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March 2015 • Vol. 159 • No. 3 Vol. 159 No. 3 March 2015 New Ways to Manage Water & Wastewater Going Natural with Boiler Room Ventilation CCGT Steam Cycle Low-Load Ops Issues Flex-Gen Early Performance Results Geothermal New Zealand

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Page 1: Power magazine march 2015   international

March

2015 • Vo

l. 159 • No

. 3

Vol. 159 • No. 3 • March 2015

New Ways to Manage Water & Wastewater

Going Natural with Boiler Room Ventilation

CCGT Steam Cycle Low-Load Ops Issues

Flex-Gen Early Performance Results

Geothermal New Zealand

Page 2: Power magazine march 2015   international

powerTHE

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Page 3: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 1

ON THE COVERNational Oilwell Varco, in partnership with Oasys, offers forward osmosis systems for use in the oil and gas industry for treating exploration and production wastewaters. Forward osmosis, especially as a companion to reverse osmosis, is beginning to see use in the power industry as well. Courtesy: Oasys Water

COVER STORY: WATER & WASTEWATER22 Water and Wastewater Treatment Technology Update

You’ve heard of reverse osmosis (RO), but now it’s being joined by a new treat-ment known as forward osmosis (FO). In addition to RO, FO, and membrane bioreac-tors, advances in membranes and zero-liquid discharge offer new options to power plants.

28 Feedwater Chemistry Meets Stainless Steel, Copper, and IronWhether you operate an older plant with a mix of piping metals or a newer one with the latest alloys, this article covers the chemistry options that operators have to minimize corrosion in a critical area of the plant.

34 Mining for Lithium in Geothermal Brine: Promising but PriceyBrine, the wastewater stream from geothermal power production, is highly corro-sive and hard on piping systems. Recently, a U.S. company developed a method that both recovers valuable minerals from that brine and makes the remaining fluid much less problematic for reinjection. Trouble is, an inability to fund the enterprise may spell the company’s demise.

SPECIAL REPORT: AUXILIARY SYSTEM EFFICIENCY & RELIABILITY36 Save Power with Natural Cooling for Building Ventilation

Coal-fired power plants release a large amount of heat during the combustion pro-cess. Switching from forced to natural ventilation in the boiler building can yield potential energy savings.

38 SCR Reheat Burners Keep NOx in Spec at Low LoadsOptimal NOx removal by a selective catalytic reduction (SCR) system requires the inlet gas temperature to remain within a prescribed range. How does a baseload unit meet NOx permit limits when it’s cycled and SCR inlet gas temperatures dip?

FEATURES

COMBINED CYCLE GAS TURBINES

42 Protecting Steam Cycle Components During Low-Load Operation of Combined Cycle Gas Turbine Plants Know the tradeoffs when operating combined cycle plants at low loads. The solution to one problem may trigger another problem or cause actual damage to your plant.

46 Are Flexible Generation Plants Performing as Expected?Designed from the start for cycling and fast starts, the new “flex” generation com-bined cycle plants promised to avoid the trauma inflicted upon earlier gas plants by more aggressive operational modes. One of the earliest plants to adopt the technol-ogy reports positive results.

er

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Established 1882 • Vol. 159 • No. 3 March 2015

22

34

36

Page 4: Power magazine march 2015   international

www.powermag.com POWER | March 20152

RENEWABLES

48 New Zealand’s Geothermal Industry Is Poised for the FutureGeothermal generation in New Zealand increased more than 20% per year from 2010 to 2014, and a current total capacity over 1,000 MWe typically contributes about 16% to the country’s supply. However, with flat load growth, developers are looking abroad for new opportunities.

FUELS

52 Nuclear Industry Pursues New Fuel Designs and TechnologiesNew fuel rod cladding technologies and fuel assembly options are being developed to make nuclear fuel safer.

DEPARTMENTS SPEAKING OF POWER6 Speaking of Cuba, Change, and Coincidence

GLOBAL MONITOR8 Cambodia’s Largest Hydropower Plant Begins Operation8 U.S., Netherlands Harness Waste Gases for Distributed Generation9 Entergy’s Ninemile 6 Plant Completes Construction11 Google Backs Norwegian-Developed Solar Plant in Utah11 DOE Wind Forecasting Grant Goes to Finnish Firm12 Power Shortages Challenge Eskom, Force Load Shedding in South Africa14 A Handheld Fuel Cell Generator15 Manufacturing Supercapacitors from Atmospheric Carbon Dioxide16 POWER Digest

FOCUS ON O&M 18 Advanced Bearing Technology Eliminates Subsynchronous Steam Turbine

Vibrations LEGAL & REGULATORY20 Cape Wind Finally Blows Out

By Thomas W. Overton, JD

COMMENTARY60 FERC’s Work on the Clean Power Plan

By Cheryl LaFleur, Chairman, Federal Energy Regulatory Commission

Use the search bar at powermag.com to find these stories. (While you’re on our homepage,

subscribe to the weekly POWERnews eletter so you don’t miss the latest developments.)

Mississippi Supreme Court Strikes Down Kemper County IGCC Rate IncreaseARPA-E Summit Takes the Pulse of Energy Technology InnovationNew Zealand Strives to Maximize the Value of Geothermal WastewaterEven More Delays and Cost Overruns for Vogtle ExpansionMIT Study: Carbon Sequestration May Not Work as AdvertisedU.S. Electric Utility Toxic Releases Decrease 49% During the Past DecadeEuropean Power Markets Force Changes at RWE, E.ON, and VattenfallDesert Sunlight PV Plant Comes OnlineJapan Mulling $800 Million Stimulus for Battery Storage and EfficiencyAEP Looks to Sell Merchant Coal Fleet

Online-Only Stories You Might Have Missed

48

9

Connect with POWERIf you like POWER magazine, follow us on-

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Become our fan at facebook.com/

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Page 5: Power magazine march 2015   international

Answers for energy.

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these new energy sources come concerns of stability

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www.powermag.com POWER | March 20154

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matrixnac.comCIRCLE 3 ON READER SERVICE CARD

Page 8: Power magazine march 2015   international

www.powermag.com POWER | March 20156

SPEAKING OF POWER

Speaking of Cuba, Change, and Coincidence

Sometimes, circumstances have a way of developing in such an unexpect-edly serendipitous way that they

practically force one to take notice. So it is with Cuba and its power sector.

CoincidenceIt all started with a letter to the POWER editorial team from Cuba that I received in mid-December. It had been written in October and was forwarded by our corpo-rate office. The very next week, on Dec. 17, President Obama announced the administra-tion’s changes in policy toward Cuba. After sharing news of the letter with Contribut-ing Editor Ken Maize, I learned that he was headed to Cuba in January for a cultural ex-change trip. (See “Cuban Revolucion Ener-getica?” at powermag.com/blog.) Then, in mid-January, I received another letter from Cuba—this time via email. (Both the letter and the email were from the same person, to whom I have replied.)

Several things made these develop-ments interesting. First, the stamp on the letter bore a picture of a lizard not unlike those in my backyard. It was also the first letter to the editor I’ve seen in hard copy. Usually, if we get something via the mail service, it’s marketing materials or an un-solicited article. (Note that both hit the recycle bin because we’re a totally digital organization.) As for the messages, both were very complimentary about a wide range of work written and published by POWER and its editors. Usually, when we get comments about content, it’s either strongly for or against a single article and is typically fueled by the writer’s political or economic views. But this author noted that his team of professionals “discuss al-most all the articles.”

I appreciated the messages from Cuba because it’s gratifying to know that one’s work is useful, but I also learned some-thing about Cuba’s power sector and the dedicated people working in it, and that prompted me to research further.

Cuba’s Energy RevolutionMost readers are familiar with Germa-ny’s Energiewende, or energy transition; fewer are aware that Cuba instituted a

plan in 2005 that goes further, in some areas, according to German consultant and author Dieter Seifried. One example: A complete switch from incandescent to compact fluorescent lamps was made in Cuba five years earlier than in Germany and the rest of the European Union. This revolution entails efficiency measures, adding distributed generation (DG), im-proving transmission and distribution (T&D), developing renewable energy as well as domestic fossil fuel resources, and increasing both international coop-eration and public awareness of energy issues. There’s still a long way to go with this revolution, as Ken’s post notes.

According to the International Ener-gy Association, in 2012 the majority of Cuba’s 18,432 GWh for its roughly 11.3 million citizens was generated by oil (15,652 GWh), with gas supplying 2,082 GWh. As for renewables, biofuels supplied 555 GWh, hydro 111 GWh, wind 17 GWh, and solar photovoltaics 5 GWh. The U.S. Energy Information Administration (EIA) estimates that 2012 installed capacity was 6.24 GW. The EIA notes that, “In an effort to diversify its energy portfolio, Cuba has set a goal of producing 24% of its electricity from renewable sources by 2030. To meet this goal, Unión Eléctrica, the state-owned power company, is plan-ning 13 wind projects with a total capac-ity of 633 MW. In addition, Cuba plans to add 755 MW of biomass-fired capacity, 700 MW of solar capacity, and 56 MW of hydroelectric power.”

Multiple sources note that the island na-tion has a high proportion of mostly die-sel-fueled distributed generation. The DG emphasis makes sense for a largely rural, sparsely populated, elongated island nation that covers a relatively large area. Cuba is the largest Caribbean island—slightly smaller than the state of Pennsylvania.

The sudden loss of economic support resulting from the collapse of the Soviet Union was another driver of DG, accord-ing to a 2008 article by Mario Alberto Ar-rastía Avila, energy specialist at Cuba’s Centre of Information Management and Energy Development. Oil consumption fell 20% in two years, Avila notes, affecting

all sectors and making 16-hour blackouts common. Hurricanes in 2004 and 2005 made matters worse, particularly for the T&D system. Emergency generators, most capable of burning diesel or fuel oil, were the fastest way to restore service in many areas and to ensure less-widespread loss of power in the event of future hurri-canes. DG accounted for as much as 40% of total generation by 2009, according to one source.

Change and Common InterestsMore recently, renewable DG is being pur-sued. The email I received mentioned a new five-year program to develop solar and wind projects. Today, the writer said, almost all rural schools are equipped with solar panels to power everything from TVs and computers to lamps, water pumps, and air conditioners; this DG model is be-ing expanded to other sectors. Though the country still relies on fossil fuels for the vast majority of generation, it is bet-ting, he said, on a future “that will rely on diversity and efficiency.” And although he and his group are in the business of providing technical services to existing fossil plants, they are fully supportive of renewables.POWER covers the global power indus-

try, even though the majority of our audi-ence is in North America, because power is of global concern. That is more true today than ever before, as all nations look for ways to develop and use energy affordably but in more environmentally benign ways. Here’s hoping we all can continue to learn from each other, even when the politicians and leaders of our many different coun-tries disagree. ■—Gail Reitenbach, PhD is POWER’s editor.

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Page 9: Power magazine march 2015   international

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Page 10: Power magazine march 2015   international

www.powermag.com POWER | March 20158

Cambodia’s Largest Hydropower Plant Begins OperationThe 338-MW Russey Chrum Krom hydro-power plant in southwestern Koh Kong province, Cambodia, was inaugurated on Jan. 12. The Chinese-built project is the largest hydropower station located in the Southeast Asian country of more that 15 million people.

The dam was constructed by China Hua-dian Corp. at a cost of about $500 million under a 35-year build-operate-transfer contract with the Cambodian government. The first five years of the contract were designed to accommodate construction, which officially began on Apr. 1, 2010. It is the largest investment China Huadian has made in Cambodia.

The hydropower facility comprises an upper and a lower station. The upper-station dam was completed on Dec. 28, 2010. The lower portion was completed in June 2013 and began to impound water on Dec. 13, 2013. The upper dam’s genera-tion capacity is 206 MW, while the lower dam contributes 132 MW to the total.

Cambodia is in desperate need of reli-able power. According to The World Bank, electricity cost and access is a key con-straint to further growth of the country’s manufacturing sector. Even so, Cambodia’s average annual growth rate was 7.7% dur-ing the past two decades, making it the sixth-fastest growing country in the world during the period.

The Cambodian Ministry of Industry, Mining, and Energy (MIME), forecasts power demand will more than double by 2020. While that sounds daunting, with a current nationwide capacity of only 1,072 MW, adding a plant the size of Russey

Chrum Krom goes a long way toward meet-ing new demand requirements.

MIME’s electricity supply development plan depends upon the construction of four more hydropower projects (totaling 1,326 MW) and three coal-fired power plants (totaling 1,235 MW) to accommo-date growth to 2020 and beyond. While some estimates have pegged Cambodia’s theoretical hydropower potential to be greater than 10,000 MW, prior to 2002 vir-tually none of it had been developed.

Since 2002, five hydropower stations have been added, and a sixth is expect-ed to come online soon. The operational sites are: Kirirom 1 (12 MW), Kirirom 3 (18 MW), Stung Atai (120 MW), Kamchay (194.1 MW), and Russey Chrum Krom (338 MW). The 246-MW Stung Tatai station is said to be complete and will be put into service later this year.

In addition to generation from the hy-dropower plants, Cambodia imports power from Vietnam (170 MW) and Thailand (120 MW). It also gets power from two 50-MW coal-fired units at the Sihanoukville proj-ect, which came online in January 2014.

But just adding capacity is not enough. Cambodia currently lacks the transmission and distribution infrastructure to get the electricity where it needs to go. Although the Russey Chrum Krom hydropower plant is technically a 338-MW facility, The Cam-bodia Daily reports that its current output is only about 5% due to its inability to transmit the power outside of the provin-cial town.

In time, Cambodian Prime Minister Hun Sen—who was on hand for the in-auguration ceremony (Figure 1)—says the transmission network will be in place to distribute the dam’s power nationally, but that could take years.

—Aaron Larson

U.S., Netherlands Harness Waste Gases for Distributed GenerationMethane emissions are garnering increas-ing attention because of their potential impact on the climate. Though far less methane is released to the atmosphere than carbon dioxide, methane has 20 to 25 times the potential warming effect. That’s spurred regulatory attention, highlighted by the January announcement from the Obama administration that it would roll out a series of initiatives designed to sub-

stantially cut methane emissions from the oil and gas industry.

But methane emissions are a problem beyond oil and gas production, as the gas is generated by a wide variety of industrial and agricultural processes. Because these emissions are typically impure, mixed with other gases such as oxygen and carbon dioxide, their low Btu value can make cap-turing and using them uneconomic. Even where there are economic incentives, such as in associated gas production from oil wells, the lack of gathering infrastructure can lead to the waste gases being flared or simply released to the atmosphere.

A variety of approaches are available to convert such waste gases to power, but they can come with additional challenges, such as generating harmful emissions of their own. In addition, they do not work with all types of waste gas.

Irvine, Calif.–based company Ener-Core believes it has a technology to harness these waste gases for power generation while producing far lower emissions. Rather than combusting the gases in a turbine or reciprocating engine, the company’s FP250 Powerstation employs an oxidizer that pro-duces useful heat energy but does it at low enough temperatures to avoid producing harmful pollutants such as NOx (Figure 2). The output from the oxidizer is then fed into a 250-kW gas turbine generator.

The use of oxidizer technology allows the FP250 to accept a much wider range of fuel qualities, including very low–Btu

1. Cambodian Prime Minister Hun Sen cuts the ribbon. The Russey Chrum

Krom inauguration ceremony included several

dignitaries and company executives. Cour-

tesy: Samdech Hun Sen, Cambodian Prime

Minister

2. Waste to power. Ener-Core’s FP250

system is capable of generating 250 kW from

very low–Btu waste gases that might other-

wise be flared or vented. This system is in-

stalled at the Fort Benning U.S. Army base in

Georgia. Courtesy: Ener-Core

Page 11: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 9

waste gases that are unusable with other methods. The system can be configured to produce virtually undetectable levels of NOx, CO, and volatile organic compounds.

The first FP250 system was installed as a demonstration project at a landfill at the Fort Benning, Georgia, Army base. That one-year trial was funded by the De-partment of Defense. The first commercial FP250 system went online at a landfill in the Netherlands this past June.

Ener-Core also recently completed a li-cense deal with Dresser-Rand to deploy the technology at an ethanol plant in Califor-nia. That two-unit facility, using a larger version that integrates Ener-Core’s oxidizer system with Dresser-Rand’s KG2 turbine, will produce 3.25 MW for Pacific Ethanol’s refinery in Stockton and will include a heat-recovery steam generator. Generating its own power from previously flared waste gases is expected to save the plant about three to four million dollars a year. The $12 million project is projected to come online in the second quarter of 2016.

According to spokesman Colin Mahoney, Ener-Core is looking to enter into license agreements with other turbine manufac-turers with larger size turbines, as well as

with manufacturers of steam-generating technologies that would enable its tech-nology to generate industrial-grade steam from waste gases.

—Thomas W. Overton, JD

Entergy’s Ninemile 6 Plant Completes ConstructionEntergy Louisiana’s two-unit, 560-MW com-bined cycle plant in Westwego, La., just out-side New Orleans, completed construction on Dec. 26, both under budget and several months ahead of its original schedule (Fig-ure 3). It’s the first new plant Entergy Loui-siana has added in nearly 30 years.

The Ninemile Point site has been gen-erating power for New Orleans since 1951, but the original two boiler units have been retired for years. Unit 3 is nearing end-of-life, and the new Unit 6 will help replace the retired capacity. Construction, led by CB&I, began in early 2012.

Unit 6 will operate on natural gas but has the ability to burn fuel oil if neces-sary. This is an important concern given the location, which was hit hard by Hur-ricane Katrina in 2005. In the event natu-ral gas delivery is disrupted, the plant will

be able to switch over seamlessly to fuel oil drawn from on-site tanks. The build-ing pad was also raised 4 feet to protect against possible flooding.

Though budgeted at $721 million, the plant was completed for about $655 mil-lion. Ninemile 6’s output will be shared among Entergy Louisiana (55%), Entergy Gulf States Louisiana (25%), and Entergy New Orleans (20%) via life-of-unit power purchase agreements.

—Thomas W. Overton, JD

CIRCLE 5 ON READER SERVICE CARD

3. Ready to roll. Entergy Louisiana com-

pleted construction on its new Ninemile 6

combined cycle plant months ahead of sched-

ule and about $70 million under budget. The

plant was dedicated in January. Courtesy: En-

tergy Louisiana

Page 12: Power magazine march 2015   international

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Page 13: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 11

Google Backs Norwegian-Developed Solar Plant in UtahThe Utah Red Hills Renewable Energy Park, a 104-MW solar pho-tovoltaic (PV) plant under development by Norwegian firm Scatec Solar at Parowan in southwest Utah, closed financing on Jan. 7 thanks to an investment from Google in the $188 million project. It will be the largest PV plant in Utah when completed.

Google has poured more than $1.5 billion into 18 renewable energy projects around the world with a total capacity of 2.5 GW—among them POWER’s 2014 Plant of the Year, the Ivanpah Solar Electric Generating System in California. Though the com-pany has made a commitment to minimize its carbon footprint and power its enormous, power-hungry data centers with renew-able energy, it is also investing in these projects because of the potential returns. Google will be the tax equity investor in Red Hills, which means it will receive the project’s tax incentives in addition to a portion of the income.

According to Scatec, the site has excellent solar irradiance, in part because it is situated at an elevation of about 8,500 feet (Figure 4). The project will sell its power to PacifiCorp subsidiary Rocky Mountain Power under a 20-year power purchase agree-ment and is expected to come online by the end of 2015.

Despite the state’s impressive potential, Utah has lagged well behind other western states in solar energy deployment, largely because it has only a voluntary renewable energy stan-dard. It currently has about 18 MW of installed solar PV ca-pacity, according to the Solar Energy Industries Association, a small fraction of that operating in neighboring states such as Nevada and Arizona.

—Thomas W. Overton, JD

DOE Wind Forecasting Grant Goes to Finnish FirmThe U.S. Department of Energy (DOE) has awarded a $2.5 mil-lion contract to Finnish environmental and industrial data firm Vaisala to coordinate a study of methods to improve wind en-ergy forecasting in complex landscapes. The Wind Forecasting

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Page 14: Power magazine march 2015   international

www.powermag.com POWER | March 201512

Improvement Project 2 (WFIP2) is a DOE initiative targeted at enhancing the reli-ability of wind forecasting, specifically in challenging areas. The goal is to improve the accuracy of short-term 0- to 15-hour wind power forecasts in mountainous areas across North America and world-wide, and thereby reduce the cost of grid integration and optimize performance through better short-term modeling of wind variability.

Accurate wind forecasting has become a key issue in wind generation, as devel-opers have discovered that existing mod-els do not always reliably predict wind volumes and energy over the long term. This creates uncertainties for financing and development, and can challenge the profitability of seemingly viable projects (see “Reducing Weather-Related Risks in Renewable Generation” in the January 2015 issue).

The WFIP2 project will comprise a comprehensive three-phase study of at-mospheric phenomena in complex ter-rain, with the goal of enhancing the widely used Weather Research and Fore-casting model and the National Oceanic

and Atmospheric Administration’s Rapid Refresh and High Resolution Rapid Re-fresh models. Following a design and planning phase, the project will collect 18 months of data to analyze environ-mental characteristics affecting wind flow patterns, ranging from soil mois-ture and surface temperatures to the topographical features of mountain-valley regions (Figure 5).

The data will then be used to update and improve the physics that underpin current forecasting models. Enhanced model predictions produced during the third phase of the project will then be compared with baseline forecasts pro-duced by existing models to evaluate the success of the initiative.

