a gross head of 600 meters. Based on water from the Andes, it will generate 840 GWh annually, power that will be sold on a long-term power purchase agree-ment with eight local distribution companies.

Siemens Awarded Plant Components for Maryland Gas Plant. Siemens will supply the main components for the 735-MW natural gas–fired Keys Energy Center in Maryland to SNC-Lavalin Constructors, who will act as the turnkey engineering, procurement, construction contractor for the project. Siemens will deliver two SGT6-5000F gas turbines, one SST-5000 steam turbine, two air-cooled generators SGen-1000A, and the asso-ciated turbine instrumentation and control systems. The plant, owned by Public Service Enterprise Group, is expected to come online in 2018. ■

—Sonal Patel is a POWER associate editor.

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Smart Access Planning Enables Efficient Cooling Tower Maintenance

Two hyperbolic cooling towers rise 495 feet over Exelon Corp.’s Byron Generating Station about 110 miles west of Chicago, Ill. The towers help cool the two Westing-house pressurized water reactors that are capable of generating up to 2,346 MW at the site.

Like all classic wet transfer hyperbolic cooling towers (Figure 1), the Byron Gen-erating Station uses fill packs to increase the exposed surface area of the water, as well as to increase the air-to-water contact time. These actions increase the rate of heat transfer and the amount of heat transfer, respectively. In a film-type fill pack, water flows in a thin film over stacks of vertically oriented plastic sheets spaced about 0.75 inch apart. The sheets feature a corrugated or V-shaped pattern to further increase surface area and con-tact time.

An Upgrade Is WarrantedRecent film-fill developments have cre-ated low-clog, open, angular cross-corru-gations that allow debris and biological growth to pass through. However, this design did not exist when the towers at Byron were built. Over the years, the station’s fill packs developed excess bio-logical growth and accumulated silt. As a result, the fill packs bulked up from less than 100 pounds to more than five times their original weight.

Normally, fill packs hang 30 to 35 feet above the cold-water basin (Fig-ure 2). However, they are designed to break away and fall from their attach-ments when they get too heavy, a fea-ture that prevents damage to the tower structure.

When several of the fill packs attached to the cooling towers of the Byron Gen-erating Station became over-burdened and fell into the cold water basin, Ex-elon engineers decided to replace all of the fill packs in both towers. They also decided to replace the drift eliminators, honeycomb-like PVC components (Figure 3) that hang above the water distribu-tion system to capture and limit the quantity of water droplets contained in the air stream leaving the cooling tow-er. In all, more than 5,000 components would need replacement.

To perform the maintenance, Exelon consulted SPX Cooling Technologies Inc., its cooling tower manufacturer. The work had to be done within two three-week windows, six months apart, while the re-

actors were shut down for routine sched-uled refueling. Planning was critical. Surprises, delays, or complications would affect Exelon’s ability to deliver electricity to northern Illinois.

1. Tall order. SPX Cooling Technologies Inc. was tasked with replacing more than 5,000

components in both of Byron Generating Station’s hyperbolic cooling towers during two three-

week maintenance periods. Courtesy: David Joel Photography

2. A cool design. During operation, water flows over fill packs (shown here being lifted into

position under the water distribution nozzles using a telehandler) in a thin film, improving heat

transfer by increasing the exposed surface area of the water. Courtesy: David Joel Photography


Working Quickly and SafelySPX’s first challenge was getting access to the fill packs in a way that would al-low its staff to work quickly and safely. As noted, the fill packs are above the cooling basin, which holds 8.5 feet of water. The drift eliminators are above the fill packs, with components for the water distribution located between them. The basin itself also contains a network of pipes for water circulation. During opera-tion, water falls inside the cooling tower at a rate nearly that of a thunderstorm. In short, gaining access to the fill packs and drift eliminators required extensive planning, extreme efficiency, and atten-tion to safety.

SPX has a longstanding relationship with Safway Services, an access and industrial services company based in Waukesha, Wis. Safway specializes in complex industrial environments where planning, efficiency, and safety are all critical to success.

“We know Safway has the right equip-ment, and we know they have the design (engineering) services we need for an en-vironment like this,” said Duane Krehbiel, director of MCT Services Construction at SPX and project manager for the Exelon

job. “With a job like this there’s a lot of work up front, and we know Safway will do it right.”

The Right StuffThe “right equipment” Krehbiel mentioned is Safway’s Systems Scaffold, which is en-gineered to provide fast and easy erection. To assemble it, workers hook horizontal or diagonal members (galvanized steel tub-ing) to rings on the vertical posts. Using a hammer, they drive home a wedge until a retainer pin drops and locks the member in place.

To disassemble, workers lift the retain-er pin with a Safway pry-bar hammer and loosen the wedge with a quick flick of the hammer. The design allows for 360-degree placement around the vertical post rings, and rings are spaced every 21 inches on vertical posts for easy height adjustment (Figure 4). Special compo-nent jacks, support frames, braces, and varying lengths of the horizontal mem-bers enable the scaffold to conform to sloping surfaces (such as on a boiler cav-ity), and all components can be passed through small openings.

“Cooling towers present complex ac-

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beams above the water distribution nozzles,

were also replaced. Courtesy: David Joel Pho-

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cess situations, and working within the time constraints of a refueling shutdown demands speed. Systems Scaffold excels in this type of environment because of its adaptability,” noted Jim Waichunas, Saf-way Tracking System coordinator for Saf-way’s Eastern Division and SPX’s liaison for the project.

To monitor every aspect of the Exelon

project, Waichunas used the Safway Track-ing System, a proprietary software pro-gram that manages all of the resources for a project.

“The Safway Tracking System provides a clear picture of costs and bottlenecks and helps us to stay on top of other key performance indicators in real time,” said Waichunas.

Planning Leads to SuccessWith an outage of three weeks, Safway wanted to give SPX workers as much time as possible to perform their task. The plan involved building four sections of scaffold that would start on the outer ring of the tower and work toward the inside of the parabolic curve. When completed, each section of scaffold would measure about 21 feet wide, 90 feet long, and 45 feet high so the SPX crew could reach the drift eliminators. After the SPX crew finished work on one section, the Safway team would dismantle the scaffold and move it laterally to reach a new area (picture clock hands sweeping around the dial).

“The eight-and-a-half-feet of water in the cold water basin and the constant ‘rainstorm’ inside the parabolic curve pre-sented the biggest challenges to sched-uling,” said Waichunas. “Exelon couldn’t drain the basin or stop the cooling water spray until the outage began.”

Two weeks prior to the scheduled out-age, Exelon brought in divers. Directed by the Safway team, the divers erected the Systems Scaffold base (standard screw jacks and wood blocking) and one level of scaffolding underwater.

“It required good planning because there was a pretty strong current moving through the water,” Waichunas recalled.

With the base in place, the Safway crew erected as much scaffold as they could in the outer ring of the cooling tower, work-ing up to the edge of the rainstorm. Once the reactor outage began, the Safway team quickly built the scaffold up to full height and the SPX personnel took over.

Krehbiel said SPX and Safway had worked out a “Plan B” to allow work in wet areas with a partial shutdown of the spray system if the job went longer than three weeks. As it turned out, they didn’t need it. With demonstrated success, the Safway and SPX teams completed work on the second tower about six months later using a similar schedule.

In both cases the SPX team accom-plished its mission in the allotted three weeks with no major incidents (Figure 5). Once the maintenance was complete, the Safway crew finished removing the scaf-folding—about a two-week job.

“The take-down was actually done in phases, because our crew dismantled sections of scaffolding where the re-placement of materials was finished,” Waichunas, said. “Systems Scaffold is also simple to take down, which makes things more efficient.” ■

—Edited by Aaron Larson, a POWER associate editor.

4. Versatile construction. Post rings on Safway’s Systems Scaffold allow quick assem-

bly and offer a variety of orientation options to meet diverse project needs. Courtesy: David Joel

Photography

5. Finishing touches. The final drift eliminators are placed into position. Drift eliminators

are the last component that air and water vapor pass across before rising through the shell and

out the top of the tower. Courtesy: David Joel Photography


FERC’s Enforcement

Priorities After 10 Years

Under the EPActCarlos E. Gutierrez

On August 8, 2005, the Energy Policy Act of 2005 (EPAct) was signed into law. It remains, arguably, the last signifi-cant piece of energy legislation to be enacted in the U.S.

The changes wrought by EPAct are far-reaching and controver-sial, and for the gas and electric industry, perhaps no change has been more significant than the law’s transformation of the Federal Energy Regulatory Commission (FERC) into a formidable enforcement agency.

EPAct endowed FERC with authority to impose civil penalties of up to $1 million, per day, per violation under the Federal Power Act (FPA), the Natural Gas Act, and the Natural Gas Policy Act, and FERC has aggressively staked out its enforcement territory. Since 2007, the Commission has imposed over $642 million in civil penalties and ordered disgorgement of more than $300 mil-lion in profits. Two areas attracting a significant amount of FERC’s attention over the past decade include market manipulation and protection of the electric grid from cyberattacks.

Market ManipulationIn July 2013, FERC entered into a consent agreement requiring JP Morgan to pay a $285 million civil penalty and disgorge $125 million in profits for allegedly making bids in the electric mar-kets administered by the California Independent System Operator (CAISO) and the Midcontinent Independent System Operator that were designed to create artificial conditions that forced those ISOs to pay JP Morgan outside the market at premium rates.

In the Hunter case in 2013, FERC had a civil penalty for alleged market manipulation rejected by the D.C. Circuit for encroaching on futures markets found to be subject to the Commodity Futures Trading Commission’s exclusive jurisdiction.

In four other cases, FERC’s role as the adjudicator of market manipulation is under assault as the defendants have elected to force FERC to file suit in federal district court, where there is to be de novo review under FPA Section 31(d)(3). These cases include challenges to:

■ A July 2013 order in which FERC required Barclays to pay $435 million in civil penalties and $34.9 million in disgorged profits for allegedly engaging in certain physical market trades for the sole purpose of benefitting its financial swap positions.

■ An August 2013 order in which FERC required Competitive En-ergy Services to pay a civil penalty of $7.5 million for alleg-edly devising and implementing a fraudulent scheme whereby one of its demand response service provider clients inflated its baseline energy usage in order to capture demand-response revenues from artificial load reductions.

■ A May 2015 order in which FERC imposed civil penalties of $30 million on Powhatan Energy Fund and others for allegedly placing round-trip up-to-congestion bids in order to profit from the distribution of transmission line–loss credits.

■ A May 2015 order in which FERC required Maxim Power Corp. to

pay a civil penalty of $5 million for allegedly falsely reporting to ISO New England that it was burning oil rather than cheaper natural gas and thereby collecting inflated make-whole pay-ments from the ISO.

In each of these cases, FERC is taking the position that the de novo review provided for under FPA Section 31(d)(3) means simply that the court should decide the case based on the re-cord that was before FERC without according any deference to FERC’s decision, while the defendants are generally claiming that de novo review means that the case is to be re-adjudicated at the district court level with full rights to discovery and to introduce evidence. If the courts adopt Barclays’ interpretation of what de novo review means in this context, this could prove to be an effective avenue to rein in FERC’s aggressive enforce-ment tactics.

CybersecurityFERC has made “serious violations” of North American Electric Reliability Corp. (NERC) standards a major enforcement priority. FERC and the electric industry have given considerable atten-tion to the development and refinement of Critical Infrastructure Protection reliability standards (CIP Standards) that are intended to protect the electric grid from cyberattacks. Frequent changes to CIP Standards reflect an effort to keep up with the increas-ingly innovative ways that hackers can exploit a vulnerable bulk electric system and inflict substantial damage on the American economy.

In the last two years alone, FERC has conditionally accepted Version 5 of the CIP Standards and then conditionally accepted seven modified Version 6 standards. In its most recent proposed rulemaking regarding CIP Standards, FERC has further directed NERC to develop a new (or modified) CIP Standard that will ad-dress supply chain vulnerability to targeted malware and inevita-bly introduce new Version 7 standards. This proposal marks only the third time FERC has used its EPAct authority to require NERC to propose a new standard, highlighting the careful attention FERC has devoted to cybersecurity threats. This concern with cy-bersecurity may be well placed, as a recent report by Lloyd’s and the University of Cambridge Centre for Risk Studies estimates that a large-scale cyberattack on the U.S. grid could cost the economy over $100 billion.

FERC seems to relish its role as an enforcement force in the electric industry under EPAct. It remains to be seen, though, whether its authority will be curtailed by the courts or whether an industry burdened with high compliance costs and exposure will push back enough to spawn the next major piece of energy legislation in the U.S. ■

—Carlos E. Gutierrez ([email protected]) is counsel in Davis Wright Tremaine’s Energy practice group in the firm’s New

York, N.Y., office.


TOP PLANTS

Central Nuclear Néstor Kirchner (Atucha II), Lima, ArgentinaOwner/operator: Nucleoeléctrica Argentina S.A.

As with many other nations in the de-

veloping world, Argentina has seen

the course of its nuclear power pro-

gram rise and fall with the country’s eco-

nomic and political fortunes. Argentina first

turned to nuclear power in the 1960s, and

the country’s first nuclear reactor, Atucha I,

entered commercial operation in 1974 at a

site near Lima on the banks of the Parana

River about 100 kilometers (km) northwest

of Buenos Aires.

Atucha I is a 357-MW pressurized heavy-

water reactor (PHWR) built by German firm

Kraftwerk Union (KWU), which at the time

was a joint venture composed of the nuclear

business units of Siemens and AEG. In the

1970s, the military government decided to

bring four more nuclear reactors online be-

tween 1987 and 1997. Siemens, which had

by then bought out AEG’s shares in KWU,

submitted a design for a second, 745-MW

PHWR at the Atucha site.

As originally intended, Atucha II was to

be built by a joint venture between KWU and

the Argentine Atomic Energy Commission

(Comisión Nacional de Energía Atómica,

CNEA), using a Siemens-KWU design that

was essentially a larger version of Atucha I.

Intermittent ProgressConstruction began in 1981, but ongoing

weaknesses in the Argentine economy meant

that funds for the project were limited. Fol-

lowing the overthrow of the military govern-

ment and the return to democratic elections

in 1983, construction slowed even further as

national attention was pulled away by more

pressing issues.

Between 1983 and 1994, the project pro-

ceeded in fits and starts as funds became

available. Construction on some of the main

buildings advanced, and materials were

stockpiled on site. Though more significant

progress was made between 1991 and 1994

as more funds were allocated, the project

was finally halted in 1994 with the plant

about 81% complete. The main buildings

had been erected, but very little electrome-

chanical work had been completed.

In 1994, a new entity, Nucleoeléctrica Ar-

gentina (NA), was set up to take over nuclear

development from CNEA. But ongoing chal-

lenges in the national economy meant there

were insufficient resources to complete Atu-

cha II at the time.

In the intervening years, the site lay idle

as the workforce dispersed and the local

construction and engineering expertise that

would be necessary to complete the plant

waned. Siemens finally withdrew from the

project in 2000. Meanwhile, a skeleton staff

of about 150 worked to preserve 40,000 tons

of materials—comprising 85,000 separate

items—that were stored at the site and other

locations.

During the late 1990s, Argentina’s econ-

omy continued to contract as a result of in-

ternal and external factors, culminating in

an economic crisis that began in 1998 and

reached its worst in late 2001, when the gov-

ernment defaulted on its public debt and riots

wracked major cities for weeks. Not until

the election of Néstor Kirchner in 2003 and

major changes in economic policies were en-

acted did the nation begin to recover.

Begun with grand ambitions in the early 1980s, the second unit at Argentina’s Atu-cha site ran smack into the country’s economic crises in the following decade. But a determined crew brought the project to completion after a 13-year hiatus through a focus on rebuilding the nation’s nuclear labor force.

Thomas W. Overton, JD

Courtesy: Nucleoeléctrica Argentina S.A.

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TOP PLANTS


Back in BusinessBy 2006, Argentina was finally back on its

feet and experiencing economic growth.

That August, the government announced a

$3.5 billion plan to revitalize the country’s

nuclear sector, which included $600 million

for completing Atucha II. Argentina’s desire

to increase the share of nuclear in the power

mix and reduce dependence on imported fos-

sil fuels—especially natural gas—lay behind

the decision.

But restarting the project after more than a

decade was a significant challenge for a va-

riety of reasons. NA, which would serve as

the architect-engineer and design authority,

needed to close out the original contract with

Siemens-KWU and obtain the intellectual

property rights for the design in order to fin-

ish the work. More significantly, it needed to

rebuild the local workforce.

NA formed cooperative agreements with

Argentine companies and institutions as

well as foreign organizations such as the

International Atomic Energy Agency, Sie-

mens, and AREVA. To staff the project,

available personnel who had worked on the

plant originally were called back, and new

engineers, technicians, and construction

workers were recruited and trained along-

side the veterans. Construction resumed in

November 2006.

Because so many new workers with so

many different skills needed to be brought

in, a special committee was formed to iden-

tify all specific labor needs and determine

how they would be filled. In addition, con-

struction tasks were broken down into four

levels of expertise—from construction of

the pressure vessel and primary piping, re-

quiring the highest qualifications, down to

basic construction tasks—to ensure labor

resources were allocated most efficiently.

NA worked directly with the local

unions and contractors to structure the

construction contracts and develop a suffi-

ciently flexible process to support on-the-

job training. Among other achievements,

more than 1,400 new welders were trained

and qualified as part of the project. Per-

sonnel on site rose from a few hundred to

more than 5,000 within two years, peaking

at nearly 7,500 in 2010.

Another challenge was refurbishing the

partially finished plant so that construc-

tion could resume safely and effectively.

The communications and data processing

networks had to be updated to support new

standards (Figure 1). Temporary power, wa-

ter, security, and sewage systems, as well as

other temporary facilities that had lain idle

for more than a decade, had to be cleaned

up, reconditioned, and integrated with new

facilities to support construction.

Electromechanical construction re-

sumed in mid-2007. The heavy-water de-

sign required 600 metric tons of heavy

water, which was produced at the coun-

try’s indigenous heavy water production

plant in Arroyito. Production of heavy wa-

ter was completed in June 2012. Primary

system pressure testing was conducted in

early 2013, and fuel and heavy water were

loaded into the reactor later that year. First

criticality was achieved in June 2014, and

100% power was achieved for the first time

that November.

Ultimately, more than 43 million construc-

tion man-hours, of which 99% were local,

would be expended in completing the plant.

Native ExpertiseAtucha II, now named for former president

Kirchner, was declared commercially opera-

tional by his widow, current President Cris-

tina Fernández de Kirchner on February 19,

2015. In opening the plant, she hailed the

work done by Argentine firms and labor in

completing the project.

“To those who some days ago were doubt-

ful of the agreements we went to sign in order

to make our economy grow and attract new

investments, I want to say that all the work

for this nuclear plant was done by Argentine

people, Argentine brains, Argentine labour,

because, you know something? We, the Ar-

gentine people have begun once again to go

down a path that we had abandoned,” Kirch-

ner said.

“In the nineties, Argentina—partly, it is

fair to say, because of external pressure—

abandoned its role as the most important

nuclear actor in Latin America. Today, we

are reclaiming that role by fully opening

this plant.”

The success in completing Atucha II has

indeed given renewed momentum to Argen-

tina’s nuclear sector.

