march 2013

Vol. 157 • No. 3 • March 2013

Leveraging Low-Grade

Fuels

Rethinking the Cost of WindReverse Engineer Steam BladesHeater Drain Piping Pitfalls

01_PWR_030113_Cover.indd 1 2/19/13 11:59:09 AM

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ONE SMALL WESTINGHOUSE REACTOR

Another giant step by the true leader in commercial nuclear energy

Westinghouse, the world leader in the development, licensing and

deployment of commercial nuclear energy plants, is again leading the

industry, this time with a 225 MWe integrated pressurized water reactor

that can generate electricity for a residential community of 180,000

homes without emitting any greenhouse gases.

And unlike other designs, the Westinghouse Small Modular Reactor

(SMR) is an outgrowth of proven, land-based nuclear reactor technology

that takes safety, reliability and constructability to unsurpassed levels.

To make this exciting new reactor a reality, Westinghouse, with the

full support and backing of its majority owner Toshiba Corporation,

is working with a distinguished group of partners, notably Ameren

Missouri, the Association of Missouri Electric Cooperatives, Associated

Electric Cooperative, Inc., � e Empire District Electric Company,

Kansas City Power & Light Company and the Missouri Public Utility

Alliance.

Proud of our track record of success, but always looking to the future,

Westinghouse nuclear technology will help provide future generations

with safe, clean and reliable electricity.

Check us out at www.westinghousenuclear.com

CIRCLE 1 ON READER SERVICE CARD

March 2013 | POWER www.powermag.com 1

ON THE COVERThe Solid Waste Authority of Palm Beach County has burned about 2,000 tons per day of refuse-derived fuel to produce renewable electricity in its Palm Beach Renew-able Energy Facility Unit 1 for more than 20 years. Unit 2, now under construction on an adjacent site, will process up to 3,000 tons of municipal solid waste per day. The Babcock & Wilcox Power Generation Group Inc. won the design, build, and operate contract for the 95-MW plant, along with consortium partners KBR Inc. and CDM Constructors Inc. The new project is slated for completion in May 2015. Courtesy: KBR Power & Industrial

COVER STORY: FUELS24 Techno-Economic Considerations When Using Low-Grade Coal for Power

Generation“Cheap” fuel is only economic if all the other variables fall in line. That’s the les-son for coal-fired plants anywhere in the world using mine-mouth or other low-grade coals. Here’s how to assess the main factors, including boiler technology, plant-mine relationship, transportation options, and more.

30 Expanded Honolulu WTE Plant Delivers Triple Benefits for OahuFor island grids without local fossil fuel resources, “waste not, want not” is more than an aphorism—it’s an operating principle. On Oahu, a recently ex-panded waste-to-energy plant turns trash into power while minimizing the acre-age needed for landfills on the scenic island and saving the utility millions in avoided fuel import costs.

36 Why Aren’t Construction and Demolition Wastes Considered Biomass Fuel?It’s wood. It’s renewable. It’s widely available. Yet construction and demolition waste—even after it has been processed to remove contaminants—is not clas-sified as biomass by the U.S. Environmental Protection Agency. That determina-tion is letting a lot of potential fuel literally go to waste.

SPECIAL REPORT

WATER TREATMENT

40 Selecting a Combined Cycle Water Chemistry ProgramCombined cycle gas turbine plants are the new darlings of the power generating industry, but caring for them requires carefully selecting the right water chemis-try regime for a specific plant configuration and plant staff. Here’s your guide to the pros and cons of each approach.

Established 1882 • Vol. 157 • No. 3 March 2013

Power in Mexico“The Spotlight on a Mexican Success Story,” a sponsored report from Global Busi-

ness Reports, finds Mexico poised to become one of the top 10 most powerful

economies in the world, and its power sector—a complicated mix of private sec-

tor participation and public ownership—is fueling its growth. Developing more-

robust gas and renewables infrastructures is high on the to do list. (After p. 46.)


www.powermag.com POWER | March 20132

FEATURES

EMISSIONS

62 Rethinking Wind’s Impact on Emissions and Cycling CostsWind power generates zero emissions. On that there’s no debate. But zero emis-sions doesn’t necessarily mean zero impact on overall emissions. Just how much effect wind capacity has on emissions and the cycling of other generation sources is something that researchers and utilities are examining.

PLANT DESIGN

67 Steam Turbine Blade Reverse Engineering, Upgrade, and Structural DesignThis detailed look at the process of reverse engineering includes a case study that describes a developed engineering approach to designing and upgrading a steam turbine blade from an existing part.

DEPARTMENTS

SPEAKING OF POWER6 Should the U.S. Export Natural Gas?

GLOBAL MONITOR

8 Nations Agree to Legally Binding Instrument to Curb World’s Mercury Emissions

10 THE BIG PICTURE: Stretching the Pipeline

11 Despite Pollution-Curbing Efforts, Dense Smog Covers Wide Swath of China

12 Hungary Inaugurates Subsurface Repository for Nuclear Plant Waste

FOCUS ON O&M16 How to Avoid Feedwater Heater Drain Design Pitfalls

LEGAL & REGULATORY22 Align Generation Reliability and Firmness of Fuel Supplies

By Barbara S. Jost, partner, Davis Wright Tremaine LLP

71 NEW PRODUCTS

COMMENTARY76 Biogas: An Alternative Energy Source

By Sarah K. Walls, partner, Cantey Hanger LLP

Get More POWER on the WebOnline, associated with this issue (on our homepage, www.powermag.com, during the

month of March, or in our Archives any time), you’ll find these web exclusives:

■ Brazil Drought Threatens Power Supplies

■ Japan Banks on LNG

■ POWER Digest, a selection of recent global power industry deals

■ “Too Dumb to Meter, Part 9” with “Uranium Rush and the New ’49ers” and “Naked

Shorts at Westinghouse”

And remember to check our What’s New? segment on the homepage regularly for just-

posted news stories covering all fuels and technologies.

Connect with POWERIf you like POWER magazine, follow us online (POWERmagazine) for timely industry news

and comments.

Become our fan on Facebook Follow us on Twitter

Join the LinkedIn POWER magazine Group

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SPEAKING OF POWER

Should the U.S. Export Natural Gas?

Controversy concerning natural gas exports flared the day the U.S. Ener-gy Information Administration (EIA)

released its estimate that U.S. natural gas exports could begin in 2021. The EIA’s analysis was revealed in the early release of its Annual Energy Outlook (AEO) 2012, made public in December 2011. The EIA’s analysis also found “increased natural gas exports lead to higher domestic natural gas prices.” As the saying goes, it’s the second-worst problem we could have.

Surprising many, the recent AEO2013 Early Release (Dec. 5, 2012) adjusted the EIA’s initial date of export estimate, pushing it up from 2021 to 2016. The magnitude of natural gas production and potential export remains staggering, and proven reserves continue to sharply rise each year. However, there is a wide gulf between proven natural gas reserves and actually building liquefied natural gas (LNG) export terminals.

Almighty DollarOn one side are environmentalists, mem-bers of Congress, and even a newly formed industry group that have come together to oppose the construction of new export terminals, although for distinctly different reasons. The American Public Gas Associa-tion, along with Alcoa, Celanese Corp., Dow Chemical, Eastman Chemical, Huntsman Corp., and Nucor Steel recently formed the coalition America’s Energy Advantage. The lobbying organization’s purpose is obvious-ly to appeal to government to limit natural gas free trade to protect member markets and balance sheets. Hypocritically, the members expect to continue unobstructed free trade of the chemical and metal com-modities they produce. Jack Gerard, head of the American Petroleum Institute, called the coalition “seriously misguided.”

On the other side are developers wish-ing to build new export terminals—and more members of Congress. The Depart-ment of Energy (DOE), under Section 3 of the Natural Gas Act, must grant a permit for natural gas exports to countries that have entered into a free trade agree-ment (FTA) with the U.S., like Mexico and Canada. Those agreements are de jure in

the public interest. Projects that involve non-FTA countries, such as Japan and EU nations, require the DOE to make a public interest determination. There are currently 17 applications for non-FTA LNG export terminals in the DOE review queue, with only a single project approved so far.

The problem facing the DOE is rational-izing the process for determining “public interest.” The DOE began by subcontract-ing the analysis to the EIA, its energy statistics organization. In January 2012, the EIA released its report, “Effect of In-

creased Natural Gas Exports on Domestic Energy Markets.” That report’s conclu-sions, limited by the lack of a global mac-roeconomic model for LNG exports, failed to answer the question.

Exports Are a Net BeneitThe DOE’s second effort was to subcontract the work to NERA Economic Consulting. NERA’s report, “Macroeconomic Impacts of LNG Exports from the United States,” re-leased in early December 2012, focused on international natural gas market factors and macroeconomic impacts on the U.S. econo-my that result from LNG export expansion.

NERA’s study found that under each of the 63 scenarios studied, the U.S. would enjoy a net positive economic impact from LNG exports to non-FTA countries, and those benefits increase with increasing LNG exports. “LNG exports have net eco-nomic benefits in spite of higher domes-tic natural gas prices,” according to the report. “This is exactly the outcome that economic theory describes when barriers to trade are removed.”

