Power - June 2011

Vol. 155 • No. 6 • June 2011

A.I. in the Plant

The Urge to Merge

Spain: A Renewable Kingdom

Validating CT Performance

K-Power Upgrades Digital Controls

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June 2011 | POWER www.powermag.com 1

ON THE COVERIllustration by Elizabeth C. Johnston, Lizzardbrand Inc. Copyright POWER.

COVER STORY: INFORMATION TECHNOLOGY24 Artificial Intelligence Boosts Plant IQ

Plant owners are facing a looming exodus of seasoned workers, mounting economic

pressures, and a proliferation of plant data. Luckily, “smarter” power plant control

technologies promise to help address all of those challenges while delivering operat-

ing cost savings. Learn how artificial intelligence neural networks are being used in

power plants today and what they may be able to offer in the not-so-distant future.

SPECIAL REPORTS

POWER POLICY

30 Spain: A Renewable Kingdom

Just over three decades ago, Spain adopted economic policies that committed the

nation to renewable power in a big way. Notable research and development was

followed by significant new wind and solar power installations. Then the subsidy

bubble burst just as the global economic crisis hit. This report examines where the

kingdom stands now as it struggles to balance aspirations against available energy

and economic resources.

INSTRUMENTATION & CONTROL

38 K-Power Upgrades Combined-Cycle Automatic Generation Controls

When South Korea’s first private merchant power plant needed an updated control

strategy to respond more efficiently to dispatch signals, it upgraded with a predictive

multivariable controller. After you read how the transformation was accomplished

and how it has improved plant operational stability, you may consider making a

similar switch at your plant.

MERGERS & ACQUISITIONS

44 The Urge to Merge

As this issue was going into production, the news about utility mergers kept rolling

in. Why now? Why these companies? Specifics from a couple of the most recent

mega-mergers hold some of the clues, and industry analysts share their insights

about what seems to be a trend.

FEATURES


48 Fully Automating HRSG Feedwater Pumps

This case study describes a combination of controls automation strategies and hu-

man-machine-interface techniques designed to increase the overall level of feed-

water pump automation. The result was improved ease of use by operators and

maintenance personnel. The approach could be used throughout a plant to help

plant owners make the most of limited staff resources.

Established 1882 • Vol. 155 • No. 6 June 2011

30

44

www.powermag.com POWER | June 20112

GAS TURBINE DESIGN

54 The T-Point Plant: The Ultimate Validation Test

Automakers have long used test facilities and remote test tracks to work the bugs

out of new models before they hit showrooms for sale to customers. For turbine

makers, “real-world” testing is rather more complicated thanks to the greater size,

cost, and complexity of the product involved. Mitsubishi Heavy Industries’ (MHI’s)

solution has been to develop “house plants” that serve as pre-launch test facilities.

MHI shared details of its latest turbine tests with POWER.

COMBUSTION TURBINES

56 Selecting Your Next Combustion Turbine

Gas turbines are winning most valuable player awards around the globe. But before

you leap into the purchase of a new combustion turbine, take a look at this article

to be sure you’ve considered all your options and have compiled a comprehensive

list of questions for potential vendors. The answers should help you choose the best

equipment for your needs.

PLANT ECONOMICS

62 A More Accurate Way to Calculate the Cost of Electricity

You might think that economic equations are more or less eternal, but that’s not the

case—at least, not when it comes to calculating the true cost of generating electric-

ity in this day and age. A new approach will give you a more accurate picture of

today’s operating environment.

DEPARTMENTS

SPEAKING OF POWER6 Turning Gold into Lead

GLOBAL MONITOR8 Seven Charged in Siberian Hydropower Plant Accident

8 Recovery Efforts Continue at Fukushima Daiichi

9 Germany Considers Accelerated Nuclear Exit on Fukushima Worries

10 Countries Abandon Subsidies for Renewables en Masse

12 Battery That Extracts Energy from Water Salinity Difference

14 POWER Digest

FOCUS ON O&M16 NERC CIP Update

16 Air Preheater Uses New Adaptive Brush-Sealing Design

20 Twin Pac Controls Upgraded

LEGAL & REGULATORY22 Reliability Challenges Cause Texas-Size Headache

By Angela Neville, JD

66 NEW PRODUCTS

COMMENTARY72 U.S. Nuclear Operations in a Post-Fukushima World

By Kathryn M. Sutton and Stephen J. Burdick, Morgan, Lewis & Bockius LLP

54

56

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SPEAKING OF POWER

Turning Gold into Lead

Despite California’s deep economic wounds, Governor Jerry Brown (D) last month signed a bill (SB 2X) that in-

creased the state’s already ambitious renew-ables portfolio standard (RPS) goal from 20% to 33% by 2020. Together with the state’s Global Warming Solutions Act of 2006, which requires caps on greenhouse gas emissions starting next year, the new law will push up the price of electricity and further delay the Golden State’s economic recovery by perma-nently driving away irreplaceable businesses and manufacturing jobs.

Worst-Run StateLast October, 24/7 Wall St., a financial news and opinion electronic newsletter, ranked the best- and worst-managed states in America. The best-run state was Wyo-ming, which received high marks in just about every evaluation category. Wyoming is also the least-populous state, perhaps hinting at one reason for its success.

The worst state on the 24/7 Wall St. list was Kentucky, barely edging out California for last-in-class honors. “While it does not quite rank as the worst state on our list, Cal-ifornia stands out as being among the most poorly governed,” the authors wrote. “The most populous state in the union has been mired in debt and political unrest for nearly a decade. It bears the unique honor of being the only state considered economically un-stable enough to have its debts, at a record $341 billion, rated at an A- by S&P.”

This year, without the $3.5 billion in federal stimulus funds to cover their loss-es, California legislators may finally be forced to pragmatically deal with a $19 billion budget deficit, on top of a 2010–11 carryover deficit of $6.1 billion.

A low opinion of California’s business climate is not limited to 24/7 Wall St. In its 2010 annual survey of the best and worst states for business, Chief Executive magazine gave its “booby prize” for worst state to California for the second year in a row. The global consulting firm Bain & Co. found that “California is far worse [for business] than any other state by a very significant margin.” Development

Counselors International (specialists in business relocations) surveyed corporate executives in March 2011 and found that 72% responded that California has the “worst business climate” in the entire U.S. The Tax Foundation lists California as 49th in its 2011 State Business Tax Climate Index. And, according to Equi-fax, the four metropolitan areas with the greatest number of small-business bank-

ruptcies (up 10% in 2010 alone) were lo-cated in California.

The direct result of a decade of anti-business practices has been permanent loss of good-paying middle-class jobs. For ex-ample, California has lost 640,000 factory jobs (34% of its manufacturing base) and 1.5 million residents over the past decade, while Texas gained more than 800,000 resi-dents and added close to 800,000 jobs to its economy, according to the Bureau of Labor Statistics. California’s unemployment rate today hovers around 12.3% (Texas sits at 8.1%) with a cost of living 33% higher than the national average. It’s not difficult to pinpoint why so many businesses have pulled up stakes and relocated: an anti-business climate, the very high cost of do-ing business, and very high business and personal income taxes.

Another equally important factor that is pushing manufacturing jobs out of Califor-nia is the rising cost of electricity, caused by the state’s ill-conceived energy policies.

Policies Push Up PricesThe two key energy policies, among many, that are rapidly pushing up the cost of electricity are the California Global Warm-ing Solutions Act (AB32) and the state’s newly hiked RPS.

That AB32 is a jobs killer is not in dispute. Even one of the California Air Resources Board

(CARB) scenarios predicts up to 320,000 additional job losses when the bill is fully implemented. A study by Charles River Asso-ciates, using CARB data, predicted a drop in household income of $1,175 as the best pos-sible result of AB32. A report by Varshney & Associates concluded that the cost for every household will be “9% of its after tax annual income ($3,857) on AB32 related regulatory costs.” The California Small Business Round-

table predicts 1.1 million job losses caused by a fully implemented AB32, about 6% of the state’s current workforce.

Together, AB32 and the new RPS have trifling environmental value, in my view, but do increase upward pressure on the cost of electricity, further eroding the economic competitiveness of the world’s eighth-largest economy. Governor Brown said that he believed the state could get 40% of its electricity from renewables “at reasonable cost” in the near future. Today, electricity costs are so “reasonable” that Pacific Gas and Electric Co.’s top tier resi-dential rates exceed $0.40/kWh, and ad-ditional rate increases are on the horizon.

Prices Push Out JobsCalifornia remains an energetic center of technological innovation, but its energy policies are causing businesses and mid-dle-class manufacturing jobs to be export-ed at an irreplaceable rate. Also seemingly overlooked by the state’s political lead-ership is that once these jobs leave the state, the losses are permanent.

In the Middle Ages, alchemists searched for the secret of transmuting lead into gold. Today, California’s economy-killing energy policies have achieved the impos-sible—converting gold into lead. ■

—Dr. Robert Peltier, PE is POWER’s

editor-in-chief.

AB32 and the new RPS have trifling environ-mental value, in my view, but do increase upward pressure on the cost of electricity.

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Seven Charged in Siberian Hydropower Plant Accident The Russian Investigative Committee has completed a probe into the August 2009 accident at the Sayano-Shushenskaya Hydro Power Plant in Siberia that killed 75 people. The committee has charged sev-en people—including the plant’s former head, Nikolai Nevolko, his deputies, and the plant’s former chief engineer, Andrei Mitrofanov—for violating safety rules. If found guilty, the officials could face five years in jail.

On Aug. 17, 2009, an explosion at the giant 10-turbine hydroelectric station de-stroyed Units 2, 7, and 9, and seriously damaged Units 1 and 3. (For details of the event, see “Investigating the Sayano-Shushenskaya Hydro Power Plant Disaster” in our December 2010 issue or in the ar-chives at www.powermag.com.) The plant’s other five units were also damaged.

In an October 2009 report that in-vestigated what caused the catastrophe at the 6,400-MW hydroelectric plant, Russian industrial safety regulator Ros-tekhnadzor cited a number of contribut-ing causes, including design, operation, and repair shortcomings. It also point-ed a finger at six high-ranking Russian officials—including former electricity monopoly chief Anatoly Chubais, Igor Yusufov (Russia’s energy minister until 2004), and Viyacheslav Sinugin (former deputy energy minister)—saying that the accident resulted from their “negli-gence, laxity, and a lack of engineering thinking.”

The October 2009 report estimated that addressing the wreckage to major power generating assets and environmental dam-age would cost up to 7.338 billion rubles (US$269 million). State-controlled Rus-Hydro, the Russian Federation’s biggest hydropower producer, recently announced, however, that it would spend 20.6 billion rubles over the next two years on restor-ing the plant.

RusHydro, which owns power plants from the Finnish border in the northwest to the Chinese frontier in the south, has already restored four 640-MW generating units. Last year, it connected Unit 6 to the grid on Feb. 24, Unit 5 on March 22, Unit 4 on Aug. 2, and Unit 3 on Dec. 22. Restoration efforts have put the plant’s current capacity at 2,560 MW, and RusHy-dro reports that total energy output of the

restored generating units exceeds the 10 billion kWh level.

Work has begun on the second phase of restoration. In 2011, RusHydro is expected to install six totally new units, manufac-tured by Power Machines, and in the fi-nal phase, spanning 2013 to 2014, it will replace the units restored last year with new ones. “The service life of new [gener-ating units] will increase to 40 years [and the] new turbines will have the maximum efficiency of 96.6% and improved output and cavitation performance,” the company said. The hydraulic units will also report-edly be equipped with advanced diag-nostic systems to promptly detect status changes and prevent accidents.

Power Machines said in a statement in March that the second phase of restora-tion was on track. Work to assemble gen-erator components for Unit 1 was being carried out in the crater of Unit 9; the 540–metric ton stator will later be moved to the prepared crater at Unit 1 using a custom-made lifting beam (Figure 1). Unit 1 is now scheduled to be put into opera-tion in December 2011.

Recovery Efforts Continue at Fukushima DaiichiIn April, Japan’s Nuclear and Industrial Safety Agency provisionally raised the accident rating for three reactors at the

crippled six-unit Daiichi nuclear plant in Fukushima Prefecture to Level 7—making it a “major accident” and putting it on par with the 1986 Chernobyl accident in the Ukraine. Recovery efforts continue at the nuclear plant with workers pumping mas-sive amounts of freshwater into Units 1, 2, and 3 and spraying it over the spent fuel pool of Unit 4.

Plant operator Tokyo Electric Power Co. (TEPCO) has said that as much as 55% of Unit 1’s reactor core is thought to be impaired—and the damage may be inhib-iting the flow of coolant water, leading to higher temperatures and pressures; Unit 2’s core is estimated to be 35% damaged, as is 30% of Unit 3’s core. Nitrogen gas continues to be injected into the contain-ment vessel in Unit 1 to reduce chances of hydrogen combustion.

Units 5 and 6, which were not in ser-vice when the devastating 14-meter tsu-nami on March 11 took out the power and debilitated cooling systems for the other units, remain in cold shutdown. Concerns continue about the condition of Unit 4, which also wasn’t operating at the time of the natural disaster but which, on March 15, saw an explosion in the top part of the building near the spent fuel pond, subsequent fires, and heightened radia-tion levels. TEPCO continues to top up water levels in the spent fuel pool (Figure 2), which had dropped due to evaporation

1. A massive overhaul. Following the

catastrophic explosion that killed 75 work-

ers at the 6,400-MW Sayano-Shushenskaya

Hydro Power Plant in Siberia in August 2009,

plant owner RusHydro plans to replace all

the station’s damaged units with new ones.

Power Machines, a contractor that will build

and install the 10 new hydraulic turbines,

nine hydraulic generators, and six excita-

tion systems, has begun work on the Unit 1

stator. RusHydro has to date restored four

less-damaged units and says the plant’s ca-

pacity now exceeds 2,560 MW. Courtesy:

Power Machines

2. Pooling resources. This image from

a video taken on April 28 shows Daiichi 4’s

spent fuel pool. The unit, which has experi-

enced fewer problems than Daiichi 1, 2, and

3, has had both a hydrogen explosion and fires

since March 11 even though it was shut down

and all of its 1,331 spent fuel rods and 204 un-

used fuel rods were being stored in the spent

fuel pool. A water sample from the pool in

April showed high levels of radioactive iodine

and cesium—indicating that some spent fuel

rods have been damaged. Courtesy: TEPCO


caused by the heat load from its 1,331 fuel assemblies. Worries are also mounting about the structural integrity of the building and its ability to support the pond.

Radiation at various locations at the nuclear plant continues to surge. The highest doses have been detected from debris left on the ground after explosions at Units 1, 2, 3, and 4. Read-ings of rubble beside Unit 3 have surged to 300 millisieverts per hour, while others are at around 40 millisieverts per hour. Highly contaminated water continues to be another pressing concern. TEPCO has yet to decide how to process massive amounts of ra-dioactive water being pumped from the basement of Unit 2’s turbine building.

Meanwhile, TEPCO has begun using a PackBot—a small robot on tank-like treads—to monitor radiation and oxygen levels at the units. Of four PackBots in use, two are equipped to take tem-perature readings and two are “Warriors,” serving to lift and haul heavy loads (Figure 3).

The accident continues to cause financial worries for TEPCO, Asia’s largest utility, whose shares have slumped nearly 80% since the incident began on March 11. As the utility braces for a massive bill to compensate local residents, three banks that last month made a total of 1.4 trillion yen in emergency loans to the beleaguered company booked a combined loss of 160 billion yen at the end of Japan’s financial year on March 31. A rough draft of TEPCO’s compensation plan has shown that the government could cap the utility’s liability at 2 trillion yen to 3.8 trillion yen. Other utilities that operate nuclear plants may be asked to contribute to the fund, which could ultimately add up to 2.7 trillion yen.

Among newer developments, Japanese authorities plan to launch an independent panel in mid-May to investigate the causes of the accident at Daiichi. Prime Minister Naoto Kan told a plenary session at the House of Representatives that the les-sons would be shared with the international community and that Japan would “take the lead in contributing to safety improve-ments of nuclear plants around the world.”

Germany Considers Accelerated Nuclear Exit on Fukushima WorriesIn the wake of the devastating nuclear crisis afflicting the Fu-kushima Daiichi nuclear plant in Japan, Germany has embarked on an abrupt shift away from nuclear power, shutting down eight

reactors for safety checks and ditching concerted efforts to keep nuclear power plants open in the long term. In mid-April, Chan-cellor Angela Merkel told reporters that leaders of Germany’s 16 states all want to “exit nuclear energy as soon as possible and make the switch to supplying via renewable energy.” The policy reversal has incited ardent opposition from the energy sector and industry.

Germany generates some 23% of its power from nuclear sourc-es, and if the country decides to shut down power from nucle-ar reactors no later than 2022, it will suffer a supply squeeze. In April, ministers agreed to set down the main points of the country’s new energy policy by June. Industry analysts say the accelerated exit from nuclear power means that Germany could implement a €5 billion ($7.42 billion) credit program to support renewables and build new gas and coal plants. Germany already has one of the most aggressive clean energy policies in the world and sources 17% of its power from renewables. The nation is looking to raise that share to 40% by 2020.

The 2022 deadline for nuclear power had been set in 2000 by the former center-left government led by Chancellor Gerhard Schröder. In September last year, Merkel’s government struck a deal with energy companies to extend the lives of the coun-try’s 17 nuclear power plants, located in five of Germany’s federal states, for another 12 years beyond 2022.

Skyrocketing Power Costs. The plan to exit nuclear power so quickly could prove costly, because Germany is Europe’s biggest economy and largest energy user. According to a study commis-sioned by the Bundesverband der Deutschen Industrie, a German industry lobby, permanently shutting down eight reactors that

EDWARD PARTS AVAILABLE!


3. Artificial intelligence. TEPCO in April began using PackBots

to assess damage and monitor temperatures, radiation levels, and oxy-

gen inside the crippled Fukushima Daiichi units. The PackBot seen here

(in black) working inside the reactor building at Unit 3 on April 17, has

on-board lights and cameras and is able to move through buildings,

opening doors with a mechanized arm. Courtesy: TEPCO


are now temporarily shut down, as has been called for, and clos-ing remaining plants by 2022 could increase wholesale power prices to €70/MWh within seven years.

The study, whose results were released on April 24, also sug-gests that Germany’s about-turn on nuclear power could spawn additional costs of €33 billion by 2020—the bulk of which will be paid by industrial and commercial energy users—as utilities turn to more expensive forms of generation (the study assumes that almost half of Germany’s nuclear output would be replaced by imports and coal and gas generation) and demand for carbon permits increases. If costs for subsidies and the German grid are included, that figure could skyrocket to €51 billion, the study conducted by r2b, an energy consulting firm, said.

The government refuted allegations that costs would rise so steeply. Economy Minister Rainer Brüderle admitted to German radio, however, that the new phase-out plan—which includes expanding grids and energy storage—could cost consumers and taxpayers between €1 billion and €2 billion per year.

German Energy Firms Strike Back. Protesting the govern-ment’s U-turn on nuclear policy, plant operators in Germany have halted annual payments of up to €3.3 billion into a fund set up last year as part of a deal to extend reactor lifespans. Among the companies involved are energy giants E.ON, RWE, and Vattenfall.

RWE CEO Jürgen Grossmann has lashed out at the government, saying the phase-out could scar the economy. “This will not bring about the end of German industry overnight,” Grossman told shareholders in mid-April. “But it could lead to a long-term depletion process with a considerable negative impact on jobs and prosperity.” The company, Germany’s largest nuclear power producer, has also begun legal proceedings against the govern-ment to fight the temporary shutdown of its Biblis nuclear plant in Hesse on allegations that the closure was illegal.

E.ON said in a statement that it would not challenge closures of its reactors Isar 1 (Figure 4) and Unterweser, even though it had doubts about the move’s legality. But E.ON CEO Johannes

Teyssen, too, has expressed concern about the proposed nuclear exit, saying it would affect Germany’s climate goals and increase power prices—which could ultimately force energy-intensive in-dustries out of business.

Meanwhile, The Wall Street Journal reported that as a result of the Daiichi crisis, German engineering firm Siemens may be reconsidering a plan to form a partnership with Russian state-owned nuclear company Rosatom. The plan has been considered a major part of Siemens’ strategy to expand its presence in the nuclear sector.

Italy Pulls Back on Nuclear as Well. While a number of oth-er European countries conducted safety checks on their nuclear facilities—but continued to back energy plans that factored in future nuclear power—in April, Italy also indefinitely shelved plans to allow construction of new plants. In 1987, the Italian public had overwhelmingly voted to reject nuclear energy after the Chernobyl disaster, and its government in April scrapped plans for a new referendum to win public support for reactors that were to be built by Italian utility Enel and France’s EDF start-ing in 2013. Prime Minister Silvio Berlusconi said he hoped the country would revive the plans within a year or two after more clarity was gained on the technology.

India Defers Approval of Four Reactors. The Fukushima nu-clear crisis has also reignited concerns about the safety of India’s nuclear program. Widespread—and violent—protests against government plans to build six AREVA EPRs over 15 to 17 years in the coastal Maharashtra region have made the new builds a bit-terly contested political issue. In late April, India’s environment ministry made the unprecedented decision to defer approval for Units 3, 4, 5, and 6, reactors being built in Tamil Nadu state by the central government–run Nuclear Power Corp. of India Ltd. (NPCIL) and Russian state-owned company AtomStroyExport. Two VVER-1000 units are already under construction in that state, and Kudankulam Unit 1 is expected to begin operations by June. The ministry cited environmental hazards—including problems concerning a proposal to dispose cooling water into the sea—and the need for new risk assessments, because no new NPCIL environmental impact reports had been filed since 2004. Sources say that to shore up confidence in the country’s nuclear-heavy future energy plans, the government will continue to tighten safety regulations and go so far as to revamp its nuclear watch-dog agency.

Countries Abandon Subsidies for

Renewables en Masse

Stricken by the economic crisis and forced to implement austerity measures, several countries around the world have been forced to abandon or slash subsidies for renewable power producers.

UK. In March, the United Kingdom’s energy and climate change secretary, Chris Huhne, said his country may cut subsidies for large and midsize solar projects by as much as 72%. He had announced a comprehensive review of feed-in tariffs in February. The Depart-ment of Energy and Climate Change said the cuts slated to take place in 2012 would ensure that subsidies were available for small-er installations—like rooftop solar—which feed-in tariffs were originally designed for. In a statement, the UK Renewable Energy Association said the tariff cut would be an “absolute disaster,” claiming no new projects would start if the proposal became law. “This industry has been strangled at birth,” it added. Several com-panies have asked a UK court to review Huhne’s decision.

The Netherlands. Holland’s new right-wing government in February announced plans to drastically reduce solar and wind

4. Shutting the door on nuclear power. Utilities produc-

ing nuclear power in Germany have said the government’s plans

to phase out all nuclear power in the country by 2022 and replace

that capacity with renewables, coal, and gas could sharply increase

power prices and cause a supply squeeze. The government tem-

porarily shut down seven nuclear plants built before 1980 and one

newer facility at Krümmel in the wake of the Japanese nuclear cri-

sis. Among those was E.ON’s 1977-built Isar Unit 1 near the city of

Landshut (shown here). The 1988-built Isar 2 continues to be used

for baseload supply. Courtesy: E.ON

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© 2011 Caterpillar. All Rights Reserved.

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subsidies from €4 billion annually to €1.5 billion because they are unaffordable. The country, a major proponent of renewable energy development, has also become Europe’s first country to ditch the European Union target to procure 20% of its domestic power from renewable sources by 2020.

Czech Republic. Cuts to a feed-in tariff program that reported-ly spurred the increase of solar energy plants in the Czech Republic from nine in 2005 to 2,230 by 2010 were approved by the govern-ment last year. The cuts target solar plants that provide a return on investment in less than 11 years and that will be built after Janu-ary 2011. The government has said it supports the move because it would increase grid stability and level electricity prices.

Slovakia. Slovakia, following the Czech Republic’s lead, had also considered subsidy cuts, but this January, the Ministry of Economy decided that it would retain price incentives for solar and biomass. The ministry earmarked €18 million until the end of 2013 for subsidies, and it will this May try to get parliament’s approval for its decision.