Two more units are planned at the site,

with construction tentatively slated to begin

in 2016 and 2017. The country has signed co-

operation agreements with Russia and China

for future nuclear development, including

possible reactor construction.

Finally, Argentina is arguably furthest

along with small modular reactor develop-

ment, with its 25-MW CAREM design—

nearing completion at the Atucha site and set

to begin testing next year. (For more on CA-

REM, see “Small Modular Reactors Speak-

ing in Foreign Tongues” in the January 2015

issue.) ■

—Thomas W. Overton, JD is a POWER

associate editor.

POWER POINTS

Winning Attributes

Restarted and completed the

project after repeated economic

challenges forced a decade-long

interruption

Rebuilt the national nuclear labor

force by training thousands of

new engineers, technicians, and

construction workers

1. Upgraded. When the Atucha II project was restarted in 2006, one key task was updating

the unfinished instrumentation and controls systems to modern standards. Courtesy: Nucle-

oeléctrica Argentina S.A.

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TOP PLANTS

Palo Verde Nuclear Generating Station, Wintersburg, Arizona

Palo Verde Nuclear Generating Station

(Palo Verde), located on 4,000 acres

deep in the Arizona desert about 50

miles west of Phoenix, serves the electricity

needs of approximately four million people

in Arizona (about 35% of its power needs),

Southern California, New Mexico, and far

west Texas. The plant, which began construc-

tion in 1976 and was completed in 1988 at

a cost of $5.9 billion, features three units

with—unlike most nuclear plants—very lit-

tle common infrastructure between the units.

Palo Verde has long been the largest U.S.

nuclear power plant as measured by power

generation.

Steam is produced by Combustion Engi-

neering System 80 pressurized water reactors

in a 2 x 4 configuration—four main reactor

cooling pumps circulate 111,000 gpm of pri-

mary coolant through two steam generators.

The reactors were originally licensed to oper-

ate in 1985, 1986, and 1987, and each was

initially rated at 3,990 MWt. The General

Electric generators remain the largest 60 Hz

generators in worldwide service at a nuclear

power plant.

Since 2005, the U.S. Nuclear Regula-

tory Commission (NRC) has approved in-

creases in the net generating capacity of

each unit to 1,311, 1,314, and 1,312 MW,

respectively, as a result of plant upgrades.

Operating license extensions for each of

the three units were approved in 2011, ex-

tending plant operation until 2045, 2046,

and 2047, respectively.

“Our mission is to safely and efficiently

generate electricity for the long term,” said

Randy Edington, executive vice president

and chief nuclear officer for Arizona Public

Service Co. (APS), which operates the plant

for the group of owners (listed at the top).

“We have worked very hard to demonstrate to

the NRC through extensive inspections and

audits that Palo Verde is prepared to operate

for an additional 20 years.”

The plant employs about 3,000 workers

and has an annual economic impact of more

than $1.8 billion in Arizona, according to

APS.

Rising Capacity FactorsNuclear power plant capacity factors are ris-

ing across the industry. The Nuclear Energy

Institute (NEI) reported that the average ca-

pacity factor of all U.S. nuclear power plants

in June was 96.4%, the highest that it has

been in six years (it was 91.7% in 2014). In

fact, 90 of the 99 operating nuclear reactors

averaged 90% or higher, and 62 operated at

100% or higher in June.

According to Platts’ Megawatt Daily

June 22 report, in 2014, Palo Verde Unit 3

generated more electricity than any single

unit in the U.S., producing 12.2 million

MWh, exceeded only by EDF’s 1,560-MW

Chooz-B2 reactor in France for worldwide

honors. However, Palo Verde’s 1,312-MW

Unit 3 posted a higher annual capacity

factor of 97.5%, compared to 94.1% at

Chooz-B2.

Palo Verde Unit 3 continued the plant’s

history of outstanding operations by du-

plicating Unit 2’s achievement the year

before. In 2013, Unit 2 reported a 94.8%

capacity factor, the highest of all plants in

the world top 10 rankings, while Unit 1

was ranked third in the U.S. and seventh

in the world.

Generating large amounts of electricity

has been in the plant’s DNA since it began

operation. All three Palo Verde units are

individually ranked among the top six pro-

ducers in the U.S., according to industry

data. “We take pride in regularly generat-

The nearly 4-GW, three-unit Palo Verde Nuclear Generating Station remains the larg-est generator of electricity in the U.S. for the 23rd consecutive year, producing more than 30 million MWh in 2014, for the 10th time (the only plant in the U.S. to do so), all while using only treated wastewater for cooling.

Dr. Robert Peltier, PE

Courtesy: Arizona Public Service

Owners/operator: Arizona Public Service Co. (APS, 29.1%), Salt River Project (17.5%), Southern

California Edison Co. (15.8%), El Paso Electric Co. (15.8%), PNM Resources (10.2%), Southern

California Public Power Authority (5.9%), and the Los Angeles Department of Water & Power

(5.7%) / APS

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TOP PLANTS


ing more electricity than any other power

plant in the country, ensuring that people

across Arizona and the Southwest can con-

tinue to enjoy reliable, low-cost electric-

ity,” said Edington.

For Palo Verde, 2014 was its 23rd con-

secutive year as the largest power generator

in the U.S., producing 32.3 million MWh

and breaking its own record of 31.9 mil-

lion MWh set in 2012. Palo Verde is the

only generating station of any technology

to produce 30 million MWh in a single

year, an achievement that it accomplished

in 2014 for the 10th time, and in six of the

past 10 years.

More RecordsThe Palo Verde staff is also well-practiced

in the art and science of conducting short

refueling outages and can turn around a unit

in record time. In the spring of 2013, the

staff completed its first sub-30 day refuel-

ing outage in plant history with a plant re-

cord-setting 29 days, 18 hours for Unit 1. In

spring 2014, the staff bettered that record by

refueling Unit 2 in 28 days, 22 hours. “This

refueling outage is another example of the

world-class performance we have come to

expect from Palo Verde, where safety re-

mains our highest priority,” Edington said.

At Palo Verde, the units are on an 18-month

refueling cycle, with two refuelings sched-

uled each year—one in the spring and an-

other in the fall.

In aggregate, the three units have been

running very well. From April 28 until Oct.

5, 2013, a period of 160 days, all three

units operated, the second-longest continu-

ous run in plant history. The long run ended

when Unit 3 was brought offline in order to

begin a planned refueling and maintenance

outage, although Units 1 and 2 continued

to operate at 100%. During 2012, Unit 2

recorded the best performance in plant his-

tory with 518 consecutive days of opera-

tion, ending Oct. 5, 2012. Each of the three

units has a recent continuous run exceeding

500 days.

Using Recycled WaterPalo Verde is the only U.S. nuclear power

plant that is not located next to an ocean or

other large body of water. It instead sits in

the middle of Arizona’s Sonoran Desert. Palo

Verde was the first nuclear power plant in the

world and remains the largest in the U.S. to

use recycled municipal wastewater for con-

denser and other plant cooling needs (Figure

1).

APS concluded a landmark 40-year

agreement in 2010 with the five cities in

the greater Phoenix metropolitan area to

provide an annual allotment of up to 26

billion gallons of treated municipal efflu-

ent to Palo Verde through 2050. The ter-

tiary treated effluent originates from the

91st Avenue Wastewater Treatment plant in

west Phoenix and is piped to Palo Verde,

where it is further treated to meet the water

quality standards established by the plant.

The agreement was negotiated over sev-

eral years and replaces the original water

pact signed in 1973. Water deliveries un-

der terms of that agreement began in 1982,

when Unit 1 began operations, and was

scheduled to expire in 2027. “Palo Verde

provides substantial environmental ben-

efits since it does not emit any greenhouse

gases and because it makes the most effi-

cient use of our limited water resources,”

said Edington. The pact also solves a prob-

lem faced by many municipalities—how to

dispose of a potentially valuable byproduct

that increases as the population grows.

Grey water effluent provided to Palo Verde

is produced in three steps: solids removal,

primary treatment to remove any remain-

ing solids, and then secondary treatment in

which biological or percolating filters break

down organic material and purify the liquid.

The treated effluent flows 28 miles downhill

and then is pumped another 8 miles to the

plant site, where it enters the Palo Verde Wa-

ter Reclamation Facility. There the effluent

is further treated before it is stored in a 760

million-gallon lined reservoir that covers 80

surface acres.

The closed loop condenser/cooling tower

circuit uses water from this reservoir for

plant cooling. Three mechanical forced-draft

cooling towers are used for condenser cool-

ing, one for each unit. The towers operate at

25 cycles of concentration, which produces a

blowdown stream whose salinity approaches

that of seawater. Once this concentration is

reached, the water is discharged to evapora-

tion ponds. Because of the corrosive nature

of the effluent, the three-pressure, three-shell

surface condensers were originally upgraded

to titanium and the tube sheets are fabricated

out of aluminum bronze with mechanically

expanded tube joints. Mechanical scrapers

are used to keep the tubes clean. The Marley

condensers continue to provide reliable ser-

vice using tertiary treatment grey water after

almost 30 years of service. ■

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

1. Water reuse. The Palo Verde Nuclear Generating Station uses 100% recycled municipal

wastewater from Phoenix and surrounding cities for condenser cooling. Shown are aeration

ponds that are part of the plant’s water reclamation and treatment facility. Courtesy: Arizona

Public Service

POWER POINTS

Winning Attributes

Only nuclear power plant in the

world to generate more than 30

million MWh in a year, and held

that record in 2014 for the 10th

time

Uses only treated wastewater for

all plant cooling, thereby saving

precious resources in its desert

surroundings

Refueling outages consistently

require fewer than 30 days• •

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9:15-10:30 The Compliance Context: Regulations & Environmental Groups

10:45-12:00 The Clean Power Plan: Uncertain Future,

Certain Pain

12:00-1:00 Lunch and keynote

Robert Meyers, Senior Counsel, Crowell & Moring; former head of the Of�ce of Air and Radiation, U.S. Environmental Protection Agency

1:30-3:30 Surviving the Environmental Compliance Minefield: CCR, ELG, Ozone, 316(b), MATS 2.0, & More

3:45-5:00 Networking reception

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CONFERENCE AGENDA Among the notable speakers, you’ll hear from: » Counsel for one of the parties in Massachusetts v. EPA, the Supreme Court case that opened the door to greenhouse gas regulation by the Environmental Protection Agency

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» Plus—the current EPA General

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These experts have represented industry, regulatory bodies, and citizen groups and are prepared to share their insights on the current bundle of regulatory concerns.

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Wildlife and Power Plants: New

Solutions for Animal ProblemsSome critters may be cute, but when jellyfish gum up power plant cooling sys-

tems; birds, rats, snakes, or squirrels cause electrical shorts; or invasive mol-lusk species obstruct hydropower plant pipes, losses can be steep. Here’s how some power plant operators are dealing with their critter troubles.

Aaron Larson and Sonal Patel

There are countless cases of wildlife

entering power plant areas where

they don’t belong. Unlike trained

workers, the animals can’t read warning

signs and often end up learning the hard

way about the danger lurking in high-

voltage systems. The result isn’t just bad

for the critter; it can be bad for the plant,

resulting in equipment damage and un-

planned outage time.

Not every power plant must deal with

the exact same pests. Pigeons, mice, rats,

and raccoons are fairly common throughout

North America, but other parts of the world

have other vermin. Snakes—some of which

are very dangerous—pose problems for some

plants, and even insects, such as termites and

carpenter ants, can cause significant damage

not just to buildings, but also inside panels

and equipment. It used to be that jellyfish

and mollusks were found mainly at plants

utilizing ocean water for cooling, but now

freshwater species have spread to many areas

throughout the U.S.

Keeping Unwanted Guests OutDamage caused to electrical equipment as

the result of animal intrusion can cost a lot

to repair, not to mention the cost associated

with lost production. Karl Mosbacher, busi-

ness development manager for Roxtec Inc.’s

U.S. Power group, recalled one instance

where a squirrel caused $300,000 worth

of damage when it triggered a power surge

that affected an Indiana community center’s

heating and air conditioning system and

some parts of its boiler system. Rats and

mice are also regular troublemakers due to

their propensity for gnawing on cable and

wire insulation.

In order to prevent such damage, it is impor-

tant to seal building and equipment penetra-

tions to keep pests out. Mosbacher said some

materials, such as metal and concrete, are less

susceptible to infestation than others, but over

time, deterioration, inadequate alterations, and

poorly completed repairs can create openings,

allowing infiltration of unwanted pests.

A good understanding of pest behavior

and vulnerable areas is important. Mos-

bacher noted that some products and materi-

als commonly used to seal openings, such as

neoprene and spray-in foam, are not rodent-

proof. On the other hand, he said Roxtec’s

uniquely designed sealing solutions are ca-

pable of preventing a wide variety of pests

from entering facilities.

According to Mosbacher, the Roxtec seals

(Figure 1) not only protect against rodents

and pests, but also against water, gas, fire,

dust, electromagnetic interference, and ex-

plosion. They are adaptable to cables of dif-

ferent sizes, which simplifies maintenance

and upgrades.

Animals and power plant substations

don’t mix particularly well either. Raccoons,

squirrels, and even snakes can end up in ar-

eas where they shouldn’t be, triggering bad

outcomes for the utility, as well as for the

animal (Figure 2). In some cases, the result is

a simple conductor failure, but a strong flash-

over can result in shattered bushings or even

complete transformer meltdowns.

TE Connectivity is another company that

has developed a wide range of covers, iso-

lators, and insulation products designed to

protect systems from animals. The solutions

include bushing covers (Figure 3), conduc-

tor covers, squirrel guards (Figure 4), bus

1. Sealing out trouble. These seals, installed at a facility in Mexico, prevent rodents,

water, and other hazards from entering buildings through cable and pipe penetrations. Courtesy:

Roxtec Inc.



support covers, raptor covers, and heat-

shrink tubes and tapes. The company esti-

mates that the overall risk factor can be cut

as much as 80% by incorporating its mitiga-

tion products.

Feathered Friends?Pigeons are a fairly common pest at power

plants. They may seem like more of a nui-

sance, but these birds are not as innocent as

they may appear. It’s no secret that harbor-

ing a flock of pigeons will create a house-

keeping problem, but Erick Wolf, CEO of

Innolytics LLC, believes that pigeons are

also a safety risk.

Bird feces can create slip and fall hazards

on concrete walkways and steel deck grating.

In addition, the birds can spook personnel

who may not be expecting them when transit-

ing through areas where the birds have taken

refuge. The surprise could result in a fall or

the ill-advised placement of a hand on a piece

of equipment.

There are also some health risks. Accord-

ing to New York City’s Department of Health

and Mental Hygiene—which sees its fair

share of pigeon problems—three human dis-

eases are known to be associated with pigeon

droppings: histoplasmosis, cryptococcosis,

and psittacosis. People with compromised

immune systems are most at risk from expo-

sure to droppings, but anyone cleaning up af-

ter pigeons should wear protective clothing,

such as disposable coveralls, boots, gloves,

and respirators.

Netting, bird spikes, electrical track or

wire systems, flight diverters, guards, and au-

dio and visual repellents are available for bird

control through a variety of companies such

as Bird B Gone, Bird-X, and BirdBusters.

Jack Wagner, president of BirdBusters, said

that there are more than 80 of his company’s

Bird Wailers installed in electrical substa-

tions throughout Alberta alone. The units

incorporate up to 34 natural sounds, such as

target bird alarm and distress calls, together

with the calls of predators like hawks, owls,

and others indigenous to the area. In Alberta,

a master unit and two speakers at each site

have been effective in controlling ravens for

more than 15 years.

Birth ControlWhen it comes to pigeons, Wolf said it is

very hard to completely rid a site of the birds.

He suggested that the cost to do so is usually

a limiting factor.

“The closer you get to zero, the more it

costs,” Wolf said. “Cost is one thing, but na-

ture abhors a vacuum, so driving things to

zero is not necessarily a good thing.”

In other words, once you eliminate a flock,

the site may remain free of pigeons for a pe-

riod of time, but eventually a new flock will

move in. Wolf said the birds are in search

of three things: food/water, harborage, and

warmth. Power plants are a prime location

for at least two of those items.

In addition to the options offered by

BirdBusters and others, Innolytics created a

product called OvoControl for gaining con-

trol of a plant’s pigeon population. For lack

of a better term, OvoControl is birth control

for pigeons.

Pigeons are sexually mature at six

months of age. The birds have two eggs per

clutch and up to six clutches per year, so

it is a rapidly reproducing species. Pigeons

typically only live for two to three years,

however, so the use of contraceptive tech-

nology is an effective control measure, ac-

2. Raccoons can’t read warning signs. This little critter crossed some wires that it

shouldn’t have. Courtesy: TE Connectivity

3. You’re covered. Bushing and conductor covers can prevent animals and others from

touching things they shouldn’t. Courtesy: TE Connectivity



cording to Wolf.

The OvoControl system is set up to au-

tomatically dispense food for the pigeons,

which includes the birth control additive.

The feeders are capable of holding more

than 120 pounds of bait, which is enough

to last several months for an average flock

size. The system activates automatically us-

ing a digital timer.

“Keeping a portion of the flock at the

facility serves the purpose of keeping other

flocks from moving in. As long as there is a

base of pigeons, there is not another flock of

pigeons moving in,” Wolf said.

According to Wolf, after a few seasons,

most customers get down to about 5% to

10% of the starting population. The cost for

OvoControl averages about $400 per month

during the first year, about $200 per month

the second year, and roughly $100 per month

thereafter. Palo Verde Nuclear Generating

Station (profiled in this issue as a Top Plant

Award winner) initiated use of OvoControl

in November 2010 with three feeders and

experienced at least an 80% reduction in its

pigeon population.

Vapor IrritantBirdBuffer offers another option. According

to Jim Beaumont, national account manager

for the company, BirdBuffer machines create

small vapor particles from an oil-based fluid

made up of 20% methyl anthranilate (MA).

MA is an extract fluid—made from the skin

of grapes—that has been used in bird control

systems for more than 40 years.

MA causes an avian-specific pain sensa-

tion in a bird’s trigeminal nerve, located in

their sub-mucous membrane. The pressure

is in the center of their face and results in

a mace- or pepper spray–like reaction. Hu-

mans experience a pleasant grape-scented

fragrance, while birds experience a facial

pressure, tearing of the eyes, and temporary

pain, creating an immediate desire to leave

the area.

The machine (Figure 5) distributes the

vapor on a two-stage timing strategy that is

designed to confuse birds and control the

amount of fluid being used. The strategy

trains birds to avoid areas. Birds cannot see

the vapor or identify the source, but they

sense pain when they fly through the tar-

get area. As they are trained to associate

pain with the location, they learn to avoid

the area. The process can take from three

weeks to three months to gain control, de-

pending on the type of bird and its history

with the location.

“Birds will never habituate or become

accustomed to the vapor—it always works,

unless a mother bird has a nest with eggs

or fledglings,” Beaumont said. “Birds will

suffer any pain to protect their young, just

like us.”