The biggest winners are obviously natu-ral gas producers that can sell their prod-uct at a higher price on the global market, particularly where competing natural gas supply prices are pinned to the market price of oil, such as in Europe. The report

identified the industries that will experi-ence “serious competitive impacts” as energy-intensive, particularly those that compete in global markets, like the mem-bers of America’s Energy Advantage. The DOE declined to endorse the NERA report results but said its conclusions will be in-cluded as part of its deliberations.

Several senators wasted no time in commenting on the NERA report conclu-sions. Sen. Lisa Murkowski (R-Alaska) noted, “It’s clear from the study that ex-porting LNG would be beneficial to the

U.S. economy, and the greater the level of exports, the greater the benefit.” Sen. Ron Wyden (D-Ore.), incoming chair of the Senate Environment and Natural Resources Committee and LNG export skeptic, called the NERA report “seriously flawed” in a letter sent to Energy Secretary Steven Chu on Jan. 10. He also used Dow Chemical as an example of an impacted company.

The NERA report concluded that job losses will occur but that they will be minor and will be absorbed by a com-mensurate increase in like jobs in other parts of the economy (ironically, the same logic used by “green power” proponents when speaking of fossil power industry job losses). Those who depend on government transfer payments (Social Security and the like) will always be the most vulnerable to energy price increases, the report noted.

Bravo to energy companies willing to invest billions in building the next generation of LNG export terminals, and a Bronx cheer to those companies lob-bying for trade barriers to prop up bal-ance sheets. Exporting natural gas may kick up the country’s GDP and overall economic activity, but the impact of importing energy dollars for a change is priceless. ■

—Dr. Robert Peltier, PE is POWER’s

editor-in-chief.

There is a wide gulf between proven natural gas reserves and actually building liquefied natural gas export terminals.

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

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

PENTAIR.COMCIRCLE 5 ON READER SERVICE CARD


Nations Agree to Legally Binding Instrument to Curb World’s Mercury EmissionsMercury emissions from power plants in 137 United Nations member countries could be subject to strict controls and reductions if an in-ternational treaty is signed by participating nations this October.

After wrapping up four years of complex negotiations to pre-pare a global instrument on mercury, governments of nations par-ticipating in the United Nations Environment Programme (UNEP) initiative on Jan. 19 agreed in Switzerland to the text of a legally binding instrument, which they called the “Minamata Conven-tion on Mercury.” The text of the convention, named after the Japanese city where serious health damage occurred as a result of methyl mercury pollution in the mid-20th century, will be open for signature at the Diplomatic Conference in Japan, from Oct. 7 to 11, 2013. It will become legally binding once 50 countries have ratified and agreed to be bound by it.

The fifth session of UNEP’s Intergovernmental Negotiating Com-mittee ended with governments including the U.S., European Union, China, and India agreeing to actions to reduce mercury emissions to the air from power plants and other sources, reduce the use of mer-cury in products and industrial processes, and address mercury supply and trade. The treaty would control mercury emissions and releases from large industrial facilities—including coal-fired power plants and industrial boilers, certain kinds of smelters (handling zinc and gold, for example), waste incineration, and cement clinker facilities.

It calls for the installation of “Best Available Technologies” for new power plants and facilities and would legally bind countries to implement plans that would bring emissions down from exist-ing ones. The plans for existing sources would take into account “national circumstances, and the economic and technical feasi-bility, and affordability of the measures,” within 10 years after the accord is ratified.

The negotiations, which were held over five sessions between 2010 and 2013, had initially sought to set thresholds on the size of the plants or level of emissions to be controlled, but with countries disagreeing on these specifics until the final week, the nations agreed to defer that decision until the first meeting after the treaty has been ratified.

Among its key aspects, the treaty would ban by 2020 the export and import of a range of mercury-containing products, including batteries, certain types of compact fluorescent lamps, and soaps and cosmetics. And it would require countries to cre-ate strategies to reduce the amount of mercury used by artisa-nal and small-scale miners, requiring countries with legal small gold-mining operations to develop national plans within three years of the treaty’s enforcement to reduce or eliminate their use of mercury.

UNEP: World’s Mercury Emissions May Be Rising after DeclineUNEP says that worldwide mercury emissions likely peaked in the 1950s to 1970s and then declined because of reductions from Eu-rope, Russia, and North America. Some indications show that emis-sions may be rising again, with increases from East Asia offsetting continuing reductions in Europe and North America, it warns.

According to the international institution’s “Global Mercury Assessment 2013,” a document that updates global releases and the environmental transport of mercury, an estimated 1,960 met-ric tons (mt) of mercury were emitted to the atmosphere in 2010 as a result of direct human activity. An updated inventory of emissions to air suggests that about 475 mt of mercury are emit-ted by coal combustion, compared with just 10 mt from combus-tion of other fossil fuels. More than 85% of the 475 mt estimated is attributable to emissions from coal burning for power genera-tion and industrial uses.

1. Quicksilver around the world. The United Nations Environ-

ment Programme (UNEP) estimates that global emissions of mercury

to air from a variety of human activities in 2010 totaled 1,960 metric

tons. This chart breaks down that total by region. The bulk of mercury

emissions in South America and Sub-Saharan Africa were released by

artisanal and small-scale gold mining practices, for which extensive

data gaps exist, UNEP admits. Source: UNEP

East & Southeast Asia, 40%

Sub-Saharan Africa, 16%

South America, 13%

South Asia, 8%

Commonwealth of Independent States

& other European countries, 6%

EU27, 6%

North Africa, 1%

Australia, New Zealand & Oceania, 1%

Middle Eastern States, 2%Central America & the Caribbean, 2%

North America, 3%

Region undefined, 4%

2. Anthropogenic mercury emissions by source. About

24% of the world’s anthropogenic emissions of mercury came from

fossil fuel combustion in 2010—mostly from coal—though the widely

varying mercury content of coal makes emissions estimates “highly

uncertain,” UNEP says. Estimated emissions of mercury from artisanal

and small-scale gold mining, the largest human-caused source, dou-

bled those reported in 2005—owing partly to the high price of gold and

increased emission estimates. Source: UNEP

Artisanal &

small-scale gold

mining, 37%

Chlor-alkali industry, 1%

Fossil fuel

combustion (power

& heating), 24%

Metal production (ferrous & nonferrous),

18%

Cement production, 9%

Other, 6%

Waste incineration, waste & other, 5%


But coal combustion isn’t the biggest source of the world’s mercury emissions, according to the report. It blames the informal sector of artisanal and small-scale gold mining for releasing a whopping 727 mt per year (mt/yr) to air. Artisa-nal gold miners, who often are poor, typically use mercury to create an amalgam separating gold from other materials, but they then have to separate the mercury from the gold. Though UNEP admits there are data gaps because collecting infor-mation about this sector is challenging owing to its widely dispersed and unregulated nature, it suggests the significant increase comes in large part from China, where the practice was banned in 1996.

Increases in Mercury Emissions from Power Plants Notable in AsiaThe report notes that coal combustion for power generation for industrial purposes continues to increase—particularly in Asia. But it also points out that air pollution controls at some power plants and stringent regulations have reduced mercury emissions from coal plants, “and thus offset some part of the emissions arising from increased coal consumption.”

Countries showing improvements include the U.S., where coal generators are rushing to meet the initial April 2015 compli-ance deadline for the Environmental Protection Agency’s (EPA’s) December 2011–promulgated Mercury and Air Toxics Standards (MATS). An agency Information Collection Request (ICR) from 2010 suggests that electric generating units emitted about 29 mt of mercury that year, but it extrapolates from a 2005 finding (because the ICR did not cover total U.S. anthropogenic emis-

sions) that 53 mt of the nation’s total 105 mt of mercury emis-sions came from electric generating units.

This claim—that power plants were responsible for 50% of mercury released in the country—was repeated in documents jus-tifying the EPA’s 2011-finalized MATS rule. The agency admitted, however, that power plants will emit 27 mt of mercury in 2016 even if MATS is not enforced, constituting 42% of the nation’s total of 64 mt of anthropogenic mercury emissions.

Meanwhile, UNEP explains the decrease from 53 mt in 2005 to 29 mt in 2010 in U.S. mercury emissions from coal plants as largely attributable to “new regulations that have resulted in changes in the sources of the coal that is burned in large power plants and the installation of mercury controls as well as controls on sulphur dioxide and particulates that have the co-benefit of further reducing mercury emissions.”

Anthropogenic mercury emissions from Asian power plants—particularly in China—are also expected to decrease because “many of the new coal-fired power plants have state-of-the-art pollution controls installed,” the report foresees. Stationary com-bustion of all fuels in Asia emitted about 622 mt per year, consti-tuting about 64% of the region’s total. According to the report, China and India dominate the region’s emission inventories, but a handful of Southeast Asian countries also contribute signifi-cantly to the total.