Italy. Italy’s government will cut generous support for renewables to ease the burden on consumers, who pay for renewable incentives in power bills. It will cap subsidies for solar developers at €6 billion to €7 billion per year by the end of 2016. The government plans to slightly cut incentives until the end of a transition period ending in 2012. Current incentives were due to expire in June, but in April, the country approved a three-month extension (until Aug. 31) to allow some investors to complete their projects.

France. France in December suspended the registration of so-lar power projects of more than 3 kW for feed-in tariffs to study how cuts in the program would limit growth in the industry. In February, the country’s Environment Ministry announced that solar capacity in the country would be much higher than the 5,400 MW target for 2020, even though subsidies would be cut. The country has since slashed solar subsidies by 24%, from €0.55 to €0.42/kWh and is instead focusing on increasing wind power capacity.

Australia. In March, Australia’s states called on Prime Minis-ter Julia Gillard to roll back generous subsidies for rooftop solar plants after forecasts suggested that costs would add as much as A$90 per year to household power bills. Last October, New South Wales slashed by two-thirds the revenue that homeowners who had installed solar panels would receive.

Spain. In Spain, where the government has made the contro-versial decision to slash subsidies by up to €3 billion over the next three years—and possibly retroactively, on plants built be-fore 2008—regulators are also suspending subsidy payments to power producers who do not meet regulatory requirements. The country recently suspended payments to 304 solar power instal-lations after requesting proof from more than 9,000 rooftop and plant operators that they qualify to receive incentives. Spanish news reports have suggested that hundreds of subsidy recipients were illegally collecting the extra payments. (For more on Spain’s situation see “Spain: A Renewable Kingdom” in this issue.)

China. As of April, almost all the 10 billion yuan ($1.54 bil-lion) of China’s Golden Sun solar subsidy program to support solar photovoltaic businesses has been allocated, but an investigation has shown that a relatively high percentage of recipients may have declared material costs to be higher than they were, fraud that increased the cost of the whole system, reported China Dialogue.

Battery That Extracts Energy from Water Salinity DifferenceA rechargeable battery developed by researchers from Stanford University employs the difference in salinity between freshwater

and saltwater to generate a current. The technology could make it possible to harness power from anywhere freshwater enters the sea, such as river mouths or estuaries, Yi Cui, associate profes-sor of materials science and engineering, who led the research team, said.

As the researchers explained in the March issue of the journal Nano Letters, the battery essentially uses two electrodes—one positive, one negative—immersed in a liquid containing electri-cally charged particles or ions. In water, the ions are sodium and chlorine, the components of ordinary table salt. The positive electrode is made from nanorods of manganese dioxide, which in-creases the surface area available for interaction with the sodium ions by roughly 100 times compared with other materials, Cui said. The researchers continue to search for a better material for the negative electrode than the silver used for the experiments, which is too expensive to be practical.

Initially, the battery is filled with freshwater and a small elec-tric current is applied to charge it up. The freshwater is then drained and replaced with seawater. Because seawater is salty, containing 60 to 100 times more ions than freshwater, it in-creases the electrical potential, or voltage, between the two electrodes. That makes it possible to reap far more electricity than the amount used to charge the battery. “The voltage really depends on the concentration of the sodium and chlorine ions you have,” Cui said. “If you charge at low voltage in freshwater, then discharge at high voltage in sea water, that means you gain energy. You get more energy than you put in.”

Once the discharge is complete, the seawater is drained and replaced with freshwater and the cycle can begin again. “The key thing here is that you need to exchange the electrolyte, the liquid in the battery,” Cui said.

In their lab experiments, Cui’s team used seawater they col-lected from the Pacific Ocean off the California coast and fresh-water from Donner Lake, high in the Sierra Nevada. They achieved

5. Worth one’s salt. A rechargeable battery developed by Stan-

ford University researchers employs the difference in salinity between

freshwater and saltwater to generate power. In the first step, a small

electric current is applied to charge the battery, pulling ions out of the

electrodes and into the water. In the second step, the freshwater is

purged and replaced with seawater. In the third step, electricity is

drawn from the battery for use, draining the battery of its stored en-

ergy, and in the final step, seawater is discharged and replaced with

river water, for the cycle to begin anew. Courtesy: Yi Cui

Step 1

Step 3

Ste

p 2

Ste

p 4

Charge

Discharge

River water

Sea water

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74% efficiency in converting the potential energy in the battery to electrical current, but Cui thinks with simple modifications, the battery could be 85% efficient.

Other researchers have used the salinity contrast between freshwater and seawater to produce electricity, but those pro-cesses typically require ions to move through a membrane to generate current. Cui said those membranes tend to be fragile, which is a drawback. Those methods also typically make use of only one type of ion, while his battery uses both the sodium and chlorine ions to generate power.

Cui admitted that one significant theoretical limiting factor is the amount of freshwater available. However, the researchers claim that their batteries could supply 2 TWh of power annually if all the world’s rivers were put to use. According to the team’s calculations, a power plant operating with 50 cubic meters of freshwater per second could have a capacity of up to 100 MW.

The battery would be best suited for the Amazon River, which drains a large part of South America, but other continents, such as Africa and North America could also benefit. Cui even sug-gested that treated sewage water might work. “If we can use sewage water, this will sell really well,” he said.

POWER DigestItalian Firm Wins Contract to Build Massive African Hydro-power Plant. Italian construction firm Salini Costruttori said on March 31 it has signed a €3.35 billion contract with Ethiopia state-owned Ethiopia Electric Power Corp. to build a 5,250-MW hydropower plant on the Blue Nile, a tributary of the Nile River.

The project, slated to be completed by September 2014, will be the biggest hydropower plant in Africa and will produce power at a cost of 5 eurocents/kWh, Salini Costruttori said. The project site is located 700 kilometers (km) northwest of Addis Ababa in the Benishangul-Gumaz region. The works will consist of a roller-compacted concrete main dam with two powerhouses located on the right and left bank of the river, which will contain 15 Francis turbine units. The project will include a concrete-lined gated spill-way and a 5-km-long, 50-m-high saddle dam on the left bank.

Alstom Begins Construction of Second 400-MW Singapore Gas Unit. Alstom, which in October 2010 signed a contract to build two 400-MW gas-fired combined-cycle units for KMC, a divi-sion of Singapore-based Keppel Corp. Ltd., on April 26 began work on the second €300 million unit. The engineering, procure-ment, and construction contract includes long-term service agree-ments, and Alstom will provide the entire plant and all associated equipment, including two GT26 gas turbines, two steam turbines, two heat-recovery steam generators, and the ALSPA Series 6 inte-grated control system. When completed, the new plant is expected to increase KMC’s production capacity to 1,300 MW. The company currently supplies about 10% of Singapore’s power.

ABB, Partners to Build Hydro Plant in Peru. ABB and con-sortium members Rainpower of Norway and Jeumont of France on April 20 said they had won a power generation order to provide engineering and power equipment to Peru’s Empresa de Gen-eracion Electrica Cheves S.A., a subsidiary of Norwegian energy firm SN Power, for the 168-MW Cheves greenfield hydropower plant. Located in the provinces of Oyon and Huaura, the Cheves project, when completed in November 2013, is expected to alle-viate voltage fluctuations and power cuts that are common to the area. ABB and its partners will provide a “water to wire” solution, which includes the ABB-supplied complete electrical balance-of-plant systems, including gas-insulated substation, generator breakers, medium-voltage and low-voltage switchgear, step-up transformers, plant controls, protection system, and other elec-trical auxiliaries. Rainpower will supply the turbine and Juemont, the generator. The consortium’s scope includes the installation and commissioning of equipment.

AREVA Solar to Install Fresnel Reflectors at Australian Coal Plant. AREVA Solar on April 13 announced it had been awarded an A$104.7 million (US$112.5 million) contract to in-stall a 44-MW solar thermal augmentation project at a 750-MW coal-fired power station in Queensland, Australia. The project, which AREVA Solar is calling “the world’s largest solar/coal-fired power augmentation project,” will involve installation of com-pact linear Fresnel reflector technology at CS Energy’s Kogan Creek Power Station. The company also plans to build and oper-ate a manufacturing facility to support the Australian-pioneered technology and Kogan Creek project. The solar steam generators and accompanying system will occupy about 30 hectares of land within the site. Construction will start this year, and commercial operation is planned for 2013.

RWE, TURCAS Begin Building 775-MW Gas Plant in Tur-key. German firm RWE and Turkey’s TURCAS on April 13 broke ground for a new 775-MW gas-fired combined-cycle power plant in Kaklik, a district of the town Denizli in western Turkey. The €500 million project being built by RWE & TURCAS Güney Elek-trik Üretim, a joint venture, is expected to be complete by the end of 2012. The International Energy Agency forecasts that Tur-key’s energy consumption will double in the next 10 years. RWE officials said at the groundbreaking ceremony that the project served as a strategic step into the growing Turkish market. ■

—Sonal Patel is POWER’s senior writer.

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NERC CIP Update

The North American Electric Reliabil-ity Corp. (NERC) Reliability Standards are under constant revision even while new requirements are under active de-velopment. As noted in the last NERC Critical Infrastructure Protection (CIP) update (“Lessons Learned in Reliability Standards Compliance,” October 2010, available in the POWER archives at www.powermag.com), the standards are con-stantly undergoing revisions, updates, and requests for interpretations. Three important regulatory definitions are cur-rently being contested.

BES DefinitionOn November 18, 2010, Federal Energy Regulatory Commission (FERC) Order 743 directed NERC to revise the definition of the bulk electric system (BES) so that it encompasses all the “Elements and Facili-ties” necessary for the reliable operation and planning of the interconnected bulk power system. NERC believes that this ad-ditional specificity in the definition will reduce ambiguity and establish consisten-cy across all NERC regions in distinguish-ing between BES and non-BES elements and facilities.

NERC includes electrical generation re-sources, transmission lines, interconnec-tions, and associated equipment in the BES. An “element” is “any electrical de-vice . . . connected to another electrical device, such as a generator, circuit break-er, bus section, or transmission line.” A “facility” is a “set of electrical equipment that operates as a single BES element.” Examples include generators, power lines, and transformers.

In addition, NERC was directed to de-velop a process for identifying any ele-ments or facilities that should be excluded from the BES. NERC is working to address these directives in two ways. First, it is modifying the definition of BES through the standard development process. NERC’s second approach is to develop a BES Defi-nition Exception Process as a proposed modification to the NERC Rules of Pro-cedure. One particular problem is FERC’s preference for including all transmission facilities rated at 100 kV and above in the definition of BES. This approach con-tradicts certain regional criteria that cur-rently consider facilities on a case-by-case basis for inclusion in BES, regardless of operating voltage.

On the surface, revising the defini-tion of BES to include all systems rated at 100 kV and above appears to be an easy fix. However, the devil is always in the details. In this situation the uncer-tainty lies with the exception process that identifies facilities operating at or above 100 kV that have minimal or no system reliability impact and therefore are not part of BES.

You can follow future developments by watching NERC project 2010-17 on the NERC website (www.nerc.com) on the Standards Under Development page. Industry members potentially affected by the new definition should watch these developments closely and submit comments.

PRC-005-1 InterpretationIn a Notice of Proposed Rulemaking (NOPR) released December 16, 2010 (Docket No. RM10-5-000, www.ferc.gov), FERC accepted an interpretation sub-mitted by NERC to clarify the scope of equipment to be addressed in standard PRC-005-1 (Transmission and Genera-tion Protection System Maintenance and Testing). Although FERC accepted the in-terpretation that clarified (in part) that equipment such as battery chargers, aux-iliary relays and sensing devices, and line reclosing relays are not included in the scope of PRC-005-1, it then expressed disagreement with the exclusion of such devices and proposed to “direct NERC to develop modification to the PRC-005-1 Reliability Standard . . . through its Re-liability Standards development process to address gaps in the Protection System maintenance and testing standard.”

NERC responded with a request that it be allowed to address FERC’s concerns rather than having FERC issue direc-tives. The NOPR drafting team is cur-rently working on PRC-005 Version 2 to reflect a complete framework for main-tenance and testing of equipment. This unanticipated FERC comment will alter PRC-005-2, which was posted for ballot for May 3 through May 12, 2011. Now the drafting team will either have to re-vise the draft standard for the upcoming balloting or quickly produce a version 3 that will answer FERC’s concerns. Reg-istered entities should closely monitor the ongoing PRC-005 proceedings and be prepared to comment on whichever approach is finally selected.

CIP-002-4 “Bright Line” Criteria and FERC Request for Additional DataVersion 4 of the CIP Standards is currently under review by FERC. The key change in Version 4 is CIP-002-4, which seeks to eliminate the current risk-based assess-ments. Registered entities must apply an-nually to determine asset criticality and replace risk-based assessements with a set of “bright line” criteria that will be used to make the determination. The bright line criteria are a series of thresholds and at-tributes that BES equipment is measured against to determine its criticality. They include, for example, a 1,500-MW thresh-old for generators, the inclusion of black-start resources in a restoration plan, and the ability to produce over 1,000 MVARs of reactive power. There are also thresholds for transmission facilities of 300 MW or higher and for control centers.

On April 12, FERC issued a data request asking NERC what the consequences would be of applying the Version 4 bright line criteria to the BES. For example, how many generators would be deemed critical, how many transmission facilities, and how many control centers? NERC advised FERC that it is able to respond within the allot-ted 45 days on roughly half of the ques-tions, while the remainder would require a survey of registered entities to compile the data. An extension was requested and granted on these specific questions.

CIP standards and their development and revision will remain very high-profile issues for the power industry for some time. Regulators and registered entities continue to work through the details of protecting our bulk electric system against an ever-changing cybersecurity threat.

—Contributed by James Stanton

([email protected]), principal adviser, regulatory services, Quanta Technology.

Air Preheater Uses New Adaptive Brush-Sealing DesignRadial, axial, and circumferential metal-lic seals installed on rotary, regenerative air preheaters have evolved little from the original metal strip designs that date back to the original Ljungström preheaters developed nearly a century ago. Unfortunately, metallic strip seals degrade soon after installation, allow-ing excessive air-to-gas leakage, which translates into increased fuel consump-tion and fan power.

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A Brush AlternativeBrush products are universally applied in virtually all industries where sealing, shielding, cleaning, and/or gap closing are required. Brush filament materials range from synthetic fibers to high-alloy steels. Alloy brush seals, now regularly in-stalled as an upgrade to conventional lab-yrinth seals on production steam turbines, reportedly can yield up to a 2% increase in unit efficiency and a 4% improvement in unit output. Some units with these seals have been in operation for eight years be-tween inspections.

Brush seals are ideally suited for replac-ing strip steels on rotary, regenerative air preheaters. As radial, axial, and circum-ferential seals, the brush products provide a high degree of abrasion resistance, flex life, and bend recovery not possible with rigid strip seals. Rigid strip seals rap-idly wear, as they are unable to conform to surface irregularities and varying gap sizes. The seals wear to the smallest gap size, allowing leakage at the wider gaps. The strip seals are also vulnerable to dam-age at high differential pressures and to expansion due to temperature increases where induced drag can shut down the ro-tor (Figure 1).

A brush seal produces an extremely dense barrier, as thousands of filaments nestle tightly together to create a high-integrity seal. Each bristle is indepen-

dent and flexible, allowing deflection to conform to any irregularities and gap variations and recovery to its original position (Figure 2).

Quantifiable BenefitsAddressing air preheater leakage has his-torically been a low-priority maintenance outage issue for many fossil plant engi-neers. Plants often experience leakage rates in excess of 15% to 20%, and ex-treme leakage rates up to 40% have been measured. These leakage levels are often tolerated because they are typically un-derestimated. As a result, plants can ex-perience capacity losses, increased heat rates, higher parasitic losses associated with fan horsepower, and higher pressure losses for downstream air quality control systems. A plant that has experienced “running out of fan” can often trace the problem to excessive air preheater leakage and its costly side effects.

As an example, a 500-MW plant firing coal and operating at an 85% annual ca-pacity factor consumes 6,000 tons of coal per day, assuming an average heat rate of 10,000 Btu/kWh and an average coal heating value of 10,000 Btu/lb. If increas-es in boiler efficiency due to improved air preheater sealing reduce fuel consumption by 2%, the annual savings in fuel cost is nearly $3 million, assuming a delivered coal cost of $80/ton.

Air preheater leakage can also account for significant increases in parasitic power use by the boiler fans, and these lost power sales opportunities translate into lost revenue. If our example 500-MW plant has 15,000 hp installed fan power and 25% is lost through air preheater leakage, the plant has lost 2.8 MW of capacity that could have been sold. If the plant is operating at an 85% capac-ity factor running 6 hours/day peak and 18 hours/day off-peak with power sales prices of $30/MWh off-peak and $150/MWh on-peak, the plant will lose $1.25 million per year. In essence, the plant is not only paying more for the coal it burns but is also experiencing a reduction in plant revenue—a double whammy to the plant’s bottom line.

A substantial benefit of reducing air leakage on a sustained basis is lower flue gas velocities and resultant pressure loss-es in downstream pollution control sys-tems and a corresponding reduction in fan load. For plants with electrostatic precipi-tators, increased velocities attributable to air preheater leakage may result in higher dust emissions at the stack. For plants with fabric filters, the higher air-to-cloth ratios due to air preheater leakage can affect the frequency of bag cleaning and possibly shorten bag life.

Four Years and RunningThe 119-MW Hardin Generating Station (HGS), owned by Bicent Power, is lo-cated in Hardin, Mont. and is operated and maintained by Colorado Energy Man-agement Inc. (Figure 3). In June 2007, the HGS engineering team and Sealeze (a Richmond, Va.–based unit of Jason Inc.) collaborated to design, manufacture, and install radial and axial stainless steel brush seals on both the hot and cold ends of the plant’s Unit A Ljungström air preheater (Figure 4).

Inspection of the brush seals in 2008 showed them to be in very good condition. Some splaying of the brush was evident on the cold end due to sootblower blasts of 400F steam. To prevent direct sootblower impingement, the brush seals mounted in the path of sootblower blasts have been redesigned to incorporate an angled ori-entation and an integral protective shield, as shown in Figure 5.

Now, with close to four years in service, the brush seals continue to outperform the original strip seals, and expectations are that the brush seals will remain in service through 2011 or 2012. Colorado Energy Management Plant Engineer Kevin Calloway states, “The brush seals have re-

1. Two sealing options. The degree of

wear on a strip seal is evident when comparing a

worn strip seal (left) and a new brush seal (right).

Flexibility of the brush seal allows it to deflect at

the smaller gaps and then rebound to ensure

sealing at wider gaps. Courtesy: Sealeze

2. Clean sweep. XtraSea HT brush seals,

with a malleable alloy foil membrane nestled

within brush filaments, are said to provide

an added 70% to 80% reduction in leak-

age without sacrificing overall seal flexibility.

Courtesy: Sealeze

3. Something old, something new. Construction of the Hardin Generating Station

began in December 2003, and commercial op-

eration was achieved in March 2006. Colorado

Energy Management’s EPC Division provided

construction management for a group of lo-

cal and national contractors. Hardin Station is

unique in that it comprises mostly used equip-

ment, including a 1968-vintage boiler and struc-

tural steel from the original boiler building that

were relocated from South Africa and com-

pletely refurbished. The used steam turbine/

generator was relocated from Korea and refur-

bished. Operation and maintenance services

are provided by Colorado Energy Management.

The Hardin Station has the distinction of being

the cleanest-burning coal plant in Montana and

was the first pulverized coal plant to be built

in that state in more than 20 years. Courtesy:

Colorado Energy Management


duced air leakage considerably, and as a result, we have reduced operational costs through fuel savings.” The brush seals are expected to continue performing through a predicted design life of at least four out-age cycles.

In 2011, the plant is planning to in-stall axial and radial brush seals on all ro-tor modules in its Unit B preheater. The

4. Sealing locations. Ljungström rotor

showing radial brush seals installed. Cour-

tesy: Sealeze

5. Complementary angles. A new

angle-mount design improves bend recovery

and seal contact while deflecting the direct

impact of sootblower blasts. Additional shield-

ing is provided by elongated holder flanges.

Courtesy: Sealeze

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plant’s target leakage goal is 6% to 8% and, to achieve this, the plant is now also considering a complete set of circumferen-tial brush seals.

—Contributed by Patrick T. Fitzgerald ([email protected]) business develop-ment manager, Power Generation at Sealeze.

Twin Pac Controls Upgraded In November 2008, a central Texas util-ity commissioned HPI, a full-service turbomachinery design and construction firm based in Houston, to perform a ma-jor upgrade of its plant’s power distri-bution and turbine control systems. The scope of the project included upgrades to four gas-fired Pratt & Whitney FT4 Twin Pac gas turbine generator packag-es, new programmable logic controller (PLC)–based control panels, generator protection panels, new fuel valves, and emergency batteries and chargers. A single Twin Pac package uses two com-bustion turbines to drive a single dou-ble-ended generator (Figure 6).

The 926-MW plant, originally con-structed in 1967–68, had original gas turbines that were designed for dual-fu-el operation; however, only the natural gas fuel system was in use, and the liq-uid fuel system had been partially dis-mantled. The project also upgraded and recommissioned the liquid fuel system.

Tough Scope of WorkA front-end engineering and design study determined the technical requirements and scope of work for the project. In gen-eral, it required a major refurbishment of the entire station’s electrical systems. Specifically, all the cross-site cables for the four Twin Pacs were replaced in new overhead cable trays. Much of the origi-nal cabling was installed in underground cable runs, which were often flooded by heavy rain. New control subpanels mounted inside existing control cabinets (Figures 7 and 8) were also added, as were new fuel valves.

The project required much demoli-tion work, including removing complete panels and junction boxes. The original cabling within the turbine enclosures was installed at the factory as part of the original package. When the demoli-tion began, workers quickly discovered control wiring mixed in with power cabling that terminated at the motor control center—no longer an accept-able wiring practice.

Instead, all of the control and power cabling was run in separate trays from

the marshalling cabinets to the field to eliminate the possibility of “cross talk” between adjacent wires, an HPI best practice. Digital and analog signals were separated into individual cables for the same reason.

HPI also aggregated the cabling be-tween cabinets, such that all control or power conductors running between points are most efficiently run in a common, multi-conductor cable, where practical. If this practice is not fol-lowed, the number of cables increases dramatically, along with the associated terminal blocks, analog cards in the PLCs, and so on. The cost of the cables

6. Upgrading a Twin Pac. A central

Texas utility recently upgraded its four Pratt &

Whitney Twin Pacs with new wiring, controls,

safety systems, and an updated dual-fuel sys-

tem. Courtesy: HPI

7. A typical 1970s-vintage FT4 governor and sequencer panel. Courtesy: HPI

8. A modern replacement control panel. In addition to the modern digital controls,

the Class I, Div II design of the panel enclosures was retained, ensuring that positive air pres-

sure is maintained inside the enclosure at all times. Courtesy: HPI


and the labor to install the cables also increases—a situa-tion to be avoided.

Package Wiring UpgradedEach of the eight FT4 engines has two thermocouple com-pensation harnesses. To obtain better engine temperature reading and tighter control of the fuel governor, these har-nesses were replaced and new cable runs were installed. The thermocouple wiring harnesses required special cables cus-tom manufactured by a third-party supplier based on HPI’s specifications. As a result of this and other improvements, the engine control system can operate closer to its maximum operating parameters, achieving an overall increase in power output and unit efficiency.

Previously, the fire and gas alarms were a standalone sys-tem producing only an audible alarm. The operator was re-sponsible for recognizing and responding to the alarm and manually tripping the engine(s) if required. New fire and gas monitors were installed and integrated with the turbine control system so that alarms are clearly visible on the main control panel. The new fire and gas alarms now indicate exactly where in the engine and generator compartments an alarm condition has occurred and will automatically trip the engine(s) when needed.

The old seismic vibration and speed probes were replaced with a new Bentley Nevada (BN) 3500 series system, along with its associated cabling. This enhancement of the vi-bration system gives operators greater visibility of the tur-bine driveline’s real-time operating conditions. The entire BN 3500 was integrated with the PLC system, and data is presented graphically on a dedicated vibration page on the main control panel. Finally, the BN keyphasor module was fitted on the shaft of the generator to measure vibration of the gear box shaft.