Beaumont said maintenance could be

done in about 15 minutes each month, which

includes refilling the reservoir with about 1

gallon of fluid, changing filters, and wiping

off any vapor blowback that may have col-

lected on the machine. Utility companies that

have used the BirdBuffer system include Pa-

cific Gas & Electric (PG&E), NRG Energy,

Nebraska Public Power District, and Lower

Colorado River Authority. An all-weather

machine costs $8,995, but BirdBuffer also

offers a covered-area model for $5,495 and

rental or leasing options. The fluid costs

$175 per gallon.

Attack of the BlobScientists have been scratching their heads

as to exactly why we periodically see sud-

den, rapid increases in the population, or

“blooms,” of that ubiquitous ocean-dwell-

er, the jellyfish. But they are certain that

there might be a mechanism at work that

involves warmer ocean temperatures and

environmental changes. And for the pow-

er sector, that’s bad news, because when

it happens—as it has dozens of times to

power plants around the world that draw

in ocean water for cooling systems—it

can be expensive.

The squishy creatures have gummed

up intake structures in the U.S., Canada,

Scotland, Sweden, Japan, Australia, and

France. In 2011, EDF Energy’s Torness

nuclear power plant in Scotland was forced

to shut down twice in one week because

cooling waters were inundated with jelly-

fish. It cost the plant about $1.5 million a

day in lost revenues. The same year, jel-

lies caused similar issues at the Shimane

nuclear plant in Japan and at Israel Electric

Corp.’s Orot Rabin coal-fired plant on the

Mediterranean coast.

It turns out that jellyfish blooms aren’t the

only clogging sea creatures to worry about.

Power plant operators also struggle to keep

5. A machine for all seasons. The

Q3 BirdBuffer model, shown here, can be

installed outdoors, while the lower-priced TD

model is designed for covered areas. Cour-

tesy: BirdBuffer

4. A well-rounded solution. Bus insulator squirrel guards—the circular, fan-shaped

protectors above the workers—are installed in this substation along with bushing covers and

other protectors. Courtesy: TE Connectivity

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salps—small jellyfish-like creatures often

seen as long gelatinous chains—at bay. In

2012, PG&E had to temporarily shut down

Unit 2 of the Diablo Canyon nuclear plant

in California (Unit 1 was already offline

for refueling at the time) after salps rapidly

clogged intake screens, even though the

screens roll in a circular fashion to allow

them to be cleaned.

Several solutions have been put forth

worldwide to deal with the spineless

swarms, but many have been unsuccess-

ful. Experts conclude that relying on de-

bris filters and safety protocols may be the

soundest approach to the unpredictable

problem.

South Korean researchers, meanwhile,

have developed a robotic jellyfish extermi-

nator that seeks out and then shreds up to

900 kg of jellyfish per hour. An innovative,

less-grisly solution used at Diablo Canyon,

and reportedly at the Ringhals Power Plant in

Sweden, is a “bubble curtain.”

“When needed, a device underwater re-

leases a sheet of bubbles in front of the in-

take structure. This curtain of bubbles helps

displace the sea salps,” PG&E’s Blair Jones

told POWER. The solution is actually recom-

mended by the National Marine Fisheries

Service as a safe and effective method to di-

vert aquatic creatures away from underwater

construction sites. (For more detail and a dia-

gram of this sort of system, see “CWA 316(b)

Update: Fish Guidance and Protection” in the

October 2011 issue.)

Torness spokesperson Lindsey Ingram

underscored how low the risk of a jelly-

fish-spawned shutdown is, but she added

that plant water intakes at all of EDF’s

nuclear plants are designed to deal with

jellyfish issues safely. EDF is “exploring

the use of equipment to improve resil-

ience of the filtration system, for example,

screen-washing facilities, design, measur-

ing equipment, and visuals to monitor

the performance of the equipment where

needed,” she said.

Along with evaluating (in cooperation

with external research groups) the drivers

that lead to the increase in large jellyfish

blooms, the company’s UK research and

development team is modeling the cooling

water intake area to show what happens un-

der various conditions. That will help the

company “predict when this phenomenon is

more likely to happen and if it is likely to

pose any risk to our sites. In this way addi-

tional measures can be implemented on site

in order to safely mitigate any risks,” Ingram

said. (For another sort of unwelcome bloom

and examples of positive plant-animal inter-

actions, see the sidebars.)

Invasive MusselsPerhaps the most insidious of power plant

pests are the fingernail-sized quagga (Fig-

ure 6) and zebra mussels. The invasive

species originating from the Black and

Caspian Sea region have caused millions

of dollars in damage in the Great Lakes re-

gion, where they were discovered in 1988.

Now, they are making their way through

U.S. waterways. Their discovery at Lake

Mead in 2007, and subsequent colonization

of Lake Powell and parts of Central Arizo-

na Project’s water-delivery system has put

the U.S. Bureau of Reclamation (USBR),

Salt River Project, and other Western pow-

er generators on high alert.

It’s because, as the USBR says, they can

cause steep losses through increased op-

eration and maintenance costs as well as

interruption in water delivery and power

generation functions. Depending on levels

of infestation and facility operating condi-

tions, mussel-related impacts stem from

“fouling” (live mussel attachment) and

“clogging” (due to fouling or release of

mussel shell debris) that may occur in a

number of water delivery and hydropower

systems, says the USBR, which is part of

the Department of the Interior and also the

second-largest hydropower producer in the

U.S. “This includes intakes and penstocks,

gates and valves, bypasses and air vents,

cooling water systems, raw water fire pro-

tection systems, service and domestic water

systems, instrumentation, and drainage, and

unwatering systems.”

A Green Attack: Algae Blooms

Problems with cooling water intake sys-

tems can also be caused by marine grass

and other aquatic life. Operators of reactors

in the Great Lakes region, for example, are

concerned with the proliferation of Clado-

phora, a taxonomic grouping that includes

species of green algae. Fertilizer runoff was

blamed for Cladophora blooms in the 1960s

and 1970s, but blooms have reappeared re-

cently, despite restrictions on phosphorus.

The resurgence of Cladophora has been

particularly costly and cumbersome to op-

erators of nuclear plants on Lake Ontario.

In 2005, algae buildup clogged cooling

water intakes and forced Ontario Power

Generation (OPG) to temporarily shut

down Units 5, 6, and 8 at Pickering B, and

Unit 1 at the Darlington generating sta-

tion was taken offline later that year for

similar reasons. In 2007, an algae event

prompted another shutdown at Picker-

ing—and, later, of Entergy Corp.’s FitzPat-

rick nuclear plant in New York for nearly a

week. OPG said that between 1995—when

the algae began to clog water intakes—

and 2005, the company lost C$30 million

in revenue from those and related Clado-

phora events.

Beyond calling for more vigilance re-

garding how much phosphorus enters the

lake from agricultural and wastewater

runoff, OPG has installed—with mixed

success—a vertical mesh barrier anchored

to the lake bottom near the end of the

water-intake canal to block the flow of the

dense green mass.

6. Musseling in. Quagga mussels, invasive freshwater mollusks that originated in the

Black and Caspian Sea region in Eurasia, have plagued the Great Lakes since the late 1980s but

were also discovered at Lake Mead, Nev., in 2007. Courtesy: Ruth Lake Community Services

District



The attention on this problem has been

good. Many entities have been battling the

critters using traditional chemical control

options—aqueous application of chlorine,

in particular—as well as physical removal

and mechanical controls; however, they

complain that these increase corrosion

initiated by the invasive mussels. But new

solutions are emerging. Marrone Bio In-

novations in 2007, for instance, developed

Zequanox, an environmentally compatible

molluscicide that does not corrode equip-

ment and does not require detoxification

before water discharge. The newly com-

mercialized product is based on research

conducted by a consortium of New York

State’s power generators and the State

Field Research Laboratory in 1991, which

found a naturally occurring, harmless

North American strain of bacteria that is

lethal to the mussels.

While Zequanox sounds promising, the

USBR isn’t stopping there. It continues to

research mussel-resistant coatings, UV light

treatment for quagga mussel larvae, and new

ways to detect mussels early.

The Insect ThreatThough minuscule, insects can’t be ruled

out when it comes to making an impact on

power plants. Carpenter ant and termite in-

festations can be a nightmare, and swarms

of bees and wasps can pose dangers to op-

erators. Even seasonal swarms can be dev-

astating: In 1984, mayflies caused a power

transformer to short out, disconnecting the

La Crosse nuclear plant in Wisconsin from

the grid.

In the Gulf Coast states, meanwhile,

the Rasberry crazy ant—native to Brazil—

has been causing alarm. The ants—named

for their rapid, erratic movement—have

a reputation for swarming into electrical

equipment, chewing through insulation, and

causing overheating, mechanical failures,

and short circuits. Around Houston, they

have plagued NASA and shut down units

in at least three chemical plants (Figure 7).

Tom Rasberry, an exterminator from Pearl-

and, Texas, who first noticed them in 2002

and has since dedicated years to studying

them, says they are spreading at an alarm-

ing rate.

Because they tend to wander in aimless

movements instead of a straight trail, they

are difficult to locate and treat. Exterminators

recommend spraying nonrepellent insecticide

such as Taurus SC or FUSE around infested

perimeters, setting up ant baits, sealing all

possible entry points, and trimming vegeta-

tion away from structures. ■

—Aaron Larson and Sonal Patel are

POWER associate editors.

Power Plants as Animal Nurturers

The spotlight is often on the detrimental

impact of power plants on flora and fau-

na, but power plants can be refuges for

an assortment of endangered or threat-

ened creatures.

American Crocodiles at Turkey

Point. The imperiled American crocodile

has been thriving in a swamp surrounding

Florida Power and Light’s (FPL’s) Turkey

Point nuclear power plant in southern Mi-

ami-Dade County. The utility has its own

on-staff crocodilian expert who monitors

nesting sites and tags hatchlings before

moving them to a more suitable habitat.

Recent reports indicate, however, that

the number of crocodile nests and hatch-

lings in the plant’s 168-mile looping

network of cooling canals have dropped

markedly, owing to waters that have be-

come too hot and salty from rising tem-

peratures and sparse rainfall.

Manatees at Big Bend. In 1986,

Tampa Electric Co.’s 1.7-MW coal-fired Big

Bend Power Plant began seeing manatees

aggregating in large numbers in a canal

where saltwater withdrawn from Tampa

Bay to cool Unit 4 is discharged (Figure

8). When the waters in Tampa Bay dip be-

low 68F, the shallow canal also attracts

stingrays and other aquatic wildlife. To-

day, Big Bend’s discharge canal is a state

and federally designated manatee sanctu-

ary that protects the endangered aquatic

relative of the elephant.

According to environmental group

Defenders of Wildlife, manatees should

rely on warm-water springs or other

natural areas for refuge in the winter

months, but around 60% of the mana-

tee population has become dependent

on artificial sources of warm water at

power plants. If these plants are shut

down or experience equipment failure,

“it could mean death for many of these

manatees,” it says.

8. Winter getaway. Between No-

vember 1 and April 15, hundreds of man-

atees can be seen in a discharge canal at

Tampa Electric Co.’s (TECO) Manatee View-

ing Center. Last year, TECO also installed a

40-foot observation tower as part of the

50-acre site’s looped nature trail that gives

visitors a view of three Florida habitats.

Courtesy: TECO

7. Electrical consumption. Rasberry crazy ants were first discovered in a Houston

suburb in 2002, but they are spreading at an alarming rate. They are known to overcome elec-

tronics and cause failures. This image shows the ants in a relay at a chemical plant. Courtesy:

Rasberry’s Pest Professionals



Load Cycling and Boiler Metals: How to Save Your Power PlantAs many coal-fired power plants designed for baseload service are asked to cycle,

unforeseen stresses have been introduced to boiler pressure parts. Under-standing the effects and implementing mitigation strategies could prevent premature component failure and keep facilities operating reliably.

Rama S. Koripelli, PhD

On August 3, 2015, the U.S. Environ-

mental Protection Agency finalized the

Clean Power Plan, which calls for cuts

in carbon pollution from existing power plants.

This rule, coupled with low natural gas prices,

could result in natural gas–fired facilities be-

ing used more frequently for baseload power

and coal-fired plants being cycled, more than

ever before, to meet grid requirements.

The majority of coal-fired units were de-

signed and constructed as baseload units, with-

out any anticipation of significant load changes.

But combustion turbines and heat recovery

steam generators offer higher thermal efficien-

cies (about 60%) than coal-fired boilers (the

best steam plants may operate at a maximum

efficiency of about 40%), which is also contrib-

uting to a change in dispatch tendencies.

Although coal-fired power plants are still

in high demand, alternative sources are very

attractive from an environmental point of

view. Increasing variable renewable energy

resources, such as solar and wind power,

are placing additional pressure on coal-fired

plants to load follow. However, load cycling

in coal-fired plants causes negative long-term

and short-term effects on equipment reliabil-

ity and availability.

Load Cycling and Its EffectsLoad cycling may include low-load condi-

tions, hot startup, warm startup, and/or cold

startup. Just as the term suggests, a low-load

condition occurs when output is reduced and

the unit is operated at a minimum load with-

out being shut down. When a unit is cycled

on and off daily, it usually undergoes a hot

startup. Warm startups generally occur in

units that operate for four to five days contin-

uously and then shut down during weekends,

while a cold startup follows an extended

maintenance shutdown (usually the plant

will have implemented a layup procedure for

these lengthy upkeep periods).

Following are the most common undesirable

effects of these sorts of cycling operations.

Creep Fatigue. Utility boilers are con-

structed using different materials and thick-

nesses. These materials expand and contract

at different rates. In addition to creep dam-

age, high-temperature components, such as

superheaters and reheaters, experience ther-

mal and mechanical fatigue. The cumulative

effect is known as creep fatigue.

The resulting damage is much more se-

vere than standalone creep or fatigue dam-

age. Under cyclic loading, tube-to-header

welds develop cracking due to a combination

of fatigue stresses and hoop stresses. Fatigue

stresses can result from relative movement

between the components, specifically dur-

ing warm-up or cool-down, or when load

changes occur due to transient stresses. Fa-

tigue stresses can also be present as a result

of inadequate tube leg flexibility, defective

supports/attachments, or rigid attachments

on the pressure parts.

Ligament Cracking. Individual high-tem-

perature superheat (SH) and reheat (RH) tubes

may operate at different temperatures because

of variations in heat distribution, slagging, foul-

ing, and misalignment. Therefore, steam enters

into the header at different temperatures.

Load cycling exacerbates the temperature

difference between the individual tubes, be-

cause the firing rate is adjusted during load

changes to maintain pressure and temperature.

During load increase, the boiler is temporarily

overfired, and the condition reverses when load

is reduced. This causes transient thermal shocks

to the header, resulting in ligament cracking.

High-Temperature Circuit Thermal Fa-

tigue. In addition to these thermal stresses,

the external stresses associated with header

expansion and contraction can cause damage

to cycling units, resulting in fatigue cracks at

the attachments. An additional fatigue com-

ponent can exist wherever components are

joined via welding, because different parts

expand and contract at different rates. Al-

though the fatigue component is within the

endurance limit, it will affect the creep prop-

erties of the components.

Over-Tempering. Creep-strength-enhanced

ferritic steels (CSEFs), like T91 and T23, are

very popular in modern power plants because

they offer higher allowable stresses and supe-

rior creep properties than their ancestor grade

steels, such as T22 and T11. However, there

are some inherent long-term maintenance is-

sues with the CSEF steels. The use of CSEFs

in heavy-cycling units, specifically in reheat

circuits, significantly affects the superior prop-

erties obtained through precise heat treatment,

resulting in premature failures.

Dissimilar-Metal Welds. Dissimilar-

metal welds (DMWs) are very frequently

used in high-temperature circuits to facilitate

material transitions. Load swings produce

significant transient thermal and differential

stresses on the DMWs. These welds are not

only subjected to creep but also are suscepti-

ble to creep fatigue failure. Load cycling sig-

nificantly reduces the useful life of a DMW.

Condensate in Low Points. Conden-

sate usually collects in the remote sections

of SH and RH circuits, resulting in two ma-

jor issues: thermal fatigue and short-term

overheating. The temperature difference that

exists between the headers and steam can

produce thermal fatigue cracking and liga-

ment cracking. Warm startups produce sig-

nificant thermal fatigue damage because the

1. Condensate in loops. This image

shows several secondary superheater tubes

that failed due to short-term overheating after

only eight months of service. Courtesy: David

N. French Metallurgists



temperature difference is usually higher.

Rapid startup conditions may lead to short-

term overheating failures, because conden-

sate in system low points can cause increased

metal temperatures downstream (Figure 1).

The tensile strength of the steel decreases

significantly once it is beyond design temper-

atures. Also, rapid startups and shutdowns, as

well as load changes, can cause exfoliation of

the inner diameter oxide scale. If the exfolia-

tion is excessive, it may lead to pluggage of

bends or erosion damage in the turbine.

Low-Temperature Circuit Thermal Fa-

tigue. In low-temperature regions of the boiler,

load cycling also causes thermal fatigue crack-

ing in economizer inlet headers or tubes, lower

furnace wall tubes or headers, and steam drum

internals. This fatigue cracking primarily oc-

curs from the ingress of relatively colder water

into hot boiler components or vice versa.

Corrosion Fatigue. Load cycling exacer-

bates corrosion fatigue on waterwall tubes be-

cause the differential stresses on waterwall tubes

are higher during startups and load swings.

Corrosion fatigue is not only a reliability issue,

but it also is a safety concern because failures

usually occur on the cold side of the boiler.

Conditions necessary for corrosion fatigue

to occur include either having the boiler wa-

ter oxygen concentration too high or the pH

outside of the control range at the same time

that stresses are high enough to break the

magnetite layer (Figure 2). Corrosion fatigue

occurs when operating or residual stresses

break the protective magnetite (Fe3O4) layer,

exposing the bare steel to the corrosive envi-

ronment (Figure 3). These stresses are high-

est during transient periods.

Caustic Gouging. Caustic gouging is a

well-known issue in natural circulation units,

specifically during low-load conditions. In

natural circulation units, the coolant flow is

biased to certain tubes because it operates on

the density difference between the hot and

cold fluids. Low-load conditions and load

swings play a major role in caustic gouging

because constantly changing conditions re-

sult in repetitive upsets to coolant flow. The

flow upsets cause caustic to concentrate at

the edges of steam bubbles. Caustic concen-

trations remove the protective layer of iron

oxide, resulting in tube wastage (Figure 4).

Phosphate Hideout. Phosphate hideout,

one of several forms of underdeposit corro-

sion, usually occurs when units are operating

with phosphate-based treatment. Phosphate

hideout causes ionic phosphate to disappear

or absorb during high-heat-input conditions,

but it returns or dissolves into boiler water

when the heat input is reduced. Phosphate

hideout promotes acid phosphate corrosion.

Hideout becomes evident during load swings

or startups while changing heat input. Dirty

boilers are susceptible to phosphate hideout

and acid phosphate corrosion.

Mitigation StrategiesThere will always be some adverse effects

on equipment reliability due to a low-load

condition, hot startup, warm startup, or cold

startup. Each of these conditions will affect

2. Corrosion fatigue. This cutaway

view shows a tube that experienced corrosion

fatigue in the transition bend near the lower

slope of a plant that cycled daily. Courtesy:

David N. French Metallurgists

3. Taking a closer look. This micro-

scopic view shows a tube surface that has

begun to crack as a result of corrosion fatigue.

