November 2012

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Vol. 156 • No. 11 • November 2012

Top Plants: Two Innovative Nuclear Plants

North Anna: Earthquake Recovery

China’s Nuclear Industry Responds to Fukushima

Prepare for New PM2.5 Standards

A compact powerhouse for reliable generation of electricity and heat. The newly developed 6-cylinder 220 kW gas engine sets standards that are nothing short of revolutionary. Its combination of four-valve technology and new combustion chamber geometry boosts specifi c performance, optimises cost effi ciency and also reduces emissions. The novel engine concept features an overhead camshaft cylinder head that additionally increase the life and service friendliness of the engine. Come along andsee the new MAN Power at BioEnergy in Hanover from 13 to 16 November.

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November 2012 | POWER www.powermag.com 1

ON THE COVERDominion Virginia Power contracted with Alstom Power to upgrade the two steam turbines at its North Anna nuclear power station in 2007. The steam turbine rework included replac-ing the double-flow, high-pressure rotor and diaphragms with a more efficient single-flow arrangement and two low-pressure (LP) double-flow turbines—shown in the photo as they are being assembled. The LP turbine’s last-stage blade length increased from 48 to 57 inches, requiring replacement of the LP inner casing and significant rework to the exhaust hoods, condenser connections, and surrounding structural steel. Courtesy: Alstom Power

COVER STORY: nuClEaR TOp planTS30 north anna power Station, louisa County, Virginia

For decades now, U.S. nuclear generators, faced with daunting barriers to new con-struction, have had to practice a special kind of energy efficiency by way of up-grades. Dominion’s North Anna station recently completed its second uprate, this one made possible by steam turbine retrofits.

32 Oconee nuclear Station, Seneca, South CarolinaNuclear plant operators and regulators are cautious by nature—for good reason. But you can’t use outmoded equipment forever. By installing the first nuclear plant digital control system in the U.S., Duke Energy has positioned itself at the forefront of an important technology switch.

SpECIal REpORTS nuClEaR pOwER34 Dominion’s north anna Station Sets new Standard for Earthquake

ResponseJust six months after the earthquake-and-tsunami-caused nuclear disaster in Japan, a record-setting earthquake struck Central Virginia. For the nuclear plant located only 11 miles from the epicenter, it was a beyond-design-basis event. How management and staff responded to that event has set a new benchmark for earthquake recovery.

42 what worldwide nuclear Growth Slowdown?Although last year’s nuclear plant disaster in Japan prompted a necessary and ex-pected reevaluation of nuclear plants and plans worldwide, one year later, the net effect on the global nuclear outlook is barely measurable.

30

A compact powerhouse for reliable generation of electricity and heat. The newly developed 6-cylinder 220 kW gas engine sets standards that are nothing short of revolutionary. Its combination of four-valve technology and new combustion chamber geometry boosts specifi c performance, optimises cost effi ciency and also reduces emissions. The novel engine concept features an overhead camshaft cylinder head that additionally increase the life and service friendliness of the engine. Come along andsee the new MAN Power at BioEnergy in Hanover from 13 to 16 November.

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Established 1882 • Vol. 156 • No. 11 November 2012

Look for this web-exclusive story under the Features heading on our homepage, www.powermag.com, during the month of November or in our Archives any time: “Too Dumb to Meter, Part 5.” It’s the latest installment of Contribut-ing Editor Kennedy Maize’s history of nuclear power in the U.S. And remember to check our What’s New? segment on the homepage regu-larly for just-posted news stories cover-ing all fuels and technologies.

More POWER Nuclear Coverage on the Web

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www.powermag.com POWER | November 20122

FEATURES

POWER IN CHINA

48 Post-Fukushima Nuclear Power Development in ChinaWhen China’s neighbor suffered the devastation of the Fukushima Daiichi nucle-ar plant disaster, it prompted a reconsideration of China’s nuclear development goals. Despite some expected short-term adjustments, the long-term goals re-main virtually unchanged.

WATER & POWER

53 Potential Impacts of Closed-Cycle Cooling Retrofits at U.S. Power Plants Though the “best technology available” (BTA) determination under the Environmental Protection Agency’s proposed rule for cooling water intake structures is not yet written in stone, industry researchers are looking at the likely consequences if BTA is closed-cycle cooling. EPRI recently completed a study of estimated costs, benefits, impacts, and environmental consequences of a potential national requirement to retrofit cool-ing towers on all once-through facilities in the U.S. The estimated costs? Over $100 billion.

AIR QUALITY

57 Hazy Timetable for EPA’s Proposed Tighter PM2.5 StandardsIt’s a question of “when,” not “if” tighter particulate standards will be released by the Environmental Protection Agency, so it’s time to take a close look at the techni-cal and economic particulars of what’s likely to be involved for plants that will be affected by the new limits.

PLANT DESIGN

62 The Evolution of Steam AttemperationIncreased superheated steam volumes and temperatures plus diverse operational modes challenge steam attemperator systems at combined cycle plants. Know the design options and engineering considerations before you choose a new or replace-ment system.

DEPARTMENTS

SPEAKING OF POWER6 Economic Meltdown

GLOBAL MONITOR 8 France Considers Departure from Iconic Stance on Nuclear Energy10 THE BIG PICTURE: Advanced Fission 12 After Blackouts, India Plans Reforms12 Progress for Germany’s Power-to-Gas Drive14 Research Center Dedicated to Power Plant Water Use Opens15 POWER Digest

FOCUS ON O&M18 Seismic Instrumentation at Nuclear Power Plants20 Maximizing Steam Turbine/Compressor Performance with Precise

Torque Monitoring at the Coupling22 Measuring On-Time Completion to Improve Your EHS Audit Program

LEGAL & REGULATORY28 EPA’s Title V Source Policy Takes a Hit

By Angela Neville, JD

66 NEW PRODUCTS

COMMENTARY72 Preparing for the EPA’s Cooling Water Rule

By Harold M. Blinderman, JD, partner, Day Pitney

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TWO GREAT COMPANIES. ONE BRIGHT FUTURE.How do you create a global company built for the future? By combining two powerful histories in pursuit of a bold vision—to help companies around the world contribute to healthier, safer environments. Building on the achievements of Pentair and Tyco’s Flow Control businesses, comprised of Valves & Controls, Thermal Controls and Water & Environmental Systems, the new Pentair delivers exceptional depth and expertise in filtration and processing, flow management, equipment protection and thermal management.From water to powerFrom energy to constructionFrom food service to residentialWe’re 30,000 employees strong, combining inventive thinking with disciplined execution to deploy solutions that help better manage and utilize precious resources and ensure operational success for our customers worldwide. Pentair stands ready to solve a full range of residential, commercial, municipal and industrial needs.

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SPEAKING OF POWER

Economic Meltdown

The bill for German Chancellor An-gela Merkel’s coalition government’s knee-jerk decision to close all 17

of its nuclear plants by 2022 is coming due. Merkel’s energy plan is to radically expand the use of renewable energy to 35% of total power consumption by 2020 and to 80% by 2050. Currently, renew-ables represent 20% of the country’s en-ergy mix.

You may recall my editorial (“Irrational Exuberance,” December 2011) in which I estimated the cost of replacing Germa-ny’s lost nuclear capacity with wind and solar. My back-of-the-envelope numbers suggested that the added costs to Ger-man electric rates for renewables would rise to 7 cents/kWh by 2020 and that the plan will cause household electric rates to rise “about 6% per year for the next nine years.” I was wrong. My long-term rate of increase estimate took place in the first year and is not sustainable.

Steep Residential RatesThe German Economy Ministry has stated that the renewable energy subsidy portion of the Renewable Energy Act (EEG) of the residential electricity bill will rise to be-tween 5.9 and 6.6 cents/kWh this year (not including the 19% value added tax, VAT) to help pay for Merkel’s renewable energy poli-cies, an increase of 30% to 50% over last year. Some in the government have sug-gested the EEG may soon rise to 7.5 cents/kWh, a 70% increase in one year.

Berlin Technical University Professor Georg Erdmann’s calculations show the EEG portion of the consumer’s electricity bill will jump to over 10 cents/kWh, or nearly three times what Merkel pledged to consumers when revealing her energy plan less than a year ago. Remember, this is only the additional cost to the monthly bill to pay for the extremely lu-crative 20-year feed-in tariff contracts for renewable electricity. For 2011, the average household electricity price was 31.6 cents/kWh, according to Eurostat, not including the VAT, three and one half

times more than the average household pays in the U.S.

German government data suggests that consumers will pay out $125 billion over the next 20 years to subsidize renew-ables installed before the end of 2011; the number rises to $250 billion if future hookups are included. Erdmann predicts the real number is well over $375 billion because the rate of photovoltaic (PV) in-stallations is much higher than govern-ment predictions. In 2011 alone, 7.5 GW of solar were installed—double govern-ment estimates.

Public interest groups condemn these rapidly accelerating electricity prices as unfairly impacting those on fixed incomes. “Private households are expected to pay for an energy transition for which no clear plan exists,” says Holger Krawinkel of the Federation of German Consumer Organiza-tions. The group says that one-seventh of Germany’s households now live in “energy poverty.” Government data shows that more than 600,000 households had their electricity turned off for non-payment in 2011. It’s no wonder that many public ad-vocacy groups are protesting the rapidly rising rates in the name of social justice.

Industrial AdvantageGermany’s largest industrial power consum-ers have always enjoyed generous electric-ity rate subsidies. Eurostat data shows that the price of electricity for the largest indus-trial users is one-half of that for consumers. In fact, industrial users are required to pay only 0.3% of the cost of the EEG mandated renewable feed-in tariffs!

Even so, the large industrial rates are the highest in the European Union and are expected to rise 20% by 2020. Ac-cording to the Association of German Chambers of Industry and Commerce (DIHK), high electricity rates are a prin-cipal cause of the acceleration of Germa-ny’s de-industrialization. DIHK reports that almost one in five industrial compa-nies plans to increase capacities abroad, if it hasn’t done so already.

Projects Behind SchedulePV projects are moving quickly, but off-shore wind projects are becalmed. Moving expensive yet abundant offshore wind en-ergy to Germany’s industrial south requires thousands of kilometers of new transmis-sion lines. It’s not surprising that many local jurisdictions don’t want these new transmission towers in their districts or are demanding expensive undergrounding of the wires. Siting of these new lines is at a virtual standstill across Germany.

In May, the operators of Germany’s four power grids presented their esti-mates of the costs to comply with the German government’s national expan-sion of the grid: $25 billion over the next 10 years. TenneT, the Netherland’s state-owned grid operator (which also supplies about a third of Germany), says it will cost an additional $15 billion in grid improvements to connect just the first wave of offshore wind turbines to the grid by 2020, and the economics don’t justify the investment. In addi-tion, another 4,000 kilometers (km) of existing lines must be modernized, al-though that cost wasn’t noted.

Many offshore wind parks are now un-der construction, some up to 200 km out in the Baltic Sea and the North Sea, but none has been finished. Without trans-mission lines, many projects are at a standstill; at least one project is three years behind schedule. Also, technical problems are confounding developers relying on unproven HVDC systems con-nected to very long undersea cables. In the meantime, the government is again looking to the consumer to pay for these project delays.

The Green Party has taken the position that it is necessary to make financial sac-rifices for the sake of the “environmen-tal transformation of society.” Germany’s “transformation” has barely begun, but it seems to me that the consumers have already been sacrificed. ■

—Dr. Robert Peltier, PE is POWER’s

editor-in-chief.

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France Considers Departure from Iconic Stance on Nuclear EnergyNo other country has been as frequently cited as an example of exploiting the virtues of a nuclear-heavy energy policy as France. Deriving more than 75% of its electricity from 58 op-erational nuclear reactors with a total capacity of about 63 GW, France has one of the lowest costs of generation and is the world’s largest net exporter of power, earning €3 billion ($3.9 billion) a year from sales of surplus power to buyers beyond its borders. But that is all about to change.

Having few indigenous energy resources, and impelled by the first oil shock of 1974, the French government embarked on a pointed mission to rapidly expand the country’s nuclear power capacity. Sub-sequent parliamentary debate reaffirmed nuclear’s central role in the country’s energy policy, which stresses security of supply and ad-dressing environmental concerns, including mitigating greenhouse gas emissions and properly managing radioactive waste. As well as developing a closed fuel cycle—nearly 17% of the country’s electricity is produced from recycled nuclear fuel—France has also established research policy that incorporates its heavy engineering experience and seeks to develop innovative nuclear energy technologies.

Considering that nuclear energy is so important to France, it is no surprise that it has featured in blueprints of the country’s economic future. Spearheaded by former President Nicolas Sarkozy, the coun-try in 2008 established the Agence France Nucléaire International (AFNI), a vehicle to help set up civil nuclear programs in other countries. Sarkozy’s government called for a massive resurgence of nuclear power, extolling its ability to combat climate change, pro-vide an economic boost, and achieve energy independence.

But even before the devastating Fukushima crisis in Japan in March 2011, experts say some French citizens had been pushing back, contesting the almost “religious consensus” on the matter of the country’s reliance on nuclear power. As early as 2008, a few nuclear experts associated with Global Chance (whose members are academic and institutional scientists—a group comparable to the Union of Concerned Scientists in the U.S.) confronted what it called the “official narrative.”

They alleged that the image of France’s nuclear program as a highly successful industry was a “sham.” Development of nuclear power was marked by a “succession of technological blind alleys, planning errors and all kinds of difficulties, which are generally noted and corrected without any public discussion.” The economic justification of vend-ing nuclear technology was also particularly suspicious, the group claimed, citing a lack of transparency on several crucial levels: Official projected investment costs for a number of projects were consistently lower than actual costs, and—as exemplified by the two EPR reac-tors under construction at sites in France and Finland—construction times and load factors often lagged behind projected figures.

When the Fukushima accident happened, as Germany and Tai-wan vowed to phase out nuclear power entirely, cracks in France’s nuclear facade widened. Public concerns for safety mounted as anti-nuclear groups highlighted startling statistics that showed French nuclear plants saw 700 to 800 incidents a year, varying in serious-ness. And when Socialist François Hollande ran on a platform pro-posing to reduce nuclear’s share of the country’s energy mix from 75% to 50% by 2025, and pledged to order the closure of the two-unit Fessenheim before the end of his first term in 2017, he won, albeit narrowly, over incumbent Sarkozy, who had called Hollande’s policies “economically disastrous.”

Hollande has, since the election, reiterated his pledge to cap nuclear’s share at 50%, promising a transition strategy based on energy efficiency and renewable energy. At a two-day conference in September, he said his government was pushing for closure of France’s oldest nuclear plant, the 1977-built Fessenheim plant in Alsace, near the German border, within four years, and that it would “make an example” of successful decommissioning (Figure 1). Meanwhile, he said new tenders for solar and offshore wind power would be launched before the end of 2012.

Even though France’s nuclear industry employs about 400,000 heavily unionized workers, the avowal has not been strongly po-litically contested—save by the Greens Party, which captured 17 parliamentary seats in May after coalescing with the center-right Socialists and having accepted the Socialists’ goal of a 50% nuclear cap (which is far higher than their own goal of zero).

Site directors of all nuclear plants operated by Fessenheim’s owner EDF have protested the closure of Fessenheim in an open letter, calling it a “profound injustice.” The decision would “create uncertainty about EDF’s plans for its nuclear plant fleet” and casts doubt on “employment and economic development” for the regions in which nuclear plants are sited, the letter said.

Some experts express skepticism about how France will carry out the transition. At the end of 2011, of France’s total generating ca-pacity of 126 GW, 25 GW was hydro, 28 GW fossil fuel, 6.6 GW wind, and 2.2. GW solar PV. Counting hydro, renewables made up 13% of the country’s total generated electricity—but that is well below the 23% target set by Sarkozy for 2020. Experts point out that compared with its neighbors Germany and Spain, only 2% of generated power comes from wind, while solar power makes up less than 0.5%.

Most nuclear industry stakeholders in France concede that a fair debate on France’s energy future is warranted. A formal na-tional discussion has been scheduled by Minister for Environ-ment, Sustainable Development and Energy Delphine Batho. It includes an “information phase” that will take place between November and December this year, followed by a public participa-

1. The end of an era. Newly installed French President François

Hollande defeated incumbent Nicolas Sarkozy in May by running on a

platform that proposed to cut France’s share of nuclear energy from 75%

to 50% by 2025 and to shut the 1978-built two-unit Fessenheim plant,

shown here, before the end of his term in 2017. Fessenheim, located in

the Alsace region of northeastern France, is the country’s oldest nuclear

plant. French regulators in 2011 deemed the plant suitable to operate for

another 10 years if it made some improvements. Courtesy: EDF

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THE BIG PICTURE: Advanced Fission



tion phase (via webcast and regional conferences) from January through April 2013. Recommendations for the energy transition will be made in May 2013 following the discussion, and a new energy policy bill could emerge as early as June 2013. Batho has noted that the discussion will pay particular attention to “social issues and economic transitions as well as industrial and profes-sional retraining authorities.”

After Blackouts, India Plans ReformsThe back-to-back collapse at the end of July of India’s Northern, Eastern, and Northeastern grids that slashed power to more than 60% of India’s population of 1.24 billion has impelled the coun-try into a spending frenzy to upgrade its rickety power network, which, a government inquiry revealed, was one cause of the unprecedented blackouts. But the 10th-largest economy in the world has much more work to do, including a much-needed over-haul of its current patchwork of energy policies, experts say.

The blackouts on July 30 and July 31 afflicted a massive swath of the subcontinent stretching 2,000 miles from Assam on the east, near China, to the Himalayas in the north, and the north-western deserts of Rajasthan. The Western and Southern grids were unaffected, leaving Gujarat and many southern states un-touched by the chaos. In the days after the blackouts, as the country registered how immense the problem was, the govern-ment jumped into action.

As speculation mounted about the cause of the blackouts, the government’s first order was to assemble a three-member panel to determine the reason for the massive failures. In an 81-page report issued on Aug. 16, the panel pinned the causes on weak interregional power transmission corridors that had been compromised by multiple existing outages. Northern India was

already seeing excessive power demand, and a chronic supply shortfall was exacerbated by lower-than-normal rainfall from the weak summer monsoon that strained the country’s hydroelectric power supply. But on July 30, several utilities overdrew from the Northern Grid despite instructions from regional load dispatch centers, causing its collapse and putting out the lights for the more than 300 million people it serves across nine states.

On July 31, after the Northern region was separated from the Western region following the trip of the 400-kV Bina-Gwalior line, the Eastern and Northeastern grids collapsed, barring a few pock-ets, due to “multiple tripping attributed to the internal power swings, under frequency and overvoltage at different places,” the report said. Restoration took five hours, eight hours, and two hours in the Northern, Eastern, and Northeastern regions, respectively.

Several measures could have saved the system from collapse, the report pointedly concluded, including “better coordinated planning of outages of state and regional networks, specifically under depleted condition of the inter-regional power transfer cor-ridors,” and “better regulation to limit overdrawal/underdrawal.”

The panel’s message was clear. In September, Power Grid Corp. of India, the nation’s largest electricity transmission company, pledged to spend 1 trillion rupees ($18 billion) to upgrade its network over the next five years. The urgency is not understated, company officials say, noting that India plans to increase its generating capacity by 76 GW by 2017. “Making sure a collapse doesn’t happen again is our top priority,” Power Grid Chairman R.N. Nayak said in an interview with Bloomberg on Sept. 14. “We may end up crossing that 1 trillion-rupee spending mark to strengthen and stabilize the gaps exposed by the blackouts.”

Yet that is only the tip of the iceberg, say experts from the International Energy Agency in a September report outlin-ing challenges that the country must address to create a well-functioning, financially viable power sector. Hurdling the first of those challenges will require further reform of the electricity sec-tor, whereby the nation’s energy companies can achieve “mana-gerial autonomy from central or state ministries . . . for timely investment.” The key issue is “not private- versus publicly-owned entities; rather, ownership should not interfere with market prin-ciples,” the report says.

Another pressing reform involves pricing mechanisms. The cur-rent rigid pricing setting determined by the government does not reflect realistic costs, and this has been a primary cause of India’s recurring fiscal and supply-side problems, the report says. India’s power sector is overwhelmingly afflicted by a shortage of fuels, insufficient infrastructure, and financial weakness of state-owned power companies—and these are issues caused by “distorted pric-ing mechanisms and a systematic weakness to enforce legitimate revenue realization.”

One way that India could possibly become an open and func-tioning energy market is by electing strong political leadership to convey clear policy messages. “Frequent populist remarks, which, for example, promise free electricity, are not conducive to creat-ing the right public perception of energy as a commodity, not an entitlement. Furthermore, in the context of an increasing need for investments and the integration of India’s energy sector into the global energy market, India needs to align its energy policies and institutions with global practices,” it concluded.

Progress for Germany’s Power-to-Gas DriveGermany’s E.ON this August began construction of a new pilot plant in Falkenhagen in northeast Germany that will convert excess wind

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energy into synthetic natural gas that can then be fed into the re-gional gas grid, where it can be used to produce heat and power.

The technology is not new. In 2010, German researchers at the Center for Solar Energy and Hydrogen Research Baden-Württemberg, in cooperation with the Fraunhofer Institute for Wind Energy and Energy System Technology IWES, announced they had developed what they called a “power-to-gas” process, which essentially employs hydrogen-electrolysis with metha-nization. It involves splitting water using surplus renewable energy to create hydrogen and oxygen. A chemical reaction of hydrogen with carbon dioxide generates methane—or synthetic natural gas (Figure 3). The researchers then built a 25-kW pilot plant in Stuttgart, supported by Austrian company SolarFuel. A second 250-kW research facility is now in the works, scheduled for completion this year.

The technology seems to have made major strides since the first pilot. SolarFuel is currently working on a project that will see the construction of an industrial pilot facility in Werlte near Oldenburg for the production of renewable gas (or e-gas) for use in Audi vehicles. If all goes as planned and the facility begins operating in the third quarter of 2013, power from four 3.6-MW offshore wind turbines will be sourced to produce around 4,000 cubic meters of renewable methane for a connected load of 6.3 MW, fueling 1,500 turbo-compressed natural gas (TCNG) Audi A3 vehicles for a year. Audi plans to begin serial production of this vehicle type next year.

Meanwhile, E.ON is just one of a dozen parties interested in the technology. European firm ENERTAG has also gotten into the game, partnering with Swedish utility Vattenfall and other com-panies to build a 6-MW hybrid power station that transforms wind energy into hydrogen in Prenzlau. After converting excess wind energy to hydrogen, the plant uses that hydrogen and biogas to generate power and heat.

But E.ON’s project is unique in that it involves methanization and is of a larger scale, consisting of a 2-MW storage facility (over a 24-hour period, the facility will store about 30 MWh of energy). The hydrogen gas produced from the Falkenhagen plant at a rate of 360 cubic meters per hour will be injected into the regional natural gas pipeline, making the natural gas pipeline network a storage system for surplus electrical power generated from renewable resources.

The project involves a turnkey contract awarded to Canadian company Hydrogenics Corp., which means that firm will supply, install, connect, and commission most components of the hy-drogen production facility, including gas compression and mas-ter controls, and ready it for operation—scheduled for 2013.

In a larger context, the technology had been lauded as showing tremendous promise—particularly in Germany, because it is well-suited to the country’s infrastructure. Germany reportedly has a natural gas storage reservoir equivalent to more than 200 TWh. Integration into the infrastructure is simple, developers say: The natural gas substitute can be stored like conventional natural gas in the supply network, pipelines, and storage systems in order to fuel natural gas cars or fire natural gas heating systems.

The approach, which is still relatively new and expensive, is strongly being promoted by Germany’s federal power and gas agen-cy, the Bundesnetzagentur, which in November 2011 held a con-ference to discuss new developments in the field. Matthias Kurth, president of the Bundesnetzagentur, has said that it could also prove invaluable to Germany in light of the nation’s change of direction in energy policy towards a renewable future. “In addition to grid expansion and intelligent load and generation management, considerably more storage capacity will in fact be required to bal-

ance fluctuations in solar and wind power generation. Pumped-storage power stations are a good solution for short-term load balancing, but there is only limited capacity available in Germany. Long-term storage is therefore a major challenge when it comes to transforming the energy supply system,” he said.

Research Center Dedicated to Power Plant Water Use OpensThe Electric Power Research Institute and several partners—including the Southern Research Institute, Southern Co. sub-sidiary Georgia Power, and Southern Research—are testing a new technology that could reduce the amount of water needed for power plant cooling. The work is taking place at the new Water Research Center (WRC) at Georgia Power’s Plant Bowen in Cartersville, Ga.—a novel facility dedicated to developing and testing technologies to reduce power plant water withdrawals and consumption.

The partners are evaluating a new thermosyphon cooler tech-nology developed by Johnson Controls (Figure 4). According to the Wisconsin-based firm, the technology transfers heat to the environment without evaporative water loss by using an air-cooled refrigerant that pre-cools water before it enters the cooling tower. The thermosyphon cooler also reduces the

3. Storing gas. Power-to-gas, a fairly new type of energy storage,

involves converting renewable power to hydrogen, using electrolysis,

and then chemically converting it to methane—or synthetic natural

gas—for storage in existing gas grids. Austrian company SolarFuel

was among the first to collaborate with German researchers as they

developed the process. Source: SolarFuel; Specht, Sterner et al.

Conversion into electricity

Storage of electricity

Combined cycle

plant/CHP

Methanization

Electrolysis/ H2 tank

Power grid Gas grid

Wind

Sun

CO2 CO2 tankCO2 CH4

CO2

H2 H2

Gas storage

tank

4. Testing the water. The newly opened Water Research Center

at Georgia Power’s Plant Bowen in Cartersville, Ga., will develop and

test technologies to reduce power plant water withdrawals and con-

sumption. This image shows Johnson Controls’ thermosyphon cooler,

which is the first project to become operational at the center. Courtesy:

Georgia Power


amount of water that must be cooled by evaporation in the cooling tower, thus reducing water consumption. The year-long testing at the WRC will document the technology’s water-saving potential and energy consumption characteristics, developers say.

The WRC will have seven distinct focus areas: moisture recovery; cooling tower and advanced cooling systems; zero liq-uid discharge; low-volume wastewater treatment; solid landfill water manage-ment; carbon technology water issues; and water modeling, monitoring, and best management practices.