Challenges FacedDue to this particular utility’s security policies, all project docu-mentation was transported manually rather than sent electroni-cally. A dedicated hard drive, in a sealed workspace, was set up at HPI to support the project. Access to project information was limited to those individuals on the project who were approved to view project documentation. The HPI team was also required to have security clearances, an additional logistical constraint on the project team.

The evolving design of the cabling system during construc-tion meant that the cable schedules were frequently updated, necessitating additional material purchases. The HPI team was able to mobilize additional cable installers to ensure that the project remained on schedule.

Key ResultsThe project was completed in May 2010 after about 10 months total site time. HPI received an “Excellent” rating on all phases of the project from the customer. There were two important reasons for the project’s success. One was effective project management and good communications be-tween the owner and contractor. Another was the fact that an integrated project team composed of controls engineers, installation technicians, and electricians—led by an experi-enced project manager—provided the right mix for handling a project with a dynamic scope of work. ■

—Contributed by Thaddeus Berry ([email protected]), busi-ness development manager, HPI.

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Reliability Challenges Cause Texas-Size Headache By Angela Neville, JD

Even though Texas is again basking in warm weather, federal regulators are still investigating the rolling blackouts that hit the Lone Star state during a record-breaking cold snap

in early February. The bulk power system in Texas experienced a significant number of outages at generating facilities during that period of high demand for electricity. The cold weather knocked offline more than 50 gas-fired and coal-fired generating units, which represented more than 7,000 MW of capacity. To compen-sate for the loss of generation, the state had to import approxi-mately 250 MW of capacity from Mexico.

An Independent Grid for a State with an Independent AttitudeTo put this reliability fiasco in context, it helps to understand the regulatory framework in Texas. Not surprisingly, for a state that was once a sovereign nation and is still known for its maverick attitude, Texas has its own unique grid system that sets it apart from the rest of the U.S. Under the regulation of the Public Utility Commission of Texas, the Electric Reliability Council of Texas (ERCOT) rides herd over the flow of electric-ity to 23 million Texas customers, representing 85% of the state’s electric load and 75% of its land area. ERCOT manages a grid that connects 40,500 miles of transmission lines and more than 550 generation units.

When the rolling blackouts happened in February, ERCOT land-ed in the hot seat. Texas state lawmakers conducted a hearing on February 15 demanding to know what went wrong. Several lawmakers pointed out that northern states routinely deal with worse weather without experiencing rolling blackouts.

ERCOT CEO Trip Doggett testified about the actions his orga-nization planned to take to ensure that such outages don’t oc-cur again. For example, he explained that ERCOT had launched a new alert system that, in the event of potential outages, would alert state officials and the state operations center, which in turn would notify police, firefighters, and first responders.

Due to increased scrutiny of the Texas grid caused by the blackouts, a number of long-time critics of electric deregula-tion in the state are now trying to reopen the debate on that issue. When full deregulation began in Texas in 2002 after the passage of Texas Senate Bill 7, state officials insisted Texas could implement a more successful system than California, where intermittent blackouts had contributed to the failure of deregulation a year earlier. Basically, deregulation in Texas divided up utility monopolies, fostered competition between companies that sell electricity to consumers, and encouraged power generation facilities to compete against one another. Although the recent blackouts have increased concerns about the deregulated system, no Texas elected officials are actively promoting new legislation to re-regulate the Lone Star power

industry. Therefore, it does not appear likely that Texas will abandon electric deregulation any time soon.

FERC and NERC Launch Separate InquiriesIn an interesting regulatory twist, the Federal Energy Regula-tory Commission (FERC) currently is examining the Texas outages even though it does not regulate ERCOT directly. The agency does monitor electricity reliability in Texas, however, through its over-sight of the North American Electricity Reliability Corp. (NERC), the nation’s reliability watchdog. NERC’s Texas regional entity, the Texas Reliability Entity Inc. (Texas RE), is the agency that regulates the state’s electricity reliability performance.

FERC already had the Texas RE up on its radar screen before the February outages. In November 2010, FERC issued an audit report in which it identified concerns related to Texas RE’s close relationship with ERCOT in light of the fact that Texas RE’s role is to monitor ERCOT’s reliability performance. Additionally, the report criticized Texas RE for not effectively overseeing ERCOT’s compliance with reliability standards. “Texas RE acted promptly to address these areas of concern,” according to the report.

FERC’s current inquiry is intended to identify the causes of the February disruptions and any appropriate actions for preventing their recurrence. In late April, as this column was being written, a FERC spokesperson told POWER that the inquiry was still ongoing.

Likewise, in February, NERC President and CEO Gerry Cauley announced that, in response to the February outages, his agency was working to examine the adequacy of preparations and iden-tify potential improvements and lessons learned. He stated that “two efforts will be launched to meet these objectives.” At press time, NERC was continuing its “lessons learned events analysis.” A NERC spokesperson told POWER that the agency “expects to have its report completed in an August time frame.”

Neither agency is expected to bring enforcement proceedings in relation to the February outages.

Keeping the Lights on Deep in the Heart of TexasHere’s hoping that the FERC and NERC inquiries produce useful information that can be passed along to the regulated commu-nity. Going forward, utilities operating in Texas need to focus on providing better oversight of their generation facilities in order to enhance reliability and prevent future widespread outages.

“If you don’t like the weather in Texas, just wait five minutes, and it will change” goes a popular saying. Given the unpredict-ability of Lone Star weather, Texas generating facilities would be well advised to focus on the lessons learned from the recent out-ages so they can be better prepared when the next “blue norther” on steroids hits the state. ■

—Angela Neville, JD, is POWER’s senior editor and a fourth-generation Texan.

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INFORMATION TECHNOLOGY

Artificial Intelligence Boosts Plant IQ

In February, viewers of the quiz show

Jeopardy! watched as IBM’s supercom-

puter Watson soundly defeated the all-

time game show champions Ken Jennings

and Brad Rutter. Watson’s victory has been

viewed by those who work in the field of

information technology (IT) as a milestone

event. The game show victory marked the

first time a machine had sufficient data recol-

lection speed, discernment accuracy, and reli-

ability to compete with humans in a real-time

test of judgment and knowledge, and win.

Watson not only retrieved data quickly,

like many of today’s popular Internet search

engines, but the supercomputer also assessed

the available data and made a judgment as to

the most appropriate answer (Figure 1). This

success was not based on a single computer

program; instead, it required many programs

working in parallel to achieve an elementary

level of artificial intelligence (AI).

Does this singular computational victory

of machine over man have implications for

the design of control systems for future pow-

er plants? To capitalize on AI technology in

the future, we need to look beyond how IT

is used in power facilities today and leverage

long-established advanced distributed con-

trols platforms to support virtual plant opera-

tions. The implications of doing so could be

significant and range from minimizing, or

even eliminating, human factors engineering

issues in plant operations to allowing hyper-

performance optimization that promises sig-

nificant operating cost savings.

The Future Is ForwardTo get a good understanding of where we might

leverage Watson-like technology advancements

in the future, we need to quickly review the his-

tory of power plant control development.

Power generation is generally a very con-

servative industry when it comes to accept-

ing new technology. This stance is justified

by the critical nature of the product that must

be supplied instantly, continuously, and with

Neural networks have already found practical application in many plants, and recent advancements in artificial intelligence promise to shape the design of the next generation of power plant supervisory controls. Will future plant operators be fashioned from silicon?

By James H. Brown, PE, PMP, Fluor Corp.

Courtesy: IBM

1. Watson’s avatar. Watson, named after

IBM founder Thomas J. Watson, was built by

a team of IBM scientists who set out to ac-

complish a grand challenge: build a computing

system that rivals a human’s ability to answer

questions posed in natural language with

speed, accuracy, and confidence. The Jeop-

ardy! format provided the ultimate challenge

because the game’s clues involve analyzing

subtle meaning, irony, riddles, and other lan-

guage complexities in which humans excel and

computers traditionally do not. Courtesy: IBM

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very high reliability. However, simply rely-

ing only on fully mature technology, as is

our habit, may result in a significant lost op-

portunity to modernize the power generation

infrastructure. Technology advancements

are already under way with many smart grid

projects that promise to improve the process

and cost of delivering electricity. Similarly,

new and emerging technologies that leverage

IT should be considered when planning for

future power plant controls.

As a major international engineering,

procurement, construction and commis-

sioning firm and technology integrator for

gas-fueled, solid-fueled, and nuclear power

facilities, Fluor Corp. has had the unique

opportunity to work with just about all ma-

jor suppliers for power plant distributed

control systems (DCSs), programmable

logic controllers, instrumentation/automa-

tion, and network components communi-

cating in various protocols over a range of

different control system architectures. Two

previous articles (“Digital Networks Prove

Reliable, Reduce Costs,” July 2009 and “TS

Power Plant, Eureka County, Nevada,” Oc-

tober 2008, available in POWER’s archives

at www.powermag.com) reviewed what are

generally considered to be state-of-the-art

digital control power system designs.

Artificial Intelligence PrimerIn very simplistic terms, AI enables com-

puters to think like humans to solve prob-

lems. When applied to power facilities, AI,

perhaps more correctly called intelligent

control, collects data from the plant and,

when combining that data with stored data

from library resources, is able to “learn”

the appropriate response based on a prede-

termined desired state or some external re-

quest to achieve another state of operation.

Many researchers consider systems that

learn from their actions and make good

decisions with incomplete information as

having a form of artificial intelligence.

Neural networks take inputs from the en-

vironment and process them to determine

patterns and relationships and then point to

a directed output (Figure 2). In human intel-

ligence, neurons in our brains learn how to

respond to daily stimuli. Neural networks al-

low computers to artificially mimic this same

process recognition and classification of

data. The AI neurons are connected by vary-

ing strengths (as represented by various line

weights in the figure).

Although the diagram is simplistically

shown in two dimensions, there are actu-

ally multiple layers—in space and time—

for the connections. Depending on the

complexity of the stimuli, there could be

a few connections or an extensive network

of connections. Processing numerous con-

nections in parallel and keeping track

of the results allows the neural network

to “learn” from experience and store or

memorize the end result. The network can

subsequently retrieve millions of prior ex-

periences quickly to make value judgments

in similar circumstances in the future.

Classical control systems have been pro-

cessing data and determining outputs for

quite some time. Conventional control prac-

tices work best when the systems are not

overly complex. These control systems rely

on alarms to ensure operator notification if

the process is approaching or achieves an

“out-of-control” or abnormal state.

The more complex the application and

the more diverse the conditions under

which it operates, the more complicated

the control system becomes. When the

process being controlled is very complex

and has to operate under a wide range of

conditions and disturbances, AI technol-

ogy enhances classical control theory tech-

niques. This type of control, based on AI

layering, is referred to as intelligent con-

trol. Incorporating AI into control systems

allows these systems to be more flexible,

to adapt to various operating conditions

and disturbances, and to incorporate hu-

man expertise and thinking into their deci-

sion-making process.

AI terminology has been somewhat for-

eign to the power industry. The lines be-

tween classical control and AI are sometimes

blurred. Familiar fuzzy logic design is an

area where classical controls have incorpo-

rated elements of AI.

Data ProliferationAt the core of intelligence is raw data. For

power generating facilities, we have seen an

exponential increase in available plant data

stored in plant databases and historians.

This growth in data has come from many

different sources.

The first source is the general growth

in plant automation as distributed control

systems replaced manual plant controls.

Another source of growth in data has been

from the advancement of predictive and

preventive maintenance in power stations.

As digital communications have spread

throughout the design architecture of new

facilities, more data is more easily accessi-

ble, and this has led to significant increases

in available data sources or inputs. Finally,

in our current state of interactive human/

nonhuman controls, significant data is col-

lected through plant alarm systems designed

to assist operations when the plant is out-

side of the normal bounds of control. Those

situations can present significant challenges

to operators if the alarms are not properly

managed through prioritization and filtering

of extraneous or duplicate alarms.

In addition to the growth in field data col-

lected, volumes of data from the many com-

ponents that make up today’s modern power

plant are available as resource information.

This data sometimes includes initial check-

out and testing data, preventive maintenance

requirements, maintenance records, and

equipment operating curves.

As an example of how voluminous the

data can be in state-of-the-art plant control

systems, Fluor recently completed a 2 x 800-

MW supercritical coal facility that includes

more than 15,000 physical instrument tags.

This facility incorporates some of the most

Input Output

Input layer Hidden layer Output layer

2. Capturing experience. Neural networks artificially mimic the human brain in process

recognition and classification of data. The complexity of the stimuli (input) determines the num-

ber and strength of the pathways (illustrated by line weight) that determine the result (output).

Processing numerous connections in parallel and keeping track of the results allows the neural

network to learn from “experience.” Source: Fluor Corp.



advanced control bus technologies. Over

70% of the more than 30,000 total plant

inputs and outputs (I/Os) are digital. More

than 8,000 alarms are programmed into the

DCS controls.

Artificial Neural NetworksAs more and more actions in power plants

have become automated, control hardware

and software have advanced. Today’s open

structure DCS gives programmers a more

user-friendly interface into which they can

incorporate control philosophies that are

very complex and sophisticated. Advances

in controls technology have added many

functional capabilities to new control sys-

tems while expanding the complexity of

the processes managed and the potential

span of control.

Although proportional-integral-derivative

(PID) control has not significantly changed in

25 years, there has been significant advance-

ment in the hardware and software to support

the faster processing speeds and increased

reliability necessary for today’s plant envi-

ronments. As the amount of available plant

data grows and the pressure to incorporate

complex optimization technology increases,

classical controls will quickly reach the limit

of their capabilities.

For the power generation industry, rule-

based AI neural networks can be applied

in at least three ways: in grassroots neural

networks, neural network oversight of con-

ventional or classical controls, and neural

network oversight of conventional classi-

cal controls in specific application areas of

plant control.

Grassroots Neural Networks. Com-

pared with other process industries, the power

industry typically takes a more conservative

approach when it comes to the introduction

of new, unproven technologies. For example,

digital bus controls have slowly been intro-

duced into the industry over the past decade.

Fluor implemented many of this industry’s

first fieldbus instruments almost two decades

ago in a number of combined-cycle power

plants. At the time, the fieldbus instruments

were limited primarily to monitoring func-

tions, because their use in process controls

was considered as having technology risks.

Today, Fluor has completed facilities in

which greater than 70% of the plant I/Os are

transmitted on digital bus networks.

The process of gaining widespread ac-

ceptance of making a new, grassroots neural

“The factory [power plant] of the future

will have only two employees, a man and a

dog. The man will be there to feed the dog.

The dog will be there to keep the man from

touching the equipment.”

—Warren G. Bennis




network part of the design of a new power

facility may be slow and arduous.

Neural Network Watchdog. Perhaps a

more likely scenario for widespread imple-

mentation of AI in power generation is a

neural network that can essentially “sit on

top” of a plant’s existing DCS. Such an AI

system will monitor, learn, and make value

judgments about potential changes in state to

optimize plant operation in order to improve

safety or, perhaps, plant reliability. These ar-

tificial neural networks are relatively mature

and commercially available today.

With the growth in automation in power

generation facilities, the incredible complex-

ity of monitoring plant operations, noting

anomalies, diagnosing those anomalies, and

taking action in a timely manner can quickly

become unwieldy and unmanageable us-

ing conventional controls technology. On

the other hand, artificial neural systems can

“view” numerous process variables almost

instantly, recognize trends or deteriorating

conditions or opportunities to improve condi-

tions, review a library for potential reactions,

and make weighted judgments on the best ac-

tion. The result can be significant benefits to

plant operations.

The neural network systems offered

by some of the major process technology

providers are open systems that work with

various suppliers’ DCS platforms. These

commercial systems are available to au-

tomatically make decisions to optimize

performance of a plant subsystem, such

as combustion controls. AI systems can

also be configured to act as an operator

consultant—a decision-support system—

to make recommendations on operating

adjustments.

Targeted Process Neural Network

Watchdog. AI systems currently used in

power plants are usually targeted to spe-

cific application areas of process control

such as combustion optimization or plant

performance. Much as with the advance of

digital controls, this stepwise adoption of

the technology provides sufficient testing

to make users comfortable with the intelli-

gent algorithms without exposing early AI

system adopters to the risk of reduced plant

reliability.

Already, numerous operating plants in-

corporate some form of targeted neural net-

works. Some plants have used some form of

AI-based controls to reduce NOx production

and to optimize their boiler cleaning or soot-

blowing systems. Some of the applications

have years of operating experience at power

generation facilities.

Watson as Your Virtual Plant OperatorClaims of improvements up to 1.5% in plant

heat rate, reductions in emissions levels, im-

provements in equipment availability, im-

provements in steam turbine ramp rates, and

improvements in start-up efficiencies are all

claims made by vendors of AI networks. The

promised benefits are significant, but there

are consequences to moving forward on AI-

based plant controls.

Critics of AI systems are quick to point

out the potential vulnerabilities that are intro-

duced with regard to cybersecurity when so

many systems are operating over plant net-

works (voice over Internet protocol, security,

plant network, operations network, and the

like). This is a significant issue that warrants

study, particularly in light of recent North

American Electric Reliability Corp. require-

ments for Critical Infrastructure Protection.

Network defense systems and monitoring are

sufficient to protect against unwanted intru-

sions, but clearly, widespread implementa-

tion of AI at power plants may make control

networks more vulnerable.

Another consideration is that AI-based

control systems “learn” from prior experienc-

es. Any system will require time to “think”

through the innumerable possible combi-

nations of process variables and operating

scenarios before it matures and develops a

library of operating scenarios and responses.

The system will also require clear exit paths

and mitigation programs should its complex

networks get “stumped.”

Finally, expect some resistance to accept-

ing AI-based controls at a more philosophi-

cal level. Some system designers believe that

intelligent control systems have the potential

to breed a culture of superficial knowledge.

Today, many plants can still be operated

manually by experienced operators. When,

in the future, reliance on AI systems is the

norm, what will be the motivation to push for

more understanding of the operating nuances

and situational responses necessary when op-

erating a plant? Will the hands-on operator

become obsolete?

On the other hand, the adoption of intel-

ligent systems may be one solution to the

expected loss of a vast amount of operating

knowledge as the baby boomer generation

approaches retirement age. How to capture

that knowledge remains problematic and is

the subject of current research.

What we have learned so far is that Watson

has proven to be a great game show player. But

we also know that it (he?) is not ready to operate

a major power generation facility . . . yet. ■

—James H. Brown, PE, PMP ([email protected]) is senior director of

engineering for Fluor Corp.’s Power Group.

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POWER POLICY

Spain: A Renewable KingdomSpain has served as both exemplar and scapegoat when it comes to renewable

energy policy. Though power policy must necessarily accommodate spe-cific national resources and goals, Spain’s experience as an early and eager adopter of renewable energy technologies and subsidies is a cautionary tale of how the best intentions can have unintended consequences.

By Sonal Patel

Spain, the fifth-largest economy in the euro zone, has been slammed by the global economic crisis and faces a criti-

cal energy dilemma. Struggling to tamp down power prices, but unable to afford billions of euros in funding, the debt-burdened govern-ment has been forced to retroactively slash its subsidies for renewables—a measure that has frozen investment in renewables and battered the nation’s once-booming solar industry. Meanwhile, policies to phase out coal power have destroyed Spain’s domestic coal min-ing industry and prompted debilitating strikes by coal miners. The nation’s nuclear power sector, too, is under siege: A moratorium on building new reactors has driven the govern-ment—amid opposition that was intense even before the Fukushima Daiichi emergency this March—to extend the lives of aging reactors.

The Kingdom of Spain saw more than two decades of dizzying economic growth before the abrupt contraction in its economy in mid-2008. Its gross domestic product (GDP) growth rate reached a historic high of 1.53% in Decem-ber 1997 and a record low of –1.70% in March 2009. The nation exited the recession last year, but it continues to face soaring unemployment. Nearly 20% of Spain’s 45.9 million people are jobless—the highest rate in the 27-member European Union (EU). Despite government efforts to boost the economy through stimulus spending and loan guarantees, the government budget deficit increased from 3.8% of GDP in 2008 to about 11% in 2011. To control the defi-cit (and reduce it to 6% by next year), as well as avoid financial contagion from other highly indebted euro zone members like Ireland and Greece, the government has implemented aus-terity measures, tried to privatize industries, and attempted to boost competitiveness through la-bor market reforms.

Most economists blame the economic woes on a burst housing bubble and the in-ternational credit crunch. Others, like Dr. Gabriel Calzada Álvarez, an economics pro-fessor at the Universidad Rey Juan Carlos in Madrid, point to the government’s substantial subsidies for the country’s inflated renewable energy sector, which Álvarez has said created

large debt bubbles and artificially created a new market that would collapse without more public funding.

In a much-cited, controversial March 2009 report on the effects that renewable subsidies have on employment, Álvarez contends that between 2000 and 2008, Spain’s government spent more than $36 billion to subsidize renew-able projects, while consumers paid almost $10 billion more for renewable power than set mar-ket cost. Álvarez also suggests that the resulting higher energy costs and “green” jobs may have more than doubled job losses economy-wide. Critics of the report say his analysis was “too simplistic” to be applied as a real-world model and that he deviated from peer-reviewed meth-odologies to estimate job impacts.

Creating a “Sustained” Renewable Policy FrameworkIn 1980, Spain’s social-democratic Socialist Workers Party enacted a law after the second international oil crisis to support what they called a “sustained” framework for the devel-opment of renewable energy. In 1997 another law was ratified that deregulated the power market while mandating that 12% of primary energy demand was to be met with renewable sources by 2010. By 2005, when it became apparent that objective would be difficult to achieve, the government approved a new Renewable Energies Plan calling for 29.4% of gross electricity demand to be covered by renewable sources by 2010.

To support sales of renewable power, the government put in place a feed-in tariff sys-tem, establishing fixed tariffs to be paid on top of market prices for renewable power in-stallations. (See “The Feed-in Tariff Factor” in our Sept. 2010 issue or in the archives at www.powermag.com.) Later, in June 2009, a directive based on targets set by the EU called for 20% of final gross energy demand to be met with renewables (and for cutting greenhouse gas emissions by 20% compared with 1990 levels).

The mandates have transformed Spain’s generation mix. Compared with the 1990s, when coal, hydro, oil, and nuclear facilities

1. Spain’s electricity profile. Installed

power capacity in Spain’s electricity system in

2010 amounted to 103,086 MW. Power actu-

ally generated totaled 275,252 GWh, including

reductions for self-consumption, pumped stor-

age consumption, and international exchanges.

“Factoring in the effects of seasonal and work-

ing patterns, the annual [demand] growth was

2.9%, compared to a fall of 4.8% registered in

2009,” grid operator Red Electrica de Espana

(REE) said in its annual report. Source: REE

Note: Total does not include 7,555 GWh used for self-

consumption. “Gas” includes power generated by inte-

grated gasification combined-cycle, conventional gas,

combined-cycle gas turbines, and oil/diesel generation.

Power generated, 2010

Combined cycle 23%

Nuclear 21%

Wind 15%

Other renewables

14%

Hydro 13%

Coal 9%

Gas 3%

Solar 2%

Combined cycle 26%

Wind 19%

Hydro 16%

Coal 12%

Other renewables

10%

Nuclear 7%

Gas 6%

Solar 4%

Installed capacity, 2010


POWER POLICY

generated nearly 99% of the nation’s electric-ity, in 2010, those four sources accounted for 69%. Gas-fired generation has grown expo-nentially in response to increasing amounts of variable wind power that require back-up generation and to meet swelling demand (a report by Spanish law firm Gomez-Acebo & Pombo notes that “Spain has one of the high-est rates of energy consumption per unit of [gross national product] in the EU”). Wind power, meanwhile, surged from 5 TWh in 2000 to 42 TWh in 2010 (Figure 1).

“Without doubt, the main factor underpin-ning our success in integrating [renewable] sources into the electricity generation system has been the economic and legal framework comprising a system of regulated premiums and feed-in tariffs, which has been in force for the last 30 years and has been subject to ongoing improvements and modifications,” says Miguel Sebastián Gascón, minister for Industry, Tourism and Trade in a government renewables-specific website. The minister also says the country’s solar thermal, wind, and other sectors are among the largest in the world, and that it is on course to exceed the EU’s 20% renewable target. He adds: “This framework is stable but adaptable to the cur-rent status of each technology as it matures.”