In 2005, China’s total mercury emissions from its power plants totaled about 108.6 mt. That number had fallen by 34 mt in 2008 with the enactment of mandates limiting sulfur dioxide emissions, which resulted in the installation of flue gas desufurization (FGD) technologies and the shutdown of smaller, inefficient units. A

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THE BIG PICTURE: Stretching the PipelineWorld natural gas demand climbed to 3,361 billion cubic meters (bcm) in 2011, increasing in all regions, with the exception of Europe. Countries with the largest volumetric gains in consumption were China (21.5%), Saudi Arabia (13.2%), and Japan (11.6%). North America, led by the U.S. (2.4%), became the second-largest consumer market after Asia-Pacific. In 2011, gas demand growth was accompanied by expanding international pipeline flows (which have increased about 3.7% per year since 2009) and inter-regional transport capacity. Here are some of the longest pipelines recently built as well as noteworthy ones in the pipeline. Sources: POWER, International Energy Agency, Cedigaz

–Copy and artwork by Sonal Patel, Senior Writer

CHINA’S WEST-EAST GAS PIPELINE PROJECT: Xinjiang Autonomous Region to Yangtze Delta and Pearl Delta Region (Phase I commissioned in 2004, Phase II, slated for 2014, Phase III, 2015)

ROCKIES EXPRESS PIPELINE: Colorado to Ohio(Commissioned 2009)

NORD STREAM PIPELINE: Russia to Germany (First line commissioned 2011, second line, 2012)

PLANNED PROJECTS

SOUTH STREAM PIPELINE: Russia to Germany This $16.89 billion project, which seeks to diversify Russian gas routes to Europe in reaction to repeated disputes with Ukraine, is expected to come online in 2018.

TRANS-SAHARAN GAS PIPELINE: Nigeria to Algeria Political disputes in Sub-Saharan Africa make this project's estimated commissioning in 2015 unlikely.

RECENT PROJECTS

NABUCCO PIPELINE: Turkey to AustriaCompeting projects could derail this $9.47 billion European Union-backed project that seeks to reduce European dependence on Russian gas. Completion slated for 2017.

GASODUCTO DEL NORESTE: Bolivia to Argentina

This $2.67 billion project could come online as early as 2016

ALASKA-TO-ASIA PIPELINE: Alaska North Slope to South Alaska

Several hurdles for this $65 billion project that seeks to liquefy and ship gas to Japan and South Korea have cleared, but it may not be ready for a decade or more given its scale, technical, legal, political, and financial barriers.

Phases I-III: 10,560 miles, 64 bcm/y

759 miles, 55 bcm/y

1,679 miles, 16.5 bcm/y

2,565 miles, 30 bcm/y


900 miles, 10 bcm/y

800 miles, capacity unknown

SAND HILLS PIPELINE: West Texas to East Texas

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720 miles, 30 bcm/y



UNEP technical briefing document also claims that by 2008, more than 95% of China’s myriad coal-fired power plants had installed electrostatic precipitators, and by 2009, 71% (about 460 GW) had installed FGD.

India’s mercury issues, on the other hand, are much more com-plex, suggests Dr. Lesley Sloss, who leads efforts by the Inter-national Energy Agency’s Clean Coal Centre to track and analyze the world’s mercury emissions. She says in an October 2012 study (funded by the U.S. State Department) that in the South Asian nation (which relied on high-mercury indigenous coal for about 70% of its heat and power production in 2007), coal combustion currently releases mercury emissions of about 40 mt/yr. By 2016, these emissions are expected to rise to 106 mt/yr and to more than 148 mt/yr by 2021. New laws could curb this output, Sloss notes, but the likelihood of nationwide mandates to curb mercury emissions “are small.”

Indian coal is low in sulfur, and sulfur dioxide emission lim-its have not been a priority—though a law exists that would require new coal plants over 500 MW to provide space on site to allow for the installation of FGD technology in the future. And India does not have nitrogen oxide emission limits, though emission limits introduced in 1981 have prompted many plants to be retrofitted with particulate control systems, mostly elec-trostatic precipitators.

Compared to India, several Southeast Asian countries have in-stalled, or are installing some of the most advanced combustion and pollution control systems available, Sloss says. About 80% of Indonesia’s 10 GW of coal-fired capacity has sulfur control

systems in place, for example. And in Thailand, where coal use is expected to increase by a factor of four by 2021, most coal plants have installed FGD and de-NOx systems.

“In many countries, mercury control is assumed to be ex-pensive—this misconception needs to be corrected with dem-onstrations of cost-effective mercury control options at real plants in Southeast Asia,” Sloss concludes. UNEP has produced an interactive process optimization guidance document (POG) that should help plant operators understand and maximize mer-cury reduction on a plant-by-plant basis, tools that along with expert workshops should be promoted throughout coal-heavy Southeast Asia, she recommends.

Despite Pollution-Curbing Efforts, Dense Smog Covers Wide Swath of ChinaFour bouts of dense smog described as the worst air pollu-tion in recent memory enveloped more than half of China in January, from the Beijing-Tianjin-Hebei triangle in the north of the country to Nanjing in the south, via the central city of Wuhan (Figure 3). In Beijing—which bore the worst of it—the U.S. Embassy’s monitoring station reported a peak of fine par-ticulates (PM2.5) of 755 micrograms per cubic meter (µg/m3), a level that is off the U.S. Environmental Protection Agency’s Air Quality Index (which is limited to 500 µg/m3). Chinese monitors reported peak PM2.5 levels of 993 µg/m3, which tre-mendously exceeded the nation’s freshly implemented 24-hour average standard for residential areas of 75 µg/m3 and is almost

When you own aSince 1968



40 times more than the World Health Organization’s 24-hour average standard of just 25 µg/m3.

Beijing is certainly no stranger to smog. Pollution episodes occur routinely; in July 2008, for example, the city forced half of private cars off the road to improve air quality in advance of the Olympic Games. But the smog that descended over the Bei-jing-Tianjin-Hebei area over the periods of Jan. 6–8, Jan. 9–15, Jan. 17–19, Jan. 22–23, and Jan. 25–31 have been described as “much more extreme” and of a longer duration. The Beijing Meteorology Bureau attributed the spike at its worst—between Jan 10 and 13—to “very poor” conditions of dispersal. “With low pressure at the surface, wind speeds fell, humidity increased and an inversion layer formed, causing pollution to accumulate,” a spokesperson said. “It was as if someone had put a lid on the city,” the China Dialogue commented.

Research results issued by the Chinese Academy of Sciences (CAS) in early February suggested that surging fine particulate contributions in January were caused almost 25% by vehicle emissions, 20% by coal combustion, and the remainder by “cook-ing.” Wang Yuesi, a CAS researcher under a group that studies haze causes and control, called for a focus on limiting industrial

pollution and improving the process of coal burning—enhancing desulfurization, denitration, and dedusting in the combustion process. Dust from construction sites should also be brought un-der control, and more attention should be given to emissions from diesel-powered cars and to fuel quality, he said.

Other experts have gone further, calling for a coal consump-tion cap policy that would limit the growth of coal usage in air pollution areas. Many cite a recent World Research Institute pa-per that estimated there are proposals to build up to 558 GW of new coal-fired capacity in China—representing a 73% increase in the energy-intensive nation’s 2011 thermal power capacity. Com-pared with other Chinese cities, Beijing’s record on replacing coal with cleaner substitutes is sound, however: In 2012, it slashed its coal consumption by 700,000 metric tons.

On the renewables front, China as a whole has also made gains. It has established a goal of increasing its use of nonfossil energy to 15% of primary energy consumption by 2020, and greatly in-creased wind power over the last several years (see “Renewable Energy Development Thrives During China’s 12th Five-Year Plan” in our December 2012 issue). Meanwhile, the central Ministry of Environmental Protection has already begun planning coal con-sumption cap pilots for the Beijing-Tianjin-Hebei, the Pearl River Delta, Yangtze River Delta, and Shandong city cluster as part of its “12th Five-Year Plan for Air Pollution Prevention and Control in Key Areas.” That document also sets targets for reduction of key pollutants by 2015, such as reducing PM 2.5 in the Beijing-Tian-jin-Hebei region and the Yangtze and Pearl River Deltas by 5%.

Over the short term, Beijing and other cities are developing air pollution emergency response measures, such as those taken by Beijing’s Municipal Bureau of Environmental Protection in Janu-ary. During the four intense bouts of smog, Beijing suspended work at 28 construction sites, clamped down on emissions from 58 factories (that reportedly reduced particulate emissions by 30%), and took 30% of government vehicles off the road.

The haze, which made international headlines, will require longer-term solutions, Li Keqiang, who will replace Wen Jia-bao as premier in March, admitted in a state radio broadcast in January. Li, the most senior official to comment on the situation to date, applauded a mandate from China’s Ministry of Environmental Protection that requires 74 major cities to monitor and publically report data for particulates and other pollutants based on new air quality standards that came into effect on Jan. 1. He also highlighted China’s efforts to regu-late industry, specifically through two new regulations pro-mulgated in February 2012 (after public outcry) that revised ambient air quality standards, including PM2.5, and developed a new definition of China’s Air Quality index. “Pollution is not a problem that emerged only a few days ago—it’s a long-term issue, and fixing it will take a long time. But we need to do something about it,” he said. “Production, construction, consumption cannot come at the price of hurting the environ-ment.”