POWER DigestGlobal Companies Take on Nigeria’s Newly Privatized Plants. Nigeria’s $1 billion liquidation of five government-owned thermal and hydropower generation companies—part of a wider privatization effort that includes transmission and dis-tribution assets to encourage investment in the power shortage–stricken country’s electricity sector—has attracted a number of global companies and investors. Eight firms bid a total of $707 million for the 434-MW Gerugu plant, 832-MW Ugheli plant, 1,020-MW Sapele plant, 600-MW Shiroro plant, and 760-MW Kainji plant, but five consortia were picked as preferred bidders for the successor companies cre-ated from the divestiture of Power Hold-ing Co. of Nigeria.

Among the highest bidders was a con-sortium listing Nigerian conglomerate Transcorp and U.S. firm Symbion Power, which offered $300 million for the gas-fired Ugheli plant. Another consisted of a Chi-nese firm and Eurafric, a Nigerian oil and gas firm, which bid $201 million for the thermal Sapele plant. And one listing was for Forte Oil, Shanghai Municipal Electric Power Co., and BSG Power, which bid $132 million for the gas-fired Gerugu plant. Man-agement contracts for the two hydropower plants went to consortiums that included several Nigerian firms, Russia’s RusHydro, and China Three Gorges Corp.

Two CFB Contracts for Foster Wheel-er in South Korea. Foster Wheeler in September won a contract from South Ko-rea’s Yeosu Cogeneration Corp., a subsid-iary of Hanwha Corp., for the design and supply of a 60-MWe circulating fluidized-bed (CFB) steam generator located in an industrial complex in Yeosu City, South Korea, that is slated to go online in the first quarter of 2015.

In October, the global engineering and construction company Foster Wheeler re-

ceived a full notice to proceed on a separate contract with Doosan Heavy Industries & Construction Co., Ltd. for cooperation in the design of a 350-MWe CFB steam gen-erator for the Yeosu Thermal Power Plant 1 Project for Korea South East Power Co., Ltd. Doosan will supply the major equip-ment, including the CFB boiler and turbine generator for the Yeosu 1 project, which will replace an existing heavy oil–fired unit. That project is also expected to be completed in the first quarter of 2015.

Demand for CFB boilers is increasing in South Korea and other countries, pegged on the growing use of low-quality coal, of which there are large reserves, a Doosan official said in a statement.

Coal Gasification Power Plant Devel-oper Secures Construction, Financing Contracts. Seattle-based Summit Power Group on Sept. 12 signed a memorandum of understanding with representatives of China’s Sinopec Engineering Group for an engineering, procurement, and construc-

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tion contract, and with the Export-Import Bank of China to secure financing for the $2.5 billion Texas Clean Energy Project (TCEP), a large-scale commercial coal gasification power/polygen project that the company is developing near Odessa, Texas.

Siemens Energy is expected to provide a high-hydrogen com-bustion turbine for the project, which proposes to remove carbon dioxide, sulfur, and mercury from the project’s gas stream prior to combustion, leaving only a high-hydrogen/low-carbon clean “syn-gas” as the sole fuel that is burned. The project will capture 90% of its carbon dioxide emissions for use in enhanced oil recovery by producers in the Permian Basin of West Texas. TCEP will also produce more than 700,000 tons per year of urea as fertilizer, which will be bought entirely by Minnesota-based CHS Inc., and Houston-based Shrieve Chemical Co. will purchase TCEP’s output (about 50,000 tons per year) of sulfuric acid. CPS Energy, San Antonio’s municipal electric and gas utility, will buy 200 MW of the plant’s power.

About $450 million of TCEP’s costs will be covered by a Depart-ment of Energy cost-sharing program under the federal Clean Coal Power Initiative.

RWE Opens 2-GW CCGT Plant in West Wales. RWE AG opened its 2,160-MW Pembroke combined cycle gas turbine plant on Sept. 19, handing over the fifth and final unit of the station to its UK subsidiary RWE npower and culminating three years of construction during which more than 10,000 contractors worked 7.4 million man hours to complete the $1.6 billion facility. The new plant was built on a site formerly occupied by a 2,000-MW oil-fired power station. The station was outfitted with five Als-tom GT26 single-shaft gas turbines, five drum-type heat recovery steam generators, five STF30C steam turbines with axial exhaust, and five TOPGAS turbo-generators. Swiss company ABB supplied the automation system and the Shaw Group put up five heat recovery steam generator boilers.

The power from the new plant in west Wales is badly needed by the UK: About 40% of the country’s existing generation facilities were built before 1975 and are expected to be shuttered over the next 10 to 15 years. Several fossil fuel–fired plants—including RWE’s own 2,000-MW coal-fired Didcot A power plant and the 1,000-MW oil-fired Fawley plant—will be shut down in line with requirements of the European Union’s Large Combustion Plant Directive. Many nuclear power plants are also reaching the end of their operational lives. Meanwhile, power demand in the UK is expected to surge, forcing the country to increase generating capacity by 35 GW by 2020 to ensure energy reliability.

SunPower Corp. Completes 1.3-MW Rooftop Solar Proj-ect in San Francisco. California firm SunPower Corp. on Sept. 19 completed a 1.3-MW solar system on the roof of the Explor-atorium, a massive science museum under construction at Pier 15 in the heart of San Francisco’s waterfront district. The system will generate as many kilowatt-hours of power as the facility needs when it opens in the spring of 2013. It uses 5,874 SunPower so-lar panels, which the company says are up to 50% more efficient than conventional panels, and a performance-monitoring system that displays system performance, updated every 15 minutes, in the lobby of the new 330,000-square-foot facility. Any energy unused by the Exploratorium will be fed into the utility grid for use by other Pacific Gas & Electric customers.

FENOC Plans to Expand Nuclear Fuel Storage Capacity at Beaver Valley. FirstEnergy Nuclear Operating Co. (FENOC) on Sept. 19 announced plans to expand used nuclear fuel storage ca-pacity at its two-unit Beaver Valley Power Station in Shippingport, Pa. The FirstEnergy subsidiary plans to install six above-ground, airtight steel and concrete canisters that provide cooling to used fuel assemblies through natural air circulation starting in the fall of

2012, but it says at least 47 additional canisters may be added as needed after that project’s completion in 2014. The canisters will be stored on a thick concrete pad located within Beaver Valley’s highly secured protected area, providing additional safety assurance. The storage system will be monitored closely by trained personnel and the Nuclear Regulatory Commission to ensure its integrity.

Beaver Valley began operation of Unit 1 in 1976 and Unit 2 in 1987, and its used fuel assemblies have been stored in an indoor, steel-lined pool within the power station. Approximately 40% of each unit’s 157 fuel assemblies are replaced and then stored in the pool following each 18-month operating cycle. But the fuel pool is expected to reach full storage capacity by 2015, and “because a national repository for used nuclear fuel has not yet been developed, Beaver Valley must plan for additional storage space,” the company said.

Plant Barry CCS Demonstration Begins Underground In-jection. A carbon capture and sequestration (CCS) demonstration project jointly under way by Mitsubishi Heavy Industries Ltd. (MHI) and Southern Co. in September began underground injec-tion of carbon dioxide (CO2) recovered from flue gas emissions of a carbon capture facility built at Southern Co.’s Plant Barry in Alabama. The demonstration test, which began last June, is the world’s largest in scale, capturing 500 metric tons per day (mtpd) with a CO2 recovery efficiency of above 90%.

Injection is being performed in a saline formation at a depth of 3,000 to 3,400 meters in the Citronelle Dome geologic struc-ture, which is approximately 12 miles west of the plant. The se-questration aspect of the project is being conducted as Phase III of the Regional Carbon Sequestration Partnerships program, a program sponsored by the U.S. Department of Energy.

The carbon capture facility consists primarily of a flue gas scrubber, flue gas CO2 capture/regeneration system, CO2 compres-sion machinery, and electrical components. For CO2 recovery the facility adopts MHI’s KM CDR Process, which uses a proprietary KS-1 high-performance solvent for CO2 absorption and desorption that was jointly developed by MHI and the Kansai Electric Power Co., Inc. MHI said it had previously completed small-scale dem-onstration testing at 10 mtpd in cooperation with the Research Institute of Innovative Technology for the Earth and Electric Power Development Co., Ltd. (J-POWER) and confirmed “unin-terrupted stable operation.”

Westinghouse Prepares for Possible AP1000 Construc-tion in Czech Republic. Westinghouse Electric, one of three bidders vying for a multi-billion-dollar tender from Czech utility CEZ to construct two new units at its Temelín nuclear power sta-tion, on Sept. 11 said it would cooperate with Czech construction company Hutní montáže a.s. to prepare for potential construc-tion of AP1000 nuclear plants in the Czech Republic and region-ally. If Westinghouse is awarded the tender, the Toshiba Corp. unit said Hutní montáže would be responsible for performing the vast majority of the mechanical installation and corresponding construction testing, including assembly and installation of the containment vessel.

Westinghouse has embarked on an initiative to develop a lo-cal supply chain to prepare for construction of the reactors at Temelín, including signing memoranda of understanding with ma-jor Czech companies, notably I&C Energo a.s., Metrostav a.s., and Vítkovice a.s. Westinghouse’s bidding competitors include AREVA, which has put forward its EPR design, and Russia’s At-omStroyExport consortium, whose bid is based on Gidropress’ MIR-1200 third-generation VVER model under construction at Leningrad Phase II and Novovoronezh Phase II. ■

—Sonal Patel is POWER’s senior writer.

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Seismic Instrumentation

at Nuclear Power Plants

When a nuclear power plant experiences ground motion due to an earthquake, an evaluation may be needed before allowing the plant to continue operating or to re-sume operating if it has been shut down, as was the case after the seismic event that shut down both units at Dominion’s North Anna Power Station on August 23, 2011. (See p. 34 for a complete analysis of the event and successful recovery pro-gram.) The Electric Power Research In-stitute (EPRI) had previously conducted research to develop guidance regarding the types of evaluations and inspections that would be necessary to ensure that an earthquake had not caused damage that could affect safe operation of a plant. More recently, EPRI has formulated guid-ance relating to the types of instrumenta-tion necessary to determine the extent of the ground motion at a plant site.

For every nuclear plant, an operating basis earthquake (OBE) has been estab-lished. The OBE has been defined such that if it can be determined that the ground motion experienced at the plant site did not exceed the design basis, the plant can continue to operate (or can return to operation if it has been shut down). If the ground motion exceeds the OBE, or if it cannot reliably be established whether the OBE has been exceeded, the plant may need to shut down and remain shut down until it can demonstrate that

the earthquake caused no damage that could affect safe operation.

Although the OBE is often character-ized in terms of a single parameter, peak ground acceleration, it is actually defined by a response spectrum. A response spec-trum relates the maximum acceleration or velocity experienced at a particular loca-tion to the frequency associated with the vibrations caused by the earthquake. The response spectrum is typically presented in the form shown in Figure 1.

Application of the Nuclear Regulatory Commission’s (NRC’s) approved OBE ex-ceedance criterion requires not only mea-surement of the OBE parameters (that is, the response spectrum and cumulative ab-solute velocity, CAV), but also walkdown inspections of the plant. CAV indicates the potential for a recorded earthquake to cause damage to nuclear plant structures. It is the absolute area under the accelera-tion vs. time plot as recorded by a time-history digital recorder.

If the OBE criterion is not exceeded and the inspections yield no evidence of sig-nificant damage, the plant can remain in operation or be restarted. Valid instrument data, available within 4 hours after an earthquake, are necessary to support such a determination. Thus, it is very impor-tant that nuclear power plants install and maintain appropriate seismic instrumenta-tion that can facilitate prompt evaluations of earthquake data.

Requirements and Options for

Instrumentation Systems

To assess whether an earthquake has ex-ceeded the OBE for a nuclear power plant, it is important for a modern, online, digi-tal seismic instrumentation system to be in place. EPRI suggests three options for a seismic instrumentation system:

■ Minimum system■ Basic automatic system■ Complete system that complies with

NRC Regulatory Guide 1.2

Minimum System. The minimum sys-tem would include one or two accelero-graphs, depending on how the OBE was defined for the plant. If the OBE had been defined in the free field, one instrument in the free field would be sufficient. On the other hand, if the OBE had been de-fined at a building location (for example,

1. Typical earthquake response. The usual form of an earthquake response spectrum

is illustrated. The plot shows maximum acceleration, velocity, or displacement caused by the

recorded earthquake at a range of frequencies associated with the vibrations caused by the

earthquake. Source: EPRI

Acc

eler

atio

n (g

)

Frequency (Hz)0.1 1 10 100

Key References

■ A Criterion for Determining Exceedance

of the Operating Basis Earthquake.

EPRI, Palo Alto, CA: 1988. NP-5930.

■ Final Policy Statement on Technical

Specifications for Nuclear Power Re-

actors. U.S. Nuclear Regulatory Com-

mission (NRC), Federal Register Notice

58FR39132, July 22, 1993.

■ Guidelines for Nuclear Plant Response

to an Earthquake. EPRI, Palo Alto, CA:

1989. NP-6695.

■ “Nuclear Power Plant Instrumentation for

Earthquakes.” NRC Regulatory Guide 1.12,

1997.

■ “Pre-Earthquake Planning and Immedi-

ate Nuclear Power Plant Operator Post-

Earthquake Actions.” NRC Regulatory

Guide 1.166, 1997.

■ “Restart of a Nuclear Power Plant Shut

Down by a Seismic Event.” NRC Regu-

latory Guide 1.167, 1997.

■ Seismic Instrumentation in Nuclear

Power Plants for Response to OBE Ex-

ceedance: Guidance for Implemen-

tation. EPRI, Palo Alto, CA: 1994.

TR-104239.

■ Standardization of the Cumulative

Absolute Velocity. EPRI, Palo Alto,

CA: 1991. TR-100082.


at the top of the basemat of the reactor containment), both an instrument at that location and one in the free field would be required.

In addition to being placed in the loca-tions at which the OBE is defined, these instruments would need to meet minimum qualifications:

■ The accelerographs would need to have battery backup, with pre-event memory sufficient to record the entire earthquake motion and a storage device that could accommodate rapid data retrieval.

■ The instruments must be digital, with a sampling rate of at least 200 samples per second.

■ The instruments would need to cover a frequency bandwidth of 0.2 to 50 Hz.

■ A stand-alone desktop or laptop com-puter equipped with software to per-form the necessary calculations on the collected data is required. The software would need to generate the CAV and the response spectra. The nature of the data retrieval and transfer to the com-puter would need to be such that the calculations could be completed within 4 hours after the earthquake.

Basic Automatic System. Improved functionality can be achieved by automat-ing certain steps that must be performed manually using the minimum seismic in-strumentation system. The basic automatic system would add a dedicated online com-puter to automatically retrieve data from the accelerographs and perform the calcu-lations related to possible exceedance of the OBE. Such a capability would expedite the process of assembling the information needed to make a decision with regard to whether a plant shutdown is required.

To upgrade from the minimum system to the basic automatic system, a dedi-cated cable would be needed from each instrument to the recording location (typ-ically, the main control room) to capture the acceleration time history. The analysis results should be displayed to the control room operators in a form that is easy to understand. An uninterruptable power source for the computer that records and analyzes the data would also be needed to ensure that the results could be available within the 4-hour timeframe.

Complete System. The complete sys-tem is the most advanced of the three. Such a system would incorporate an online

computer for data acquisition and analysis along with more extensive instrumentation. The system could be configured so that it complies with NRC Regulatory Guide 1.12. Although the minimum and basic automatic systems could facilitate short-term response, the complete system would facilitate the collection of more extensive response data from within plant structures, enabling more comprehensive long-term evaluations of the earthquake’s damage potential.

A complete system would incorporate additional accelerograph locations, rather than accounting only for the free field and the location at which the OBE is defined. Data collected from other response locations within the containment and auxiliary build-ings would provide more definitive informa-tion regarding the impact of the earthquake. The system would be fully battery-backed.

Costs of Seismic

Instrumentation Systems

The costs to implement a seismic instru-mentation system will vary from plant to plant, depending on many factors: what options are desired for the instrument, where the sensors might need to be locat-ed, and whether the instrumentation will

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augment or replace an existing instrument system. EPRI estimates the cost of the minimum system in the range of $120,000 to $180,000, the basic automatic system at $150,000 to $270,000, and the com-plete system at $225,000 to $300,000, although specific site locations could add additional cost.

A seismic instrumentation installation or upgrade at a nuclear power plant is sub-ject to certain licensing considerations. It should be noted first that voluntary im-plementation of the earthquake-response guidelines provided in the four EPRI refer-ences listed in the sidebar, including in-stalling new seismic instrumentation, does not generally require prior NRC approval.

This is a synopsis of an EPRI white paper originally published in January 2012 and available at no charge from www.epri.com. Search for document 1024889.

—Edited by Dr. Robert Peltier, PE

Maximizing Steam Turbine/Compressor Performance with Precise Torque Moni-toring at the CouplingAll turbo machinery is subject to degrada-tion that, over time, will affect the system’s efficiency and operational performance. Precise monitoring of turbo machinery per-formance with continuous torque-monitor-ing systems can be used to identify gradual efficiency loss. That, in turn, allows a more focused maintenance scope to be developed that can return the system to its optimum operation and efficiency.

Torque monitoring based on heat bal-ance, energy balance, and other methods requires measuring numerous parameters such as pressure, temperature, flow rate, and gas composition, which require high-accuracy instrumentation. However, phase displacement technology can be used to accurately measure torque directly at the coupling to within 1% of full-scale torque, a combination of all electrical and me-chanical sources of error.

Measure the Torque

A torque-monitoring system was recently installed on a cracked-gas compressor train at Qenos Olefins in Australia to de-termine the causes of a power limitation. The Kop-Flex Powerlign system installed utilizes phase displacement technology for long-term reliability, eliminating the need for recalibration.

Two rings with pickup teeth are in-stalled on a torsionally soft spacer and are intermeshed at a central location. Two monopole sensors 180 degrees apart are mounted on the coupling guard. As the

coupling rotates, the ferromagnetic teeth create an AC voltage waveform in the sen-sor coil, which is digitally processed using known calibration parameters. Because of the intermeshed pickup teeth, the system is referred to as a single-channel phase displacement system, producing two inde-pendent torque measurements (Figure 2). The Powerlign system will output torque, power, speed, and temperature, which can be easily integrated with any distributed control system (Figure 3).

At the Olefins plant the operating cycle of the steam-driven, cracked-gas compres-sor train is seven to eight years. During this cycle the plant eventually has produc-tion limitations because the compressor train encounters a power limit. “Turbine fouling” or “compressor fouling” or a com-bination of both caused the power limit. The true cause had long been the subject of an engineering debate among the Ma-chinery group, Process Engineering group, and Operations department.

The power loss was so important that the plant considered upgrading the tur-bine’s power rating from 7.5 MW to 9 MW. This upgrade would have required a capi-tal investment of $2 million, so the plant elected to defer this investment and in-stead installed a torque meter during the last eight-year major overhaul shutdown.

The installation involved replacing the existing coupling spacer and flex-ible halves with a “drop-in” torque meter and integral flexible elements (Figure 4). The torque meter assembly was dynami-cally balanced to API standards so it was not necessary for the user to return any coupling components for the retrofit. The coupling guard was modified so that the two variable-reluctance sensors could be installed, completing the mechanical in-stallation (Figures 5 and 6).

Successful Restart

The plant was restarted after completing a number of compressor efficiency improve-

2. Tracking two signals. The Powerlign system produces two independent torque sig-

nals. Source: Kop-Flex

Volt

age

4

3

2

1

o

-1

-2

-3

-4

Time

Sensor 1 Sensor 2

3. Important stats. Typical output from Powerlign system includes torque, power, speed,

and temperature. Source: Kop-Flex

Valu

e (N

-m, k

W, R

PM)

60,000

50,000

40,000

30,000

20,000

10,000

0

Time

Torque Power Speed Temp

16:3

7:11

16:4

0:42

16:4

4:12

16:4

7:44

16:5

1:12

16:5

4:43

16:5

8:13

17:0

1:44

60

50

40

30

20

10

0

Tem

pera

ture

(C)



ments during the overhaul outage. The data collected from the torque meter clearly showed the 7.5-MW steam turbine did not require an uprate and that the major power losses were coming from the compressor. The torque meter also allowed online tun-ing of the seal gas system of the compres-sor to establish the lowest power draw. The turbine load was reduced an additional 200 kW with the manual adjustments made on the seal gas system alone.

The torque meter is now being used to monitor turbine steam fouling issues and processes related to compressor fouling so that the corrective online washing can be ac-tivated as soon as performance is affected.

The historical data collected from the torque meter will also provide a baseline

of mechanical loading through the drive drain of the cracked-gas compressor over time. This data will be used to determine if increases in the maximum continuous operating speed rating of the compressor and the turbine can be accomplished at minimal cost. If so, this will increase the operating envelope of the compressor.

The value of the torque meter justi-fied installation of a second system in the plant’s second steam cracking plant tur-bine/compressor train in October 2012.

—Contributed by Daniel Phillips ([email protected]), manager, field

service engineering, Kop-Flex, Emerson In-dustrial Automation; Trevor Mayne ([email protected]), machinery engineer,

and Mark Ellul ([email protected]), an I & E specialist, for Qenos Olefins Pty

Ltd, Australia.

Measuring On-Time Completion to Improve Your EHS Audit ProgramMany companies have difficulty ensuring that issues identified during their envi-ronmental, health, and safety (EHS) au-dits get resolved in a timely fashion. This can be particularly difficult in the utility industry, where a number of different ac-tivities may be conducted at a facility, each managed by a different part of the organization (such as generation, trans-mission, and temporary storage of trans-formers brought in for repair). A number of factors promote effective and responsi-ble completion of EHS audit action plans, with the most important being the proper alignment of responsibility and authority for developing and implementing the au-dit action plan.

Measuring On-Time

Completion Performance

Generally, organizations understand the need to assign specific corrective and preventive actions to specific persons. Ensuring that the periodic review of im-plemented lockout/tagout procedures is conducted might be assigned to the facil-ity’s maintenance manager. The environ-mental manager is the probable choice for realigning written procedures for equip-ment calibration found in the continuous emissions monitoring plan with current practices. The person most closely aligned with responsibility for implementing the requirement usually ends up with the as-signment and the deadline.

But how do you ensure that the actions do get completed this time? After all, the item may have been on that person’s list all along, and somehow the responsible

person missed it. The answer is that in addition to assigning responsibility for an action to the right person, that person and his or her supervisor need to be held accountable for completing the action.

While managing an EHS audit program at a major waste and recycling services company that conducts more than 100 audits a year, the corporate managers de-vised a simple way to monitor progress on audit action plans. This successful EHS audit program is outlined in “Case Study: Browning-Ferris Industries’ Computer-ized System for Managing Audit and En-vironmental Performance” in Auditing for Environmental Quality Leadership: Beyond Compliance to Environmental Excellence, John T. Willig, Editor, 1995.

Rather than distributing lengthy reports to management describing actions planned and actions completed, EHS auditors dis-tilled their progress into one-page reports detailing completion performance, showing:

■ Total number of findings and actions.■ Number and percentages of actions

completed.■ Number and percentages of actions

completed on or before their respective target dates.

■ Short descriptions of actions that were overdue.

Quickly, and with little need for in-depth understanding of EHS requirements, senior management could review these re-ports and identify which action plans were being managed well, and which facilities needed attention and assistance. Regard-less of how many findings were identified or how many discrete actions needed to be tracked to resolve the findings, every manager could achieve a 100% on-time completion performance—if he or she managed the action plan effectively.

This approach adopts the principle learned from quality management pro-grams that things that get measured are things that improve performance. For example, the Browning-Ferris Industries’ (BFI) staff achieved a near doubling of on-time completion in the first year of measurement, improving from below 40% of the items being completed on time to a nearly 80% completion rate.

Accountability of Senior

Managers

Because supervisors and senior managers directly influence facility and local manag-ers by assigning tasks, setting objectives, and approving budgets and compensation, senior managers need to be held account-

6. Back in business. This is the com-

pleted mechanical installation of the Power-

lign system. The spacer is covered with the

shaft shield. Courtesy: Kop-Flex

4. Simple retrofit. The Powerlign sys-

tem provides accuracy to within 1% of full-

scale torque, utilizing single-channel phase

displacement. Courtesy: Kop-Flex

5. Shaft replacement. The original

shaft spacer was replaced with a Smart Spac-

er. Courtesy: Kop-Flex

DetailedDesign•EPC•CMStudies•Owner&BankEngineering

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05_PWR_110112_O&M.indd 23 10/13/12 4:57:29 PM


able for completion of EHS audit action plans as well. This was accomplished by rolling up the on-time completion perfor-mance for all the audit action plans for facilities and activities for which a par-ticular senior manager has responsibility.

Consider a senior manager who has re-sponsibility for all the service centers in a particular geographic area. That manager would receive a copy of the individual re-ports showing performance levels for all the action plans for service centers for which the manager was responsible. That senior man-ager would also receive a rating compiled from the on-time performance for all the ac-tion items for all of those service centers. The more activities and properties under a senior manager’s direction, the greater the number of audit action plan items compiled into that senior manager’s rating.

In the example shown in Figure 7, the compiled on-time completion performance for the two action plans for activities un-der the control of Senior Manager A is 100%, because all actions for both sites were completed on time. Senior Manager B, however, has an on-time completion performance of only 60%, because 5 of 10 items were completed on time at one site and 10 of 15 actions were completed on time at the other site (Figure 8). Manag-ers in the “A” grouping receive congratula-tions, while managers in the “B” grouping need assistance and/or attention.

Linking On-Time Completion

Performance to Compensation

Encouraged with the improvement in on-time completion performance that result-ed from measurement and reporting, the company linked measurement to bonus compensation to promote further improve-ments. Other operational measures deter-mined the potential bonus for a manager and the percentage of actions completed on time was then multiplied by the poten-tial bonus. Because on-time completion performance could range from 0% to 100%, managers worked hard to complete all their actions on time so they could receive their full bonus. Senior managers wanted to receive 100% of their potential bonus as well, so they made sure their facility man-agers completed their action plans on time. Predictably, as shown in Figure 9, on-time completion performance of EHS audit ac-tion plans approached 100% after being linked to senior managers’ compensation.

A concern heard too often during EHS audits of utilities is that the particular manager initially assigned to implement an action item doesn’t have responsibil-ity for certain equipment or activities. The

manager might say, “The transformer may be located on this property, but the trans-mission operations group takes care of it, not me,” or “The laboratory is managed by the shared services group. They essential-

ly lease office space from the generating plant.”