Industry StructureSpain today splits its generating units into two groups—ordinary and special regimes—based on how they interact with the com-petitive electricity market. Five companies generate the bulk of conventional power, which includes large hydro, nuclear, coal, and gas: Iberdrola, Endesa, Gas Natural Fenosa, E.ON, and HidroCantábrico. All genera-tors under the ordinary regime sell power to suppliers through the wholesale market pool or bilateral contracting and receive remu-neration for power sold on the market, plus capacity payments (including 10-year invest-ment payments that vary according to the net power of the plant).

Special regime generators—those that pro-duce power from renewables with installed capacities of up to 50 MW and cogeneration fa-cilities—are not required to bid in the power pool and are permitted to sell power at government-ordained tariffs or at the Spanish pool price, plus premiums and incentives. In 2010, according to grid operator Red Eléctrica de España (REE), special regime generators produced 33% of the country’s peninsular power.

Growing Demand and CapacityPeninsular Spain’s electricity demand

(excluding its islands) currently exceeds 259,940 GWh, having risen 30% since 2000. The increase would have been more dramatic were it not for the economic slowdown, when demand plunged 5%, from 265,281 GWh in 2008. In 2007, industry consumed 38% of Spain’s generated power, followed by the services and agricultural sectors. Households consumed 33% of all power generated.

2. Pumping up wind. Spanish renew-

ables giant Iberdrola’s 1989-built 635-MW

La Muela pumped storage facility will be fol-

lowed by the 852-MW La Muela 2, slated to

be operational in 2012. The ability to dispatch

pumped storage power helps to mitigate the

variability of wind power. Courtesy: Iberdrola

The UDI Combined-Cycle and Gas Turbine (CCGT) Data Set links plant contact

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power, and auto-producer power stations in 160 countries. Approximately 6,300 of

these sites are in operation (1.7 GW) and contacts and/or mailing addresses are

available for nearly 3,500 of the larger installations which account for 1.5 GW of

available capacity.

For more details, visit www.udidata.com, or call your nearest Platts office:

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POWER POLICY

National energy plans drawn up before the recession call for substantial increases in total generation (72 TWh between 2008 and 2016) to fuel future growth, including further ramping up of gas power by 42 TWh and wind power by 33 TWh, but cutting coal-fired generation by 23 TWh and oil by 10 TWh. An increase of nuclear power is also foreseen—but only through uprates.

Spain has already made great strides in adding new capacity. The International Ener-gy Agency (IEA) reported that from 2001 to 2008, total capacity increased by 87%—one of the largest hikes for a member country. As of 2010, about 95% (97,447 MW) of capac-ity was installed in the peninsular system and the rest, 5,639 MW, was installed in other territories, including the Canary Islands and Balearic Islands.

The Renewable FutureBecause of its size and geography, Spain’s climate varies substantially by region (see a map of all of Spain’s power plants at http://bit .ly/hiFN3h). And climate has influenced its choice of renewables.

Hydro. About 1,200 hydro plants with a total installed capacity of 18.97 GW have been built in Spain, 20 of which are 200 MW or larger, and at least 2,400 MW of which is pumped storage (Figure 2). Though these represent about 50% of the hydro total, they have been underperforming since 2004, most-ly because of increased droughts (blamed by the government on climate change). In 2010, however, the nation saw abundant rainfall that allowed hydroelectric facilities to gener-ate 36.6 GWh—30% higher than the histori-cal average and 65% above the 2009 figure.

But droughts and fierce opposition by environmental groups aren’t the only rea-sons large hydropower plants will not be counted on as significant future energy sources. In addition, “there are [no more] available spaces in our rivers for the in-stallation of a big hydro plant,” explained David Gomez, the director of energy for Spain’s Trade Commission, based in Los Angeles. The country intends to exploit all its hydro potential, he told POWER, through so-called “mini-hydro plants” of less than 10 MW, which are subsidized through feed-in tariffs.

Wind. Wind is faring better. Spain boasts that wind power produced 42,976 GWh in 2010—15% of total generation. The sector’s rapid growth, reportedly boosted by premi-ums and feed-in tariffs, has been aided by a burgeoning wind manufacturing industry. Several wind turbine makers have set up shop in Spain, including Gamesa, Eólica, Accio-na Windpower, and Alstom-Ecotècnia, and Spanish wind farm developers like Iberdrola

and Acciona Energía have projects all over the world. The component supply chain, too, is thriving: 75 industrial centers related to wind exist in Spain, 18 of which are wind turbine assembly plants.

Solar. In contrast, the solar photovoltaic (PV) sector, which over the past five years saw a similar—maybe even more pro-nounced—boom driven by high subsidies, has been frozen by uncertainty following the government’s December 2010 decision to retroactively slash previously agreed-upon subsidies to solar energy producers.

Meanwhile, the country maintains its dominance in the solar thermoelectric sec-tor (see the sidebar). More than a third of worldwide solar thermal electric capacity is installed in Spain. The country that commis-sioned the world’s first commercial central tower plant (the PS10 plant in Seville, Figure 3) in 2006 after establishing a feed-in tariff, is actively developing projects to increase solar thermal capacity to 2,400 MW by 2013—and it is building and managing several projects around the world. Of new capacity planned, 93% will likely be parabolic trough receiver technology, central towers will make up 3%, and the remainder will be Stirling dish and Fresnel receivers.

Biomass. Feed-in tariffs for biomass were also implemented in 2007, but growth for that sector has been slow because the remunerative framework that could spark significant growth was “enacted practi-cally as the recession hit,” the Ministry of Industry said. Today, Spain has some 400 MW of installed biomass capacity, fueled by products from the pulp and paper, tim-

ber, and olive oil industries.Other Renewables. Spain has yet to

fully develop its marine and geothermal power sectors. Valencia-based Iberdrola Renovables is spearheading a project to in-stall 10 Ocean Power Technology buoys for a total rated capacity of 1.35 MW at a pi-lot marine energy plant in Santoña. Mean-while, though studies have shown Spain has substantial geothermal resources, no power plants exist. Geothermal energy is being developed for heating, however.

3. A solar beacon. The €35 million ($49

million) 11-MW PS10 concentrating solar pow-

er tower, a facility featuring 624 heliostats,

went into operation in 2007. In 2009, owner

Abengoa Solar completed PS20, a 20-MW

solar tower facility at the same platform in

Sanlúcar la Mayor. It later began operating

Solnova 1, 3, and 4, three of five planned 50-

MW parabolic trough plants. Along with two

other 50-MW projects (Solnova 2 and 5), an-

other 20-MW tower plant (AZ20) and an 80-

kW concentrating solar plant based on Stirling

dish technology are under construction there.

Courtesy: Abengoa Solar

Energy Technology Investments

Spurred by policy drafted by the coun-

try’s Ministry of Science and Innovation

and boosted by public funding that cov-

ers basic and applied research to pilot and

demonstration projects, Spain has quickly

become a well-respected hub for energy

technology. Three primary institutions

have been pivotal in the rollout of new

technologies, from carbon capture to solar

thermal: CIEMAT, CENER, and CIUDEN.

CIEMET, the center for energy, envi-

ronment, and technological research, is

best known for its 250-acre Plataforma

Solar de Almería, a facility that tests and

optimizes numerous concentrating solar

power concepts. CENER operates a major

wind turbine test facility that includes

an experimental wind farm. CIUDEN,

located in the coal-mining region of El

Bierzo, carries out research and devel-

opment on clean coal technologies. The

institute is building a €72 million dem-

onstration plant for carbon capture with

oxyfuel combustion.

Privately funded research is also making

headway. Wind turbine maker Gamesa in

February, for example, announced it was

developing two families of offshore tur-

bines, the 5-MW G11X (to be tested in late

2012 in collaboration with German power

company E.ON) and the G14X, which could

have a capacity of up to 7 MW (a pre-series

is expected to be ready in 2014). Gamesa

and Spanish firms Acciona and Iberdrola,

among others, are also spearheading the

Azimut initiative, which seeks to develop

a 15-MW offshore wind turbine using only

Spanish technology.

WE

ST

IN

GH

OU

SE

E

LE

CT

RI

C C

OM

PA

NY

L

LC

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E N E R G I Z I N G T H E W O R L D F O R 1 2 5 Y E A R S



POWER POLICY

Subsidies: The Shadow on Solar and WindSpain began subsidizing renewable and combined heat and power sources after the adoption of its Electric Power Act in 1997. In 2004, a new law allowed renewable power generators to choose between a regulated tariff or a market price plus premium. And in 2007—after the EU established a target for member countries to source 20% of their power from renewables by 2020—another law set high and low electricity purchase price levels for some technologies.

The level of public financial support and total revenues per kilowatt-hour varied sig-nificantly. In 2008, for example, wind gener-ators received €0.069 to €0.086/kWh ($0.10 to $0.12/kWh), while solar PV producers got almost quadruple that: €0.32/kWh. This sub-sidy mechanism, the so-called “feed-in tar-iff,” was guaranteed for 25 years, or for the lifetimes of the systems, to increase investor confidence.

And it worked. Generous subsidies rapid-ly boosted PV development in Spain. By the end of 2008—just as the economic crisis hit the country—solar PV capacity had exceed-ed the initial capacity target for 2010 more than eightfold.

After the onset of the financial crisis, the price of electricity from new PV projects was lowered to €0.259/kWh from €0.440/kWh, reports The Global Subsidies Initiative (GSI), an international watchdog that monitors “the transfer of public money to private interests.”

By comparison, the market price for electric-ity from natural gas, for example, has been under €0.045/kWh. According to the GSI, in 2009, solar PV tariffs alone amounted to €2.7 billion, though the sector supplied only 2% of Spain’s electricity. GSI points out that wind producers received €600 million for supply-ing 12% of the country’s power.

Another critical problem with Spain’s feed-in tariff system is that instead of allow-ing utilities to charge more for renewable power bought at above-market prices (and letting consumers bear the brunt of the hikes), the nation has preferred to keep the price of power artificially low. That means that utili-ties have shouldered the burden, operating at a loss and trusting in a government guarantee to eventually pay them back. Sources say the sum of this “tariff deficit” has ballooned to more than €16.5 billion since 2000.

Then, last year, faced with an economic crisis and buckling under an overall burden of debt, Madrid drastically cut spending and implemented austerity measures that includ-ed slashing renewable subsidies. On Christ-mas Eve, the Industry Ministry announced it would slash PV solar subsidies between 10% and 30% for existing projects until 2014—or €3 billion over the next three years.

PV backers, including foreign private eq-uity groups and specialist funds, are outraged by the possibility that cuts will be imposed retroactively (on plants built before 2008). Filing lawsuits, they say government’s “sud-den reversal in policy” breaches long-term contracts, and it could drive many of them out of business. Legal challenges have already been filed by the regional authorities of Ex-tremadura, Murcia, Navarra, and Valencia; at least 15 international investors, who have pumped more than €4 billion into Spanish so-lar PV projects, are also seeking reparations.

European Commissioners Guenther Oet-tinger (for energy) and Connie Hedegaard (for climate) have also chimed in about the cuts ordained by Royal Decree 14/2010 and approved by the lower parliament earlier this year. They warned that “forward-looking changes [to tariffs] may be understandable and necessary,” but that the European Com-mission “will not accept retroactive amend-ments.” Further, they argue, the nation’s cap on the number of production hours when solar generators can earn above-market rates adds to a perceived risk of investing in re-newables. “Without stability and predict-ability, there will be more risk of delays,” the commissioners wrote to Industry Minister Miguel Sebastian on Feb. 22. “You must not forget that the negative consequences for in-vestors’ confidence from retroactive changes in the economic conditions of one type of renewable facility may spread and produce

similar effects for other types of facility in other countries.”

In March, Industry Minister Miguel Se-bastian promised PV investors his department would “find solutions to prevent irreparable damages” to the sector. Key participants are hopeful: In July last year, the government managed to reach an agreement with the wind power sector under which it would cut top-up rates to wind producers by 35% until 2013—a measure that could save it €1.3 billion.

In the last week of March, Reuters report-ed that Spanish energy regulator Comision Nacional de Energia (CNE) had suspended subsidies for 350 PV systems alleged to have been providing fraudulent power production figures. PV Tech quoted the Spanish Renew-able Producers Association as saying that owners of as many as 9,000 of Spain’s 55,000 registered PV systems could be questioned (most, for technical issues dealing with reg-istration, it claimed). CNE had drafted a bill to prevent solar fraud in January 2009 after some plants were exposed for receiving sub-sidies without actually generating power.

Coal Use Contracts, Natural Gas Use ExpandsThe rise of renewables in Spain has increased natural gas use and, as expected, constricted coal use. Spain—a once-thriving coal export-er—in recent decades has turned to import-ing nearly 73% of its supplies, mostly from South Africa, but also from Indonesia and Russia. About 90% of all coal is used to gen-erate electricity, producing 25,851 GWh—or about 9% of total generation. This compares with 74 TWh of coal-fired power produced in 2007, which made up almost 24.8% of total generation.

Coal use, as frequently explained by in-dustry analysts, has been affected by pol-lution requirements and competition with natural gas. Electricity industry association UNESA claims that coal-fired power plants in Spain have an average efficiency of 37% and emit 930 kg of carbon dioxide/MWh, whereas combined-cycle gas turbines are 52% efficient and emit 365 kg of the green-house gas per MWh. That makes coal gen-eration expensive to operate under the EU’s cap-and-trade program. Other reasons for the drop are that coal plant operators have had to take plants offline to abide by increasingly rigid EU directives, and the operation of coal plants that are used to supplement hydro is dependent on hydrological conditions.

This is not to say that the sector will disap-pear altogether. Spain’s Prime Minister José Luis Rodríguez Zapatero, who comes from the coal heartland of León, in October 2010 won the European Commission’s approval to subsidize—but only until 2015—utilities that

4. Gas-guzzling. Since 2000, gas-fired gen-

eration has grown by 101 TWh, driven by require-

ments for fast capacity increases, wind power

backup, and Europe’s cap-and-trade program.

Today, combined-cycle gas turbines (CCGT) have

an installed capacity of 26.8 GW—more than

any other fuel source in Spain. This image shows

HC Energía’s Castejón CCGT Plant in Navarre.

The 2002-built Unit 1 has a capacity of 424.9

MW; the 418.5-MW Unit 3 started commercial

activity in January 2008. Should the supply of

natural gas be interrupted, Castejón 3 can also

use diesel. Courtesy: Iberdrola

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POWER POLICY

are operating coal-fired power plants in re-turn for their use of Spanish coal rather than imported coal, which is more affordable and of higher quality. Zapatero was looking to cushion conditions for tens of thousands of workers in coal mines, who have been pro-testing nonpayment, but as he told the com-mission, coal is also necessary to protect the country from power supply shocks caused by intermittent generation.

Spain’s government is also pouring public funding into several cleaner coal technologies. In October 2010, energy firm ELCOGAS started capturing carbon dioxide from a 14-MW pilot plant built at its 335-MW integrated gasification combined-cycle (IGCC) facility at Puertollano. The Puertollano IGCC plant some 200 km south of Madrid—which began commercial operation in 1996 with natural gas and in 1998 with syngas from gasifica-tion of an equal mixture of local coal (with an ash content of more than 40%) and high-sul-fur petcoke—is one of only five utility-scale IGCC facilities in the world.

Also under way is the much-watched Integrated Carbon Capture and Sequestra-tion Technology Development Plant under construction at Endesa’s Compostilla power plant in Ponferrada. The Spanish utility is col-laborating with research institution CIUDEN to set up a 30-MWth Foster Wheeler–built circulating fluidized bed unit and test Foster Wheeler’s Flexi-Burn carbon capture tech-nology. The unit, which will test burn a wide range of domestic (mostly anthracite) and imported coals—as well as biomass—is ex-pected to start operations by the second half of 2011. Testing programs are expected to follow thereafter.

Natural gas, on the other hand, has be-come the most significant component of Spain’s power profile. The amount of gas consumed for power generation depends on

the availability of wind and hydropower. In 2010, 68,828 GWh were generated by com-bined-cycle gas turbines (CCGT)—23% of total generation (Figure 4). CCGT installed capacity surged nearly 10% from 2009 to 2010. However, Spain imports more than 99% of its gas, mostly from Algeria, Nigeria, and Qatar.

Phasing Out NuclearSpain’s eight nuclear reactors—accounting for a total installed capacity of 7.7 GW—produce a fifth of the nation’s power. The sector got its start in June 1965, when construction began on the country’s first nuclear plant, the Jose Cabrera Zorita, a pressurized water reactor. In 1971, the 460-MW Santa Maria de Garoña, a boiling water reactor (BWR), began commer-cial operation, followed two years later by the 500-MW Vandellos-1, a gas-cooled reactor. All three plants were turnkey projects.

In the 1970s, construction began on seven reactors, but just five were completed. Con-struction of five other plants began in the 1980s, but only two were completed (Trillo-1 and Vandellos-2) after the socialist govern-ment imposed a moratorium on new nuclear in 1983, citing economic reasons. In 1994, after the Minister of Industry and Energy proposed a plan in which alternative energy would phase out nuclear—and vowed to shut down older plants when they reached the end of their 40-year lifetimes—five other units under construction were abandoned.

Spain is planning to add 810 MW of nu-clear capacity through uprates. The Iberdro-la-owned Confrenetes BWR that came online in 1985 has been uprated four times, taking it to 1,063 MW or 112% of its original ca-pacity. Plans to be implemented later this de-cade will increase the plant’s power to 120% of original capacity. In March—just a day before workers began their long struggle to cool the quake-stricken Fukushima Daiichi reactors in Japan—the Spanish government recommended a 10-year extension for the operating license of the Confrenetes plant. In February, Spain’s parliament removed a legal provision limiting nuclear plant lives to 40 years. It remains opposed to new construc-tion, however.

Since Fukushima, the government is re-viewing key renewal decisions, such as the highly controversial 2009 decision by the Nuclear Safety Council (CSN) to renew an operating license for the country’s oldest plant, the Santa Maria de Garoña. The gov-ernment had already shut down Vandellos-1, the gas-graphite reactor, in the mid-1990s, after a turbine fire made the plant uneco-nomic to repair, and Jose Cabrera in 2006, after it reached its 40-year limit. Although CSN said plant owner and operator Nucle-

nor had implemented a €155 million work program to keep the 40-year Santa Maria de Garoña serviceable, the current social-ist government—which campaigned on an anti-nuclear platform—forced the regulatory body to grant it only a four-year, rather than a 10-year, license, taking it to 2013.

Several reactors’ licenses have been ap-proved since then, including Almaraz 1 and 2, and the 1,045-MW Vandellos 2, the newest and largest plant of Spain’s fleet (Figure 5). In response to recent pressures to shut down Garoña, CNE’s Antonio Cornado told Agence France Presse that the question was “not if Fukushima is similar to Garona” but whether Japan had the same seismic or tsunami risks as Spain. “The answer is ‘no,’” he said.

Spain’s uranium resources are limited to Salamanca, where the metal was mined from 1974 to 2000, when activities trickled to a close due to low uranium prices. According to the World Nuclear Association, most of the 1,600 metric tons of uranium used in Spain each year are imported from Niger.

Currently, the country stores some 6,000 metric tons of spent fuel at reactor sites. Though it has no reprocessing plans, the government has called for construction of temporary dry storage facilities at the Trillo nuclear plant and at the now-closed Jose Cabrera plant, until a longer-term storage facility can be established. Two options are being considered for longer-term storage: the preferred, centralized nuclear spent fuel and high-level waste storage facility (whose site selection began in December 2009) and a deep geological facility. Nuclear waste management strategies, funded by a 1% tax on nuclear power revenues, also include re-search on extended onsite storage conditions and advanced recycling options.

Balancing Renewables on the GridSpain’s management of its transmission sys-tem has blazed a trail for countries looking for examples of how to balance a national grid that is fed by a large amount of renew-able generation. The variability of wind gen-eration in particular—which made up 15% of the nation’s power profile in 2010—keeps grid operator REE precariously balancing load. The challenge has recently become riskier: REE in 2004 warned that trying to in-tegrate more than 14% of wind power could significantly increase the possibilities of a major power cut.

One way REE says it manages large amounts of renewable power is through its Renewable Energies Control Centre (CECRE). Opened in 2007, that pioneering operational unit within the REE Power Con-trol Centre is used to supervise and control sources of intermittent generation. Every 12

5. No new nuclear. Spain has no plans

to build new nuclear plants. Since the Fukush-

ima Daiichi emergency, license renewals for

plants like Santa Maria de Garoña, the oldest

in Spain’s fleet, have been criticized. Spain’s

newest reactor is the 1,045-MW Vandellos 2

(shown here), built in 1988 near Tarragona in

northeastern Spain. Courtesy: Foro Nuclear


POWER POLICY

seconds, CECRE analyzes connectivity and wind speed from all wind farms rated at 10 MW or more and uses that data to calculate wind-powered generation levels. It also as-sesses the real-time risk of a sudden loss of or surge in wind power.

Still, every day brings new challenges. On Nov. 9, 2009, for example, Spain’s wind farms generated record power—315,258 MWh—enough to meet 43% of demand (at around 2 a.m.). Earlier, on June 26, at 10:32 a.m., wind farms barely covered 1%. Intense fluctuations are dealt with by using pumped storage plants as much as possible while switching off CCGT plants on a daily basis.

“Spanish legislation gives priority to re-newable energies when it is possible and secure,” María Pachón, REE spokesperson, told POWER in March. “Red Eléctricas’ role consists just of putting into practice [the In-dustry Ministry’s political] decisions under secure conditions.” Solutions being consid-ered in the near term include international interconnections, using surplus wind for pumped storage, and, in the long term, charg-ing electric vehicle batteries.

Meanwhile, Spain is pressing on with plans to build new transmission links. Cur-rently, the grid is divided into primary (at least 380 kV) and secondary (220 kV to 380 kV) transmission networks composed of over 35,797 kilometers of transmission lines and more than 3,000 substations. It also has, through the 2007-created integrated Iberian electricity market (MIBEL), interconnections with France, Portugal, Morocco, and Andor-ra, equal to some 5% of generating capacity. The Energy Infrastructure Investment Plan (2008–2016) calls for projects developing the 220-kV and 400-kV networks, including a high-voltage power link between the main-land and the Balearic Islands and reinforcing international links with France and Portugal (with whom Spain plans to exchange, at min-imum, 3,000 MW).

Key Challenges Remain Spain must monitor and resolve the key chal-lenges posed by the large, rapid development of renewables—striving, above all, to “bal-ance objectives of environment, competitive-ness, security of supply and efficiency in its policy formulation,” says the IEA in a 2009 country analysis.

It should also end a mechanism that uses capacity payments as a substitute for market-based incentives to build new generation ca-pacity because it tends to lead to inefficient investment decisions, the agency says. These payments provide participants with the “per-verse incentive of withholding their plans for new capacity in order to receive the payment,” and are “complex” to administer. Another

critical needed improvement is to increase re-tail prices and resolve government-incurred tariff deficits of up to €16 billion.

The country’s emphasis on the long-term integration of renewable power is commend-able, the IEA said, but it is crucial that the na-tion establish clearer policies regarding other sources, such as nuclear. It also must ensure a streamlined and transparent siting and per-mitting process that includes interconnection to the grid for renewable developers.

Another concern is that the nation has not

adequately assessed the need to build and operate backup capacity to compensate for the unavailability of intermittent renewable sources. CCGTs were and will continue to be the best option for peak-load supply and backup capacity, but they increase greenhouse gas emissions and raise security-of-supply is-sues owing to the volatility of international gas markets.

“Uncertain policies are bound to affect the investment climate,” the IEA concluded. ■

—Sonal Patel is POWER’s senior writer.




K-Power Upgrades Combined-Cycle Automatic Generation ControlsTightly managed grids require combined-cycle plants equipped with power

block controls that can quickly respond to automatic generation control signals with minimal error. K-Power’s successful controls upgrade dem-onstrates that that goal—and more—is achievable.