Hungary Inaugurates Subsurface Repository for Nuclear Plant WasteConstruction of a $310 million repository about 250 meters below Earth’s surface for low- and intermediate-level radioactive waste from the operation and future decommissioning of Hungary’s power plants reached a significant milestone at Bataapati. Inau-gural ceremonies for the National Radioactive Waste Repository (Figure 4) were held last December, opening the first disposal chamber that will hold 4,600 drums of radioactive waste in 510

3. In a haze. As residents of Beijing and many other Chinese cities

were warned to stay inside in January due to the worst periods of air

quality in recent history, NASA’s Terra satellite captured this image from

space on Jan. 14. It shows extensive haze, low clouds, and fog over

northeastern China, when fine particulates peaked at 755 micrograms

per cubic meter in Beijing. “The brightest areas tend to be clouds or

fog, which have a tinge of gray or yellow from the air pollution. Other

cloud-free areas have a pall of gray and brown smog that mostly blots

out the cities below,” NASA says. In areas where the ground is visible,

some of the landscape is covered with lingering snow from previous

storms. Source: NASA

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reinforced concrete containers. More chambers are to be built to eventually accommodate 40,000 cubic meters of waste.

The facility is being built by the Public Limited Company for Radioactive Waste Management (Radioaktív Hulladékokat Ke-zelo Kft., RHK Kft), formerly the Public Agency for Radioactive Waste Management (PURAM). The state-owned body carried out site investigations for more than 10 years before finally focus-ing on building the repository in granite in the south of the country. The government accelerated licensing of the facility in 2006, and surface facilities for the repository were opened in October 2008.

Hungary has four nuclear reactors that generate about 43% of its power (about 30% is generated with gas, 18% with coal, and the remainder is imported from its neighbors, mainly Slovakia). All four of its reactors, housed at the Paks Nuclear Power Plant, are Russian-designed VVER-440s that first gener-

ated power in the 1980s. Paks Units 2, 3, and 4 are scheduled to be closed between 2014 and 2017 (though the Hungarian Parliament has approved 20-year extensions for all the units). Paks 1’s license was extended to 2032.

The March 2009 approval for a new nuclear plant by the Hun-garian Parliament has prompted Paks to consider building two new 1-GW reactors at the Paks site. A decision is expected this year, and possible contenders for the tender are AREVA’s EPR, the Atmea1, Atomstroyexport’s VVER-1000, Westinghouse’s AP1000, and South Korea’s APR-1400.

According to the International Atomic Energy Agency, at the end of 2010, a global radioactive waste inventory reported that there were approximately 61.4 million m3 of short-lived, low- and intermediate-level waste (LILW–SL), 13.9 million m3

of long-lived, low- and intermediate-level waste (LILW–LL), and 423,000 m3 of high-level waste (HLW). Disposal facilities for low-level waste were operational or under construction in sev-eral countries, including Belgium, Bulgaria, the Czech Repub-lic, France, India, Japan, Lithuania, Norway, Romania, Slovakia, Spain, and the UK.

A LILW disposal complex similar to the one at Bataapati is un-der construction at Gyungju, in the Republic of Korea. That facil-ity began in 2010 accepting the first 1,000 drums of waste from the twin-reactor Ulchin nuclear plant for outdoor storage until the $730 million underground repository can be commissioned in mid-2014. The completed repository is expected to have a num-ber of silos and caverns about 80 meters below the surface with an initial capacity of about 100,000 drums. ■

—Sonal Patel is POWER’s senior writer.

4. Burying waste. Hungary’s National Radioactive Waste Reposi-

tory at Bataapati, a facility that will eventually hold all low-level and

intermediate radioactive waste from the country’s four nuclear power

plants, was inaugurated in December. Courtesy: PURAM

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How to Avoid Feedwater Heater Drain Design Pitfalls

Feedwater heaters are used to preheat boiler feedwater by condensing steam extracted from several stages of the steam turbine. Feedwater heaters enhance the thermal efficiency of the power plant by reducing the amount of fuel burned in the boiler to produce a specified power. At the same time, the steam energy extracted from the turbine by the feedwater heater helps to reduce the rate of energy rejection to the en-vironment via the condenser.

Steam extracted from the turbine for feedwater heating is con-densed on the shell side of the feedwater heater. The hot conden-sate collects in the shell and drains to the next lower pressure heater or condenser. A level control valve and piping maintains the proper condensate level in the shell. The condensate level control in the heater shell is very important. High condensate levels can adversely affect steam turbine operation, while low levels can cause steam blow-through, damaging the heater inter-nals and drain piping.

This article explores the complexities and key issues associ-ated with selecting the proper pipe sizing/layout and control valve design that must control hot condensate flow from the feedwater heaters. The biggest challenge occurs when hot con-densate flashes to steam as pressure decreases in the drain pip-ing. The flashed steam produces a two-phase flow mixture that can restrict flow in the drain system and thus upset operation of the heater shell level control. The flashed steam can also erode the control valve internals and drain piping.

Complex Heater Design

The feedwater heater shell can comprise up to three separate zones within the shell: the desuperheating, condensing, and drain cooling zones. First, the incoming superheated steam en-ters the optional desuperheating zone, where it is reduced in temperature until reaching saturated conditions. Next, the steam enters the condensing zone, where the saturated steam changes state, at the saturation temperature, to become saturated liquid. Finally, steam condensate enters the optional drain cooling zone, where it is subcooled below the saturation temperature by the incoming feedwater.

In multizone heaters, the normal heater drains are con-nected to the outlet of the drain-cooling zone and therefore are capable of handling subcooled condensate. The normal drains are routed through a level control valve to the next lower pressure heater, which also improves the cycle effi-ciency. In contrast, emergency drains are typically connected to the condensing zone, where they discharge condensate at saturated temperature and pressure conditions through a sep-arate line and level control valve directly to the condenser. The drains from the lowest high-pressure (HP) heater in the typical Rankine cycle are routed to the deaerator.

Many Complex Calculations

Maintaining the proper condensate level in the heater shell is critical. Therefore, the heater drain level control valve and piping system must be adequately designed to discharge the hot condensate flow across the specified operating range of the plant. Guidance and commentary on how to complete a successful design is provided in the remainder of this article.

See the sidebar “Step-by-Step Calculation Procedure” for a summary of the discrete calculation steps described in the article.

Review Drains from Feedwater Heater to Level

Control Valve

The drain piping upstream of the level control valve should be designed to handle single-phase condensate without steam flash. For proper operation, the drain should be adequately subcooled to prevent steam flashing when line pressure de-creases due to frictional pressure drop or elevation change (upward-rising pipe). The frictional pressure drop is mini-mized by using guidelines such as the Heat Exchange Insti-tute (HEI) criterion of heater nozzle velocity not exceeding 4 ft/sec at operating temperature. However, the velocity-based

Step-by-Step Calculation ProcedureThe main text describes the calculations and their sequence

in much detail. The following is a step-by-step guide that

will be useful to those wishing to develop an Excel spread-

sheet or for those who merely desire an overview of the cal-

culation process.

Step 1. Gather the required inputs:

■ Upstream/downstream heater pressures

■ Condensate flow rate and supply temperature

■ Pipe size and length/orientation for piping upstream/down-

stream of control valve

Step 2. Calculate critical pressure at the exit of the control valve.

Step 3. Check critical pressure against the saturation pres-

sure and the downstream heater pressure to establish the cor-

rect exit pressure for pressure gradient calculations and to

establish single-phase or two-phase flow in piping downstream

of the control valve.

Step 4. Calculate piping resistance (K + f L/D) for the piping

segment downstream of the control valve, working backwards

from the downstream heater.

Step 5. Assume value for control valve outlet pressure (P2)

downstream of control valve with the calculated exit pressure

and input the associated fluid properties in the modified Ber-

noulli equation.

Step 6. If the right-hand side of the modified Bernoulli equa-

tion matches the left-hand side, then the assumed value of P2

is correct. Otherwise, change the value for P2 and repeat until

the correct value for control valve outlet pressure is obtained.

Note that the value for P2 will change as the downstream piping

resistance (K + f L/D) changes.

Step 7. Ensure that control valve inlet pressure is calculated

using conventional single-phase flow line pressure drop.

Step 8. Once control valve inlet/outlet pressures are es-

tablished, the control valve datasheet can be filled out for

the vendor to supply a suitable valve for flashing/cavita-

tion service.

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design approach should be verified and revised, if necessary, by ensuring that line pressure after elevation and frictional change does not drop below the saturation pressure.

The pressure loss caused by increasing elevation (upward-rising pipe) is ideally minimized by placing all HP heaters side by side on the same elevation in the plant and the low-pressure (LP) heaters side by side on a lower elevation. However, the deaerator must be installed at a much higher elevation because of the boiler feed pump’s net positive suction head requirements. Therefore, when the lowest HP heater drains to the deaerator, the drain line pressure change due to elevation becomes significant. For example, the low-est pressure HP heater must drain from a low elevation (say, 7 meters) to the deaerator at a higher elevation (say, 30 meters), thus making the elevation difference (30 – 7 = 23 meters) very significant.