If a responsible manager can be identi-fied, then responsibility for the action item can be assigned, and, consequently, on-time

7. Perfect score. Because supervisors and senior managers directly influence facility and

local managers by assigning tasks, setting objectives, and approving budgets and compensation,

senior managers need to be held responsible for completion of environmental health and safety

(EHS) audit action plans. In this example, the compiled on-time completion performance (OTCP)

rate for the two EHS audit action plans under the control of Senior Manager A is 100%, because

all actions for both sites were completed on time. Source: Specialty Technical Consultants

Senior Manager A

OTCP = 100%

25 of 25 actions completed on time

Manager A-1

OTCP = 100%


Manager A-2

OTCP = 100%


8. Accountability is key. One of the main principles learned from quality management

programs is that things that get measured are things that can help improve performance. In

contrast to Senior Manager A (Figure 7), Senior Manager B has a low 60% on-time completion

performance rate related to EHS audit action plans because at one site under his supervision

only five of 10 items were completed on time and at another site only 10 of 15 actions were

completed on time. The OTCP rate is a signal that managers in the “B” grouping need assis-

tance to improve their EHS audit programs. Source: Specialty Technical Consultants

Senior Manager B

OTCP = 60%


Manager B-1

OTCP = 50%


Manager B-2

OTCP = 67%


9. The power of incentives. In this example, the OTCP rate of EHS audit action plans

approached 100% after being linked to senior managers’ compensation. Assessing senior

staff’s management abilities by measuring their on-time completion performance will improve

an organization’s ability to resolve audit findings in a timely and effective way and help achieve

the fundamental auditing goal of improving the organization’s overall EHS performance. Source:

Specialty Technical Consultants

Early yearsWhen linked to

compensationFirst-year

measuring

100%

80%

60%

40%

20%

0%

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completion performance can be measured to hold that manager (and his or her supervi-sor) accountable. If a management responsi-bility gap is uncovered (such as no one was assigned responsibility for the action), then the manager with authority for the property should be accountable for completing the action. This makes sense because a third party or an agency would reasonably assume that the manager who has authority over that property would also be responsible for the action related to that property.

Additional Benefits of

Measuring On-Time

Completion Performance

Audit programs that measure performance by the number and severity of findings inev-itably turn contentious. Facilities may even conceal failures to conform to approved ac-tion plans from internal auditors and thereby allow problems to continue unabated.

By measuring performance based on the ability to complete the action plan, the au-dit program profiled in the BFI case study evolved to one of resolution and improve-ment. Appropriately, pressure remained on auditors to be correct and to distinguish findings of nonconformance from opinions and improvement opportunities, but there were fewer disagreements between audi-tors and facility personnel about whether identified issues were findings to be in-cluded in the report.

With the organization focused on resolu-tion and improvement, more managers col-laborated on solutions. Whereas previously it seemed that every site was on its own, once management compensation was impacted by the on-time completion performance mea-sure, senior managers were much more likely to lend support staff, form teams, and coor-dinate budgets so as to design and imple-ment solutions that could be applied across the organization, reducing overall costs.

Regardless of whether EHS audit action plan completion performance can be linked to compensation in your organization, as-sessing your senior staff’s management abil-ities by measuring their on-time completion performance will improve your organiza-tion’s ability to resolve audit findings and help achieve the fundamental auditing goal of improving your organization’s overall per-formance in a timely and effective way. ■—Contributed by Curt Johnson (cjohnson@

stcenv.com), a senior program director with Specialty Technical Consultants (www.

specialtytechnicalconsultants.com), with more than 30 years’ experience in compli-

ance and management systems auditing and improving organizations’ EHS compli-

ance assurance systems.

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EPA’s Title V Source Policy Takes a HitBy Angela Neville, JD

Location, location, location. This has long been the guiding principle for selling real estate. Now, due to a recent appel-late case, the U.S. Environmental Protection Agency (EPA)

has learned this concept’s importance in determining under what conditions multiple facilities can be aggregated as a single source under the Clean Air Act (CAA) Title V permitting program.

The Summit Case’s BackgroundOn August 7, in the case Summit Petroleum Corporation v. EPA (Case Nos. 09-4348; 10-4572), the U.S. Court of Appeals, Sixth Circuit, vacated the EPA’s determination that a Michigan natural gas operation’s plant and production wells constituted a single major source and remanded the case to the agency for a reassess-ment of Summit Petroleum Corp.’s Title V source determination.

The case arose from the EPA’s final action determining that a natural gas sweetening plant near Rosebush, Mich., and vari-ous production wells, commonly owned by Summit and separately located, constitute a single stationary source under the Title V permitting program. The EPA had determined that Summit’s plant and wells were “adjacent” to one another, in part, because they are functionally interrelated.

Summit’s plant by itself has the potential to emit just under 100 tons of pollutants per year, which is below the threshold for being considered a major source. On the other hand, if the plant and the nearby wells are considered to be one source, their combined pollution totals exceed 100 tons and they would be classified as a major source under Title V.

Summit’s plant “sweetens” the “sour” gas from approximately 100 sour gas production wells by removing hydrogen sulfide so that the gas can be used. Summit owns all of the production wells and the subsurface pipelines that connect each of the wells to the sweetening plant. The wells themselves are located over an approximately 43-square-mile area at varying distances from the plant—from 500 feet to 8 miles away—and Summit does not own the property between the individual well sites nor the prop-erty between the wells and the plant. None of the well sites share a common boundary with each other, nor do any well sites share a common boundary with Summit’s production plant. The closest flare is located approximately 0.5 mile from the plant, while the remaining flares are each over 1 mile away.

Debate over De� nition of “Adjacent”The EPA defines a “stationary source” as “any building, struc-ture, facility, or installation” that emits or may emit a regulat-ed air pollutant under 40 Code of Federal Regulations, Section 52.21(b)(5). Multiple pollutant-emitting activities can be ag-gregated and considered a single source under a three-prong test (also known as the “Aggregation Factors”) only if they: are under common control, are located on one or more contiguous

or adjacent properties, and belong to the same major industrial grouping (such as SIC code).

The EPA explained its reasoning with respect to adjacency in making its Title V source determination for the multiple Summit facilities. Although the Summit plant and wells were separated by large distances, the agency had never established a fixed distance beyond which facilities would not be considered “adjacent.” The EPA also asserted that the “degree of interdependence” between the Summit facilities and the fact that they “together produced a single product” suggested that the facilities were not “truly independent.”

In its decision, the Sixth Circuit ruled that the EPA’s source determination regarding the Summit facilities is contrary to the plain meaning of the word “adjacent.” The court ultimately concluded that the EPA’s interpretation of the aggregation rule “undermines the plain meaning of the text, which demands by definition that would-be aggregated facilities have physical proximity.” The court vacated the EPA’s source determination and remanded the case to the EPA for reassessment “in light of the proper, plain meaning application” of the adjacency prong of the Aggregation Factors.

Moving ForwardDown the road, the EPA may seek a rehearing of the Summit case before the Sixth Circuit en banc or U.S. Supreme Court review. In the meantime, Kentucky, Michigan, Ohio, and Tennessee, located in the Sixth Circuit, are bound by the Summit case. Additionally, the Sixth Circuit’s arguments will no doubt be cited in other parts of the country in ongoing judicial and administrative matters involving Title V source designations.

The Sixth Circuit’s decision will also probably have important consequences for existing and future power plants. The threat of environmental authorities combining widely dispersed yet functionally related emission points, where ownership is the only common factor, into a single point source is unlikely to occur, given this decision.

In her dissent in the Summit case, Circuit Judge Karen Nelson Moore argued that “absent a bright-line rule as to how far is too far for numerous sources to be considered adjacent” source desig-nations based on adjacency may continue to be “subjective.”

How far is too far? This recent ruling shows that, indeed, the EPA went too far in stretching the meaning of “adjacent.” The agency needs to pay more attention to sources’ actual geo-graphical proximity to one another when determining adjacent locations for Title V permit purposes. In the future, the EPA should assume the plain meaning of the word “adjacent” as used in the CAA when aggregating sources under its permitting programs. ■

—Angela Neville, JD, is POWER’s senior editor.

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North Anna Power Station, Louisa County, VirginiaMajority owner/operator: Dominion Virginia Power

By Dr. Robert Peltier, PE

Electricity from a newly constructed

nuclear reactor has not entered the U.S.

power grid since the Tennessee Valley

Authority’s Watts Bar 1 went into service in

1996. However, the electricity produced from

reactor upgrades has added the equivalent of

perhaps eight to 10 new reactors over the past

three decades—without the enormous cost of

new construction. That’s been made possible

by modern analytic tools that permit today’s

engineers to reexamine the safety margins

used in the original design of operating reac-

tors to identify potential upgrades.

These upgrades, according to the U.S.

Nuclear Regulatory Commission (NRC), fall

within three categories:

■ Measurement uncertainty recapture (MUR)

—made possible by using better reactor in-

strumentation (up to 2% power increase).

■ Stretch power uprates—usually existing sys-

tem upgrades (up to about 7% increase).

■ Extended power uprates—require exten-

sive system upgrades and replacements

(up to 20% increase).

The nuclear industry has added 6,823

MW across its fleet through 146 approved

uprates of all types; 864 MW of uprates are

pending NRC approval; another 1,231 MW

of uprate applications are expected within

the next few years.

Squeezing Out CapacityDominion Virginia Power’s (Dominion’s)

North Anna Power Station, located 40 miles

northwest of Richmond, Va., is one of many

plants that have benefited from the NRC-

approved uprates. North Anna consists of

two pressurized water reactors that entered

service in 1978 and 1980. When constructed,

each reactor was rated at 850 MW.

Both North Anna units completed a 4.2%

stretch uprate in 1986. The NRC approved

North Anna’s recent 1.6% MUR uprate in

2009. That added more accurate means of

measuring feedwater flow to the reactor and,

therefore, a small amount of additional reac-

tor thermal power is possible. The practical

effect was that additional steam production

was possible while staying within the mea-

surement accuracy of the new instruments.

The additional steam produced means that

more power could be produced—if there

were sufficient excess capacity in the steam

turbine, generator, switchgear, other plant

equipment, and the grid interconnection.

Unfortunately, North Anna’s generators

were the limiting component, so steam tur-

bine upgrades were selected in conjunction

with a generator replacement to allow the

plant to maximize the efficient use of the ad-

ditional reactor steam production.

Major Steam Turbine UpgradeThe steam turbine upgrade to North Anna

Unit 1 was the fourth and final turbine up-

grade project completed by Alstom Power

In 2007, Dominion Resources contracted Alstom to perform

steam turbine retrofits on two generating units at its North Anna nuclear power station. The Unit 1 retrofit, with its

ongoing instrumentation upgrade, was the second to be completed at the North Anna plant and the fourth overall for Dominion. Completion of this project marked

a significant milestone in terms of both technical achievement and investment in providing clean, safe, and reliable baseload electricity for Dominion customers.

Courtesy: Dominion Virginia Power

TOP PLANTS

TOP PLANTS


for Dominion. Previously, two steam turbines

at Dominion’s Surry Power Station and the

North Anna Unit 2 turbines were upgraded

by the same Alstom project team.

The scope of the steam turbine upgrades

for Unit 1 might be described simply as re-

placing the double-flow, high-pressure (HP)

rotor and diaphragms and two low-pressure

(LP) double-flow turbines. However, the

retrofit was much more complex and chal-

lenging than an ordinary like-for-like com-

ponent replacement.

The two-section HP turbine was changed

to a more efficient single-flow turbine con-

figuration. The LP turbine was also opti-

mized for performance with much larger

last-stage blades. These modifications re-

quired installation of new turbine inner

casings and significant external extraction

piping modifications. A thrust bearing locat-

ed on the LP end handles the shaft thermal

growth movement.

The LP turbine presented what was per-

haps the greater challenge when you consid-

er that the last-stage blade length increased

from 48 to 57 inches, an 18-inch diameter

increase, while maintaining the same shaft

centerline. This much larger LP turbine vol-

ume required replacement of the entire LP

inner casings. Installation of the two new

LP turbines also required structural modifi-

cation of the unit’s LP condensers, a process

achieved with state-of-the-art computer-

guided propane torches that removed sec-

tions of structural beams to make room for

the larger LP unit casings.

Before the North Anna plant could be

upgraded with these latest advancements

in turbine technology, the project team first

had to address several significant engineer-

ing challenges.

First, a completely new high-energy pip-

ing configuration had to be designed, fab-

ricated, and installed to accommodate the

transition from a double-flow HP turbine

to a modern single-flow unit. This major

adaptation of the plant’s design required

the removal and replacement of 2,000 lin-

ear feet of piping and the replacement of

350 welds. This effort also included the

swap-out of turbine exhaust pipe that is 4

feet in diameter.

Learn by Doing—and PlanningNuclear steam turbine retrofits are, by na-

ture, big projects. The equipment is mas-

sive, as is the level of technical expertise

and collaboration required of both the plant

and supplier teams. The North Anna project

benefitted from hundreds of lessons learned

during retrofits carried out by Dominion and

Alstom on the plant’s Unit 2, and also on

Units 1 and 2 of Dominion’s Surry Power

Station. North Anna Unit 2’s upgrades were

completed during the spring 2010 refueling

outage. The Unit 1 upgrades were complet-

ed a couple of months prior to the extended

forced outage at North Anna caused by the

August 23, 2011, earthquake (see “Domin-

ion’s North Anna Station Sets Standard for

Earthquake Response,” p. 34).

Planning the choreography of labor and

equipment began over two years before the

outage began. Engineers used laser-scanning

techniques to prepare 3-D models of all of

the affected piping with millimeter accuracy.

The model was then used to guide the plan-

ning of every step of the construction work.

The result was a project construction plan

that consisted of 1,100-plus work activities

(any activities that took more than an hour)

that then had to be conformed to the planning

schedule of the plant’s refueling outage.

One of the key challenges of coordination

with the refueling work was scheduling the

use of the overhead crane. The steam tur-

bine tear-out, reconfiguration, and reassem-

bly consisted of three dozen heavy lifts of

components such as the 140-ton LP rotors

and the 35-ton new inner casings (Figure 1).

The confined nature of the work around the

steam turbine required close coordination of

craft labor. It was also constrained to a par-

ticular sequence: Casings must be installed

before rewelding the exterior piping, which

is followed by the rotor reinstall and then

the “centerline” work.

Every one of the 1,100-plus work items

was described in detail in an associated

work package that described the work to be

performed. When completed, a craft and Al-

stom shift supervisor signed off every work

package as a cross-check that the work was

properly completed. Planning meetings

were conducted at the end/beginning of ev-

ery shift, with foremen to shift managers

present to ensure there was a “hands on”

turnover, particularly with any remaining

“hot work” under way.

About 140 craft labor were assigned to

the project during each 12-hour shift, plus

those involved with quality, safety, schedul-

ing, and management. NRC work rules that

limit workers to a maximum of 72 hours per

week were rigidly followed and exceptions

required approval by the site vice president.

Therefore, a labor pool of 160 to 170 work-

ers per shift was maintained to ensure day-

off rotations.

Before work packages for the refueling

outage were completed, the steam turbine

upgrades were completed, signed off, and

the turbine was sitting on its jacking gear

ready for steam. This last of four successful

uprate projects is part of the work complet-

ed by Dominion to extend the life of North

Anna’s Unit 1 for up to another 25 years of

operation while providing a significant in-

crease in capacity.

Economic Capacity Added“When the [spring 2012 refueling] outage

is finished, the company will have added

about 234 megawatts to the Virginia elec-

trical grid” as a result of the upgrades at

North Anna and Surry, Dominion said in a

message to employees. In fact, the MUR

uprate and steam turbine upgrades have in-

creased the gross output of Unit 1 to 980.5

MWe and Unit 2’s generating capacity to

972.9 MWe, according to NRC data. Do-

minion’s peak summer capacity rating for

each North Anna unit after the upgrades is

now 943 MWe net.

The project also constituted a significant

milestone for Alstom, as the two LP units

for the North Anna 1 retrofit were among

the first delivered by the company’s new

manufacturing facility in Chattanooga,

Tenn. Alstom invested $300 million to build

the facility to serve the domestic production

needs of customers like Dominion. ■

—Dr. Robert Peltier, PE is POWER’s

editor-in-chief.

1. Heavy lifting. The steam turbine

upgrades on Dominion’s North Anna Unit

1, completed prior to the earthquake that

temporarily shut down the plant, replaced

the high-pressure and low-pressure sec-

tions with more efficient components.

Shown in the photo are workers placing

a low-pressure turbine shroud segment.

Courtesy: Alstom Power


Oconee Nuclear Station, Seneca, South CarolinaOwner/operator: Duke Energy

By Thomas W. Overton, JD

The Oconee Nuclear Station near Sen-

eca, S.C., first came online with Unit

1 in 1973; Units 2 and 3 began opera-

tion in 1974. With a total capacity over 2,500

MW, the station—now one of the oldest in the

country—has been a key element of the area

grid for almost four decades, having generated

more than 500 million MWh over its lifetime.

Oconee’s three units have a common Bab-

cock & Wilcox pressurized water reactor

design, each with a capacity of 885 MW. In

2000, the station received a license extension

from the U.S. Nuclear Regulatory Commis-

sion (NRC) that permitted operation through

2034. That, Duke recognized, meant signifi-

cant replacements and upgrades would be

required to continue operating Oconee in a

reliable, cost-efficient manner well into the

21st century.

Like every other nuclear plant built in the

U.S., the station’s original protection systems

were analog. However, over Oconee’s life-

time, the original equipment manufacturers

for the control and protection systems began

to discontinue support for their equipment.

One way or another, Duke needed to replace

it. But rather than simply upgrade with newer

analog systems, Duke made the decision to

give Oconee the first digital control system

of any U.S. nuclear plant.

Digital instrumentation and control (I&C)

systems in fossil and renewable plants are

nothing new and are now largely standard

because of the clear benefits they offer over

analog. However, regulatory concerns over

potential safety issues have slowed deploy-

ment of digital controls in nuclear plants,

particularly in safety-related systems.

In 2006, as part of the overall refurbish-

ment program, Oconee’s staff began their

effort to upgrade many of the plant’s analog

I&C systems. The projects were selected

based on their impact on plant operation.

Duke chose AREVA as the vendor for the

new I&C systems based on the success of its

Teleperm XS technology. The AREVA Telep-

erm system was designed for use in the new

AREVA EPR plants that are currently under

NRC design review, but it can also be used

for upgrades at existing plants.

One of the projects involved the digital up-

grade of the reactor protection system (RPS)

and engineering safeguards (ES) system. The

digital upgrades to nonsafety systems such as

the integrated control system could be per-

formed without modifying the plant’s exist-

ing operating license, but the safety-related

RPS/ES digital upgrade project required

NRC review and approval. After several years

Courtesy: Duke Energy

With license extensions for its three units in hand, Duke Energy’s Oconee Nuclear Station began a digital controls upgrade program in 2006, and in January 2010, AREVA became the first supplier to receive Nuclear Regula-tory Commission approval for a safety-related digital instrumentation and controls system. That set the stage for the first digital control system in a U.S. nuclear plant.

TOP PLANTS

TOP PLANTS


of planning and design, the NRC finally gave

Duke the go-ahead in January 2010, allowing

the upgrade project to move forward. With

that decision, AREVA also became the first

supplier to receive NRC approval for a safe-

ty-related digital I&C system. The upgrades

to Unit 1 were scheduled for a refueling out-

age in April-May 2011.

Core ChallengesUpgrading the RPS and ES systems was not

a job to undertake lightly. The RPS is the

key system controlling reactor operation and

safety, as it monitors inputs related to reac-

tor core operation (core power and coolant

pressure, flow, and temperature, among other

parameters), and is the system that will shut

down the reactor (by automatically tripping

the control rods) any time safe values or com-

binations of values are exceeded.

Likewise, the ES system monitors inputs—

such as coolant pressure and containment pres-

sure—that would indicate the occurrence of

certain design basis events. The ES system also

actuates safety features such as cooling water

injection, containment isolation, and contain-

ment cooling that would be necessary to prevent

damage to the plant or release of radioactivity

in the event of an accident (Figure 1).

In addition to addressing the obsolescence

of the existing analog equipment, the digital

upgrades incorporated some significant en-

hancements into the design. These included an

additional set of ES channels, which created a

fully redundant ES system. Having two com-

plete ES systems offers substantial operational

and maintenance benefits that allow staff to

perform testing and maintenance without tak-

ing reactor safety features offline.

The systems are also “smart” in the sense

that they’re capable of recognizing when a

sensor has failed or is malfunctioning. This

means that a dodgy sensor won’t cause the

reactor to trip when conditions are actually

okay. That offers significant long-term bo-

nuses for reliability and capacity factor and,

thus, revenue.

Another major benefit of the digital up-

grade project was the addition of online mon-

itoring and diagnostic capabilities, which

allow for the elimination of periodic operator

checks of system performance. This elimi-

nated the need for functional testing of the

ES system, which had to be performed online

at each unit. Elimination of online functional

testing greatly reduced the potential for in-

advertent actuation of the engineered safety

features, something that had occurred at

Oconee in the past.

In addition, reducing the need for manual

online testing meant reduced expenses and

man-hours that had previously been neces-

sary with the analog controls. Oconee was

thus able to eliminate quarterly functional

testing and daily channel checks.

Regulatory InnovationsThe changes brought about by the digital

upgrades meant that the NRC needed to de-

velop new regulatory guidance for safety-re-

lated digital applications, as the new features

and capabilities of the digital signals were

not fully addressed by existing regulations.

NRC officials worked extensively with Duke

and AREVA staff to update their regulatory

oversight during the project review. The proj-

ect team ultimately had to respond to more

than 100 Requests for Additional Informa-

tion from the NRC, and a total of more than

38,000 pages of documents were provided to

the NRC for review.

As with any digital system, cybersecurity

was a key issue. During the design and ap-

proval process, Duke and AREVA conducted

thorough reviews of the system’s ability to

mitigate communications faults between var-

ious subsystems and its ability to maintain

reliability of the safety-related functions. The

new system includes physical and software

barriers as well as defense-in-depth and di-

versity methods to provide cybersecurity for

critical assets.

The upgrades were completed and brought

online in June, and Unit 1 has since been op-

erating with no major issues. The project was

completed without a single lost-time accident

or near miss. The success of the upgrade led

the Nuclear Energy Institute (NEI) to give

Oconee its 2012 Best of the Best Top Indus-

try Practice award in May.

Leading the WayDuke has set out to share the lessons learned

by Oconee during the licensing process with

the rest of the industry in seminars, con-

ferences, and interim staff guide working

groups. These have been used to provide en-

hancements to the NRC licensing process for

digital upgrades.

“As the first plant in the nation to add this

new equipment, Oconee is demonstrating its

commitment to continuous improvement as

new systems and technologies become avail-

able,” said Oconee VP Preston Gillespie. “It’s

enhancements like these that have us well posi-

tioned to operate a safe, reliable, efficient plant

through the duration of our license extension.”

Details matter when you’re a trailblazer in

the nuclear sector. “When I look back over

the decisions of leaders that I worked for

10 years ago, who had the vision of what it

would take to install a safety-related digital

system, I stand very much in respect of what

those leaders did,” Gillespie said. “They knew

it would be hard; they knew the cost would

be great; they knew they had to find the right

partner; they knew they had to get it through

the licensing process. All of this, they knew,

would result in reliable and safe operation of

the plant. Because of that vision, the trail is

now blazed for the rest of the industry to take

advantage of the fruits of their labor.”

Upgrades to the I&C systems on Unit

3 were carried out earlier this year and are

planned for Unit 2 during a refueling outage

in 2013.

Innovation at Oconee has not been limited

to the I&C upgrade. The NEI also honored

the plant for its development, with Babcock

& Wilcox, of a robotic steam generator tube

inspection system. The single-pass, fully au-

tomated system incorporates a robot and ana-

lytical tools that enhance safety and reduce

the time and labor needed to perform steam

generator inspections. The data is so accurate

that it eliminated the need for a second, con-

firmatory analysis of the inspection results.

“These two awards recognize the achieve-

ments of the project teams at Oconee and our

corporate headquarters. Engineers, techni-

cians and others worked diligently to install

and ensure these systems functioned as de-

signed,” said Gillespie.

A video about the digital upgrades can be

viewed on the Duke Energy website at http://

bit.ly/PHG4vh. ■

—Thomas W. Overton, JD is POWER’s gas technology editor.

1. Crossing to the digital side. The digital engineering safeguards system at

Oconee (here, opened to show the incoming

power distribution wiring) manages various

safety features around the plant. Courtesy:

Duke Energy


NUCLEAR POWER

Dominion’s North Anna Station Sets New Standard for Earthquake ResponseOn August 23, 2011, at 1:51 p.m., a magnitude 5.8 earthquake knocked both

units at Dominion’s North Anna Power Station off-line—the first time such an event has occurred in the U.S. After 80 days of extensive evaluation and inspection by plant staff and representatives from the U.S. Nuclear Regulatory Commission, both units were back online. What occurred dur-ing those days is a remarkable story.

By Dr. Robert Peltier, PE

Dominion is one of the nation’s largest

producers and transporters of energy

and routinely prepares for threats to

service. But when the company’s North Anna

Power Station experienced a magnitude 5.8

earthquake—the largest ever in Central Vir-

ginia—it became the first operating nuclear

station in the U.S. to shut down because of a

temblor and the first to experience an event

that exceeded its design basis.

This event was also a first for the U.S.

Nuclear Regulatory Commission (NRC),

which would oversee remediation work af-

ter the event. Despite immense challenges,

Dominion’s disciplined culture of safety,

preparedness, operational excellence, and

transparency successfully enabled it to work

through the crisis on every level: engineering,

public, and regulatory. As a result, the units

returned to service in under three months

(Figure 1).

“Dominion’s culture is to be prepared

for emergencies,” said David A. Christian,

chief executive officer of Dominion Genera-

tion, the Dominion unit that operates North

Anna. “We understood right away this would

be a significant test. Our corporate values—

safety, excellence, doing the right thing and

teamwork—guided us in our response.” He

added, “We wanted the operations, engineer-

ing, regulatory and public response to be the

best we could possibly make it. We knew we

had the right team and the know-how—and

we knew that both Dominion’s reputation and

the industry’s reputation were on the line.”