By Sang-joon Park, GE Energy and Gaurav Gupta, LeeMary Ma, and Uttam Narasimhan, GE Measurement & Control Solutions

K-Power Combined Cycle Plant, located

in KwangYang National Industrial

Complex, is South Korea’s first private

merchant power plant (Figure 1). The plant,

which entered commercial operation in May

2006, is configured with two power blocks,

each one consisting of a 2 x 1 combined-cycle

plant. Each 525-MW net power block relies

on two General Electric (GE) 7FA combus-

tion turbines (CTs) equipped with dry low-NOx

combustion systems, one Nooter three-pressure

heat-recovery steam generator per combustion

turbine, and a single Hitachi steam turbine.

K-Power (also the name of the plant own-

er) is a 65:35 joint venture between SK Corp.

(a leading Korean energy company) and UK-

based BP. The plant is fired with liquefied

natural gas imported from the Tangguh field

in Indonesia.

K-Power sells electricity to KEPCO, with

the Korea Power Exchange (KPX) handling

the transactions. To do so, the plant is con-

figured with automatic generation controls

(AGCs) that dispatch the plant by power

block. K-Power provides KPX with a 24-hour

maximum gross generation capacity one day

ahead and, in turn, receives a 24-hour dispatch

schedule from KPX. The plant receives two

dispatch signals (one for each power block)

that are frequently updated. The existing plant

controls made dispatching to a continuously

changing plan very difficult and inefficient.

This less-than-optimal process pressed K-

Power to consider a controls update.

K-Power’s primary requirement was for

an advanced process control (APC) solution

that would improve the efficiency of the AGC

by minimizing variation from the KPX-pro-

vided setpoints. Another goal was to thermo-

dynamically optimize the operation of each

power block, within operational constraints,

to provide electricity efficiently. Together,

these upgrades would ensure that electricity

was produced under the prescribed operating

conditions as efficiently as possible.

After considering a number of options,

K-Power asked GE to supply its “MVC” so-

lution, a model predictive multivariable con-

troller. MVC uses predictive control models

derived from plant dynamics and plant

simulation results. Nonlinear mathematical

models are used to calculate the optimal con-

trolled variables and issue the corresponding

manipulated variable setpoints on each ex-

ecution cycle. Automatic bias maintains the

predictive integrity of control models under

varying plant conditions.

How AGC WorksWhen the plant is operating, the AGC re-

ceives two dispatch signals, one per power

block, every 10 to 15 minutes. The signals

received are the new setpoints for total gross

power required per power block. For plan-

ning purposes, K-Power sends to KPX a day-

ahead, 24-hour maximum gross generation

capacity based on current equipment perfor-

mance and anticipated ambient conditions.

The dispatch signals sent from KPX to the

plant will be within the maximum gross gen-

eration estimated, given the expected operat-

ing constraints.

The original CT control strategy was quite

ordinary. CTs were loaded using the “prese-

lect” mode once the power block reached an

acceptable stable condition after the genera-

tors were synchronized with the grid. Once

the CTs reach their preselect conditions, the

load control setpoint can be raised, lowered,

or set to baseload, and the CTs will respond

in tandem. If controls are set to baseload, the

CTs ramp up to that condition based on the

control settings within the Mark VI (GE’s CT

control package). The design CT ramp rate

is 5 MW per minute (manual) and 3 MW per

1. First independent power producer in South Korea. K-Power, a 1,050-MW

combined-cycle power plant, was the first merchant power generation facility constructed in

South Korea. The plant consists of two power blocks, each based on a 2 x 1 configuration. The

plant entered commercial service in May 2006. Courtesy: K-Power

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minute (automatic), according to the Mark

VI system specifications.

When the load on each CT is increased such

that the measured exhaust temperature reaches

the prescribed baseload temperature control

limit, the CT output is then said to be operat-

ing at baseload conditions. Once at baseload,

the CTs operate on the baseload inlet guide

vane/temperature control curve. Under certain

ambient and operating conditions, the CT may

be limited by this control curve even though

expected baseload output is reached—a not-

unusual scenario under high ambient tempera-

tures. The power demand signal is directed to

the Mark VI CT digital controls from the plant

distributed control system (DCS) to produce

the required electricity.

The updated CT control strategy is a re-

markable improvement. The MVC controller

sends supervisory megawatt (MW) setpoints

to the DCS for the operating CTs. In turn,

the DCS sends a setpoint signal directly to

the Mark VI CT controller, just as before.

Modified control logic in the DCS allows the

operator to select “computer Mode” for the

individual CTs, which enables MVC control.

computer mode is an added operating mode

now programmed in the DCS in addition to

the “baseload” and “preselect” modes dis-

cussed above.

MVC takes control of the CT MW setpoint

when the operator selects computer mode

and the Mark VI remote control is enabled.

The MVC is only used when the CTs are op-

erating and is secured before CT shutdown.

During start-up, the MVC has high and

low MW and maximum MW ramp rate limits

defined for individual CTs. A feedback signal

from the Mark VI indicates when baseload

conditions have been reached. That signal is

used in the MVC controller to set the high

limit of the controller. The MVC high limit

is set as the current output of the CT plus

three times the maximum ramp rate (that is,

9 MW) until the feedback signal indicates

that baseload (or maximum output based on

operating conditions) has been reached.

When baseload has been reached, the high

limit is set at current output plus 0.5 MW.

This 0.5-MW margin allows for the normal

oscillation of the CT output and for maintain-

ing the turbine at stable baseload condition.

In this way, the MVC optimally controls the

online CT MW setpoints to meet the K-Pow-

er dispatch commitment. Table 1 summarizes

many of the other plant design constraints

in the MVC that will limit the power block

ramp rates.

MVC System ArchitectureFigure 2 depicts the communication interface

between the K-Power DCS and the GE Bently

Nevada EfficiencyMap/CLOC (closed-loop

optimal control) computers. EfficiencyMap

is plant optimization and performance moni-

toring software designed to measure, predict,

and track plant performance. CLOC is a su-

pervisory control and optimization system

for complex, dynamic processes.

The MVC software and plant historian

are installed on one computer; Efficien-

cyMap is installed on a second computer.

The plant historian, hosted on the CLOC

computer, communicates with the plant’s

Honeywell DCS OPC server via the his-

torian-OPC interface. The CLOC system

does not communicate directly with the

turbine controllers. All communications

pass through the DCS OPC server, and the

necessary information (such as operating

parameters and setpoints) is communicated

to and from the CT controllers to the DCS

via OPC protocol. To facilitate receiving

incoming data, the Honeywell DCS has ad-

ditional logic programmed to ensure that the

incoming data is permitted and will not ad-

versely affect the control system.

Scheduling and PlanningThe system also includes an off-line GateCy-

cle “what-if” tool. This tool, in the form of an

Excel spreadsheet, is used by plant person-

nel for what-if parametric studies. It imple-

Table 1. Plant ramp rate constraints. The speed at which a power block’s output can

be increased or decreased is limited by equip-

ment design. For example, a minimum value

of steam flow to the block 1 steam turbine

must be available before the desired combus-

tion turbine MW ramp rate can be achieved.

Source: GE Power

Operating constraint Type

ST 1 inlet flow Min

ST 2 inlet flow Min

HP steam flow 1 Min

HP steam flow 2 Min

HP steam flow 3 Min

HP steam flow 4 Min

Condenser pressure 1 Max

Condenser pressure 2 Max

ST 1 HP header pressure Min/Max

ST 2 HP header pressure Min/Max

Train 1 NOx Max

Train 2 NOx Max

Train 3 NOx Max

Train 4 NOx Max

Train 1 CO Max

Train 2 CO Max

Train 3 CO Max

Train 4 CO Max

CT1 TREF Min

CT2 TREF Min

CT3 TREF Min

CT4 TREF Min

CT1 exhaust pressure Max




Notes: ST = steam turbine, CT = combustion turbine, HP

= high pressure, TREF = CT reference firing temperature.

2. MVC data communications at K-Power. Source: GE Power

System 1

i-Historian

Honeywell DCS

OPC serverCLOC EfficiencyMap

Mark VI

CT#1

Mark VI

CT#2

Mark VI

ST#1

Mark VI

CT#3

Mark VI

CT#4

Mark VI

ST#2

EGD

OPC data (vibration) to i-Historian using DCOM

OPC data (HRSG, BOP) from Honeywell OPC server to i-Historian using DCOM

OPC data (HRSG, BOP) from Honeywell OPC server to CLOC

Modbus TCP/IP

Calculated data to Honeywell OPC server. CLOC is client and can write data to OPC server

Kepware Modbus to OPC server to collect Mark VI data from i-Historian Cimplicity HMI

Calculated data from/to CLOC



ments full-plant equipment models and can

be “tuned” to the latest plant conditions.

The tool allows the user to accurately fore-

cast maximum power that can be generated

from the two power blocks under a variety of

operating conditions. To forecast the maxi-

mum power generation possible, the user

must input the following parameters:

■ CT inlet pressure drop

■ CT exhaust pressure drop

■ Ambient temperature

■ Ambient pressure

■ Relative humidity

■ Cooling water inlet temperature

■ Current level of CT degradation

The CT inlet pressure drop, exhaust pres-

sure drop, and current CT degradation can

be obtained from the online EfficiencyMap

system. The user can also estimate the maxi-

mum power generated by each block under

“new and clean” conditions.

K-Power generates the forecast for the

next 24 hours using these tools and then

sends the forecast to KPX based on the low-

est, highest, and average expected ambient

temperatures. After receiving the load profile

from K-Power, KPX sends the load profile

for the next day back to K-Power by 18:00

hours. The load profile is then converted to

a continuous AGC signal, which MVC uses

to control plant output by manipulating the

power setpoint of the individual CTs.

Commissioning New ControlsA long-term commissioning plan was estab-

lished at the project kickoff. A complete team

charter was also developed to define the roles

and responsibilities of the GE engineers and

K-Power staff. The MVC commissioning

plan had five stages:

1. Instrument input/output checkout

2. DCS level configuration checkout

3. Plant step testing and APC controller

tuning

4. Model building and implementation

5. Site acceptance test

The start-up team included GE commis-

sioning engineers working on DCS-level

configuration checks to ensure that the plant

was well protected during all anticipated op-

erating scenarios and that switching between

different control modes (such as APC con-

trol, automatic, and manual functions) was

bumpless. Additional configuration changes

were made to ensure that the regulatory con-

trollers defaulted to safe mode in the event of

failure of the supervisory computer.

Before plant step tests, all DCS level con-

trol loops were checked to make certain all

the basic regulatory controllers were prop-

erly tuned. These were not just APC-related

loops but also other loops that improved unit

stability and ensured smooth plant operation.

The GE engineer developed the DCS logic

changes, and the K-Power DCS engineer ap-

proved the logic changes and implemented

the logic changes on site during scheduled

outages. GE and plant engineers tested the

logic changes thoroughly before the power

blocks were returned to operation.

Full involvement of plant staff, especially

the operations staff, is critical for the success

of any APC implementation. During the step

testing phase of MVC commissioning, for

example, plant operators were fully involved.

Continuous and frequent interaction between

the GE engineering team and operating per-

sonnel allowed the GE engineering team

to learn about the intricacies of plant op-

erations. In turn, the plant operators learned

more about multivariable control.

Operator TrainingThe plant operators are the primary users of

the APC system, and proper operator training

is a critical component of a successful APC

project. Formal operator training consists of

a systematic and comprehensive training pro-

gram, which is normally held after commis-

sioning and prior to the site acceptance test.

At K-Power, operators were trained on APC

fundamentals as well as hands-on usage of

the APC system during project implementa-

tion and post-commissioning.

The APC training material covered ba-

sic process control concepts, DCS-based

advanced control concepts, multivariable

control concepts, and the MVC system. Hu-

man machine interface and K-Power-specific

control strategies and operational procedures

were also discussed.

During the hands-on APC system train-

ing, the GE engineer explained the control

strategies specific to this project and how

the multivariable controllers move manipu-

lated variables to satisfy setpoint variables

and constraint variables under different sce-

narios. Operators were trained how to acti-

vate and deactivate MVC, how to perform

minor troubleshooting, and how to handle

system start-up and shutdown. An operator’s

manual was provided at the end of the train-

ing. An ongoing supporting services agree-

ment ensures that the benefits derived from

the MVC, EfficiencyMap, and what-if tools

continue into the future.

Post-APC PerformanceThe MVC was successfully commissioned at

K-Power in October 2007. Thanks to a user-

friendly operating interface, a single-window

philosophy of operation, and proper train-

ing, operators have readily accepted the APC

system. This system has achieved measure-

Table 2. Power block test results. An assessment of the MVC performance was conducted about two years after the system was

commissioned. The performance improvement of the plant on AGC control was remarkable. Source: GE Power

Dispatch ramp

(MW)

MVC

status

Average AGC

demand (MW)

Average actual

production (MW)

Standard

deviation (MW)

Improvement

in standard

deviation (%)

Difference between AGC

demand and AGC average

actual (MW)

Improvement in

AGC control (%)

Power Block 1

500–525 Off 518.4 533.2 7.2 35 –14.8 29

On 512.4 522.9 4.7 –10.5

252–550 Off 530.5 537.9 7.2 31 –7.4 27

On 532.8 527.4 5.0 5.4

Power Block 2

500–525 Off 511.5 527.5 7.8 36 –16 49

On 545.3 523.5 5.0 –8.2

252–550 Off 520.8 531.8 10.9 53 –11 59

On 531.8 527.3 5.1 4.5

Note: AGC = automatic generation controls.



able benefits for K-Power, such as improved

closed-loop AGC control, stable plant oper-

ation, and increased operator understanding

of process interactions.

A study was conducted in February 2010

to assess the long-term benefits of the MVC.

In sum, the APC has provided increased sta-

bility in plant operations, and the variation

of important plant operating variables has

been reduced by a minimum of 30%. These

results are seen in the test data, showing the

standard deviation calculated between the

MVC On and Off conditions, for each power

block (Table 2).

The MVC has also reduced the variations in

overall power generation. With MVC control,

overall power generation is controlled closer

to plant targets than without MVC control. A

minimum 27% improvement was observed.

Figures 3 and 4 illustrate the improvement in

AGC control between MVC Off and On for

each power block. The test data clearly shows

that when MVC is On, the average actual MW

is closer to the average AGC MW.

A less-quantifiable, but nevertheless im-

portant, benefit of the APC is improved op-

erator perception of process interactions and

understanding of optimum operating condi-

tions. Process interactions are more clearly

visible to operators as the controller simulta-

neously manipulates variables to maintain a

controlled variable at its target value. A plant

staff that understands how the MVC works

is much more valuable than one that knows

only which to buttons to push. ■

—Sang-joon Park is the GE Energy O&M operation manager for K-Power. Gaurav

Gupta ([email protected]) is service manager, LeeMary Ma (leemary.ma@

ge.com) is lead technical specialist, and Uttam Narasimhan (uttam.narasimhan@

ge.com) is lead application engineer for the Performance & Optimization group in GE

Measurement & Control Solutions.

570

550

530

510

490

470

450

MW

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81

Data points

MVC off MVC on

AGC power setpoint Actual power Average setpoint Actual average power

3. Power block 1 MVC performance test results. Source: GE Power

570

550

530

510

490

470

450

MW

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61

Data points

MVC off MVC on

AGC power setpoint Actual power Average setpoint Actual average power

64 67 70 73 76 79 82

4. Power block 2 MVC performance test results. Source: GE Power

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The Urge to MergeUtility mergers and acquisitions are on the upswing again. When faced with

flat load growth, pervasive regulatory uncertainty, and the rising cost of doing business, larger companies are better able to afford expensive new plants while maintaining shareholder dividends.

By Kennedy Maize

No one ever accused Jim Rogers of thinking small. Over his years in the energy business, the Duke Energy

CEO has frequently looked around his neigh-borhood and seen places he wanted to go—and companies he wanted to acquire.

During his 23 years as a CEO in the electric-ity business, Rogers has used mergers to grow his companies, his clout, and his reputation, both in industry and in the world of public policy and politics. When Rogers became PSI Energy (Public Service of Indiana) CEO in 1988, his gaze soon fixed on Cincinnati Gas and Electric. It was a troubled utility that nearly foundered on an ill-fated venture into nuclear power. The resulting marriage created a company called Cinergy. Rogers led the merged company for 11 years. In 2006 he orchestrated a deal in which powerhouse Duke acquired little Cinergy; after a suitable cooling-off period, Rogers ended up in the catbird seat.

Rogers’ latest move is to use the muscle of his Charlotte, N.C., utility to acquire his Raleigh-based neighbor, Progress Energy, producing what would be the largest investor-owned utility (IOU) in the nation. In the deal announced in January, Duke will buy Prog-ress for $13.7 billion in stock (at a modest 7% premium for Progress shareholders) and assume $12.2 billion in Progress debt, creat-ing a behemoth with a market capitalization (the total value of the combined companies’ outstanding shares) of $37 billion.

The new company, to be headquartered in Charlotte, will own assets worth over $90 bil-lion, serve some 7.1 million customers in six states (North Carolina, South Carolina, Flor-ida, Ohio, Indiana, and Kentucky), and have 57 GW of generating capacity, including what the companies claim will be the largest regulated fleet of nuclear plants in the U.S. (Figure 1). Duke currently has seven nuclear units at three sites with a total nameplate ca-pacity of 6,816 MW. Progress has five nucle-ar units at four sites, totaling 4,345 MW.

An Unlikely MarriageThe Duke-Progress merger caught many by surprise, in part because of the personalities involved. Often, mergers result when a young,

aggressive executive takes over from an older, less-assertive leader looking for an easy path to the first tee. In the case of Duke and Prog-ress, two very strong personalities—Rogers and Progress Chairman, President, and CEO Bill Johnson—are involved. Both can suck the oxygen out of a room just by entering. Johnson is well over six feet tall and fit. He is a former big-time college football player (he matriculated at Penn State under legend-ary football coach Joe Paterno but transferred to Duke University). Both he and Rogers are lawyers. Unlike the peripatetic and flashy Rogers, Johnson has spent his entire career as an electric utility executive at Progress.

According to the merger announcement, Rogers will become a company éminence grise, thinking big thoughts and working on the national and international stage. That’s a role that fits his personality. Rogers led the electricity industry’s failed endeavor to get Congress to enact a cap-and-trade program to control carbon dioxide emis-sions. He also has been a leading advocate of utility energy efficiency programs and renewable generation. A rare Democrat swimming in the sea of Republicans in-habiting industry executive suites, Rog-ers was successful in persuading his party to schedule its 2012 national convention, where President Obama will be renomi-nated, in Charlotte.

Johnson will become the day-to-day chess master, moving the pieces around the util-ity’s broad territory. He has a reputation as a conventional but very effective manager. But the Zen master vs. chess master distinc-tion may not hold, according to one veteran industry observer, who told POWER, “The border is pretty blurry. It’s hard to tell where public policy and company direction begin and end.”

A utility lobbyist told the environmental news service Greenwire, “Bill Johnson is a deep strategic thinker who is much less likely than Rogers to throw around flavor-of-the-month ideas in an effort to appease some regulators and legislators.”

What drives the Duke-Progress merger? Nuclear power plays an important role, ac-

cording to several analysts. Barclays Capital investment banker James K. Asselstine, a for-mer member of the Nuclear Regulatory Com-mission (NRC), made that point recently at a Platts nuclear conference in Maryland. He noted that at $10 billion a pop, new nuclear plants can sink a company.

NRG Energy, for example, was, until re-cently, heavily involved in the South Texas Project (STP) nuclear expansion, to the tune of more than $5 billion for its share. The com-pany has a market capitalization of $5 billion, so failure in Texas could mean goodnight for NRG. On April 19, NRG announced it was writing down its investment in the develop-ment of STP Units 3 and 4, at least partially in response to the nuclear disaster in Japan.

A combined market cap of $37 billion for the new Duke-Progress utility would make investments in new nuclear more palatable, Asselstine concluded. Barclays Capital is advising Progress in the merger.

1. Mega-merger pending. Approval

of the Duke Energy–Progress Energy merger

will form a utility with over $90 billion in assets

and annual revenues exceeding $22 billion. The

generating capacity of the new Duke Energy

Corp. will exceed 57,200 MW, and its service

territory will cover more than 100,000 square

miles. Source: Duke Energy, Progress Energy

Duke Energy

Progress Energy




In an interview, Peter Fox-Penner of The

Brattle Group agreed there was a nuclear

aspect to the deal. “There is no question, a

bigger balance sheet is better” for compa-

nies that see a future in new nukes, he said.

“That’s clearly a major part of it.”

A well-run utility in two states with con-

ventional cost-of-service state regulation,

Progress was clearly an attractive target

for a takeover. John Rowe, the aggressive

CEO of Chicago-based Exelon Corp., ac-

knowledged after the Duke announcement

that he had considered a play for Prog-

ress. But Rowe said his number crunchers

couldn’t make the deal work out.

Rowe’s Exelon lost a major merger move

five years ago when its plan to take over New

Jersey’s PSEG Corp. faltered because the New

Jersey Board of Public Utilities nixed the deal.

That merger would have created the largest U.S.

IOU. Rowe made it clear he was still looking

to grow through acquisitions, and on Apr. 28,

Exelon announed a $7.9 billion deal to acquire

Constellation Energy. If the deal is approved by

regulators, it will make Exelon the country’s

largest operator of nuclear plants.

FirstEnergy Deal ClosesAs Duke and Progress were unveiling their

merger—the start of at least a year-long

journey—Cleveland-based FirstEnergy and

Allegheny Energy, headquartered outside

Pittsburgh, were wrapping up their $8.5 bil-

lion combo. Announced in February 2010,

the FirstEnergy-Allegheny deal got the final

seal of approval from the Pennsylvania Pub-

lic Utilities Commission almost exactly a

year later, on Feb. 25, 2011. The new, beefier

FirstEnergy will have some $16 billion in an-

nual revenues and six million customers in

Pennsylvania, Ohio, Maryland, New Jersey,

New York, Virginia, and West Virginia.

FirstEnergy was the result of merger ma-

nia that escalated in the 1980s and peaked in

the 1990s. That episode was largely driven by

structural changes in the electricity business

that resulted in the creation of competitive

wholesale and retail markets serving about

half of the states, plus the unique need to deal

with troubled, high-cost nuclear plants. Ak-

ron, Ohio–based FirstEnergy was born of the

1986 merger of Cleveland Electric Illuminat-

ing and Toledo Edison, two troubled neigh-

bors who joined to create Centerior Energy

Corp. Toledo owned the Davis-Besse nuclear

plant, which has had a checkered history (Fig-

ure 2). Centerior became FirstEnergy in 1997

by merging with Ohio Edison. FirstEnergy

acquired GPU Corp. in 2001, which owned

Three Mile Island (TMI) Unit 2, which was

shut down in 1979 and never reopened. Ex-

elon Nuclear owns and operates TMI Unit 1.

Merchant MergersMergers on the merchant side of the business

are also picking up speed. The most recent

example is the newly minted GenOn Ener-

gy Inc., a mixture of Mirant Corp. and RRI

Energy Inc. When that deal closed in early

December 2010, the combined 23,600-MW

merchant operator instantly became one of

the largest independent power producers in

the U.S. Edward R. Muller, chairman and

CEO of GenOn, said the merger “will create

significant near-term stockholder value driv-

en by $150 million of annual cost savings.”

Is This a Trend?Are the Duke-Progress, FirstEnergy-Allegh-

eny, and Exelon–Constellation Energy deals

evidence of a revitalized trend of electric com-

pany mergers? Opinions are mixed. Accord-

ing to Thomson Reuters Deals Intelligence,

“Merger activity in the energy and power sec-

tor is off to its fastest ever start in a year, with

nearly $94 billion in deals so far in 2011,” up

40% over last year. That assessment came in

February, after the Duke announcement and

just as the FirstEnergy deal was closing. The

figures include foreign merger and acquisi-

tion (M&A) activity, such as BP’s $7 billion

hookup with India’s Reliance Industries. Ac-

cording to Thomson Reuters, “Cross-border

energy & power deals have accounted for

$58.1 billion of the activity this year, or 63

percent of worldwide mergers in the sector.