Elevation differences are particularly important at part-load operation, when the differential operating pressure between the HP heater and the deaerator decreases. In this case, the level control valve should be located so that the line pressure does not drop below the saturation pressure for all operating cases upstream of the level control valve. Otherwise, the control valve flow capability will be significantly reduced and the potential for erosion in the piping system will increase.

Calculate Pressure at Drain Piping Exit Downstream

of Level Control Valve

The drain piping downstream of the level control valve can han-dle single-phase flow or two-phase flow, or the initial part of the drain flow can be single phase, changing to two phase farther downstream.

In all cases, the pressure drop in the piping can include sig-nificant static head, which must be considered in determining the control valve outlet pressure (P2). Of course, the static head is much larger for single-phase flow due to the presence of the fully liquid column downstream of the control valve.

Single phase is promoted by subcooling condensate in the upstream heater drain cooler. In drain piping downstream of the control valve, single-phase flow is indicated when critical exit pressure is found to be higher than the saturation pressure.

The pressure in the drain piping exit downstream of the con-trol valve depends on whether this section has single-phase,

1. Go with the flow. A typical feedwater heater with condensate

drain lines is shown. Courtesy: Bechtel Power Corp.

Steam in

Condensate

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two-phase nonchoked, or two-phase choked flow. The critical pressure at the exit is required to determine if the flow is choked or nonchoked.

Technical literature provides several methods for calculating this critical pressure. One useful methodology is based on the homogeneous equilibrium model (HEM) for two-phase flow and involves simultaneous solution of energy and momentum con-servation equations. That is the approach used for calculating critical pressure in this article.

This critical pressure at the exit (Pce) corresponds to choked flow at the downstream heater inlet based on pipe diameter, flow rate, and saturation pressure (Psat) of the fluid at the temperature it leaves the upstream heater. As discussed below and shown in Figure 2, Pce can then be compared against Psat

and against the downstream heater pressure (P2dh) to select the correct pressure at the exit.

Once the pressure at the exit is determined, the pressure gradient is calculated working backwards from the drain pip-ing exit at the downstream heater toward the level control valve outlet, considering single-phase flow or two-phase flow (using HEM), as applicable.

There are three scenarios to be considered when determining the end receiver inlet pressure:

■ If Pce > Psat, then there can be no steam flash, and the entire section of drain piping downstream of the level control valve must be treated as having single-phase flow. In this case, Psat is considered as the end receiver pressure and the single-phase pressure drop worked backwards to establish the control valve outlet pressure P2.

■ If Pce < Psat and Pce > P2dh, then steam flash is occurring (un-der choked flow conditions) and the section of drain piping downstream of the level control valve must be considered as having two-phase flow. In this case, Pce must be used as the end receiver pressure instead of P2dh. The two-phase pressure drop is then worked backwards to establish the control valve outlet pressure P2.

■ If Pce < Psat and Pce < P2dh, then steam flash is occurring (under nonchoked flow conditions) and the section of drain piping downstream of the control valve must be considered as having two-phase flow. However, in this case P2dh can be used in the flow calculation as the end receiver pressure. The two-phase pressure drop is then worked backwards to establish the con-trol valve outlet pressure P2.

Calculate Control Valve Outlet Pressure

If there is no condensate flash, the section of drain piping downstream of the level control valve (up to the downstream heater) must be treated as single phase. In this case, the

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2. Pressure points. Locations of drain line pressures referenced

in the article are shown. Courtesy: Bechtel Power Corp.


conventional Darcy equation can be used for liquid conden-sate pressure drop calculations using Psat as the downstream heater pressure. This calculation, along with adjustments for static head and velocity head, will establish the control valve outlet pressure.

If condensate flash is present, the fluid in the section of drain piping downstream of the level control valve (up to the down-stream heater) must be treated as two-phase flow. In this case, the general flow equation (modified Bernoulli equation) can be used to determine the upstream pressures starting with small pipe sections backward from the receiving heater:

Where, K = piping component resistance coefficient; f = fric-tion factor; L = piping equivalent length, ft; D = piping di-ameter, ft; I = 0 for horizontal pipe, +1 for vertical pipe (down flow), or −1 for vertical pipe (up flow); W = flow, lb/sec; A = pipe area, ft2; ĭ = density, lb/ft3; P = pressure, psia; subscripts A and B represent the upstream and downstream conditions, respectively.

The integral expression can be approximated as (PA – PB)(ĭA + ĭB)/2 for small pipe sections and the general flow equation used in several steps to cover the downstream piping.

The general flow equation can be used to establish the up-stream density ĭ1 and the corresponding pressure P1 and is best executed with commercially available computer software. How-ever, if software is not available, this equation is still fairly man-ageable using a spreadsheet program.

Because the downstream receiving heater pressure P2dh (or the critical pressure at the exit in the case of choked flow) and saturation pressure Psat are known, the amount of steam flash can be computed. Knowing the amount of steam flash,

the density of liquid vapor mixture ĭB can be evaluated at the downstream point. For the upstream point, a trial and error method can be used by selecting a value of P1, then calculat-ing P1/Psat and corresponding steam flash and corresponding density ĭA. The density values are then used in the general flow equation and the process is repeated for ĭA until the equation balances.

The two-phase mixture density (based on HEM) can be computed from the quantity of steam flashed as follows: ĭMIX = (WG + WL)/(WG/ĭB + WL/ĭB), where WG and WL are flashed steam and condensate flow rate in units of lb/hr, respectively and ĭG and ĭL are steam and condensate density in units of lb/ft3, respectively,

In the special case where the downstream piping has vary-ing piping diameters (such as a reducer attached to the control valve), the critical pressure at the exit should be evaluated for the different diameters. If Pce at the smaller end of the reducer works out to be greater than the saturation pressure, then the flow is liquid at the valve outlet (and the pressure should be set at the saturation pressure).

The key to sizing and selecting the best control valve is estab-lishing the correct value of P2. The control valve sizing selection also involves determining the pressure at the control valve inlet P1, but this value is fairly simple to calculate because it is based on single-phase liquid flow.

Check Heater Drain Valve Cavitation/Flashing Conditions

The heater drain control valve may be subject to cavitation or flashing service, which could damage valve internals and piping. It is therefore important to establish clearly whether the valve is subject to cavitation or flashing so the appropriate mitigating methods can be used.

The heater drain control valve sizing depends on the al-lowable pressure drop (∆Pa) across the valve. The allowable pressure drop is the smaller of the actual pressure drop and the choked pressure drop.

The engineer responsible for checking the adequacy of a new

or an existing design should include the following items on the

review checklist:

■ The pressure drop between the upstream heater and the

downstream heater should be adequate to pass the required

flow during both full-load and some selected reduced-load

operating conditions.

■ Heater locations and elevations should be properly determined,

because this can contribute significantly to the total pressure

drop between the heaters. The effect is especially true for the

lowest HP heater draining to the deaerator, and LP heaters

draining to the next lower heater, where the static head be-

comes significant relative to the difference in heater pressures.

■ The drain line from the heater outlet to the control valve should

be designed so that single-phase condensate flow exists up to

the control valve.

■ The drain line from the control valve outlet to the receiving

heater inlet should be designed for two-phase flow. The two-

phase flow should not occur at the control valve outlet but at

some distance from the control valve. If the two-phase flow

occurs at some distance from the control valve outlet, then

the static pressure due to the liquid head must be considered

in the pressure drop calculation for the piping downstream of

the control valve.

■ The control valve should be properly sized based on correct

values of valve inlet pressure P1 and valve outlet pressure

P2. The inlet pressure P1 can be calculated in a straight-

forward manner by computing the pressure drop between

the upstream heater and the control valve using the Darcy

equation for single-phase flow. The outlet pressure P2 may

be based on single-phase or two-phase flow. The computa-

tion is more involved for two-phase flow, requiring use of

the general flow equation.

■ The control valve should be checked for cavitation against the

valve manufacturer’s recommended index to determine if dam-

age mitigation is required or not.

■ The control valve should be checked for flashing and steps taken

to minimize its damaging effect on valve internals and down-

stream piping.

Design Review Checklist


The choked pressure drop, for valves installed without inlet/outlet fittings, can be predicted by the following equation: ∆Pchoked = FL

2 x (P1 – FFPv), where FL = liquid pressure recovery factor provided by valve manufacturer; P1 = upstream pressure at valve inlet, psia or kPa; FF = liquid critical pressure ratio factor = 0.96 − 0.28SQRT(PV/PC); PC = critical pressure of liquid, psia or kPa; and PV = vapor pressure of the liquid at flowing temperature, psia or kPa.

The choked pressure drop corresponds to choked flow in the valve created by the formation of gas bubbles when the fluid pressure drops below the vapor pressure at the valve vena con-tracta. The formation of gas bubbles at the valve vena contracta depends on the downstream pressure (P2), meaning the valve could be in cavitating service or flashing service.