Record-Breaking EarthquakeNorth Anna Power Station’s 1,865-MW twin

pressurized water reactors were at full power

when the quake struck on August 23, 2011, at

1:51 p.m. The quake’s epicenter was 11 miles

southwest of the station in Mineral, Va. Both

of the station’s units shut down immediately,

automatically, and safely. As a result of the

earthquake, the plant lost off-site power from

the switchyard, but back-up power from die-

sel generators picked up the load within 8

seconds, as designed. The station returned to

off-site power later that evening.

The station declared an “Alert,” the next to

lowest of the NRC’s four emergency classi-

fications. Immediately, the company focused

on ensuring that station workers and the pub-

lic were safe. Then it began a thorough plant

inspection process and proactively and trans-

parently communicated with internal and ex-

ternal stakeholders that the reactors were in a

safe and stable condition.

On the morning of August 24, North Anna

downgraded from an Alert to a Notice of Un-

usual Event, the lowest of the four emergency

classification levels, while the reactor cool-

down and inspections of plant equipment and

systems continued. The plant exited the Un-

usual Event that afternoon, after completing

all walkdown inspections of the equipment

that is most susceptible to seismic activity.

Those inspections found that the equipment

was in satisfactory condition.

Due to additional seismic activity, North

Anna declared a second Unusual Event on

August 25 following a reported magnitude

4.5 aftershock. The plant exited that Unusual

Event later in the week. North Anna again

declared an Unusual Event on the morning

of September 1 for an aftershock, exiting the

event shortly after noon that day. Over sev-

eral weeks after the initial earthquake, the

plant experienced a number of aftershocks,

none resulting in any impact to plant struc-

tures, systems, or components.

This quake was felt from the South to the

Midwest to New York City to Canada. It was

felt at 13 locations with nuclear power plants,

from North Carolina to Michigan (including

Dominion’s other nuclear power station in

Surry, Va., less than 100 miles from the North

Anna location). Apart from North Anna, each

of the affected stations notified the NRC of

the unusual event and that they had not sus-

tained any plant damage, interruption of ser-

vice, or public safety issues.

Numerous buildings in the quake area sus-

1. A day to remember. On August 23, 2011, at 1:51 p.m., a magnitude 5.8 earthquake

knocked both units at Dominion’s North Anna Power Station off-line. Although the plant did not

experience any permanent damage, the process to gain approval for restart of the two units

took 80 days. Courtesy: Dominion Generation

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NUCLEAR POWER

tained damage. Cracks even appeared in the

Washington Monument in the nation’s capi-

tal, and the rumbling of the initial shock and

aftershocks were felt throughout the Mid-

Atlantic and Northeast U.S.

It is important to recall that the Central

Virginia temblor occurred six months after

the devastating earthquake and tsunami that

crippled Japan’s Fukushima Daiichi nuclear

station. The Japanese accident caused gov-

ernments around the world to reevaluate their

nuclear energy policies, and public interest in

nuclear energy greatly intensified. This was

new and unexplored territory for Dominion

and the NRC. There was never any doubt that

the company’s first priority was to ensure pub-

lic safety. But Dominion also knew that in this

time of extreme sensitivity to nuclear energy,

the company’s response could very well set the

tone for the future of nuclear energy policy.

Dominion soon realized the company

would need to develop and obtain approval

from the NRC for the appropriate process to

restart the two units. (See the sidebar for a

summary of the steps taken to restart the two

units.) Dominion also knew that the NRC

had little experience in dealing with a nuclear

plant shutting down as a result of a beyond-

design-basis earthquake. In fact, no nuclear

unit in U.S. history had ever experienced a

shutdown caused by a temblor.

Recovery and RestorationWithin 24 hours, the company’s North Anna

Power Station restored off-site power and

exited the emergency plan after completing

all walkdown inspections of equipment most

susceptible to seismic damage. This was in

keeping with the company’s formal Corporate

Emergency Response Plan, which includes an

extensive public communications program.

No damage was reported to systems required

to maintain the station in a safe condition.

While the ground force accelerations

from the earthquake did exceed North An-

na’s licensed design basis for about 3 sec-

onds, the station—built with multiple layers

of safety—sustained no functional damage

to safety systems, structures, or compo-

nents. In fact, the extensive engineering

analysis completed by the company demon-

strated that it could have safely withstood a

quake well above that experienced.

Using an NRC-endorsed document prepared

by the Electric Power Research Institute (EPRI),

the company assessed the overall impact on the

station. On a scale from zero (where no func-

tional damage is observed) to three (where very

significant damage has occurred), the com-

pany’s detailed inspections determined that the

earthquake ranked as zero impact for North

Anna. However, to be extra thorough and safe,

the company proceeded to evaluate the station

as if the quake had an impact of one on the scale.

This required far more extensive engineering in-

spections, testing, and analysis. That decision

went a long way to establish up front that the

company would be conservative and systemat-

ic. Dominion has since been lauded by nuclear

safety experts as a prime example of an excel-

lent nuclear safety culture.

Additionally, the company immediately

brought in some of the top external seismic

experts to walk down the station and put eyes

on important adjacent structures to make sure

the station was safe and that the company

was not overlooking anything.

In the days and weeks that followed, a spe-

cial NRC inspection team, with full coopera-

tion from Dominion, thoroughly evaluated

the company’s response to the earthquake,

including initial actions by control room op-

erators to place the unit in a safe and stable

condition. They concluded that:

■ Control room operators and station em-

ployees responded to the quake as trained.

■ Safety systems engaged as designed and

expected.

■ No significant damage occurred to safety-

related systems at the power station.

Additional inspections and analysis were per-

formed by the NRC, and the company thorough-

ly documented its own inspections and analysis

and responded to every question posed to it by

NRC inspectors, engineers, and seismic experts.

Before the NRC allowed the units to restart, the

company had provided the NRC with more than

1,000 pages of documentation (Figure 2).

Examples of minor damage included non-

structural concrete cracking, insulation that

was shaken off some pipes, and broken seals on

electrical insulators attached to the main station

transformers. These were repaired or replaced

prior to restarting the units (Figures 3 and 4).

2. Rigorous inspections. Dominion visually inspected 100 feet of safety-related buried

pipe with wall thickness verified by ultrasonic measurements. Courtesy: Dominion Generation

3. Minor repairs required. The minor damage experienced by the two stations cracked

mortar and concrete. The necessary repairs were completed prior to restart. Courtesy: Domin-

ion Generation

4. Short trip. The dry casks holding spent nuclear fuel moved from 1 to 4½ inches during

the earthquake. Courtesy: Dominion Generation



NUCLEAR POWER

As the reactors were returned to service,

various measurements were taken each step

of the way toward full-power operations to

ensure that the equipment was operating as

designed. Dominion developed a special

Unit Restart Readiness Procedure—using

information from other nuclear units that

had been shut down by hurricanes, floods,

and other external events—to control restart

readiness and provide for system monitoring

and plant performance oversight. These les-

sons were blended with Dominion’s already

robust restart review and monitoring process.

System Engineering and Operations physi-

cally observed and monitored the systems

as they were placed in service, as well as the

containment building, to make sure all com-

ponents were working properly and as ex-

pected. At various phases, power escalation

was stopped so additional testing could be

performed to validate that equipment used to

measure reactor power was all working pre-

cisely. All of this was documented.

Dominion placed its greatest emphasis on

delivering the highest margin of safety and re-

liability as the North Anna units were returned

to service. This process required significantly

increased staffing, with representation from

Engineering, Operations, Outage and Plan-

ning, Maintenance, and Management onsite

24 hours a day, seven days a week.

Dominion performed additional seismic

analysis and update of licensing basis, added

a “free-field” seismic instrument in a field,

where its readings would be unaffected by

any buildings, and added an uninterruptible

power supply to one of the existing seismic

detection systems to prevent power loss.

“When the quake struck, North Anna’s

people responded as they were trained and the

safety equipment operated as it was designed

and built,” said David A. Heacock, presi-

dent and chief nuclear officer of Dominion

Virginia Power, a unit of Dominion. “They

responded with every bit the same talent and

dedication to inspect it afterwards, effect

repairs and make it ready for safely resum-

ing operation in what was really a very short

amount of time under the circumstances.”

While the nuclear industry’s standard in

evaluations of potential plant effects from an

earthquake normally focuses on design basis

ground motion response spectra—plotting

measured accelerations (Figure 5) against

shaking frequency—the latest and more so-

phisticated tool to gauge expected damage

from an actual earthquake is called “cumu-

lative absolute velocity” (CAV). CAV is the

integrated absolute value of the acceleration

time history for the earthquake. According

to EPRI, CAV provides a better measure of

the potential for damage to plant systems and

structures for a specific earthquake than does

a comparison of the experienced accelera-

tions to the design response spectra.

CAV values for the August 23 earthquake

indicated it was essentially at the level at which

no significant damage had ever been observed

for “engineered structures.” This is conserva-

tively based on an analysis of damage to struc-

tures from hundreds of earthquakes around the

world. It indicated that virtually no damage to

safety-related systems and structures should be

expected and that only very minimal damage

should occur to other components. This was

consistent with the findings of Dominion’s hun-

dreds of inspections: no significant damage to

seismically designed structures and systems or

to conventionally designed structures.

The company and the NRC conducted

thousands of inspections and exhaustive

safety analyses, including of structural com-

ponents, low-margin components, electrical

systems, the Lake Anna Reservoir, the Waste

Heat Treatment Facility, the North Anna

Dam, the Independent Spent Fuel Storage In-

stallation concrete pads and steel casks, and

fuel and reactor vessel internal inspections.

They specifically focused on potential hid-

den damage. Dominion completed:

■ 134 system inspections.

■ 141 structure inspections.

■ More than 445 surveillance tests when the

units were in a cold shutdown condition.

■ More than 29 tests after the units were heated

up to operating pressures and temperatures.

The overall effort to inspect and analyze

the thousands of structures, systems, and

components prior to returning the units to

service required more than 110,000 person-

hours and an expenditure of more than $21

million to fully ensure safety, repairs, and a

station that was demonstrated to be ready for

restart and continued safe operation.

Establishing a Protocol with the NRCBefore the August 23 quake, the NRC had

spent two decades reviewing and evaluating

U.S. Geological Survey earthquake hazard

estimates for the central and eastern U.S. All

operating nuclear units in the U.S. were built

to withstand predicted maximum earthquake

motion based on methods and techniques de-

veloped using data from the seismically active

California region. This was because compara-

tively little was known at the time about the

seismology of the eastern half of the U.S. The

NRC had earlier reviewed seismic estimates

for the central and eastern U.S. in a fact sheet

issued by the agency in May 2011.

Over the past several years, a project

jointly funded by the NRC, the Department

of Energy, and EPRI developed new meth-

odologies and data to determine the seismic

hazard for this region. The NRC acknowl-

edged in a post-Fukushima Daiichi accident

fact sheet that “seismic hazard estimates at

some current Central and Eastern U.S. op-

erating sites may be potentially higher than

what was expected during design and previ-

ous evaluations, although there is adequate

protection at all plants.”

When the quake occurred, between the

time that the earthquake hit Japan and the

growing realization that the seismic hazard

for some U.S. nuclear plants was greater than

what they had been originally designed for,

the stage was set for a potentially long and

difficult review of North Anna’s readiness for

restart. Dominion was able to demonstrate

that the proposed startup plan would lead to

safe and successful restoration of the station.

In fact, the company went beyond established

protocol to first convince itself that the station

5. Three-second ride. The intensity of the earthquake was high but exceeded the plant’s

design basis for only about 3 seconds. Source: Dominion Generation

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NUCLEAR POWER

sustained no functional damage and could be

restarted safely before presenting its finding

to the NRC, which had to give permission for

the units to return to service.

Dominion took the initiative to determine

the process, communicate the details to the

NRC and the public, systematically carry out

the plan, and, finally, present the results in a

clear, convincing manner. “The plant tells the

story,” Heacock said. “We went over North

Anna very systematically—every safety sys-

tem, structure and component—and found no

safety-related functional damage. Right from

the beginning, we decided that we would not

bring the station back up until both we and

the NRC independently were fully satisfied

as to its complete safety.”

Effective Crisis ManagementIn Dominion’s management of the restoration

effort, safety was never compromised and elec-

trical service to customers was never interrupt-

ed, even though the large generation station was

out of service for nearly three months.

Dominion followed extensive safety veri-

fications in restarting the units and worked

very closely with the NRC and other organi-

zations to involve them in the restart process

and keep them informed step by step. Ongo-

ing communications efforts included daily

internal updates through conference calls

as well as coverage in the company’s em-

ployee online Connect Today news service,

in its newsmagazine Connect, and in inter-

nal briefings. Company representatives made

presentations to civic organizations about the

earthquake and activities undertaken to re-

turn the units to service.

The NRC conducted and Dominion par-

ticipated in four public meetings—two in

Louisa County and two at NRC headquarters

in Rockville, Md. The company hosted North

Anna tours for local and national news me-

dia to show them the station and the small

amount of minor of damage incurred at the

site and to counteract any criticism and mis-

information by anti-nuclear organizations.

Coverage was local, regional, national, and

international, with company representatives

issuing no fewer than four formal media an-

nouncements and participating in several

hundred interviews.

Dominion was also proactive in com-

municating with state and local government

officials. The day after the quake, the North

Anna Power Station was visited by both Vir-

ginia Gov. Robert F. McDonnell and House

Majority Leader Eric Cantor, whose Seventh

Congressional District includes the site.

Dominion’s leadership moved the indus-

try forward. The company worked with the

NRC to establish the protocol for recovering

from a nuclear station shutdown caused by an

earthquake. The agency oversaw the process

and approved the restart within three months

of the quake. In contrast, repairs to the Wash-

ington Monument are scheduled to begin late

this year and are expected to require 12 to

18 months to complete, even though a local

philanthropist donated half the cost of repairs

shortly after the quake.

Shaping the Nuclear Power Industry’s Present and FutureAll in all, Dominion’s rapid and effective re-

sponse to the record Central Virginia quake

prevented an unreasonably extended outage.

It also avoided lingering questions about

nuclear safety and damage to the company’s

and the industry’s reputations. The company

went above and beyond regulatory require-

ments and in short, efficient order estab-

lished the safety of its units and had them

back online to produce low-cost, emissions-

free power for its customers. In the process,

it demonstrated that Dominion and the U.S.

nuclear industry are capable of handling ex-

treme, nature-induced emergencies in a safe,

effective, and transparent manner—just as

the public rightfully expects.

“Leadership in the nuclear industry can’t

be just in science, engineering and technol-

ogy,” said Christian. “A nuclear operating

company has to be able to perform across

the board, from safety and management to

financial results, from complex regulatory is-

sues to working effectively with a skeptical

and sometimes hostile news media. I believe

our results in this event demonstrated that we

were up to the challenge.”

Clearly, the events of August 23 presented a

challenge not only to Dominion but also to the

entire nuclear power industry. Dominion’s com-

mitment to safety first and the company’s lead-

ership in establishing the standards for recovery

from a crisis of this magnitude will positively

affect the future of nuclear power generation in

the U.S. and around the world. ■

—Dr. Robert Peltier, PE is POWER’s editor-in-chief. The substantial assistance provided by many Dominion employees in the preparation of this article is gratefully

acknowledged.

North Anna Power Station Restart Timeline

Aug. 23, 1:51 p.m.: A magnitude 5.8

earthquake occurs in Mineral, Va., ap-

proximately 11 miles from North Anna

Power Station. Both reactors shut down

automatically. Safety systems function as

designed to keep the reactors safe.

Aug. 29: U.S. Nuclear Regulatory Com-

mission (NRC) sends an Augmented In-

spection Team (AIT) to North Anna.

Sept. 8: At the first of what will be four

public meetings, Dominion makes an initial

presentation on the earthquake and its im-

pact on North Anna Power Station to NRC

staff in Rockville, Md. The company states

no significant damage has been found.

Sept. 30: NRC issues Confirmatory Ac-

tion Letter, stating that North Anna will

not restart “until the Commission has

completed its review of your information,

performed confirmatory inspections, and

completed its safety evaluation review.

The permission to resume operations will

be formally communicated . . . in a written

correspondence.”

Oct. 3: At the second public meeting,

the NRC’s AIT presents its report at the

North Anna Nuclear Information Center

in Mineral, Va. The NRC also announces

that it will dispatch a Restart Readiness

Inspection team to the station. The AIT

finds that Dominion responded appropri-

ately to protect the public and that the

units are safe.

Oct. 21: Dominion makes its third pub-

lic meeting appearance with the NRC, this

time in front of the NRC commissioners at

NRC headquarters in Rockville. The com-

pany confirms no functional damage was

found after more than 100,000 hours of

inspection and units are ready to restart,

pending NRC approval. The company states

that while some ground force acceleration

frequencies exceeded the station’s design

basis for about 3 seconds, the overall im-

pact to the station was well below the de-

sign basis, and the minor damage found

bears this out.

Nov. 1: The NRC has its fourth public

meeting, this time in Louisa County, to

present its Restart Readiness Inspection

Team report. Dominion confirms no func-

tional damage was found, and units are

ready to restart, pending NRC approval.

Nov. 11: Dominion receives NRC letter

granting it permission to restart North

Anna Power Station.

Nov. 15: Unit 1 is restarted and con-

nected to the grid.

Nov. 22: Unit 2 is restarted and con-

nected to the grid.

•

•

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NUCLEAR POWER

What Worldwide Nuclear

Growth Slowdown?Data detailing plans for new nuclear reactors worldwide show few effects of

the March 2011 Fukushima accident. China and Russia in particular con-tinue to be hot spots for nuclear development, but cost overruns, con-struction glitches, and ongoing safety reviews are slowing construction projects elsewhere.

By David Wagman

On paper at least, the March 2011 ac-cident at Japan’s Fukushima Daiichi nuclear power plant that followed a

devastating earthquake and tsunami barely al-tered the list of operating power reactors and nuclear projects planned for construction.

At the end of 2011, there were 435 power reactors in operation with a total capacity of 369 GWe, 2% fewer than at the beginning of the year, according to the International Atomic Energy Agency’s (IAEA’s) annual report published in August. The decrease in generating capacity was due to the permanent retirement of 13 reactors. Twelve of the 13 traced their closure to the accident at Tokyo Electric Power Co.’s Fukushima plant. The tally included four reactors at the Fukushima plant itself and eight in Germany. A 13th re-actor was shuttered in the United Kingdom due to its age.

Those closures were offset somewhat as seven new reactors were connected to the grid in 2011, an increase from five reactors in 2010, two in 2009, and none in 2008.

The IAEA said the Fukushima accident slowed nuclear power’s expansion but did not reverse it. Its post-accident projection of global nuclear power capacity in 2030 was 7% to 8% lower than what was projected be-fore the accident. The agency now expects nuclear capacity to grow to 501 GWe in 2030 in its low projection and to 746 GWe in its high projection.

Most of the projected growth will occur in countries that already have operating nuclear power plants. Countries in Asia as well as Russia are expected to be the focus of new expansion projects. Of the 64 new power reac-tors under construction at the end of 2011, 26 were in China, 10 in Russia, six in India, and five in the Republic of Korea (South Korea).

Despite these plans for new reactors, nuclear power projects face a laundry list of challenges.

French power company Électricité de France SA (EDF) said in August it will delay

construction of four planned nuclear reactors in the UK. EDF had planned to start building the first reactors next year. Published reports said EDF now plans to take time to evaluate the consequences of delays at a French reac-tor under construction in Flamanville as well as the Fukushima accident. EDF is expected to release a new timetable for the UK proj-ects this fall.

Other countries such as Belgium, Italy, and Switzerland have reevaluated their nu-clear programs since March 2011. And coun-tries such as Austria, Denmark, Greece, and New Zealand continue to exclude the nuclear power option outright.

In Asia, plans for more than 12.7 GW of new nuclear capacity in South Korea have been delayed amid Fukushima-inspired safety concerns. Korea Hydro & Nuclear Power Co. Ltd. pushed back the date for completing two reactors by at least 10

months due to a delay in government ap-proval. The reactors were first scheduled to enter service in 2016 and 2017. In addition, construction of four other reactors has been pushed back by at least one year. And plans for two other reactors have been scrapped altogether, according to local news reports quoting company officials.

In Japan, nonbinding plans (that could be reversed) were announced by the govern-ment in mid-September to phase out nuclear power by 2040. The “policy goal” called for all 50 of the country’s reactors to close once they reach 40 years in operation. In addition, no new reactors would be built. At a press briefing in Tokyo, National Policy Minister Motohisa Furukawa said, “We will introduce policies to bring nuclear power generation down to zero within the 2030s . . . so that we can build a society that does not rely on nuclear power as early as possible.” Before

1. Steady progress. The new Units 3 and 4 at Plant Vogtle are beginning to take shape. In

the foreground is the foundation for the turbine building (right) and the containment vessel (left).

In the middle of the photo are the same foundations for Unit 4. On the far left are the founda-

tions for the hyperbolic cooling towers, one per unit. In the background, the prefabrication of the

containment shells continues. The photo was taken in August 2012. Courtesy: Southern Co.


NUCLEAR POWER

the March 2011 accident, nuclear supplied

26% of the country’s electricity. Long-term

plans had been in place to raise that contribu-

tion to 53% by 2030.

Higher Costs and Delayed StartsCloser to home, the first new nuclear plants

in the U.S. in years are costing more to build

than first thought and are experiencing con-

struction delays that are pushing back their

projected in-service dates. Some plans for

new reactors have been scrapped altogether.

For example, NRG Energy wrote off a $481

million investment in two planned reactors in

Texas shortly after the 2011 Fukushima ac-

cident, citing uncertainties.

The Associated Press reviewed public re-

cords and regulatory findings and said licens-

ing delay charges, rising construction costs,

and construction errors are driving up the

costs of reactors in Georgia, South Carolina,

and Tennessee anywhere from hundreds of

millions of dollars to as much as $2 billion.

Some of the news agency’s reporting focused

on work at the Vogtle, V.C. Summer, and

Watts Bar stations:

■ Plant Vogtle. The Associated Press report-

ed that the Georgia Power–led Vogtle proj-

ect, initially estimated to cost $14 billion,

has run into more than $800 million in ex-

tra charges related to licensing delays. A

construction monitor hired by state regu-

latory authorities has said that co-owner

Southern Co. is having trouble holding to

its budget. The plant, whose first reactor

was supposed to be operational by April

2016, is now delayed seven months (Fig-

ure 1). Southern Co. and others say cost

overruns are to be expected in projects

this complex, and that overruns are bal-

anced by other savings over the life of the

plant. Southern Co. expects Plant Vogtle

will cost $2 billion less to operate over its

60-year lifetime than initially projected

because of tax breaks and historically low

interest rates.

■ V.C. Summer Nuclear Station. This South

Carolina reactor was expected to cost

around $10.5 billion but has experienced

cost increases of around $670 million, the

news agency said. Owners say the project

remains on or under budget, helped by fa-

vorable interest rates and labor costs that

are lower than expected. The first reactor’s

in-service date has been delayed from

2016 to 2017; the second reactor reported-

ly is eight months ahead of schedule with

an in-service date targeted for early 2018.

■ Watts Bar Nuclear Plant. Completing

work on the long-mothballed Watts Bar

plant in eastern Tennessee, initially bud-

geted at $2.5 billion, will cost up to $2 bil-

lion more, the Tennessee Valley Authority

(TVA) said this past spring. The utility

said its initial budget underestimated how

much work was needed to finish the plant,

and the utility wasted money by not com-

pleting more design work before starting

construction. The project had been tar-

geted to finish this year but has been post-

poned until 2015.

Another utility in line to build, Progress

Energy—which completed its merger with

Duke Energy this summer—pushed back

construction plans for two reactors in Florida

because of economic uncertainty, low de-

mand growth, and inexpensive natural gas for

power generation. Progress now expects its

first new reactor to be finished in 2024.

Meanwhile, Progress faces problems with

its existing Crystal River nuclear plant. The

reactor went offline in September 2009 for

maintenance and upgrades, but the plant’s

42-inch-thick concrete containment building

cracked during the outage. Efforts to repair

the damage cost $500 million and resulted in

more cracks. Repairing the new cracks was

first estimated to cost another $900 million

to $1.3 billion, plus more than $1 billion for

replacement power.

In early August, Duke Energy CEO Jim

Rogers said the previous high-end estimate

of $1.3 billion is likely too low. The utility

has not decided whether to repair the plant

or permanently shut it down. An indepen-

dent technical evaluation commissioned by

Duke’s board was expected to be complet-

ed in early September, Rogers told a local

newspaper. “The cost estimate is trending

higher,” Rogers was quoted as saying. “The

repair plan appears to be technically feasible

but issues remain.”

Spent Fuel Storage DilemmaFurther complicating new nuclear’s out-

look, the U.S. Nuclear Regulatory Commis-

sion (NRC) in early August put a hold on

requests for new reactor construction and

license renewals after a federal court ruling

questioned the agency’s plans for storing

spent nuclear fuel (SNF).

The NRC’s moratorium will delay almost

20 requests by utilities for new construction

and operating licenses or license renewals.

Those projects include Ameren Corp.’s bid

for a 20-year license renewal at its Callaway

plant in central Missouri, a renewal request

by the Calvert Cliffs power plant in Mary-

land, and a request by Florida Power & Light

to build two reactors at its Turkey Point nu-

clear plant south of Miami.

Some two dozen environmental groups

sought the delay after a federal appeals

court ruled in June that the NRC’s plans for

long-term storage of SNF at individual re-

actors were insufficient. The ruling came in

response to a lawsuit by attorneys generals

in New York, New Jersey, Connecticut, and

Vermont over a relicensing application for

the Indian Point nuclear plant. The federal

appeals court found that spent nuclear fuel

rods stored onsite at power plants “pose a

dangerous, long-term health and environ-

mental risk.”

The NRC sought for decades to build a na-

tional waste storage site at Yucca Mountain in

the Nevada desert, but that plan was scrapped

two years ago by the Obama administration.

A decision in August offered good news

to North America’s nuclear industry when

Canadian nuclear regulators issued a site

preparation license to Ontario Power Genera-

tion (OPG) for new reactors proposed at the

Darlington site in Ontario. The license was

the first to be issued in Canada in 25 years

and will be valid for 10 years. It means that

preconstruction activities such as clearing,

excavating, and grading the land adjacent to

the company’s existing four-unit Darlington

station can begin.

Two potential vendors are preparing de-

tailed construction plans, schedules, and

cost estimates under service agreements

signed with OPG in June. SNC Lavalin/

Candu Energy Inc. and Westinghouse have

a year to complete their reports for the En-

hanced Candu 6 and AP1000 reactor designs

respectively. The reports will be submit-

ted to the Ontario provincial government,

which will decide whether to move forward

with the project.