Courtesy: David N. French Metallurgists

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4. Caustic gouging. This cutaway view

shows a tube that experienced caustic attack in

a cyclone inlet roof tube. The plant commenced

load cycling about one year prior to this failure.

Courtesy: David N. French Metallurgists



the integrity of pressure parts one way or an-

other. It has been observed across the board

that warm startups cause the most damage

to equipment, because the temperature dif-

ference is higher and there is greater suscep-

tibility to air in-leakage than what is found

during other cycling conditions.

Following are some useful strategies for

mitigating equipment damage.

Add More Tube Flexibility. Fatigue

stresses often occur as a result of inadequate

tube leg flexibility between tube penetrations

and the header, and also from rigid attach-

ments on the tube. More flexibility and bet-

ter attachment design will reduce the fatigue

stresses. Sometimes header relocation may

be required to provide more flexibility.

Use Slip-Type Attachments. Many

older units were designed with rigid attach-

ments. Slip-type attachments should be used

in place of rigid attachments to accommodate

differential thermal expansion.

Redesign for Symmetrical and Widely

Spaced Tube Penetrations. Several older

plants were designed with closely spaced, un-

symmetrical tube penetrations, which are sus-

ceptible to ligament cracking. It is well known

that evenly spaced, larger ligaments are less

susceptible to creep fatigue damage (Figure 5).

Redesign of tube-hole penetrations and

tube-to-header weld configuration, especially

eliminating the lack-of-fusion notch at the end

of the tube penetration, can also increase creep

fatigue resistance. The inclusion of a smooth

chamfer at the inner diameter of the header

bore hole reduces stress concentration (Figure

6), improving creep fatigue resistance.

Make Periodic Inspections. The majority

of piping-related problems are associated with

hangers and support systems. Good attachment

design is vital to minimizing creep fatigue. Peri-

odically inspecting attachments and correcting

deficiencies will reduce fatigue-related issues.

Terminations of attachments should taper to the

surface to reduce localized stress concentra-

tions. Lack of penetration in attachment welds

can result in hot spots where heat is unable to

effectively dissipate or can increase stress con-

centrations. Good weld design and adherence

to welding procedures is essential.

Lower Ramp Rates. Transient stresses

due to load cycling affect the useful life of

a DMW. Transient stresses can be reduced

with slower startups.

Use Nickel-Based Filler Metals. A

DMW can be made with or without filler

metal, which will have a finite life. DMWs

made with EPRI P87 or Inconel filler metal

are expected to have a longer life than those

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Small ligament

Large ligament

Present Upgrade lower ligament stress

5. Bigger is better. Larger ligaments

are less susceptible to creep fatigue damage.

Source: David N. French Metallurgists

Large lack of fusion notch

Chamfer

Present Upgrade lower stress

Smaller lack of fusion notch

6. Design changes. Elimination of the

lack-of-fusion notch at the end of tube pen-

etrations and including a smooth chamfer at

the inner diameter of the header bore hole

can improve creep fatigue resistance. Source:

David N. French Metallurgists



without filler metals. A DMW made using

nickel-based filler metal lessens the effects

of the thermal expansion differences between

stainless steel and ferritic steel.

Relocate DMWs. Stresses and temperatures

are the critical factors in the lifespan of a DMW;

performance can be improved by controlling

these factors. The weld joint can be relocated to

a position where it is exposed to lower tempera-

tures. Frequent inspection and maintenance of

tube hangers, supports, and spacers can be per-

formed to reduce secondary loads.

Bake Tubes. Condensate in high-temper-

ature circuits creates major problems during

startup periods. The tubes should be baked

for long enough to evaporate the condensate

before increasing the heat input. Reduce the

thermal gradient between the fluid and metal

during startup periods. Although load cycling

plays a major role in thermal fatigue, once

the component reaches equilibrium, thermal

fatigue will not be a significant factor.

Use Rifled Tubing. The use of rifled tub-

ing in areas susceptible to underdeposit corro-

sion can provide better flow mixing to avoid

potential corrosion issues. Load cycling sig-

nificantly increases the susceptibility of water-

wall tubes to corrosion fatigue. Fast startups

increase transient stresses because different

parts expand and contract at different rates,

breaking protective oxides and exposing bare

tubes to the corrosive environment.

Improve Welding Techniques. Pad welds

should be avoided in regions susceptible to

corrosion fatigue. The residual stresses from

welding exacerbate corrosion fatigue. Addi-

tionally, poor weld profiles should be elimi-

nated to reduce stress concentration. Lack of

penetration in attachment welds can increase

metal temperatures and stress concentration.

Maintain Proper Water Chemistry. It is

critical to ensure that water chemistry is with-

in range for pH and oxygen content, especial-

ly during startups or load shifts, to reduce the

risk of corrosion fatigue. Boiler cleanliness

must be maintained to reduce the risk associ-

ated with phosphate hideout. Use trisodium

phosphates in place of mono- or disodium

phosphates to bump phosphate readings. The

addition of trisodium phosphates does not

cause acid phosphate corrosion, but the addi-

tion of mono- and disodium phosphates can

promote acid phosphate corrosion.

Avoid heavy blowdowns, which will signifi-

cantly affect sodium phosphate ratios and ag-

gravate the situation in units susceptible to acid

phosphate corrosion. Perform periodic deposit

weight density testing to know how dirty the

boiler is. Boiler cleanliness will significantly re-

duce a majority of waterside issues. ■

—Rama S. Koripelli, PhD ([email protected]) is technical director

for David N. French Metallurgists

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FUNDAMENTALS

Ensuring Reliable Boiler Operation Through Proper Material AnalysisCreeped out and fatigued—that’s the state of many coal-fired boilers these

days. Understanding failure mechanisms and suitable testing methods for identifying potential trouble can help you find problems before the problems find you.

Brandon Bell, PE

Even as the current regulatory environ-

ment pushes new power generation

to utilize natural gas over other fuel

sources, a significant amount of existing

coal-fired generation remains in operation.

A majority of these coal-fired power plants

have been in existence for a long time—the

average age is near 40 years. Keeping these

plants online and running efficiently pres-

ents a challenge, but with programs in place

to effectively monitor equipment condition

and replace critical parts at optimal times,

these units can continue reliable operation

for years to come.

Modes of FailureFor long-term operation of coal-fired steam

generators, creep and thermal fatigue are the

two damage mechanisms that typically affect

boiler integrity. Boilers can also be damaged

by chemical imbalances in water or flue gas

chemistry, but generally those problems can

be corrected in a short period of time.

Thermal Fatigue. Thermal fatigue is ex-

perienced from cyclic stresses caused by tem-

perature gradients that vary over time. Steam

generators experience the greatest amount of

thermal fatigue during startup and shutdown

activities.

In high-temperature boiler tubes, lo-

calized high-stress areas will plastically

deform until the stress is relieved. This

deformation process, while providing tem-

porary relief to components at elevated

temperatures, also introduces new stresses

in these same components as the system

cools—with material unable to return to its

original position.

Boiler designers anticipate a planned

number of startup and shutdown cycles

and design the boiler to handle these sce-

narios. However, excessive cycling of a

steam generator, either as a result of being

dispatched too frequently or being brought

down in unplanned, forced outages (due

to poor equipment reliability) will pre-

maturely push the boiler past its original

design life. The excessive cycling will ul-

timately lead to thermal fatigue cracking

of boiler tube elements. Typically, thermal

fatigue occurs at weldments or points of

configurational change.

Creep. The second significant mechanism

of steam generator tube failures is creep.

Creep is a progressive, permanent deforma-

tion of a material under stress at high tem-

peratures.

When materials are manufactured, mi-

crovoids form within the material structure.

Over time these microvoids begin to propa-

gate and interconnect, forming cracks within

the material. The deformation occurs plasti-

cally and causes a thinning of the material,

which results in higher stresses and an in-

creasing creep rate. This phenomenon can

occur in materials experiencing high stresses,

but still at levels below the yield strength of

the material.

Creep occurs in three defined stages dur-

ing the life of a material. The first stage is

commonly referred to as primary creep. Dur-

ing this stage the strain rate is high, but it

rapidly slows with time as a result of work

hardening. This first stage of creep is rela-

tively short-lived and results in no significant

changes to the material structure.

The next phase of creep is the secondary,

or steady state, phase. The material will expe-

rience secondary creep for the majority of its

lifespan. This stage is defined by a relatively

constant strain rate, where work hardening is

balanced by its recovery rate.

The final stage of creep, the tertiary phase,

is defined by rapid elongation over time. This

rapid elongation will accelerate until failure

of the material occurs.

Predicting LifespanThere are mathematical approaches to calcu-

lating the useful life of a material versus time

and temperature. General Electric engineers

developed one method in the 1950s that can

be used to extrapolate experimental data for

creep and rupture strength of materials. It’s

known as the Larson-Miller Parameter and is

expressed as:

P = T x (C + log t) x 10-3

where:

T is the absolute temperature of the mate-

rial during operation

t is the number of hours in service

C is a constant (typically a value of 20),

and

P is the Larson-Miller Parameter

1. Out with the old. This main steam

header developed ligament cracks from many

years of operation and thermal cycling. It had

reached its end of service life and required re-

placement. Courtesy: Brandon Bell, PE


FUNDAMENTALS

Thermal fatigue cracking tends to be a

localized phenomenon that can be identified

using conventional nondestructive examina-

tion methods. Once thermal fatigue crack-

ing is identified, welding can easily repair

it. Creep damage typically is identified us-

ing metallographic examination methods.

If a material has been identified to be in the

tertiary stage of creep, simple repairs are not

possible, and replacement of the material is

required (Figures 1 and 2).

Analyzing Boiler MaterialsTo avoid forced outages resulting from ther-

mal fatigue and creep, nondestructive exami-

nation techniques can be used to determine

the state of materials (Figure 3). When used

effectively, these techniques are able to track

the progression of either thermal fatigue or

creep, which helps plants plan in advance for

replacement of components rather than wait-

ing for material failure and then scrambling

to correct the problem. Some commonly

used nondestructive examination techniques

follow.

Liquid Penetration. A common non-

destructive examination technique used for

detecting surface cracking on a material is

called liquid penetration. This technique

is very versatile, as it does not require spe-

cific material properties for the metal being

tested.

Prior to the material being tested, it must

be cleaned of any contaminants and allowed

to dry. A low-tension liquid with a visible

dye is then applied to the surface of the mate-

rial, at which point the capillary effect will

draw the liquid into any discontinuities in the

metal. Any excess liquid is removed from the

surface prior to inspection.

Under a white or fluorescent light, the ma-

terial is inspected for the presence of the liquid

penetrant. The presence of the liquid penetrant

indicates voids in the surface material, either

from cracking or porosity of welds.

2. In with the new. Installing this replacement steam header will extend the plant’s op-

eration for years to come. Courtesy: Brandon Bell, PE

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FUNDAMENTALS

Ultrasonic Testing. Ultrasonic testing

(UT) is a powerful tool that is used to detect

and evaluate flaws in a material and character-

ize the material flaws. It also can be used to

measure thicknesses of materials. UT testers

make use of three basic components: a pulser-

receiver, a transducer, and a display device.

This technology generates a high-fre-

quency ultrasonic wave that is transmitted

through the material being tested. When

the sound wave is generated at the surface

of the material using the pulser, it quickly

propagates through the material structure at

a known velocity. If the sound wave encoun-

ters a discontinuity in the grain structure of

the material, a portion of the initial sound

wave is reflected back to the receiver. The

sound wave will continue until it reaches the

opposing boundary of the material and the

remaining sound energy is reflected back to

the receiver.

The receiver captures the intensity and

intervals at which the initial sound wave is

reflected. This data can be processed into

a graphical result on the display device.

Readings are displayed in real time—pro-

viding the user with instantaneous results.

With the sound wave processed, a techni-

cian or engineer can evaluate any flaws

found in the material structure while as-

sessing overall material thickness through-

out.

Determining the thickness of the material

in service is critical to calculating the materi-

al’s ability to resist stress. The minimum wall

thickness for a material can be calculated us-

ing a variety of material properties and op-

erating conditions. The calculation uses the

following relationship:

tm = PD / 2 x ( SE + Py ) + A

where:

tm is the minimum wall thickness

P is the internal design pressure

D is the outside diameter of the pipe

SE is the maximum allowable stress of the

material at the design temperature

y is a coefficient (based upon material

properties and design temperature), and

A is any additional thickness (for example,

an allowance for corrosion/erosion)

Comparing the actual wall thickness to the

minimum wall thickness will identify if the

element needs to be replaced as a result of

loss of material.

Phased Array Ultrasonic Testing. An

offshoot of standard UT testing is the phased

array ultrasonic testing (PAUT) method. Also

a nondestructive examination technique, the

PAUT method makes use of multiple probes

that emit high-frequency ultrasonic waves.

The introduction of the sound wave is

time-delayed from element to element in or-

der to produce a focal point to be analyzed.

The timing of the sound waves can be varied

in order to “sweep” the material and scan

for imperfections. As with UT, the results

are viewed in real time, allowing the user

to locate and identify material flaws instan-

taneously.

Magnetic Particle Testing. Magnetic

particle testing (MT) is a nondestructive

examination method used to identify linear

flaws at or near the surface of a material.

With the MT technique, the material being

tested is magnetized, which produces flux

lines along the surface of the material.

Flaws or discontinuities in the material

distort the flux lines, causing the magne-

tism to leak out. Dissipation of the flux lines

creates regions of magnetic polarity. When

magnetic particles are applied to the surface

of the material, they visibly pool together in

these areas of high polarity and highlight ar-

eas with flaws or discontinuities.

Alternately, this test can be performed

by using wet magnetic particles mixed with

fluorescent dyes, similar to that of liquid

penetration inspections. Compared to dry

particles, the use of wet particles provides for

a more effective media to fill into cracks and

fissures found in the material. When viewed

under a black light, the use of a fluorescent

dye will clearly highlight material cracking

to the inspector.

The MT technique is quick, simple, and

yields real-time results for cracking as a re-

sult of creep. However, the test method is

limited only to materials that are ferromag-

netic. After completion of the test, the mate-

rial will need to be demagnetized, typically

using an alternating current coil.

Replication Metallography. In order to

view the grain structure of a material at high

4. Clean as a whistle. This pipe’s surface has been cleaned thoroughly for inspection of

a critical weld. Courtesy: Brandon Bell, PE

3. Visible defects. No special nondestructive examination techniques were needed here.

A simple visual inspection revealed that several pressure part supports were either damaged or

missing and needed repair. Courtesy: Brandon Bell, PE


FUNDAMENTALS

magnification, a nondestructive examination

technique called replication metallography

can be used. It provides a mirrored image of

a material’s structure.

In order to provide this level of detail, the

material to be tested needs to be cleared of

any contaminants and polished to a smooth

mirror-like finish. This can be a time-con-

suming and laborious process, as manual

techniques are typically required to clear

scale and rust from the installed material

(Figure 4).

After the material has been cleaned and

polished, a chemical etchant is applied to the

surface that allows the grain structure to be

revealed. The chemical used, and duration

of application (to reveal the material’s grain

structure), will be chosen based on the mate-

rial being tested.

A replicating material will then be ap-

plied to the material surface to embed the

grain structure into the replicating material.

Once the material dries, it can be removed

and sent for microscopic observation. The

replicating material will now reveal the

grain structure of the material without com-

promising the integrity of the material itself.

The process will give insight into only the

grain structure at the surface of the mate-

rial and is used on base metals and critical

welds alike.

High-Energy Pipe SurveillanceIn addition to employing nondestructive ex-

amination techniques, conducting surveys of

a plant’s high-energy piping systems should

be a routine occurrence. High-energy piping

systems typically include main steam, hot

reheat, cold reheat, boiler feedwater, and

turbine extraction piping systems. High-

energy piping surveys analyze stress and

strain on the piping and support system.

This is critical for extended plant operation,

because the survey can detail areas of con-

cern that can be corrected prior to a material

or pipe support failure.

As these high-energy systems operate

over time, hanger adjustments are sometimes

made that change the dynamics of the system.

Additionally, poor initial designs, changes

in modes of operation, or plant preferences

can result in the addition or removal of key

pipe support elements. Because high-energy

piping expands and contracts considerably

during startup and shutdown cycles, if such

changes are not properly implemented, the

system will grow, bend, or cycle in an unde-

sirable way.

In order to effectively evaluate these high-

energy systems, they need to be observed in

the two extreme states of operation. Docu-

menting the hanger positions in both hot

(full-load operation) and cold (zero-load

cold plant) conditions allows engineers to

model the stress and strain of the system.

This modeling can then be compared against

the original design and evaluated for proper

support and growth allowance. The results

will dictate if adjustments to hangers are re-

quired or if new support hardware is neces-

sary to bring the system back into allowable

stress ranges.

Although it may be challenging to contin-

ually inspect and document the material con-

dition of steam-generating equipment and

high-energy piping, the payback will come

in the form of increased equipment reliabil-

ity and availability. Shutdowns as a result of

forced outages are costly, due to the likeli-

hood of expedited material purchases and

uncertain availability of skilled craft labor.

Establishing programs to track and plan for

repairs will lead to fewer forced outages and

longer plant life. ■

—Brandon Bell, PE ([email protected]) is lead project manager for power

projects at Valdes Engineering Co.

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SAFETY

Minimizing Coal Dust Combustion Hazards: Lessons from Laramie River StationCoal dust combustion events injured employees and damaged equipment at

Laramie River Station in May 2013. Any dust-filled facility could consider implementing some of the plant’s corrective actions to reduce the risk of experiencing a similar incident.

Basin Electric Power Cooperative

When Laramie River Station (LRS),

near Wheatland, Wyo., was built

nearly 35 years ago, it was state-

of-the-art. Constructed by the Missouri Basin

Power Project (MBPP), the plant has three

570-MW coal-based units: Unit 1 began op-

erating in 1980, Unit 2 in 1981, and Unit 3

in 1982.

The MBPP is made up of six organiza-

tions: Basin Electric Power Cooperative

(BEPC), Tri-State Generation and Transmis-

sion Association, Western Minnesota Munic-

ipal Power Agency, Lincoln Electric System,

Heartland Consumers Power District, and

Wyoming Municipal Power Agency. BEPC

is the plant’s operator.

LRS includes a coal system consisting

of 23 conveyors with nearly 25,000 feet of

conveyor belt, 16 dust collectors, 25 feed-

ers, 21 main plant silos and pulverizers,

three coal yard silos, and a rotary dumper.

The entire coal supply system extends more

than one mile.

It’s a massive system and one that has

had consistent and constructive maintenance

throughout its history. However, events at LRS

in the spring of 2013 caused BEPC to evaluate

and make changes to how the coal system was

inspected and operated thereafter.

Developing a TeamOn two separate occasions in May 2013, coal

dust combusted within the system, resulting

in injuries to three employees and forcing re-

pairs to Units 1 and 2. BEPC employees and

plant management reacted quickly to ensure

similar incidents would never occur again.

That summer, representatives from the Op-

erations, Maintenance, Planning, and Safety

and Engineering departments met to form the

LRS Coal System Focus Team.

“These team representatives were people

from throughout the employee ranks with the

ability to effect real, positive change,” said

Brian Larson, LRS plant manager.