Consider Effects of Cavitation

Cavitation occurs in the valve only in single-phase liquid ser-vice across the valve. As the liquid flows through the control valve, the pressure falls from the inlet pressure until a point is reached when the local fluid pressure falls below the vapor pressure. At this point, vapor bubbles are formed. The poten-tial for cavitation damage occurs when the downstream pres-sure (P2) again rises above the vapor pressure and the vapor bubbles collapse.

As mentioned previously, if the actual pressure drop is higher than the choked pressure drop, the choked pressure drop is the allowable pressure drop for control valve sizing. However, at these conditions, fully developed cavitation can be expected with its high potential for damage to valve inter-nals and downstream piping.

If the actual pressure is less than the choked pressure, the actual pressure is the allowable pressure for control valve sizing. But, to establish the damage potential from cavita-tion, this value of actual pressure drop must be compared to the ∆P associated with the cavitation index provided by the valve manufacturer. Instead of the cavitation index, some valve manufacturers use the cavitation coefficient, calculated as KC = ∆P x (P1 – Pv). The cavitation coefficient KC assumes that a valve may function without damaging cavitation at any pressure less than the pressure drop calculated using the coefficient.

Another commonly used cavitation index (į) is defined by the Instrument Society of America (ISA) in publication ISA-RP75.23-1995, where į = (P1 – Pv)/(P1 – P2).

The valve manufacturer can provide the minimum recom-mended value for sigma at various conditions, including incipient cavitation, onset of damaging cavitation, or manu-facturer’s recommended value. These values may need to be adjusted for pressure scale effect (PSE), size scale effect (SSE), and pipe reducer effect (defined in ISA-RP75.23-1995) in case the reference conditions used for establishing į dif-fer from the service conditions. The adjusted value of į un-der service conditions may be higher than the manufacturer’s recommended value (after adjustments for PSE, SSE, and pipe reducer effect).

Based on the above considerations, cavitation in control valves can be mitigated by two methods:

■ Modify system operating conditions so that either valve outlet pressure remains below the vapor pressure, thus creating only flashing conditions but no cavitation, or minimize valve pres-sure drop so that į exceeds the valve manufacturer’s minimum recommendation.

■ Use multistage trims or anticavitation trim in the control valve. This type of trim divides the overall pressure drop into several stages, thus preventing the pressure at the vena con-tracta of any individual stage from falling below the vapor pressure. Some flashing service damage can be minimized by use of hardened trim material or upgraded metallurgy for valve body and use of target flanges in the downstream piping.

Finally, if the downstream pressure is lower than the vapor pressure at the flowing temperature of the fluid, the fluid will flash, resulting in a vapor-liquid mixture. This mixture moving at high velocities often causes erosion in the valve internals and downstream piping. Some flashing damage can be minimized by use of hardened trim material or upgraded valve body metallurgy and use of target flanges in the downstream piping

Additional Design Considerations

Designing heater drain piping and the associated control valve is complex and requires careful evaluation to ensure that the heater drains function properly and are capable of passing the required flow over the intended range of operation. To aid the engineer responsible for checking the adequacy of the design, use the checklist provided in the sidebar “Design Review Checklist.” By following this procedure you can be assured of producing a ro-bust design that will operate under all expected plant operating conditions for many years. ■

—S. Zaheer Akhtar, PE is the assistant chief & technical advi-sor to the PGESCo manager of engineering, on assignment from

Bechtel Power Corp. to PGESCo, Cairo, Egypt.

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Align Generation Reliability and Fuel Supply FirmnessBy Barbara S. Jost

More and more electricity is generated by natural gas. This trend is likely to persist. Hydraulic fracturing technology is increasing domestic supplies and enabling natural gas pric-

es to remain at historic lows. These circumstances encourage fuel switching by electric generators. Cheaper fuel allows less-expensive electricity, but the long-term consequences of this trend could well be less-reliable electric service if the fuel used to generate a grow-ing portion of the nation’s electric power lacks firmness.

Increasing Reliance on GasIn August 2012, the Federal Energy Regulatory Commission (FERC) convened five regional conferences to address whether current market structures and regulations are adequate to sup-port the electric sector’s increasing reliance on gas-fired genera-tion. These conferences were well attended (by more than 1,200 registrants) and FERC was inundated with written comments and associated recommendations on whether the increasing use of gas in lieu of oil/coal was making electric service less reliable and, if so, how to solve this problem. In addition, concerns were raised about two related but subsidiary issues: communication, coordination, and information sharing across the electric and gas industry; and disconnects between the scheduling for electricity and gas.

In November, FERC issued a staff report summarizing the re-sults of its information-gathering and an order directing actions on the two subsidiary issues. However, FERC left the threshold question unanswered: When power is needed, how best to ensure that generators with firm delivery obligations have reliable up-stream fuel resources and, if they do not, who should bear the resulting reliability costs?

Based on regional conference comments, such electric resource adequacy is of greater concern in areas with organized capacity markets than in those areas where vertically integrated utilities operate. Organized capacity markets such as the Northeast and Mid-Atlantic do not currently provide an incentive for generators to purchase firm contracts for gas pipeline transportation. The staff report notes that “[p]articipants in virtually all regions with capacity markets indicated that their capacity markets do not consider the firmness of a generator’s fuel supply when clearing resources.” It adds that appropriate incentives to deliver firm en-ergy are necessary to better ensure that gas-fired generators are able to reliably deliver firm energy; reliance on nonfirm pipeline capacity to deliver gas to power plants is inconsistent with the firm energy delivery obligation.

In areas where there are vertically integrated utilities, such as the Southeast, the correlation between the firmness of delivery of natural gas to power plants and resource reliability appears to be less of an issue. Many entities are subject to integrated resource planning requirements that specify that electric genera-tors have firm pipeline transportation service and/or storage.

Unresolved Cost AllocationAt the regional conferences, pipeline operators, not surpris-ingly, urged that generators be required to hold firm capac-ity/storage. Generators maintain that pipelines should (and some already have) design more flexible transportation ser-vices that can meet generator seasonal demands without potentially costly gas system expansions. Natural gas local distribution companies (LDCs) appear wary of electric indus-try suggestions that regional gas infrastructure planning is needed. The LDCs also complain that the costs of serving electric generator variability are already being shifted im-properly to LDCs and ultimately to their customers.

Yet the staff report shies away from offering any possible remedies or even a path for resolution with respect to the con-sequences of less-than-firm transportation service and electric resource adequacy. FERC concurs with the staff report that “re-source adequacy issues . . . should continue to be addressed in the first instance by market participants, states, and other stakeholders in each region.”

Consistent with FERC’s “deferral to the regions” approach, the North American Electric Reliability Corp. (NERC) generally favors a requirement for generator “firmness” that would account for the multiple ways to firm up the fuel supply, but NERC nonethe-less does not see a need for a national standard. It concurs that the issues can be addressed on a regional basis. More recently, however, a consulting firm has proposed that from a system reli-ability standpoint, NERC should act by redefining “firm power” on a fuel-neutral basis so that generators who want to bid into power markets would have to firm up fuel reliability.

FERC Defers DecisionThat electric resource adequacy is not an immediate concern in all parts of the country is not an adequate reason for FERC to defer to the regions for solutions. Indeed, resource reliability concerns are most pressing in organized regional transmission organization/independent system operator capacity markets that are already comprehensively regulated by FERC. Nor is the fact that organized markets vary in design an adequate excuse for de-ferral. The costs of ensuring that natural gas–powered generators are delivered fuel sufficient to ensure electric resource adequacy will be substantial regardless of the resolution.

Understandably, and as made clear by the staff report, stake-holders differ widely on how to proceed, and their proposals typi-cally align with their economic interests in the outcome. That these issues may be difficult to resolve is not an excuse for inac-tion. FERC needs to commence the appropriate proceeding de-signed to provide a national and comprehensive policy direction for the electric and gas industries on this imperative issue. ■

—Barbara S. Jost ([email protected]) is a partner in the Washington, D.C., office of the law firm Davis Wright Tremaine LLP.

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FUELS

Techno-Economic Considerations When Using Low-Grade Coal for Power Generation

Regardless of a power plant’s objectives

or the relationship between a plant and

an associated coal mine, the availabil-

ity of a low-grade coal resource creates the

possibility for a symbiotic relationship. In or-

der to harness the benefits of such a relation-

ship between power generation and coal min-

ing, certain techno-economic considerations

should be kept in mind.

Because the variables are numerous, a few

clarifications are in order to start. In this ar-

ticle, “low-grade coals” refers to lignite and

subbituminous coals with a calorific value

(CV) of less than 18 MJ/kg (7,725 Btu/lb)

and ash quantities of greater than 40% by

weight. These coals are further characterized

by varying/inconsistent volatile matter (VM),

high inherent moisture, high sulfur, and a low

Hardgrove Grindability Index (HGI).

