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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
powerTHE
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CIRCLE 1 ON READER SERVICE CARD
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
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
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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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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
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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
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
IS YOUR POWER PROJECT A WINNER?
Find out by nominating it for a POWER award
All nominated projects must be in commercial operation by the nomination
deadline of April 30, 2015. You’ll find award information, lists of former winners,
and nomination forms at www.powermag.com/power-awards
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Coal Top Plant Award Winners
Prepare Your Plant for Cold Weather Operations
Boosting Combustion Turbine Response
Getting New Hydro Projects Built
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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4. High power. The Red Hills Renewable Energy park, under de-
velopment at a site in southwest Utah and shown here in this photo
mock-up, will comprise 325,000 solar photovoltaic modules. Courtesy:
Scatec Solar
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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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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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CIRCLE 8 ON READER SERVICE CARD
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
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ou
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Gas in
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
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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
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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
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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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
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.
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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
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
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
The management of thermal and renewable assets requires numerous services to maintain
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CIRCLE 13 ON READER SERVICE CARD
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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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.
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WATER & PROCESS SOLUTIONS
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OW
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14
CIRCLE 14 ON READER SERVICE CARD
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.
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.
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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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.
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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
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.
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)
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
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.
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
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.
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.
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
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
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
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
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
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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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
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
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
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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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.
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
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,
visit us online at UDIDATA.COM or contact the UDI Editorial
team at [email protected].
The 2014 UDI Who’s Who Directory covers more than 4,500 U.S. and Canadian generating plants. The directory provides:
• Nearly 8,100 plant management and support contact names, titles, and primary job functions.
• Basic plant operating statistics for more than 1,500 power stations, including:
Generation (MWh)
Availability (%)
Heat rate
Capacity Factor (%)
• Power plant design characteristics
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March 2015 | POWER www.powermag.com 55
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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.
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