The project partners include Vaisala; the National Center for Atmospheric Re-search; researchers from the University of Colorado at Boulder, Texas Tech University, and the University of Notre Dame; Lock-heed Martin; wind energy firms Iberdrola Renewables and Eurus Energy; meteorol-ogy consulting firm Sharply Focused; and several western utilities.

—Thomas W. Overton, JD

Power Shortages Challenge Eskom, Force Load Shedding in South AfricaThe South African power system is severely constrained and will remain tight until at least the end of April, according to Eskom. The company generates approximately 95% of the electricity used in South Africa and approximately 45% of the electricity used in all of Africa.

In a media presentation, CEO Tshediso Matona explained that Eskom’s reserve margin is very low and that the company does not currently have enough capacity to meet demand. The situation has neces-sitated planned, controlled, and rotational load shedding to protect the power system from a total countrywide blackout.

The company says it avoided load shed-ding over the past seven years by sub-scribing to a “keeping the lights on at all costs” philosophy. As a consequence, much needed maintenance has been post-poned over the years, resulting in a severe maintenance backlog and an increase in equipment breakdowns.

One measure Eskom uses to track reli-ability is its unplanned capability loss fac-tor (UCLF). An increasing UCLF percentage indicates deteriorating plant health. From 2005 through 2009, the UCLF averaged 4.43%. However, since that time, as more and more maintenance has been deferred, the percentage has risen steadily, reach-ing 14.85% by the end of 2014.

“We have arrived at a point that does not allow us to ignore the health of our plants,” Eskom said. “Our reserve margin is so thin, that every incident creates a major systems issue and could also have safety implications for the plant. The mas-sive usage of diesel helps to bridge the problem somewhat, but can’t help the sys-temic healing and a shortage of capacity for the coming three years appears to be unavoidable.”

This summer has seen increased use of open cycle gas turbines and other reserves

5. For better wind data. The U.S. Department of Energy is funding a study to improve

forecasting models for wind energy in difficult terrain. Part of the initiative will involve deploying

wind-measuring equipment like Vaisala’s Triton wind profiler. The Triton is a self-powered, mobile

SODAR (SOnic Detection And Ranging) unit that uses sound waves to collect high-level wind

speed and direction data. Courtesy: Vaisala

6. Koeberg Power Station is like a beacon in the night. With an average

availability over the last three years of 83.1%,

Koeberg is Eskom’s most reliable power sta-

tion. Courtesy: Pipodesign/Phillipp P. Egli

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Page 15: Power magazine march 2015   international

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Page 16: Power magazine march 2015   international

www.powermag.com POWER | March 201514

to balance supply and demand, but Eskom says, “new generating capacity and other levers are needed in order to ease the pressure on the system.”

The maintenance season in South Africa is usually from September to mid-May—the Southern Hemisphere’s summer—when Eskom typically sees lower demand for electricity. This year, planned out-ages will place additional stress on an already fragile system. Unit 1 at the Koeberg Power Station—the only nuclear

power station in Africa and Eskom’s self-proclaimed best in class operator—is expected to come offline on Feb. 9 for a lengthy refueling outage, which will re-move 900 MW from service (Figure 6).

Eskom completed a return-to-service program in 2014 that included re-commis-sioning three previously mothballed coal-fired stations, including the Camden Power Station, a 2014 POWER Top Plant award winner (see the October issue). More ca-pacity is needed though. In the first half

of 2015, the 100-MW Sere wind farm is expected to enter service along with the first of six 794-MW coal-fired units at the Medupi facility, a greenfield project. Other capacity additions will follow, including the Ingula Pumped Storage Scheme Proj-ect next year and the 6 x 800-MW Kusile Power Station Project beginning in 2017.

For the time being though, load shed-ding will be the norm. Eskom predicts in-sufficient generation capacity and a high probability of load shedding on 62 of the 89 days from Feb. 1 through Apr. 30. It says that there is a medium probability of load shedding on 18 additional days dur-ing the period, leaving only nine days in which generation capacity is expected to be adequate—mostly over weekends.

—Aaron Larson

A Handheld Fuel Cell

Generator

After decades of potential but limited deployment, fuel cells are beginning to carve out a role in grid-scale generation (see “59-MW Fuel Cell Park Opening Her-alds Robust Global Technology Future” in the May 2014 issue). Now, continually falling costs are bringing fuel cell gen-eration all the way down to the consumer level.

In December 2014, Dresden, Germany–based firm eZelleron launched a fund-raising effort on crowd-sourcing website Kickstarter for a personal charging device based on its proprietary microtubular fuel

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7. Portable power. The kraftwerk por-

table charger can recharge a variety of elec-

tronic devices using an internal fuel cell and

liquefied petroleum gas. Courtesy: eZelleron

USB plug

LPG gas

tank

Refill valve

Control electronicsPower electronics

Insulation

Microtubular

metallic fuel cell

Gas control unitMicro blower

Pow

er

ou

t

Gas in

Page 17: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 15

cell technology. Called kraftwerk (German for “power station”), the charger gener-ates power from liquefied petroleum gas (LPG) such as propane or butane using commonly available recharge canisters. Most of the palm sized–, 7-ounce unit is taken up by the LPG fuel tank; the actual fuel cell is smaller than a cigarette (Figure 7).

The Kickstarter project reached its funding goal in a week, and the compa-ny is promising to begin delivery of the units in December 2015. According to the company’s website, the microtubular fuel cells can also be packed into arrays for larger capacity. It offers 250-W modules that can be combined into stacks of up to 80 kW capacity.

—Thomas W. Overton, JD

Manufacturing Supercapacitors from Atmospheric Carbon DioxideResearchers at Oregon State University (OSU) have developed a method to man-ufacture nanoporous graphene for use in supercapacitors from atmospheric carbon

dioxide (CO2). Graphene is a form of car-bon that is essentially a one-atom-thick layer of graphite, in which the carbon at-oms are arranged in a hexagonal lattice. Because of its virtually two-dimensional character, it has a variety of fascinating chemical and physical properties. Gra-phene is 100 times stronger than steel and is an excellent conductor of heat and electricity.

Nanoporous graphene is graphene in which nanopores have been created in

the lattice (Figure 8). It has a very high specific surface area, about 1,900 square meters per gram. This gives it an electri-cal conductivity at least 10 times higher than the activated carbon currently used to make commercial supercapacitors.

However, the method developed at OSU to create nanoporous graphene is faster, less expensive, and has less environmen-tal impact than previous methods such as chemical etching, which often use toxic materials. Rather than etching graphene,

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8. Small pores, big potential. A method for manufacturing nanoporous graphene

holds the potential for creating vastly more powerful supercapacitors. Courtesy: Oregon State

University

300

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Page 18: Power magazine march 2015   international

www.powermag.com POWER | March 201516

the OSU method uses a mixture of mag-nesium and zinc metals that are heated to high temperature in a flow of carbon dioxide. This produces a controlled reac-tion that converts the elements into their metal oxides and nanoporous graphene.

Because of its simplicity and low cost, OSU researchers believe the method has good potential to be scaled up for com-mercial manufacture. Supercapacitors with nanoporous graphene electrodes could potentially have far higher storage capacity than current designs using acti-vated carbon.

—Thomas W. Overton, JD

POWER DigestTIC to Build First U.S. J-series GT Plant. The Industrial Co. (TIC), a wholly owned subsidiary of Kiewit Corp., was recently awarded an engineering, pro-curement, and construction contract to build a gas turbine (GT) power plant for the Grand River Dam Authority (GRDA), Oklahoma’s state-owned electric utility. The 495-MW Grand River Energy Center Unit 3 will feature the first U.S.-installed Mitsubishi Hitachi Power Systems Americas Inc. M501J-series GT. Construc-tion will begin in early 2015 in Chouteau, Okla. The new plant will help GRDA meet new emissions regulations by reducing its dependence on coal-fired power genera-tion. The project is scheduled to become operational in May 2017.

South Africa to Develop Continent’s First CSP Project. The South Africa De-partment of Energy awarded preferred bidder status for a 100-MW concentrating solar power (CSP) project to a consortium led by SolarReserve, a global developer of utility-scale solar power projects, and International Company for Water and Power Projects, the Saudi water and power developer, owner, and operator. The Redstone Solar Thermal Power project is scheduled to achieve financial close lat-er in 2015 and commence operations in early 2018. It will be the first of its kind in Africa and will feature SolarReserve’s molten salt energy storage technology in a tower configuration, providing 12 hours of full-load energy storage. The project also features dry cooling to minimize wa-ter use.

Saudi Arabia Plans First CSP-Combined Cycle Plant. The Green Duba project will integrate 50 MW of parabolic trough concentrated solar power (CSP) in a combined cycle plant with a total ca-pacity of 600 MW. Saudi Electricity Co. selected General Electric to supply the

gas turbine–based plant, to be built in the western Red Sea port of Duba. Project completion is expected by 2018. The tech-nology provider for the CSP component was not named.

Morocco Adds Solar Thermal Ca-pacity. The Moroccan Agency for Solar Energy (MASEN) has selected a consor-tium including SENER to construct the 200-MW Noor 2 and 150-MW Noor 3, which represent phases 2 and 3 of the country’s largest solar complex, located in Ouarzazate, in southern Morocco. SENER will perform the engineering, con-struction, and commissioning of the two solar thermal power plants, which make use of different technologies: Noor 2 will use SENERtrough parabolic troughs (de-signed and patented by SENER), while Noor 3 will use a central tower and an array of heliostats. Noor 4, for which a contract has not yet been awarded, will use photovoltaic technology.

B&W to Design and Manufacture Equipment for Vietnamese Plant. The Babcock & Wilcox Co. (B&W) sub-sidiary Babcock & Wilcox Power Gen-eration Group Inc. has been chosen to design and manufacture a supercritical coal-fired boiler and selective catalytic reduction system for the Duyen Hai 3 Extension power plant in Vietnam. The selection was made by Japanese prime contractor Sumitomo Corp., which will build the 688-MW plant for Power Gen-eration Corporation 1, a subsidiary of Electricity Vietnam. It will be B&W’s sixth steam generator in Vietnam. B&W has received a full notice to proceed, engineering is under way, and the plant is scheduled for commercial operation in mid-2018.

Siemens Delivers Three F-Class Gas Turbines to Peru. Siemens has received an order for three SGT6-5000F dual-fuel gas turbines from Peruvian util-ity EnerSur. The turbines will be used for the Nodo Energético del Sur–Planta No. 2 Región Moquegua project in the port of Ilo, in the Moquegua region of southern Peru. They will power three simple cycle plants with a combined capacity of 600 MW. Commercial operation is scheduled for March 2017.

Construction Begins on UK Biomass Plant. Ground was broken on Jan. 20 for the Snetterton Renewable Energy Plant—a 44.2-MW straw-powered biomass plant—located in Norfolk County, England. Bur-meister & Wain Scandinavian Contractor A/S (BWSC) will oversee the construction process and will own the plant in part-nership with a Danish infrastructure fund

managed by Copenhagen Infrastructure Partners A/S.

The project was originally developed by Iceni Energy Ltd., with renewable energy project developer Eco2 Ltd. later joining forces to take the project forward to fi-nancial close. The plant is expected to be operational by mid-2017. BWSC will be in charge of the operation and maintenance of the plant for a 15-year period and has contracted for supply of straw for the next 12 years.

This is the second biomass power plant the group is constructing in the UK. The other is the Brigg Renewable Energy Plant in Lincolnshire, further north in England.

Novel Wind Power System to Be Tested in Florida. SheerWind—an en-ergy technology company based in Chas-ka, Minn.—will design, manufacture, and commission its unique INVELOX wind pow-er system at Tampa Electric’s Big Bend Power Station in Apollo Beach, Fla. While the system utilizes conventional wind power equipment, the design is completely different. Wind enters an omnidirectional intake area at the top of the structure and is funneled down to a venturi, where it is concentrated and further accelerated. Turbine generators are placed inside to take advantage of the velocity increase and convert the wind to electrical power. A diffuser section on the outlet slows the wind speed prior to exiting the system at the bottom.

One of the advantages of the INVELOX solution is that turbines and rotors are installed at ground level for easier, safer, and cheaper operation and maintenance. The system is capable of operating in a wide range of wind speeds (from 2 mph to over 100 mph) and is said to pose no harm to birds or other animals. Multiple turbines can be installed in series to in-crease output capacity from each tower. A 200-kW system will be installed this year as a pilot project. If the technology is proven to be viable following collection of sufficient data (expected to take from six to eight months), Tampa Electric may consider purchasing a utility-scale 1.8-MW INVELOX system.

Another Massive Coal Plant Planned for India. Hong Kong–based China Light & Power Holdings Ltd. is planning a 2,000-MW coal-based power plant in Gu-jarat, India, at a projected investment of $2 billion. The new plant would join to its existing 600-MW gas-fired power plant in the state and will most likely be fueled by imported coal. ■—Thomas W. Overton, JD; Aaron Larson;

and Gail Reitenbach, PhD

Page 19: Power magazine march 2015   international

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Page 20: Power magazine march 2015   international

www.powermag.com POWER | March 201518

Advanced Bearing Tech-nology Eliminates Subsyn-chronous Steam Turbine Vibrations

A facility’s steam turbine ranks at, or at least near, the top of the list of vital power plant equipment. Without it, the thermal energy in pressurized steam can not be converted to rotary motion, which is required to generate electricity. That is why it is imperative for a plant’s steam turbine to operate flawlessly.

Abnormal vibrations are a good indi-cation that something’s not right. If ig-nored, the problem causing the vibration will frequently worsen, and in a turbine it could result in damage to blades or other internal components. In extreme cases, catastrophic failure of the equipment can occur, endangering personnel and costing millions of dollars to repair.

Commissioning HiccupDoosan Škoda Power understands that ab-normal turbine vibration requires action. The company has more than a century’s ex-perience manufacturing steam turbines and has invested in research and development to be an international leader in the delivery of advanced clean energy technologies.

For one of its power generation custom-ers in Scandinavia, Doosan Škoda Power engineered a 46-MW steam turbine as part of a combined cycle system for generation of electricity as well as heat recovery. Dur-ing the initial commissioning process, the turbine experienced rotor instability that prevented the drive train from operating at full load. High subsynchronous vibra-tions forced a trip in turbine operation at just 27 MW versus the rated 46 MW.

Changes to the bearing clearances and configurations mitigated the vibrations but were not able to eliminate them com-pletely. Doosan Škoda Power decided to contact Bearings Plus, a Waukesha Bear-ings business, for a damper solution.

Assessing and Solving the ProblemBearings Plus performed a system-level rotordynamic assessment of the turbine, which evaluated the rotor, bearings, and seals. The cause of the vibrations was confirmed to be a flexible rotor (caused by the large span between the bearings) combined with steam whirl forces in sec-ondary sealing locations.

The steam turbine’s original five-pad

rocker pivot tilt pad journal (TPJ) bear-ings were designed with asymmetrical oil film stiffness to try to accommodate the rotordynamics of the combined cycle sys-tem. However, the rotor flexibility and de-stabilizing steam whirl forces resulted in a negatively damped system and, conse-quently, strong subsynchronous vibrations at about 30 Hz (Figure 1).

For a solution, Bearings Plus suggested soft-mounting the rotor system on TPJ bear-ings with trademarked ISFD technology. In contrast to the original design, bearings with this integral squeeze film damper tech-nology provide low-stiffness and high-effec-tive damping to maximize the damping ratio and eliminate subsynchronous vibrations.

How It WorksThe ISFD design is manufactured through electrical discharge machining. Integral “S” shape springs connect an outer and inner ring, and a squeeze film damper land extends between each set of springs. Bearing pads are housed in the inner ring (Figure 2). The unique design allows for high-precision control of concentricity, stiffness, and rotor positioning. It pro-duces superior damping effectiveness by separating stiffness from damping.

While a conventional squeeze film damper (SFD) experiences a dynamic stiff-ness from the damper film that is depen-dent on amplitude and frequency, in the ISFD design, the stiffness is defined only by the springs. This allows for good pre-dictability, and precise placement of criti-cal speeds and rotor modes, regardless of vibration amplitudes and frequencies.

Whereas damping in a conventional SFD is generated by squeezing in the damper

film and governed by circumferential film flow, the segmented ISFD design prevents circumferential flow and absorbs energy through the piston/dashpot effect. Flow resistance at the oil supply nozzle and end seals controls ISFD damping.

Both the stiffness and the damping of the ISFD design are optimized for the application through a rigorous rotordynamic analysis. For the steam turbine, because steam whirl was one of the root causes of the subsynchronous vibrations, the analysis of the ISFD solution paid careful attention to modeling destabiliz-ing seal forces and stage forces.

A damped eigenvalue analysis without those forces showed a better stability mar-gin by a factor of 12 with the ISFD design compared to the original bearings. With the destabilizing forces, the ISFD solution main-tained a high stability margin. The combina-tion of low stiffness and optimum damping at

1. Abnormal vibrations identified. The waterfall spectrum shows subsynchronous vibra-

tions at 30 Hz with the original five-pad tilt pad journal bearings. Courtesy: Waukesha Bearings

2. The ISFD design. This four-pad tilt

pad journal bearing utilizes integral squeeze

film damper technology. Courtesy: Wauke-

sha Bearings

Page 21: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 19

the bearing support is the key in transforming bending modes to more rigid body modes and improving the overall stability and damping ratio of the rotor/bearing system.

Proven Results

Field vibration data after installation proved that the solution worked. The sub-synchronous vibration spikes experienced at the initial commissioning were eliminated with the use of the ISFD design (Figure 3). The larger stability margin provided by the

bearings with ISFD technology freed the system from significant subsynchronous vi-brations and enabled full-speed, full-power operation of the turbine.

More than 3,200 bearings with ISFD technology have been supplied over the last 20 years and have established this unique design as a leading solution to vi-bration problems in turbomachinery. ISFD technology is successful in a broad range of turbomachinery due to the flexibility of its design. The technology can be used with

tilt pad bearings, as described above, as well as with Flexure Pivot bearings, fixed profile bearings, and rolling element bear-ings, in sizes from 10 mm up to 400 mm.

ISFD technology has successfully im-proved stability, shifted critical speeds, and reduced amplification factors in steam and gas turbines, integrally geared air and pro-cess compressors, centrifugal compressors, turbo-expanders, radial turbines, supercriti-cal CO2 power turbines, generators, motors, and overhung process equipment. The cost to implement an ISFD bearing-damper solution is nominal compared to the ongoing, poten-tially significant costs that can result from vibration problems’ effects across a machine.

In many applications, the minimal space requirements of the ISFD design allow bearings with ISFD technology to serve as drop-in replacements to existing bear-ings. Most importantly, the ISFD bearing-damper solution can be engineered to a specific support stiffness and damping for each application’s operating conditions to maximize the ratio of energy transmitted to the bearing locations, thus significantly improving the stability of the system. ■—Jong Kim is senior principal engineer of

Waukesha Bearings.

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Kalenborn Abresist5541 North State Road 13, Urbana, IN 46990

E-mail: [email protected]

www.abresist.com

I made my �rst sales call in June, 1973 for Abresist

products. I tell my sales sta�, “Follow the customer’s

material through their plant to where it leaves or changes

and isn’t abrasive anymore. Their processes are very

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Joe Accetta (top) —

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CIRCLE 11 ON READER SERVICE CARD

3. Problem solved. The waterfall spectrum shows the subsynchronous vibrations were

eliminated using the ISFD design. Courtesy: Waukesha Bearings

Page 22: Power magazine march 2015   international

www.powermag.com POWER | March 201520

Cape Wind Finally Blows OutThomas W. Overton, JD

If ever there were a case of winning all the battles and losing the war, it would be the saga of the long-delayed-and-now-probably-dead Cape Wind offshore wind project in

Massachusetts.As I wrote last year (see “When States Try to Manipulate

Wholesale Power Markets” in the March 2014 issue), this project that hoped to be the nation’s first offshore wind farm has been fighting headwinds since it was first proposed more than a de-cade ago. The fundamental problem has always been the price tag. Even with the help of subsidies and loan guarantees, Cape Wind was going to be so expensive that its developers could not offer its power into the ISO-New England power market at competitive prices.

The issue is not, as some supporters have claimed, an opposi-tion to wind power amongst the region’s utilities. They’re already buying quite a lot of it under various state renewable portfolio standards, including Massachusetts’ Green Communities Act. The problem is that land-based wind power is substantially cheaper than anything Cape Wind could offer.

When National Grid and NStar were bullied into signing pow-er purchase agreements (PPAs) with Cape Wind (for 50% and 27.5% of its power, respectively) by the Massachusetts state government, they were forced to pay an initial rate of 18.7 cents/kWh—more than twice what they were paying for land-based wind—with a 3.5% increase every year. That made a lot of people unhappy.

Escape ClauseBut those PPAs had an out. Cape Wind’s developers had to either close financing and begin construction by the end of 2014 or post a $645,000 security deposit to extend the deadline by six months (or $1.29 million for another year). Cape Wind still needs to raise a lot more money (and sell the remaining 22.5% of its output), but having PPAs in place is pretty much a prerequisite for a project like this to proceed. With the total cost projected to be around $2.5 billion, one would have thought committing $645,000 to save the PPAs would be a no-brainer. For whatever reason—the developers may not have had the money to do it—Cape Wind chose to forgo the deposit.

Instead, Cape Wind invoked what is known as a force majeure clause in the PPA. Force majeure—French for “superior force”—is the name given to a common provision in most contracts that can free the parties from performing their obligations when an extraordinary event beyond their control makes performance im-possible. Though the term had a traditional meaning, U.S. courts nowadays strictly construe these clauses as drafted in the con-tract. For an event to trigger force majeure, it has to fit within the terms of the agreement.