Steam Pro and Steam Master proprietary

software (from Thermoflow Inc.) were used

to generate some of the data used in this ar-

ticle’s charts and table. Efficiency, coal con-

sumption, and capital expenditure (CAPEX)

graphs assumed a 300-MW single-reheat

subcritical steam cycle. The graphs only in-

dicate the relationship among CAPEX, plant

efficiency, coal consumption, and CV for

this power plant design specification. What’s

more, a power plant’s economic viability de-

pends on several project-specific factors such

as plant CAPEX and operating expenses

(OPEX), the availability of a favorable power

purchase agreement (PPA) and coal supply

agreement (CSA), transmission infrastruc-

ture, coal and limestone costs, water costs,

labor costs, and so on.

This article considers only plant CAPEX

and OPEX as major factors contributing

The use of low-grade coal is becoming synonymous with circulating fluidized bed (CFB) power plants. Although CFB technology may often be a better choice than pulverized coal technology, that is not always the case. Owners and developers need to consider several technical and economic factors before making this decision.

By Chudi Egbuna, MSc.Eng. (Mech.) Pr Eng., Parsons Brinckerhoff Africa

Courtesy: Cleco

FUELS


to power plant economic viability. Power

plant OPEX constitutes variable and fixed

operation and maintenance costs (such as

coal, limestone, fuel oil, water, and labor).

The OPEX discussion is limited to the cost

of coal, including transportation, as a major

contributor to power plant operating costs.

Power plant and coal mine relationships and

their interactions with CAPEX and OPEX

depend on the specific circumstances of a

project, which can be numerous. As a result,

the described relationships and interactions

have been limited and simplified somewhat.

Plant Technology Subcritical power plants are known to achieve

efficiencies between 30% and 36% on aver-

age, while supercritical and ultrasupercritical

power plants can achieve efficiencies up to

40% and 45%, respectively. The CV of the

coal generally affects the plants’ ability to

achieve these efficiencies in that the lower the

coal CV, the less likely a plant will operate in

the higher regions of its efficiency class. This

is especially true when a plant has not been

designed to burn a specific grade of coal. To

maximize a power plant’s potential to utilize

low-grade coal, plant technology should be

selected that is least likely to be affected by

coal quality.

Most of the technologies used in thermal

coal power generation are independent of

the coal being used. The main technologies

of concern are boilers, their associated fuel-

handling and -processing equipment, and

their emissions control technology.

Boiler Technology. Generally, a con-

ventional pulverized coal (PC) boiler will

function properly, provided there is minimal

deviation from the range of coal specification

for which it was designed. Significant varia-

tions in coal characteristics in PC boilers such

as VM content are dangerous and could lead

to tube rupture and boiler explosions. Arch-

fired PC boilers by Foster Wheeler have been

developed to address low-volatile coals but

not a wider range of VM coal feed for a spe-

cific design. Figure 1 depicts the relationship

between PC and circulating fluidized bed

(CFB) boilers and coal grade.

Varying and inconsistent coal types can

be processed into an acceptable fuel by

several available coal beneficiation pro-

cesses, in which case a PC boiler can be

used, even for low-grade coals. However,

where minimal downstream coal prepara-

tion is available, the CFB boiler is gener-

ally more capable of handling coal quality

inconsistencies. Although CFB boilers are

capable of handling a wider range of fuels

by virtue of their fuel firing/coal combus-

tion system, they are limited by their ther-

mal design to a specific range of fuel. For

this reason, multifuel combustion or cofir-

ing with dual fuels such as biomass and

coal in CFB boilers is not always achiev-

able.

An important aspect of boiler choice is the

auxiliary power consumption associated with

fuel processing and emissions control. In PC

boilers that use mills to grind coal, this is

important from a fuel processing viewpoint.

Generally, higher plant auxiliary loads result

in lower plant efficiency. The finer pulver-

ized coal required for a PC boiler results in

higher auxiliary load requirements and lower

plant efficiency. Therefore, for a specific

plant design, a lower HGI will result in high-

er auxiliary power to achieve the required

coal fineness and, consequently, a lower

overall plant efficiency. CFB boilers, on the

other hand, do not require fine coal, and so

a PC plant’s grinding mills are replaced by

crushers in CFB plants, which reduce coal

processing auxiliary power consumption re-

quirements (see table).

Should the coal HGI decrease for the PC

plant, there will be a consequent increase

in auxiliary power requirements and a de-

1. Combustion characteristics. A conventional PC boiler will function properly, pro-

vided there is minimal deviation from the range of coal specification for which it was designed.

Source: Adapted from S.J. Goidich, “Supercritical Boiler Options to Match Fuel Combustion

Characteristics,” Foster Wheeler North America, 2007

PC arch-fired

Anthracite,

petroleum coke

PC wall-fired

Bituminous, subbituminous, lignites

CFB

High-ash waste coals

40

35

30

25

20

15

10

5

00 10 20 30 40 50

Hig

he

r h

ea

tin

g v

alu

e (

MJ

/kg

)

Volatile content (% dry ash free)

Power distribution summary. The first two data columns illustrate typical auxiliary and

miscellaneous loads as a percentage of total auxiliary load required by a PC and CFB plant of

the same capacity burning a low-grade coal with an HGI of 50. The last two columns illustrate a

decrease in sulfur removal–related auxiliary power requirements to 13% and 6%, respectively,

for the CFB and the PC plant. Source: Chudi Egbuna

Plant system

Low-grade coal (HGI = 50) Low-grade coal (S <1%)

CFB plant PC plant CFB plant PC plant

Boiler PA & SA fans (%) 17 6 16 6

Boiler ID fan (%) 9 10 9 10

ESP (%) 2 2 3 3

Cooling tower fans (%) 3 2 3 2

BFP and booster pumps (%) 32 27 33 30

Other pumps (%) 6 8 7 8

Miscellaneous and other auxiliaries (%) 12 9 12 10

Transformer losses (%) 1 1 1 1

Ash handling (%) 15 9 13 10

Boiler fuel delivery (%) 3 13 3 14

Sulfur scrubbing equipment (%) 0 13 0 6

Total (%) 100 100 100 100

Notes: BFP = boiler feed pump, ESP = electrostatic precipitator, HGI = Hargrove Grindability Index, ID = induced draft,

PA = primary air, S = sulfur, SA = secondary air.

FUELS


crease in plant efficiency. This is not the

case with CFB plants, which are less sensi-

tive to coal HGI.

Where low-grade coals with high sulfur

content (>1% sulfur by weight) are being

used, the auxiliary power requirements re-

lated to sulfur removal in CFB and PC plants

are negatively affected, the consequence be-

ing a reduction in plant efficiency. In CFB

plants, this increase in auxiliary power con-

sumption is experienced in ash handling due

to the increase in sorbent requirement for

desulfurization and a consequent increase in

bottom ash mass flow. In PC plants, this in-

crease in auxiliary power consumption is ex-

perienced at the desulfurization equipment.

Desulfurization accounts for 15% and 13%

of the total auxiliary and miscellaneous loads

for the table’s specific CFB and PC plants,

respectively.

The far right columns of the table illustrate

similar CFB and PC plants using low-grade

coal but with sulfur content less than 1%, and

show a decrease in sulfur removal–related

auxiliary power requirements to 13% and 6%

for the CFB and PC plant, respectively. This

reduction translates into higher efficiencies

in both plants. Note that the single largest

auxiliary power requirement in all conven-

tional Rankine cycle steam plants is from the

boiler feedwater pumps. Therefore, although

the auxiliary power requirements for mills/

crushers and sulfur removal are important in

the choice of boilers, they account for a small

percentage of overall plant auxiliary power

requirements and have marginal impact on

overall plant efficiency.

Emissions Control. For power plant

projects requiring World Bank (WB) fi-

nancing or financiers and for host coun-

tries requiring adherence to WB standards,

proper emissions control equipment capa-

ble of achieving the prescribed emissions

limits must be installed. PC boilers re-

quire additional equipment in the form of

flue gas desulfurization (FGD) scrubbers

to achieve WB emission limits on SOx.

In CFB plants, this can be achieved with

in-situ capture by the direct addition of

limestone into the boiler furnace without

the need for additional equipment. Sul-

fur content alone does not determine the

grade of the coal, as some higher-grade

coals exhibit higher sulfur contents than

lower-grade coals. High sulfur content is

an indicator of the coal grade and affects

plant performance, as discussed previous-

ly. Regardless of the coal grade, the SOx

capture methods for CFB and PC plants

remain as introduced above.

NOx control in PC plants can be achieved

using selective catalytic or selective non-

catalytic reduction (SCR/SNCR) equipment

and low-NOx burners. CFB plants inher-

ently operate below temperatures at which

NOx is typically formed (1,500C). The lower

operating temperature of CFB plants is also

ideally suited for the in situ capture of SOx.

The low operating temperature of CFB boil-

ers is usually sufficient for non-degraded air-

shed situations; however, in degraded airshed

situations, SCR/SNCR may be installed to

achieve the prescribed NOx limits.