Planned Reactor ConstructionThe U.S. currently has 104 operating nucle-

ar reactors at 64 plants across the country.

Around half of those units are more than 30

years old. The Nuclear Energy Institute says

The U.S. Nuclear Regulatory Commission in early August put a hold on requests for new reactor construction and license renewals.


NUCLEAR POWER

19 companies and consortia are studying, li-

censing, or building more than 30 reactors.

The NRC is reviewing 10 combined license

applications from nine companies and con-

sortia for 16 nuclear power units. Even so,

work is actively under way at just a handful

of sites, and one major international nucle-

ar group—the World Nuclear Association

(WNA)—counts only the Watts Bar reactor

as currently under construction. It considers

a plant “under construction” only after first

concrete for the reactor has been poured.

By that measure, neither Vogtle unit appears

on the WNA’s tally even after three years of

work at the site.

Research by POWER on data maintained

by the WNA suggests that globally, plans

for new nuclear generating capacity rose be-

tween 2008 and 2012 despite the effects of

the worldwide economic crisis and the Fuku-

shima accident.

As Table 1 shows, almost 74 GW of

planned capacity representing 65 reactors

were added to the list of planned reactors

worldwide between 2008 and August 2012.

China added the most planned units, 27,

which if built, would add more than 31 GW

of nuclear generating capacity. (See p. 48 for

more on China’s nuclear plans.) The WNA

said China had 26 reactors under construc-

tion as of August, with a combined 27.6 GW

of generating capacity. China currently has

15 reactors in service with a combined gen-

erating capacity of 11.9 GW.

Russia increased the number of its

planned nuclear units by seven between

2008 and 2012. It now plans to build 17

reactors with a combined 20 GW capacity.

Russia has 10 reactors under construction at

present, representing almost 9.2 GW of ca-

pacity. Its installed capacity is almost 24.2

GW at 33 reactors.

WNA data show that 16 countries in-

creased the number of planned nuclear reac-

tors between 2008 and 2012. Those increases

account for 74 reactors and a combined gen-

erating capacity of more than 82.5 GW.

At the other end of the spectrum, WNA

data show that the number of planned reac-

tors fell by one each between 2008 and 2012

in South Africa, Argentina, Bulgaria, North

Korea, Japan, Brazil, the United States, and

Canada. Those losses equal around 8.7 GW

of generating capacity. Pakistan was the only

country to cut its number of planned reac-

tors by two during the four years between

2008 and 2012. It currently has no plans to

Nuclear

electricity

generation

(2011 bil-

lion kWh)

Percent-

age of

electric-

ity supply

No. of

operable

reactors

(Aug.

2012)

MWe net

capacity

(Aug. 2012)

Number of

reactors

under

construc-

tion (Aug.

2012)

MWe

gross

Number

of

reactors

planned

(Aug.

2012)

MWe

gross

Change in

number of

planned

units (2012

vs. 2008)

Change

in

planned

capacity

(2012 vs.

2008)

Change in

uranium

demand

(2012 vs.

2008 metric

tons U)

China 82.6 1.8 15 11,881 26 27,640 51 57,480 27 31,160 5,154

Russia 162.0 17.6 33 24,164 10 9,160 17 20,000 7 8,040 2,123

United Kingdom 62.7 17.8 16 10,038 0 0 4 6,680 4 6,680 -103

India 28.9 3.7 20 4,385 7 5,300 18 15,100 8 6,540 -41

Poland 0.0 0 0 0 0 0 6 6,000 6 6,000 0

Turkey 0.0 0 0 0 0 0 4 4,800 4 4,800 0

UAE 0.0 0 0 0 1 1,400 3 4,200 3 4,200 0

Vietnam 0.0 0 0 0 0 0 4 4,000 4 4,000 0

Czech Republic 26.7 33 6 3,764 0 0 2 2,400 2 2,400 -36

Bangladesh 0.0 0 0 0 0 0 2 2,000 2 2,000 0

France 423.5 77.7 58 63,130 1 1,720 1 1,720 1 1,720 -1,273

Lithuania 0.0 0 0 0 0 0 1 1,350 1 1,350 -225

Armenia 2.4 33.2 1 376 0 0 1 1,060 1 1,060 13

Egypt 0.0 0 0 0 0 0 1 1,000 1 1,000 0

Jordan 0.0 0 0 0 0 0 1 1,000 1 1,000 0

Kazakhstan 0.0 0 0 0 0 0 2 600 2 600 0

South Korea 147.8 34.6 23 20,787 4 5,205 5 7,000 0 400 858

Iran 0.0 0 1 915 0 0 2 2,000 0 100 27

South Africa 12.9 5.2 2 1,800 0 0 0 0 -1 -165 1

Pakistan 3.8 3.8 3 725 2 680 0 0 -2 -600 52

Argentina 5.9 5 2 935 1 745 1 33 0 -707 1

Bulgaria 15.3 32.6 2 1,906 0 0 1 950 -1 -950 52

North Korea 0.0 0 0 0 0 0 0 0 -1 -950 0

Japan 156.2 18.1 50 44,396 3 3,036 10 13,772 -1 -1,173 -2,933

Brazil 14.8 3.2 2 1,901 1 1,405 0 0 -1 -1,245 18

USA 790.4 19.2 104 101,930 1 1,218 11 13,260 -1 -1,740 806

Canada 88.3 15.3 17 12,044 3 2,190 2 1,500 -1 -1,800 29

World 2,518 13.5 433 371,745 65 64,979 158 175,115 65 73,720 3,375

Table 1. Nuclear remains a part of generation plans worldwide. Source: World Nuclear Association

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NUCLEAR POWER

add more nuclear power. Pakistan has two

reactors under construction with a combined

capacity of 680 MW and three reactors cur-

rently operating with a combined capacity of

725 MW.

The Fukushima accident had little effect

on the gross amount of new nuclear capacity

under construction worldwide, even in Japan,

where the accident took place. According to

WNA data in Table 2, three reactors with a

combined 3,036 MW of capacity were under

construction in Japan as of August 2012. That

was up from two reactors and a combined

2,756 MW reported in 2011. Worldwide, al-

most 65 GW of nuclear generating capacity

was under construction in August. That was

up 945 MW from 2011.

The WNA expects almost 10.6 GW of nu-

clear capacity to enter service this year (Table

3). That includes three units in India, two in

South Korea and China, and one each in Rus-

sia, Argentina, and Iran. The WNA also counts

in its 2012 total the completion of refurbish-

ment work on three units in Canada: Bruce

A1, Bruce A2, and Point Lepreau Unit 1.

Next year, some 14.9 GW of capacity

are expected to be completed, representing

13 reactors. The count includes seven re-

actors in China, two each in Slovakia and

South Korea, and one in Russia. One U.S.

completion included in the WNA’s count for

2013—Watts Bar Unit 2—is likely to slip to

2015 after TVA revised its expected comple-

tion date earlier this year.

Uranium SuppliesIncreased nuclear generating capacity seems

unlikely to tax global supply channels for

uranium. World uranium resources appear

ample to meet requirements for the foresee-

able future, but timely investment in facili-

ties will be needed to make sure production

keeps pace with growing demand, according

to a new edition of the “Red Book” published

jointly by the IAEA and the Organization of

Economic Cooperation and Development’s

Nuclear Energy Agency.

The latest Red Book edition concluded

that total identified uranium resources have

increased by more than 12% since the last

edition, which included data up to 2009. Even

so, lower-cost uranium resources were found

to have decreased “significantly” due to in-

creased mining costs. Nevertheless, with to-

tal identified resources standing at 7,096,600

metric tons (mt) of uranium (U) recoverable

at costs of up to $260 per kilogram, identified

resources reportedly are sufficient for at least

100 years of supply for the world’s nuclear

fleet. So-called undiscovered resources (de-

fined as resources thought to exist based on

existing geological knowledge but requiring

significant exploration to confirm and define

them) stand at 10,400,500 mt.

WNA data suggest that growth in global

demand for uranium for electricity genera-

tion rose 3,375 mt between 2008 and 2012,

as shown in Table 1. The increase occurred

even as Japan cut its demand for the fuel by

almost 3,000 mt over the period. That drop

was more than offset by demand growth in

China (up 5,154 mt from 2008 to 2012) and

Russia (up 2,123 mt). U.S. demand rose 806

mt and Canadian demand rose 29 mt.

The Red Book said the increase in the ura-

nium resource base stems from concerted ex-

ploration and development efforts. Some $2

billion was spent on uranium exploration and

mine development in 2010, a 22% increase

from 2008 figures, with a focus on areas with

the potential for hosting in-situ leach (ISL)

recovery operations.

The report ranked Kazakhstan as the

world’s leading uranium producer—stand-

ing at 54,670 mt in 2010—in a period when

global production has increased by more than

25% since 2008. Two countries joined the list

of those reporting uranium production fig-

ures since the previous Red Book: Malawi,

which started uranium production in 2009,

and Germany, where uranium production re-

sumed through uranium recovery from mine

remediation work.

Globally, ISL is now the dominant min-

ing method, accounting for almost 40% of

2010 production, the result of ISL produc-

tion increases in Kazakhstan. Underground

mining’s share stood at 32%, open pit mining

at 23%, and co-product and byproduct recov-

ery from gold and copper mining operations

made up 6%.

The world’s operating commercial nuclear

power reactors cumulatively required 63,875

mt of uranium per year in 2010. By 2035, this

is forecast to grow to between 97,645 mt and

136,385 mt, depending on growth scenarios.

The scenarios take into account the effects of

policies introduced by some countries fol-

lowing the March 2011 Fukushima accident.

Currently defined uranium resources are

“more than adequate” to meet the high case

demand as far out as 2035, but not without

“timely investments” in uranium production

facilities, the report said. “Significant invest-

ment and technical expertise will be required

to bring these resources to the market and

to identify additional resources. Sufficiently

high uranium market prices will be needed to

fund these activities, especially in light of the

rising costs of production,” it said.

In August, Canada’s minister of environ-

ment approved a deep open pit mine at Mid-

west, near McClean Lake in Saskatchewan.

AREVA Resources and Denison Mines are

also evaluating other potential mining meth-

ods, including conventional underground

and surface jet bore drilling, using Surface

Access Borehole Resource Extraction min-

ing technology. The deposit has indicated

resources of 16,500 mt of uranium at 4.66%

U. Milling will be at McClean Lake, 15 ki-

lometers away. There are no current plans to

start mining.

August 2011 August 2012

MWe gross

change

No. under

construction MWe gross

No. under

construction MWe gross

China 26 28,710 26 27,640 -1,070

Iran 1 1,000 0 0 -1,000

Korea RO (South) 5 5,800 4 5,205 -595

United Kingdom 0 0 0 0 0

France 1 1,720 1 1,720 0

Finland 1 1,700 1 1,700 0

Slovakia 2 880 2 880 0

Argentina 1 745 1 745 0

Brazil 1 1,405 1 1,405 0

USA 1 1,218 1 1,218 0

Russia 10 8,960 10 9,160 200

Japan 2 2,756 3 3,036 280

Pakistan 1 340 2 680 340

Canada 2 1,500 3 2,190 690

India 6 4,600 7 5,300 700

UAE 0 0 1 1,400 1,400

World 62 64,034 65 64,979 945

Table 2. Fukushima had little impact on global reactor construction plans. Source: World Nuclear Association


NUCLEAR POWER

Secondary sources of uranium (stockpiles

of natural and enriched uranium, downblend-

ed weapons-grade uranium, reprocessed

used fuel, and the reenrichment of depleted

uranium tails) will continue to be required,

although their role is expected to decline

post-2013, when agreements between Russia

and the U.S. to downblend highly enriched

uranium from nuclear weapons for use in

nuclear fuel expire. ■

—David Wagman is executive editor of

POWER.

Country Reactor Type MWe (net)

Commercial operation 2012

Argentina, CNEA Atucha 2 PHWR 692

Canada, Bruce Power Bruce A1 PHWR 769

Canada, Bruce Power Bruce A2 PHWR 769

Canada, NB Power Point Lepreau 1 PHWR 635

China, CGNPC Hongyanhe 1 PWR 1,080

China, CNNC Qinshan phase II-4 PWR 650

India, NPCIL Kaiga 4 PHWR 202

India, NPCIL Kudankulam 1 PWR 950

India, NPCIL Kudankulam 2 PWR 950

Iran, AEOI Bushehr 1 PWR 950

Korea, KHNP Shin Kori 2 PWR 1,000

Korea, KHNP Shin Wolsong 1 PWR 1,000

Russia, Rosenergoatom Kalinin 4 PWR 950


China, CGNPC Ningde 1 PWR 1,080


China, CGNPC Yangjiang 1 PWR 1,080

China, CGNPC Taishan 1 PWR 1,700


China, CNNC Sanmen 1 PWR 1,250

China, CNNC Fangjiashan 1 PWR 1,080

China, CNNC Fuqing 1 PWR 1,080

Korea, KHNP Shin Wolsong 2 PWR 1,000

Korea, KHNP Shin-Kori 3 PWR 1,350

Russia, Rosenergoatom Leningrad II-1 PWR 1,070

Slovakia, SE Mochovce 3 PWR 440

Slovakia, SE Mochovce 4 PWR 440

USA, TVA Watts Bar 2 PWR 1,180






China, CGNPC Taishan 2 PWR 1,700

China, CNNC Sanmen 2 PWR 1,250

China, CNNC Fangjiashan 2 PWR 1,080


China, CNNC Changjiang 1 PWR 650

China, CPI Haiyang 1 PWR 1,250

Finland, TVO Olkilouto 3 PWR 1,600

India, Bhavini Kalpakkam FBR 470

Japan, Chugoku Shimane 3 ABWR 1,375

Table 3. Nuclear reactor expected in-service dates. Source: World Nuclear Association

Country Reactor Type MWe (net)

Commercial operation 2014 (cont’d)

Japan, EPDC/J Power Ohma 1 ABWR 1,350

Korea, KHNP Shin-Kori 4 PWR 1,350

Russia, Rosenergoatom Vilyuchinsk PWR x 2 70

Russia, Rosenergoatom Novovoronezh II-1 PWR 1,070

Russia, Rosenergoatom Rostov 3 PWR 1,070

Russia, Rosenergoatom Beloyarsk 4 FNR 750

Taiwan Power Lungmen 1 ABWR 1,300




China, CGNPC Fangchenggang 1 PWR 1,080

China, China Huaneng Shidaowan HTR 200

China, CNNC Changjiang 2 PWR 650

China, CNNC Hongshiding 1 PWR 1,080


China, CPI Haiyang 2 PWR 1,250

India, NPCIL Kakrapar 3 PHWR 640

Taiwan Power Lungmen 2 ABWR 1,300




France, EdF Flamanville 3 PWR 1,600

India, NPCIL Kakrapar 4 PHWR 640

India, NPCIL Rajasthan 7 PHWR 640

Korea, KHNP Shin-Ulchin 1 PWR 1,350

Pakistan, PAEC Chashma 3 PWR 300

Romania, SNN Cernavoda 3 PHWR 655

Russia, Rosenergoatom Novovoronezh II-2 PWR 1,070


Russia, Rosenergoatom Rostov 4 PWR 1,200

Ukraine, Energoatom Khmelnitsky 3 PWR 1,000


Bulgaria, NEK Belene 1 PWR 1,000

China, CNNC Taohuajiang 1 PWR 1,250

India, NPCIL Rajasthan 8 PHWR 640

Japan, JAPC Tsuruga 3 APWR 1,538

Korea, KHNP Shin-Ulchin 2 PWR 1,350

Pakistan, PAEC Chashma 4 PWR 300

Romania, SNN Cernavoda 4 PHWR 655

Russia, Rosenergoatom Baltic 1 PWR 1,200


Ukraine, Energoatom Khmelnitsky 4 PWR 1,000

Notes: ABWR = advanced boiling water reactor, FNR = fast neutron reactor, HTR = high-temperature reactor, PHWR = pressurized heavy water

reactor, PWR = pressurized water reactor.


POWER IN CHINA

Post-Fukushima Nuclear Power Development in ChinaChina regards nuclear energy as a critical part of its strategic goal of achieving

sustainable economic development while reducing environmental pollu-tion. An analysis by North China Electric Power University predicts that the pace of nuclear power development may slow for a short time as a result of the Fukushima accident, but nuclear power is still a top develop-ment priority.

By Zeng Ming, Chen Li-min, Xue Song, Wei Yang, and Wang Lei, North China Electric Power University

Promoting the development of cleaner

energy has become one of the most

efficient ways of enabling energy-sus-

tainable development and mitigating environ-

mental pollution problems. Because nuclear

energy is clean and reliable, it has attracted

worldwide attention, and many countries

have made it a significant strategy in their

efficient energy production and pollution re-

duction plans. However, the nuclear incident

at Japan’s Fukushima plant caused by the

earthquake and tsunami in March 2011 sig-

nificantly slowed development of the nuclear

power industry in some countries, and others

are on course to soon eliminate nuclear pow-

er. We have investigated the short- and long-

term effects the Japanese accident has had on

development of China’s nuclear industry and

its energy strategy, particularly with respect

to China’s future plans for nuclear power and

the immediate measures the government and

energy enterprises put into practice shortly

after the earthquake.

The result of our analysis of China’s com-

mitment to nuclear power is summarized in this

article. In sum, the pace of nuclear power de-

velopment will be slowed in the short run, but

nuclear power will remain a key technology in

China’s long-term development priorities.

Historical PerspectiveIn March 2011, the Daiichi plant at Japan’s

Fukushima complex was hit by an earthquake

and subsequent tsunami, causing a leakage of

radioactivity. The accident, thought to be the

most serious recorded since the Chernobyl di-

saster, has reverberated through the global nu-

clear power industry and has forever changed

the nuclear power development strategy of

many countries.

After Fukushima, French President Nico-

las Sarkozy made it clear that France would

neither give up the exploitation and utiliza-

tion of nuclear energy nor evade any nuclear

security issue. The United States announced

that it would continue with its “nuclear re-

naissance” strategy and invest more financial

resources in nuclear energy research as well.

Conversely, Germany announced it would

temporarily shut down seven nuclear power

plants and permanently close all its nuclear

plants by 2022.

The Chinese government and its nuclear

energy experts also reexamined the future de-

velopment of nuclear power and the impor-

tant role it plays in China’s energy strategy.

With rapid economic development, many

countries, including China, are facing severe

energy and environmental stresses. In recent

years, environmental pollution and ecological

imbalance problems caused by coal, oil, and

other forms of fossil energy utilization have

become important factors restricting China’s

economic development. As a country with

high energy consumption and equally high

air emissions, China’s electricity suppliers

are facing mounting pressure to support eco-

nomic growth while also reducing emissions.

(See “China’s 12th Five-Year Plan Pushes

Power Industry in New Directions” in the

January 2012 issue of POWER, available in

the archives at www.powermag.com.)

Compared with traditional fossil energy,

nuclear power is more efficient and less pol-

luting. It is considered the most promising

form of energy to help alleviate the energy

crisis and improve the energy infrastruc-

ture, thus controlling environmental pol-

lution and climate change threats. In 2007,

China’s State Council approved the National

Development and Reform Commission’s

“Medium- and Long-Term Nuclear Power

Development Plan (2005–2020).” It outlines

China’s plans to increase the nation’s nuclear

capacity to about 40 GWe by 2020 and in-

crease nuclear’s share of total capacity to

4%. A 2007 State Council Information Office

white paper, “China’s Energy Conditions and

Policies,” further enshrined nuclear energy as

an indispensable energy option.

Nuclear Power in ChinaAs energy supply is becoming a bottleneck

restricting China’s economic and social devel-

opment, nuclear energy has become China’s

consensus choice for alleviating energy short-

ages. As early as the 1970s, the State Coun-

cil made the decision to develop the nuclear

industry. In 2004, China changed its nuclear

power development strategy from “moderate

development” to “positive development.” By

introducing technology and independent in-

novation, the production capacity of China’s

nuclear fuel cycle system continued to ex-

pand. Today, China has become one of the

few countries possessing a relatively complete

nuclear industry system and already has the

technical conditions to speed up development

of nuclear power. The following sections ex-

amine key characteristics of China’s nuclear

power development program.

Installed Capacity. The first nuclear reac-

tor put into commercial operation was Unit

1 of Qinshan Nuclear Power Plant, built in

1991, with a net installed capacity of 279

MWe (Figure 1). Since 2000, China’s nuclear

development plan has been to develop “in-

stalled capacity 40 GW, and under construc-

tion 18 GW by 2020,” directed by the policy

of “promoting the development of nuclear

power actively.” With financial and political

support, the bulk of new nuclear power sta-

tions have been recently built in Guangdong,

Zhejiang, Liaoning, Fujian, and Shandong

coastal areas. Driven by massive electric de-

mand, nuclear power stations also have been

constructed in Hubei, Hunan, Jiangxi, Anhui,

Sichuan, Chongqing, and other inland prov-

inces, breaking the pattern of building nuclear

power stations only in coastal areas.

By the end of 2010, the total capacity of

the 13 generation units in operation was more

than 10 GW, and the capacity of the 32 gener-

ation units under construction was more than

30 GW. Still, there are more than 30 stations

with almost 100 generating units pre-planned


POWER IN CHINA

or waiting for approval. The nuclear reactors

built or under construction in China are sum-

marized in Table 1.

According to data from the International

Energy Agency (IEA), by the end of January

2011 there were 442 nuclear power units in

operation around the world, mainly distrib-

uted in North America, Asia, and Europe, ac-

counting for 16% of the world’s total power

production (see “What Worldwide Nuclear

Growth Slowdown?” p. 42). There also were

65 units under construction, including China’s

30 units. At present, there are 14 nuclear re-

actors in operation in China, with a total net

installed capacity of 11.169 GW, accounting

for 1.16% of China’s total installed capacity,

with its power production equivalent to 31.72

million tons of coal.

According to data from the China Electricity

Council and the “Medium- and Long-Term Nu-

clear Power Development Plan,” China’s nuclear

power installed capacity currently ranks 11th in

the world. China will maintain a steady growth

rate in the next decades, reaching an estimated

86 GW by 2020, an average annual growth rate

of 6.5 GW, 2.5 times the total of 2.6 GW placed

in operation from 2002 to 2007, ranking the first

in the world. China’s new added nuclear capac-

ity in operation and the installed capacity fore-

casts are shown in Figures 2 and 3.

Power Production. Nuclear electricity

production accounted for 15.5% of the world’s

total electricity production in 2010. For indi-

vidual countries, France produces 75.9% of its

electricity using nuclear energy, followed by

the Ukraine (47.3%), South Korea (29.9%),

and Japan (26.0%), according to the IEA’s Key

World Energy Statistics 2012.

In China, the power system remains highly

dependent on thermal power plants. Though

the total production of hydropower, nuclear

power, and wind power has increased more

than sevenfold from 1985 to 2009, thermal

power still accounts for 78% of the total elec-

tricity produced in China (see “China’s Power

Generators Face Many Business Barriers,” in

the September 2012 issue).

With its shortage of coal resources, devel-

oping clean energy like nuclear power has

become one of the key measures to realizing

China’s sustainable development goals. As

shown in Figure 4, in the past nine years nucle-

ar power production in China shows a grow-

ing trend and reached 87,400 GWh in 2011.

However, this accounts for just 1.85% of total

power production at present—a level that still

lags behind the level of developed countries.

Even so, the combined capacity of reactors

under construction, planned, and proposed in

China amounts to 184,540 MWe, accounting

for 32% of the world total and ranking first in

capacity, offering China the most potential to

develop nuclear power in the future.

Development Plans. In general, future

nuclear projects approved are mainly coastal

and expansion projects. In 2020, the construc-

tion of AP1000 units is expected to account

for about 30%, and the capacity of “second

generation” units will still account for more

than 50%. Based on the “Medium- and Long-

1. China’s first reactor. Qinshan Nucle-

ar Power Plant Unit 1 was the first nuclear plant

designed, constructed, operated, and managed

by China. The 310-MW Unit 1 entered service

in 1991. Four additional units have since en-

tered service on adjoining sites, with the sixth

unit expected to complete construction the

end of this year. Three additional units are un-

der construction. Courtesy: China Guangdong

Nuclear Power Holding Co., Ltd.

Plant Location

Reactor

design Units

Rated

power

(GW)

Designed

lifetime

(years)

Investment

(billion RMB)a

Construction

start

(year.month)

Qinshan I-1 Zhejiang CNP300 1 0.30 30 1.2 1985.3

QinshanII-2 Zhejiang CNP600 2 0.65 40 14.8 1996.6

Qinshan II-3 Zhejiang CANDU6 2 0.73 40 2.6 1998.6

Daya Bay Guangdong M310 2 0.98 40 4.0 1987.8

Lingao 1 Guangdong CPR1000 2 0.99 60 4.0 1997.5

Tianwan 1 Jiangsu AES+91 2 1.06 40 3.2 1999.1

Qinshan II-2 Zhejiang CNP600+ 2 0.65 40 14.4 2006.4

Lingao 2 Guangdong CPR1000 2 0.99 60 26.0 2005.12

Hongyanhe Liaoning CPR1000 4 1.00 60 48.6 2007.8

Ningde 2 Fujian CPR1000 4 1.00 60 49.0 2008.2

Fuqing 1 Fujian CPR1000 2 1.00 40 26.7 2008.11

Yangjiang 1 Guangdong CPR1000 6 1.00 60 74.0 2008.12

Fangjiashan Zhejiang CPR1000 2 1.00 60 26.8 2008.12

Sanmen1 Zhejiang AP1000 2 1.25 60 40.0 2009.4

Taishan 1 Guangdong EPR 2 1.75 60 50.0 2009.12

Haiyang 1 Shandong AP1000 2 1.25 60 43.0 2009.12

Shidao Bay Shandong HTGR 1 0.20 40 3.0 NA

Changjiang 1 Hainan CNP600+ 2 0.65 40 16.0 2010.5

Fanchenggang Guangxi CPR1000 2 1.00 60 25.6 2010.7

Total 44 17.45 440.0

Table 1. Nuclear plants in service or under construction in China. Source: China Guangdong Nuclear Power Holding Co., Ltd.

Notes: a. RMB = $0.16. NA = not available.