During its first meeting, the focus team

declared that its mission was to improve coal

system safety and reliability using a combi-

nation of technology and cleaning to meet

respirable dust level requirements prescribed

by the Combustible Dust National Emphasis

Program (NEP).

“The team realized it would take a combi-

nation of major capital projects, maintenance

technique refinements, and operation proce-

dure adjustments,” Larson said. “There was

no ‘silver bullet.’”

During the second meeting, the team split

up the coal system into eight areas and con-

ducted a criticality analysis using 11 differ-

ent criteria, including generation impact, risk

exposure, dusting (Figure 1), and reliability.

The plant’s cascades/main plant silos area

became the team’s primary focus.

Through the first eight months, the focus

team worked to gain the knowledge needed

to make an impact on the LRS coal system.

To support the focus team’s work and share

knowledge, BEPC formed the “Co-op Wide

Dust Team.” This team consisted of person-

nel from all of BEPC’s coal-based facilities—

LRS, Dry Fork Station, Antelope Valley

Station, Leland Olds Station, and subsidiary

Dakota Gasification Co.’s Great Plains Syn-

fuels Plant. The team met quarterly, rotating

between the different facilities to study and

learn the different coal systems, share knowl-

edge, and cultivate ideas.

In February 2014, BEPC contracted

CoalTech Consultants Inc. to conduct an as-

sessment of the LRS coal system. The focus

team also joined the Powder River Basin

Coal Users’ Group (PRBCUG) and sent a

few members to the PRBCUG annual meet-

ing in 2014 to collect more information.

With the initial analysis complete and the

broad knowledge gained by studying coal

systems used throughout the BEPC fleet and

elsewhere, the time had come to implement

some changes.

Upgrading Main Plant Cascades and SilosTo prevent coal dust combustion within a

bunker, the coal system focus team deter-

mined that the plant would benefit by adding

the following:

■ An internal bunker carbon monoxide (CO)

monitoring system to identify undesired

combustion in its early stages.

■ A fixed internal fire suppression system

to suppress undesired combustion with no

risk exposure.

■ A fixed internal wash-down system to

prevent offline combustion events in an

empty bunker.

BEPC engineers tackled the CO monitor-

ing project by investigating an air-sampling

1. Gauging dust levels. A surface film

thickness gauge is used to measure coal dust

accumulation and ensure that levels meet

National Environmental Policy Act standards.

Courtesy: Basin Electric Power Cooperative

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SAFETY

CO monitoring system rather than the con-

ventional in-situ CO monitors. The team felt

that if air within the bunkers could be drawn

to a monitoring system outside of a combus-

tible dust area, using equipment concentrated

in a group of panels, safety would be im-

proved and reliability increased.

To accomplish this, BEPC engineers

designed a system that draws air from the

cascade rooms and silos to a group of moni-

toring panels mounted on the outside of the

cascade walls (Figure 2). After successful

initial trials, construction was started to mir-

ror the design in the Unit 1 and Unit 2 cas-

cades, as well as in the coal yard silos. Data

from the system is monitored by both plant

operations and the Wheatland Volunteer Fire

Department to observe CO trends, allowing

more informed decisions to be made.

“The CO monitors will be an early detec-

tion that will help us respond more quickly,”

said Kevin Brown, LRS planner and Wheat-

land volunteer firefighter.

With state-of-the-art combustion detection

in place, the team’s focus switched to sup-

pression and prevention. Employees designed

a fixed internal washdown and suppression

system that can be used to either wash down

a bunker that is being taken out of service or

suppress a combustion event detected by the

CO-monitoring system.

Minimizing Dust CreationAfter addressing the likely root cause of the

LRS coal dust combustion incidents, the

team shifted its focus to dust creation and

collection. The coal system focus team pur-

sued two technologies to accomplish this:

foam suppression and controlled flow trans-

fer points.

A foam suppression system was installed

in the crusher house in an effort to reduce

dust creation at subsequent transfer points.

As part of the system, a chemical solution is

mixed with compressed air to create a shav-

ing cream–like substance (Figure 3) that is

injected into the crusher feeders. Data are

still being gathered to measure the foam’s ef-

fect on respirable dust levels, but preliminary

results are promising.

The coal system focus team decided to re-

place the chutes and implement a controlled

flow design. The goals of the chute project

were to:

■ Replace older coal chutes

■ Minimize coal dust creation

■ Facilitate the transfer of coal (minimize

plugging)

■ Decrease dust collection volumes

■ Minimize wear on conveyors through cen-

tral coal loading

■ Reduce coal spillage

To achieve these goals, a team of BEPC

engineers developed a technical scope to re-

place 10 different transfer points in the LRS

coal system. One objective was to match

the velocity of the coal stream to that of the

receiving belt at the chute discharge point,

minimizing the induced airflow traveling

through the transfer point. After the modifi-

cations were completed, studies showed that

the newly installed chutes reduced respirable

dust levels in all of the conveyer transfer ar-

2. Safely out of harm’s way. CO monitoring panels are mounted outside of the cas-

cade walls, but draw air from the cascade rooms and silos. Courtesy: Basin Electric Power

Cooperative

3. No, it’s not shaving cream. Adding a GE Betz foam suppression system was just

one step Laramie River Station took to reduce the amount of coal dust generated at the plant.

Courtesy: Basin Electric Power Cooperative


SAFETY

eas—one by more than 75% (Table 1).

Not only did the changes decrease dust levels, but the chutes also

improved conveyor capacity by more centrally loading the coal. The

new chutes plug less frequently, reducing coal spillage and eliminat-

ing the need for one of the existing dust collectors while also being

easier to maintain.

“This project would not have been as successful without the dil-

igence and patience of the Plant Techniques personnel. They were

able to accomplish incredible things in very short hot-work periods,”

Larson said. “The new transfer points met all the goals, and Laramie

River Station plans to install more in the coming years.”

Improving Dust CollectionAlthough controlled flow chutes and foam suppression reduced dust

creation, the focus team still saw the need to address dust collection,

both through baghouses and washdown. Nearly all of LRS’s exist-

ing baghouses were indoors and lacked internal fire suppression. For-

tunately, an already-completed major dust collection improvement

served as the basis for all other coal yard baghouse modifications.

In 2011, a new Air-Cure dust collector was installed at the rotary

car dumper to pneumatically convey the dust almost one mile through

a 6-inch line to the main plant silos. With this design, the vast major-

ity of dust collected at the dumper is only handled once before it is

fed into the pulverizers.

The focus team decided to replace four of the coal yard dust col-

lectors with modern, fully equipped Air-Cure baghouses that dis-

charge the dust into the pneumatic line. This project will put a stop

to handling the same dust at different transfer points and decrease

dust levels throughout the system. Project construction is planned for

completion in 2016.

Regardless of the dust control equipment, dust cleanup through

washdown is still an essential facet of a clean coal system. Current-

ly, coal yard personnel perform all washdown activities manually at

LRS. To address this, the focus team developed a three-year plan to

install an automated washdown system throughout the coal system.

The project is scheduled in three phases beginning in 2016 with com-

pletion expected in 2018. Drainage modifications are under way in

the main plant cascades and other areas to accommodate the higher

effluent volumes generated by the new system.

Automatic washdown will allow rapid cleaning in tight time win-

dows, permitting the coal yard to direct its manpower to other ac-

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Chute location

Average

before chute

replacement

(mg/m3)

Average

after chute

replacement

(mg/m3)

Percent

improvement

Conveyor 3 to 5 5.5 2.2 59%

Conveyor 3 to 6 5.5 1.3 77%

Conveyor 4 to 5 5.5 2.5 54%

Conveyor 4 to 6 5.5 1.8 68%

Conveyor 5 to 7 4.8 2.3 53%

Conveyor 6 to 8 4.8 2.6 46%

Crusher 1 to 9 NM 0.4 NA

Crusher 1 to 18a NM 0.4 NA



Notes: NA = not applicable, NM = not measured.

Table 1. Dust levels in controlled flow chutes. This

table shows controlled flow chute dust level improvements at the tail

end of receiving conveyors. Source: Basin Electric Power Cooperative


SAFETY

tivities. Additionally, it will keep the coal

system well within NEP dust accumulation

standards, which will reduce the chance of

another coal dust combustion incident.

People and ProceduresWhen all is said and done, people following

proper procedures are what make everything

work and what keep everyone safe. The fo-

cus team recognized the importance of the

human element and the need for a refined

operating approach, new procedures, and ad-

ditional training for all BEPC employees and

local emergency response personnel.

The LRS coal system is remotely oper-

ated from the main plant control room, but

the focus team worked with both main plant

and coal yard personnel to refine operations.

The coal yard and main plant coal system

operator rounds were completely over-

hauled with records now populating a new

database for better trending. Infrared cam-

eras, dust accumulation measurement, and

more thorough bearing temperature data

collection were added to the rounds. These

new parameters help to catch heat sources

before they become a combustion hazard

and aid in documenting the efficacy of the

washdown schedule.

Many new procedures have been devel-

oped to minimize the risk of another event.

An operational modification identified by

the focus team is to run the coal system

conveyors at full load, which reduces wear

on components and reduces spill frequency

and dust generation. A major effort to re-

store and add belt scales is under way and

expected to be completed by the end of

2015. This is expected to provide control

room operators with more accurate tonnage

information to ensure the system is running

at its optimal capacity.

To decrease the chance of coal dust com-

bustion in bunkers, employees developed an

online and offline main plant silo unloading

procedure. The online procedure calls for

unloading one silo in each unit every day to

flush out stagnant coal that can accumulate

at the profile change. This means that every

bunker is unloaded once per week to encour-

age first-in first-out coal storage throughout

the system.

The offline procedure sets timelines for

how long coal can sit in an offline silo. Re-

claimed coal has a higher chance of sponta-

neous combustion due to its higher oxidation

levels as a result of being exposed to atmo-

spheric elements for longer periods of time,

so the times vary depending on whether the

coal in the bunker came straight from a train

or if it was reclaimed from a stockpile.

Workaround procedures have been de-

veloped for coal system equipment failures.

The procedures focus on calling LRS and

emergency response personnel to come to-

gether and agree upon any workarounds

that may be required to continue operating

the coal system. This procedure ensures ev-

eryone stops, assesses all the hazards, and

comes up with the best possible solution to

any problem.

Finally, the plant’s Emergency Action Plan

was updated to ensure the well-equipped

Wheatland Volunteer Fire Department (Fig-

ure 4) is the first responder to all PRB coal

combustion events. This is a natural fit, as

eight members of the fire department are also

current LRS employees, making them very

familiar with the plant.

Training and Other InitiativesTraining has been critical to the improve-

ment in safety and operation of the LRS coal

system. LRS employees now undergo annual

general PRB coal awareness training, and

BEPC and the Wheatland Volunteer Fire De-

partment have collaborated on joint training

that addresses the unique hazards present at

the plant.

“Laramie River Station has types of haz-

ards we don’t usually deal with,” said Bob

Glasson, Wheatland Volunteer Fire Depart-

ment training captain. “Basin Electric provid-

ed us with training for coal dust combustion

and specialized equipment that has helped us

more effectively fight fires at the plant.”

Employees at LRS are also taking part in

BEPC’s “Our Power, My Safety” process,

which consists of a series of safety initiatives

intended to spur continuous improvement of

working conditions and keep safety top-of-

mind for employees at both work and home.

Continuous Improvement (CI) initiative

#1, improved worksite inspections, has been

rolled out at all BEPC facilities, and CI ini-

tiative #2, improved safety communications,

has been rolled out at LRS and several other

BEPC facilities. CI initiative #3, employee

education, will roll out in fall 2016.

BEPC’s management understands that it is

imperative to make proactive changes by in-

vesting in capital projects, improving main-

tenance and operation techniques, updating

procedures, encouraging teamwork, and

conducting suitable training to help mitigate

hazards. Collaboration is encouraged within

facilities, as well as between companies and

coal experts.

“I am proud that we have done so much

in the last 28 months,” Larson said. “I feel

confident that within the next three years,

through the efforts of many, we will have a

world-class coal system.” ■

—Article submitted by Basin Electric Power Cooperative.

4. Ready for duty. The Wheatland Volunteer Fire Department is designated as the first

responder to all coal combustion events. Pictured here from the left are Kevin Brown, Bob Glas-

son, Barry Sishc, and Scott Scheller. Courtesy: Basin Electric Power Cooperative


FUEL SUPPLIES

Marooned: How Island Power Systems Keep the Lights On Largely dependent on imported fuel oil, many island systems must grapple

with soaring electricity costs and reliability issues, in part because they are isolated and they don’t benefit from economies of scale. But some nations are seeking alternatives.

Sonal Patel

It’s the same story all over the world. To

fuel their economies and support grow-

ing populations, geographically iso-

lated islands big and small procured fuel

oil generators and developed a dependence

on diesel delivery barges while crude was

relatively stable. But as oil prices soared—

hitting a record high in July 2008—nations

like the Marshall Islands, the Bahamas, Ja-

maica, and Mauritius were forced to declare

economic emergencies or admit that their

vulnerability to oil price and currency ex-

change fluctuations could prove economi-

cally devastating.

Fuel imports are generally blamed for

the exorbitant prices many islanders pay for

power, but experts also point to size—which

limits economies of scale—and the islands’

geographic isolation.

The U.S. territories face higher energy

costs than the rest of the nation, for exam-

ple. In those territories, the average resi-

dential rate for electricity is about $0.37/

kWh—about three times higher than the U.S.

national average cost of electricity. Com-

paratively, the Caribbean regional average is

$0.33/kWh, while Pacific island nations pay

between $0.28/kWh (Palau) and $0.48/kWh

(the Federated States of Micronesia).

Larger islands, which boast high elec-

trification rates, are often plagued by more

complex energy needs, as in Puerto Rico’s

case (see sidebar, “Drowning in Debt: Puerto

Rico’s Story”).

Renewables: An Obvious Choice, but Not Without ChallengesTo combat the high cost of electricity, a num-

ber of island nations or territories are seek-

ing alternatives. Because they are blessed

with solar, wind, biomass, and marine re-

sources but bereft of fossil fuels, making re-

newables a key component in island nation

power profiles would seem a given. There is

tremendous interest in adopting renewables.

Drowning in Debt: Puerto Rico’s Story

Puerto Rico is a striking example of an

island that almost went underwater finan-

cially because its electric utility was over-

loaded with debt stemming from high-cost

oil and old equipment.

Despite electricity rates that are more

than two times the national average

and higher than any U.S. state (except

Hawaii), the Puerto Rico Electric Power

Authority (PREPA) has racked up a $9 bil-

lion debt.

Experts say the situation stems from

years of negative cash flows that have

been made worse by the global recession

and the territory’s own fiscal crisis, which

can be attributed to a population and

economic decline. PREPA’s deficits are also

due in large part to its aging, outdated

generation facilities, poor customer bill

collection, and power theft. An inability

to access capital markets has, meanwhile,

rendered it unable to continue buying fuel

for its five main power plants (Figure 1).

On a bigger plane, the uncertainty sur-

rounding the high level of debt held by

PREPA (and other government entities)

has stalled much-needed private invest-

ment in the U.S. territory.

But things may be looking up. In Sep-

tember, PREPA reached an agreement with

a bondholder group to reduce its debt, as

a significant step toward restructuring.

Governor Alejandro Garcia Padilla hailed

the agreement as another measure to get

the liquidity needed to invest in the is-

land’s antiquated generation plants.

PREPA is also moving to save $200 mil-

lion to $400 million annually by stream-

lining fuel sourcing and by improving

customer service and safety.

One measure will see Siemens Energy

create a comprehensive, integrated re-

source plan (IRP) that addresses genera-

tion, transmission and distribution, and

fuel options.

Meanwhile, as a U.S. territory, Puerto

Rico still needs to comply with federal

environmental mandates. Eight of its 14

units subject to the Mercury and Air Tox-

ics Standards (MATS) comply with the rule,

but the territory’s environmental quality

board recently denied a requested one-

year extension for four units at the Palo

Seco and the San Juan plants. Puerto Rico

now plans to replace those units with

more efficient ones but notes that doing

so will require significant capital.

1. Pouring oil on troubled wa-ters. The Puerto Rico Electric Power

Authority (PREPA) produces power for its

1.4 million inhabitants on the main island

and on the adjacent Vieques and Culebra

islands. About 68% of its power, from

five main power plants, is oil-based; 15%

comes from liquefied natural gas; 15% is

from coal; and about 2% is from hydro. The

602-MW Palo Seco plant (shown here) was

built between 1960 and 1970 and burns

No. 6 fuel oil. Courtesy: PREPA


FUEL SUPPLIES

However, a number of obstacles limit their

widespread use.

The foremost reason is cost. Guam, for in-

stance, uses a hefty chunk of gross domestic

product to import fuel for transportation and

power needs and must rely on assistance to

build new projects. But as Esther Kia’aina,

assistant secretary for the Department of En-

ergy’s Insular Areas office, told lawmakers at

a congressional hearing this July, high-prior-

ity projects slated for some U.S. territories

must be supplemented with funding from the

Office of Insular Affairs’ capital improve-

ment program and technical assistance pro-

grams, and these “are already stretched thin.”

Notable federally funded projects include a

$1.8 million project to install a 1.2-MW solar

power system by the American Samoa Power

Authority and a $2 million wind turbine pilot

project in Guam.

Sometimes, renewables are kept at bay to

protect another sector. Hawaii, which spends

$5 billion on oil for its energy needs and suf-

fers the highest energy costs among the 50

states, first moved to integrate renewables

when the price of oil during the Arab oil em-

bargo in the early 1970s made dependence

on oil an economic liability. However, it took

more than 30 years for plans to become ac-

tionable policies.

“There was considerable inertia from Ha-

waii’s historic reliance and interdependence

on petroleum as the predominant fuel in all

sectors,” said Mark Glick, who is the state

energy administrator for the Department of

Business, Economic Development, and Tour-

ism. “This was due to the knowledge that

downward pressure on petroleum demand

in Hawaii’s small energy market would ad-

versely affect the delicate product balance

of the two local refiners supplying jet fuel,

gasoline, diesel, and low-sulfur fuel oil.”

The urgency for more energy security cre-

ated momentum for change. Today, Hawaii

has pledged to produce 30% of its power with

renewables by 2020, 70% by 2040, and 100%

by 2045. As of January 2015, the renewable

portfolio had topped 21%, way ahead of the

interim target of 15% (Figure 2).

Grid stability concerns also bar some

islands from installing larger-scale renew-

able projects. As some experts point out,

many island networks are aging, making

them prone to high system losses, and

the generating assets they depend on may

have been installed more than two decades

ago. The U.S. Department of Energy’s

March-released “Islands Playbook”—an

action-oriented guide (available at http://

goo.gl/CIq8OL) to successfully complete

a transition to an energy system that elim-

inates dependence on imported fuels—

recommends getting help from experts

to overcome integration challenges. That

document also highlights Hawaii’s prog-

ress on the distributed generation front

and regards its island system as a unique

laboratory for new solutions.

Hawaii leads the nation in the adoption

of distributed solar. While the national aver-

age is less than 1%, Oahu leads with 12%,

Maui has 10%, Hawaii Island has 9%, and

Kauai has 7.3%. “The result of this unprec-

edented growth in solar is that one-third, or

136 of Hawaiian Electric Co.’s 416 circuits

in Oahu are said to exceed 120% of daytime

minimum load, with 10% exceeding 250%,”

Glick said. “At 250%, that means that on any

given day, there is 2.5 times the amount of

electrical generation capacity on a circuit at

certain times of the day than the minimum

load requirements.”