On Dec. 31, Cape Wind chief Jim Gordon wrote to NStar and National Grid, as well as Massachusetts regulators, asserting that

the repeated litigation against Cape Wind excused it from its obligations to close financing by that date.

In one respect, Gordon had a point. Opponents of Cape Wind have filed a rather impressive 26 lawsuits against the project, including the one I wrote about last March. Every single one of them failed, with the most recent one having been dismissed in May. The groups behind them, starting with billionaire and bête noire of the left Bill Koch, have been frank about their aim to delay Cape Wind as long as they could.

Out the DoorThe utilities’ feelings about the PPAs can probably be judged by the alacrity with which they abandoned them the moment they had the opportunity. On Jan. 6, the second business day after the deadline had passed, both NStar and National Grid announced that they were jumping ship. Overnight, Cape Wind went from having sold 77.5% of its power to 0%. Northeast Utilities (which merged with NStar in 2012) CEO Tom May later told The Boston Globe he was waiting for the first possible moment to get out.

Cape Wind has since responded that the joint move is invalid, because its failure to begin construction was excused by force majeure. Unfortunately for Cape Wind, that’s a dispute that won’t be resolved without more litigation. The force majeure clause in the PPA is too long to quote here, but it does require that the triggering event be both “unusual” and “unexpected,” and that it not be anything that “merely increases the costs or causes an economic hardship to a Party.”

With the Koch-funded litigation over the project having be-come a fixture in the process well before the PPAs took effect, it may be tough for Cape Wind to convince a court that there was anything unusual or unexpected about it at the time the agreement was signed. Meanwhile, its chances of closing financ-ing, let alone beginning construction, without a PPA in place are basically nil. (As I write this in late January, Cape Wind has been suspended from participation in the ISO-New England power market, and its developers just abandoned two leases they had entered to support construction.)

If there’s a lesson to be drawn here, it’s probably that there is a limit to how far governments can go to force energy projects through when the market is resisting them. Had Cape Wind made more finan-cial sense, it’s likely that the customers for its power wouldn’t have bolted for the exits the moment the doors were unlocked. ■

—Thomas W. Overton, JD is a POWER associate editor.

Its chances of closing financing . . . without a PPA in place are basically nil.

Page 23: Power magazine march 2015   international

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Page 24: Power magazine march 2015   international

www.powermag.com POWER | March 201522

WATER & WASTEWATER

Water and Wastewater Treatment Technology Update

Water is the lifeblood of a thermal

power plant. As such, obtaining

clean and pure makeup water and

dealing with wastewater has been a require-

ment since the first steam generating unit

went into operation. As rules and regulations

change, new technology is often necessary to

meet more restrictive guidelines. The desire

for energy savings, more reliable treatment

methods, and solutions to water availability

challenges can also lead to innovations.

Reverse osmosis (RO) is a widely used

technology in the power industry. Devel-

oped in the 1950s, the first commercial RO

plant began operating in 1965. The process

uses a semipermeable membrane to purify

water by applying pressure to overcome os-

motic pressure, forcing water from a region

of high-solute concentration through the

membrane to a region of low-solute concen-

tration. A newer membrane technology that

may not be as familiar to readers is forward

osmosis (FO).

Fast Forward to Forward OsmosisThe first FO water treatment plant was built

in 1998 for use on landfill leachate; today,

research and development continues to refine

the process. While not as common as RO, FO

systems are proving to offer a new solution for

some challenging situations. Boston-based Oa-

sys Water recently installed a system to treat a

Chinese coal-fired power plant’s flue gas des-

ulfurization (FGD) wastewater (Figure 1).

Lisa Marchewka, vice president of strategy

and marketing for Oasys, explains, “We use

membrane technology, but instead of using hy-

draulic pressure to force water through a mem-

brane, we instead use a high-molarity ‘draw’

solution that pulls freshwater across the mem-

brane rather than pushing it on the surface.”

The key ingredient in the system is the

draw solution. Oasys uses ammonium bi-

carbonate, which is an off-the-shelf product

available in bulk. Although ammonium bi-

carbonate is not completely harmless, it is

a relatively safe product that was once used

in homes before modern day baking powder

became available. In fact, Oasys obtains its

product from the well-known baking soda

company Arm & Hammer.

Feedwater enters the FO system at one

end of the membrane module (Figure 2). The

draw solution flows on the opposite side of the

membrane, counter to the direction of feedwa-

ter flow, and pulls water molecules through the

membrane. The draw solution becomes more

and more diluted until it exits the module and

is directed to the thermal process.

In the thermal recovery device, the diluted

draw solution is heated to evaporate only the

draw solutes, leaving behind the clean, puri-

fied water. Because evaporation of the water

The handling of power plant water and wastewater is becoming increasingly com-plex. Fortunately, innovative treatment technologies can help. Recent advances in-clude forward osmosis, membrane bioreactor wastewater treatment systems, and reverse osmosis membrane improvements.

Aaron Larson

Courtesy: U.S. Water

Page 25: Power magazine march 2015   international

WATER & WASTEWATER

March 2015 | POWER www.powermag.com 23

is not required in the thermal column (Fig-

ure 3), less energy is consumed than would

otherwise be necessary. Another advantage

of this arrangement is that no impurities en-

ter the thermal process, therefore scaling and

foaming are not a problem.

By design, the closed loop system should

not require additional ammonium bicarbon-

ate to be added. The plant has typical me-

chanical components though, such as tanks,

valves, pumps, and piping, so there is always

the potential for leaks or a component fail-

ing. For that reason, Oasys suggests that ad-

ditional draw solution be kept on hand.

Benefits of FOOasys says its FO system offers some advan-

tages over other more common water treat-

ment options. According to Marchewka, in

RO systems used for seawater desalination,

the typical water recovery rate is only about

50%. In other words, for every two gallons of

seawater taken into a system, one gallon of

purified water is produced and one gallon of

reject water is discharged back to the source.

The FO process can be used to take the reject

from a seawater desalination RO system and

concentrate that to achieve an additional 80%

recovery. Therefore, combining the two sys-

tems can result in an overall recovery of 90%.

RO systems also are limited in the salinity

that they can handle. Once the system reaches

its maximum hydraulic pressure, water can

no longer be pushed through the membrane

to achieve recovery. In contrast, FO technol-

ogies can treat water up to 150,000 ppm of

total dissolved solids—four times the maxi-

mum for conventional RO systems—and con-

centrate it to over 280,000 ppm. So not only

can much higher recovery be achieved using

FO—because it is not limited by an osmotic

gradient—but it also operates at a lower pres-

sure, which offers an energy savings.

Thermal systems, such as multiple effect

distillation, multi-stage flash, or mechanical

vapor recompression, offer another option

for desalination of seawater and brine con-

centrating. Although thermal systems can be

designed to work well in many situations,

they have limitations of their own.

For one thing, thermal systems are capi-

tal intensive to install. The materials used

have to be capable of handling the corrosive

effects of seawater, so they are frequently

constructed of more expensive alloys. The

energy consumed by a thermal system is also

much higher than in FO systems.

In thermal systems, the feedwater must be

heated to its vaporization temperature, which

requires significant energy. The vapor is then

condensed to produce the distillate. In that

process, impurities in the water can cause

scaling or foaming, resulting in a very main-

tenance-intensive operation. As noted previ-

ously, only the draw solution and clean water

enter the thermal recovery column of the FO

system, which eliminates this problem.

Innovative FO UsesAlthough FO and RO may sound like rival sys-

tems designed using similar technology—the

membrane portion of an FO system does look

nearly identical to that of an RO system, at

least on the outside—Oasys views its FO sys-

tem as more of a complement to RO systems

rather than a replacement for them. It suggests

FO systems are better able to compete directly

with thermal evaporation systems.

“The focus of the company, right now,

is more on industrial high-salinity recov-

1. In with the new. Oasys Water’s forward osmosis technology is installed to treat flue

gas desulfurization wastewater at the Changxing Power Plant in China. Courtesy: Oasys Water

3. The draw solution thermal re-covery system. Heat is added in the ther-

mal column to evaporate the draw solution,

leaving behind purified water. Courtesy: Oa-

sys Water

2. No magic involved. This process diagram shows how a forward osmosis system

produces purified water. Source: Oasys Water

Saline water

Concentrated brine

Draw

solution

Salt-rejecting

membraneRecovery

system

Heat

Clean water

Salt

Drawsolutes

Waterdiffusion

Organics, minerals, pollutants

Page 26: Power magazine march 2015   international

WATER & WASTEWATER

www.powermag.com POWER | March 201524

ery projects, specifically in zero-liquid

discharge, or near zero-liquid discharge sys-

tems,” said Marchewka.

In addition to the FGD wastewater treat-

ment system Oasys installed at the Changx-

ing Power Plant, it has another FO system

already operating in China. That system has

the flexibility to be used for seawater de-

salination or for treating cooling tower blow-

down, depending on the plant’s needs.

Through a partnership with National

Oilwell Varco (NOV), Oasys’ technology

is being deployed in the oil and gas in-

dustry too (see this issue’s cover photo).

NOV says the system is suitable for on-

shore unconventional shale plays, and it

markets the solution as a means of treating

exploration and production wastewaters. It

touts that these streams can be converted

to freshwater quality, fully treated for re-

use in new drilling and completion fluids

or for surface discharge in remote areas

where disposal options have traditionally

been limited and expensive.

Oasys says it is the first company to de-

ploy an FO-based brine concentrator. The

company can also imagine using the technol-

ogy for things like brackish desalination and

other municipal applications.

One final advantage that really benefits

operators is the FO system’s ability to handle

variation. Marchewka noted that the company

has learned from its experience in China that

the water chemistry from the FGD process

is quite variable—seasons, load, and various

other operating parameters all factor in. Al-

though changes can be problematic for many

systems, because the FO system operates at

lower pressure and pulls the water across the

membrane with the draw solution, it is much

less prone to fouling and scaling, and it can

handle the challenge.

“It actually gives operators a nice ben-

efit when dealing with fluctuations and

changes in water quality and water chem-

istry,” says Marchewka.

Utilizing Treated Municipal WastewaterPower plants continue to face greater restric-

tions in the usage of water from traditional

sources, such as oceans, lakes, rivers, and

wells. In the U.S., regulations like 316(b) are

forcing facilities to consider alternatives to

business as usual. State-of-the-art technology

has made treated municipal wastewater gen-

erated by publicly owned treatment works

(POTW) an attractive source of cooling water

makeup for many power plants.

A study conducted at the University of

Pittsburgh, evaluating more than 400 existing

coal-fired power plants, revealed that 49.4%

of them could have sufficient cooling water

supplied by POTWs within a 10-mile radius

of their plant. If the radius were expanded to

25 miles, the percentage increased to 75.9%.

It also evaluated 110 proposed power plants

and found that 81% of those facilities could

meet their cooling water supply requirements

from POTWs within 10 miles of their pro-

posed locations. The 25-mile radius satisfied

all but three of the plants.

According to Kaveh Someah, vice presi-

dent of global energy for Ovivo USA, the

use of reclaimed water started decades ago

and is gaining in popularity. There are a

number of treatment technologies that must

be considered based on an individual plant’s

situation, but one of the more advanced

methods includes the use of a membrane

bioreactor (MBR).

An MBR is a wastewater treatment process

utilizing biological treatment alongside filtra-

tion all in one common tank. MBR systems

are considered the best available technology

for wastewater treatment and reuse applica-

tions, because they are reliable, space efficient,

and cost effective. Ovivo—formerly known as

Eimco Water Technologies—worked with a

power plant in Texas to develop a solution that

uses an MBR system to provide makeup water

to the plant’s cooling pond.

The Membrane Bioreactor Treatment ProcessAt the Texas facility, the screen box design

handles course screening, allowing raw

wastewater to be pumped straight into a fine-

screening system to remove particles that

could potentially damage the membranes.

The screened influent enters the equalization

basin, which maintains flow forward up to

the peaking capacity of the membranes.

If sufficient hydraulic pressure is not

available, the plant is designed with an emer-

gency overflow to a basin located adjacent to

the equalization basin. Once plant flow and

level return to normal, any overflow can be

pumped back to the equalization basin for

feed forward.

From the equalization basin, screened and

equalized wastewater is pumped to the anox-

ic basin. The level in the anoxic basin varies,

depending on hydraulic loading conditions.

Control of the MBR plant is based on level in

the anoxic basin.

A programmable logic controller (PLC) re-

ceives a level input and varies the flow rate of

treated water to accommodate influent flow. It

also initiates an intermittent mode to preserve

biology, reduce power consumption during

low plant loading, and protect equipment.

A mixer in the anoxic basin operates con-

tinuously to mix the activated sludge with

incoming wastewater, maintaining a uniform

concentration of mixed liquor suspended sol-

ids. Pumps in the anoxic basin are used for

feeding forward and internal recycling.

4. A state-of-the-art wastewater treatment process. The submerged

membrane bioreactor configuration relies on

course bubble aeration to produce mixing and

limit fouling. Courtesy: Ovivo USA

5. Waste not, want not. The Palo Verde Water Reclamation Facility can treat up to 90

million gallons of secondary effluent from the Phoenix metropolitan area and provides all of the

cooling water for the Palo Verde Nuclear Generating Station. Courtesy: Arizona Public Service

Page 27: Power magazine march 2015   international

The management of thermal and renewable assets requires numerous services to maintain

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Page 28: Power magazine march 2015   international

WATER & WASTEWATER

www.powermag.com POWER | March 201526

Diversion valves on the pump discharge

allow operator-controlled manual wasting of

waste-activated sludge—that is, removing a

portion of it—in order to maintain a proper

mixed liquor suspended solids concentration.

Waste-activated sludge is pumped to a sludge

holding tank that is aerated to prevent sep-

tic conditions. Sludge may be removed via

pump truck, if necessary.

From the anoxic basin, activated sludge is

pumped to the pre-aeration basin. Fine bub-

ble diffusers evenly disperse air, providing a

residual dissolved oxygen concentration to

prevent premature fouling of the membranes

in the MBR basin. The aerated mixed liquor

gravity feeds into the adjacent MBR basin.

Submerged membranes in the MBR (Fig-

ure 4) filter the sludge to produce an extreme-

ly clean effluent referred to as permeate. The

flow rate of permeate is controlled using a

modulating valve to maintain a constant level

in the basin. The membranes foul over time,

so the PLC automatically opens the control

valve to adjust flow until parameters signal

that fouling warrants an in-situ cleaning.

During the cleaning process, the mem-

branes are relaxed by closing the permeate

control valve and scouring the membranes

with the blower. Excess membrane biofilm

is scoured away to recover flux and improve

performance. A maximum relax time is set to

prevent membrane abrasion.

Permeate from the membranes is pumped

to an in-line chlorine tablet feeder for dis-

infection prior to discharge. Disinfected ef-

fluent then flows by gravity to the discharge

point. Sludge is processed through a belt

press for dewatering, and dry solids are re-

moved for disposal. The recovered water is

recycled back into the process for treatment.

The system in Texas is sized to treat

100,000 gallons of wastewater per day, pro-

viding effluent water suitable for makeup to

the plant’s cooling pond. Ovivo has many

other systems using various technologies op-

erating all around the world.

Zero-Liquid Discharge—and BeyondOne of the largest zero-liquid discharge

(ZLD) systems is at the Palo Verde Water

Reclamation Facility in Arizona (Figure 5).

It is a 90 million gallon per day tertiary treat-

ment plant that reclaims treated secondary ef-

fluent from the cities of Phoenix, Scottsdale,

Tempe, Mesa, Glendale, and Tolleson. Ac-

cording to Someah, the Palo Verde Nuclear

Generating Station is a ZLD facility and the

only nuclear power station that uses 100%

reclaimed water for its cooling.

Palo Verde’s process includes a series of

trickling filters to achieve biological de-nitri-

fication. Next, first- and second-stage solid

contact clarifiers remove hardness-causing

minerals and calcium from the water. Final

polishing is accomplished in mixed media

gravity filters, after which the softened water

enters the plant’s cooling water cycle.

“The technology to treat the water has

come a long way and has advanced drasti-

cally over the last decade,” said Someah.

“Today there are cost-effective technologies

offered by Ovivo that will allow the industry

to use the secondary treated water and treat it

further for use for cooling water source and,

with further treatment, for boiler feedwater.”

Membrane InnovationsThe RO process is well understood and has

proven to work satisfactorily in many appli-

cations. Even so, membrane manufacturers

continue to improve upon thin-film com-

posite technology used in their elements.

According to U.S. Water Services Inc. (U.S.

Water), a Minnesota-based integrated water

management solutions provider, a couple of

significant advances have enabled design and

operation improvements in RO systems.

One improvement is in the fouling char-

acteristics of some membranes. Power plants

are frequently being forced to use poorer

quality water as a source for makeup to circu-

lating and demineralized water systems. The

latest fouling-resistant membranes have been

designed to meet the more difficult working

conditions while reducing cleaning frequen-

cy and minimizing pretreatment.

Pressure requirements for low-energy ele-

ments have also been improved. Historically,

low-energy elements have had rejection rates

too low to gain much acceptance in the power

industry. The negative impacts of increased

salt ion passage to downstream components,

such as mixed bed demineralizers or electro-

deionization systems, were too great.

However, newer membrane technology is

lowering pressure requirements while keep-

ing the rejection at, or near, traditional rates

of brackish water membranes. The improve-

ment allows original equipment manufac-

turers, like U.S. Water, to reduce pump and

motor sizes, which saves energy and im-

proves net plant heat rate.

While membrane improvements are help-

ful, the control of microbiological activity is

still extremely important to aide in the long-

term reliability of RO systems. Many fa-

cilities have large water tanks that serve as

process and firewater reserves. Holding times

in these tanks can be very long. As the water

sits relatively stagnant, controlling the micro-

biological growth in these tanks needs to be

considered. When they are left unmanaged,

operators often struggle to maintain control

and will be required to clean RO systems

more frequently.

Challenges can also result from active bio-

logical growth on RO membranes or from the

slimy byproduct shed from biofilms upstream

of the RO. U.S. Water strongly recommends

that plants maintain a free halogen level in

the process water tank and upstream multi-

media (Figure 6) or ultrafiltration systems at

all times to help minimize these issues. ■

—Aaron Larson is a POWER associate

editor.

6. Managing alternatives. Multimedia filters offer an option for removing suspended

solids, iron, and manganese from incoming water, which can improve RO performance. Cour-

tesy: U.S. Water

YOU WILL GENERATE THE POWER THE WORLD NEEDS.Power companies globally count on DW&PS for the reliability, quality and consistency of its separation and process technologies to help meet the ever increasing demands of providing an uninterrupted energy supply, along with the capabilities to help extend the life of their plant operations.

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Page 29: Power magazine march 2015   international

YOU WILL GENERATE THE POWER THE WORLD NEEDS.Power companies globally count on DW&PS for the reliability, quality and consistency of its separation and process technologies to help meet the ever increasing demands of providing an uninterrupted energy supply, along with the capabilities to help extend the life of their plant operations. Make Real Progress.

To find out how Dow can help you meet your increased demand, please visit us at www.MakeRealProgress.com

WATER & PROCESS SOLUTIONS

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Page 30: Power magazine march 2015   international

www.powermag.com POWER | March 201528

WATER & WASTEWATER

Feedwater Chemistry Meets Stainless Steel, Copper, and Iron

Alloys found in the condensate and

feedwater systems of power plants in-

clude carbon steel for piping, pumps,

and in some cases heat exchangers. Many

systems still have some copper-based alloys

from admiralty brass, and copper-nickel (Cu-

Ni) alloys all the way to 400 Series Monel,

primarily as feedwater heater tubes.

The major corrosion mechanisms affect

the carbon steel and copper alloys. These in-

clude flow accelerated corrosion (FAC) and

corrosion fatigue in carbon steel as well as

ammonia-induced stress corrosion cracking,

and ammonia grooving in copper alloys. FAC

can have a variety of appearances (Figures 1

and 2).

Gradually, as aging feedwater heaters are

replaced, plants often choose to go with a

stainless steel alloy such as 304 or 316 for

feedwater tubing. When the last copper feed-

water heater is replaced, a change in feedwa-

ter chemistry is in order.

Stainless Steel Stainless steel is protected by a tight adher-

ent chromium oxide layer that forms on the

surface. Stainless steels alloys are resistant to

essentially all the corrosion mechanisms that

commonly affect copper and carbon steel al-

loys in feedwater.

There is the tendency to think that stainless

steel is the perfect alloy to replace copper-

alloy feedwater heaters. However, stainless

steel has its own Achilles heel: Chlorides can

cause pitting, and chloride and caustic have,

in some cases, led to stress corrosion crack-

ing (SCC).

Typically, these chemicals are not present

in sufficient concentration to cause corrosion

on the tube side of feedwater heaters. How-

ever, there are cases where contamination of

the steam that feeds the shell side of the stain-

less steel–tubed heat exchanger has resulted

in SCC.

Remember, it is not the average concen-

tration of the chloride or caustic that is of

concern. Spikes in contamination can collect

and concentrate in the desuperheating zone

Developing a feedwater chemistry program that will minimize corrosion across a variety of metallurgies doesn’t have to be difficult. This article reviews the require-ments for three common metallurgies in condensate and feedwater piping and the chemistry options that operators have to minimize corrosion in this critical area of the plant.

David Daniels

Courtesy: Plymouth Tube Co.