2. New nuclear capacity addition amounts and growth rate of new nuclear construction. Source: China

Electricity Council

16

14

12

10

8

6

4

2

0

200%

150%

100%

50%

0%

-50%2010 2012E 2014E 2016E 2018E 2020E

Mill

ion

kW

New capacity Growth rate

3. Total installed nuclear capacity by year and total nuclear capacity growth rate. Source: China Electricity

Council

100

80

60

40

20

0

60%

50%

40%

30%

20%

10%

0%2010 2012E 2014E 2016E 2018E 2020E

Mill

ion

kW

Installed capacity Growth rate


POWER IN CHINA

Term Nuclear Power Development Plan,” Chi-

na’s nuclear power development will maintain

a rapid growth rate into the future.

Since 2005, Guangdong, Zhejiang, Lia-

oning, Fujian, Shandong, and other coastal

provinces in China have accelerated the pace

of nuclear power development. Moreover, Ji-

angxi, Hunan, Hubei, Anhui, Jilin, Chongqing,

Henan, and other central provinces are also

actively implementing nuclear power projects

driven by surging power demand in each re-

gion. In China, nuclear power development in

inland and coastal cities will occur simultane-

ously, forming an “east-central nuclear belt”

(Figure 5).

4. Nuclear power production in China during the period 2003–2011. The absolute amount of nuclear-generated

electricity is growing rapidly in China. Source:

China Electricity Council

900

800

700

600

500

400

300

2003

2004

2005

2006

2007

2008

2009

2010

2011N

ucle

ar p

ower

pro

duct

ion

(x10

0 G

Wh)

Year

5. Nuclear power in China. Illustrated are the locations of plants pre-planned, approved,

under construction, or in operation. Source: Department of Environmental Protection of Nuclear

and Radiation Safety Center

Nuclear power plants in operation

Nuclear power plants under construction

Nuclear power plants approved

Nuclear power plants pre-planned

Covering over 34.000 generating units from over 160 countries and territories

This unique database globally covers over 34,000 installed or projected generating units including details as geographic location, capacity (MW), age, technology, fuels, boiler, turbine, generator and emissions control equipment. You also gain access to over 4,200 plant management and support contacts including titles and job functions. This data set comes in Microsoft Excel, an easy to use application that allows you to manipulate data and import easily into your own database.

TO DOWNLOAD A FREE SAMPLE ONLINE, VISIT WWW.PLATTS.COM/PRODUCTS/UDICCGT

2012 Combined-Cycle/Gas Turbine Dataset


POWER IN CHINA

In recent decades, China has accumulated

a wealth of experience in nuclear power de-

velopment in engineering design, equipment

manufacturing, construction, operation, and

management, cultivating a great number of

technology and management personnel with

high professional standards and practical

experience. This is especially important for

the introduction of third-generation Chinese

nuclear power technology and increasing the

proportion of local nuclear power equipment.

Nuclear fuel procurement is also an im-

portant part of China’s accelerating nuclear

program. More than 200 uranium mines have

been identified in Jiangnan, Qinling, Tianshan

Mountain, Qilian, Yanliao, western Yunnan,

and other regions in China, with total proved

reserves of 44,000 metric tons (t), accounting

for about 2% of the world’s total reserves, ac-

cording to the International Atomic Energy

Agency. However, China’s uranium output

has always been at low levels, even declining

at times compared with several years ago. In

2008, China’s uranium output was merely 769

t, and the shortage was met largely through

imports from Kazakhstan, Russia, Namibia,

and Australia.

China’s Post-Fukushima ResponseThe March 2011 Fukushima accident brought

the issue of nuclear power security and sus-

tainability to worldwide attention. With nearly

40% of the world’s nuclear reactors under

construction in China, the focus of China’s

nuclear development strategy is to learn les-

sons from this event and ensure the same mis-

takes aren’t repeated in China. Some of the

measures taken in China are described below.

Make Policy Shifts. On March 16, 2011,

Premier Wen Jia-bao presided over a State

Council executive meeting that decided to or-

ganize immediately a comprehensive safety

inspection of all nuclear facilities. Specifi-

cally, it was decided that safety management

of the nuclear facilities in operation should

be strengthened, new nuclear power projects

should undergo a more strict approval process,

and nuclear safety plans and a medium- and

long-term nuclear development plan should be

drawn up and improved as quickly as possible.

The meeting also determined that approval of

all the new nuclear power projects, including

those with preparatory work already carried

out, should be suspended until the nuclear

safety plan is established. In short, measures

should be taken to ensure the absolute safety

of nuclear power development.

On the same day, China’s Environmental

Protection Department issued new regula-

tions for environmental radiation protection of

nuclear power plants, which defined the nec-

essary site conditions for new nuclear power

plants. According to the new regulations,

environmental characteristics such as geol-

ogy, earthquakes, and other potential hazards

caused by nature or by humans should be con-

sidered when evaluating a site’s suitability for

a nuclear plant.

Develop New Regulations. To perfect

nuclear safety laws and regulations, China is

speeding up legislative work on the Atomic

Energy Act and its supporting regulations, for-

mulating and perfecting management methods

related to scientific research, exploitation, and

construction, as well as the safety of nuclear

power and nuclear fuel industries. Meanwhile,

the market access system of uranium explora-

tion and mining will continue to be perfected.

Also, the qualification system for production

and services—such as for nuclear fuel puri-

fication, conversion, concentration, elements

processing, reprocessing, waste treatment, and

decommissioning—will be enhanced.

In the future, China will consider nuclear

safety and reliability as top issues in the nucle-

ar power development process. To ensure the

quality and safety of nuclear power construc-

tion, China is devoted to establishing com-

plete regulations and rules for nuclear power

safety, thus forming a complete set of nuclear

power safety supervision systems, environ-

mental protection supervision systems, and

nuclear power emergency response systems.

With these regulations and the organization

systems, China will be able to take a compre-

hensive approach to site selection, design, and

construction of nuclear power plants.

Implement Technical Innovation. In the

final analysis, Japan’s nuclear accident was

a technology and design problem. After the

shock, the first response of the Fukushima

safety systems was normal: first, the safety

shutdown system was triggered even as the

self-contained emergency generator started

to help discharge the core’s residual heat. But

in less than an hour, a tsunami caused by the

earthquake destroyed the emergency response

power generation system, resulting in a reactor

explosion. However, a second-generation nu-

clear power plant whose active safety systems

are supported by external power are not com-

parable to China’s third-generation AP1000

plants under construction that have passive

safety systems. This plant design would not

have experienced the nuclear leakage events

like those at Fukushima, even faced with the

additional effects of earthquake and tsunami.

To ensure nuclear safety, several countries’

well-developed nuclear power programs have

already started fourth-generation nuclear

power reactors with even higher safety perfor-

mance levels, and so has China. Furthermore,

China will accelerate construction of large-

scale advanced pressurized water reactors and

promote pressurized water reactor and fast

reactor technologies, as well as research and

development on advanced nuclear fuel cycle

core technologies. The largest energy project

in China’s 863 projects—the “China experi-

mental fast reactor”—reached critical condi-

tions for the first time, indicating that China

has basically mastered the key technologies of

fourth-generation nuclear power systems, the

world’s eighth country that has mastered fast

reactor technology.

Cultivate New Nuclear Talent. The scale

of China’s nuclear construction ranks it as

first in the world, which requires a very well-

trained workforce. National Defense Technol-

ogy Industry Ministry statistics show that if a

million-kilowatt-class (1 GW) nuclear power

plant needs 400 workers, then more than

12,000 workers will be needed for 30 GW of

new nuclear power plants by 2020. Because

the personnel training cycle is long and the

modes of training and practical application

don’t match well, students cannot adapt to the

fast development of nuclear power.

In order to speed up the cultivation of nu-

clear talent, China has established nuclear en-

ergy training programs in many colleges and

will provide financial support for universities

that have nuclear power programs.

Implement Daily Supervision Manage-

ment Measures. The earthquake was not the

only factor that raised concern following the

Fukushima nuclear accident; problems such

as aging facilities should also be considered.

In China, there are 13 nuclear power plants

in operation. Although strict monitoring and

maintenance mechanisms were established,

cautious attitudes should be kept to ensure that

problems are solved as they are found. At the

same time, the government should strengthen

the popularization of nuclear safety knowl-

edge and perform training exercises regularly.

All the measures and policies discussed

above are aimed at avoiding an accident simi-

lar to what happened in Japan, or to at least

minimize losses if an accident does occur.

China has learned lessons from the Fukushi-

ma accident.

What Will Be Fukushima’s Impact on China’s Nuclear Industry?Some of the effects of Fukushima on China’s

nuclear program were felt immediately, but

the long-term goals of the program remain

unchanged.

Some Short-Term Impact. China has

temporarily slowed the speed of construction

of nuclear power stations and has reexamined

its safety programs. In addition, it has changed

the development strategy of nuclear power

from “positive development” to “safe devel-

opment.” Specifically, on March 16, 2011, the

executive meeting of the State Council noted

that all project approvals should be suspend-

ed until a nuclear safety plan could be put in


POWER IN CHINA

place. As a result, new nuclear power projects cannot be carried out and

the timing of nuclear power development goals will be delayed, which

will also influence the realization of the nuclear power planning goal

in China’s 12th and 13th Five-Year Plans. Simultaneously, the nuclear

power plants approved as part of the 12th Five-Year Plan will be re-

vised to consider more safety factors. In addition, China will reconsider

locating nuclear power plants in central China, and the nuclear power

plant sites in Hunan, Chongqing, Shanxi, and Gansu Provinces will be

reevaluated to determine if these regions have ever experienced earth-

quakes or are prone to earthquakes.

On the other hand, nuclear power won’t replace traditional energy

in the short term. China’s economy is in an industrializing stage and

requires large energy supplies, causing high energy demand growth.

Traditional fossil energy, especially coal and oil, will still be the main

energy sources. Meanwhile, the development of the natural gas and

renewable energy industries will also enjoy high growth. However, it

is hard to change the basic pattern of any country’s energy use over-

night. So, in the short term, nuclear power will remain a small part of

China’s overall energy supply.

Though Japan’s nuclear accident further strengthened the concept

of “safety first,” it doesn’t change the medium long-term strategy of

China’s nuclear industry. China’s goal to reduce the use of fossil fu-

els, meet energy conservation goals, and reduce air emissions requires

long-term development of nuclear power.

Continue to “Actively Promote” Nuclear Industry. Shortly af-

ter the Fukushima nuclear crisis happened, the State Council required

a comprehensive safety inspection of all nuclear facilities and limited

the project approval to strengthen safety management; thereafter, all

nuclear power construction will return to normal.

The long-term goal of China’s nuclear industry is to actively

promote nuclear power construction based on safety, a unified de-

velopment route, economic efficiency, an insistence on a strategy of

“self-independence and Sino-foreign cooperation,” the import of ad-

vanced technology from abroad, and realizing innovation and auto-

mation of key nuclear power technologies.

Slowed Pace of Investment. In the past few years, nuclear

power development in China has seen rapid growth. Since 2005, 13

nuclear power projects and 34 nuclear power units were approved

for construction, totaling 37.02 GW. So far, 30 units have been con-

structed, and the capacity under construction is over 30 GW, which

accounts for about 40% of the world’s total. However, the nuclear ac-

cident in Fukushima led to the suspension of nuclear power projects

and thus affected the confidence of investors, causing an investment

slowdown. In the long term, China will still adopt a positive attitude

towards nuclear power development, but restoring investors’ confi-

dence will take some time.

No Impact on Energy Strategy. In terms of energy policy and

strategy, nuclear power still plays an important role. According to the

12th Five-Year Plan, 40 units will be constructed by 2015. Though

the Fukushima accident affected China’s nuclear industry to a certain

extent and prompted additional improvements in the management of

nuclear power projects, fundamentally, the general direction of Chi-

na’s energy policy will not change. China will still give a high priority

to the development of the nuclear industry in the long run.

With technology improvement, nuclear power is competitive

with traditional energy resources. Also, the security and reliability

of nuclear power are under the double protection of technology and

policy, and uranium resources can meet the basic needs of nuclear

power. So in China, it’s a wise choice to develop nuclear power

and let it replace coal power gradually. The economic efficiency of

nuclear power plants and coal-fired power plants in different coun-

tries is shown in Figure 6.

Final ThoughtsJapan’s nuclear disaster has influenced recent changes in the global nu-

clear power industry. For China, the change has been from “moderate

development” to “positive development,” and now from “positive devel-

opment” to “safe development.” All of China’s nuclear power plants are

designed to ensure the safe, clean, and efficient use of nuclear energy. ■

—Zeng Ming, Chen Li-min, Xue Song ([email protected]), Wei Yang, and Wang Lei, North China Electric Power University,

Beijing, China. The work described in this paper was supported by The Energy Foundation (G-1006-12630).

6. Nuclear vs coal plants. The horizontal axis represents the ratio

of plant investment, fuel costs, and production costs of nuclear versus

coal-fired power plants. Source: Liang X., Qiu A., Sun C., 2009. “China

Electrical Engineering Canon,” China Electric Power Press, pp. 115–118.

Investment (nuclear/coal-fired) Fuel costs (nuclear/coal-fired)

Production costs (nuclear/coal-fired)

0 1 2

Germany

France

Belgium

Hungary

Russia

Japan

Korea

Canada

United States

China

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WATER & POWER

Potential Impacts of Closed-Cycle Cooling Retrofits at U.S. Power Plants The Clean Water Act Section 316(b) rule changes regarding cooling water in-

take structures that are expected next year could affect up to 428 power plants, representing 1,156 individual units, according to the Electric Power Research Institute. Depending on plant size and the complexity of the ret-rofit project, retrofit capital costs could range from very low to over $500 million for large nuclear plants. The power industry total cost is projected to be over $100 billion.

By David Bailey, Electric Power Research Institute

Power plant owners face numerous chal-

lenges ensuring adequate water supplies

for operations while protecting aquatic

life in the water bodies that provide power plants

with cooling water. In the U.S., Section 316(b)

of the Clean Water Act requires plant owners to

minimize the adverse impacts of impingement

and entrainment mortality by potentially install-

ing fish protection technologies on cooling wa-

ter intake structures. The U.S. Environmental

Protection Agency (EPA) is finalizing regula-

tions under Section 316(b) that may require in-

stallation of cooling water intake fish protection

technologies or potential retrofit of closed-cycle

cooling systems (cooling towers).

On April 20, 2011, the EPA released a pro-

posed rule implementing the requirements of

Section 316(b) for existing facilities. In the

proposed rule, the EPA noted that closed-

cycle cooling systems were not a best tech-

nology available (BTA) for reducing adverse

impacts of cooling water intake structures;

however, entrainment standards developed on

a site-specific basis could require retrofits of

closed-cycle cooling systems. Furthermore,

although the EPA rejected closed-cycle cool-

ing as BTA and selected a regulatory option

that provides for site-specific development of

entrainment standards for protecting aquatic

life, it did consider two options that included

requirements for closed-cycle cooling, and one

of these options could be adopted for the final

rule, scheduled to be issued in June 2013.

EPRI recently completed a study of the

estimated costs, benefits, impacts, and en-

vironmental consequences of a potential na-

tional requirement to retrofit cooling towers

on all once-through facilities in the U.S. The

estimated costs exceed $100 billion on a net

present value basis.

Research ApproachA first key step in the research was to devel-

op an accurate list of once-through facilities.

EPRI’s initial draft list was developed with

information from the EPA and the Depart-

ment of Energy. EPRI then sent the draft list

to the electric industry for review and veri-

fication. EPRI also contacted some facilities

directly to seek clarification on plant- and

unit-specific operational status.

A spreadsheet model was developed to esti-

mate the cost to retrofit 125 facilities based on

existing cost estimates and a worksheet com-

pleted by facility owners. These 125 estimates

were then extrapolated to generate the national

retrofit cost estimate for all nuclear and fossil

generating stations. The study results provided

input for an economic model used to estimate

the number of units and megawatts at risk of

premature retirement if they were required to

retrofit closed-cycle systems. The model input

parameters included unit-specific capacity uti-

lization and hourly dispatch power generation

market information.

Results of this analysis were then used to

estimate the potential risk of localized elec-

tric system security or overload violations

as a result of unit retirements. A methodol-

ogy to quantify the environmental and social

impacts of retrofitting facilities with wet

mechanical-draft cooling towers was also de-

veloped and submitted to the EPA for review.

With the exception of a single natural draft

tower, mechanical-draft towers have been

used exclusively for wet closed-cycle cool-

ing for the last two decades and were the as-

sumed retrofit choice in our study.

The study also evaluated potential impacts

associated with salt drift, human health ex-

posures, public safety, noise, aesthetics, and

terrestrial and wildlife changes. Based on a

literature review and modeling of 26 repre-

sentative facilities, impacts were qualitatively

discussed, quantified, and/or monetized. The

quantified and monetized results were then

extrapolated to a national scale for compari-

son to the cost and benefits of retrofits.

To estimate the national economic benefits

of closed-cycle cooling retrofits, a three-tiered

approach was used. In Tier 1, the economic

value of commercial and recreational losses

was either acquired or generated based on

EPA methods. In Tier 2, the same losses were

estimated based on acceptable correlations

between impingement and entrainment loss

data for those facilities that entered data in

the EPRI Impingement and Entrainment Da-

tabase. In Tier 3, estimates were based on the

relationship between cooling water flow and

data from facilities that had conducted im-

pingement and entrainment studies for various

water body types and U.S. regions.

Study ResultsThe EPRI report examined the impact of the

proposed 316(b) rule in terms of the cost of

the retrofits, financial impact to ratepayers,

impacts to the electric system, other adverse

environmental impacts, and an evaluation of

the costs relative to benefits for a rule that

requires closed-cycle cooling retrofits.

Cost of Retrofits. EPRI identified 428

facilities that use greater than 50 million gal-

lons per day (mgd) of once-through cooling

water, representing approximately 312,000

MW of electricity: 60,000 MW from the

39 nuclear facilities and 252,000 MW from

the 389 fossil facilities. While closed-cycle

cooling is commonly employed for new

generating facilities, the cost of retrofitting


WATER & POWER

existing facilities can be significantly higher

due to 11 factors:

■ Availability of suitable on-site tower

location

■ Distance from turbine/condenser to tower

location

■ Site geological conditions (rock? soft

sand? wet?)

■ Existing above-ground or underground in-

frastructure

■ Need to reinforce existing condenser and

water tunnels

■ Need for tower plume abatement

■ Potential impact of on- or off-site salt drift

■ Need for noise-reduction measures

■ Use of alternative sources of cooling tower

makeup water

■ Modifications to plant equipment (such as

auxiliary cooling systems)

■ Condenser reoptimization

Based on these factors, the capital cost to

retrofit once-through cooled units with wet

mechanical-draft cooling towers was esti-

mated to be $42.4 billion for the 389 fossil

facilities and $19.6 billion for the 39 nuclear

facilities (Table 1). Also estimated were the

annual cost of power to operate the cool-

ing tower fans and pumps ($427 million for

fossil facilities and $141 million for nuclear

facilities) and the cost of reduced generation

output due to the loss of plant efficiency with

closed-cycle cooling systems compared to

once-through systems ($527 million for fossil

and $182 million for nuclear facilities).

Additionally, many facilities would incur

a significant loss of revenue due to extended

outages that would be required, estimated at

$9 billion for fossil facilities and $8.3 billion

for nuclear facilities. The significantly great-

er proportional cost for the 39 nuclear facili-

ties results from the fact that nuclear units are

baseloaded with an average capacity utiliza-

tion on the order of 90% compared to fos-

sil units, some of which operate in peaking

mode and thus have much lower capacity fac-

tors. The total estimated present value costs,

assuming all once-through cooled facilities

were to retrofit, was over $95 billion for the

fossil and nuclear facilities.

Individual facility costs that were not includ-

ed in the study were permitting costs, costs for

labor and chemicals to operate and maintain the

cooling towers, and the cost of capital to finance

construction. The study also estimated that up

to 5% of the fossil generation capacity (15,600

MW) was at risk of premature retirement due to

inadequate space to install closed-cycle cooling

or the inability to acquire the necessary envi-

ronmental permits to construct cooling towers.

Financial Impact. An important area of un-

certainty is the actual number of facilities and

the associated MW generation that might be

retired if they were required to retrofit. Many

of the older fossil facilities have low capacity

utilization and, due to economic inefficiency,

may operate only for a few weeks or months

per year during periods of peak power demand.

Installation of closed-cycle cooling would fur-

ther reduce efficiency, with the result that many

older units may retire for economic reasons

rather than retrofit.

In some cases, retirements may require the

addition of new generation capacity, adding

to the cost of a national requirement to retrofit

with closed-cycle cooling.

The study estimated that about 26,000

MW of generation were at risk of premature

retirement for economic reasons, and the im-

pact varies among North American Electric

Reliability Corp. (NERC) Regions (Table 2).

The study then focused on five NERC Re-

gions: PJM, New England ISO, New York

ISO, ERCOT, and MISO. A modeling analy-

sis of those regions determined that PJM and

MISO had adequate new generation coming

online to meet reserve margins. However,

new unplanned generation would be required

for ERCOT (5,683 MW), ISO New Eng-

land (2,640 MW), and New York ISO (3,441

MW). The cost of new replacement genera-

tion was estimated to be just under $7 billion,

bringing the cost of a closed-cycle cooling

requirement to over $100 billion.

Impacts to the Electric System. The

study identified some 42,000 MW at risk of

premature retirement (26,000 MW of fossil

generation due to financial impacts and 15,600

MW—5% of the fossil units—due to lack of

space to accommodate cooling towers or be-

cause of permitting issues).

Researchers modeled the potential power

system impacts of eliminating units in PJM,

New England ISO, New York ISO, ERCOT,

and MISO (those evaluated in the financial im-

pacts study). The model results found there is a

potential risk of localized security and/or volt-

age violations in each of the five regions. The

result is that there would be an additional cost

that was not quantified to install electric system

upgrades in these localized areas in order to

maintain electric system reliability.

It is important to note that modeling poten-

tial reliability impacts has a very high level of

uncertainty. One key factor is that once one

company makes a decision to retire a unit, it im-

mediately impacts the economics of other units,

decisions on planned electric system upgrades,

potential unit retirements, and new generation.

Thus, although modeling indicates potential for

voltage and security impacts to the system, the

precise location of those effects cannot be reli-

ably predicted.

Adverse Environmental Impacts. The re-

search considered the following environmental

and social impacts of closed-cycle cooling:

Plant type

Degree of difficulty

for retrofits Allocation (%) Flow (gpm) Cost (billions)

Fossil

Easy 22 30,691,540 $5.56

Easy/average 10 13,950,700 $3.18

Average 26 36,271,820 $9.97

Average/difficult 13 18,135,910 $6.17

Difficult 24 33,481,680 $13.56

More difficult 5 6,975,350 $3.98

Total fossil 100 139,507,000 $42.42

Nuclear Less difficult 30 12,836,700 $3.52

Intermediate 40 17,115,600 $7.86

More difficult 30 12,836,700 $8.27

Total nuclear 100 42,789,000 $19.56

Total facilities 182,296,000 $62.07

Table 1. Degree of difficulty allocations and capital cost for the con-version to closed-cycle cooling. Source: EPRI

Region

All waterbody types

Units

at risk

Capacity

(MWe) at risk

PJM 21 3,250

ERCOT 25 5,458

ISO-NE 12 2,561

Midwest ISO 7 906

NYISO 11 3,325

SERC 38 3,044

FRCC 21 2,196

SPP 20 1,475

WECC 18 2,699

MRO 8 328

RFC 33 816

Totals 214 26,058

Table 2. Regional estimates of the number of units and capacity at risk. Source: EPRI


WATER & POWER

■ Human health

■ Terrestrial resources

■ Water resources

■ Solid waste

■ Public safety and security

■ Quality of life

■ Greenhouse gases

■ Permitting issues

The overall significance of environmental

impacts varies on a site-specific basis. Facili-

ties located in urban and suburban areas tend

to have more social impacts due to exposure to

noise, drift, fogging, and visible vapor plumes;

rural facilities tend to have greater impacts on

agriculture and wildlife, depending on prox-

imity to farmland, state parks, wetlands, or

other wildlife habitat. Table 3 provides a sum-

mary of some of the quantified impacts.

Even with drift elimination, an estimated

29,000 tons/year of particulate matter (PM2.5

and PM10) would be generated. However, no

studies on the potential human health impacts

of cooling tower particulate matter have been

conducted, and the impact likely varies de-

pending on the composition of solids in the

cooling water.

It was estimated that about 25,000 metric

tons/year of biocides would be required to main-

tain cooling tower operations and that approxi-

mately 500 billion gallons/year of freshwater

would be lost to evaporation, roughly double the

loss from once-through cooling. This volume of

freshwater is sufficient to meet the potable water

needs of the state of Illinois.

The 39 once-through-cooled, baseloaded

nuclear facilities do not emit carbon dioxide

(CO2). However, it would take an estimated

six months on average to retrofit these fa-

cilities with closed-cycle cooling and likely

would require replacement power generation

from fossil facilities, resulting in an estimat-

ed 163 tons of CO2 emissions.

The total “willingness to pay” to avoid the

social and environmental impacts resulting

from closed-cycle cooling retrofits was esti-

mated to be $33 million nationally—in other

words, what ratepayers would be willing

to pay to maintain the status quo. What the

study did not consider was the economic im-

pact to ratepayers for the cost of closed-cycle

cooling retrofits. The social and environmen-

tal costs break down as follows:

■ $13,000,000 for CO2 emissions, estimated

from voluntary carbon credit prices

■ $16,000,000 for noise, estimated from

noise impact studies on housing prices

■ $2,400,000 for aesthetic impact, estimated

from studies of viewshed impact on hous-

ing prices

■ $970,000 for debris removal, estimated

from water cleanup event costs.

Impact type

Freshwater

facilities Great Lakes

Oceans, estuaries

and tidal rivers Total

PM (tpy) 2,000 800 27,100 29,800

Chlorine use (mt/yr) 18,000 7,000 NA 25,000

Evaporative water loss (billion gal/yr) 372 128 NA 500

Debris removal (tpy) 328 241 281 861

CO2 (tpy); 6-month nuclear unit outage 74 22 67 163

Table 3. Some quantified impacts of a closed-cycle cooling retrofit re-quirement. Source: EPRI

Notes: tpy = tons per year, mt/yr = metric tons/year.



WATER & POWER

Many environmental and social impacts, including, but not limited

to, evaporative water loss, wildlife impacts, icing on roadways, biocide

usage, and salt damage from drift could not be monetized due to lack

of information.