Remember, Glick said, Hawaii’s grid is

isolated, which makes the rates of renewable

penetration even more impressive. “Conse-

quently, often at the firm prodding of the Ha-

waii Public Utilities Commission and other

energy stakeholders, Hawaii’s utilities have

had to act in real time to propose, deploy, and

confirm solutions for integrating such high

levels of renewables.”

Strategies deployed by the Hawaiian Elec-

tric Co. include testing and working on speci-

fications of “fast trip” inverter functionality to

avoid transient overvoltage events; computer

modeling each individual distribution circuit

to determine proactively the distributed gen-

eration resource’s “hosting capacity”; and

working with inverter manufacturers to bring

to market advanced inverter functionality to

manage voltage levels. “Planning of systemic

change,” energy efficiency, and demand re-

sponse are all also playing crucial roles with

respect to integration of more renewable en-

ergy, Glick noted.

Mulling the LNG OptionDiversification of island power portfolios

may also be achieved with the integration of

natural gas, the U.S. Energy Information Ad-

ministration (EIA) has suggested.

Liquefied natural gas (LNG), the EIA

noted in an August 2014 article, has not been

an option for many islands because it is typi-

cally shipped in bulk carriers in quantities

far too large for island economies to absorb.

And, LNG requires expensive regasification

and distribution infrastructure. However,

the development of standardized cryogenic

shipping containers means small amounts of

LNG can now be trucked, railed, and shipped

like other cargo. Once received by ship, the

LNG can be connected to portable regasifica-

tion units adjacent to electric power plants or

industrial facilities.

Puerto Rico and Hawaii are separately

testing the economics of small-scale LNG

imports, evaluating whether LNG prices jus-

tify switching away from diesel and residual

fuel oils.

But though the concept seemingly has the

backing of international financial institutions

like the International Development Bank, ex-

perts warn it has a glaring disadvantage: LNG

is currently slightly less expensive than diesel,

but it is much more price volatile. Also, LNG

prices are set regionally and are sensitive to

volumes under contract. That would mean

some islands may not be able to secure smaller

amounts of LNG at competitive prices.

Propane Power Sparks InterestFor a couple of islands, at least, propane has

2. Going renewable all the way. In 2014, 21% of the power used by customers of

Hawaiian electric companies came from renewable energy resources, including wind, solid

waste, geothermal, hydro, solar, and biofuel energy. The state wants to produce 100% of its

power from renewables by 2045. Source: POWER/Gail Reitenbach


FUEL SUPPLIES

proven the best alternative.

While the U.S. Virgin Islands is typically

recognized for its pristine white sands and

azure waters, the group of Caribbean islets

has become an energy trailblazer, particu-

larly among the U.S. territories.

In September 2011, wholly dependent on

fuel oil to generate power, and at the mercy

of wide fluctuations in fuel oil prices (in

2003, the price per barrel was about $22,

but by 2014 it was about $131), the U.S.

Virgin Islands, along with other U.S. terri-

tories, drew up an energy roadmap. Its goal:

Reduce dependence on fuel oil by 60% by

2025.

Within four years, the Virgin Islands Water

and Power Authority (WAPA) had achieved a

20% reduction in fossil fuel energy consump-

tion by implementing several renewable en-

ergy and energy efficiency initiatives. These

include 8.2 MW of solar through partner-

ships with Toshiba International Corp. and

Mainstreet Power Co. At least 9 MW of new

solar is in the pipeline, along with a 7-MW

anaerobic digester facility that will be built

by Tibbar Energy. The efforts have pushed

down residential power rates from $0.51/

kWh to about $0.33/kWh today.

However, it was WAPA’s deal with Swiss-

based, Dutch-owned multinational com-

pany VITOL Group in the summer of 2013

to convert all of its combustion turbines to

burn lower-cost and cleaner-burning lique-

fied petroleum gas (LPG) along with No. 2

fuel oil that has seemingly sparked the most

interest. The ambitious conversion of seven

General Electric turbines requires the instal-

lation of 18 propane storage tanks (Figure

3) along with infrastructure adjustments to

enable the safe transportation of LPG ves-

sels. It is expected to reduce WAPA’s fuel

costs by 30%.

According to WAPA Executive Director

Hugo V. Hodge Jr., the project has not been

without its challenges. Costs have increased

from $87 million to $150 million, owing to

a number of factors. During early phases of

the project, for example, adverse weather

posed delays, while undocumented soil

conditions and other underground obstacles

“presented unforeseen challenges,” he said

in a recent statement.

In spite of cost increases, the project has

become a model for the Caribbean region.

“For most Caribbean islands, converting to

the use of propane as the primary fuel source

for power generation represents the best,

near-term option to significantly reduce the

cost of fuel . . . while ensuring widespread

economic benefits,” Hodge said. “The entire

region is looking at WAPA’s project intently

to see how the model can be adapted in their

respective areas.”

The concept is making waves stateside,

too. Capstone Turbine Corp. in December

2011 installed 23 propane microturbines

on Catalina Island, 26 miles off the south-

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3. Propelled by propane. The U.S. Vir-

gin Islands, which was wholly dependent on

fuel oil just a few years ago, is moving to use

propane as the primary fuel source for power

generation. This image shows eight propane

storage tanks, which will eventually hold effec-

tive supply for about 19 days (10,400 cubic me-

ters), positioned for permanent installation on

St. Croix Island. Courtesy: U.S. Virgin Islands

Water and Power Authority


FUEL SUPPLIES

ern California coast. “What the Capstone

microturbines are doing for Southern Cali-

fornia Edison on Catalina Island is allowing

us to meet the island electrical demand and

frequency moment by moment, perfectly,”

said Ronald Hite, a Southern California

Edison district manager. What prompted the

switch from historically used diesel inter-

nal combustion engines are new air quality

standards, Hite explained. The new stan-

dards would have required the company to

install selective catalytic reduction (SCR)

units on the diesel engines, which then lim-

ited their output. “We needed to bring in

some form of generation that is quickly and

easily dispatched in small increments,” he

said. Propane is brought to the island twice

a week by barge that fills the storage tanks;

the propane is vaporized before it is fed to

the microturbines, Hite added.

Cleaner Diesel EnginesWhile change is clearly afoot on the island

scene (see sidebar, “Beyone Diesel”), diesel en-

gines aren’t going to fade into oblivion anytime

soon. They are the generator of choice for larger

installations.

Wärtsilä recently made a deal to extend

the six-unit Pockwood Pond Power Generat-

ing Station in the British Virgin Islands with

two gensets running on light fuel oil. When

completed in late 2016, the 50-MW plant

located on the main island of Tortola will

supply 100% of the British Virgin Island’s

electricity, including for its 11 islets (via sub-

marine cables).

Meanwhile, MAN Diesel & Turbo in June

2015 officially inaugurated a 210-MW engine-

operated power plant on the Caribbean island of

Guadeloupe for French utility EDF (Figure 4).

Since 2008, MAN Diesel has commis-

sioned similar plants (though on a smaller

18.5-MW scale) on La Réunion, Corsica,

and Martinique islands for EDF. The newly

inaugurated Point Jarry plant on Guadeloupe

Island isn’t your run-of-the-mill diesel in-

stallation, noted Dr. Hermann Kröger, head

of MAN’s power plants business unit, in a

statement. “The plant achieves a technical

and environmental standard that is seldom

seen in the field of diesel power stations,” he

said. “SCR catalytic converter technology

and urea injection deliver significantly re-

duced toxic emissions, while the dedicated

seawater desalination plant allows 700,000

tonnes of valuable drinking water to be

saved every year.”

Significantly, the plant will provide base-

load power to the island that is remarkably

outfitted with renewable installations. Wind,

geothermal, solar, and bagasse produce about

17% of the island’s total power. French law

requires EDF to buy power from any inter-

connected renewable generator, but owing

to concerns about grid stability and the vari-

ability of renewable sources, it restricts the

amount of wind and solar supplying the grid

at any given instant. For EDF, having backup

power is imperative. ■

—Sonal Patel is a POWER associate

editor.

Beyond Diesel

Here are some more innovative ways is-

landers are generating power while reject-

ing costly diesel imports:

■ Remote villages in the Pacific island na-

tions of Timor-Leste and the Solomon

Islands are using locally harvested and

processed coconut oil to fuel two Cat-

erpillar Olympian generators supplied

by Australian specialized Cat engine

dealer Energy Power Systems Australia

in 2013. Developers say a small system

can provide power with an average us-

age of only three coconuts per kWh—

with virtually no emissions.

■ The 11-MW Kaféate wind farm on the

Pacific island of New Caledonia has 42

Vergnet anti-cyclone wind turbines. In

the event of a cyclone, the tower can

be tilted and attached to the ground in

order to protect the turbine.

■ Kodiak Island (Figure 5) in southern

Alaska this May began producing 99.7%

of its power using only wind and hydro,

eliminating imports of about 3 million

gallons of diesel a year. The 28-MW is-

land system uses two 1.5-MW battery

systems to help manage intermitten-

cies. Plans are under way for a crane

upgrade at the port and for installation

of an ABB integrated commercial fly-

wheel technology to enable the addi-

tion of more renewable energy from an

expansion at the 9-MW wind farm.

■ Since 2009, the Réunion Island Univer-

sity, the Réunion Island Local Authori-

ties, and DCNS have worked toward the

deployment of ocean thermal energy

conversion (OTEC) technology in tropi-

cal regions by constructing a non-ex-

perimental OTEC plant in Réunion.

5. Microgrid. Kodiak Island, off Alaska’s

south coast, is the second-largest island in

the U.S. The Kodiak Electric Association, an

electric cooperative owned by the island’s

15,000 residents, has shunned costly die-

sel imports and designed a system that

uses only wind, hydro, and battery storage.

Courtesy: ABB

4. State-of-the-art diesel power. The 210-MW Pointe Jarry power station handed

over to French utility EDF by MAN Diesel & Turbo on the Caribbean Island of Guadeloupe this

June comprises a dozen 18V48/60 engines. It replaces a 30-year-old plant—cutting fuel con-

sumption by 15% and nitrogen oxide emissions by 85%—and is large enough to cover 45% of

the island’s energy needs. Courtesy: MAN Diesel & Turbo


PROJECT SITING

Turning Brownfields into Greenfields: From Coal to Clean Energy As the coal industry declines in many places around the world, can the mines

it leaves behind be repurposed for cleaner energy projects that benefit multiple stakeholders, including local economies? Several existing and planned projects demonstrate that there may be multiple paths toward that transition.

Lee Buchsbaum

No question, the coal industry in Ap-

palachia, the rest of the U.S., and

much of the developed world is go-

ing through massive structural changes. As

mines close and regulators and citizens take

stock of their legacy, people are wondering

what’s next for the coalfields. Beyond at-

tempting to restore scarred lands to their

“approximate original contours,” as required

by U.S. federal law, there may be another ap-

proach, one that could provide lasting value

to mining companies, landowners, residents,

and other stakeholders.

Thousands of acres of once-abandoned

mines are now wildlife preserves or slow-

ly reviving parklands, but can mined land

be put to economic use? With the help of

a relatively new and little-known Environ-

mental Protection Agency (EPA) initiative,

“RE-Powering America’s Land,” transi-

tional assistance for taking brownfields to

greenfields is now available. Borrowing

from lessons learned at sites across the U.S.

and Europe, the EPA is trying to jumpstart

new clean energy projects at abandoned and

closing mines throughout economically dis-

tressed coal country.

Meanwhile, as the timeline for President

Obama’s Clean Power Plan (CPP) moves

forward, the distress in Appalachia might be

leading to new experiments in carbon credit

bundling, which could provide a model for

coal burners on how to generate electricity

while staying beneath limits set by the CPP.

Front and center is a proposal by the non-

profit Virginia Conservation Legacy Fund

Inc. to purchase thousands of acres of for-

mer mined lands from the now-bankrupt Pa-

triot Coal, along with several active mines,

and plant millions of trees as carbon offsets

to be sold along with future coal production.

The scheme, approved by the West Virginia

Department of Environmental Protection on

October 6, would also jump-start remedia-

tion and reclamation on dozens of old mine

sites throughout the East while keeping hun-

dreds of coal miners employed. The agree-

ment remains subject to bankruptcy court

approval, expected by the end of October.

The Greening of Lignite in GermanyWorldwide, there already are numerous ex-

amples of solar and wind power installations

on former mine lands, especially in Germany,

which earlier this century began decarboniz-

ing its economy.

One of the first brownfield to green-

field redevelopments, the Leipziger Solar

Power Plant, was installed upon 49 acres

of a former lignite mine site in Espenhain,

Germany. Initially, the 5-MW photovoltaic

power plant was made up of 33,500 solar

modules feeding directly into the German

electricity grid. The project, which has op-

erated since 2004, was initiated and devel-

oped by the energy company GEOSOL for

$26.5 million. The Espenhain site, located

near Leipzig, was a former settling area

for lignite or “brown coal” ash and dust.

Based on this prior use and the amount of

contamination at the settling area, the site

did not offer many traditional reuse or re-

development options. However, a solar

energy plant was an option, but only after

on-site contamination was remediated. At

the Espenhain site, the lignite waste had to

first be buried under a foot of soil before

custom-built supports for the solar panels

could be installed.

A similar project nearby is the 3.4-MW

Borna Solar Plant, installed at a cost of $28

million on the site of a factory that had pro-

duced lignite briquettes (Figure 1).

Building upon the success of these and

similar conversions, in 2012 a consortium of

Chinese and German firms converted part of

another former lignite strip mine into a so-

lar power plant. Working with the German

firm Energiebauern, the Chinese company

JinkoSolar supplied 5.7 MW of solar mod-

ules to the new 11.6-MW solar power station

in Starkenberg, Thuringia. Constructed by

Energiebauern, the solar power station is lo-

cated on an abandoned strip mine in the south

of Starkenberg and is the largest project of its

kind in that German state.

1. From coal to sol. Borna Solar PV Park

generates 3.5 million kWh annually on a site

in Germany previously used to manufacture

lignite briquettes. Source: GEOSOL/EPA


PROJECT SITING

Huge Potential for RE-Powering AmericaThroughout the U.S., according to the Gov-

ernment Accountability Office, there are be-

tween 80,000 and 250,000 similar abandoned

mine lands (AMLs) pock-marking the land-

scape. AMLs include abandoned mines and

the areas adjacent to or affected by the mines.

Because of safety or environmental concerns,

the majority of these sites have never been

considered for any type of reuse and have re-

mained idle.

AML sites are often in rural or remote

areas that may not be well-suited for more

traditional commercial or industrial reuse op-

portunities. Quite a few are “pre-law” sites

not subject to the Surface Mining Control

and Reclamation Act of 1977 and/or are not

former coal mines. Because of this, the land

often sits fallow or has become de facto na-

ture or hunting preserves. And few companies

or entities would ever seriously consider tak-

ing on the remediation costs associated with

redevelopment. Indeed, the land essentially

becomes a ward of the state, often leaching

toxins into the environment with little over-

sight. Struggling agencies barely have the

resources to adequately clean up these areas.

And now, following the disaster at the Gold

King Mine in southwestern Colorado earlier

this year, you can bet any group currently in-

volved in remediation work is reevaluating

its plans.

But if stakeholders are able to think out-

side the box and look forward, there are

some real benefits inherent in transform-

ing these blighted areas. Many of these

sites can take advantage of local renewable

resource attributes to produce power while

returning the land to productive use. As

part of its RE-Powering America initiative,

the EPA has identified renewable energy

development at mining sites as a priority

for the agency’s reuse-related activities at

contaminated sites. The initiative identifies

brownfields, Resource Conservation and

Recovery Act, Superfund, and mining sites

for their wind, solar, and biomass devel-

opment potential and provides other use-

ful resources for communities, developers,

industry, state and local governments, or

anyone interested in reusing these sites for

renewable energy development. The EPA

supports the reuse of former mine lands

through the Superfund Redevelopment

Initiative (SRI).

Working in collaboration with the Na-

tional Renewable Energy Laboratory, the

RE-Powering Initiative has propelled renew-

able energy development on contaminated

lands from merely an intriguing notion to an

ever-increasing portfolio of viable projects.

According to the EPA, since the initiative’s

inception in 2008, more than 150 renewable

energy installations on 144 contaminated

lands, landfills, and mine sites have been

established throughout 35 states and terri-

tories, representing a combined 1,046 MW

of capacity—not a huge amount of power,

but not bad for a relatively obscure project

within a very thinly stretched agency.

Of course, the EPA doesn’t site renewable

energy projects but directly and indirectly

supports cleanup of contaminated properties

where such sites could be developed. Reme-

diating contaminated sites and determining

their eventual reuses results from the efforts

of a diverse set of stakeholders including

communities, developers, states, tribes, local

government, and the financial community.

Siting AdvantagesAs noted above, AMLs often are excellent

locations for solar energy and wind produc-

tion facilities. Many abandoned mining sites

are located in the western and southwestern

U.S., in areas that have abundant available

sunlight (300+ days a year). However, states

like Pennsylvania are also demonstrating

2. Where the wind blows and the antelope roam. A 66-turbine wind farm rated

at 99 MW near Glenrock, Wyo., now generates renewable energy where the Dave Johnston

Coal Mine once sat (see next figure). Courtesy: PacifiCorp


PROJECT SITING

the viability of renewables facilities on the

East Coast.

Additionally, utility-scale solar energy

projects require access to large, open sites,

and the size of many AMLs means that large

solar arrays can be accommodated at a single

property.

Precisely because of their history as indus-

trial sites, many AMLs are located near exist-

ing infrastructure, including roads and power

transmission lines, which can reduce project

costs. However, many are also situated in re-

mote areas with limited electricity infrastruc-

ture; those sites are well suited for using solar

energy for onsite cleanup and reclamation

activities, such as to power a groundwater

pump and treatment system.

U.S. Examples of Repurposed SitesTo be fair, several power producers moved

ahead long before the EPA did to engage in

green power redevelopment. One of the first

projects was a large windfarm installed by

PacifiCorp in 2008. Today, 66 wind turbines

near the hamlet of Glenrock, Wyo., with a

nameplate capacity of 99 MW, generate re-

newable power on land that Warren Buffet’s

Berkshire Hathaway–owned PacifiCorp re-

tired and reclaimed from surface coal mining

operations (Figure 2). Perhaps the first wind

facility in the West to recycle fossil fuel–pro-

ducing land for green energy generation, the

300 acres upon which the Glenrock turbines

stand were part of the 14,000-acre Dave

Johnston Mine (Figure 3) that produced 104

million tons of subbituminous coal between

1958 and 2000. The surface mine operation

fueled PacifiCorp’s neighboring Dave John-

ston Plant—still one of the largest coal-fired

power plants in the West.

Back East, from 2000 through 2004 the

Tennessee Valley Authority installed 18 wind

turbines on a former strip mine in Tennessee.

The Buffalo Mountain project, visible for

miles, supplies clean energy to roughly 3,400

homes annually.