Page 31: Power magazine march 2015   international

WATER & WASTEWATER

March 2015 | POWER www.powermag.com 29

of the shell side of the feedwater heater and

in crevices. These are the areas that can fail,

even if the steam is pure most of the time.

Where there is a potential for chloride or

caustic contamination of the steam, stainless

steels may not be the best fit or, at a mini-

mum, alloys should be considered that have

a higher resistance to chloride attack, such

as 316 or 904L. In general however, it may

be more productive to work on eliminating

the potential for contamination than to alloy

around the problem.

The most commonly quoted downside to

the replacement of copper-alloy feedwater

heater tubes with stainless steel is the dif-

ference in thermal conductivity. A quick

look at the reference values will show that

a 304 stainless steel has only one-seventh

the thermal conductivity of admiralty brass

and about one-third the conductivity of 90-

10 Cu-Ni alloy. Numerous papers have been

published discussing why these “textbook”

values are unlikely to be experienced in the

real world. This is certainly an important

consideration with condenser tubes, where

the potential for cooling water–side deposits

and condenser cleanliness is likely to have a

much more prominent effect on heat transfer

than the textbook thermal conductivity of the

tube metal. However, feedwater heater tubes

should have little steam- or water-side foul-

ing. Other factors, such as tube thickness

may offset some of the thermal conductivity

loss, and there are other design factors, such

as susceptibility to vibration damage, to con-

sider in selecting a material.

Carbon Steel Carbon steel is passivated by the formation

of a dual layer of magnetite (Fe3O4). The

layer closest to the metal is dense but very

thin, whereas the layer closest to the water is

more porous and less stable. Hydroxide ions

are necessary for the formation of magnetite.

Due to the common utility practice of using

feedwater to control the final temperature

of superheat and reheat steam, the source of

hydroxide in feedwater must be volatile, and

ammonia or an amine is generally used for

this purpose. A solid alkali such as sodium

hydroxide must never be introduced ahead

of where the takeoff to the attemporation is

located.

Ammonia is very volatile, remaining in

gaseous state during initial condensation.

This may occur in the deaerator, condenser,

or on the shell side of a feedwater heater. This

lowers the effective pH of the first condensate

and increases the solubility of the magnetite

layer in that area. This can increase the rate

of FAC in these areas.

For carbon steel, higher pH values are bet-

ter for the production and stability of mag-

netite. Operating with low pH values in the

feedwater and condensate destabilizes mag-

netite and increases the rate of FAC on carbon

steel in the feedwater system. It also increas-

es the iron in the feedwater, which generally

winds up on the waterwall tubes. This iron

deposition increases the risk of under-deposit

corrosion mechanisms, inhibits heat transfer

across the tube, and increases the frequency

of chemical cleaning.

A case can be made for the use of carbon

steel feedwater heater tubes, particularly al-

loys such as T-22, which contains 2.25%

chromium (Cr) and 1% molybdenum (Mo).

It has better thermal conductivity than stain-

less steel, is highly resistant to chloride SCC,

and because it contains 2.25% Cr, is gener-

ally considered immune to FAC.

Copper Alloys Copper alloy corrosion in the power industry

has been studied in depth due to problems

with copper deposits on the high-pressure

(HP) turbine that reduced turbine efficiency

and the maximum load that the unit could

produce.

Zinc-containing brass alloys such as ad-

miralty brass are particularly susceptible to

attack from ammonia vapors. This can result

in ammonia-induced SCC on the steam side

of the condenser or feedwater heater. The

same alloys are susceptible to a mechanism

termed “ammonia grooving,” where steam

and ammonia condense on the tube sheet and

support plates of the feedwater heater and run

over the tubes, creating a narrow group of

corrosion directly adjacent to the tube sheet

or support plate. Copper alloys containing

nickel are far less susceptible to ammonia-

induced SCC.

Admiralty brass alloys have the additional

concern of corrosion of zinc in the alloy due

to low-pH conditions in the feedwater or

steam. Over time, the zinc can leach from

the brass matrix, leaving only the copper

sponge, which has little structural strength.

This mechanism is called dezincification. Al-

though not as common, copper-nickel alloys

can also suffer from dealloying (Figure 3).

There are three separate rates associated

with the rate of corrosion of any copper alloy.

These have been referred to as:

■ Rd—the rate at which corrosion products

leave the surface as a dissolved species

in the water (typically copper ammonium

complexes).

■ Rf—the rate at which corrosion products

(copper oxides in operating steam and

condensate systems) form on the surface

of the metal.

■ Rs—the rate at which copper corrosion

products (typically oxides) leave the sur-

face as suspended particles.

These rates are not necessarily correlated

with each other and may not occur under the

same chemical conditions. Copper oxide for-

mation (Rf) can be protective, minimizing

further corrosion of the alloy—as long as it

remains intact. When chemical conditions

change, such as moving from an oxidizing to

a reducing condition, Rd and Rs may increase

dramatically. Protective copper oxides are

aggressively dissolved by the combination of

ammonia, carbon dioxide, and oxygen. The

most common place for all three of these to

1 Typical. Classic flow-accelerated corrosion

(FAC) orange peel texture with no oxide coating.

Courtesy: M&M Engineering Associates Inc.

2. Atypical. Compare the previous exam-

ple with this one showing an unusual pattern

of FAC in a deaerator. Courtesy: M&M Engi-

neering Associates Inc.

3. Weakened. Dealloying, dezincifica-

tion in brass alloys, or removal of nickel from

copper-nickel alloys will destroy the strength

of the material. Courtesy: M&M Engineering

Associates Inc.

Page 32: Power magazine march 2015   international

WATER & WASTEWATER

www.powermag.com POWER | March 201530

be present is in a copper-tubed condenser that

has air in-leakage issues.

Once these corrosion products are dis-

solved or entrained, they are subject to down-

stream chemical conditions, where a change

in the at-temperature pH or the oxidation re-

duction potential (ORP) in a specific location

can cause the copper to “plate out” as copper

metal on suction strainers, pump impellers,

or on another feedwater heater tube surface

in the form of a pure copper “snakeskin.”

They may also continue on through the feed-

water system and deposit on a boiler or su-

perheater tube or on the HP turbine. Similar

conditions (plating out) can occur in stainless

steel sample lines, making the accurate mea-

surement of copper corrosion products in a

conventional sample line difficult.

Chemical Control of Feedwater Proper alloy selection, either in the initial

construction or as equipment is replaced,

should be carefully considered. Once the

decision is made, the water chemistry pro-

gram must follow to minimize corrosion of

the feedwater equipment and deposits in the

boiler and turbine. The more metals there are

in the mix, the more things need to be con-

sidered in the chemistry program. Copper al-

loys, in particular, force compromises, as the

optimum chemistry requirements for copper

and iron cannot be met simultaneously.

Feedwater pH Control. The pH limits

recommended on all ferrous-alloy condensate

and feedwater piping are now a minimum of

9.2 with an upper limit of 9.8 or even 10.0

in systems with an air-cooled condenser. If

there are no copper alloys in the system, the

biggest downside to having too much ammo-

nia in the system is the frequent replacement

of cation conductivity columns rather than

corrosion in the carbon steel.

For those operating heat-recovery steam

generators (HRSGs), there can be a sig-

nificant drop in pH of the low-pressure (LP)

drum water as ammonia (and some amines)

leaves with the LP steam. It is important that

the LP drum pH be monitored continuously

and controlled certainly within the range of

9.2–9.8. Some suggest a minimum pH of 9.4

for water in the LP drum to protect down-

stream high-pressure and intermediate-pres-

sure economizers.

The current recommended pH range for

systems that have copper in either the main

condenser or feedwater heaters is 9.0–9.3.

(See the sidebar for an explanation of the ne-

cessity of accurate pH measurement.) Labo-

ratory studies have shown that is actually the

minimum range for avoiding copper corro-

sion in the copper alloys used in feedwater

heaters and condensers. Lower feedwater and

condensate pH values (for example, pH 7.0)

have higher copper corrosion rates than pH 9,

particularly under oxidizing conditions.

Ammonia or Amines. The addition of

ammonia to condensate is the simplest and

most direct way to raise the pH of the con-

densate and feedwater into the desired range

to create and stabilize the magnetite layer. In

all-ferrous systems, there should be a clear

case or desired objective for using any other

chemical for pH control. On the other hand,

the use of neutralizing amines in the utility

steam cycle has a long, successful history,

particularly in units that have copper alloys

in the feedwater heaters.

The decision to use neutralizing amine

for iron corrosion should be based primar-

ily on the need to provide more alkalinity (a

higher pH) in an area of concern than can be

achieved simply by increasing the ammonia

levels. This may include areas where steam

is first condensing into water, such as in an

air-cooled condenser, or where water/steam

mixtures are being released, such as in the

deaerator.

Although amines are more common when

copper alloys are found in the feedwater sys-

Measuring pH

Accurate pH measurement in high-purity

water is difficult. The very low specific

conductivity of the water combined with

the potential for ammonia to be lost and

carbon dioxide to be simultaneously ab-

sorbed by the sample while it is being

collected and measured can lead to con-

fusing results. Inaccurate pH monitoring

can result in over- or under-feeding of

ammonia or amines.

Continuous online pH monitoring using

pH probes specifically developed for high-

purity water can improve the accuracy and

reliability of the measurement.

The pH of high-purity waters can also be

calculated from a combination of the spe-

cific conductivity and cation conductivity

results. This can be done manually, or there

are commercially available instruments that

display a calculated and measured pH.

Due to these issues with pH, specific

conductivity is often used to control the

ammonia feed instead of controlling di-

rectly from a pH meter.

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Page 33: Power magazine march 2015   international

WATER & WASTEWATER

March 2015 | POWER www.powermag.com 31

tem or condenser, their presence does not

necessarily require the use of a neutralizing

amine. There are many mixed-metallurgy

units that operate using ammonia and that

carefully control air in-leakage with very low

copper corrosion rates.

The choice of which neutralizing amine to

use (and there are many) should be based on

where and how it is to function. It is critical that

both the basicity (amount of pH rise per ppm of

amine) and volatility of the amine (the ratio of

what goes into the steam versus what remains

in the water) is matched to the application.

The criticism of the general use of amines

in high-pressure utility cycles is centered on

two issues: the degradation of these organic

molecules in the steam cycle (particularly in

the superheater and reheater) and the con-

sequence of these degradation products—

namely, an increase in the cation conductivity

of the condensate and feedwater.

It has been long known that as neutraliz-

ing amines pass through the steam cycle, they

break down into ammonia and organic acid

byproducts such as acetic acid, formic acid,

and carbon dioxide. The percentage of deg-

radation is certainly specific to the particular

amine and concentration in the steam, but it is

also unit specific and depends, at a minimum,

on the size and complexity of the superheater

and reheater piping, where it appears most of

the degradation occurs.

Those who advocate for the sole use of

ammonia instead of amines point to the deg-

radation of these products and see them as

“single-use” chemicals—good for only one

trip around the steam cycle. If all the amine

degrades with one trip through the super-

heater and reheater, it cannot be available to

minimize the corrosion of copper condenser

tubes or affect the pH of a steam/water mix-

ture in the feedwater, and so it would not be

worth the trouble.

However, there are many different fac-

tors that affect amine degradation rates and,

therefore, how beneficial an amine might be

in the system. These include the operating

pressure of the unit, where the copper alloys

are located, and whether the unit even has a

reheater. For example, in the standard triple-

drum HRSG, a significant percentage of the

amine may leave with the LP steam, where it

recycles through the condenser and preheat-

er sections of the HRSG and never sees the

high-temperature areas. This would signifi-

cantly increase its longevity and usefulness.

All these factors need be taken into account

when considering whether an amine would

be beneficial at a particular plant. It would

behoove anyone who is considering trying

an amine to set up to sample and test for the

amine and degradation products around the

cycle and also quantify improvements to iron

and copper corrosion rates. That will help

them determine, for their particular unit, if

the benefits of amine use outweigh the costs.

The degradation products of any amine

will add to the cation conductivity of the

condensate and feedwater. The longevity and

chemical structure of the amine will affect

the cation conductivity “bump” that the plant

will experience. Degassed cation conductiv-

ity can remove carbon dioxide but generally

not all the other organic acids produced by

amines. So if amines are used, the normal

cation conductivity will need to be adjusted

for the presence of these products.

Controlling Oxidation Reduction Potential It can be generalized that the ability of an

alloy to withstand corrosion is a function of

the stability and tenacity of the oxide layer

that forms on the metal surface. As discussed

above, stainless steel has a very tight and

tenacious layer of chromium oxide that pre-

vents corrosion of the metal from oxygen and

from the common pH ranges found in feed-

water.

Establishing and maintaining a good oxide

layer on carbon steel is critical to minimizing

FAC. Copper oxides are also protective—as

long as they remain in place.

Particularly in the case of copper alloys,

the oxide layer can be easily disrupted. Re-

search has shown that one of the most cor-

rosive times for copper alloys is when they

cycle between a reducing and oxidizing

condition. Therefore, it is imperative that

mixed-metallurgy feedwater systems contain

sufficient reducing agent such as hydrazine

or carbohydrazide to maintain a reducing

condition at all times.

A reducing condition is not the same as

the absence of dissolved oxygen. Regard-

less of how well the deaerator is functioning,

if there are copper feedwater heaters in the

system, the continuous addition of a reducing

agent is required to achieve the negative ORP

that is protective of copper alloys.

All volatile reducing agents used in utility

cycles break down at temperatures typically

associated with HP feedwater heaters or the

economizer—and certainly by the time the

water reaches the boiler. Therefore, regard-

less of which reducing agent is added to the

condensate pump discharge, there is no pro-

tection for the copper alloy condenser tubes

against the combined effect of dissolved oxy-

gen, carbon dioxide, and ammonia. This is

why it is so critical to minimize air in-leakage

and control feedwater pH.

Many units have been replacing copper

alloy feedwater heaters with carbon steel or

stainless steel tubes over the years. When the

last copper feedwater heater is replaced, the

reducing agent can almost always be elimi-

nated, regardless of whether the condenser

contains copper alloys or not.

Carbon steel corrosion is inhibited by the

presence of small amounts of dissolved oxy-

gen. Research has shown that as little as 5

ppb to 10 ppb of dissolved oxygen signifi-

cantly reduces the rate of FAC under feed-

water conditions. This occurs because the

dissolved oxygen present in the low-temper-

ature feedwater (from the condenser to the

deaerator) forms iron oxides that fill in the

pores of the outer layer of the magnetite, dra-

matically improving its stability. Even in the

absence of any measurable dissolved oxygen,

after the deaerator, the ORP remains positive

and increases the stability of the magnetite

layer through the HP feedwater heaters and

economizer.

The formation of these more resilient

protective oxides is the basis of oxygenated

treatment, which is successfully used on all

supercritical plants in North America and

many HP drum units. However, simply dis-

continuing the use of a reducing agent should

never be confused with oxygenated treat-

ment, where pure oxygen is purposefully

injected, the deaerator vents are closed, and

the dissolved oxygen levels in the feedwater

are an order of magnitude higher than in a

conventional feedwater system.

Stable feedwater chemistry in the absence

of a reducing agent continues to strengthen

the passive oxide layer throughout the feed-

water piping over time. Therefore, although

dissolved oxygen levels may temporarily

spike during a startup, it is also unnecessary

to add a reducing agent during layup or for

the subsequent startup. ■

—David Daniels is a POWER contribut-ing editor and senior principal scientist at

M&M Engineering Associates Inc.

When the last copper feedwater heater is replaced, the reducing agent can almost always be eliminated, regardless of whether the condenser contains copper alloys or not.

Page 34: Power magazine march 2015   international

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www.powermag.com POWER | March 201534

WATER & WASTEWATER

Mining for Lithium in Geothermal Brine: Promising but Pricey

Worldwide, the U.S. is the largest

producer of geothermal power;

however, geothermal energy pro-

vides less than 0.5% of total generation in

the U.S. Given geothermal’s small piece of

the U.S. electricity pie, it may surprise you to

learn that the nation is leading the way with

breakthrough technology to capitalize on

the economical use of valuable constituents

found in geothermal wastewater.

From Brine to MineWorldwide, geothermal wastewater, the

“produced water” or brine, is either dis-

posed of by release to waterways (which

may cause adverse environmental effects

due to both its constituents and higher

temperature) or return to the geothermal

reservoir via reinjection wells. Use of this

wastewater, when that is an option, falls into

two main categories: using the brine’s en-

ergy value for a variety of heating purposes

and using the brine’s constituent elements.

The former is technically simpler. The latter

is often called a “cascade” use and has been

challenging to commercialize.

In the U.S., federal government funding

for geothermal research increased in 2014

and 2015 after a decline in previous years.

Though the bulk of those funds (well be-

low what is provided for wind and solar) is

directed toward power production, byprod-

uct uses are also considered. They include

support for Surprise Valley Electrification

Corp., a nonprofit Oregon rural cooperative

that has plans for a 3-MW geothermal power

plant that will send its waste heat for use by

aquaculture, greenhouse heating, and district

heating. The Department of Energy (DOE)

Geothermal Technologies Office “Vision

Study” also includes consideration of low-

temperature mineral recovery as an “additive

value” proposition. A previous DOE grant

(among others) went to a company that has

demonstrated such a value-added use of the

geothermal process.

In 2010, Simbol Mining Corp. received

$3 million from the DOE for a $9.6 million

project that was to produce battery chemicals

lithium, manganese, and zinc from Califor-

nia’s Salton Sea geothermal reservoir. The

company, formed in 2008, licensed tech-

nology from Lawrence Livermore National

Laboratory. Simbol said, in a presentation

for the DOE, that its business model “puts

mineral extraction into a separate company,

shielding the geothermal operator from risk

and letting each company focus on its core

competencies.”

Former President and CEO Dr. John Burba

Brine, the waste stream of the geothermal power production cycle, is usually con-sidered a nuisance. High in corrosive minerals, even when reinjected, it’s challeng-ing to manage. So when Simbol Inc. showed it had a way to turn this waste stream into a revenue stream by mining it for high-value minerals like lithium, a lot of people got excited. However, just as this article was going to press, a lot of people got laid off.

Gail Reitenbach, PhD

Courtesy: EnergySource

Page 37: Power magazine march 2015   international

WATER & WASTEWATER

March 2015 | POWER www.powermag.com 35

was previously technology director at FMC

Lithium, where he pioneered selective extrac-

tion of lithium from saturated salt brines. (A

Simbol representative told POWER on Feb. 5

that Burba was no longer with the company.)

By 2013 the Pleasanton, Calif.–based compa-

ny had demonstrated production of a high-pu-

rity lithium hydroxide through the electrolysis

method, produced the world’s first battery-

grade lithium carbonate from a geothermal

brine, and achieved more than 9,000 hours of

demonstration plant operation.

Process DetailsSimbol says its proprietary process “elimi-

nates traditional methods of invasive mining

or evaporation ponds that require significant

land, water, and energy use.” The process is

said to produce “virtually zero waste, while

consuming CO2, waste water, and other emis-

sions from the geothermal power plant.”

Although the company does not provide

details about its process, a January 2013 U.S.

Geological Survey (USGS) report on lithium

says that it involves utilizing “a unique reverse-

osmosis process,” which “eliminates the need

for solar evaporation, a crucial and lengthy

procedure in common brine operations.”

Commercialization of Simbol’s technol-

ogy began with a demonstration facility in

2010 and was followed by the opening of

what it says is the world’s highest purity

lithium carbonate plant in September 2011.

At the beginning of this year, the company

said it was preparing to break ground on its

first commercial lithium plant, which at full

capacity, is expected to produce “enough

lithium for about 1.6 million plug-in hybrid

electric vehicles per year.”

Why It MattersThe materials Simbol is extracting from

geothermal brine are high-value minerals

used in everything from the batteries used to

power electronic devices and electric cars to

military applications. As worldwide demand

grows for these materials, supplies and prices

have become a concern, and more countries

have begun development of their resources.

Worldwide lithium resources, for example,

are approximately 39.5 million tons, with 5.5

million tons of that total in the U.S.

According to the USGS, in 2012, Chile

and Australia both produced the largest vol-

ume of the super-light metal (13,000 metric

tons). From 2008 to 2011, the U.S. imported

96% of its lithium from Argentina and Chile.

As of 2012, the U.S. had only one commer-

cially active lithium mine, in Nevada, and

only 68 people were employed by mine and

mill operations.

The Salton Sea area is believed to be the most

prolific mineral-rich brine source in the world,

which explains why it is an ideal place to com-

mercialize this technology. Other locations may

be more restricted to using other geothermal res-

ervoir minerals and gases, depending on market

needs for those constituents. (See the web ex-

clusive “New Zealand Strives to Maximize the

Value of Geothermal Wastewater,” associated

with this issue online, for a look at how New

Zealand is exploring these opportunities.)

When Tesla Motors opens what will be the

world’s largest battery factory in 2017, in Ne-

vada, it will need lots of battery-grade lithium

from a reliable source. Even though Nevada

is said to have large lithium deposits, the cost

of production is lower in other countries.

The Desert Sun reported on Jan. 15 that

Simbol expects full-scale production to be-

gin in 2018; if the first plant finds success,

the company said it could eventually build

10 more in the valley, which would have a

productive life of 600 years, according to

Tracy Sizemore, the company’s vice presi-

dent of business development. The promise

of a high-demand value-added product could

boost prospects for additional geothermal en-

ergy development in the area.

Simbol believes it can produce these ma-

terials at a competitive price, in part because

its raw materials source is “a secure, scalable,

and sustainable resource base.” The company

expects the Salton Sea “will yield many de-

cades of lithium, manganese, and zinc mate-

rials securing our critical materials future.”