U.S. targeted deals have accounted for rough-

ly half of the volume.”

Berenson & Co. electric analyst Ed Tirello

is bullish about electric company mergers. But

then, he would be. Tirello is famous for his

1987 “50 in five” prediction: He predicted that

only 50 investor-owned electric utilities would

be around in 1992. He missed. According to

the Energy Information Administration, in

2000 there were 240 IOUs in the U.S.

Tirello chuckles at his missed prognos-

tication. “It’s taken a bit longer,” he says

with good humor, “but the premise doesn’t

go away. Look at the industry as a whole. It

doesn’t matter what the generating fleet looks

like today, it is all going to have to be turned

over in this country in the next 20 years.

Years ago, we did five, 10, 20-year advanced

plans. Deregulation messed that up and we

stopped doing it. And we are back to doing

that planning again.

“[The Environmental Protection Agency]

is putting pressure on generation. Plants are

getting old. Rules change and fuels change,

and you must get the money somewhere to

keep the lights on.” So, in Tirello’s mind,

the way to find the resources is to bulk up.

“When you look at mergers so far,” says Tire-

llo, “each one had a particular reason. But the

overall theme is still there: fewer and larger.

2. Buy rather than build. FirstEnergy Nuclear Operating Co., a subsidiary of FirstEnergy

Corp., owns the single-unit 879-MW Davis-Besse Nuclear Power Station. The plant was origi-

nally owned by Centerior Energy Corp.—created by the merger of Cleveland Electric Illuminat-

ing and Toledo Edison—and was acquired by FirstEnergy in 1997. In August 2010, FirstEnergy

submitted a license renewal application for Davis-Besse (which is licensed to operate through

2017) to the NRC, a process that is sure to be extremely contentious given the plant’s uneven

operating history. Source: NRC



You need stronger balance sheets to change

the fleet over.”

The Brattle Group’s Fox-Penner isn’t buy-

ing all of Tirello’s analysis. “The industry

is always considering mergers and acquisi-

tions,” he said. “Nothing jumps out at me

as a major driving force today. There are

always a lot of factors hitting the industry

at any one time, things such as the cost of

debt and equity, strategic factors, regulation.

Maybe there are times when they all align, as

Ed Tirello thought they did in the 1980s, but

I don’t see any kind of alignment of factors

at this time.”

Fox-Penner points to the deal last year

when PPL Corp. agreed to buy E.ON.US for

$7.6 billion (cash and debt) as an example of

how particulars drive business marriages. In

that case, PPL, based in Allentown, Pa., had

become essentially an unregulated merchant

generator. The U.S. arm of the German multi-

national E.ON was the owner of conventional,

state-regulated, cost-of-service utilities: Lou-

isville Gas & Electric and Kentucky Utilities.

The particular structural elements “led to that

particular deal” and not some larger force at

work in the industry.

Following the same playbook as Tirello,

Todd Shipman of Standard & Poor’s said the

rating agency expects to see “25 in 5” or 25

utility mergers in the next five years. Given the

Duke-Progress, Northeast Utilities–NStar, and

FirstEnergy-Allegheny hookups over the past

year, that prediction seems a safe bet.

Shipman pointed to several factors that are

likely to bring utilities together over the next

few years:

■ Low electricity sales growth putting pres-

sure on dividend growth.

■ Rising costs of environmental retrofits in

response to regulatory and legislative re-

quirements.

■ The perpetual regulatory uncertainty that

hangs over the industry.

■ Direct investment by deep-pocketed for-

eign countries or companies (often there

is little difference between the two) in

either equities or as a market for technol-

ogy sales.

A carefully designed complementary merg-

er can reduce corporate risks and, therefore,

costs, providing desirable upward pressure on

company earnings over the long term.

Veteran Washington energy lawyer Clint

Vince is agnostic when it comes to merger

trends. “There is a certain logic” to electric

generating company mergers, he said in an

interview. “The businesses have spread out

beyond state borders, it’s an increasingly

competitive business, and major capital

costs, particularly for nuclear, are increas-

ing, so it makes sense to spread out over a

larger customer base for some companies.”

On the other hand, Vince said, “It’s hard to

know if we are actually seeing a trend. It

will take some more time to reach any con-

clusion on that question.”

Add the market research firm of Wood

Mackenzie to those who see a merger

trend in progress. In a recent report, Wood

Mackenzie says it expects M&A activity

in the power business to “intensify in 2011

as North American power markets remain

oversupplied with power generating capac-

ity and face sluggish demand growth pros-

pects and environmental policy pressures.”

Hind Farag, North American research

manager for the firm, notes that during

the past two years, some 13% of installed

North American power plant capacity

has been involved in M&A deals. “Since

January 2009,” she said, “completed and

announced M&A activity has involved at

least 148 gigawatts of existing generators

in North America while only about 70 GW

of new resources achieved commercial op-

eration during the same time period.”

Generalizations are dangerous when

discussing “energy” mergers, because that

rubric encompasses so much: Integrated

oil companies, wildcatters, new shale gas

developers, merchant electric generators,

regulated electric companies, and local

gas distribution companies all fall under

the heading. Tracking trends across such a

diverse landscape becomes daunting. One

indicator, and it is far from conclusive,

is the pace of mergers coming before the

Federal Energy Regulatory Commission

(FERC). FERC must review all mergers

that involve electric utility assets used in

interstate commerce. According to FERC

data, the late 1990s represented the peak

of the agency’s merger activity. FERC

dealt with 17 merger applications in 1997,

15 in 1999, and 16 in 2000. In contrast, it

saw four merger applications in 2005, 10

in 2006, five in 2007, three in 2008 and

2009, and two last year.

Though it’s difficult to find a clear-cut

merger trend, one new element feeds the urge

to merge. Since 2005 it has become easier—

although still time-consuming and costly—to

pull off a major merger. For 70 years, starting

with the 1935 Public Utility Holding Com-

pany Act (PUHCA), federal policy looked

askance at electric utility mergers, although

the vigilance waned considerably in the final

two decades of that period. The 1935 law was

the result of the collapse of Samuel Insull’s

pyramid of utility holding companies in the

Great Depression, a disaster that dwarfed this

century’s Fall of the House of Enron.

Congress in the 2005 Energy Policy Act

essentially repealed PUHCA requirements

for vigorous FERC merger oversight.

Since then, the states have largely super-

vised mergers of firms under their juris-

diction. New Jersey, not FERC, killed the

Exelon-PSEG affair.

Only a few states have taken their merg-

er authority to heart. Scott Hempling, head

of the National Regulatory Research Insti-

tute, the policy think tank for the National

Association of Regulatory Utility Com-

missioners, said he has been trying to “en-

courage states to develop a merger policy”

but has had limited success.

Hempling argues that states should look

hard at mergers based on whether they fur-

ther the broad interests of consumers in the

state, not simply based on whether they are

benign or on what state regulators can ex-

tort from the parties in merger conditions.

“There has not really been an understand-

ing of the key effects a merger can have”

on a state, Hempling says, citing potential

issues such as the impact on ancillary ser-

vices, renewable generation, and transmis-

sion needs. “Are we producing corporate

structures so diverse and complex and fi-

nancing too difficult for normally staffed

regulators to keep track of,” he asks? His

implication is that the answer is yes. ■

—Kennedy Maize is a POWER contribut-ing editor and executive editor of

MANAGING POWER.

During the past two years, some 13% of

installed North American power plant

capacity has been involved in M&A deals.



Fully Automating HRSG Feedwater PumpsModern distributed control system platforms can provide many tools to cap-

ture best operating practices and automate them. This case study shows the steps taken to automate a hypothetical simplified feedwater pump system for a combined-cycle power plant. It describes a combination of controls automation strategies and human-machine interface techniques designed to increase the overall level of automation while improving ease of use.

By Steven Leibbrandt and Bill Thackston, Siemens Energy Inc.

Modern distributed control system

(DCS) platforms offer capabili-

ties that were unavailable just a

few years ago. Features such as integrated

graphical engineering environments, sim-

plified sequencing controls, and improved

human-machine interfaces (HMI) make

higher levels of automation more practical

from the standpoints of implementation,

maintenance, and ease of use. The timing of

these advances couldn’t be better—critical

operating personnel throughout the power

industry are approaching retirement age,

and there are insufficient numbers of skilled

younger personnel to replace them. Lever-

aging the existing plant knowledge base to

design automation that reduces the burden

on plant operators will be essential to meet-

ing tomorrow’s plant demands.

As an example, the following case study

describes automating a simplified feedwater

system for a combined-cycle power plant.

The existing legacy DCS controls are proven

and reliable; however, the sequence of op-

erations and coordination of regulatory con-

trols is not automated, therefore, it requires

a high degree of knowledge and attention

on the part of the operator. This case study

describes a combination of controls automa-

tion strategies and HMI techniques designed

to increase the overall level of automation

while improving ease of use by operators

and maintenance personnel. (Note: DCS ex-

amples were developed using the Siemens

SPPA-T3000 DCS platform. A detailed de-

scription of this control system was included

in “Upgraded Control System Adds to Mer-

chant Plant’s Bottom Line,” January 2009,

available at www.powermag.com.)

The “as-found” DCS graphics and controls

strategy for this case study form the basis for

comparison with newer strategies, so a brief

discussion of the existing automation base-

line is in order. The reference information

used in this case study was provided by the

Electrical Power Research Institute (EPRI)

but also incorporates information taken from

one or more operating plants.

The Hypothetical Plant’s LayoutThe hypothetical plant consists of two com-

bined-cycle combustion turbines, each with a

heat-recovery steam generator (HRSG). Both

HRSG units are coupled to a single steam tur-

bine with feedwater supplied from a common

condenser and the hotwell, the receptacle for

the hot water drawn from the condenser by

the air pump.

Looking at a single HRSG, the feedwa-

ter train consists of a pair of 100% capacity

feedwater pumps and a set of three drums

for low-pressure (LP), intermediate-pressure

(IP), and high-pressure (HP) steam headers.

The feedwater pumps transfer feedwater from

the LP drum to the IP and HP drums. Mini-

mum flow through the pump is maintained

by a recirculation line back to the LP drum

with a modulating valve and a variable-flow

setpoint calculated from the pump manufac-

turer’s operating curves. Both pumps share

supply lines and valves to the IP and HP

drums. Each pump is equipped with a vari-

able frequency drive (VFD) for speed control

and has a dedicated lube oil pump.

Existing Drum Level ControlFeedwater control to IP and HP drums consists

of both single- and three-element drum level

control. Single-element controls modulate the

supply valve to each drum based on the level.

Three-element control uses steam flow from

the drum as a feedforward signal to a feedwa-

ter flow controller whose setpoint is modulated

to maintain desired drum level. Pump speed is

modulated to adjust IP and HP flows in coordi-

nation with the feedwater valves as follows:

■ Control of VFD and feedwater valves ap-

plies regardless of single- or three-element

level control.

■ The VFD runs at minimum speed, modu-

lating the IP valve to maintain IP drum

level and the HP start-up valve to maintain

HP drum level until the HP start-up valve

is fully open.

■ Once the HP start-up valve is fully open,

the VFD will modulate to keep the IP

valve within its control range (<85%).

■ If the IP valve is <85% open, modulate the IP

valve to maintain IP drum level and modu-

late the VFD to maintain HP drum level.

■ If the IP valve is >85% open and the HP

start-up valve is fully open, increase the

VFD speed until the IP valve output is

<85%. Modulate the HP main feedwater

valve to maintain the HP drum level.

Existing Baseline HMIThe existing operator interface for each

feedwater train consists of three full-screen

graphics. The first is a partial schematic of

the feedwater system, showing pumps and

discharge lines, but not the drums. The sec-

ond graphic is a collection of control face-

plates for use in setting up discrete devices

and regulatory controls. The last display is a

tabular collection of relevant plant operating

data, including feedwater pumps and drum

conditions. Each feedwater pump has numer-

ous process interlocks that are not immedi-

ately accessible from the HMI.

Case Study Assumptions The assumptions for this case study are as

follows:

■ Only normal operation is considered (no

power augmentation).

■ Pump failure will start the standby device

without cycling common discharge valves.

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■ Shutdown will stop all pumps and close all

valves in the feedwater system.

■ VFD and feedwater valve coordination as

supplied on the piping and instrumentation

diagram appears incorrect. The original op-

eration as stated above is an interpretation.

Proposed Control StrategiesOperators and maintenance personnel can

use a number of control strategies to improve

the operation of their facilities’ feedwater

pump systems.

Open-Loop Control. There are many

possible methods of automating boiler feed

pump systems. The method chosen minimiz-

es the number of sequences so the operator

can easily follow the actions of the automa-

tion system. This becomes more important as

the whole power plant is automated. The se-

quence is used to place equipment in service

and place closed-loop controls in the relevant

modes, such as filling, start-up drum level,

and normal drum level control. The protec-

tion logic is carried out directly at the device

drive level. A basic principle is that the op-

erator has the option to control at all times.

Any field equipment loss of status during

start-up after being placed in service (such

as the isolating valve open status being lost)

should be handled as a status discrepancy on

the device. The affected closed-loop controls

utilize the process values (feedwater flow and

isolating valve not closed) to maintain their

operation. The plant protects itself through

the process values (drum level trip).

On this basis, reversing sequences are not

recommended as a best practice. Instead, the

sequence design utilizes check-backs from

the process (such as pressures and flows) and

device check-backs as the sequence feedback

for overrides and step criteria. If a sequence

is restarted, fulfilled criteria or override

check-backs bring the sequence back to point

of action required immediately. As a result,

status discrepancies can be used to stop the

sequence and allow the operator to investi-

gate the fault and restart the sequence with-

out unnecessary actions on the sequence or

process.

The main automation structure for the

feedwater pumps is given in Figure 1.The se-

quence for a feedwater system is controlled

by a single subgroup control (SGC) block.

The two feedwater pumps are, in turn, man-

aged by a single device configuration overlay

(DCO) block. Each motor has a separate mo-

tor block, with appropriate logic for permis-

sives, interlocks, and automatic operation.

Sequential Logic. The sequence logic

mirrors the steps and actions of the manual

start-up sequence taken from a plant operat-

ing procedure. The complete sequence begins

with no pumps running, first having the op-

erator go through the required manual checks.

Once the system is ready, the IP and HP drums

are isolated, the recirculation path is opened,

the lube oil pumps are started, and the select-

ed pump is started. From this point forward,

a pump failure will cause the DCO block to

start the standby pump. In fact, the switchover

logic will remain in effect even after the main

sequence is complete. Steps match the written

sequence for this example but could easily be

consolidated for simplicity.

Shutdown. The shutdown sequence initi-

ates the closure of the IP and HP feedwater

and isolation valves as well as the feedwater

and lube oil pumps.

Operator Prompts. As the sequence pro-

gresses, three single-line messages appear on

the screen. The first line displays an opera-

tor prompt and acknowledgement button, if

required. The second line is a description of

the current step actions and conditions. The

final line lists information related to the next

step in the sequence. Figure 2 shows typical

messages and an operator prompt.

HMI Concepts for RobustnessSeveral concepts built into the HMI have

the goal of improving the operator interface:

A single process graphic simplifies naviga-

Pump1

Pump2

Notes: DCO = device configuration

overlay, SGC = subgroup control.

SGC

Step 1

Step 2

DCO

Motor

Motor

1. Automation hierarchy. This sche-

matic shows the main automation structure

for the feedwater pumps. The sequence for

a feedwater system is controlled by a single

subgroup control block. The two feedwater

pumps are in turn managed by a single device

configuration overlay block. Courtesy: Sie-

mens Energy Inc.

2. Friendly reminders. This figure shows typical messages and operator prompts. Cour-

tesy: Siemens Energy Inc.

3. One-click convenience. A single consolidated process graphic encompasses the ma-

jor components of the feedwater system, including the LP, IP, and HP drums. Courtesy: Siemens

Energy Inc.

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tion as well as monitoring of the feedwater

system; linked pop-up displays provide easy

access to more detailed information; and a

dedicated alarm summary displays a prefil-

tered set of alarms related to the feedwater

system for faster reference.

Single Process Graphic. A single con-

solidated process graphic encompasses the

major components of the feedwater system,

including the LP, IP, and HP drums. Figure

3 shows typical messages and an operator

prompt.

Control is accessed by faceplates linked to

each dynamic symbol. The sequence (SGC)

and group (DCO) controls are linked here

as well. A space on the page is reserved for

operator messages and prompts during the

sequence. Access to control settings, alarms,

and the linked control diagram is given by the

icons below the title bar. Linking to the online

control diagram permits one-click checking

of logic or permissive/interlock conditions.

Pop-up Displays. For major equipment

such as a feedwater pump, it is sometimes

useful to have a dedicated set of small pop-

up displays, each linked to a button on the

process display. Figure 4 shows several ex-

amples. The permissives listed in the EPRI

case study have been assembled into a small

pop-up overlay, along with a similar list of

interlocks for each pump. Bearing tempera-

tures and other pump/motor data are avail-

able from the data button.

Regulatory (Closed-Loop) ControlSingle push-button start-up is not possible

without stable regulatory controls. This sta-

bility is required not only during normal oper-

ation but also during start-up and throughout

the full operating range of the unit. With this

in mind, the coordination of the VFD and

feedwater valves is revisited.

VFD Control StrategiesProvided stable operation is maintained, re-

ducing pump load can result in significant

energy savings. Assuming a plant electrical

load of approximately 1.5 MW for the feed

pump, a 10% reduction in pump load would

save over 1,300 MWh annually.

The strategy as described for the case

study uses the VFD in combination with

the feedwater valves in an overlapping split

range. The VFD starts at minimum speed (a

35% turndown from maximum). It increases

as needed once the valves are at the upper

end of their control range and only modulates

while the IP valve is less than 85% open. One

consequence of this strategy is a somewhat

disjointed control response and an undesir-

able coupling of the IP and HP drum levels.

For example, as the VFD speed increases,

both the IP and HP valves throttle back in re-

sponse to increased flow. Once the IP valve

throttles below 85%, the VFD could remain

above minimum speed indefinitely.

An alternative approach is to change the

VFD strategy by introducing an override con-

troller, as illustrated in Figure 5. For simplic-

ity, a single output is used for the HP drum.

This output could in turn be sent to each

valve via a balancing control or simple split

range. The IP drum level controls also are not

4. Pop-ups in a flash. For major equipment such as a feedwater pump, it is sometimes

useful to have a dedicated set of small pop-up displays, each linked to a button on the process

display. Courtesy: Siemens Energy Inc.

5. Easy overrider. Once the IP valve throttles below 85%, the variable-frequency drive

(VFD) could remain above minimum speed indefinitely. An alternative approach is to change the

VFD strategy by introducing an override controller. Courtesy: Siemens Energy Inc.

HP drum level

LI

FI

FI

A

A

A T A

A T A

PI PI

PI

PI

T

f(X) f(X)

>

f(X)

f(X)

+ +– –

–+

+–

HP steam flow

HP feedwater flow

3-element

No

Yes

IP valve output

85%

HP valve output

Pump master speed control



shown in this scheme for simplicity but could

also be added as an additional override.

The level control demand output for the

HP drum, whether single- or three-element,

is passed to both the HP valve and the pump

VFD. As long as the IP valve stays below

85% open, this output is a simple split range,

with the valve opening from 0% to 100%,

then increasing the pump from minimum

to maximum from 100% to 200%. A hid-

den direct-acting controller (error = process

variable – setpoint) monitors the IP valve de-

mand with a fixed setpoint. The output of this

controller passes through the “high select”

function to the VFD. As the valves respond

to the increased flow by throttling, the over-

ride controller output returns to zero, which

allows the HP valve to open completely and

the VFD to modulate to maintain level. The

master speed control drives the speed con-

trols for both pumps.

This control scheme has the advantage of

being simple yet efficient; however, it does

retain some coupling between IP and HP

drums. As a further modification, changing

the override to a bias function and adding a

decoupling function to this control strategy

would minimize disturbances to HP drum

level during override conditions. This modi-

fied strategy is illustrated in Figure 6. As in

the previous diagram, the IP drum level is

omitted for simplicity. To account for this, a

second proportional integral controller would

be added to the scheme with IP feedwater

valve position as its controlled variable. The

two positioning controllers would pass to the

VFD via a high select, with decoupling bi-

ases to each valve.

Process Aspects: Pressure Varia-tions, Drum Swell, and StabilityDuring start-up, the drum level controls can

be a challenge for any operator. The operator

and controls have to contend with drum level

shrink/swell; the drum level swings due to

the interaction of the steam pressures and the

drum levels. Providing stable drum levels is a

key part of any full start-up automation.

Operators use different strategies to deal

with the so-called “drum-level rodeo.” This

sometimes entails continuous blowdown of

the drums to ensure that the feedwater is

continuously flowing, mitigating the ef-

fect of feedwater cycling and temperature

differential between the water entering the

drum and drum water/steam temperatures.

However, this requires continuous atten-

tion by the operators.

Pressure variations also affect the drum

level through the compressibility of the

water-steam mix, and cause steam flow

variation leaving the drum. This means any

instabilities or cycling of the bypass sys-

tems are also reflected in the drum level. In

addition, variations in the rate of pressure

change affect the drum level. This effect is

also utilized by operators when manually

influencing the drum level.

Bypass strategies have been implement-

ed that stabilize drum level controls, and

pressure-raising strategies have been used

to stabilize drum level for cold through hot

starts. In addition, including the pressure

dynamics in the drum level controls has

proven to be a factor in stabilizing drum

level controls during start-up. Proper tun-

ing of the controls is also a must.

Because the boiler feed pumps usually

supply water for attemperation of steam

supply and bypass lines, changing the sup-

ply pressure may affect these temperature

controls, requiring further coordination.

One example might be a pressure control

feedforward to the temperature controls;

decreasing boiler feed pump discharge

pressure increases spray water demand.

Simple, Yet ComplexEven a relatively simple start-up process

can have many steps and delays for opera-

tor cross-checks. Automation can simplify

the procedure for the operator while reducing

start-up time. In addition, more sophisticated

controls techniques may be applied to im-

prove process stability, reduce energy usage,

and increase operating flexibility.

This article was written based on case

study guidelines provided by the Electric

Power Research Institute. The control dia-

grams created for this case study are avail-

able in PDF format from the authors, via

email request (george.thackston@siemens

.com). Portions of this article were presented

at the 2010 ISA POWID Symposium. ■

—Steven Leibbrandt ([email protected]), chief technology officer,

and Bill Thackston ([email protected]), principal engineer, work for

Siemens Energy Inc.

HP drum level

LI

FI

FI

A

A

A T A A T A

PI PI

PI

PI

T

Ĕ

f(X) f(X)

f(X) f(X)

+ +– –

–+

+–

HP steam flow

HP feedwater flow

3-element

No

Yes

IP valve output

85%

Pump master speed control

+

+

Ĕ

+–

Ĕ

+

+

f(X)

HP valve output

6. Curbing disturbances. Changing the override to a bias function and adding a decou-

pling function to this control strategy minimizes disturbances to HP drum levels during override

conditions. Courtesy: Siemens Energy Inc.


GAS TURBINE DESIGN

The T-Point Plant: The Ultimate Validation TestFourteen years ago, the MHI T-Point demonstration combined-cycle plant in

Takasago, Japan, changed the way modern gas turbines are validated under real operating conditions. In February, T-Point marked yet another milestone by starting to validate the world’s largest and highest efficiency gas turbine, which operates at the unprecedented turbine inlet tempera-ture of 1,600C.

By Angela Neville, JD

Until the 1990s, gas turbine prototypes

were shop-tested and validated at

“beta” sites where commercial power

production was typically hampered by issues

associated with the introduction of new tech-

nologies. In order to optimize the process of

detecting and correcting defects during the

validation phase, and to prevent exposing

clients to the debugging process, Mitsubishi

Heavy Industries Ltd. (MHI) introduced the

concept of in-house validation under real op-

erating conditions.