Around the same time as Buffalo Moun-

tain went into service, to the north, the Cas-

selman Wind Power Project in Somerset

County, Pennsylvania, started generating

upon another closed surface mine (Figure

4). Eight of Casselman’s 23 wind turbines sit

atop a reclaimed strip mine. Developed and

owned by Iberdrola Renewables, collectively

the wind power project can generate up to

34.5 MW. In addition, the former mining site

hosts the wind farm’s operation center, col-

lector transformer, and interconnection facil-

ity. While the project spans approximately

2,000 acres, the actual footprint is less than

2% of the total acreage.

On the solar side, with help from the EPA’s

initiative, a 43-acre solar farm is now gen-

erating power at a former Superfund site in

Indiana, making it the nation’s largest solar

farm yet built on a Superfund site. Made up

of 36,000 solar panels, the Maywood Solar

Farm started producing power last year. The

EPA touts it as one of 85 renewable energy

projects that the agency has helped install

on Superfund sites, landfills, and old mining

sites nationwide. In this case, the solar farm

is on the site of a former coal tar refinery

plant, which dealt with hazardous chemicals

until its closing in 1972. In the 1980s offi-

cials found that the groundwater underneath

the site was contaminated with benzene and

ammonia; afterwards, the area was desig-

nated a Superfund site. “This innovative so-

lar project demonstrates that Superfund sites

can be redeveloped,” EPA Regional Admin-

istrator Susan Hedman said in a statement.

“The Maywood Solar Farm project has trans-

formed a site with a long history of contami-

nation into a source of renewable energy.” At

the end of the day, it’s a great step forward

upon an otherwise nearly dead landscape.

Tree-Hugger Plan Promises to Protect Coal Mining, Miners, and EnvironmentLong the sickest man in the room, Patriot

Coal has gone through bankruptcy proceed-

ings twice in the past two years. Perhaps

designed to fail from the outset (see “The

Shifting Fates of Coal Markets, Coal Mining,

and Coal Power” in the October issue), the

metallurgical coal boom that started before

the 2008 recession boosted the company’s

fortunes as investors financed expansions to

tap met coal reserves. With the collapse of all

coal prices, Patriot has been on the proverbial

down-bound train ever since.

In June, Patriot agreed to sell the majority

of its remaining mines to Blackhawk Min-

ing. However, a smaller chunk of Patriot’s

coal-producing assets—including several

operating mines, millions of dollars of envi-

ronmental liabilities, and dozens of old mine

permits—may be transferred to a newly cre-

ated subsidiary of the nonprofit Virginia

Conservation Legacy Fund (VCLF) as part

of a scheme to plant hundreds of thousands

of trees and bundle carbon credits into the

sales of several million tons of new coal

production.

As noted earlier, the plan has received en-

vironmental department approval but awaits

bankruptcy court approval. As envisioned

by CEO Tom Clarke and the rest of VCLF’s

management team, planting trees and reaping

the carbon credits may be one path forward

for all coal companies—many of which are

3. Dave Johnston Coal Mine, 1993. Source: Office of Surface Mining

Reclamation and Enforcement, U.S. Depart-

ment of the Interior

4. Still providing energy. Roughly a third of the Casselman Wind Power Project tur-

bines in Somerset County, Penn., sit atop a former surface coal mine. Courtesy: Iberdrola Re-

newables


PROJECT SITING

also huge landholders with millions of trees

on their property.

Through its affiliate, ERP Compliant

Fuels LLC (ERP), VCLF, its manage-

ment, and other shareholders have sought

and been granted provisional regulatory

approval to receive 153 mining permits

from Patriot while purchasing other re-

lated equipment, processing facilities, and

collateral. VCLF’s goal is to help restore

Appalachian communities through active

mining, land reclamation, and water qual-

ity improvement. ERP will also assume

all of Patriot’s Workers Compensation and

state black lung obligations, estimated to

be as much as $109 million. ERP proposes

to grant significant equity ownership of the

new company to the United Mine Workers

of America to support their pension and re-

tiree health benefits.

With the acquired Patriot assets, ERP

would operate the established Federal Min-

ing Complex in northern West Virginia,

which has the capacity to produce over 4

million tons of thermal coal annually. It

will also take over the Corridor G facility

in southern West Virginia. VCLF says it will

reclaim land and improve water quality in

West Virginia, Ohio, Illinois, Kentucky,

Pennsylvania, and Indiana.

Can Trees Save Coal?VCLF is committed to the so-called “forestry

reclamation approach,” creating economic

opportunities for Appalachian communities.

Here’s how it works. VCLF supporter Green-

Trees from The Plains, Virginia, has planted

more than 36 million trees on over 100,000

acres of land in the Mississippi Alluvial Del-

ta, sequestering over 12 million metric tons

of carbon dioxide (CO2) and, thus, creating

saleable carbon credits. GreenTrees accounts

for over 90% of the reforestation carbon

credits registered to date by the American

Carbon Registry. ERP intends to sell “com-

pliant fuels,” which bundle carbon credits

with coal sales to produce a “compliance

instrument,” effectively reducing CO2 emis-

sions. The compliant fuels market is expect-

ed to increase under the recent EPA emission

standards required by the CPP.

As part of the acquisition, ERP will main-

tain 683 jobs in West Virginia through the

operation of the Federal mine and its forestry

reclamation activities. VCLF already con-

trols over 30,000 acres of conservation land,

including the Natural Bridge of Virginia, and

provides “environmental management ser-

vices” at 459 coal mining and water quality

sites in five states.

VCLF/ERP would also potentially as-

sume liability of more than $400 million in

connection with Patriot’s workers’ compen-

sation, state black lung, and environmental

obligations. In addition, VCLF/ERP would

assume or replace surety bonds supporting

reclamation and related liabilities associ-

ated with the purchased assets. “In VCLF,

we have found an experienced partner who

will responsibly manage our remaining as-

sets consistent with the highest environmen-

tal standards and we believe this proposed

transaction is in the best interest of Patriot

and its stakeholders,” Patriot Coal President

and CEO Bob Bennett said.

VCLF’s Clarke—who billed the court’s

initial agreement as a landmark achievement

for the fund, Appalachia, and the entire coal

industry—stated that VCLF expected to

maintain employment in West Virginia at

current levels and expand as it invests up

to $176 million in land reclamation, refor-

estation, and water-quality improvements.

“Continued mining at [the Federal Min-

ing Complex] will allow us to launch our

‘compliant fuel’ program, which bundles

reforestation carbon credits with coal sales,

effectively reducing CO2 emissions, as re-

quired under the new emission standards,”

Clarke outlined.

According to a rather skeptical report

published by InsideClimate News, to off-

set the carbon emissions from burning

coal, Clarke plans to plant trees both on

the mine property and elsewhere in Appa-

lachia. (Note that Clarke’s plan isn’t the

only effort to plant trees on former mining

sites; see Figure 5.) He will then bundle

the carbon credits from planting trees with

the coal and sell it to utilities for a profit.

“We inset the carbon with the coal and so

when the train arrives at the power station,

it also has cancelled [carbon credit] certifi-

cates,” said Clarke. “We’re creating a new

product.” The carbon credits are supposed

to account for about 30% of the emissions

from burning the coal.

Seemingly controversial and outland-

ish, Clarke’s plan isn’t altogether new.

Renewable energy credits are sometimes

sold bundled with the underlying energy

source. But what’s radically unique is that

it comes from someone who claims to be

a climate activist who also wants to keep

coal mines open.

Clarke contends that environmental

groups have to be directly involved in the

coal market. By selling coal and doing it in

a way that reduces carbon emissions, it will

push the market to use cleaner fuel sources,

he said. “We’ve got to do everything,” Clarke

5. A new beginning. Seedlings such

as this one on a former coal mining site near

Hazard, Ky., are among 100,000 bee-friendly

native Appalachian trees planted on 500

acres since 2008 in coordination with the Ap-

palachian Regional Reforestation Initiative to

produce pollen and nectar favorable for estab-

lishing a honeybee industry in Eastern Ken-

tucky. Courtesy: The Lane Report

Clarke’s plan isn’t altogether new. Re-newable energy credits are sometimes sold bundled with the underlying energy source. But what’s radically unique is that it comes from someone who claims to be a climate activist who also wants to keep coal mines open.


PROJECT SITING

insisted. “We’ve got to push all of the solu-

tions simultaneously . . . We have to take bold

risks.” The plan will also keep jobs in the

region and help the Appalachian economy

slowly transition away from coal dependency

while helping push the area toward more of a

restoration economy.

Innovation or Smoke and Mirrors?Environmentalists are confused by Clarke

and his intentions. Earlier this year, he

became involved with another troubled

mining giant, Southern Coal. Led by the

billionaire Jim Justice, who is running for

West Virginia’s governorship, Southern

is facing millions of dollars in fines for

health, safety, and environmental viola-

tions, as well as lawsuits by former em-

ployees alleging they had been unfairly

fired. Clarke initially mounted a very pub-

lic campaign against the company but later

decided to join Justice’s company as an

unpaid consultant to create a compliance

strategy. The success of this new partner-

ship is still questionable, as are Clarke’s

loyalties, apparently.

Another significant question is whether

utilities can actually use Clarke’s coal to ful-

fill their requirements under the CPP. If the

EPA disallows a compliance strategy based

on attaching carbon credits to fossil fuels,

utilities would lose any incentive to purchase

coal from Clarke.

“Approval of this ‘compliant fuel’ strat-

egy is likely to be a difficult challenge,” said

Ken Colburn, head of U.S. operations at the

Regulatory Assistance Project, a nonprofit

that provides technical assistance on energy

and environment issues. The regulations re-

quire utilities to reduce emissions from pow-

er plants. Offsetting emissions elsewhere by

planting trees won’t meet the requirements of

the rule, Colburn said. “The trees would be

reducing the amount of carbon in the atmo-

sphere, but not the amount emitted from the

power sector,” he explained. That said, be-

cause individual states can create their own

CPP compliance plans, it’s possible West

Virginia and other coal-dependent states can

create a carve-out exemption favorable to

these types of credits.

In defense of this plan, Clarke said his

group is already in talks with a Virginia-

based power station that emits about 6

million tons of CO2 a year. If a deal is fi-

nalized, Clarke’s group will offset about 2

million tons of CO2 by planting hundreds of

millions of trees.

“Whether environmental groups realize it

or not, this is a major way to help solve this

issue,” said Chandler Van Voorhis, managing

partner of GreenTrees. “It’s a powerful way

to deal with carbon emissions.” But it will

likely meet resistance from environmental

groups that see defeating coal as a top prior-

ity. “The Sierra Club doesn’t like it because

they want power companies to invest in solar

and wind,” Clarke said. “We believe coal is

still going to play a role.”

Beyond whatever happens with Patriot,

Clarke and the VCLF have substantial land

holdings and partners with holdings of their

own. Between them, they control a slew of

wild and planted forests whose CO2 seques-

tering ability can already be monetized. For

an estimated 10% increase in cost, VCLF’s

new coal production would come bundled

with credits, equal to about 30% of the com-

bustion emissions, already paid for. “The

tree is the answer, it really is the answer,”

Clarke said. ■

—Lee Buchsbaum (www.lmbphotography.com), a former editor and contributor to

Coal Age, Mining, and EnergyBiz, has covered coal and other industrial subjects

for nearly 20 years and is a seasoned industrial photographer.

UDI Who’s Who at

Electric Power PlantsFor more detailed information and a list of all available data,

visit us online at UDIDATA.COM or contact the UDI Editorial

team at [email protected].

The 2014 UDI Who’s Who Directory covers more

than 4,500 U.S. and Canadian generating plants.

The directory provides:

• Nearly 8,100 plant management and support contact names, titles, and primary job functions.

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Generation (MWh)

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• Power plant design characteristics

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NUCLEAR TECHNOLOGY

On the Nuclear Frontier: New Designs Aim to Replace LWRsGeneration III nuclear reactors have not shown much ability to overcome the

weaknesses of conventional Gen-II light-water reactor technology, offering at best evolutionary approaches. Is there room for a more revolutionary approach? Many parties are exploring new technologies, but it’s impos-sible to tell which, if any, will succeed.

Kennedy Maize

Last August, Andy Revkin, The New York

Times’s “Dot Earth” blogger, waxed en-

thusiastic about a new fusion reactor de-

sign from a team of students and researchers

at the Massachusetts Institute of Technology

(MIT). Revkin reported (based mostly on the

MIT press release) that the team had come

up with a plan for a “demonstration-scale fu-

sion energy power plant that could actually

produce a fusion energy machine that is af-

fordable, robust, compact.”

MIT claimed that the new design takes the

long-disappointing “tokomak” donut-shaped

fusion reactor and shrinks it with new ma-

terials. This would allow the use of a much

higher magnetic flux to contain the super-

hot plasma needed to fuse hydrogen atoms,

which would produce heat far exceeding

any conventional fission reactors, yet with a

much smaller footprint. The hype suggested

a 10-year time frame.

Despite the credulous coverage of MIT’s

dream machine, there are important skeptics,

many of whom note that fusion is a tech-

nology whose horizon has receded despite

years of research and billions of dollars of

government investment. Robert Hirsch, who

ran the fusion program for the Atomic En-

ergy Commission (AEC, the predecessor

of the Nuclear Regulatory Commission)

and the Energy Research and Development

Administration in the 1970s, told POWER,

“Higher magnetic field tokamaks have

been around since the early 1970s, but high

magnetic fields contain high stored energy,

which can be released when [superconduct-

ing] magnets quench, which the regulators

will be very sensitive to.” Magnet quench-

ing—abrupt termination of the magnetic

field—can result in destructive forces inside

the machine and considerable damage.

The MIT reactor design, which MIT is

calling the ARC (Figure 1), hits all the proper

notes to attract attention: small, modular, and

efficient. But it’s just one of a number of “new”

(actually mostly old but previously discarded)

reactor models various engineers and entre-

preneurs are advancing as the solutions to the

well-known woes of conventional, large-scale

light-water reactors (LWRs).

A Nuclear Gen-XCall them “Gen-Next” reactors, as they do

away with the conventional numerical no-

menclature of Gen-I (small, early plants

such as Indian Point I in New York, now long

closed), Gen-II (most of the large plants or-

dered in the 1970s and operating today), and

Gen-III (today’s designs, such as the West-

inghouse AP1000 and AREVA’s EPR, under

construction but not yet operating). Gen-IV,

the industry’s label for advances over Gen-

III designs, implies more of the same, while

Gen-Next implies radically different ap-

proaches, with much promise and plenty of

risk (see sidebar).

Earlier conventional reactor designs are

being phased out. The Gen-Is are gone.

Many Gen-IIs are nearing retirement. But

Gen-IIIs have not met stated goals for plants

that are cheaper and easier to build, feature

much greater standardization, and offer

modular construction advantages over the

prior generation.

Investment portfolio manager Henry Hewitt

wrote in Greentech Media recently that Gen-

III reactors “have been a disappointment.”

None are currently operational, and many of

the plants under construction have seen delays

and budget overruns—some of them huge, as

with the EPR. The latest World Nuclear Indus-

try Status Report (a publication that is skepti-

cal of nuclear power) attributes these delays,

including those at the four Westinghouse units

under construction in the U.S., to “design is-

sues, shortage of skilled labor, quality control

issues, supply chain issues, poor planning ei-

ther by the utility and/or equipment suppliers,

and shortage of finance.”

Those looking to nuclear power as a long-

term component of a plan to limit carbon di-

oxide emissions have for more than a decade

been examining and touting new generations

of nuclear concepts that escape the limits of

the LWR (see “Nuclear Industry Pursues

New Fuel Designs and Technologies” in the

March 2015 issue). These new technologies

include designs that rely on thermal (slow)

neutrons, fast neutron breeder reactors,

various cooling approaches, higher-temper-

ature machines that are more efficient, and

the ability to burn spent nuclear fuel from

those conventional LWRs, which look to be

around for a very long time.

Salt of the EarthThe most recent leader of the Gen-Next hit

parade is the molten salt reactor. As is the

case with the small, modular fusion project,

a revival of this design is also under way at

MIT. Nuclear scientists Leslie Dewan and

Mark Massie are designing what they call

the “Waste-Annihilating Molten Salt Reac-

tor” (Figure 3). Starting with designs origi-

nated at Oak Ridge National Laboratory in

the 1950s and 1960s, Dewan and Massie are

developing plans for a liquid-fueled reactor

that overcomes some of the problems with

the 7.5-MW Oak Ridge plant that operated

from 1966 until 1969, when the money ran

out. Their design also addresses important

current problems with LWR plants.

MIT’s Dewan and Massie have formed a

1. Pocket powerhouse? This fusion re-

actor design from the Massachusetts Institute

of Technology (MIT) promises larger power

through a smaller footprint. Courtesy: MIT


NUCLEAR TECHNOLOGY

company, Transatomic Power, to commercialize

their concepts. They have raised $6 million in

venture capital so far. Unlike the old Oak Ridge

reactor—championed by nuclear power found-

ing father Alvin Weinberg (1915–2006)—their

design does not use fast neutrons in order to

breed plutonium. It is a thermal device, with the

fuel in suspension in the coolant, a key feature

of Weinberg’s Oak Ridge machine. According

to their website (transatomicpower.com), the

fuel can be either “fresh” (unenriched) uranium

or spent fuel, unlike the 33%-enriched ura-

nium in the Oak Ridge prototype. The devel-

opers claim that the “main technical change”

they have made from the Oak Ridge days “is

to change the moderator and fuel salt used in

previous molten salt reactors to a zirconium hy-

dride moderator, with a LiF [lithium fluoride]-

based fuel salt.”

This machine, according to its MIT devel-

opers, can run on spent fuel, can burn up as

much as 96% of the energy in the fuel, and

should provide exceptional safety. It avoids

the intense radiation damage from fast neu-

trons. If the plant loses all of its electric

power, a phenomenon known as “station

blackout” (such as what occurred at Fuku-

shima), the fuel drains into a tank and freezes

solid. There can be no meltdown.

But there are tough challenges to overcome,

particularly handling the highly corrosive

molten salt, which carries the fuel, serves as

the moderator, and cools the reactor. Licens-

ing will be a problem in the U.S. because of

the novelty of the design. The reactors could

require on-site chemical plants to deal with the

coolant and fuel mixture. Nor are the econom-

ics of the technology at all clear.

The WaveIn 2006, multi-billionaire Microsoft founder

Bill Gates and former Microsoft chief strate-

gist Nathan Myhrvold concluded that raising

living standards globally—including provid-

ing access to electric power to all—requires

the private sector to step into the action. They

founded Intellectual Ventures, located in Bel-

levue, Wash., to come up with ideas for re-

ducing global poverty. Two years later, they

spun off a new company, TerraPower, to fo-

cus on a new approach to an old, largely un-

successful, nuclear technology: fast breeder

reactors, which generate electricity while

producing more plutonium fuel than they

consume from natural uranium and fast (un-

moderated) neutrons.

TerraPower’s wrinkle on breeders was

called the “traveling wave reactor” (TWR)

first proposed in the 1950s, according to the

Alvin Weinberg Foundation. It was a sodi-

um-cooled fast breeder design to burn the

plutonium it breeds internally from conven-

tional spent reactor fuel, without the need for

plutonium reprocessing. That’s a big techni-

cal, economic, and environmental advantage.