Co-Location AdvantageThe Simbol pilot plant is co-located with

the John L. Featherstone Geothermal Power

Plant shown in the header photo (formerly

known as Hudson Ranch 1) in California’s

Imperial Valley. When the 49-MW plant,

owned and operated by EnergySource, went

into commercial operation in March 2012, it

was the first stand-alone geothermal plant to

go online in the Salton Sea area in 20 years.

Power from Featherstone is sold to Salt River

Project, an Arizona public power and irriga-

tion district.

The Simbol Minerals extraction plant will

use Featherstone’s spent, but still warm brine

as a feedstock, before it is reinjected into the

reservoir. By extracting the corrosive miner-

als that are the bane of geothermal plants ev-

erywhere, before the brine is reinjected into

the reservoir, Simbol would help the power

plant minimize pipe damage. (This article

was written Feb. 1. When I contacted several

Simbol executives over the following week,

they did not respond to POWER’s requests

for information about any leasing, revenue

share, or other financial details of the part-

nership with EnergySource.)

To support the Simbol plant’s expected de-

mand for about 200,000 MWh per year, the

Imperial Irrigation District has said it is con-

sidering plans to build a natural gas–fired plant

next to the lithium plant. The minerals plant is

also expected to use roughly 2,400 acre-feet of

water each year, which would come from the

Colorado River via the All-American Canal.

The New York Times reported last spring

that from 2011 to March 2014, Simbol’s pilot

plant had extracted about 100 metric tons of

lithium from the Featherstone plant’s brine. As

the Times noted, another benefit of colocation

is that geothermal companies have an exemp-

tion from water laws that allows them to pump

their brine back into the ground. That exempts

Simbol from any future potential cleanup or

environmental mitigation costs.

More recently, on Jan. 15, The Desert Sun

reported that construction of the large-scale,

commercial plant is expected to employ “400

people during an 18-month construction peri-

od and between 120 and 150 people once fin-

ished. Many of those high-wage jobs could

go to residents of the Imperial Valley, one of

the state’s most impoverished areas.”

From Boon to BustThen, on Feb. 3, local news sources started

reporting that Simbol had fired the majority

of its employees the previous week. Chief

Financial Officer Pete Sunada told The Des-

ert Sun that the company can produce the

high-quality lithium, as advertised, but that

there wasn’t enough funding to build the full-

scale extraction plant, so it didn’t make sense

to keep so many employees on the payroll.

When I spoke very briefly with Sunada on

Feb. 4, he sounded flustered but did not share

information about the layoffs.

The local paper said Sunada “insisted the

company still plans to build the full-scale

plant” and that executives are “actively in

talks” with a group interested in purchasing

a majority stake. Others, including Ener-

gySource CEO Dave Watston, are more skep-

tical. Watson told the paper that even though

the two companies had settled on terms for

brine use in 2014, he hadn’t heard from Sim-

bol since December.

Nevertheless, EnergySource isn’t writing

off the technology. Watson was quoted as

saying, “We do feel very confident that this

technology will be picked back up at some

point in the not-very-distant future. It really

needs good management, and the focus was

on all the wrong things (at Simbol).”

Developing game-changing technologies,

especially in the energy space, is just the first

step. Taking the much bigger leap of securing

sufficient start-up capital to prove the technolo-

gy’s commercial feasibility has been the down-

fall of many enterprises. Whether Simbol’s

name is added to that list remains to be seen. ■

—Gail Reitenbach, PhD is POWER’s editor.

Page 38: Power magazine march 2015   international

www.powermag.com POWER | March 201536

AUXILIARY SYSTEM EFFICIENCY & RELIABILITY

Save Power with Natural Cooling for Building VentilationTougher environmental regulations are pushing for more energy efficient coal

plants. Every kilowatt counts, and the boiler building ventilation system can free up many of them.

Brandon Bell

With the final Clean Power Plan rule

covering existing power plants

scheduled for release this summer,

and the amount of flexibility that has been

afforded to the states to meet emissions tar-

gets, states have a variety of options that can

be explored to meet this regulation. Plant

upgrades, improving energy efficiency, fuel

switching, and promoting renewable energy

are just a few. With these options in mind,

generators that expect coal-fired units to

remain operational in the long term need to

start evaluating all plant systems for potential

auxiliary power savings.

In all thermal power plants a portion of

the electricity produced is needed to operate

the plant’s auxiliary systems. These consist

of fans, pumps, compressors, and even plant

lighting. With more efficient plant auxiliary

systems, more electrical energy is available

for sale, and the plant operates at a higher ef-

ficiency, with reduced carbon pollution.

One system to consider when evaluating

potential energy savings is the boiler build-

ing ventilation system. In coal-fired power

plants, a large amount of heat is released dur-

ing the combustion process. The intent of this

process is to transfer thermal energy from the

combustion process to a working fluid (water

and steam) to be used for electric power gen-

eration. In order to contain as much thermal

energy in the boiler as possible, thick insula-

tion is installed on the boiler casing to retain

thermal energy in the working fluid.

Unfortunately, insulation is unable to con-

tain all the thermal energy, and some heat

is transferred to the ambient surroundings

inside the boiler building. In addition to the

heat from combustion, many other forms

of heat generation exist within these build-

ings. All the fans, pumps, and compressors

required to operate the plant are driven either

by electric motors or steam turbine drives.

Electric motors convert electrical energy to

mechanical energy. This conversion of ener-

gy is not ideal, and the inefficiencies result in

heat rejection to the environment. Steam tur-

bine drives have the same issue as the boiler,

and insulation is unable to contain all their

thermal energy.

Cool-Down OptionsIf they are not controlled, heat losses from all

sources in the boiler building would increase

internal ambient temperatures to a point where

workers would not be able to enter the build-

ing for safety reasons. To counter the large

amount of heat generated from combustion

and equipment, boiler buildings are equipped

with very large ventilation systems to continu-

ously draw in cooler air from outside and re-

move hot air from within the building.

At the majority of coal-fired boiler build-

ings, a forced ventilation system is used to

remove hot air from the structure and draw

cooler air in. Large fans are installed on the

roof, with intake louvers at the base of the

structure to accomplish the needed ventila-

tion. Because of the large amounts of air be-

ing moved, some boiler building ventilation

systems may require in excess of 450 kW of

operating power for a single boiler.

In addition to using auxiliary power for

operation, forced ventilation systems require

regular maintenance to remain operational.

Routine maintenance tasks include belt re-

placements, motor rewinds, bearing replace-

ments, and fan realignments. Some existing

systems may also contain known hazardous

materials such as asbestos insulation or lead

paint. Over time, the asbestos insulation will

deteriorate and fall off, and lead paint begins

to chip or peel from surfaces. These sub-

stances are hazardous to workers and require

special, costly removal processes.

However, alternatives to forced ventilation

systems exist that both reduce auxiliary load-

ing and the need for continuous maintenance

activities. Natural ventilation systems, some-

times referred to as gravity ventilation sys-

tems, are typically used as replacements for

forced ventilation systems. Their designs are

simple in nature, have very few moving parts,

and require little to no maintenance.

Leveraging the Stack EffectIn a natural ventilation system, large open-

ings in a structure’s roof are used in lieu of

the smaller openings that are common to most

forced ventilation systems. These larger open-

ings promote movement of hotter, buoyant air

out of the structure, resulting in the stack ef-

fect. Multiple sources of heat rejection inside

the boiler building will drive the ambient air

temperature up until it is higher than the am-

bient temperature outside the building.

The difference in temperature creates a

difference in air density and air pressure

(Figure 1). Because the warmer air inside the

boiler building has a lower density than the

cooler air outside, a difference in air pressure

is created, with the higher pressure located

outside of the boiler building.

Due to this developed pressure differential,

cooler, outdoor ambient air will naturally try

to infiltrate the lower portion of the structure

while trying to equalize internal/external air

pressures. In the case of a forced ventilation

1. Stacks are stacks. The same forces

that govern pressure differentials in combus-

tion system stacks will apply to boiler building

ventilation. Courtesy: National Renewable En-

ergy Laboratory (NREL)

Page 39: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 37

AUXILIARY SYSTEM EFFICIENCY & RELIABILITY

system, the fans induce a large pressure differ-

ential that drives the movement of air. Because

the pressure differential is large, only a small

opening in the roof is required. By contrast,

the pressure differential in a natural ventila-

tion system is much smaller than that of a

forced ventilation system; therefore, a larger

open area on the top of the boiler building is

required to lessen flow restrictions and com-

pensate for the reduced pressure differential.

Various commercial products are available

to appropriately address the need for addi-

tional open roof area. Depending on the heat

distribution within the building and the ambi-

ent environment, a simple louver may suffice.

This will provide the building with additional

open roof space while protecting the building’s

contents from weather elements such as rain.

These louvers can either be manually adjusted

or motor driven to vary the amount of roof

opening required for adequate ventilation.

For structures requiring high airflow

movement, a clamshell-style natural venti-

lator may be the most appropriate solution

(Figure 2). A clamshell-style natural ventila-

tor will provide the same benefits as a louver;

however, the percentage of free area to face

area will be greater.

For a louvered application, the free area to

face area ratio typically ranges from 50% to

60%. With a clamshell-style natural ventila-

tor, the free area to face area is 100%. This

equates to more equivalent roof opening area

while still protecting the interior from out-

door weather events. Similar to a louvered

application, dampers inside the clamshell

natural ventilator can be opened or closed to

allow the appropriate amount of airflow in

and out of the structure. Manual chain drive

or motor actuators can be provided to accom-

plish this function.

An equation for estimating stack effect

ventilation follows:

QS = Cd A 2 g Hd √TI – TO

TI

Where:

Qs = ventilation airflow rate

Cd = discharge coefficient for an opening

A = cross-section area of opening

g = gravity

Hd = distance between the middle upper

and lower openings

TI = average indoor temperature

To = average outdoor temperature

Wind-Powered VentilationWind can also play a role in improving the

efficiency of a natural ventilation system.

When a building is exposed to winds, the

windward side of the structure will experi-

ence an increase in ambient pressure, while

the leeward side will experience a decrease

in ambient pressure. Similar to the buoyancy

forces that contribute to the stack effect, the

pressure of the windward and leeward sides

of the structure will try to equalize. With ad-

equate openings in the sides of a boiler build-

ing (Figure 3), additional air movement can

be achieved, resulting in lower indoor ambi-

ent temperatures.

The equation for estimating airflow in-

duced by wind follows:

QWIND = A x V x k

Where:

QWIND = volume of airflow

V = outdoor wind speed

A = area of smallest opening

k = coefficient of effectiveness

Additional ConsiderationsNatural ventilation systems can be designed

to operate without the need for electrical

power. In some instances, it may be advan-

tageous to utilize power for adjustments of

the effective open space on the rooftop, but

for most of the systems’ operation, the equip-

ment is static, resulting in minimal wear and

tear on components.

However, a conversion to natural ventila-

tion may not be practical for all coal-fired

units. A feasibility and cost/benefit analy-

sis should be performed to determine the

amount of effective area required for natural

ventilation within a structure. The required

area might not be attainable due to existing

roof configuration; in such cases, at best, a

partial conversion may be possible.

Some plants don’t have to worry about

this issue. There are a number of coal-fired

units (located in “fair weather” states) that

have been constructed as outdoor units. This

“open” type of construction means that no

building surrounds the boiler, steam turbine,

and auxiliary systems; thus, no ventilation

system is required or installed.

Given that only the most energy efficient

coal plants are expected to remain economic

once the Clean Power Plan is finalized, ev-

ery kilowatt of auxiliary power savings will

be needed to increase the odds of continued

operation. The conversion from a forced ven-

tilation system to a natural ventilation system

can free up approximately 90% of the power

used by a purely forced ventilation system.

For a typical 600-MW power plant, this can

equate to approximately 400 kW of power

savings.

Even without the regulatory consider-

ation, existing forced ventilation systems

will continue to age, become increasingly

unreliable, and replacement parts will be

increasingly harder to find. For all of these

reasons, a new approach to boiler building

ventilation using natural forces should be

considered for future operation. ■

—Brandon Bell ([email protected]) is a senior project manager for Valdes

Engineering Co. and a POWER contributing editor.

2. Same principle, different name. A ridge vent uses the same principle as the clam-

shell but is smaller and has a slightly different shape. Ridge vents like this MoffittVent are com-

mon in the power industry. Courtesy: Moffitt Corp.

3. Wind-cooled structure. Louvers

placed around a building can take advantage

of wind cooling. Courtesy: NREL

Page 40: Power magazine march 2015   international

www.powermag.com POWER | March 201538

AUXILIARY SYSTEM EFFICIENCY & RELIABILITY

SCR Reheat Burners Keep NOx in Spec at Low LoadsOptimal NOx removal by a selective catalytic reduction (SCR) system requires

the inlet gas temperature to remain within a prescribed range. How does a baseload unit meet NOx permit limits when it’s cycled and SCR inlet gas temperatures dip?

Robert Parent and Bruce Rivera

Selective catalytic reduction (SCR) sys-

tems installed in steam generators for

NOx reduction are ordinarily designed

for full boiler load conditions, when SCR

inlet temperatures normally exceed unit-

specific temperatures in order for the catalyst

to function efficiently. Under full-load con-

ditions, SCR units operate at optimum lev-

els of NOx reduction, often exceeding 90%,

with minimal ammonia slip, although the

optimum temperature range heavily depends

on the type of catalyst used and the flue gas

constituents.

The unit operating profile when an SCR

was added often bears little resemblance to

its operating profile today, now that low-load

operation has become increasingly common.

Low natural gas prices have spurred con-

struction of high-efficiency combined cycle

plants that now compete with coal-fired gen-

eration in many regions of the U.S. for the

top spot in the dispatch order. Also, some

units are disadvantaged in the dispatch order

because large amounts of renewable energy

are available, principally wind and particu-

larly at night, which tends to push coal-fired

units into cycling or load-balancing service.

A coal-fired unit originally built as a

baseload unit but now forced into cycling

service will experience lower SCR inlet gas

temperatures, which in turn will reduce the

SCR catalyst’s ability to efficiently remove

NOx. In addition, reduced gas temperatures

can reduce SCR catalyst activity due to pore

blockage on the catalyst surface from the

condensation of ammonium bisulfate (ABS)

and ammonium sulfate (AS).

At full load, the SCR inlet temperature

exceeds the salt dew point; therefore, salt

condensation is avoided. At below design

gas temperatures, ammonium salts are

formed when ammonia is injected into the

flue gas to react with NOx due to undesirable

side reactions with SO3 and H2SO4. As these

salts deposit on the SCR catalyst, there is a

resulting loss of catalyst de-NOx capability,

as access for the SCR reactants (NOx, NH3v

and O2) is inhibited.

The natural consequence of reduced SCR

inlet temperatures is to experience catalyst

deactivation and/or increased ammonia slip.

Increased ammonia slip can also cause plug-

ging or corrode downstream components,

and ammonia absorption by fly ash may af-

fect disposal or reuse of the fly ash.

SCR Performance Problem SolvingCoal-fired units experiencing one or more

SCR problems caused by cycling or load-

following service just described have three

potential solutions to their problem.

One common option is to install gas-side

economizer bypass ductwork to divert a por-

tion of the hot flue gas that would normally

enter the economizer and send it directly to

the inlet of the SCR. This option has three

important issues that must be addressed.

First, an economizer bypass can be an

expensive option due to the high capital and

installation costs for the structural steel, by-

pass ducts, diverting dampers, actuators, and

expansion joints. The existing flue gas duct-

work often makes locating new ductwork

for the economizer bypass difficult. Second,

some plants have required pressure part mod-

ifications associated with “split” economizer

designs. Third, less energy is transferred to

the boiler feedwater with an economizer by-

pass. The consequence is a small reduction in

boiler efficiency and, therefore, a correspond-

ing increase in fuel consumption in order to

maintain required steam production.

Another option that has found favor is to

make a fuel switch to low-sulfur coal. A coal

that produces a lower concentration of SO3

at the SCR inlet will reduce the formation

of ABS and AS. This option can be very ex-

pensive, as the delivered cost for low-sulfur

coal is often higher than for medium- to high-

sulfur coal. Many other unit and plant equip-

ment upgrades are required to efficiently

and safely burn low-sulfur coal. If refueling

is a viable option, then begin your research

Ammonia injection

grid

Air

preheater

Electrostatic

precipitator

SCR

reheat

burners

CoalAir

Boiler

SCR

reactor

1. Heating flue gas. Register burners can be added to existing ductwork upstream of the

ammonia injection grid to heat the flue gas in order to obtain optimum performance of the se-

lective catalytic reduction (SCR) system under all operating conditions. Source: Forney Corp.

Page 41: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 39

AUXILIARY SYSTEM EFFICIENCY & RELIABILITY

by contacting the PRB Coal Users’ Group

(www.prbcoals.com).

The third and lowest capital cost option

for solving low SCR inlet gas temperature

problems is to install one or more SCR re-

heat burners in the ductwork upstream of the

SCR inlet (Figure 1). Typically, one or more

register burners can be strategically mounted

directly on the outside of the existing SCR

ductwork, which is particularly effective in

high-ash environments.

Register burners inject high-velocity, high-

temperature air directly into the flue gas stream

across the width of the duct. This results in

even mixing and a uniform temperature dis-

tribution to the SCR ammonia injection grid

that is critical for efficient SCR operation.

Also, the register burner design eliminates the

problems of slagging, ash buildup, and burner

fouling. The external burners also minimize

added system pressure drop.

A typical register burner system consists

of a gas or oil burner, igniter, flame detec-

tor, combustion air blower, combustion

chamber, and a burner management system

(Figure 2). Design and layout of the burner

system is determined using computational

fluid dynamics modeling, ensuring optimal

heat distribution across the ammonia injec-

tion grid.

Noteworthy Case StudyNorthern Indiana Public Service Co. (NIPSCO),

one of the seven energy distribution companies

of NiSource Inc., produces and supplies elec-

tricity to the northern third of Indiana. NIPSCO

is also the state’s largest natural gas distribution

company. NIPSCO’s Bailly Generating Station

(BGS) is located in Chesterton, on the shore of

Lake Michigan, in northwest Indiana (Figure 3).

The plant consists of two supercritical coal-fired

units.

Unit 7, which entered service in 1962,

uses a Babcock & Wilcox (B&W) cyclone

boiler that produces 160 MW. Unit 8, also

using a B&W cyclone boiler, has a net full-

load output of 320 MW and was installed

in 1968. The plant burns bituminous coal

containing about 3% sulfur. Both units are

equipped with SCR for NOx control, elec-

trostatic precipitators for particulate matter

(PM) control, and SBS Injection for SO3

control. The two units share a common wet

limestone flue gas desulfurization system

and stack.

2. Retrofit register burner. A fully as-

sembled register burner system includes a

combustion chamber, combustion air blower,

and burner management system. Courtesy:

Forney Corp.

3. Indiana plant on Lake Michigan. NIPSCO’s Bailly Generating Station consists

of two coal-fired supercritical units built in the

1960s that share a common stack. Courtesy:

NIPSCO SYSTEMS ENGINEERING

Reference Project:

RIGA TPP-2, 2nd Unit, Latvia

Designed, manufactured and tested in Switzerland

SWAN SYSTEME AG · www.swansystems.ch

Water & Steam Sampling & Analysis Systems

CIRCLE 16 ON READER SERVICE CARD

Page 42: Power magazine march 2015   international

www.powermag.com POWER | March 201540

AUXILIARY SYSTEM EFFICIENCY & RELIABILITY

The plant has been operating, since

January 2011, under the terms of a legal

settlement between NIPSCO and the U.S.

Environmental Protection Agency regarding

compliance with the Clean Air Act. The con-

sent decree specifies the maximum 30-day

rolling average emission rates for NOx, SO2,

and PM emissions for both units combined.

Emissions data are collected by the plant’s

continuous emissions monitoring system

mounted on the combined stack, and a new

30-day rolling average is calculated each

calendar day. The average emission rates

that occur during the daily averaging pe-

riod specifically include startup, shutdown,

and malfunctions that may occur each day.

The consent decree does allow for specific

malfunctions that qualify as a force majeure

event that aren’t factored into the rolling av-

erage emission rate.

Both units are operated based on system

demand and are regularly cycled. During

reduced load conditions, the flue gas tem-

perature often drops below the 645F mini-

mum temperature setpoint for the operation

of the Unit 8 ammonia injection system for

the SCR, as the June through October 2010

operating data illustrates (Figure 4). This

system limitation means that when the plant

is dispatched to lower loads that reduce the

flue gas temperature below 645F, the am-

monia injection system does not start, SCR

efficiency remains low, and the plant could

fail to meet the 30-day rolling average NOx

limit (0.18 lb/MMBtu) specified in the con-

sent decree.

BGS determined that adding four Forney

natural gas–fired register burners (three on

Unit 8 and one on Unit 7) minimizes the risk

of the plant failing to meet NOx emissions

limits during low-load operation and thereby

avoids expensive penalties associated with

noncompliance. The four register burners

were installed in 2011.

The register burners were delivered to BGS

three months after drawing approval. The

three Unit 8 burners were lifted into place in

June 2011 and placed onto a structural foun-

dation adjacent to the SCR inlet ductwork.

Each SCR burner assembly weighs approxi-

mately 17,600 pounds (Figures 5 and 6).