The plants providing this service are op-

erated and maintained by MHI staff and sell

their electrical output to local utility compa-

nies. Carlos Koeneke, vice president, project

engineering at Mitsubishi Power Systems

Americas Inc., told POWER in April that

MHI built the first 50-Hz validation plant, K-

Point, in Kanazawa in 1992. It was followed

in 1997 by a 60-Hz counterpart in Takasago,

called T-Point (Figure 1).

“These demonstration plants were the

first of their kind and revolutionized the

way validation of advanced gas turbines is

performed,” Koeneke said. “K-Point plant

was decommissioned several years ago, but

T-Point plant continues selling the generated

power and even today, 14 years after T-Point

went commercial, there is no other company

that performs the comprehensive validation

that the T-Point plant provides.”

The highest cost of sustained long-term

validation under real operating conditions

is not the equipment but the fuel consumed.

The T-Point plant is maintained and operated

by MHI under dispatch instructions from the

local utility (Kansai Electric). The plant is

frequently started and stopped, and every sin-

gle MW is sold under a contract, as with any

other independent power producer. Koeneke

explained that this arrangement “makes it

possible, from the economic point of view, to

sustain long-term validation operation.”

A Strong Track RecordIn addition to revolutionizing the way mod-

ern industrial gas turbines are validated,

in 1997 the T-Point plant pioneered the in-

troduction of steam cooling to gas turbines.

Through extensive validation of the steam-

cooled M501G gas turbine, as well as the

upgraded M501G1 gas turbine in 2003, the

T-Point plant delivered excellent results that

facilitated deployment of the largest and most

successful steam-cooled fleet of gas turbines

in the market. To date, 47 units in operation

have logged in excess of one million actual

hours and 11,600 starts. This impressive G-

Series record culminated with the introduc-

tion of the air-cooled version, which also was

validated since 2009.

Operating and maintaining the demon-

stration plants in the same facility where

design and manufacturing occurs (the MHI

Takasago Machinery Works, which also in-

cludes a rheostat shop test facility that can

be used to test off-frequency conditions)

results in a smooth debugging process with

a lower risk of failures and quick recovery

after unforeseen issues, Koeneke explained.

The validation process would not be repre-

sentative of real operating conditions if the

running modes were not determined by a real

demand condition or if the duration of the

validation run were restricted to only a few

hundred hours due to the high cost of fuel.

The T-Point plant has logged more than 2,300

start-stop cycles, 1,300 of those correspond

to daily operating cycles. It has also operated

more than 420 days, either continuously or

under weekly start/stop cycles.

“Because of the lower failure and inter-

ruption risks, this demonstration concept

is widely praised by the insurance commu-

nity,” Koeneke said. “The testing scope goes

beyond the gas turbine. T-Point also has al-

lowed testing of a number of innovations,

including steam turbine upgrades, air-cooled

1. Carrying its own financial weight. The T-Point combined-cycle plant is maintained

and operated by MHI under dispatch instructions from the local utility, Kansai Electric. The plant

is frequently started and stopped, and every single MW of generated electricity is sold under

a contract. This makes it economically possible to sustain long-term validation operation. Cour-

tesy: Mitsubishi Heavy Industries Ltd. (MHI)


GAS TURBINE DESIGN

condenser technology, generators, and static

frequency converters.”

Donald S. Schubert is the senior vice presi-

dent of the Power Practice Division of Marsh

Inc., an insurance company in the energy

sector that provides coverage in the areas of

project risk management, claims services, and

errors and omissions protection for engineer-

ing services. He told POWER that he agrees

with Koeneke’s assessment of the value of the

demonstration concept pioneered by MHI.

“Looking back at the history of all the

[original equipment manufacturers’] efforts

to test and validate their new engines, T-Point

certainly leads historically for the applica-

tion of ‘load dynamic’ testing,” Schubert

said. “MHI’s early industrial approach was

testing in a power plant environment where

dispatch and loading of units are not under

their control.”

The insurance community’s point of view

shows that MHI’s approach promotes ad-

vanced product validation in a non-owner

operator environment, according to Schubert.

The new engine validation “supports tech-

nology acceptance by the insurance markets

by clarifying risks associated with new and

upgraded designs.”

Validating Upgraded Components During Periods of Low DemandMHI uses periods of low demand to inspect the

plant’s equipment and to introduce upgraded

components intended to promote enhanced re-

liability and performance, Koeneke said.

Designers and research and development

staff based in nearby buildings have the abil-

ity to request the installation of temporary

sensors that allow them to gather valuable in-

sights pertaining to the modified parts. They

have the invaluable opportunity to see imme-

diate, first-hand results of their modifications

and review their ideas to develop even better

designs. Numerous improvements to the G-

Series fleet of gas turbines were validated at

the T-Point plant and consequently resulted

in the high reliability this class enjoys.

Another Milestone: Demonstra-tion of the M501J Gas TurbineIn November 2010, after T-Point staff complet-

ed validation of the air-cooled M501GAC gas

turbine, they replaced this frame with the first

M501J gas turbine (Figures 2 and 3). T-Point

has achieved another unprecedented milestone

with the ongoing demonstration operation of

this turbine, which has a inlet temperature of

1,600C (2,912F). That’s 100C higher than the

current highest-temperature engine.

The 60-Hz J-Series turbine achieves a rated

power output of about 320 MW (ISO basis)

and 460 MW combined-cycle power genera-

tion. According to MHI, this new gas turbine

is able to withstand temperatures 100 degrees

higher than the company’s existing 1,500 C-

class G-Series gas turbine because of a low-

thermal-conductivity thermal barrier coating

technology and improvements in cooling ef-

ficiency. The adoption of an enhanced three-

dimensional design contributes to improved

aerodynamics. In the J-Series gas turbine, the

compressor is designed to provide a higher

compression ratio, while the combustor car-

ries on the steam-cooled technology originally

developed for the G-Series turbine.

“We have rheostat capabilities at

Takasago Machinery Works, but it is naive

. . . to assume that the short-term shop test

operations with or without off-frequency

operations can replace true validation un-

der ‘demand conditions,’” Koeneke said.

However, “Validation should replicate as

much as possible the operating conditions

the equipment will be exposed for years to

come, and no demonstration plant in the

world has achieved this task better than the

T-Point Plant.” ■

—Angela Neville, JD is POWER’s

senior editor.

2. Traveling turbine. The M501J gas turbine is prepared for transportation to the T-Point

plant for validation testing. Courtesy: MHI

3. Making the mark. The T-Point achieved another unprecedented milestone with the on-

going demonstration operation of the M501J gas turbine, which has a turbine inlet temperature

of 1,600C (2,912F). Courtesy: MHI


COMBUSTION TURBINES

Selecting Your Next Combustion TurbineWith natural gas serving as the fuel de jour, many utilities and merchant gen-

erators will be considering the purchase of new combustion turbines in the near future. If you are in the market for a gas turbine, here are some key design features you should discuss with turbine vendors prior to your next purchase.

By Amin Almasi, WorleyParsons Services Pty Ltd.

The growth of the combustion turbine

(CT) market over the past two de-

cades has been facilitated by prog-

ress in three technologies:

■ Metallurgical advances that have made

possible high temperatures in turbine

components (especially turbine blades)

and combustors.

■ The advancement of aerodynamic and

thermodynamic knowledge (especially

from aircraft and spacecraft industries).

■ Advanced computer technology used in

the design and simulation of turbine air-

foils, combustors, and turbine blade cool-

ing configurations.

Combined, these advances have made

possible CT designs with state-of-the-art

1,600C (2,912F) turbine inlet temperatures

and combined-cycle efficiency pushing the

60% thermal efficiency barrier.

The challenge for a purchaser of a new

CT is what questions to ask, given that

these design advances are not readily ap-

parent. The discussion that follows is not

meant to tell a manufacturer how to design

a CT, nor is it comprehensive. Rather, it is

intended to prompt some useful planning

before a potential buyer has the first tech-

nical discussion with a potential supplier.

Turbine ConfigurationsCTs are usually categorized as either heavy

frame industrial or aero-derivative gas tur-

bines, although a few turbines have recent-

ly adopted features of both design types.

One good example of a “hybrid” is Gen-

eral Electric’s LMS100; it has a Frame 6FA

low-pressure compressor and a CF6-80C2

high-pressure compressor.

In general, the differences between the

aero-derivative and industrial turbines are

weight, size, combustor and turbine de-

sign, bearing design (antifriction bearings

for aero-derivative turbines and hydrody-

namic ones for industrial turbines), and

the lube oil system. Industrial turbines are

also field erected and maintained in place,

whereas aero-derivative turbine plants are

designed for a quick replacement of the en-

tire engine when maintenance is required.

Manufacturers of aero-derivative CTs

include General Electric, Rolls Royce

(Figure 1), and Pratt & Whitney. Manufac-

turers of industrial CTs include Siemens

(Figure 2), Mitsubishi (see page 54), Als-

tom (Figure 3), General Electric, and Solar

Turbines Inc. Each manufacturer’s CT is

available in 50-Hz and 60-Hz models.

Selection of CT type is usually made

based on the nature and location of ser-

vice and a long list of site-specific design

1. Rolls Royce RB211. The 44-MW en-

gine upgrade released by Rolls Royce in mid-

2010 boasts a 41.5% thermal efficiency. The

high-pressure turbine and much of the triple-

spool compressor is based on aero engine

technology. Courtesy: Rolls Royce

2. Siemens SGT6-8000H. Siemens Energy introduced the 60-Hz version of its combus-

tion turbine in June 2010. The 274-MW turbine features a turbine inlet temperature of 1,500C.

This turbine can go from standby to start in 5 minutes and can reach full power in 15 minutes.

Courtesy: Siemens Energy



COMBUSTION TURBINES

and economic factors that are usually led

by the projected price of natural gas. The

conventional wisdom was once to place

aero-derivative units in remotely located

applications (including offshore) and to

place heavy frame industrial units in eas-

ily accessible baseload applications. How-

ever, about 10 years ago in the U.S., the

combined cycle, based on the aero-deriv-

ative turbine, became very popular given

both the speed at which a plant could be

constructed and its superior efficiency.

Both CT types are available in differ-

ent configurations. In the hot-end-drive

configuration the output shaft is at the

turbine or exhaust end, where the higher

temperatures can affect bearing life and

make servicing of those bearings more dif-

ficult. In the cold-end-drive configuration,

the output shaft extends out the front of

the compressor, allowing the exhaust gas

flow to be axial in some models (Figure 4).

With a cold-end-drive turbine, the driven

equipment is also relatively cooler and

easier to service. However, the compressor

inlet and ducting must be configured to ac-

commodate the output shaft and the driven

equipment. In sum, the CT configuration

is usually selected, when possible, by ap-

plication and site configuration.

Single-spool, integral output shaft CTs

(in both hot-end and cold-end-drive config-

urations) are used primarily to drive elec-

tric generators. However, the high torque

required to start pumps and compressors

under full pressure results in high turbine

temperature during the start-up cycle when

internal cooling airflow is low or nonex-

istent. The solution has been to connect a

single (or two or three) spool compressor/

turbine section (also called a gas genera-

tor) that produces hot gases to a separate

power or free turbine. The gas generator is

not physically connected to the power tur-

bine shaft but is coupled aerodynamically

(Figure 5). Also, the power turbine can be

designed to operate at the same speed as

the generator, not the gas generator, and

often eliminates the need for a gearbox to

match speeds. (Typical gearbox losses are

2% to 4% of power.)

Keep It CleanIt’s often said that the key to achieving maxi-

mum CT life is keeping the combustion air,

fuel, and lubricating oil clean. There are few

areas in the plant where an owner can more

easily improve long-term performance, and

therefore profitability, of the plant than in

these three systems.

Clean Air. The inlet and exhaust systems

should be selected for the minimum practi-

cal pressure drop because those losses are

3. Alstom GT24/26. The sequential combustion system is a unique feature of the

GT24/26. Compressed air is heated in the first combustion chamber (EnVironmental or EV com-

bustor) by adding about 50% of the total fuel (at baseload). The pressure is halved after the

combustion gases expand through the single-stage high-pressure turbine. The remaining fuel

is added into the second combustion chamber (Sequential EnVironmental or SEV combustor),

where the combustion gas is heated a second time to the maximum turbine inlet temperature.

The gas then expands through a four-stage low-pressure turbine. Courtesy: Alstom

Compressor Shaft Turbine

Combustion chamber

Atmosphere air intake

Generator

Exhaust to atmospheric

Compressor ShaftGas

generator turbine

Combustion chamber

Air intake Exhaust

Generator

Starter

Fuel in

Power turbine

Shaft

Hot gas flow

Gas generator section Power turbine section

4. Cold-end-drive option. The typical single-shaft combustion turbine has the compressor

and turbine sections on opposite ends of the shaft. The driveshaft in this figures extends from

the compressor section, hence it is a cold-end-drive engine. If the driveshaft extended from the

turbine end, it would be a hot-end-drive engine. Source: WorleyParsons Services Pty Ltd.

5. Two-shaft option. The typical two-shaft or split-shaft combustion turbine configuration places

the compressor and gas generator turbine on a common shaft. The hot exhaust gases “aerodynami-

cally” connect the power or free turbine to produce shaft power for the generator or other driven load.

The advantage of this configuration is that the output shaft speed can be controlled to that required

by the generator to eliminate a gearbox. Aero-derivative configurations use multiple gas generator

sections on concentric shafts to improve efficiency. Source: WorleyParsons Services Pty Ltd.

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COMBUSTION TURBINES

paid for every hour that the plant operates.

The filter should remove 100% of particles

in the inlet air that are 3 microns and larg-

er and, at minimum, 99% of particles 0.5

to 3 microns. Be sure to include an entry

screen to prevent debris from entering the

filter house; orient the air inlet, louver,

or cowling to minimize entry of driving

rain, snow, or sand; also ensure that there

is good access to all parts of the air filter

module for maintenance and filter element

replacement.

The optimum duct design will:

■ Minimize the number of direction chang-

es required before the air enters the com-

pressor, including required turning vanes

(to ensure uniform flow distribution and

avoid resonance).

■ Limit the inlet air velocity to between 20

meters (m)/s and 30 m/s.

■ Design ducts to be sufficiently rigid to

avoid vibration (plate 5 to 10 millimeters

thick is generally used).

■ Include plenty of man-ways for cleaning

and inspection.

■ Include a differential-pressure alarm for

each stage of filtration.

At the end of construction, thoroughly

clean the air side of the inlet filter and duct-

work to eliminate any objects, no matter how

small, that could come loose during operation

and cause catastrophic damage to the CT.

If the CT is located close to the seacoast,

sea salt ingestion will rapidly cause sulfida-

tion or hot section corrosion, so make sure

the filter system materials and level of filtra-

tion are proper for the location.

Here are a few other tips for selecting

equipment:

■ Don’t skimp on the materials inside the fil-

ter house and ductwork. The filter house,

inlet silencer, and perforated plate ele-

ments should be fabricated from suitable

grades of stainless steel.

■ Make sure the silencers have a rigid struc-

ture to prevent damage due to acoustical

or mechanical resonances or differential

thermal expansion.

■ The ducting and casing design should per-

mit field balancing in the end planes of the

rotors without requiring the removal of

major casing components.

When determining the arrangement of

the plant, make sure the air inlet is up-

stream of the exhaust stack during prevail-

ing wind conditions to avoid recirculation

of exhaust gases under any projected wind

conditions. A good recommendation is to

keep a minimum horizontal separation of

7.5 m. The air inlet (elevated a minimum

of 5 m) and CT exhaust should also be

located outside a three-dimensional fire

hazardous zone and outside any classified

electrical area.

Clean Oil. A good gauge of the oil cool-

ing system design quality is to confirm that

the inlet oil temperature and oil tempera-

ture rise through the bearing are less than

50C and 33C, respectively. Another good

idea is to include a full-size, redundant

shell and tube lube oil cooler configured

with a removable tube bundle and redun-

dant oil filters with removable elements.

Also be sure to use stainless steel for all

lube oil piping and valves—accept noth-

ing less.

Each oil supply line to critical compo-

nents should be individually monitored,

mainly for oil pressure. We recommend

that the oil reservoir retention time should

be at least 8 minutes. For aero-derivative

CTs (that have antifriction bearings and

use synthetic lubrication oil), the turbine

lubricating oil system usually should be

separate from the driven equipment (such

as the generator) lubricating oil system.

We also strongly recommend that CTs

equipped with antifriction bearings should

be instrumented with metal chip detec-

tion, an online metallic debris monitoring

system. Industrial CTs, which normally

use hydrodynamic bearings and mineral

oil–based lubricating oil, typically have a

single integrated oil system for the entire

driveline.

Clean Fuel. Designing a combustor

is a complex task, often likened to light-

ing a match in a hurricane. For most CTs,

there are two distinct configurations: the

can-annular (a number of combustor cans

arranged around the circumference of the

CT) and the annular design, which in-

cludes the single-can option.

The design of the fuel supply system

is critical and requires special attention.

Always include a fuel strainer (a Y-type

strainer with stainless steel internals) and

a blowdown system (manual valve) for

purging and warming up the fuel system

for approximately 20 minutes prior to

starting. A manual valve closed about 2

minutes after starting should be included

as well as a safety shutdown valve. The

plot limit valve (fail safe) for trip on gas

knockout drum high liquid level (manual

and automatic) preceded by a high level

alarm is required in any robust fuel system

design. Also consider including a fuel gas

superheater designed to deliver 40C fuel

gas to prevent condensate mist carryover

or hydrate formation. If fuel gas compres-

sion is required, screw compressors always

seem to be the optimal selection.

The fuel control system should also in-

clude a shutoff valve (separate from the

fuel control valve) that stops all fuel flow

to the turbine on any shutdown condition

(local and remote tripping) and that cannot

open until all permissive firing conditions

are satisfied. Fuel shutoff valves should

have a remote shutdown actuator and a

partial stroke feature to permit field check-

ing of the operability of the shutoff valve

during normal operation of the CT.

Driveline DesignThe rule of thumb for power generation

packages is that the generator shaft diam-

eter should be equal to or greater than the

CT shaft diameter. For mechanical drive,

shafts should have approximately the same

diameter. When torsional vibration prob-

lems appear, the primary cause is the lack

of a comprehensive torsional analysis, im-

proper coupling selection (mainly flexible

couplings), and lack of proper operation

and maintenance.

Most original equipment manufacturer

(OEM) designs make certain that the blade

natural frequencies do not coincide with

any source of excitation from 10% below

minimum governed speed to 10% above

maximum continuous speed. For the en-

It’s often said that the key to achieving

maximum CT life is keeping the combustion

air, fuel, and lubricating oil clean.


COMBUSTION TURBINES

tire driveline, there is the potential for tor-

sional, lateral, or blade resonance to cause

fatigue failure. The coupling between the

turbine and gearbox or gearbox to gen-

erator, for example, is the best option for

tuning the torsional character of the driv-

eline. There are a couple of coupling op-

tions: high torsional stiffness (preferably

dry flexible diaphragm type)—or direct

forged flanged rigid connection (which is

optimum, if allowed by torsional analysis),

and a flexible coupling with more elastic-

ity, damping, and more maintenance.

The coupling torque is usually chosen

on the basis of average requirements for

full load, but it also must have a sufficient

service factor to handle likely overload

(such as electrical faults). A pulsation of

generator load caused by current pulsation

is an important concern, especially for a

CT or a plant electrical network that is con-

nected to a relatively weak electric system.

Our comparative analysis showed a >25%

error in shaft stiffness and inertia between

detailed finite element analysis and simpli-

fied calculation methods. Rotor torsional

data coming from simplified methods may

lead to missing (or shift of) torsional criti-

cal speed(s) and torsional problems. Make

sure the OEM supplies a stress and vibra-

tion analysis of your turbine configuration

rather than just a “typical” report.

Take special care with the starting de-

vice selection and rating. The preferred

starting device is electro-hydraulic (an

electric motor drives a hydraulic pump,

which in turn transmits hydraulic power to

start the gas turbine) and rated to supply,

at a minimum, 110% of the starting and ac-

celeration torque in worst-case conditions.

The typical criterion for selection is that

the starting system should be capable of

an immediate hot start anytime after a unit

trips for three consecutive start attempts.

Cold-start and hot-start restrictions are

also very important and greatly affect the

starting reliability and, perhaps, the forced

outage rate of the plant.

Manage Performance DegradationTurbine stage degradation cannot be

avoided but can be slowed. It also has a

cumulative effect. A degraded stage (a

single wheel with blades along the periph-

ery) will create different exit conditions,

causing each subsequent stage to operate

further away from its design point.

The main causes of blade degradation are

increased tip clearances, changes in airfoil

geometry, and changes in surface quality.

The cause of degradation is blade fouling,

caused by particles that stick to blade airfoils

and annulus surfaces, or hot corrosion, the

loss or deterioration of material by chemical

reactions from components exposed to hot

gas. The corrosion is caused by both the hot

gas and contaminants.

Erosion also occurs in the same regions

as hot corrosion. Erosion is the abrasive

removal of material from the flow path by

hard or incompressible particles imping-

ing on flow surfaces. Abrasion is caused

by foreign objects in the gas that strike the

flow path components and when a rotating

surface, such as the tip of a blade, rubs on

a stationary surface.

Good inlet air and fuel filtration will

help defeat foreign object–caused damage,

although sodium in the inlet air and sulfur

in the fuel will always cause some fouling

and corrosion in the hot gas path.

Include Condition MonitoringCondition monitoring is particularly cost-

effective when malfunctions are identified

before a severe failure occurs. The best

tool available is vibration monitoring. We

recommend casing vibration monitoring (a

minimum of two sets for compressor and

turbine casings) with both velocity mea-

surements for low-speed vibrations up to

2 kHz and accelerometers for high-speed

vibrations and for hot sections. Noncon-

tacting probes should be used for axial

and radial vibration monitoring. These

measurements include journal bearings,

noncontacting X-Y probes mounted at a

45-degree angle from the vertical center-

line, and a velocity seismic transducer for

bearing housings and dual probes axial po-

sition for thrust bearings.

Temperature monitoring is also an im-

portant element of a robust condition-moni-

toring system. We recommend temperature

monitoring of oil, including the lubricat-

ing oil drain thermocouples for alarm and

emergency shutdown and hydrodynamic

thrust and radial bearings with replaceable

resistance temperature detectors (RTDs).

We also recommend temperature monitor-

ing of the hot air path flow.

Over-temperature protection should be

independent of the CT combustion control

system to add another level of operating

redundancy. Six thermocouples placed

around the turbine exhaust gas frame to

measure exhaust gas temperatures for

alarm and trip are usually sufficient.

Our normal design approach is to in-

clude triple-redundancy instruments to

the electronic governor. That means that

there are three input sensors, with two out

of three voting logic. This approach will

prevent, for example, CT speed increases

beyond the overspeed limit in the case of a

loss of rated load or a coupling failure. For

multiple-shaft CTs, each shaft should have

its own overspeed protection system with

online testing capability; the overspeed

trip system is independent of the gover-

nor system. Our standard design monitors

overspeed, low fuel supply, combustor

flame out, low lube oil pressure, and radial

and axial shaft vibration, in addition to the

measured parameters of the driven equip-

ment as the source of shutdown signals.

Always Operate SafelyOur design approach for a system gas

purge is to replace a minimum of six times

the exhaust system volume (including tur-

bine, exhaust duct, waste recovery device,

exhaust stack, and so on) before firing the

unit. The ignition temperature of the gas

must always be higher than the surface

temperature of the gas turbine. A HAZOP

(hazardous operations) review (action

and response) should be conducted with

consideration of all possible malfunction

scenarios, including failure of individual

instruments and components. As part of

this review, consider cases of possible re-

verse flow, higher flow, all scenarios of

tube rupture or component damage, and all

potential cases of gas to atmosphere that

may form flammable gas clouds.

The design of the enclosure ventilation

system must produce a negative pressure

within the enclosure (when located within

a safe area) or a positive pressure (when

located within a hazardous area). We rec-

ommended at least two 100%-sized venti-

lation fans with automatic start controls.