Cost Relative to Benefits. The results of the analysis estimate

that the annual benefits associated with the impingement and entrain-

ment (I&E) reductions resulting from a national closed-cycle cool-

ing retrofit requirement would be approximately $16 million, with a

lower bound estimate of $13.8 million and an upper bound estimate

of $22.7 million. Table 4 provides benefit estimates for 57 facilities

for various dollar ranges.

The national estimated benefit of $16 million to retrofit once-

through-cooled facilities to closed-cycle cooling is on the same order

of magnitude as the willingness to pay estimate of $33 million to avoid

closed-cycle cooling and a fraction of the estimated cost of over $100

billion to retrofit facilities with closed-cycle cooling.

It should be noted that the EPA is engaged in a national willingness-

to-pay study to estimate non-use or other societal benefits that may

accrue. Preliminary partial results for that study were reported in the

Federal Register (Vol. 77, No. 113, June 12, 2012, or at http://water.epa.

gov/lawsregs/lawsguidance/cwa/316b/index.cfm). Including non-use

benefit estimates significantly increases the national benefit estimate.

However, these estimates tend to be highly subjective for a number of

reasons, such as because survey respondents were not informed that in

the majority of cases I&E reductions may not result in any measureable

fishery benefit and were not given a choice between using any extra in-

come to save fish versus paying for better health care, education, or ad-

dressing other environmental issues. (EPRI comments submitted on the

study can be found at www.nera.com/nera-files/PUB_UWAG_0712_

final.pdf. Nuclear Energy Institute comments can be found at www.nei.

org/filefolder/NEICommentEPANODAsurvey.pdf. )

EPRI 316(b) Research Implications Relative to the Proposed RuleThe EPA’s proposed rule (Federal Register, Vol. 76, No. 76, April 20,

2011), did not propose closed-cycle cooling as BTA for existing facili-

ties as its preferred option. However, the EPA requires all facilities us-

ing more than 125 mgd actual intake flow to evaluate fine-mesh screens

and closed-cycle cooling to address entrainment. The BTA decision

would be made on a site-specific basis and could range from closed-

cycle cooling to a determination that the existing cooling water intake

structure is BTA. In the Notice of Data Availability issued in June 2012

(Federal Register, Vol. 77, No. 112, June 11, 2012), the EPA stated it

was not the agency’s intention to require closed-cycle cooling as BTA

for impingement.

The EPA considered three other options, any one of which could

serve as the basis for the final rule. Two of those options (Options

2 and 3) are based on closed-cycle cooling as BTA, but they affect

a somewhat different population of facilities than those assumed

by EPRI in its research and modeling. EPRI identified 428 once-

through-cooled facilities potentially affected by a retrofit requirement

(39 nuclear and 389 fossil). Under Option 2, only those facilities

withdrawing more than 125 mgd design intake flow rate (DIF) would

require use of closed-cycle cooling as BTA. The EPRI cost of retrofits

report provides retrofit cost estimates separately for nuclear and fossil

facilities. Since all of the once-through-cooled nuclear facilities use

more than 125 mgd DIF, there is no change for the estimated costs to

retrofit these facilities under Option 2.

Selecting only the fossil facilities using 125 mgd DIF rather than 50

mgd DIF as the closed-cycle cooling retrofit basis reduces the number

of affected fossil facilities from 389 to 322 (a reduction of 67 facilities).

However, these are the smallest facilities on the list, and retrofit costs

are directly related to the size of the facility. The 67 small facilities

represent only 2.9% of the total once-through-cooled fossil facilities

based on flow, and only 2.8% of total generation capacity. The effect of

not including these 67 facilities in the nationwide analysis results in a

relatively small reduction in the retrofit cost estimates and other impli-

cations of a closed-cycle cooling BTA requirement under Option 2.

Under Option 3, the proposed rule would cover additional steam elec-

tric facilities not included in the EPRI analysis based on facilities that

use more than 50 mgd DIF. As with Option 2, there would be no effect

on the study results for nuclear facilities. Though EPRI does not have a

good estimate of the number of fossil power generation facilities that use

less than 50 mgd, EPRI believes many of these facilities already employ

closed-cycle cooling and therefore do not affect research results. (The

EPA estimated 148 in-scope facilities had closed-cycle cooling: Federal

Register, Vol. 79, p. 22191, Exhibit IV-1, April 20, 2011.) ■

—David Bailey ([email protected]) is senior project manager, Water and Ecosystems, Electric Power Research Institute.

Dollar range

Number of facilities

in dollar range

Percentage of facilities in

dollar range

$0–$10,000 23 40%

$10,000–$50,000 14 25%

$50,000–$100,000 6 11%

$100,000–$500,000 10 18%

<$500,000 4 7%

Total 57 100%

Table 4. Distribution of commercial and recreational impingement and entrainment economic loss esti-mates for 57 facilities. Source: EPRI

Statement of Ownership, Management, and Circulation (Requester Publications Only) 1. Publication Title: POWER magazine 2. Publication Number: 0032-5929 3. Filing Date: 10/4/2012 4. Issue Frequency: Monthly 5. Number of Issues Published Annually: 12 6. An-nual Subscription Price $87. Complete Mailing Address of Known Ofice 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 Ofice Publisher: Access Intelligence, LLC, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 9. Full Names and Complete Mailing Addresses of Publisher, Editor, and Maging Editor: Publisher: Brian Nessen, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 Editor: Robert Peltier, 4 Choke Cherry Road, 2nd Floor, Rockville, MD 20850-4024 Managing 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 address of the corporation immediately followed by the names and ad-dresses 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-proit organiza-tion: not applicable. 13. Publication: POWER magazine 14. Issue Date for Circulation Data: September 2012. 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) 54,604 53,496b. Legitimate Paid and/or Requested Distribution (1) Outside County Paid/Requested Mail Subscriptions 45,013 43,585 (2) Inside County Paid/Requested Mail Subscriptions 0 0 (3) Sales Through Dealers and Carriers, Street Vendors, 6,644 6,944 and Other Paid or Requested Distribution Outside USPS (4) Requested Copies Distributed by Other Mail Classes 0 0c. Total Paid and/or Requested Circulation 51,657 50,529d. Nonrequested Distribution (By Mail and Outside the Mail) (1) Outside County Nonrequested Copies 1,162 1,207 (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) 842 757e. Total Norequested Distribution 2,004 1,964f. Total Distribution (Sum of 15c and 15e) 53,661 52,493g. Copies not Distributed (Ofice, Returns, Spoilage, Unused) 943 1,003 h. Total (Sum of 15f and g) 54,604 53,496i. Percent Paid and/or Requested Circulation 96.27% 96.25%16. Publication of Statement of Ownership for a Requester Publication is required and will be printed in the November 2012 issue of this publication17. Signature of Owner: Don Pazour Date: 10/4/12 PS Form 3526-R, August 2012


AIR QUALITY

Hazy Timetable for EPA’s Proposed Tighter PM2.5 StandardsOn June 15, in response to a court order, the U.S. Environmental Protection Agen-

cy (EPA) proposed new lower limits on particulate matter (PM) emissions that are scheduled for release in mid-December. Even with implementation de-lays, now is a good time to start paying closer attention to the requirements of the proposed standard.

By Angela Neville, JD

Particulate matter (PM) is a complex

mixture of extremely small particles and

liquid droplets. PM comprises a number

of components, including acids (such as ni-

trates and sulfates), organic chemicals, metals,

and soil or dust particles. The size of particles

is directly linked to their potential for caus-

ing health problems. The U.S. Environmental

Protection Agency (EPA) is concerned about

particles that are 10 micrometers in diameter

or smaller (PM10) because those are the ones

that generally pass through the throat and nose

and enter the lungs. Once inhaled, these par-

ticles can affect the heart and lungs and cause

serious health effects (Figure 1).

Particles may be emitted directly or formed

in the atmosphere by transformations of gas-

eous emissions such as sulfur oxides (SOx),

nitrogen oxides (NOx), and volatile organic

compounds (VOCs). Examples of secondary

particle formation include the following:

■ The conversion of sulfur dioxide (SO2) to

sulfuric acid droplets that further react with

gaseous ammonia to form various sulfate

particles such as ammonium sulfate.

■ Reactions involving gaseous VOC yield-

ing organic compounds with low ambient

temperature (saturation) vapor pressures

that condense on existing particles to form

secondary organic aerosol particles.

The EPA groups particle pollution into

two categories:

■ Inhalable coarse particles, such as those

found in industries handling dusty materi-

als like coal, are larger than 2.5 micrometers

and smaller than 10 micrometers in diam-

eter. These particles are classified as PM10.

■ Fine particles (PM2.5), such as those found

in smoke and haze, are 2.5 micrometers in

diameter and smaller. These particles can

be directly emitted from sources such as

forest fires, or they can form when gases

emitted from power plants react in the air.

Due to environmental concerns, coal-fired

power plants are required to operate a par-

ticulate collection system to control the re-

lease of particulate emissions. These systems

include inertial collectors (cyclone collec-

tors), fabric filter collectors (baghouses), wet

scrubbers, and electrostatic precipitators.

POWER has published a variety of articles

about PM standards and PM control technolo-

gies. The most recent examples (available in

the archives at www.powermag.com) include

“Particulate Matter Air Quality Standards

Continue to Evolve” (June 2011) and “EPRI

Bridges Industry R&D Gaps” (January 2012).

Regulating Particulates in the PastThe first rules regulating PM were promul-

gated in 1971 under the Clean Air Act (CAA).

Since that time, the EPA has continually up-

dated the PM standards (Table 1) to better

1. Particulate policy. Particulates of dif-

ferent diameters have different effects on the

human body and often originate from different

sources. PM10 and PM2.5 particles are eas-

ily inhaled and penetrate airways and lungs.

Source: California Environmental Protection

Agency Air Resources Board

Human hair

(60 mm diameter)

PM10

(10 mm)

PM2.5

(2.5 mm)

Hair cross section (60 mm)

2. The air is getting cleaner. This graph illustrates the reduction in the amount of the

six common pollutants (SO2, NOx, PM, CO, ozone, and lead) in relation to other key economic

indicators over the past two decades. Source: EPA

220%

200%

180%

160%

140%

120%

100%

80%

60%

40%

20%

0%

-20%

-40%

-60%

-80%

95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11

Gross domestic product

Vehicle miles traveled

PopulationEnergy ConsumptionCO2 emissions

Aggregate emissions

(Six common pollutants)

Year


AIR QUALITY

protect human health and the environment. The CAA’s centerpiece has been the national ambient air quality standards (NAAQs), which were established for six pollutants: sulfur dioxide, NOx, PM, carbon monoxide, ozone, and lead (Figure 2).

PM’s chemical and physical properties vary greatly with time, region, meteorology, and source category, thus complicating the as-sessment of health and welfare effects. Since the EPA completed the last PM standards review in 2006, the agency has examined hundreds of new studies. The new evidence includes more than 300 new epidemiological studies, many of which report adverse health effects even in areas that meet the current PM2.5 standards. The EPA also has consid-ered analyses by agency experts.

Court Order Drives EPA’s New Proposed PM StandardsUnder the CAA, the EPA is required to con-sider revising its PM standards every five years, and it last did so in 2006. Yet, as the agency approached the five-year deadline in October 2011, it announced that it wanted to delay issuing revised PM rules until the sum-mer of 2013 because it needed more time to sift through the latest scientific research.

Eleven states, including New York and Cal-ifornia, plus the American Lung Association and the National Parks Conservation Associa-tion, challenged the delay in court, arguing that it violated the CAA. On June 2, 2012, Judge Robert L. Wilkins ruled in the case (American

Lung Association v. U.S. Environmental Pro-

tection Agency, U.S. District Court, District of Columbia) and ordered the EPA to sign a proposed rule by June 7, a deadline that was later extended under an agreement between the agency and the plaintiffs.

On June 14, the EPA proposed to strength-en the NAAQS for PM2.5. The agency also proposed to retain the existing standards for PM10. The agency said that its proposed changes to the PM2.5 standards are consis-tent with advice from its independent science advisors, the Clean Air Scientific Advisory Committee (CASAC).

Specifically, the agency proposed to take the following actions:

■ Strengthen the annual PM2.5 health stan-dard by setting the standard at a level within the range of 12 micrograms per cubic meter (μg/m3) to 13 μg/m3. The cur-rent annual standard, 15 μg/m3, has been in place since 1997.

■ Retain the existing 24ύhour fine particle standard, at 35 μg/m3. The EPA set the 24ύhour standard in 2006.

■ Set a separate PM2.5 standard to improve visibility, primarily in urban areas. The

EPA is proposing two options for this 24ύhour standard: at 30 deciviews or 28 deciviews. (A deciview is a yardstick for measuring visibility.)

■ Retain existing secondary standards for PM2.5 and PM10 identical to primary standards to provide protection against other effects, such as ecological impacts, effects on materials, and climate impacts.

The EPA also proposed to retain the ex-isting 24ύhour standard for PM10. This stan-dard, with a level of 150 μg/m3, has been in place since 1987.

The EPA also made the following proposals:

■ Grandfathering preconstruction permit-ting applications that have made substan-tial progress through the review process at the time the final standards are issued. The agency is taking this action to ensure a smooth transition to the new standards.

■ Making updates and improvements to the nation’s PM2.5 monitoring network that include relocating a small number of mon-itors to measure fine particles near heavily traveled roads. The EPA’s proposal does not require additional monitors.

■ Updating the Air Quality Index for particle pollution.

The EPA anticipates making attainment/nonattainment designations by December 2014, with those designations likely becoming effec-tive in early 2015. A nonattainment area is a lo-cation considered to have air quality worse than the NAAQS as defined in the CAA Amend-ments of 1970. Nonattainment areas must have and implement a plan to meet the standard. An area may be a nonattainment area for one pollut-ant and an attainment area for others.

States would have until 2020 (five years af-ter designations are effective) to meet the pro-posed health standards. Most states are familiar with this process and can build on current work

Final rule

Primary/

secondary Indicator

Averaging

time Level Form

36 FR 8186

Apr. 30, 1971

Primary TSP 24-hour 260 µg/m3 Not to be exceeded more than once

per year

Annual 75 µg/m3 Annual average

Secondary TSP 24-hour 150 µg/m3 Not to be exceeded more than once

per year

52 FR 24634

July 1, 1987

Primary and

secondary

PM10 24-hour 150 µg/m3 Not to be exceeded more than once

per year on average over a 3-year

period

Annual 50 µg/m3 Annual arithmetic mean, averaged

over 3 years

62 FR 38652

July 18, 1997

Primary and

secondary

PM2.5 24-hour 65 µg/m3 98th percentile, averaged over 3

years

Annual 15.0 µg/m3 Annual arithmetic mean, averaged

over 3 years

PM10 24-hour 150 µg/m3 Initially promulgated 99th percen-

tile, averaged over 3 years; when

1997 standards for PM10 were

vacated, the form of 1987 standards

remained in place (not to be ex-

ceeded more than once per year on

average over a 3-year period)

Annual 50 µg/m3 Annual arithmetic mean, averaged

over 3 years

62 FR 38652

July 18, 1997

Primary and

secondary

PM2.5 24-hour 35 µg/m3 98th percentile, averaged over 3

years

Annual 15.0 µg/m3 Annual arithmetic mean, averaged

over 3 years

PM10 24-hour 150 µg/m3

Not to be exceeded more than once

per year on average over a 3-year

period

Table 1. Early evolution of PM standards. The first rules regulating particulate

matter were enacted in 1971 under the Clean Air Act. Since that time, the EPA has continu-

ally updated PM rules under the National Ambient Air Quality Standards (NAAQS). By law, the

agency cannot consider costs in setting or revising NAAQS. Source: EPA

Notes: FR = Federal Register, PM = particulate matter, TSP = total suspended particulates.


AIR QUALITY

to meet the news standards. A state may request a possible extension to 2025, depending on the severity of an area’s PM2.5 problems and the availability of pollution controls.

The CAA does not specify a date for states to meet secondary PM2.5 standards; the EPA and states determine that date through the state implementation planning process. The same controls that will be installed to meet the pri-mary, healthύbased standards will also help ar-eas meet the secondary standards. In 2020, the EPA expects virtually all counties will meet the secondary standards without state/local re-ductions. By law, the agency cannot consider costs in setting or revising NAAQS.

The EPA intends to issue a regulatory impact analysis that will estimate the potential benefits and costs of meeting a revised annual health standard in the year 2020. The proposed stan-dards are expected to yield significant health benefits, valued at $2.3 billion to $5.9 billion annually for a proposed standard of 12 μg/m3 and $88 million to $220 million annually for a proposed standard of 13 μg/m3, according to the EPA. The EPA will issue final standards by Dec. 14, 2012, after holding hearings to seek public comment. The proposed standards re-flect the continuing trend of tightening the PM NAAQS over time (Table 2).

How New PM Rules Affect the Power IndustryIn August, POWER interviewed Block An-drews, PE, director of Strategic Environmen-tal Solutions, and Robynn Andracsek, PE, associate environmental engineer, Environ-mental Studies and Permitting Division, with the engineering firm Burns & McDonnell about the new PM standards.

“Previous government studies have shown that the biggest environmental ‘bang for your buck’ is from reduction of fine particulate matter,” Andrews said. “But, have we gotten to the point of diminishing returns? I don’t know; I will defer this answer to the toxicolo-gists and economists.”

Andrews said that the EPA has a pro-cess for evaluating the ambient air qual-ity standards that includes a working group (CASAC) with toxicologists that evaluates health-based studies and uses the results to set the NAAQS.

PM2.5 can be in a filterable (solid) form, or a sulfate or nitrate condensable form, Andrews said. For the filterable portion, air dispersion modeling can be a problem if the PM2.5 standard is lowered, especially with coal-fired plants’ fugitive emission sources such as ash handling and road and coal pile dust. He said, “Background PM2.5 levels to-day are around 80% of the proposed standard. This does not allow many additional impacts from an existing or new facility.”

Andrews explained that sulfate formation is a chemical transformation of SO2 emis-sions. Natural gas combustion is relatively free of SO2 emission, but a coal plant stack’s SO2 emissions will form sulfates. Nitrate for-mation is a chemical transformation of NOx emissions. Both coal and natural gas com-bustion would be expected to form nitrates.

Primary standards provide public health protection, including protecting the health of “sensitive populations such as asthmat-ics, children, and the elderly,” Andrews said. Secondary standards provide public welfare protection, including protection against de-creased visibility and damage to animals,

crops, vegetation, and buildings. In addition, the EPA is proposing a new

visibility standard for the secondary NAAQS. Some of the same atmospheric chemistry that converts SO2 and NOx to form sulfates and ni-trates can also impact visibility, Andrews said.

“A good amount of work to determine re-gional haze impacts on Class I areas has been performed. I have not seen any determinations of visibility outside of the Class I, so it is un-clear (no pun intended) what, if any impacts this may have on the coal and natural gas power plants beyond the primary standard,” Andrews said. “My concern is that the visibili-ty modeling results have not always correlated well with the ‘real world’ results. This could require industry/industries to spend money without a real visibility reduction return.”

Andracsek explained that the model re-quired for demonstrating compliance with the PM2.5 NAAQS is AERMOD, which is the EPA’s most commonly used air disper-sion modeling program. “It has been around for several years. The problem comes in getting the model to demonstrate PM2.5 NAAQS compliance. The sum of modeled impacts from the source, plus impacts from their neighbors within at least 50 kilometers, plus the background concentration is what must be compared to the now lower PM2.5 annual NAAQS,” she said.

There are two main issues related to prov-ing PM2.5 NAAQS compliance, according to Andracsek.

First, PM2.5 is made up of primary PM2.5 and secondary PM2.5. Primary PM2.5 is what is normally thought of as very fine dust. Secondary PM2.5 is formed from NOx, SOx, VOCs, and ammonia that react chemically in the air to form fine particulates. The EPA does not yet have a method to calculate or model secondary PM2.5, other than using SOx and NOx as surrogates. “This leaves a hole in com-plying with any PM2.5 NAAQS,” she said.

Second, the background levels for PM2.5 in many parts of the country are 8 mg/m3 to 11 mg/m3. “When the NAAQS is lowered from 15 mg/m3 to 12 mg/m3 or 13 mg/m3, the background does not change,” Andracsek said. “This leaves an even smaller amount of available room for source emissions. Combined with the fact that the models are quite conservative, modeling compliance with the PM2.5 NAAQS at 15 mg/m3 is problematic; modeling compliance at 12 mg/m3 to 13 mg/m3 is stifling.”

The cost to run PM2.5 modeling at a fa-cility varies greatly, depending on the spe-cific circumstances, according to Andracsek. Modeling stacks is much easier and faster than modeling fugitive emissions. A lot of primary PM2.5 is from fugitive emissions. “A dispersion modeling project would run from $15,000 to $50,000 and take from one to six

Year Regulatory action

1971 TSP NAAQS promulgated

1987 PM NAAQS revision; PM10 standards introduced

1997

PM NAAQS revision; PM2.5 standards introduced; PM10 Surrogacy Policy established where-

by permit applicants are allowed to use compliance with PM10 NSR requirements (including

PM10 NAAQS) as a surrogate approach for meeting PM2.5 NSR requirements

2006 PM2.5 24-hour NAAQS revised/lowered; PM10 annual NAAQS revoked

2008PM2.5 NSR rules finalized; significant emission rates established for primary PM2.5 emis-

sions (10 tpy); and the PM2.5 precursors, SO2 and NOx (40 tpy each)

2010 Final PSD increments, SILs, and SMC for PM2.5 promulgated

2011

PM10 Surrogacy Policy ended; PSD compliance demonstrations required for PM2.5 emis-

sions, including accounting of direct PM2.5 emissions and secondarily formed PM2.5 from

precursors; states must establish limits taking into consideration the condensable fraction

of PM2.5 emissions

2012 (proposed)Stricter annual PM2.5 NAAQS; secondary standard to address urban visibility concerns; revi-

sion of numerous monitoring requirements

Notes: NAAQS = National Ambient Air Quality Standards, NOx = nitrogen oxides, NSR = New

Source Review, PM = particulate matter, PSD = Prevention of Significant Deterioration, SIL =

significant impact level, SIP = state implementation plan, SMC = significant monitoring concen-

tration, SO2 = sulfur dioxide, tpy = tons per year, TSP = total suspended particulates.

Table 2. Regulatory milestones for PM NAAQS and related compliance assessment requirements. Source: EPA


AIR QUALITY

months,” she said. “This is a very rough esti-

mate. Compliance costs will vary depending

on what controls may be required to comply

with the PM2.5 NAAQS.”

The rule states that, for now, meeting

the 24-hour PM2.5 NAAQS is sufficient to

demonstrate that the secondary visibility

standard is attained, Andracsek said. So if

the EPA issues its guidance along with the

revised final rule, there should be no further

analysis above the “normal” PM2.5 analysis

and, therefore, no additional cost above that

needed to run the model described above.

There is a lot of uncertainty, however, as to

whether or not the surrogacy policy would be

allowed to stand in court, especially in light

of the fact that visibility is already considered

for Class I analysis and the Best Available

Retrofit Technology regulations.

Andracsek explained that if the EPA re-

leases the new standard before the guidance

is finalized, applicants might then have to

follow the Federal Land Managers’ Air Qual-

ity Related Values Work Group’s 2010 analy-

sis for long-range visibility (such as regional

haze) impacts, which would add $50,000 and

three months, or more, to the project’s cost.

She added, “It may not be possible to even

meet the regulation given the uncertainty

about the methodology. A big part of the

PM2.5 problem is the uncertainty and lack

of understanding about how these very fine

particulates behave in the atmosphere.”

The Impact of CSAPR’s Nullification On August 21, 2012, the U.S. Court of Ap-

peals for the D.C. Circuit vacated the Cross-

State Air Pollution Rule (CSAPR). Andrews

discussed the impact of the CSAPR’s nul-

lification on coal-fired and gas-fired power

plants that have to install new air pollution

control equipment in order to comply with

the proposed PM2.5 NAAQS.

“There have been two rules that were driv-

ing PM2.5 controls: CSAPR and the PM2.5

NAAQS. Since CSAPR has been vacated,

it is unlikely that EPA will have a replace-

ment rule in the near future. In fact, it took

EPA three years to replace the original CAIR

[Clean Air Interstate Rule],” he said.

After a new CSAPR or similar rule is final-

ized, the states will be given an opportunity

to develop a State Implementation Plan (SIP),

which will have to be approved by the EPA

and give a reasonable timeframe for compli-

ance, according to Andrews. “It could easily

be five years or more before any CSAPR com-

pliance would be expected,” he said.

The NAAQS regulatory process can be

the timeframe driver as well, Andrews ex-

plained. A typical process would require

states to monitor PM2.5 (which has been

happening for several years), submit to the

EPA a list of non-attainment areas, develop

SIPs for compliance, obtain EPA approval of

the SIPs, and then require controls in or near

non-attainment areas.

“The EPA may set a timeframe for this pro-

cess, but history tells us that the timeframe is

not always reliable for a variety of reasons. It

could easily be five years or more before any

PM2.5 NAAQS compliance would be expect-

ed,” Andrews said. “The bottom line is that a

controls timeframe is uncertain. History tells

us that NAAQS-driven control requirements

are rarely required immediately.”

Will Plants Require New Equipment to Meet Stricter PM Standards?Andrews explained that for fugitive dust

emissions, meeting the new standard could

require more enclosed coal piles and fur-

ther fugitive dust reduction techniques, such

as road paving, surfactants, and baghouses,

where feasible. “For SO2 and NOx emissions,

further reductions could be required such as

scrubbers and selective catalytic reduction

(SCR) technology,” he said.

POWER asked Andrews if he thinks the air

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AIR QUALITY

pollution control equipment currently used

by most U.S. coal-fired and gas-fired power

plants will be sufficient to enable them to

comply with the proposed secondary PM2.5

NAAQS. He answered, “I don’t think we

know at this point what scale of reductions

will be required to meet the proposed visibil-

ity standards. However, if the 24-hour PM2.5

surrogate policy continues to be in place,

then it would have a limited impact.”

Andrews had no estimates about the costs

of installing air pollution control technol-

ogy that would enable fossil-fired plants to

comply with the proposed PM standards. He

explained that he would first have to know

if the power plants in question are going

to retrofit a unit, retire, build new genera-

tion, or rely on the market for power. “Once

we know this answer, then we would have

to know the stringency and form of the

regulation(s),” he said.