The SCR register reheat burners are

monitored and modulated by two separate

control systems: the burner management

system (BMS) and the combustion con-

trol system (CCS). An Invensys I/A Series

distributed control system (DCS) using

a dedicated pair of fault-tolerant CP270

controller modules manages each of the

three control systems. BGS also uses the

Invensys DCS platform in other areas of

plant operation.

During operation, the heat load at the

outlet of the economizer is calculated by

the CCS by multiplying the difference

between the economizer average outlet

temperature and SCR inlet temperature

with the specific heat of the flue gas and

the flue gas mass flow rate. This value is

“trimmed” by the SCR inlet temperature

trim controller, and the final calculated

value is used by the CCS as the heat that

must be added to the economizer outlet

gas (heat) to maintain the necessary SCR

inlet temperature. The number of burners

required (Unit 8 only) is determined by di-

viding the heat by the maximum thermal

energy available from a single burner. The

BMS determines when burners are started

and stopped once the system is in service.

Multiple burners are operated in parallel in

order to maintain a uniform exit gas tem-

perature across the duct at the ammonia

injection grid.

Compliance Risks AvoidedThe 320-MW BGS Unit 8 has experienced

no loss of ammonia injection at reduced load

since the SCR reheat burners were installed

in June 2011. The burners have worked flaw-

lessly in maintaining the minimum ammonia

injection temperature above 635F under all

operating conditions. BGS also reports that

the 635F permissive temperature for ammo-

nia injection can be maintained down to 180

MW, which gives the utility additional flex-

ibility in plant dispatch.

An added benefit is the ability to use the

SCR reheat burners during unit startup time

from cold start to full load. Depending on

the specific boiler conditions during ramp-

up, one, two, or three reheat burners are en-

gaged. This can reduce the startup time by 2

to 6 hours as the ammonia injection permis-

sive temperature is achieved faster. This has

a positive influence in the compliance emis-

sion rate calculations. ■

—Robert Parent (robert.parent @forneycorp.com) is sales manager for

Forney Corp. Bruce Rivera (brivera @nisource.com ) was NIPSCO’s project

manager for the installations.

750

700

650

600

550

500

45050 100 150 200 250 300 350

SC

R i

nle

t te

mp

. (F)

Unit load (MW)

SCR reheat system design point with three SCR

reheat burners (1,000F injection temperature)

4. Adding burners. NIPSCO’s Bailly Generating Station added three natural gas–fired 40

MMBtu/hr register burners to Unit 8 (whose data are shown in the figure) and one to Unit 7 in

2011. Each burner has a maximum firing temperature of 1,000F. Burners are engaged when the

flue gas temperature entering the SCR drops below 633F (marked by the red line) and the gas

is reheated to approximately 633F. The dotted line illustrates the maximum capability of the Unit

8 SCR reheat system. Data are for Unit 8 operations during October 2010. Source: NIPSCO

5. Assembling burners. The three

burner systems are preassembled prior to in-

stallation on Unit 8. Courtesy: NIPSCO

6. Burner lift. A register burner is lifted

into place on Unit 8. Courtesy: NIPSCO

hdrinc.com

Navigating the CCR RulingWe’re partnering with clients nationwide to lay the groundwork for safe and cost-efective CCR management. If you’re ready to take the next step, we’re ready to help you navigate all the critical compliance factors. This is where great begins.

Page 43: Power magazine march 2015   international

hdrinc.com

Navigating the CCR RulingWe’re partnering with clients nationwide to lay the groundwork for safe and cost-efective CCR management. If you’re ready to take the next step, we’re ready to help you navigate all the critical compliance factors. This is where great begins.

Page 44: Power magazine march 2015   international

www.powermag.com POWER | March 201542

COMBINED CYCLE GAS TURBINES

Protecting Steam Cycle Components During Low-Load Operation of Combined Cycle Gas Turbine Plants How low can you go? That’s the question owners of gas turbine combined cy-

cle plants are asking these days as they are being called upon to operate those units for rapid response in markets where load following is becom-ing the norm. The resulting cyclic operation introduces challenges that can result in damage to steam cycle components if you aren’t careful.

Dave Moelling, Peter Jackson, and Jim Malloy

Originally, the modern combined cycle

gas turbine (CCGT) unit was de-

veloped to act as a largely baseload

source of generation due to its high thermal

efficiency and low initial capital cost. But as

markets developed for independent power,

the service requirements changed. Many

markets were essentially energy only (MWh)

and while high-efficiency CCGT plants were

competitive during peak daytime hours, their

limited turndown capability and high part-

load heat rates were uneconomic at night.

The result was that most new CCGT units

were required to do overnight shutdowns

(two-shift cycling) during the work week and

longer shutdowns over weekends. As natural

gas prices have dropped in North America,

and renewables with significant tax credits

and take-or-pay contracts expanded, markets

have had to change to a combination of en-

ergy and capacity supply plus related ancil-

lary services. This has increased the need for

operational flexibility in CCGT units.

Historically, large gas turbine units have

been limited in turndown to about 60% of rated

power while maintaining acceptable exhaust

gas emissions of NOx and CO. Turndowns

were controlled in such a way that exhaust

gas temperatures would rise as load dropped.

As operational demand for better low-load

capabilities increased, GT original equipment

manufacturers (OEMs) offered modifications

to equipment and controls to allow good emis-

sions performance down to 40% to 50% of

design load. The Alstom sequential combustor

design in the GT24/26 designs could go even

lower: 20% to 30% of design power.

Having the ability to operate at lower

power levels, plants can keep the steam sys-

tem hot and online rather than go offline at

low-demand periods. This reduces wear and

tear on the gas turbine and steam turbine (ST)

from frequent starts, as in equivalent start

formulations. The cost to start a large GT is

typically estimated at $12,000 to $15,000 per

start. Thermal cycling of the heat-recovery

steam generator (HRSG) is also reduced by

eliminating extra starts.

The primary driver in many markets is

the ability of a plant to participate in 10- and

30-minute synchronized reserve markets. In-

creasing wind generation, especially in take-

or-pay systems, increases the need for rapid

online reserve capability both day and night.

For 2 x 1 CCGT units, taking only one unit

offline while running the remaining unit at

low load can maximize a plant’s rapid reserve

capacity while minimizing fuel expense.

Reduced power and fuel use at extended

low load also reduces total NOx and CO2

emissions per hour. This can be valuable in

plants that have tight air permits.

One of the largest areas of concern for

low-load operation is a CCGT’s steam cycle.

This article provides an overview of the com-

ponents that may be affected by low-load

operation and highlights some potential solu-

tions and the trade-offs involved.

A Vulnerable Steam CycleThe gas turbine generator sets the operat-

ing limits of a CCGT unit, but can the steam

cycle handle them? Changes to CCGT plants

for low-load operation are usually started as

GT modifications. Often these are part of

general GT improvement packages and are

implemented before considering the entire

plant capabilities at low loads. The ability of

the steam cycle elements of HRSG, power

piping, steam turbine generator, and con-

denser to function reliably at lower GT loads

is essential to effective low-load operation.

HRSGsHeat-recovery steam generators are opti-

mized for full-power GT operation and often

include the ability to add substantial heat via

duct burners. At low loads, the amount of

steam produced is significantly lower than at

full-power conditions. The operating steam

pressures are also lower than in full-power

operation. These pose challenges to ensure

that the HRSG is operating within design

limits and avoiding any unnecessary damage

to HRSG components. Brief discussion of

several such challenges follows.

Keeping Metals Cool Enough. At

low-load conditions it is often difficult to

keep heat exchange surfaces below design

temperatures or operationally limited tem-

perature. The finned tube designs of pressure

parts in HRSGs are very effective in moving

heat from the exhaust gas to the tube wall. At

part loads, several things happen to make this

problem worse. The total mass flow of the GT

exhaust is reduced, but often the temperature

is increased. This results in lower steam flow

from evaporators that is available to cool su-

perheater and reheater tubes. Maintaining

the required outlet steam temperatures while

keeping intermediate metal temperatures be-

low limits can be a challenge.

As an example, consider a large (170-MW)

GT in combined cycle service. At design full-

power conditions, exhaust gas flow is around

3,400,000 lb/hr at 1,150F to the HRSG. At

low load (85 MW) flow is 2,456,000 lb/hr

Page 45: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 43

COMBINED CYCLE GAS TURBINES

and 1,210F–1,215F.

Recently, a large GTCC plant in the U.S.

implemented an extended turndown with

a GT performance upgrade. The increased

turbine exhaust temperature was around

1,208F–1,215F at about a 50% output level.

Problems were observed with the existing

desuperheater spray valves, which prevented

raising spray flows, so steam temperatures

rose from 1,048F to 1,058F–1,060F. This

raised owner concerns about exceeding de-

sign tube metal temperatures in the super-

heaters and reheaters.

The maximum tube temperatures set for

ASME Boiler and Pressure Vessel Code

calculation is the design midwall (average)

tube temperature allowed. The design al-

lowance for spread in tubes temperatures is

typically around 25F. Thus, the average tube

temperatures should be 25F below the design

temperature. The tube temperatures at the ac-

tual operating conditions were checked at the

higher steam temperature for acceptability, as

shown in Table 1. The values were acceptable

but close to limits. Operation was not feasi-

ble until the desuperheater spray valves were

modified to allow greater spray amounts.

Keeping Steam Cool Enough for Mak-

ing Power. With lower steam flows and

higher GT exhaust temperatures, the final

steam temperatures from main steam and

hot reheat can be more difficult to keep at re-

quired values. Often at low loads, the steam

turbine will also have reductions in allowed

steam inlet temperatures.

Almost all modern drum type HRSGs reg-

ulate final steam temperatures (main steam

and hot reheat steam) with interstage spray

attemperators. These are typically located

between the primary and secondary stages of

superheaters (SH) and reheaters (RH). This

arrangement avoids risks of water intrusion

to the steam turbine and allows some control

of tube metal temperatures in the final stages

of superheat and reheat.

Desuperheaters usually have a minimum

steam velocity and upstream enthalpy re-

quirements set by the OEM to ensure good

droplet evaporation. The area of the SH/RH

surface is fixed, and at low flows the effec-

tiveness (i) of the surface is much higher than

at higher flows. Effectiveness is defined as:

i = Ch(th,in – th,out)

Cmin(th,out – tc,in)

The values Ch and Cmin are the heat capaci-

ty rates of the hot fluid (gas) and the minimum

(steam) rate as mass flow x heat capacity.

As flow is reduced (steam side), Cmin is re-

duced, increasing effectiveness because the

outlet steam is more easily heated to the gas

temperature range.

The derivative of Tc,out to Tc, in is simply

(1– i).

At low flows (<50%) the change in out-

let temperature for a given inlet temperature

change is only 40% or so of its value at full

flow. Large changes in inlet temperature af-

ter desupereaters are required for even small

reductions in final steam temperature. This

high spray water to steam flow ratio can lead

to incomplete evaporation and liquid water

accumulation on pipe and header walls.

Improved sprays and spray controls can

allow additional spray capacity without vio-

lating limits on approach to saturation temper-

ature, but they still cannot fully compensate

for reduced steam flow in some units. The ad-

dition of terminal attemperation sprays in the

outlet steam lines is possible, but the instal-

lation should be in compliance with ASME

TDP-1 (Prevention of Water Damage to Steam

Turbines Used for Electric Power Generation:

Fossil-Fuel Plants).

Adding Steam Attemperation. Some

newer HRSGs have steam attemperation to

help control final steam temperature. Typi-

cally, some amount of colder steam is taken

from the saturated steam outlet of the steam

drum (for main steam) or the cold reheat pip-

ing (for hot reheat steam). This colder steam is

then piped to the steam outlet to cool the steam

flow to the turbine. With no liquid water, the

risk of thermal shock damage to the piping or

steam turbine is eliminated. However, using

this bypass steam reduces the steam flow to

the superheater and reheater sections in the

HRSG. This can result in higher tube metal

temperatures due to inadequate cooling.

A newer HRSG has been equipped with

steam attemperation instead of interstage

desuperheaters in the reheat steam. At ex-

tended turndown, the steam attemperation

was successful in maintaining final RH tem-

peratures, but because the system reduced

steam flow in the RH tube panels, local steam

temperature limits were exceeded. These

were set to prevent overheating of the tubes

and headers in the RH system.

Managing Inlet Exhaust Gas Attem-

peration. Cooling the inlet exhaust gas to

lower temperatures is another method of

controlling metal temperatures in the HRSG

at low loads. This cooling can be done by

water spray or ambient air fed into the hot

exhaust gas. In both cases, the actual process

of mixing with the highly turbulent, swirl-

ing exhaust gas must be carefully designed

to achieve a uniform cooling and avoid dam-

age to the HRSG inlet duct or pressure parts.

Failure of air attemperation components can

result in consequential damage to pressure

parts—typically, the finish high-pressure

(HP) superheater or reheater tube panel—

immediately downstream.

Figure 1 shows a system where water is

sprayed into the inlet exhaust gas. It worked

well, but overspray can damage the liner

plates, as seen in Figure 2. At other plants

with water sprayed into the duct, repair of

spray nozzles has become a regular mainte-

nance issue.

Colder ambient air can be used to reduce

exhaust gas temperature. Figure 3 shows a

system to blow cold ambient air into the inlet

exhaust gas at a CC unit with a GE Frame

7FA gas turbine. The system works, but the

highly turbulent inlet duct flow can lead to

damage in the air inlets and consequential

damage to HRSG heat transfer surfaces, as

seen in Figure 4.

Keeping Gas Hot Enough. At the inlet

to the HRSG, the problem is exhaust gas that

is too hot, but as the exhaust travels through

the HRSG, it can be cooled to an excessively

low temperature. In many cases, additional

operational constraints are required.

For example, plants with NOx control by se-

lective catalytic reduction systems (SCRs) will

have a specific temperature range for operation.

SCRs are usually located just after the HP evap-

orator sections for this purpose. At low loads

in sliding pressure operation, the HP evaporator

pressures can be low enough that the low satu-

Tube location Design tube temperature (F)

Max. operating tube

temperature (F)

Tube temp. at 50%

load; TEG 1,214F

HPSH4 1,125 1,100 1,095

RH31 1,125 1,100 1,098

RH32 1,125 1,100 1,090

HPSH3 1,065 1,040 951

RH2 1,061 1,036 965

HPSH21 1,125 1,100 All well below design

HPSH22 1,125 1,100 All well below design

RH1 1,100 1,075 All well below design

HPSH1 935 910 All well below design

Notes: HPSH = high-pressure superheater, RH = reheater, TEG = turbine exhaust gas.

Table 1. HRSG design tube temperature comparison. Source: Tetra Engineering

Page 46: Power magazine march 2015   international

www.powermag.com POWER | March 201544

COMBINED CYCLE GAS TURBINES

ration pressure, combined with large evapora-

tor heat exchange surface, will produce low gas

temperatures entering the SCR.

Recently, a plant in the European Union

(EU) commissioned extended turndown at

20% using the Alstom sequential combustion

system. The operation was successful, but gas

temperatures were very low in the HRSG. No

SCR was required in the plant, but local gas

temperatures would have been too low for

operation if an SCR were required. At plants

with SCRs, raising the HP drum pressure by

modulating turbine admission valves may be

necessary to keep the SCR functioning and the

unit in compliance with emissions permits.

Avoiding Pressure Part FAC and LDI

Damage. Lower exhaust gas flow and ener-

gy can result in changes in the low-pressure

evaporator and economizers sections. Re-

duced production of low-pressure (LP) steam

can produce problems with local steaming in

economizers, circulation stability in LP evap-

orators, and steam separation problems.

Lower pressures in the LP evaporators

leads to high circulation ratios and conse-

quent fluid velocities. These high velocities

can produce excessive flow accelerated cor-

rosion (FAC) and liquid droplet impingement

(LDI) erosion of tubes, piping, and headers.

In drum type HRSGs, steam pressures

will drop in sliding pressure mode for the HP

system and will tend to drop in intermediate-

pressure (IP) and LP systems due to less heat

being available and thus less steam production.

These natural circulation systems are designed

to have good flow stability in their circulating

sections at normal operating loads. At very low

loads, reduced steam production and pressures

can lead to unstable configurations.

Power PipingPower piping is affected by low-load op-

eration due to reductions in steam flow that

correspond with lower MW output and the

potential for higher steam temperatures. In

addition, elevated requirements for steam

attemperation will increase vibration and fa-

tigue damage. For plants with Grade 91 main

steam and reheat steam piping, this may ac-

celerate consumption of remaining reliable

lifetime, depending on plant-specific condi-

tions. Enhanced maintenance and inspection

programs may be required to maintain power

piping reliability.

Low-load operation for 1 x 1 plants has

a direct effect on unit operating conditions.

However, for 2 x 1 and 3 x 1 plants in low-

load operation, the result is significant ther-

mal gradients at fittings (including tees and

laterals), where the steam flows combine to

common near the steam turbine. These high-

er thermal stresses contribute to accelerated

consumption of remaining reliable lifetime.

Good engineering design practice for 2 x 1

and 3 x 1 configurations requires that piping

system designers consider the full set of per-

mutations in units being “on” or “off” to ensure

that ASME B31.1 Code stress limits aren’t ex-

ceeded. Sometimes, unintended high stresses

result in certain configurations, which then re-

quire that the pipe hangers be reevaluated for

low-load operation (Figure 5). This should be

a standard activity when contemplating a tran-

sition to low-load operation. Enhanced nonde-

structive testing inspection is recommended to

monitor power piping integrity.

Mitigating Creep and Fatigue Dam-

age. Low-load operation also introduces

enhanced risk of fatigue damage and acceler-

ated life consumption for Grade 91 materials.

It is well known that Grade 91 components

have a higher frequency of deficient material

properties and expected in-service lifetimes.

Improperly maintained pipe support systems

exacerbate the conditions associated with

low-load operations, raising local stresses in

some configurations to much higher values

1. Solution. This water spray attempera-

tion nozzle is part of a system used to spray

water into the inlet exhaust gas. It worked, but

overspray can damage liner plates, as shown in

the next figure. Courtesy: Tetra Engineering

2. Unanticipated consequence. This is the inlet duct liner damage from the

water attemperation shown in the previous

figure. Courtesy: Tetra Engineering

3. A cool breeze. At this plant a system

was devised to blow cold ambient air into the

inlet exhaust gas at a combined cycle plant

with a GE Frame 7FA gas turbine. It works,

but turbulent inlet duct flow can lead to dam-

age in the air inlets and consequential dam-

age to heat-recovery steam generator heat

transfer surfaces, as shown in the next figure.

Courtesy: Tetra Engineering

4. Ouch! Here, loose parts from a failed air

attemperation inlet duct are impacted on the

lead row of the high-pressure superheater.

Courtesy: Tetra Engineering

5. Never assume. A piping engineer

evaluates a pipe hanger prior to low-load op-

eration. Courtesy: Tetra Engineering

Page 47: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 45

COMBINED CYCLE GAS TURBINES

than predicted by design analysis.

For Grade 91 components, Type IV creep

cracking, enhanced by fatigue loads is a pre-

dominant damage mechanism leading to mac-

roscopic cracks (Figure 6) and, in some cases,

leaks. This damage is more likely for compo-

nents with inadequate metallurgical properties

but is an issue of concern for all components,

especially those subjected to higher stresses in

1 x 1 operation than expected under the original

design. CCGTs in low-load operation require

a comprehensive approach to assess and main-

tain power piping condition, which should be

an integral part of the Covered Piping System

Program in accordance with the recent ASME

Code Section B31.1 Power Piping, Chapter

VII, Operations and Maintenance.

Preventing Water Hammer. Water ham-

mer is a well-known issue for CCGT plants.

The more common types of damage at low

load will be caused by inadequate drain ca-

pacity downstream of attemperator spray sta-

tions and attemperator system malfunctions,

including controls logic inadequacies. At

low-load operation, there is increased like-

lihood of condensate and spray water accu-

mulation; therefore, it is essential that drain

capacity be capable of removing water from

HP and hot RH steam piping that accumu-

lates after or during shutdown.

Damaged or inadequately maintained non-

return and stop valves will contribute to higher

risks of water hammer damage. Water hammer

events are generally severe, with yielding of

pipe spool pieces, destruction of pipe supports

(Figure 7), and a resulting piping system that

is no longer operating within the maximum

allowable stresses specified by ASME Code

design. The result is generally premature and

costly inspections and repairs.

Steam Turbines Establishing a minimum floor pressure for

HRSG operation at low loads is essential.

The trade-offs are that at low pressures, steam

flow increases, which can be helpful for LP

steam turbine operation but raises steam ve-

locities in HRSGs and piping. Low pressures

for HRSG operation can also reduce stability

in evaporator circulation.

At low steam flows, the performance of

the LP turbines is key. Low steam flows (and

enthalpies) result in poor turbine efficiencies.

Internal flow distribution and recirculation

can cause power loss and local heating.

Steam is pushed to the outer regions of

the turbine blades, and a recirculation flow

is established (Figure 8). This windage heat-

ing can be reduced by using exhaust hood

sprays. These sprays can result in blade ero-

sion if caught up in the recirculation. At these

conditions the average temperature of the LP

turbine rotor is increased, which increases

the rotor expansion.

Excessive expansion of the rotor is a criti-

cal operational limitation on low-load opera-

tion, both limiting the absolute lower load

and limiting the time that low-load operation

can be maintained. These are site-specific

impacts that are assessed in assessments of

low-load operations.

Condensers The use of hood sprays at low loads to cool

windage-heated LP steam raises the risks of

droplet impingement and damage to tubes.

Good maintenance and monitoring of sprays

is essential to preventing condenser damage.