O&M IntervalsA well-built CT should have the design

life of its principal components—includ-

ing rotors, casings, bearing housings, sup-

ports, and base-frame. At a minimum of

160,000 operating hours, that would be

about 20 years, when the time between

starts is about 80 to 100 hours. With many

combined-cycle plants now cycling daily,

that design life will be reduced. How much

the design life will be shortened is project-

specific and requires much analysis by the

OEM. However, under normal operation,

expect the planned time between major

overhauls to be 40,000 fired-hours (five

years), 16,000 fired-hours (two years) for

hot gas path inspection, and 8,000 fired-

hours (one year) for borescope inspection.

These intervals will need to be shortened,

sometimes significantly, when turbines are

cycled daily or weekly. ■

—Amin Almasi (amin.almasi@ worleyparsons.com) is a lead rotating

equipment engineer for WorleyParsons Services Pty Ltd., Brisbane, Australia.


PLANT ECONOMICS

A More Accurate Way to Calculate the Cost of ElectricityLife-cycle cost of ownership is a common metric used to compare power plant

system alternatives. However, the familiar formula for calculating the cost of generating electricity omits factors that are becoming increasingly important to business decisions. A new formula addresses those blind spots by estimat-ing the value of the part-load performance of cycling combined-cycle plants.

By S. Can Gülen, PhD, PE, GE Energy

Previous articles proposed more ac-

curate and consistent definitions of

combined heat and power (CHP) ef-

ficiency (“A Proposed Definition of CHP

Efficiency,” June 2010) and steam plant ef-

ficiency (“Plant Efficiency: Begin with the

Right Definitions,” February 2010). This

article proposes a revision of another com-

mon definition: the unit cost of generating

electricity (COE). COE is a widely used

metric for comparing power plant system

alternatives. Traditionally, it combines a

power generation system’s ownership costs

(capital and operating) and thermal perfor-

mance (output and efficiency). This metric

is useful when comparing power generation

alternatives that use similar technologies.

The standard formulation of COE is the

sum of capital, fuel, and operations and main-

tenance (O&M) costs of plant ownership, as

shown in Equation 1 (see sidebar).

The cost of generation as provided by

this COE formula can be interpreted as the

price at which electricity must be sold in

order to cover all fixed and variable gener-

ating expenses and to match the return on

company’s equity implicit in the assumed

cost of money (ß). The COE is limited to

a single operating condition, typically new

and clean rated performance, and is usually

calculated at International Organization for

Standardization (ISO) baseload.

This definition of COE is useful for

initial screening studies and comparison

of baseload combined-cycle (CC) power

plants. At this time, however, many CC

units are relegated to daily cycling opera-

tion that entails frequent starts and stops as

well as large load swings, often to provide

spinning reserve and backup power for re-

newable energy generation that is not dis-

patchable. Even assuming that natural gas

prices hold steady at their current low level,

gas-fired CC plants are expected to contin-

ue in intermediate and cyclic duty for many

120

100

80

60

40

20

0

Loa

d (

%)

Hour

0 5 10 15 20 25 30

Day of week 1 Day of week 2

Average (effective)

LF = 76.2%

Daily (hot) start1 hour

Midday part load

Eveningpart load

Nightly shutdown

Weekly (warm) start - 2 hours

1. Typical cyclical duty profile for a combined-cycle plant. This particular

plant’s operation is sometimes described as “two-cycled.” Source: GE Energy

Equation 1

where

ĝ = Levelized carrying charge factor or cost of money

C = Total plant cost ($)

H = Annual operating hours

P = Net rated output (kW)

f = Levelized fuel cost ($/kWh [LHV])

ģ = Net rated efficiency of the combined-cycle plant (LHV)

OMf = Fixed O&M costs ($ or $/kW-yr)

OMv,b = Variable O&M costs for baseload operation ($/kWh)

Ĩ = Maintenance cost escalation factor (1.0 for baseload operation)

Equation 2


PLANT ECONOMICS

years to come. Consequently, an overhaul

of the standard COE formula is needed to

determine the value added by improved op-

erational flexibility, such as better part-load

efficiency and faster starts.

Cyclical OperationTypical daily operation of a “two-cycled”

CC plant is shown in Figure 1. The plant

is operated five days a week year-round or

perhaps only during the summer months.

In this example, every Friday, the plant is

shut down at 10 p.m. for the weekend and

is restarted the following Monday at 5 a.m.

Twice a year, the plant is shut down for

one week to carry out scheduled mainte-

nance tasks. Thus, the annual plant start

schedule comprises 250 starts (two cold,

48 warm, and 200 hot starts).

Ignoring the time spent during start-up

(the added generation is estimated later)

and the seasonal ambient variation, the

plant is expected or planned to operate

(H) 4,250 hours per year with a service

factor (SF) of 4,250 / 8,760 = 48.5%. At

a nominal 500 MW baseload power, the

total annual energy production (E) can be

calculated as 1,700,000 MWh for a capac-

ity factor (CF) found as 1,700,000 / (500

x 8,760) = 38.8%. Similarly, the load fac-

tor (LF) is calculated as 1,700,000 / (500 x

4,250) = 80%, or nearly twice the CF.

Power generation during start-ups can

be estimated via simple integration (see the

shaded area in Figure 1 for a hot start) based

on applicable start-up curves provided by

the manufacturer. Using the load profile in

Figure 1 and typical start-up curves, an ad-

ditional 29,400 MWh per year of start-up

electric generation is estimated.

Load ramps can be found in a similar

fashion to contribute another 5,200 MWh,

assuming a rate of 10% per minute. Add-

ing these two unsteady-state generation

quantities to the nominal generation of

1,700,000 MWh calculated above, you

find the effective total generation (Eeff) is

1,734,600 MWh. Total or effective operat-

ing hours (Heff) are higher than the nomi-

nal operating hours, H, by the total time

spent during plant starts (shutdowns are

ignored), or Heff = 4,250 + 200 x 1 + 48 x 2

+ 2 x 3 = 4,552 hours. This corresponds to

an effective plant output (Peff) of 1,734,600

/ 4,552 = 381 MW. Thus, the correction

due to the dynamic effects of start-up re-

sults in an effective load factor (LFeff) of

381 / 500 = 76.2%.

Note how accounting for the energy

generated during start-ups reduced the

load factor by about four percentage

points when the additional operating

hours at low loads are included. This fact

hints at a key advantage of fast-start plants

that spend less time at low loads: the LFeff

and heff are higher, resulting in a favorable

(lower) COE.

Average cycling plant load factors of

75% to 80% and the adverse impact of the

time spent during plant starts (200 or even

more per year for such units) suggest that

an improvement could be made to the basic

COE equation to account for plant cycling

effects. In addition to accounting for the

load factor variation just discussed, many

other key plant operability considerations

could be included in the COE formula. The

following four key factors, when added to

the basic COE equation, will produce a

more accurate evaluation of real CC plant

operation:

■ Seasonal temperature variation

■ Nonrecoverable performance degradation

■ Reliability (forced outage rate)

■ System (dispatch) considerations

The first two factors can be readily ac-

counted for by calculating a corrected base

performance. Ambient correction factors

can be found from OEM-supplied curves

using an appropriate annual load-weighted

average temperature, which can be directly

calculated using a seasonal temperature

variation chart. (For most moderate cli-

mates, the deviation from the ISO value is

less than ~5F.)

Average or mean-effective values of

output and efficiency degradation fac-

tors can also be easily found from sup-

plier-provided curves. Both corrections

are multiplicative and less than unity in

magnitude (unless the plant is located in

an extremely cold site), so the net overall

impact is higher COE via lower effective

values of power output, energy produc-

tion, and load factor.

The availability of CC power plants based

on advanced combustion turbines is normal-

ly quite high: usually above 90% and often

above 95%, especially for F-Class units op-

erated in large fleets, even in cycling service.

The reliability of these turbines can be taken

into account by multiplying the total energy

generation with an assumed reliability factor

(R) of 99% (the complement of the forced

outage rate).

Continuing with the example above, R x

Eeff = 99% x 1,734,600 MWh = 1,717,250

MWh. The expected reduction in the unit

service hours due to a less-than-perfect

reliability is thus reflected in a reduction

of the unit’s total energy generation and,

consequently, the load factor. The reduc-

tion in the latter will manifest itself in

lower effective plant efficiency and, as

will be shown below, in higher costs as-

sociated with capacity and energy replace-

ment. Even a small reduction in reliability

(worth ~17,350 MWh for 1 percentage

point in this example) can easily negate a

perceived advantage in rated performance

or operational flexibility.

A New FormulaThese system interactions suggest a modi-

fied and expanded COE formula that tai-

lors the original formula, adds emission

costs, and adds system impact costs such

as capacity and energy replacement during

outages.

At this time, there is no industry-wide

accepted method to convert specific plant

emissions (that is, pounds of pollutants

such as NOx, SOx, CO2, unburned hydro-

carbon, particulate matter, and so on per

generated MWh) into cost. Nevertheless,

emission costs (or penalties) can be added

to the COE via a term comprising two new

parameters: ci (price/cost of pollutant i in

terms of $/ton) and mp,i (plant generation of

pollutant i in tons/kWh). These terms can

also be used to represent a cost of emis-

sions during start-up. Although they are

not a concern at baseload, CO emissions

can be a problem when the unit is turned

down, especially during plant starts when

the unit spends a considerable amount of

time at low loads.

The last new term added, system im-

pact, accounts for the variation in effective

An overhaul of the standard COE formula

is needed to determine the value added by

improved operational flexibility.


PLANT ECONOMICS

total MWh generation and output (ig-nored by the standard formula) that must be provided when a deficiency in energy (kWh or MWh) must be made up by bring-ing another unit in the system online and/or when a deficiency in capacity (kW or MW) must be made up by purchasing firm capacity from neighboring systems. The COE analysis is adjusted to a common an-nual total energy generation basis using the following terms:

Sc = System replacement capacity cost ($/kW-yr)

Se = System replacement energy cost ($/kWh)

∆P = Capacity to be replaced (kW)∆E = Energy to be replaced (kWh)

For multiple unit comparisons, the alter-native with highest total energy production can be selected as the basis to determine ∆P and ∆E. Energy replacement cost (Se) is dependent on the makeup of the particular generating system, for which the alterna-tives are evaluated using COE. Note, how-ever, that the economic dispatch principle requires using a variable generation cost at least equal to or higher than that of the units under consideration. Otherwise, the replacing unit would already be online and generating electricity.

Case StudyThe new COE formulation’s contribution to the life-cycle cost analysis is best il-lustrated using an example. Consider a

standard 500-MW CC plant (57.5% rated efficiency) described as Plant A. Two en-hancements are planned for Plant A: im-proved part-load heat rate and a faster start-up and load ramp capability (assumed 50% shorter time). The new product that incorporates these improvements will be called Plant B. The remainder of the key plant parameters and assumptions used in this case study are summarized in Table 1. The beneficial impact of the planned im-provements on the COE is conceptually explained in Figure 2.

Two operating scenarios for Plant B could be analyzed:

■ Scenario B1. Plant B reaches baseload quicker than Plant A, allowing the plant to be dispatched for a longer period. Therefore, it generates more revenue—but at the expense of higher total fuel consumption and emissions. Heff is the same as for Plant A, or 4,552 hours (cal-culated previously).

■ Scenario B2. Plant B starts later than Plant A and reaches baseload at the same time as Plant A normally would. The benefit to operating in this manner is lower fuel consumption and emis-sions—but at the expense of less gen-eration (less revenue). Heff is reduced by 150 hours to 4,402 hours.

It would seem that starting a “fast” pow-er plant as early as possible so that it con-tributes baseload power to the grid quicker (scenario B1) is a better strategy than starting it as late as possible to be online at the last minute (scenario B2). However, this may not be the case when electricity sale prices are taken into account.

If the price before the prescribed time when the market price becomes effective is significantly lower (or even below the vari-able cost of generation), the apparent ad-vantage of B1 may be much more modest or even nonexistent. In fact, B1 is most likely to occur in an emergency situation, when immediate dispatch is required to exploit an opportunity or to make up for a sudden or im-minent loss in generation.

However, B2 is probably the norm for regular plant starts. Furthermore, a plant may have fast-start capability, but the plant owner may choose to use it sparingly or not at all unless paid a premium by a sys-tem operator to dispatch on short notice at a significant premium. Thus, the actual value of the fast-start capability is more likely to fall somewhere between the two scenarios. For this example, a weighted average of the performance of the two sce-narios is used.

Parameter Value

Annual load-weighted average ambient temperature 64F

Rated power at ISO base (P) 500 MW

Rated efficiency 57.50%

Specific price of plant $1,000/kW

First-year fuel cost options $5 and $10/mmBtu (HHV)

Fixed O&M $15/kW

Energy replacement cost options (Se) 6¢ and 11¢/kWh

Capacity replacement cost (Sc) $50/kW-yr

Variable O&M 1.5 mils/kWh

Capital charge factor (ĝ) 15%

Levelization factor (L) 1.25

Reliability (R) 99%

Maintenance factor (μ) 2.5

Table 1. Key data and parameters used for calculating COE. The data

shown here are for illustration purposes and do not reflect any existing product and/or

guarantee. Sources: Electric Power Research Institute, U.S. Energy Information Adminis-

tration, and PJM

2. Combined-cycle part-load efficiency. Plant B has better part-load efficiency

lapse than Plant A in this hypothetical comparison. Thus, at the same average load, B has

better efficiency (less fuel consumption) than A. The benefit of the faster start-up capability

is a higher effective load factor (less time spent at lower loads) and, consequently, higher

efficiency. Note that the generic curves shown here are for illustration purposes and do not

reflect any existing product and/or guarantee. Source: GE Energy

Part load efficiency lapse benefit

Load factor benefit of fast start

1.0

1.0

B

A

CC

eff

icie

nc

y

CC load or load factor


PLANT ECONOMICS

A comparison of the COE calculated

using the standard (original) and modi-

fied (proposed) formulations is shown in

Figure 3. The new formulation returns

a 25% higher value, driven by the use of

“real” effective kWh and efficiency values

(lower than their nominal baseload coun-

terparts) and additional cost components.

(Note the significant contribution of emis-

sions even when only CO2 is considered.

When NOx, CO, and other emissions are

also thrown into the mix with system-

specific “known” costs, the impact will be

more pronounced.) The real benefit of the

proposed formulation, however, is its abil-

ity to account for plant metrics other than

rated performance, thereby providing an

improved plant life-cycle cost evaluation.

From the equipment supplier’s point of

view, an interesting question is now raised:

What is the market value of the Plant B up-

grades, assuming Plant B COE remains the

same as Plant A’s? If the Plant B upgrades

are evaluated by assuming 10% unplanned

starts (a reasonable assumption given the

earlier discussion), then the results, sum-

marized in Table 2, are quite interesting:

■ A CC design with a better part-load heat

rate has a value of $7 million to $13

million for $5 and $10 fuel, respective-

ly. This is quite significant when you

consider that each 0.1 percentage point

in rated efficiency is worth ~$1 million

to ~$2 million (with the assumptions of

this example) for the same fuel price

range. The implication is that there is

room for about 0.7 net CC efficiency

points for a trade-off between ultimate

rated performance and sustained perfor-

mance across a wider load range.

■ A nimbler CC design, which slashes the

start time and load ramp rate by 50%,

has an additional value of $10 million

to $13 million for $5 and $10 fuel for a

total value of $17 million to $26 million

compared with Plant A, assuming no

difference in plant reliability, maintain-

ability, or component degradation.

■ A reduction of 1% in reliability (R = 98%

instead of 99%) is more than enough to

wipe out all the value compared with

Plant A, or even more (a reduction in

value by $15 million to $22 million). The

economics worsen if any potentially ad-

verse impact on maintenance factor and/

or nonrecoverable degradation is thrown

into the mix.

■ In order to simplify the treatment here-

in, NOx and CO emissions (typically re-

duced during faster starts) are ignored.

Inclusion of either will increase the val-

ue of Plant B with the fast-start feature.

■ Similarly, in extremely hot climates

and/or applications with duct firing, hot

day part-load performance characteris-

tics of the plant become important. This

refinement can be easily incorporated

into the proposed COE formula using

applicable correction curves or a load

profile table.

The expected increased use of CC plants

in the future will place a premium on units

that can be heavily cycled and quickly

started. By adding these effects to the fa-

miliar COE equation, we get a new formu-

lation that can be easily used to perform

screening studies to determine the value of

a plant more comprehensively.

In most applications, significant life-cy-

cle cost savings are possible for plants that

can operate at part load with improved ef-

ficiency or that can start and reach baseload

faster than conventional plants. Now you

have a screening tool to estimate the value

of those operational improvements. ■

—S. Can Gülen, PhD, PE (can.gulen @ge.com) is a principal engineer with

GE Energy.

Equation term

Original

COE

equation

Modified

COE

equation

Capital $35.30 $43.70

Fixed O&M $4.40 $5.50

Fuel $41.10 $43.80

Variable O&M $4.70 $4.70

Emissions $0.00 $7.50

Replacement power $0.00 $3.80

Total $85.50 $108.90

3. Calculating the COE. Applying the

assumptions listed in Table 1 to the original and

modified COE formulas to Plant A illustrates

the usefulness of this new way of calculating

COE. The assumed price of natural gas used to

calculate the COE was $5/mmBtu. An energy

replacement cost of $60/MWh was assumed.

Values shown in the table are in millions of dol-

lars. Source: GE Energy

Fuel 48.1%

Capital 41.3%

Variable O&M 5.5%

Fixed O&M 5.2%

Fuel 40.2%

Capital 40.1%

Emissions6.9%

Fixed O&M 5.0%

Variable O&M 4.3%

Replacement 3.5%

Table 2. Evaluating the COE of two plant design options. Note the dramatic

negative economic impact of a small decrease in Plant B’s reliability. The detrimental impact on

plant economics would be even more pronounced should a maintenance factor and/or nonre-

coverable performance degradation be considered as well. Dollar values reflect the difference

from the Plant A baseline. Be aware that electricity sale price or ancillary market opportunities

and payments are not included in this analysis. Source: GE Power

Plant design option LF R

$5/mmBtu fuel price $10/mmBtu fuel price

COE COE

$ $/MWh $ $/MWh

Plant A 79.30% 99% Base $108.90 Base $155.20

Plant B (improved part-load heat rate only) 79.30% 99% $7,000,000 $108.30 $13,000,000 $154.00

78.50% 98% ($8,000,000) $109.60 ($9,000,000) $155.90

Plant B (improved part-load heat rate plus 82.40% 99% $17,000,000 $107.40 $26,000,000 $152.90

10% Scenario B1, 90% Scenario B2 81.50% 98% $2,000,000 $108.80 $4,000,000 $154.80

Notes: COE = cost of generating electricity, LF = load factor, R = reliability.


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

Digital Pressure TransducerThe new Heise DXD digital pressure transducer

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IFS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 . . . . . . . . . 13 www.youragile55.com

Jeffrey Rader. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 . . . . . . . . . 10 www.jeffreyrader.com

Magnetrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 . . . . . . . . . 17 www.magnetrol.com

Membrana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 . . . . . . . . . 18 www.liqui-cel.com

Mobil Industrial Lubricants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 . . . . . . . . . . 2 www.mobilindustrial.com

Orion Instruments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 . . . . . . . . . 23 www.orioninstruments.com

Paharpur. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 . . . . . . . . . 24 www.paharpur.com

Petro-Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 . . . . . . . . . . 4 www.petrovalve.com

ProEnergy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 . . . . . . . . . . 6 www.proenergyservices.com/vision

Santee Cooper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 . . . . . . . . . . 8 www.santeecooper.com/wpsale

Siemens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 . . . . . . . . . . 9 www.siemens.com/energy/solutionsets

Swagelok. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 . . . . . . . . . 22 www.swagelok.com/customsolutions

Tyco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 3 . . . . . . . . . 26 www.tyco.com

Victory Energy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 . . . . . . . . . . 7 www.VictoryEnergy.com

Westinghouse. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 . . . . . . . . . 16 www.westinghousenuclear.com

CLASSIFIED ADVERTISINGPages 68-70. To place a classified ad, contact

Dianne Hammes, 713-343-1885, [email protected]

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COMMENTARY

U.S. Nuclear Operations in a Post-Fukushima WorldBy Kathryn M. Sutton and Stephen J. Burdick

On March 11, 2011, the magnitude 9.0 Tohoku earth-quake struck northeast Japan and was followed by a large tsunami. Both events damaged the Fukushima

Daiichi nuclear plant. These natural forces appear to have eliminated first the offsite power and then onsite emergency diesel generators. Explosions at the site followed. As a con-sequence of these and other events, the Fukushima plant experienced significant damage to plant systems, structures, and equipment.

Perhaps more than for any other industry, a nuclear acci-dent in any part of the world affects nuclear operations else-where. Such an incident necessarily and inevitably results in industry self-examination, heightened regulatory oversight, and third-party scrutiny.

The full extent of any resulting regulatory changes will not be clear until more is known about the earthquake, the tsunami, and the resulting performance of the Fukushima plant. A few important conclusions, however, already have become clear. First, the existing U.S. nuclear regulatory re-gime is robust and already addresses the contributors to the Fukushima event. Second, the U.S. nuclear industry will learn from the event. Finally, U.S. nuclear licensing activi-ties should continue unabated, as the underlying regulatory regime fully accommodates the lessons learned from Fuku-shima and other events.

Current U.S. Nuclear Regulations The U.S. nuclear regulatory regime is robust and dynamic. Though specific regulatory requirements will be evaluated and reexam-ined in great detail in the coming months and years in response to the Fukushima event, they already address key issues raised by that event, including:

■ Reactor siting criteria, such as seismology and hydrology.■ Designs that protect against natural phenomena and accident

scenarios. ■ Ability to withstand a “Station Blackout” event (loss of all AC

power).■ Multiple redundant heat removal means during an accident.■ Separate mitigative strategies intended to maintain or restore

core cooling, containment, and spent fuel pool cooling capa-bilities in the event of loss of normal cooling systems.

■ Emergency planning.

Lessons Will Be Learned and AppliedA key strength of the U.S. nuclear industry is its commitment to learning from operating experience and applying those lessons in a methodical and analytical fashion. This hap-pened following the Three Mile Island and Chernobyl nuclear

accidents and is happening now. In this regard, the response by the nuclear industry and its safety regulator, the U.S. Nu-clear Regulatory Commission (NRC), to the Fukushima event has been swift, systematic, and thorough.

The NRC almost immediately issued a “Temporary Instruc-tion” to its staff and industry to assess the adequacy of actions that will be taken in response to events similar to those experienced at Fukushima. This NRC action parallels the nuclear industry’s independent efforts to assess plant ca-pabilities to manage natural events and total loss of off-site power, mitigate flooding, and inspect important equipment needed to respond successfully to extreme events such as fires and floods.

In addition, the NRC is independently evaluating the Fu-kushima event to determine whether any changes need to be made to its regulations to provide further protection of public health and safety. Specifically, the NRC established a senior level agency task force to review the existing regula-tory regime to determine whether the NRC should make ad-ditional improvements. This task force will brief the NRC at 30, 60, and 90 days on near-term efforts and will continue its long-term review.

Nuclear Licensing Activities Should ContinueNuclear reactors in the U.S. are safe to operate now and in the future. This is due to strict regulation; oversight by an expert regulatory agency; a transparent, public licensing process; and a commitment to learning from events around the world and adapting accordingly. For this reason, nuclear licensing activities in the U.S. should continue, including the renewal of existing operating licenses and issuance of new reactor licenses.

The lessons of the Fukushima event will apply to nuclear plants in the U.S. whether they hold original, renewed, or new operating licenses. This was true of the NRC’s response to past significant events, such as the Three Mile Island nuclear accident and the September 11 attacks. Those precedents provide an ef-fective model to be followed in the coming months and years. Ongoing licensing processes should not be suspended or delayed, as the underlying regulatory paradigm fully accommodates the incorporation and verification of new lessons learned.

The U.S. nuclear regulatory regime will undergo intense scru-tiny in response to the Fukushima event. Although the exact nature of any regulatory changes is unknown, it is certain that any such changes will further improve an already robust and safe U.S. nuclear industry.■—Kathryn M. Sutton ([email protected]) is the head of

the Energy Practice Group and Stephen J. Burdick ([email protected]) is an attorney in the Energy Practice Group at

Morgan, Lewis & Bockius LLP (www.morganlewis.com).

[email protected]

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Power - June 2011

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