When discussing the probable impact that air

pollution control upgrades will have on affected

power plants’ bottom lines, Andrews referred

to the “good old days when there were fewer

moving parts in the environmental arena.” He

explained that today there is great uncertainty

about the required controls and cost impacts re-

lated not only to air regulations, but also water

and coal combustion residuals regulations.

Is retrofitting a coal unit cost competitive

compared to buying market power or other

forms of energy such as natural gas com-

bustion? An answer to this question is quite

utility-specific, according to Andrews. It will

depend on many factors, including delivered

fuel costs, environmental costs, the power

market pricing in specific geographical areas

and the individual utility’s future projections

of key cost and risk issues

“Historically, energy companies have

done a great job of balancing regulations,

ratepayer costs, and—for investor-owned

utilities—a reasonable rate of return for the

shareholders,” Andrews said. “Their job is

even harder today, but I am confident that

they will continue to perform well.”

EEI Responds to Proposed PM StandardsThe Edison Electric Institute (EEI), an asso-

ciation of shareholder-owned electric compa-

nies, filed its comments about the proposed

PM standards with the EPA on August 31,

and referred to the “regulatory treadmill of

NAAQS standards.” The group said that if

the proposed PM rules are finalized, the EPA

will be adding to the already existing list of

separately enforceable PM NAAQS. Accor-

ing to the EEI, finalization of the proposed

PM rules would mean that the EPA and the

states will be concurrently implementing:

■ The 1997 PM2.5 annual standard.

■ The 2006 PM2.5 24-hour standard.

■ A new 2012 PM2.5 annual standard.

■ A potentially revised 2012 PM2.5 24-hour

standard.

■ The 1987 PM10 24-hour standard.

■ A new 2012 secondary PM2.5 visibility

standard.

■ The 2006 secondary PM2.5 standards as

newly targeted on “other” welfare effects

apart from visibility.

Under the EPA’s currently planned sched-

ule for NAAQS reviews, a new ozone stan-

dard could be promulgated in 2014 that

would layer on top of existing standards and

potentially add another secondary standard

to the two 2012 PM2.5 secondary standards,

according to the EEI. In addition, during this

time period, the newly revised NO2 and SO2

NAAQS will be implemented, requiring ad-

ditional designations and SIP submittals.

The EEI said that the EPA needs to do “a

far better job of coordinating these regula-

tions and minimizing their overall burden

for the agency itself, states, and regulated

entities.” The current situation causes “an

immense waste of resources” and, given the

lengthy process of designating new nonattain-

ment areas and revising SIPs, fosters years of

uncertainty for states, local governments, and

industry that are affected by revised NAAQS,

it said. The industry group commented that

the EPA should, instead, seek to rationalize

its NAAQS process to better conform to ex-

isting executive orders.

Looking AheadCurrently, the proposed PM standards’ imple-

mentation timeline is unpredictable because

of the complicated implementation process.

The most likely scenario would require the

individual states to monitor PM2.5, submit a

list of non-attainment areas to the EPA, de-

velop SIPs for compliance, obtain EPA ap-

proval of the proposed SIPs, and then require

controls in or near non-attainment areas.

Even though the implementation process

could take as long as five years, regulated fa-

cilities need to start planning for how to deal

successfully with compliance and permitting

issues. The increased complexity of PM2.5

NAAQS compliance will no doubt boost fa-

cility costs and staff work hours. Therefore,

it is important to begin assessing projected

PM2.5 emissions and possible permitting

problems to prepare for and, hopefully, avoid

permitting hurdles and delays. ■

—Angela Neville, JD, is senior editor of

POWER.

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PLANT DESIGN

The Evolution of Steam AttemperationThe fundamental design principles and process for modern steam desuper-

heating, or the attemperation of superheated steam in the power gen-eration industry, have been evolving since the early 1930s. Meeting the requirement for steam quantity, quality, and temperature consistency is the foundation of traditional attemperator component design, particularly for fast-response combined cycle plants.

By Martin-Jan Strebe and Arvo Eilau, Tyco Valves & Controls

Increases in steam and combustion turbine

operating temperatures and capacity that

are inherent in the quest to increase steam

cycle efficiency are advancing metallurgy

technology. At the same time, diverse opera-

tional requirements—including cycling and

low-load and load-following operations—

have added complexity to the design of to-

day’s combined cycle (CC) plants. Increased

final superheated steam volumes and temper-

atures coupled with these diverse operational

modes are, in turn, challenging many other

vital plant components and systems, particu-

larly the steam attemperator system.

Attemperator Design OverviewAn excellent attemperation system for a mod-

ern CC plant requires a balance of design ef-

ficiency, component flexibility, and system

reliability. Rapidly varying load conditions

place strenuous duty cycles on steam attem-

peration components and downstream appa-

ratus. On average, the attemperator system

will experience 700 to 1,000 thermal cycles

per year of normal operation. The thermal

cycles can double in a cycling unit.

Most modern heat-recovery steam genera-

tion (HRSG) superheated steam attemperator

component designs can be characterized as

either circumferential, probe, or a combi-

nation of both technologies. As with many

complex engineering components, designs

evolve from functional requirements derived

from expected plant operations. Each of these

design categories has a unique set of require-

ments that must be met to achieve expected

levels of plant performance and efficiency.

One of the more common superheater attem-

perator designs used in the HRSG CC market

today is a circumferential spray design (Figure

1). The primary function of this design is to

inject water perpendicular to the steam flow

through multiple fixed or floating spray nozzles

via a penetration in the main steam pipe wall and

the attemperator’s inner spray liner or protective

shield located inside the pipe. The nozzles pro-

duce mechanical atomization of the water drop-

lets into the superheated steam flow. This design

will often utilize external circumferential piping

to the main steam pipe for water supply to the

individual spray nozzles in conjunction with a

remote spraywater control station.

An alternative design for steam tempera-

ture control integrates a probe unit within the

pipe. This design is divided into two major

categories: integrated units (IU) and separat-

ed units (SU). Integrated probes incorporate

the spraywater control valve function within

the component (Figure 2). SUs offer a probe-

style spray for water atomization with a re-

mote spraywater control valve and external

water supply piping (Figure 3). The probe

application, whether of IU or SU design, em-

ploys single or multiple spray probes into the

superheated steam flow, spraying water drop-

lets parallel with the steam flow.

1. Circumferential in-line attemperator. In this design, water is injected perpen-

dicular to the pipe steam flow through spray nozzles to desuperheat steam. Source: Tyco Valves

& Controls

In-line

attemperatorSteam flow

DCS

TIC

2. Probe-style IU desuperheater. In this design, an integrated flow control valve is

inserted into a pipe through which water is injected into the flowing steam. A downstream

probe measures the downstream temperature and is used to control the water flow. Source:

Tyco Valves & Controls

Steam flow

DCS

TIC


PLANT DESIGN

Whether an attemperation system is cir-

cumferential or probe style in design, it must

be supported by robust integrated control

components and control functionality. The

placement, design, and function of tempera-

ture probes are critical. A spraywater control

valve or valves must enable “bubble tight”

shutoff, and manual valves required for com-

ponent and system isolation should be rou-

tinely inspected.

Most current HRSG steam attemperator

systems are designed for minimal to zero

water flow at maximum steam flow. CC

plants that are dispatched through automated

load-following management systems or au-

tomatic generation controls will see constant

superheated steam attemperation as load is

increased or decreased to meet fluctuating

megawatt demand. This mode of operational

dispatch will stress existing design limita-

tions of the attemperation system.

Common system and component failure

issues associated with extreme cycling con-

ditions are:

■ Spraywater control valve packing leaks or

packing blowout.

■ Wetting or droplet impingement of down-

stream thermal probes.

■ Nozzle spring failure.

■ Nozzle cracking or erosion.

■ Linear weld attachment (pin) cracking or

complete line failure.

■ Main steam pipe cracking.

■ Foreign object damage to the steam

turbine.

Engineering and Design ConsiderationsAttemperator system components are de-

signed and engineered to an expected life

span, based on detailed 3-D finite analysis

computer models, operational case histories,

material composition, and expected thermal

cycles associated with each component.

Some shortened component life in the steam

attemperator system can be attributed to sup-

porting operational systems, such as feedwa-

ter or condensate supply conditions, water

chemistry, distributed control system (DCS)

settings, or response times. These support

systems are usually designed for no or mini-

mum spray conditions at design or baseload

conditions for maximum efficiency.

The attemperator system installed at a

plant designed for baseload may exhibit much

different operation when cycled. A functional

field test often proves prior factory test set-

tings to be inaccurate. The following is a

minimum list of supporting systems and pa-

rameters associated with the attemperator that

should be reviewed and/or inspected to mini-

mize the chance of downstream damage:

■ Feedwater or condensate supply pressure,

flow rate, and temperature at the spraywa-

ter control valve during various load con-

ditions, or at the attemperator probe if an

integrated design is present.

■ Thermal probes, operational temperature,

and location specifications should be veri-

fied and/or tested.

■ DCS logic settings should be consistent

with plant operation. The dead band of

the control signal should be within the re-

quired tolerance.

■ Water chemistry should be known through-

out the steam and condensate systems un-

der various load conditions.

This equipment, if not originally designed

for cyclical operation, can be redesigned or

modified to better suit current operational

conditions. Often, a presumed shortage of

feedwater or condensate spray capacity can

be attributed to a logic setting in the DCS for

valve position, or for response at a predeter-

mined load condition.

Additionally, if the plant infrastructure has

been in service for a period of years and has

experienced a series of routine control valve

preventative and corrective maintenance ac-

tions, operators may observe a minor, incor-

rect spraywater control valve stem position

setting. Thermal probes are often placed in-

correctly during unit construction, resulting

in probe wetting or water droplet impinge-

ment, which will result in inaccurate steam

temperature measurement.

Locating the AttemperatorIn addition to mechanical design and field

operations, accurately predicting water drop-

let atomization is very important. However,

measuring droplet atomization in the field is

difficult. If atomization of spraywater into

the steam system is negatively affecting the

ability of the temperature probe to measure

downstream steam temperature correctly,

then severe overspray and underspray condi-

tions can produce increased thermal cycles

and component damage.

Thermal probe location is a first step in

verifying or eliminating probes as a possible

contributor to poor steam attemperator sys-

tem performance. Here are two general rules

for measuring and verifying the proper loca-

tion of upstream and downstream attempera-

tor thermal probes (in a straight pipe):

■ The upstream thermal probe should be a

minimum of five pipe diameters from the

attemperator location.

■ The downstream thermal probe should be

a minimum of 20 pipe diameters from the

attemperator location.

These rules of thumb should be used as

a quick check of an existing installation in

straight pipe and are useful in determining

if a gross error was made in thermal probe

placement. Droplet atomization calculations

can be used to determine the exact require-

ments and dimensions for the piping arrange-

ment and thermocouple locations.

Advances in Steam Temperature ControlPrecise steam temperature control has been a

challenge for steam plant operators since coal

was first shoveled into a furnace. Today’s su-

perheat temperatures and daily plant cycling

place extraordinary stresses on critical com-

ponents. Effective steam temperature control

is needed to protect expensive downstream

equipment, such as the steam turbine.

In a typical CC plant, precise steam tem-

perature control often conflicts with compact

steam piping design. That makes it difficult

to select an attemperator that can operate in

the shortest possible straight length of pipe

yet with an effective evaporation rate. This is

particularly difficult when short pipe length

is coupled with a high turndown ratio and

the desire for a flat temperature distribution

across the steam pipe.

3. Probe-style SU desuperheater. This design is similar to that shown in Figure 2, but

the water flow to the desuperheater is controlled via a separate flow control valve. Source: Tyco

Valves & Controls

Steam flow

DCS

TIC


PLANT DESIGN

Primary atomization of the feedwater used to attemperate the steam is produced by the nozzle design and geometry within the desuperheater and the pressure differential between the cooling water and the steam. Together with the University of Eindhoven in The Netherlands, Tyco Valves & Con-trols commissioned a joint research project to develop theoretical modeling of primary atomization using computational fluid dy-namics (CFD) analysis and laboratory laser diffraction to analyze water droplet size upon discharge from the desuperheater.

The study examined two nozzle designs, spring-loaded and swirl nozzles. Initial re-sults have identified that when operating at 25 bar (263 psi) with a 0.05 mm lift and Kv = 0.047 (Kv is a function of the nozzle design, and it relates the flow through a nozzle as a function of the fluid properties and the pres-sure drop across the nozzle), spring-loaded nozzles produce droplet sizes of 87 µm (the diameter of a human hair averages 30 µm). The same calculation for swirl nozzles at 25 bar, Kv = 0.043 resulted in droplet sizes of 27 µm—a factor of two to four times smaller than spring-loaded nozzles, depending on the operational pressure range. Basic engineer-ing guidelines indicate that the smaller drop-let sizes will evaporate faster and provide better desuperheater controllability.

Using this data, Tyco analyzed the sec-ondary atomization characteristics evident when the speed differential and drag forces between the cooling water and pipeline me-dia cause the droplets to split into smaller sizes. By measuring the speed differential of the two nozzle designs, Tyco is able to define which nozzle achieves higher speeds and therefore faster secondary atomization. Optimum atomization will result in frictional forces breaking the droplet size, which re-sults in complete mixing and true tempera-ture control and measurement.

The results of the Tyco desuperheater re-search study demonstrate that swirl nozzle designs offer enhanced performance and max-imum use of water pressure drop for atomiza-tion in the shortest possible length. Optimized spray injection angles of swirl nozzles allow equal temperature distribution within the pipe and provide the highest turndown ratio using mass flow control, rather than pressure control. Having no springs or moving parts within the nozzle, and no pressure drop and cavitation in the control valve, maximizes the operational life cycle of the swirl nozzle design compared to spring-loaded nozzles.

Improving Desuperheater DesignThe next generation of combustion turbines, HRSGs, and steam turbines will be able to operate at final steam temperatures that are projected to reach 1,150F. As steam tempera-tures rise, the need for tight steam control also increases, and multiple design solu-tions are required, depending on the specific modes of operation expected from the plant. At these higher steam temperatures it is im-perative that potential weak points in a steam temperature control system are identified be-fore it is installed in the field. That means re-lying on modern engineering techniques, 3-D design simulations, and the use of CFD and finite element analysis (FEA) tools.

For example, using CFD and FEA allows effective spacing of the nozzle openings to prevent areas of high stress. These tools can then be used to confirm whether the spray water nozzles are designed at the optimum angle for the shortest evaporation time and the reduction of cold spots on the inner steam line, which could lead to pipe cracking. Un-derstanding the stress of higher cycling on the attemperator system and desuperheater

nozzle units helps engineers to avoid future mechanical stress-related failures and maxi-mize system life.

CFD modeling techniques also enable close examination of the droplet distribution within the pipeline from both probe-style and circumferential desuperheaters. This identi-fies which design offers more equal droplet distribution between the hot steam flow and cooling water and therefore faster and more effective evaporation. Using CFD analysis provides greater understanding of attempera-tor system design and how altering desuper-heater geometry and spray nozzle angle can improve droplet evaporation and minimize impingement on the pipe wall.

FEA offers particular advantages dur-ing the design and engineering phase of the project by analyzing the heating and cooling cycles of critical desuperheater components. Attemperator components in the “hot zone” are at increased risk of thermal fatigue and shock. Using an FEA program, Tyco can identify where a crack may appear in, for ex-ample, the desuperheater nozzle and predict the potential failure point over the service life of the product.

Taking its steam temperature control testing further, Tyco has carried out thermal fatigue cycle analysis on its desuperheater nozzle in-jection units in two material types—F91 and Inconnel 718—at steam temperatures up to 1,150F, water temperature of 307F, and up to 10,000 thermal cycles. These analysis tools have allowed Tyco to improve the design ge-ometry and metallurgy of its severe service desuperheaters, which then allow engineers to produce a design that will minimize stress points and optimize the design and engineer-ing characteristics of the attemperator system (Figure 5).

4. Small droplets desired. This is a

laboratory image of droplet size analysis. The

size of the water droplets flowing into the

steam determines the rate of water atomi-

zation and steam temperature. Source: Tyco

Valves & Controls

5. TempLowHT flow path. TempLowHT incorporates a spraywater control valve lo-

cated outside the heat-affected zone, reducing the risk of thermal shock to critical components.

A single probe provides water droplet atomization through a series of nozzles located parallel to

the steam flow. Source: Tyco Valves & Controls

Steam flow

conditions

Control

shaft

PistonUninsulated

atmospheric

conditions

TempLowHT TempLow

Piston


PLANT DESIGN

The Future of Steam Attemperation Technology Drawing on the results of the water droplet study, CFD modeling, and FEA, Tyco has developed a new circumferential steam at-temperation system for the power generation industry. CircTemp has been designed and engineered to improve desuperheater perfor-mance in severe-service boiler system appli-cations. In developing the product, Tyco used the advanced modeling techniques to establish the performance characteristics and opera-tional parameters. CircTemp’s design uses the high-temperature, high-cycling experience Tyco has gathered through its Narvik-Yarway TempLowHT probe desuperheater and applies it to the new product development.

Tyco started with a nozzle design that pro-vided good primary atomization, ensuring that droplets would only become smaller dur-ing secondary atomization with the shortest possible evaporation time. This approach has reduced water droplet sizes from 100 µ to 20 µ, delivering shorter evaporation times. The key is the higher turndown ratio achieved by the CircTemp desuperheater, compared with typical spring-loaded nozzle circumferen-tial designs. Using mass flow, rather than a pressure-reducing control valve, maintains a constant pressure differential within the at-temperator system. This increases the velocity of the water discharged from the nozzle injec-tion unit, producing smaller water droplets. In spring-loaded nozzle designs, the control valve is the limiting factor because the pressure after the valve determines the discharge velocity.

The CircTemp design enables individual nozzles to be shut off as the steam load fluc-tuates. This means that a considerably higher turndown ratio can be achieved by sequenc-ing nozzle open and closing. As the load increases, smaller nozzles and then larger nozzles can be opened one at a time, as the flow requires. When less flow is needed, the nozzles can be closed in the reverse sequence: first the largest and then the smaller nozzles.

Tyco’s study into optimum spraywater an-gles also determined that cooling water entering the pipe perpendicular to the steam flow could impinge on the pipe wall. Optimized spray an-gles and nozzle configuration creates different cooling water spray patterns and ensures equal

distribution. This research into desuperheater spraywater characteristics has influenced the CircTemp design to prevent potential damage to downstream pipe and liners by eliminating cold spots on the inner pipe wall and maintain-ing constant steam temperature.

Striving for higher CC plant efficiency means higher steam temperatures and, prob-ably, high cycling duty over the lifetime of a plant. Components in direct contact with the higher-temperature steam must have the best materials, be based on state-of-the-art

research, and integrate field operating experi-ence into their design and manufacture. One of those components, the critical yet problem-atic desuperheater valve, is ready today for the next generation of combined cycle plants. ■

—Martin-Jan Strebe ([email protected]) is director for global

product management control valves and Arvo Eilau is marketing manager, Tyco

Valves & Controls. As of October 1, 2012, Tyco Valves & Controls will be officially

known as Pentair Valves & Controls.

For more information, call Wright’s Media

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In spring-loaded nozzle designs, the control valve is the limiting factor.


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Germany-based solar mirror maker Flabeg has developed an anti-soiling coating for solar mirrors used in solar thermal power plant applications, duraGLARE, which can repel dust and sand from the surface of mirrors. Dirt on mirrors can be reduced up to 50% compared with panels that are not coated, the company claims. As well as an increase in reflection, the enhanced performance of the collectors means that the effective solar area can also be made smaller, and this would cut the need for additional collectors and their components. The coating has been tested for several months in various climate zones worldwide. (www.flabeg.com)

Spent Fuel Multi-Monitor System

The new 1E-qualified CL86 Plus Spent Fuel Pool Multi-Monitor System from Fluid Components International (FCI) integrates three critical measurements: continuous level, point level, and temperature into a multi-variable solution designed specifically for spent fuel pool (SFP) applications in nuclear power plants. Maintaining water levels within spent fuel pools is of vital importance to ensure that spent fuel is kept cool and insulated, preventing the release of radiation. The new CL86 Plus Monitoring System features integrated continuous water level, multiple point level wet/dry indication and alarms, and water temperature sensors. These precision sensors operate independently of one another, offering the reliability and dependable accuracy required in demanding nuclear power plant installations.

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NEW PRODUCTS

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

Improved Thermal Images

Measurement technology specialist Testo announced the new Testo 875i thermal imager, a professional quality and versatile thermal imager with very high thermal sensitivity, outstanding image quality, and simplified ease of use. With the device’s high thermal sensitivity of less than 50 mK, and the outstanding image quality of 160 x 120 pixels (which can be increased to 320 x 240 pixels with SuperResolution technology), even the smallest details and the slightest temperature differences can be identified. The new imager allows the easy and safe detection of areas of

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Portable Milling Machine for Linear and Gantry Milling

The Climax LM5200 and LM6200 portable milling machines are designed with a split rail system to easily perform both linear and gantry milling with a minimum of changeovers. A rigid, modular bed design allows shorter bed sections to be combined to fit the length of the work area, without losing rigidity, and to extend the bed by two or three times its original length. With just a few simple changeouts, bed lengths can be extended to 192 inches and RAM length to 116 inches. The machines enable precision milling, drilling, and boring to be done more efficiently to meet tight tolerances.

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Combination Cutting Torch

ESAB introduced a new, improved line of combination cutting torches as part of the new Purox Elite Series of gas apparatus products. The Purox Elite Series Combination Torch includes the WH-4200 welding handle and the CA-4200 cutting attachment. The torch welds material up to 1 inch thick and cuts up to 8 inches in thickness. The torch delivers superior safety with its tubeless extruded handle that minimizes the potential of gases mixing in the handle. This tubeless handle design, along with the torch’s head injector, contains any flashback that could occur at the furthest point from the user. It also features color-coded pressure adjustment knobs for quick and easy identification of gases. The torch is properly weighted for comfort and reduced operator fatigue. (www.esab.com)


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COMMENTARY

Preparing for the EPA’s Cooling Water RuleBy Harold M. Blinderman, JD

With the U. S. Environmental Protection Agency’s (EPA’s) issuance of a final rule regulating cooling water intake structures at existing facilities potentially less than a

year away, facilities should be paying close attention to the pro-posed rule’s provisions, data requests, and study requirements as they evaluate their compliance options and begin to formulate their compliance strategy.

Overview of Proposed RuleThe proposed rule’s primary purpose is to regulate existing facili-ties utilizing once-through cooling water systems. The rule, as proposed, applies to all existing power plants and manufactur-ing facilities that have the design capability to withdraw more than 2 million gallons per day (mgd) from U.S. waters and use at least 25% of such water exclusively for cooling water pur-poses. The EPA states that 355 facilities across the U.S. employ once-through cooling. Of the 104 operating U.S. nuclear units, 60% use once-through cooling systems, according to the Nuclear Energy Institute.

Under the proposed rule, permitting authorities will use their best professional judgment in selecting the best technology available (BTA) to reduce entrainment, the incidental drawing of fish and other aquatic organisms into a power plant’s cool-ing water system. Consequently, while the EPA’s draft rule does not identify closed-cycle cooling or any other technology as the national standard for minimizing entrainment, the ultimate deci-sion on how best to reduce entrainment at a particular facility will be made, in most instances, by state environmental protec-tion agencies after reviewing all the information before them.

Focusing on Entrainment ReductionIt is incumbent upon facility managers to begin developing their overall approach from the very first submittal required by the proposed rule. Provisions in the proposed rule allow for consid-eration of a number of technical, biological, and economic fac-tors that may help a facility develop its site-specific approach to entrainment.

The proposed rule recognizes that energy reliability, increased air emissions, land availability, and remaining useful plant life are four key factors, among others, that the permitting authority must consider in making any decisions regarding BTA for reduc-ing entrainment. Furthermore, the proposed rule provides that the permitting authority may reject an otherwise BTA (or not require any BTA controls) if the control costs are not justified by the benefits. Thus, any compliance strategy must fully consider these issues.

In addition, if a nuclear facility can show that compliance with the proposed rule conflicts with a U.S. Nuclear Regula-tory Commission safety requirement, the proposed rule pro-vides that either the EPA or state permitting authority must make a site-specific BTA determination for minimizing adverse

environmental impact without conflicting with the facility’s safety requirements.

All plants subject to the proposed rule must be mindful of the numerous application studies that will be triggered once the rule is issued, which, at present, is likely to occur in the summer of 2013. The permitting authority will use these sub-mittals to assess the entrainment impacts of a facility’s cooling water intake structure and to reach a determination regarding the appropriate technological and operational controls to be implemented at the facility.

Importantly, the amount of information requested is tied to a facility’s intake flow. The greater the design and actual intake flow, the more studies are required. Facilities should be aware that, within six months of the final rule’s effective date, plants with a design intake flow of 50 mgd or more must initially submit a wide range of information, including studies to describe the source water body, cooling water intake structures, and cool-ing water system; characterization of the biological community in the vicinity of the cooling water intake structure; a plan for controlling impingement mortality; a description of biological survival studies addressing technology efficacy and other studies on impingement and entrainment at the facility; and a discus-sion of the operational status of the facility.

Following these submittals, facilities that fall within this cat-egory and also withdraw more than 125 mgd, and existing facili-ties with new units, have more work to do. The proposed rule calls for the development of information leading to the submit-tal of an entrainment characterization study within four years and comprehensive studies assessing technical feasibility, costs, and benefits of installing various technological and operational controls within five years of the final rule’s effective date. These reports will be critical to any agency BTA assessment, and it is within the discretion of the permitting agency to move up these reports’ timetables.

Throughout this process, facility owners and operators should be very aware of federal and state regulatory preferences in de-veloping an overall compliance strategy reflecting the individual facility’s specific circumstances. For instance, California and New York have policies in place favoring closed-cycle cooling tech-nology or achieving reductions in intake flow or entrainment mortality to levels commensurate with closed-cycle cooling.

Facilities Need to Advocate Site-Speciic Plans The information submitted by a facility as required by the pro-posed rule will form the basis for the permitting agency’s deter-mination about what constitutes BTA for entrainment. As any BTA determination will be based upon the permit writer’s best professional judgment, facilities have the opportunity to “make their case” based on site-specific economic, technical, and bio-logical findings as developed throughout the entire process. ■—Harold M. Blinderman, JD ([email protected]) is

a partner at the Day Pitney law firm in Hartford, Conn.


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