Many low-load contracts require the ca-

pability of running in 100% bypass of steam

from the steam turbine to the condenser. In

this way dispatched power is less but fuel

consumption is the same as for low-load GT

operation without bypass. Extended bypass

raises risks of damage to internal baffles,

dummy and live condenser tubes and piping,

as well as the steam conditioning valves. In

general, the increased maintenance costs for

long-duration bypass can be substantial. Few

plants expect to run in this mode, but the ca-

pability is necessary.

Careful Attention Is EssentialIt’s a given that low-load operation is be-

coming a familiar fact of life in an increas-

ing number of markets. To ensure you get

the most reliable, long life out of your unit,

you need to understand the potential effects

of low-load operation on the steam cycle and

the tradeoffs involved in mitigating them. In

most cases, enhanced maintenance and in-

spection programs may be required. ■

—Dave Moelling ([email protected]) is chief engineer at Tetra Engi-

neering Group, consults on HRSG thermal design evaluations, and leads low-load

operations assessments. Peter Jackson ([email protected]) is direc-

tor of field services at Tetra Engineer-ing Group, responsible for HRSG field

services, power piping, balance of plant, and leading root cause failure analysis

and fitness-for-service assessments. Jim

Malloy ([email protected]) is managing director at Tetra Engineering

Europe and is responsible for managing CCGT engineering services for Europe,

Middle East, and Africa.

6. Cracked. This example of cracked

Grade 91 hot reheat latrolet was caused by

fatigue and Type IV creep damage Courtesy:

Tetra Engineering

7. Hammered. Water hammer damage

to large-bore HP steam piping supports can

be significant. Courtesy: Tetra Engineering

8. The low-down. Low-load operation has recirculation of low-pressure (LP) steam flows

at the exit of the LP section of the steam turbine. This can result in trailing edge blade erosion.

Courtesy: Tetra Engineering

Page 48: Power magazine march 2015   international

www.powermag.com POWER | March 201546

COMBINED CYCLE GAS TURBINES

Are Flexible Generation Plants Performing as Expected?Highly flexible, fast-ramping, fast-cycling combined cycle plants hit the market

with a big splash a few years ago. But are they performing as advertised? Though the few operational plants are still new and still learning, the ini-tial results are encouraging.

Thomas W. Overton, JD

The Lodi Energy Center (LEC) is a 296-

MW 1 x 1 combined cycle plant in

Lodi, Calif., just north of Stockton and

east of the San Joaquin River delta (Figure 1).

From the outside, there’s little to distinguish

it from the many other combined cycle plants

large and small that power the California In-

dependent System Operator (CAISO) grid.

On the inside, though, there’s much to set

this plant, which began commercial opera-

tions in November 2012 and earned a POWER

Top Plant award that year, apart from its older

brethren. LEC was one of the first plants in

a new generation of combined cycle facilities

specifically designed for fast starts and fast

ramping while maintaining both high efficien-

cy and low emissions.

LEC is operated by the Northern California

Power Agency (NCPA) and owned by NCPA

and a coalition of local public power agen-

cies in the area. A turnkey plant delivered by

Siemens, which refers to the design as a Flex-

Plant 30, it’s built around Siemens’ SCC6-

5000F gas turbine, which is paired with a

Nooter Eriksen triple-pressure reheat heat-

recovery steam generator (HRSG) equipped

with a once-through Benson high-pressure

section, high-capacity steam attemperation,

and full-capacity steam bypass systems.

LEC also utilizes innovative piping warm-

up strategies, a Siemens SPPA-T3000 control

system and steam turbine stress controller,

and optimized plant stand-by using auxiliary

steam to maintain vacuum. The plant has as

many analyzers and system drains as a con-

ventional 3 x 1 plant.

Another Siemens Flex-Plant, NRG Yield’s

two-unit, 550-MW El Segundo Energy Cen-

ter, came online in 2013; two more, Panda

Power Funds’ Temple I and Sherman plants

(both 2 x 1 758-MW plants), started up in

Texas in 2014.

Designed for intermediate to continu-

ous cycling duty, LEC manages efficiencies

above 57% with startup times that are as

short as half those of earlier plants due to the

integration of fast-start features. Ramping at

13.4 MW/minute from a cold start, the plant

can reach 150 MW output in a little over

10 minutes, and the fast ramp rate means it

reaches CO compliance in 23 minutes and

NOx compliance in 40 minutes.

That’s performance that is becoming

critically important with continually increas-

ing amounts of renewable generation being

added to CAISO. California already has the

nation’s highest state renewable portfolio

standard, 33% by 2020, and Governor Jerry

Brown announced in January that he would

seek to raise it even further, to 50% by 2030.

That means the state’s gas-fired fleet will be

called upon to back up an enormous amount

of variable wind and solar generation.

But Does It Work?All that, at least, was the intent. But are LEC

and the new highly flexible plants like it liv-

ing up to the hype?

The question is not an idle one. A 2012

study by the National Renewable Energy

Laboratory and Intertek APTECH found that

shifting to faster ramping and startups from a

baseload role resulted in considerably higher

operational and maintenance costs for typi-

cal combined cycle plants. Worse, these costs

increased with greater penetration of renew-

able generation into the energy mix.

In the case of LEC, at least, according to

Plant Manager Michael DeBortoli, the an-

swer is an unqualified yes.

“It has lived up to our expectations,” he

told POWER in an interview in January. “So

far, the plant has been running very well. We

cycle a lot and have a lot of starts and stops

almost on a daily basis, and everything has

been running fine.”

DeBortoli confessed some concern with

being what amounted to a guinea pig for the

new design. “Being the first one in the country

with this new technology,” he said, “I thought

we were going to encounter a few hiccups, but

the plant has been operating to expectations.”

LEC has been a workhorse since it came on-

line. From November 2012 through the end of

January 2015, the plant racked up an impressive

380 starts despite two planned outages. Over

that period, it’s achieved 94% availability.

The plant is regularly being ramped from

165 MW minimum load to maximum output.

“That’s basically achieved within a 10-minute

interval,” DeBortoli said. “The gas turbine is

being run at the max ramp rate.”

And it’s being done without any excessive

wear and tear on the HRSG. “The Benson

technology, which is the once-through HP

section, we have not had any issues on that,”

DeBortoli said. “All of our bypass valves

have been working very well.”

In the Benson once-through natural-circu-

1. Fast start for a fast starter. The Lodi Energy Center in California was the first U.S. plant

to employ Siemens’ Flex-Plant technology. In the first two years, it’s totaled 380 starts and achieved

94% availability. Courtesy: Siemens

Page 49: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 47

COMBINED CYCLE GAS TURBINES

lation design, the drum is replaced by a thin-

walled external separator. The change allows

for higher temperature transients and simpler

chemistry control.

Rafael Santana, LEC maintenance man-

ager, said the number of problems has been

surprisingly small. “We did encounter some

minor hiccups with our HP turbine control

valve,” he said. “But it’s not the fast-start

plant that caused that issue, but rather a man-

ufacturing defect, probably aggravated by the

number of starts.”

The gas turbine as well is performing

admirably.

“We have had multiple planned outages to

conduct inspections, and in the most recent in-

spection of the turbine in November, all the com-

ponents looked pristine, so they were returned

back to operation instead of replacing them.”

Though greater demands are placed on

the plant with the additional cycling, the de-

mands on the plant staff are not unusual. “I

wouldn’t say there is much difference,” San-

tana said. “In terms of normal maintenance

and intervals of operation, it’s the same.”

Minor Growing PainsAs with any plant, there was a learning curve.

Siemens provided remote monitoring of LEC

for the first year, using networked instrumen-

tation to track the operating parameters from

its service center in Orlando, Fla. This enabled

Siemens to give LEC feedback any time any-

thing wasn’t operating in an optimal fashion.

“There were some growing pains in the

beginning,” Jeremy Lawson, LEC plant en-

gineer said, such as properly tuning the water

levels in the HRSG up to the bypass valves.

There were a few little hiccups with the

HRSG, with one of the lower acoustic baffles

coming loose due to the cycling regime and a

lack of support. There was also a minor leak

in one of the tube bundles in the #1 preheater

at the tube support a few months after opera-

tions began. Both problems were corrected

and have not recurred.

The plant also encountered high-tempera-

ture trips of the steam turbine (ST) across the

intermediate-pressure exhausts. This was re-

solved through faster ST starting and loading.

DeBortoli’s staff also found some ways to

reduce the plant’s already low CO emissions.

Working with Siemens, the plant staff made ad-

justments to the fuel flow and positioning of the

inlet guide vane (IGV). “We ended up keeping

our IGV closed until we got to 50 MW.”

These tweaks, plus boosting the ramp rate

to its 13.4 MW/minute maximum, helped cut

CO emissions by 350 pounds per start.

But all in all, these were minor challenges.

“Out of the box, there is just a little bit of di-

aling in so the operators understand what works

and what doesn’t,” Santana said, “but overall I

think that we haven’t really changed anything

major with the logic or the operation.”

DeBortoli concurred: “The overall process

is pretty much where we want it to be. Not

ongoing improvements from here on out, but

just really minor things.”

Moving OnWith the uncertainty and changes in the Cali-

fornia energy market, particularly the drought

that is challenging hydroelectric generation,

DeBortoli said LEC expects to continue seeing

demand for its fast-ramping capabilities going

forward. “The market condition is very dynam-

ic right now, so we don’t know what’s going to

happen in the next couple of months.”

Last July, General Manager Ken Speer lik-

ened NCPA’s experience with LEC to “driv-

ing a Ferrari rather than a Chevy.” LEC and

its sister unit in El Segundo appear to have hit

the ground running when it comes to meeting

the role they were intended for. ■

—Thomas W. Overton, JD is a POWER

associate editor.

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our Energy

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Page 50: Power magazine march 2015   international

www.powermag.com POWER | March 201548

RENEWABLES

New Zealand’s Geothermal Industry Is Poised for the FutureGeothermal power is New Zealand’s most reliable renewable energy source.

The country, which is justifiably proud of its geothermal facilities, faces economic forces familiar to the rest of the developed world. The geother-mal industry’s solution: diversify and innovate.

Chris Webb

Contact Energy fully commissioned New

Zealand’s largest geothermal power

plant last year, nudging installed geo-

thermal capacity to a shade over 1 GW. Near-

ly 80% of the country’s electricity is sourced

from renewables, placing it among the highest

in the world. New Zealand also is ranked in the

top 10 globally by the World Energy Council

for achieving the right balance between reli-

ability, sustainability, and affordability.

Though New Zealand aims to be the

first nation to go 100% renewable, that ac-

colade may elude it, as Iceland edges ever

nearer that coveted target; New Zealand has,

nonetheless, progressed rapidly in its bid to

achieve domestic energy security. According

to government data, in 2013, hydro provided

the largest amount of the country’s power

(22,815 GWh), gas came in second (8,134

GWh), followed by geothermal (6,053 GWh),

coal (2,238 GWh), wind (2,000 GWh), and

other thermal and bioenergy providing the

remainder (618 GWh).

Why Geothermal?First commercially tapped by the Kiwis (as New

Zealanders are known) in the 1950s, significant

underground geothermal resources made the

country one of the earliest large-scale users of

the technology. It is widely considered to be

the most attractive “new” source of energy, as

“easy” hydropower sites have been largely ex-

ploited, and the country is rigorously pursuing

a low-carbon goal. In 2014 geothermal electric-

ity contributed approximately 7,000 GWh to a

total of 43,000 GWh, roughly 16% of the total,

according to GNS Science.

New Zealand is rich in geothermal re-

sources because of its many volcanic areas

(Figure 1), faults, and tectonic features. But as

geothermal fluid is much lower in temperature

than steam produced by a coal boiler or gas

turbine exhaust gas, the conversion efficiency

to electricity is much lower—around 15%

(see sidebar). For this reason geothermal en-

ergy supply produces a relatively low fraction

of New Zealand’s electricity—about 15%—

though it also provides some district heating.

New Zealand has seen a period of rapid

growth in the utilization of geothermal en-

ergy over the last decade. The availability of

high-temperature, productive geothermal re-

sources has made geothermal plants the low-

est cost generation facilities to construct and

operate (on an energy unit cost basis) com-

pared to other renewable energy or fossil-

fueled options.

The increase in geothermal generation

from 2010 to 2014 of some 1,500 GWh is

significant, being greater than a 20% per

year increase over the four-year period. The

current total of over 1,000 MWe geothermal

capacity typically contributes about 16% of

total generation today, now that the Te Mihi

plant is fully online (an increase from 13% in

2010). New Zealand today produces almost

80% of its electricity from renewable energy

and is strategically targeting 90% by 2025,

a figure that analysts, among them, Price-

waterhouseCoopers’ Chris Taylor, believe is

comfortably achievable. “It’s just a question

of when the market is ready for the new ca-

pacity,” he says.

Major Players and PlantsState-owned Mighty River Power (MRP),

Contact Energy, and Maori Trusts have been

the key entities in the geothermal develop-

ment space over the past 10 years. Both Con-

tact Energy and MRP have had billion dollar

geothermal investment programs in the last

decade, and total geothermal expenditure

topped NZ$2.4 billion (US$1.75 billion).

Nga Awa Purua. The 140-MW Nga Awa

Purua Geothermal Power Station (Figure 2),

a joint venture between MRP and the Tauhara

North No. 2 Trust, was completed in 2010.

The plant was constructed by Sumitomo

Corp. in partnership with Fuji Electric, the

main suppliers, and Hawkins Construction.

Beca geotechnical engineers, as subcon-

tractors to Hawkins, confronted difficult con-

struction conditions. The company notes that

“Weak volcanic soils, aggressive groundwater

and high temperatures, and susceptibility to

liquefaction” required 30-meter-deep bored

piles to support plant structures, including

the turbine hall; the generator and turbine

weighed a combined 325 metric tons.

A Fuji Electric technical paper explains

that the steam turbine for Nga Awa Purua is

a “triple-pressure inlet, single-casing, single-

shaft, double-flow HP, IP and LP sections,

bottom exhaust, and its nominal output is 139

MW. Both steam turbines utilize 31.4-inch-

long last-stage blades, which are the largest

in any geothermal application.” That made it

possible to build what the company says is the

largest single-casing geothermal power station

utilizing multi-flash cycle technology.

Te Mihi. In 2014, Contact Energy, which

supplies 22% of the country’s power, com-

1. Powerful steam. New Zealand’s

North Island has several craters and active vol-

canoes. The popular Tongariro Alpine Crossing

trail brings hikers to a saddle with a view of

Emerald Lakes (top) and Red Crater (bottom),

where steam can be seen and felt below one’s

feet. Courtesy: Gail Reitenbach

Page 51: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 49

RENEWABLES

pleted the 166-MW Te Mihi Power Station

(Figure 3) in the Wairakei steam field north

of Taupo. (It was the 2013 POWER Marma-

duke Award winner; see the August issue at

powermag.com for technical details.) The

NZ$623 million plant forms part of a larger

local investment, which includes a bioreactor

and new wells, making Wairakei the seventh-

largest geothermal field in the world.

Contact CEO Dennis Barnes says, “With

two 83-MW steam turbines, the plant has

been designed to make the best use of steam

and maximise capacity. A vast network of

pipes connects Te Mihi to the Wairakei steam

field, increasing overall efficiency and gen-

eration reliability.”

Te Mihi consists of two Toshiba mixed-

pressure units and began generating in 2013.

It is located near the center of the current

Wairakei production field, at high elevation

(about 400 meters above sea level), which as-

sists reinjection, gas dispersion, and cooling

tower performance.

Originally conceived as a three-unit re-

placement for the elderly Wairakei plant, Te

Mihi was built as a two-unit plant with space

for a future third unit. Steam that was original-

ly conceived for use in the third Te Mihi unit

is supplied to Wairakei, which remains in ser-

vice, albeit operating at a lower than previous

load. This development strategy has met the

required environmental performance improve-

ments at lower cost than full replacement and

offers a future potential path for renewal.

The original Wairakei power station began

operation in 1958, so some key parts of the

plant are more than 50 years old. Increas-

ing maintenance and refurbishment require-

ments, and the expectation that continued

operation using river water for cooling will

not be possible, suggest that it is nearing the

end of its useful life and is unlikely to run be-

yond 2026, when its current suite of resource

consents expire, according to Barnes.

Yet, the Wairakei steam field as a whole is

predicted to be able to supply steam for elec-

tricity generation for many more decades. To

enhance the use of this renewable energy re-

source, Contact developed Te Mihi.

Te Mihi added 574 GWh per year compared

to Wairakei. Other benefits include higher effi-

ciency due to lower steam transmission losses,

superior location, better energy utilization

using dual-flash technology, and significant

reduction—over time—in cooling water dis-

charges into the Waikato River.

Ngatamariki. The 82-MW Ngatamariki

Power Station, less than two years old, is the

world’s largest single-site binary geothermal

power plant (Figure 4). The plant, built under

a NZ$142 million supply and engineering,

procurement, and construction contract by

Ormat Technologies, features Ormat energy

converters that are directly fed by a high-

temperature (193C/380F) geothermal fluid.

Previously, only steam turbines or geother-

mal combined cycle plants had been used.

In the case of Ngatamariki, 100% of the

exploited geothermal fluid is reinjected, re-

sulting in zero water consumption and low

emissions, minimizing the impact on the en-

vironment and with no depletion of the un-

derground reservoir.

Former MRP chief executive Doug Heffer-

nan said the plant near Taupo was completed

within the cost forecast detailed in the compa-

From Heat to Power

Electricity generation can only be under-

taken commercially in high-temperature

(roughly 193C/380F) geothermal fields.

The fluid collection and disposal system

for these developments is similar to those

for heat applications, consisting of:

■ Wells with multiple casings, typically

drilled to 2 to 3 kilometers deep.

■ Separators and associated water vessels—

large pressure vessels that separate the

phases through centrifugal action.

■ Pipes of various sizes for taking the

steam-water mixture from the wells to

the separators, then steam to turbines

or heat exchangers, or water to reinjec-

tion wells or to other heat exchangers,

and condensate to reinjection.

The main New Zealand geothermal pow-

er station designs include:

■ Simple back-pressure turbines.

■ Condensing turbines (potentially re-

ceiving steam at up to three different

pressures).

■ Binary cycle plants—essentially reverse

refrigeration cycles taking advantage

of the organic Rankine cycle. A more

recent innovation uses a working fluid

that is a mix of ammonia and water and

is known as the Kalina cycle.

Some research is being undertaken in

New Zealand on the use of Stirling en-

gines to generate electricity from geo-

thermal energy or waste heat sources,

according to Brian R. White of the New

Zealand Geothermal Association. White

says a number of the high-temperature

fields use a hybrid plant consisting of

back-pressure turbines discharging at

just above atmospheric pressure plus

a binary cycle plant to condense the

steam. A binary plant may also be used

to extract heat from brine.

2. World record holder. The 140-MW Nga Awa Purua Power Station near Taupo, New

Zealand, boasts the largest single-shaft geothermal steam turbine in the world. Courtesy: Kevin

McLoughlin, CEO, Credit Ringa Matau

3. Steamer. New Zealand’s 166-MW Te

Mihi Power Station was the 2013 POWER

Marmaduke Award winner. Courtesy: Steve

Boniface and Contact Energy

Page 52: Power magazine march 2015   international

www.powermag.com POWER | March 201550

RENEWABLES

ny’s prospectus and had proven performance

above design specifications in testing.

Then the largest of its type in the world,

Ngatamariki was, he said, “a milestone, and

with power output now expected to be 3 MW

(4%) higher than spec, shows what can be

done with such technology.”

Market SlowdownThe euphoria over Te Mihi and Ngatama-

riki was short-lived. The two plants were

welcomed by the energy market, with the

baseload generation they provided helping to

smooth out supply from more volatile renew-

able power sources such as wind. But flat de-

mand for electricity means power companies

have put further plans on hold.

In early 2007, when Contact announced plans

to invest up to NZ$1 billion in the construction

of two new geothermal power stations in the

Taupo region—one at Te Mihi and another at

Tauhara—demand for electricity was growing

strongly at around 2% per year, and New Zea-

land needed large amounts of new capacity to

power its growing economy. At the same time,

concern about the impact of climate change and

the need to reduce the level of greenhouse gas

emissions meant it was important that as much

new electricity generation as possible derived

from renewable sources.

But the slowdown in load growth has af-

fected generators across the board. Brian R.

White, executive officer at the New Zealand

Geothermal Association (NZGA), says, “I

think it will be quiet in New Zealand for a

while in terms of a wide range of geothermal

generation. My view is that in the immediate

future new geothermal generation will come

from the line [distribution] companies who

can see niche opportunities and don’t need to

build 100-MW plants.”

Another company to apply the brakes to new

development is MRP, which just 15 months

ago marked the completion and handover of

the Ngatamariki power station, expanding the

company’s geothermal production to more

than 40% of its total generation.

A year ago, Top Energy announced plans

to lodge a resource consent application in

2015 for additional Ormat binary power sta-

tions, very similar to the units currently at

Ngawha. The Ngawha field is the only high-

temperature geothermal resource in New

Zealand outside the Taupo Volcanic Zone and

is thought to be between 20 and 40 square

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4. Record holder. The 82-MW Ngatamariki Power Station, less than two years old, is the

world’s largest single-site binary geothermal power plant. Courtesy: Mighty River Power

Page 53: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 51

RENEWABLES

kilometers in area. The springs at Ngawha village are among the very

few external signs of the huge natural boiler buried deep below.