Nuclear reprocessing is fraught with prob-

lems, including diversion of plutonium from

civilian reactor fuel into atomic weapons.

An article in MIT’s Technology Review

reported, “As it runs, the core in a traveling-

wave reactor gradually converts nonfissile

material into the fuel it needs.” Another de-

scription, from ZDNet, likened it to a candle,

burning from one end to the other.

The technology got a lot of hype. New York

Times reporter Matthew Wald (who wrote the

Technology Review article and now works for

the Nuclear Energy Institute), wrote that Ter-

raPower’s idea could answer the quest “for a

new kind of nuclear reactor that would be fu-

eled by today’s nuclear waste, supply all the

electricity in the United States for the next

800 years and, possibly, cut the risk of nucle-

ar weapons proliferation around the world.”

It was an intriguing concept. But Terra-

Power soon abandoned the traveling wave

in the face of an engineering conundrum.

The reactor’s liquid sodium cooling system

had to follow the wave, a very tricky task.

Instead, TerraPower changed the design so

the uranium-plutonium conversion does not

move. “It’s just the practical considerations

associated with making the most of every

neutron, and the engineers’ love of keep-

ing the cooling system in one place and not

chasing the wave,” TerraPower’s CEO John

Gilleland told Weinberg Foundation blogger

Mark Halper. TerraPower continues to call its

machine the traveling wave reactor, although

now it’s more of a standing wave. The com-

pany says it hopes to achieve startup of a

600-MW prototype TWR in the mid-2020s.

TerraPower’s move away from its origi-

nal technology recognized the problems with

liquid sodium coolant. While it has excellent

heat transfer properties, it also has a tendency

to leak and come into contact with air and wa-

ter. When that happens, it can spontaneously

ignite in a wild reaction. That’s a real prob-

The Fabulous Flying Fusion Machine

Last summer, a team of Boeing engineers

got a U.S. patent for a laser-fusion-powered

aircraft engine. The conceptual design (Pat-

ent No. US 9,068,562 B1) has high-power

lasers aimed at a target of deuterium and

tritium, a simplified concept similar to the

much larger research on laser fusion under

way at the Department of Energy’s National

Ignition Facility at Lawrence Livermore Na-

tional Laboratory in California.

In the Boeing patent, the lasers cause

the hydrogen isotopes to fuse into he-

lium, producing a thermonuclear explo-

sion (Figure 2). As described by Business

Insider, the helium and hydrogen by-

products shoot out of the back of the

engine at enormous pressure, yielding

thrust. The inside of the “thrust cham-

ber,” coated in natural uranium (mostly

U238), reacts with the neutrons from the

thermonuclear reaction, generating im-

mense heat.

Coolant flowing along the outside of

the combustion chamber captures the heat

and is sent through a turbine generator to

produce electricity to power the engine’s

lasers. According to the patent application,

the engine could power rockets, missiles,

and spacecraft.

Fusion expert Robert Hirsch was dismis-

sive of the design. He told POWER that

Lawrence Livermore “seems to have failed

to ignite pellets, and a laser to do the

suggested job at the needed energies isn’t

even on anyone’s drawing board, as far as

I know. But you never know, so you sub-

mit a patent.”

“As of now, the engine lives only in pat-

ent documents,” notes Business Insider.

2. A flying reactor? Boeing engineers

have received a patent for this concept for

a fusion-powered jet engine. Courtesy:

Boeing

3. Salty prospect. Experimental reac-

tors using molten salt as a coolant and fuel

carrier have been around since the 1960s, but

new designs hope to overcome past prob-

lems. Courtesy: Transatomic Power


NUCLEAR TECHNOLOGY

lem, because sodium fires are very difficult to fight. They create caustic

fumes, release explosive hydrogen, and can’t be quenched with water or

CO2. Breeders in operation in the world so far have had serious sodium

coolant problems.

TerraPower has broadened its interests in Gen-Next nuclear, in-

cluding looking at molten salt reactors.

On Sept. 22, the company announced a memorandum of under-

standing with China National Nuclear Corp. (CNNC). A press release

sent to POWER said that “The two companies plan to work together to

complete the traveling wave reactor (TWR) design and commercial-

ize TWR technology. Cooperation between TerraPower and CNNC

will speed technology development, promote clean energy growth,

and enable global economic growth in both countries” (Figure 4).

AstridBreeder reactors remain the nuclear Holy Grail for many plant devel-

opers, despite the mixed record of earlier generations, because they

offer an endless supply of fuel generated by transmuting uranium into

plutonium. Among various projects, the most advanced appears to be

Astrid (Advanced Sodium Technological Reactor for Industrial Dem-

onstration), a sodium-cooled fast breeder project led by the French

government’s energy research agency CEA, working with AREVA,

Electricité de France, and Toshiba.

Japan and France, countries with few indigenous energy resources,

have long seen breeder reactors and plutonium reprocessing as the

path to greater energy independence. But the breeder programs in both

countries have had problems. France’s Superphenix reactor closed in

1998 after serious engineering problems with the liquid sodium cool-

4. Traveling wave reactor design traveling the world. In September, Bellevue, Wash.–based TerraPower announced it had

signed a memorandum of understanding with China National Nuclear

Corp. to complete the design and commercialize the new form of nu-

clear technology. Courtesy: TerraPower

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Statement of Ownership, Management, and Circulation (Requester Publications Only) 1. Publication Title: POWER 2. Publication Number: 0032-5929 3. Filing Date: 9/30/15 4. Issue Frequency: Monthly 5. Number of Issues Published Annually: 12 6. Annual Sub-scription Price &107. Complete Mailing Address of Known OfÞce of Publication: Access Intelligence, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 Contact: George Severine Telephone: 301-354-1706 8. Complete Mailing Address of Headquarters or General Business OfÞce Publisher: Access Intelligence, NNC, 4 Choke Cherry Road, 2nd Floor, Rock-ville, MD 20850-4024 9. Full Names and Complete Mailing Addresses of Publisher, Editor, and Managing Editor: Publisher: Matt Grant, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 Editor: Gail Reitenbach, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 10. Owner if the publication is owned by a corporation, give the name and ad-dress of the corporation immediately followed by the names and addresses of all stockholders owning or holding 1 percent or more of the total amount of stock: Veronis Suhler Stevenson, 55 East 52nd Street, 33rd Floor, New York, NY 10055 11. Known Bondholders, Mortgagees, and Other Security Holders Owning or Holding 1 Percent or More of Total Amount of Bonds, Mortgages, or other Securities: None 12. Non-proÞt organi¦ation: not applicable. 13. Publica-tion: POWER 14. Issue Date for Circulation Data: September 2015. Average No. of No. Copies of 15. Extent and Nature of Circulation: Copies Each Issue Single issue During Preceding Nearest to 12 Months Filing Datea. Total Number of Copies (Net press run) 45,585 46,093b. Negitimate Paid and/or Requested Distribution (1) Outside County Paid/Requested Mail Subscriptions 40,073 40,480 (2) Inside County Paid/Requested Mail Subscriptions 0 0 (3) Sales Through Dealers and Carriers, Street Vendors, 2,479 2,195 and Other Paid or Requested Distribution Outside USPS (4) Requested Copies Distributed by Other Mail Classes 0 0c. Total Paid and/or Requested Circulation 42,552 42,675d. Nonrequested Distribution (By Mail and Outside the Mail) (1) Outside County Nonrequested Copies 1,208 1,193 (2) Inside-County Nonrequested Copies 0 0 (3) Nonrequested Copies Distributed Through the USPS by Other Classes of Mail 0 0 (4) Nonrequested Copies Distributed Outside the Mail (Include Pickup Stands, Trade Shows, Showrooms, and Other Sources) 851 756e. Total Norequested Distribution 2,059 1,949f. Total Distribution (Sum of 15c and 15e) 44,611 44,624g. Copies not Distributed (OfÞce, Returns, Spoilage, Unused) 974 1,469 h. Total (Sum of 15f and g) 45,585 46,093i. Percent Paid and/or Requested Circulation 95.38% 95.63%16. Electronic Copies Distribution: None Reported17. Publication of Statement of Ownership for a Requester Publication is required and will be printed in the November 2015 issue of this publication18. Signature of FulÞmment Manager: George Severine Date: 9/30/15 PS Form 3526-R, July 2014


NUCLEAR TECHNOLOGY

ant. Japan’s Monju reactor also closed after

similar problems, including a nasty coolant

fire and a utility and government cover-up.

Last May, the governments of France and

Japan announced they would move forward

with Astrid, aimed at developing a demon-

stration breeder burning spent nuclear fuel

at CEA’s Marcoule site near Avignon on the

Rhone River. In 2011, France put up $900

million to fund Astrid through 2017. Ja-

pan Prime Minister Shinzo Abe and French

President Francois Holland signed a joint

agreement to “intensify their civilian nuclear

research,” while both countries were restruc-

turing their nuclear programs. Japan is still

recovering from the Fukushima disaster,

which led to the shutdown of all of the coun-

try’s nukes, now slowly coming back into

service. France, meanwhile, is aiming to re-

duce its dependence on nuclear, from 75% of

its electricity production down to 50%.

According to the World Nuclear Associa-

tion, “Astrid is envisaged as a 600 MWe pro-

totype of a commercial series of 1500 MWe

[sodium fast reactors] which is likely to be de-

ployed from about 2050 to utilise the half mil-

lion tonnes of [depleted uranium] that France

will have by then and also burn the plutonium

in used MOX fuel. Astrid will have high fuel

burnup, including minor actinides in the fuel

elements, and while the MOX fuel will be

broadly similar to that in PWRs [pressurized

water reactors], it will have 25-35% plutoni-

um. It will use an intermediate sodium coolant

loop, and the tertiary coolant is nitrogen with

Brayton cycle.” CEA says a final decision

on whether to build the Astrid prototype will

come in 2019. As is the case with all advanced

nuclear technologies, the economics of com-

mercial plants are entirely unknown.

Hot, Hot, HotOne weakness of LWRs is the low quality of

their steam, which reduces the efficiency of

the plant. Typical steam outlet temperatures

for PWRs are under 400C, which compares

unfavorably to modern ultrasupercritical

coal-fired plants that operate with steam tem-

peratures above 600C.

Very-high-temperature nuclear reactors

with outlet temperatures around 1,000C are

possible and have actually been demonstrated,

although not commercially in the U.S. The

AEC and the Philadelphia Electric Co. teamed

up on a high-temperature gas reactor (HTGR),

a 40-MW graphite-moderated, helium-cooled

design originated by General Atomics in the

1950s. The unit located at the company’s

Peach Bottom site operated well from 1967 to

1974, with a lifetime capacity factor of 75%.

As a result, Public Service Co. of Colo-

rado, with AEC financial backing, ordered a

300-MW HTGR based on a scale-up of Peach

Bottom—the Fort St. Vrain plant. But that

plant operated poorly from the day it opened

in 1979 until it shut down just a decade later.

Both Peach Bottom and Fort St. Vrain used

large prism-shaped fuel blocks of enriched

uranium surrounded by a graphite moderator.

Since then, much time, effort, and money

have gone into attempts to revive HTGRs,

mostly focused on a General Atomics design

that uses billiard ball–sized “pebbles” con-

sisting of many 9-mm uranium fuel spheres

embedded in graphite (the moderator), sur-

rounded by a ceramic coating. These are

known as “pebble bed reactors.”

According to noted nuclear engineer An-

drew Kadak, an HTGR is fundamentally dif-

ferent from LWRs. The differences include

higher thermal efficiencies, an inert and

noncorrosive helium coolant, lower water

requirements, the use of gas turbine technol-

ogy, and a less-complicated design, because

there is no emergency core cooling system

like those required in LWRs.

Philadelphia Electric, before it was ac-

quired by Exelon Corp. in the early 2000s,

spent some $20 million for a 12% share in a

joint venture with South Africa’s state-owned

Eskom utility to develop a commercial 110-

MW pebble bed HTGR, aimed both at South

African and U.S. markets. After Chicago-

based Exelon took over, spending on the

project stopped in 2002. Eskom continued

work but dropped it in 2010, citing “run-away

costs and technical problems.” According to

Kadak, among the disadvantages of HTGRs

are the poor operating history, “little helium

turbine experience,” and “licensing hurdles

due to different designs.”

Yet industry interest in the HTGR concept

remains. A consortium of New York utilities,

the New York State Energy Research and De-

velopment Agency, National Grid, and South

Africa’s Pebble Bed Modular Reactor Co. in

2013 pitched the design into the U.S. Depart-

ment of Energy’s (DOE’s) second-round com-

petition for financial support for small, modular

reactors (SMRs). That bid was unsuccessful,

losing out to NuScale’s more conventional

LWR-based SMR technology. NuScale is now

negotiating with the DOE over terms and con-

ditions for a cooperative funding agreement.

Nuclear reactor designers have produced a

wide variety of fascinating concepts for alter-

natives to the light-water technology that is the

world’s go-to choice for atomic energy. But

these exotic designs, no matter how elegant, ex-

ist mostly on paper and may not be practical or

economic. For now, LWRs rule the real world. ■

—Kennedy Maize is a frequent contribu-tor to POWER.

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MD&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 4 . . . . .26 www.mdaturbines.com

NuScale Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 . . . . . . . .15 www.nuscalepower.com

Paharpur. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 . . . . . . . .13 www.paharpur.com

PCL Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 . . . . . . . . 4 www.pcl.com

Power Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 . . . . . . . .20 www.webachutes.com

Safway Services ……. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 . . . . . . . .27 www.safway.com

Schweitzer Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 . . . . . . . .22 www.selinc.com

Sealeze . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 . . . . . . . .10 www.sealeze.com

Sentry Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 . . . . . . . .17 www.sentry-equip.com

Structural Integrity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 . . . . . . . .16 www.structint.com

Van Beest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 . . . . . . . .11 www.vanbeest.com

Victory Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 2 . . . . . 1 www.victoryenergy.com

Westinghouse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 . . . . . . . . 2 www.westinghousenuclear.com

Zequanox . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 . . . . . . . .19 www.zequanox.com

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Valerie Thomas Paul Kerl


COMMENTARY

Reduce Ozone When and

Where It Matters Most

Just as we were drafting this commentary, the U.S. Environ-mental Protection Agency (EPA) issued a new ground-level ozone rule, tightening the standard from 75 to 70 ppb. The

projected human health and environmental benefits are substan-tial. Yet there has been significant concern about tightening the ozone standards because of compliance cost.

As it happens, our research team at the Georgia Institute of Technology recently developed a new way to help meet air qual-ity standards that might reduce the costs of meeting the new ozone rule. Our method is not an end-of-pipe air pollution con-trol technology. Rather, we take advantage of the fact that ozone concentrations vary substantially by day and by hour, depending on the emissions from local and regional sources as well as on atmospheric chemistry and atmospheric conditions such as tem-perature and mixing. Emissions from a specific hour of the day can have a disproportionately large—or minimal—impact on the pollution that forms, owing to the synergy with emissions from other hours combined with the effects of changing winds, atmo-spheric mixing, and sunlight.

What’s interesting about this is that for a power plant operat-ing at full capacity, on some days and at some times the resulting human health impacts may be low, whereas on other days—even similar days at the same time—health impacts can be elevated.

Basically, our method, which we call APOM (for Air Pollution Optimization Model), targets high-impact times, reducing health impacts at a lower cost. During low-impact time periods, the op-erations of power plants do not need to change, minimizing the impact on electricity generation cost. During high-impact times, some generation is either shifted to power plants that will have less effect on ozone concentrations in highly populated regions at that specific time, or generation is reduced using demand management. Because this method can be used when its ben-efits are greatest, and because it is managed entirely through power system operations, without purchase of pollution control equipment, it can reduce ozone levels at lower cost. (See www.apom.gatech.edu for more details and an animation.)

Why Hasn’t This Been Done Before?Power systems use computer models to control the operations of their power plants throughout the day, determining the level at which each power plant should operate as the day progress-es. Our method allows a simplified air quality impact model to be included as part of a power system’s operation model. The simplified “reduced form” air quality model is based on a very comprehensive model, called CMAQ, used by the scientific com-munity, government agencies (including the EPA), and stake-holders worldwide to simulate and study air pollution formation and forecast air quality. CMAQ does a great job, but it is too slow and complex to run the thousands of times needed for APOM.

Using a technique developed by our team called DDM-3D, we can determine from one CMAQ simulation how air quality across a region responds to emissions from power plants and other targeted sources, without repeating CMAQ simulations for

each emissions scenario. This leads to a reduced form model that responds almost exactly like CMAQ to changes in emissions, but instead of taking days to run, takes less than a second.

New Method Still Under DevelopmentIn our first demonstration of this technique, we focused on reduc-ing health impacts in the state of Georgia by using mathematical optimization to quickly sift through a huge number of possible electricity generating patterns. By considering many ways to ad-just power plant operations as the day goes on, balancing ozone impacts with power plant operation costs on an hourly basis every day, the APOM method was able to search out and find low-cost ways to improve air quality and human health.

More needs to be done before this method is ready for broad operational deployment. Also, although our case study demon-stration was done for an electricity generation system, the same method could be applied to industrial sources, transportation sources, and residential sources of ozone-producing emissions.

There are examples of similar approaches that have successfully been incorporated in the operation of electricity systems. One is the use of congestion pricing. When the transmission system is congested, the operator chooses alternative (often more expen-sive) generating units to relieve system congestion in a given region. These prices differ in terms of time and space. Pricing air quality in the same way is now a possibility with this approach.

Facilitating a Broader Mix of GenerationThe key advantage of this approach is that it can find low-cost ways to improve air quality. A second advantage is that it can be applied soon, for existing facilities. While pollution control equipment or replacement of emission sources may be the best approach, the APOM approach can be applied quickly. It can also be applied anywhere in the world. In locations with significant air quality challenges, this approach can provide benefits before pollution control technology can become widespread. A third advantage is that the APOM approach can allow different kinds of emission sources to work together, using market-based ap-proaches, to reduce ozone levels at least cost.

The heart of the APOM approach is to find the lowest cost ways to change operations when it matters most—times when ozone concentrations would be highest. This approach can work with high-emitting sources and, in fact, could allow high-emitting sources to continue operating while contributing to meeting the new air quality standards. Because of this, reliance on the APOM approach is unlikely to be able to substitute for improved tech-nology that will reduce emissions permanently and comprehen-sively. Yet, it can be an opportunity for electricity generators, industrial facilities, and other sources to remain in operation and meet emissions limits at lower costs than they have expected. ■

—Valerie Thomas, Paul Kerl, Juan Moreno Cruz, Athanasios Nenes, Matthew Realff, Armistead Russell, and Joel Sokol are

at the Georgia Institute of Technology; Wenxiang Zhang now works at Trinity Consultants. hdrinc.com

When foresight meets insight, you’re in business.New EPA regulations mean important decisions lie ahead. We’re helping utilities nationwide find practical compliance solutions by breaking down options and stepping through the process holistically. We have the experience and capability to guide you to your best possible outcomes.

hdrinc.com

When foresight meets insight, you’re in business.New EPA regulations mean important decisions lie ahead. We’re helping utilities nationwide find practical compliance solutions by breaking down options and stepping through the process holistically. We have the experience and capability to guide you to your best possible outcomes.

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