It was anticipated that these could start generating electricity as

early as 2020. “We’ve been conducting scientific research and mod-

elling . . . to understand how much geothermal resource might be

available,” Top Energy chief executive Russell Shaw says. “Although

we won’t know exactly what we have until we explore through test

drilling, we believe there could be enough resource for an additional

100 MW of energy.”

The original Ngawha geothermal power station opened in 1998

with a capacity of about 8 MW. An expansion was completed in 2008,

increasing it to 25 MW. The Ngawha Power Station was the first

power station to come into operation via a resource consent applied

for and issued under the Resource Management Act. It is owned and

operated by Top Energy and uses a binary cycle manufactured by Or-

mat Industries. Plant Manager Ray Robinson says the Ngawha plant

had “a complex resource consent. It’s subject to continual audit by

the Northland Regional Council and also to peer review by an inde-

pendent panel of environmental experts.” Such considerations add a

further dimension to developing geothermal power in New Zealand.

Many ambitious plans are currently on hold. Drilling and explor-

atory work scheduled for 2014 has been pushed back as part of a

series of cost-cutting measures Top Energy has had to implement as

a result of a softening New Zealand electricity market and a corre-

sponding drop in projected revenues from Ngawha. There are still

plans, however, to apply for its first resource consent with a view to

expanding the existing 25-MW station by 50 MW in two stages.

Economic Conditions Prompt Developers to Look AbroadSince 2013 the hiatus in construction of geothermal capacity due to

flat demand growth has prompted developers to shift their focus. New

Zealand geothermal operators are concentrating instead on sustaining

and maintaining existing developments, looking to share experience

by partnering in international developments, and investigating some

new prospects.

Greg Bignall, coauthor of a paper to be presented at the upcoming

World Geothermal Congress in Melbourne, Australia, and senior scientist

at GNS Science, says several New Zealand companies have invested sig-

nificantly in large-scale industrial direct geothermal energy applications

in the past five years. They include Ngati Tuwharetoa Geothermal Assets

Ltd. supplying the Svenska Cellulosa Aktiebolaget tissue mill at Kawerau

and Tuaropaki supplying clean steam generated from geothermal energy

to the Miraka milk powder processing plant at Mokai.

Despite these new developments, there has been a reduction in

geothermal direct use overall since 2010, primarily a consequence

of Norske Skog Tasman closing one of the paper production lines at

its Kawerau facility in January 2013. “There is more that needs to be

done in New Zealand to further foster direct geothermal heat use, and

the uptake of geothermal heat pumps,” Bignall says.

Developers also are responding to the downturn by setting their

sights offshore. MRP for example, is now applying its geothermal

expertise in Chile and in the U.S. through EnergySource.

Geothermal Investment and Cost TrendsA steep increase in geothermal investment that took place in New Zea-

land about 10 years ago looked set to continue and was sustained until

the middle of 2014. On the whole, investment in the past five years has

been similar to the previous five years but has shifted from the state-

owned MRP to the publicly listed Contact Energy, although both com-

panies and a range of others have been active throughout the period.

There has also been significant investment in large industrial di-

rect heat projects in the past five years, as well as in geothermal heat

pumps and smaller direct heat applications, but data on such uses is

difficult to obtain.

Another indication of investment activity is well drilling, with well

costs being a substantial, and growing, proportion of total project

costs, whether for electricity generation or heat supply. There is a

startling contrast between efforts in earlier decades—when drilling,

exploration, and development were controlled by the New Zealand

government—and the past decade, during which these efforts have

been driven by market conditions and a combination of public and pri-

vate investment. Recent drilling efforts have exceeded those of former

years in both number of wells drilled and diversity of fields in which

drilling has been undertaken. Recent wells are generally deeper and

larger in diameter than early wells, and so are more costly.

There have been reports of significant drilling cost increases out-

running inflation, but rising costs are also said to be attributable to

changes in well design and construction methods. Basically, invest-

ment has been enabled on fields that were previously investigated by

the New Zealand government, and the heritage exploration data has

facilitated additional investigation activities, leading in some cases to

further drilling and field development.

Each project will have its own peculiarities with respect to concept

and cost, the costs being highly dependent on the nature of the res-

ervoir (especially temperature and productivity of wells). The scale

of development has less effect on the cost/MW installed. Given that

most future developments will be of a larger scale, typical investment

will be on the order of NZ$4/MW installed. With approximately

1,000 MW of viable, consentable generation, this indicates upcoming

investment of the order of NZ$4 billion. ■

—Chris Webb (www.bluegnumediasolutions.com) is a freelance energy journalist based in Auckland, New Zealand.

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Page 54: Power magazine march 2015   international

www.powermag.com POWER | March 201552

FUELS

Nuclear Industry Pursues New Fuel Designs and TechnologiesEnriched uranium, the most commonly used fuel in commercial nuclear re-

actors worldwide, has many well-known advantages; however, recent events have underscored its disadvantages. Can new fuel technologies be developed and proven effective fast enough?

Kennedy Maize

Late last year, Japanese engineers and

technicians accomplished a major mile-

stone nearly four years after the most

damaging light-water reactor accident in

history at the Fukushima Daiichi nuclear sta-

tion. They removed the last of the undamaged

fuel rods from the devastated Unit 4 reactor

building, some 1,500 assemblies stored in a

pool above the reactor (Figure 1). Hydrogen

explosions shortly after the Mar. 11, 2011,

earthquake and tsunami nearly destroyed that

reactor, while it did destroy three others.

Removing the fuel from reactor 4 was the

easiest task related to the radioactive fuel at

the plant. Units 1, 2, and 3 suffered complete

fuel meltdowns. The New York Times com-

mented, “These reactors were so damaged—

and their levels of radioactivity remain so

high—that removing their fuel is expected to

take decades. Some experts have said it may

not be possible at all, and have called instead

for simply encasing those reactors in a sar-

cophagus of thick concrete.”

Among the advantages of nuclear power,

fuel is one of the more important. Uranium

packs a lot of punch and is widely available.

Atomic power plants offset high capital

costs with low fuel costs. But nuclear fuel

presents big challenges because of the enor-

mous amount of energy—and heat—packed

into a small package. Even when nuclear

fission stops, as happens in conventional

light-water reactors during a loss-of-coolant

accident, enormous heat remains. Nuclear

fuel rods can melt, in the worst case into a

glowing, radioactive blob in the bottom of

the reactor vessel.

The Pros and Cons of Zirconium CladdingConventional fuel—enriched uranium oxide

pellets in long rods encased in metal—offers

the first line of defense in a reactor accident.

Metal cladding housing the uranium is de-

signed to protect the fuel’s integrity while

emergency cooling equipment removes re-

sidual heat. AREVA explains on its website,

“Zirconium cladding is the reactor’s primary

safety barrier. Zirconium is the leading mate-

rial for nuclear fuel assemblies used in light

water reactors . . . because it is transparent

to neutrons, it has good temperature perfor-

mance, and it withstands corrosion.”

But experience has shown, first at Three

Mile Island (TMI) near Harrisburg, Pa., in

1979 and again, in spades, at Fukushima, that

this first line of defense can fail.

At TMI, as the events of a small loss-of-

coolant accident progressed, General Public

Utilities operators were confident that the

fuel would not melt. As fuel damage became

obvious, plant officials consistently underes-

timated the extent of the damage. According

to the written material accompanying the

TMI exhibit at the Smithsonian Institution’s

Museum of American History, plant officials

always took an optimistic view when trying

to understand the unfolding picture of the

fuel damage. In the end, it was clear that a

majority of the fuel had melted down and the

accident completely destroyed the core. Yet,

the conventional wisdom about the accident

is that the reactor experienced a euphemistic

“partial meltdown,” because less than 100%

of the fuel melted.

At Fukushima, there is no challenge to the

observation that the three reactors suffered

complete fuel melting. But that may not have

been the worst event in the accident. A 2013

news release from the Massachusetts Insti-

tute of Technology (MIT) observes that the

zirconium alloy cladding of the Fukushima

fuel played a major role in the events at the

multi-reactor site. Noting the series of spec-

tacular hydrogen explosions at the site, the

MIT release says that “hydrogen buildup was

the result of hot steam coming into contact

with overheated nuclear fuel rods covered by

a cladding of zirconium alloy, or ‘zircaloy’—

the material used as fuel-rod cladding in all

water-cooled nuclear reactors, which con-

stitute more than 90 percent of the world’s

power reactors. When it gets hot enough,

zircaloy reacts with steam to produce hydro-

gen, a hazard in any loss-of-coolant nuclear

accident.”

The Hunt for New Fuel Assembly OptionsMIT researchers are working on a ceramic

cladding for enriched uranium fuel pellets to

offer characteristics similar to zircaloy while

reducing the risks of hydrogen evolution “by

roughly a thousandfold.” MIT’s focus is on

silicon carbide (SiC). Mujid Kazimi, the

TEPCO (Tokyo Electric Power Co., owner

and operator of the Daiichi plant) professor

of nuclear engineering at MIT, who is lead-

1. Old fuel, new pool. This Nov. 22,

2013, photo shows a fuel rod removed from

the destroyed Unit 4 at the Fukushima Daiichi

nuclear station being moved to the common

pool elsewhere on the site. Courtesy: Tokyo

Electric Power Co.

Page 55: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 53

FUELS

ing the research team, said, “We are looking

at all sides of the issue, regarding replacing

the metal cladding with ceramic.” SiC, he

says, is “very promising, but not at the mo-

ment ready for adoption” (Figure 2).

According to Kazimi, SiC cladding has po-

tential advantages beyond reducing accident

risks. Because it reacts slowly with water,

says Kazimi, under normal conditions, SiC

should degrade less and remain in the core

longer than zircaloy, allowing operators to

squeeze extra energy out of the rods before

refueling. That would also reduce the amount

of spent fuel produced by the reactor.

Other industry teams are also looking at

ways to increase the accident tolerance of

reactor fuels. Last fall, an AREVA-led team

including the Tennessee Valley Authority,

Duke Energy, the universities of Wisconsin

and Florida, and the Department of Energy’s

(DOE’s) Savannah River National Laborato-

ry won a DOE contract to examine technolo-

gies to increase the tolerance of reactor fuel

to loss-of-coolant accidents. In a press re-

lease, AREVA said the researchers are focus-

ing on “coatings on the zirconium cladding,

additives to the uranium pellets as well as

modifications to the coolant loop.” AREVA

said it hopes to launch tests in commercial

reactors in 2022.

The Electric Power Research Institute

(EPRI) in 2011, responding directly to Fu-

kushima, started a program to examine “fuel

technology innovations for improving nuclear

plant safety by reducing hydrogen generation

and preventing core meltdown during severe

loss-of-coolant accidents.” EPRI is focusing

on molybdenum (Mo) as “a potential break-

through for meeting performance targets dur-

ing normal operations while maintaining fuel

integrity at temperatures exceeding 1500°C.”

EPRI says it is working on proof-of-concept

of dual cladding with “thin-wall Mo tubes

coated with oxidation-resistant layers of ei-

ther zirconium alloy or aluminum-coated

stainless steel,” as well as a three-layer de-

sign (Figure 3). EPRI says it hopes to expose

the new fuel assemblies to radiation this year,

“supporting in-plant demonstration within a

decade.”

The DOE is supporting multiple re-

search projects on new ways to clad fuel,

because of the safety advantages and for

the prospect of extended burnup of the

fuel. The DOE’s nuclear energy program

has been looking at ways to extend fuel life

in reactors for over 20 years. A 2008 paper

in Nuclear Engineering and Technology

described obstacles in extending the life of

conventional reactor fuel, which has a use-

ful life of around four years before removal

from the reactor. The article said, “To stay

competitive the industry needs to reduce

maintenance and fuel cycle costs, while en-

hancing safety features. Extended burnup

is one of the methods applied to meet these

objectives. However, there are a number of

potential fuel failure causes related to in-

creased burnup.” All of those are related to

problems with zircaloy cladding.

Apparently, some small progress is be-

ing made. In January, Westinghouse an-

nounced that its next-generation fuel,

called CE16NGF—the CE is for the Com-

bustion Engineering pressurized water

reactor (PWR) fleet—would be used at Ar-

izona Public Service’s Palo Verde Nuclear

Generating Station. It has also been used at

two other U.S. sites. Westinghouse, which

is a single-source global fuel provider for

PWRs, says the new fuel “incorporates

proprietary materials, such as advanced

cladding material and burnable absorb-

ers, and advances in structural design that

improve the fuel’s efficiency and reliabil-

ity while also increasing its service life.

CE16NGF provides improved economic

performance and greater operational flex-

ibility in fuel duty, thermal margin and up-

rate capability.”

Alternatives to Conventional TechnologiesAs researchers examine ways to make conven-

tional nuclear fuel safer and more economi-

cal, on a longer time scale, other scientists

are looking at ways to move away from light-

water reactor technology and the current fuel

cycle. In the U.S., the focus of this work has

been at the DOE’s Idaho National Laborato-

ry, traditionally the place where new reactor

designs have been tested, going back to 1951,

and at the DOE’s Argonne National Labora-

tory near Chicago, where reactors have long

been conceived and designed.

Argonne’s Mark Peters told The New York

Times, “There’s a whole class of reactor that

are not evolutionary concepts relative to what

you have out there now—they’re really dif-

ferent.” While there’s no market for these

designs today, that could change in 30 years

or so. “In a carbon-constrained world,” said

Peters, “with that time frame, you better

have some advanced reactors ready to go.”

2. Cross-section view of pro-posed silicon carbide cladding for nuclear fuel rods. The fuel pellets are in

the center, shown as a gray crosshatch. Then,

after a thin layer of inert helium gas, the three

layers of cladding are shown in black (solid

SiC), green (composite material made up of

SiC fibers infused with SiC), and blue (another

solid layer of SiC). Courtesy: Mujid Kazimi and

Youho Lee

3. Adding Mo protection. Fuel cladding incorporating molybdenum (Mo) offers one po-

tential technological pathway toward accident-tolerant nuclear fuel concepts. Courtesy: EPRI

Page 56: Power magazine march 2015   international

www.powermag.com POWER | March 201554

FUELS

(For a look at reactor designs under develop-

ment, see “THE BIG PICTURE: Advanced

Fission” in the November 2012 issue or at

powermag.com.)

Most of these advanced concepts are not

exactly new. Nuclear researchers have long

looked at liquid sodium as a reactor coolant,

because sodium has attractive characteristics,

including excellent heat transfer, a low melt-

ing point, and a high boiling temperature.

Using sodium coolant could provide ex-

tended fuel burnup. But sodium is inherently

dangerous, capable of burning or exploding

when exposed to water or air.

GE has put many years and millions of

dollars into its PRISM sodium-cooled, fast

neutron reactor design. TerraPower, a com-

pany with financial backing from Microsoft

founder Bill Gates, is designing a sodium-

cooled “traveling wave reactor” using de-

pleted uranium (U-238 left after enrichment

has removed much of the fissionable U-235),

optimistically projecting commercialization

in “the late 2020s.”

There is also widespread work on devel-

oping a fuel cycle based on the naturally

occurring element thorium. Bombarding

thorium with neutrons can transmute the

element into U-233, which does not occur

in nature and is fissile. The late nuclear

energy pioneer Alvin Weinberg long advo-

cated thorium reactors, because they cannot

melt down and do not produce plutonium,

used in weapons. The Atomic Energy Com-

mission experimented with thorium reactors

in the 1960s, but the technology lost out to

light-water reactors, as also occurred with

sodium-cooled reactors.

Thorium has its own set of inherent tech-

nical and economic problems, among them

the need to reprocess the irradiated thorium

to get the U-233. A 2012 article in the Bul-

letin of the Atomic Scientists claimed that a

thorium fuel cycle would be considerably

more expensive than the current uranium fuel

cycle and would “require too great an invest-

ment and provide no clear payoff.”

Research into the thorium fuel cycle con-

tinues. India has the most ambitious program.

India refused to sign the 1968 Nuclear Non-

Proliferation Treaty and exploded its own

atomic bomb in 1974, largely cutting itself

off from international assistance in devel-

oping a nuclear power program. The coun-

try has little indigenous uranium but lots of

thorium. That led India to explore a thorium

fuel cycle. The country is now getting inter-

national assistance for conventional light-

water reactors, but its interest in thorium has

not waned.

According to World Nuclear News, India

is building a 500-MW prototype thorium re-

actor, expected to be in operation this year.

This step, said the publication, will “set

the scene for eventual full utilization of the

country’s abundant thorium to fuel reactors.

Six more such 500-MWe fast reactors have

been announced for construction, four of

them by 2020.”

Less-ambitious thorium research and de-

velopment (R&D) efforts are under way in

Canada, China, Germany, Israel, Japan, Nor-

way, the UK, and the U.S. An article in The

Economist a year ago breathlessly touted the

thorium fuel cycle’s advantages as if they

were newly discovered. U.S. interest is re-

portedly at a very low level at the DOE. Sens.

Harry Reid (D-Nev.) and Orrin Hatch (R-

Utah) have pushed to revive the government’s

research into the liquid fluoride thorium reac-

tor, abandoned in the 1960s because it lacked

a military connection. Reid and Hatch have

repeatedly introduced legislation to revitalize

thorium R&D. Congress has shown no inter-

est so far. ■

—Kennedy Maize is a POWER contributing editor.

UDI Who’s Who at

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

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Page 57: Power magazine march 2015   international

March 2015 | POWER www.powermag.com 55

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POWER

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www.powermag.com POWER | March 201560

COMMENTARY

FERC’s Work on the Clean

Power PlanCheryl A. LaFleur

One of the most controversial issues facing the energy world today is how our electric sector will respond to the U.S. Environmental Protection Agency’s (EPA’s) proposed Clean

Power Plan (CPP). If finalized, the CPP would, under Section 111(d) of the Clean Air Act, require states to significantly reduce carbon dioxide emissions from existing power plants.

The Federal Energy Regulatory Commission (FERC) is not an environmental regulator, and is not tasked with writing the final rule—that is clearly the EPA’s responsibility. And FERC is not responsible for developing implementation plans—that is the states’ responsibility. But FERC will have an essential role to play as the CPP is implemented.

I believe that we as a nation can achieve real environmental progress, including on climate change, but only if we’re willing to build the infrastructure—both gas and electric—and adapt the energy markets to make that possible.

That is where FERC comes in. We will have responsibilities across three areas: infrastructure, markets, and convening and facilitating discussions about how to balance the core values of reliability, cost, and the environment.

Infrastructure DevelopmentFirst, I believe that additions to both gas and electric infra-structure will be needed to implement the CPP. In the case of interstate natural gas facilities, FERC is responsible for issuing permits—which includes performing environmental reviews—and setting rates.

Building block two of the CPP calls for substantially increas-ing the utilization of the natural gas plants that exist all around the country. I believe the CPP will also lead to construction of additional gas generation because it may be, in many areas, the most cost-effective way to meet the overall targets of the plan. But while new gas infrastructure will be needed, it is facing unprecedented opposition from local and national groups. Our nation is going to have to grapple with our acceptance of gas generation and gas pipelines if we hope to achieve our climate and environmental goals.

FERC’s responsibility under the Natural Gas Act is to consider and act on pipeline applications, ensuring that needed pipelines can be built safely and with limited environmental impact. Our work on gas infrastructure permitting is going to be essential to the successful implementation of the CPP. I am dedicated to ensuring that the process is fair, clear, timely, and transparent.

FERC is also going to have a role to play in facilitating the development of electric transmission that will need to be built to support compliance with the CPP. Building Block 3 of the CPP points to increasing reliance on location-constrained renew-able generation like wind and utility-scale solar that, because they are usually built far from population centers, are highly transmission-dependent.

Although electric transmission siting decisions are made at the state level, FERC is responsible for planning and setting rates for interstate transmission. FERC is working hard to help needed transmission get built by implementing our landmark Order No. 1000, which requires broad, transparent, and competitive trans-mission planning processes that explicitly consider public policy requirements, like state implementation plans under the CPP. These processes are intended to result in the most cost-effective projects, not just for one small area, but for an entire region and even between regions. We also ensure that needed lines are built at reasonable cost by balancing the needs of investors and consumers in approving fair rates and incentives.

Market AdaptationSecond, FERC will have a great deal of work to do to adapt whole-sale electric markets to the CPP. Regional capacity and energy markets incentivize investment and dispatch power over large regions based on cost. Both have made some limited adapta-tions to support state environmental preferences like renewable portfolio standards, but not always easily.

However, under the CPP, 49 states will develop individual implementation plans that will require changes in utilization of power sources. These plans may not be automatically compat-ible with the existing least-cost model. Regional cooperation will help markets make these adaptations, but that cooperation itself will require considerable change and compromise.

So FERC, the market operators, and stakeholders will have to work together to adapt the existing market model to sup-port the state plans while still delivering the benefits of competition. FERC will also need to continue to ensure that markets support investment in resources needed for reliabil-ity. Our fuel assurance order issued earlier this year is one example of this effort.

Honest BrokerFERC’s final job is to serve as an honest broker as work on the CPP is finalized and implemented. We are beginning this effort with a series of technical conferences to examine reliability, in-frastructure, and market issues tied to the CPP. Our objective is to hear from a wide range of entities about how compliance with the rule might impact them and to begin to prepare for the work FERC will need to do as compliance moves forward. We must also continue our engagement with agencies, especially the EPA and the states, to lend our expertise, share information, and provide constructive suggestions.

I am honored to be a part of FERC’s work, and look forward to continuing change, challenge, and progress on the nation’s energy and environmental aspirations. ■

—Cheryl LaFleur is chairman of the Federal Energy Regulatory Commission.

Page 63: Power magazine march 2015   international

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