Particulate matter (PM) control in both

CFB and PC plants is identical and requires

the use of electrostatic precipitators (ESPs)

or baghouse fabric filters. Some low-grade

coals exhibit high silica and alumina content

in their ash, which increases ash resistivity,

thus reducing the PM collection efficiency

of ESPs. Low-sulfur coals also exhibit high

ash resistivity and may necessitate the use of

baghouse fabric filters. For CFB plants with

in-situ SOx removal, the use of ESPs is not

recommended. Baghouse fabric filters are

therefore the preferred PM control technol-

ogy as they are unaffected by ash resistivity.

Generally, if a coal mine can ensure a coal

specification within a suitable range for a

PC plant over the life of the plant (approxi-

mately 30 years), PC technology can be used.

Achieving this range will normally require

more downstream preparation (beneficiation)

of the coal feedstock, especially if the coal

supply consists of discards from coal mining.

Where securing this range cannot be ensured,

and where the range of coal feedstock is

likely to be inconsistent and varied, or if the

coal mine is unwilling to invest in beneficia-

tion, then a CFB plant is the better choice.

Most often, where discard coal is the source

of feedstock, CFB plants are preferred.

Project EconomicsBecause low-grade coals have low energy

content, larger quantities will be required

to achieve a certain power plant output than

would be required using higher-grade coal

with higher energy content. The farther away

the power plant is from the mine(s), the

greater the fuel OPEX, especially where low-

grade coals are used. Up to a 40% increase

in boiler coal consumption can be required

by decreasing the utilized coal’s CV from 20

MJ/kg to 14 MJ/kg. This could translate into

significant coal transportation costs and, con-

sequently, a higher OPEX.

Where a power plant’s owners intend to

source from a single mine, that plant can

be designed for the specific low-grade coal

being supplied. When a power plant is not

at a mine mouth, it may be worthwhile to

improve the coal quality and thereby lower

the cost of transportation to minimize coal

OPEX. For a fixed power plant capacity

and distance from a coal mine, a lower

grade of coal at a lower price will incur

2. Showing Improvement. The percentage change in CAPEX and efficiency with calo-

rific value (CV) for typical CFB and PC plants is illustrated. In general, the screening curves

assume that as the efficiency of the plant increases with increasing CV, the CAPEX decreases

(see Figure 4). For example, for a hypothetical CFB plant, a CV of 14,000 kJ/kg corresponds

to an efficiency of 31.6% and CAPEX of $2,320 for a baseline design. If the quality of the fuel

were improved to 21,210 kJ/kg, then the efficency increases 6%, to 33.5%, and the CAPEX

decreases 15%, to $2,022/kW. Naturally, the baseline design CAPEX depends on many site-

specific design features as well as the contracting methods and equipment suppliers. Source:

Parsons Brinckerhoff Africa

CFB efficiency CFB CAPEX PC efficiency PC CAPEX

16

14

12

10

8

6

4

2

0

–2

Pe

rce

nta

ge

ch

an

ge

13,500 14,500 15,500 16,500 17,500 18,500 19,500 20,500 21,500

Calorific value (kJ/kg)

FUELS


higher transportation costs because of the

higher tonnages to be transported. A bet-

ter quality coal at a higher price will incur

lower transportation costs because of the

lower tonnages to be transported.

Where a power plant’s owners intend

to source low-grade coal from multiple

mines, the coal qualities could be similar

or different. Sourcing coal from mines

that are significantly distant from one an-

other or on different coal seams typically

means that coal blending will be required

to achieve the coal specification for which

the plant is being designed.

Power Plant–Coal Mine DependenciesThe following coal mine and power plant

project relationships or dependency scenar-

ios could exist.

The Power Plant Is Solely Respon-

sible. In this scenario, responsibility for the

power plant’s economic viability rests solely

on the plant. The coal mine is not necessar-

ily an exporter of coal or a supplier of coal

for power generation, and the power plant

decides what quality and price are needed.

Because lower coal quality often implies a

lower coal price, building a power plant de-

signed to burn low-grade coal while maintain-

ing acceptable plant efficiency may result in

better plant economic viability than building

a power plant to burn coal requiring greater

OPEX. Figure 2 illustrates the relationship

among CAPEX, efficiency, and coal CV for

CFB and PC plants.

In both the CFB and PC plants, as the

coal’s CV improves, CAPEX decreases and

efficiency increases. This may be attribut-

ed to smaller boiler plant and equipment,

smaller bulk material-handling infrastruc-

ture, and less auxiliary power consump-

tion. An increase in CV, however, implies

an increase in coal costs. The overall coal

OPEX (cost at source plus transport costs)

will depend on project specifics with re-

spect to proximity of the power plant to the

coal mine(s).

Viability Rests Partly with the Mine.

In this scenario, the power plant’s eco-

nomic viability rests slightly on the mine,

in that it is in the mine’s interest to provide

the power plant with as high a coal grade

as it can, because the plant is the prima-

ry source of its revenue. Here, additional

capital investments for beneficiation may

be considered to attain the quality required

by the power plant while achieving the re-

quired coal qualities for export. This im-

plies that cost of the coal to the power plant

(OPEX) may increase while some savings

in power plant CAPEX may be achieved.

This arrangement could lead to better over-

all economic viability for both the power

plant and coal mine, assuming that both are

owned by the same entity.

No Incentive for Beneficiation Equip-

ment. This scenario is similar to the first

scenario above in that responsibility for

the power plant’s economic viability rests

solely on the plant. The difference is that

no incentive exists on the part of the coal

mine for beneficiation equipment invest-

ment, and the low-grade coal is often a

byproduct of the export coal beneficiation

process. The power plant therefore must

be designed and optimized around the

low-grade coal. In such situations, CFB

plants often are preferred. The power plant

CAPEX may be relatively higher, but the

plant can operate efficiently with a lower

OPEX and be economically viable.

Mine and Power Plant Have the Same

Owner. This scenario is similar to the second

one, in which viability rests in part with the

mine; however, the coal mine is fully depen-

dent on the power plant for its revenue. This

is often a situation where the mine and power

generation project are owned by the same en-

tity. There is, therefore, a need to optimize

the CAPEX and OPEX of both the mining

and power generation projects. The capital

investment required to develop a power plant

is usually far greater than that required to de-

velop an associated captive coal mine. Cer-

tain coal mine infrastructural costs may be

added to the power plant. These added costs

CFB coal consumption PC coal consumption

170

160

150

140

130

120

110

Co

al

co

nsu

mp

tio

n (

t/h

r)

15,000 16,000 17,000 18,000 19,000 20,000 21,000


3. Coal burn. The CFB plant exhibits 1% to 2% higher coal consumption than the PC plant

for a given fuel CV. Source: Parsons Brinckerhoff Africa

CFB plant PC plant

16

14

12

10

8

6

4

2

0

–2

CA

PE

X (

%c

ha

ng

e)

13,500 14,500 15,500 16,500 17,500 18,500 19,500


20,500 21,500

4. CAPEX change. For the same coal CV, the CAPEX of a CFB plant is less than that of a

PC plant. This normalized data is used in the efficiency and CAPEX screening curves illustrated

in Figure 2. Source: Parsons Brinckerhoff Africa

FUELS


may have a negligible effect on power plant

viability but a significantly negative impact

on the coal mine’s viability. If the coal mine

is producing predominantly low-grade coal,

it may be advantageous to minimize any cap-

ital investments for beneficiation and design

the power plant based on run-of-mine coal. In

such situations, a CFB plant is preferred.

Coal ConsumptionCFB plants with the same thermal duty as PC

plants typically have higher coal consump-

tion. This is due to the higher combustion

efficiency of PC boilers. The ultrafine coal

particles (around 200 microns in size) in the

PC boiler provide a larger surface area for

more efficient combustion compared to the

larger coal particles (typically 6 mm) in CFB

boilers. CFB plants are therefore designed

to recirculate the unburned coal particles so

that combustion efficiencies approach those

achievable in PC plants.

This higher coal consumption accounts

for the marginally lower efficiencies achiev-

able in CFB plants. Figure 3 illustrates this

difference with an increase in coal CV. The

CFB plant exhibits 1% to 2% higher coal

consumption than the PC plant.

This 1% to 2% increase in coal consump-

tion represents about 1.2 tons/hour (t/hr) more

coal for the CFB plant than is required for the

PC plant, and it implies that CFB plants have

higher coal OPEX than PC plants. However,

this does not necessarily imply that PC plants

are more economically viable. To explain this

notion, Figure 4 illustrates the effect of coal

CV on plant CAPEX for CFB and PC plants.

The figure shows that for the same coal CV,

the CAPEX of a CFB plant is less (for lower

CVs, more so) than that of a PC plant. This

remains the case up to higher coal CVs on

the horizontal axis, where the CAPEX values

intersect. The figure also illustrates that CFB

plants are less sensitive to variation in coal

quality (in this case coal CV) than PC plants.

Assuming a low-grade coal of 16 MJ/kg

with a price of $30 per metric ton and an av-

erage power plant capacity factor of 90%, an

increase in coal consumption of 1.2 t/hr over

a 30-year plant life totals approximately $8.5

million. For this coal’s CV, the CAPEX of a

CFB plant is about 3% less than that of an

equivalent PC plant. In present terms, the cal-

culated $8.5 million increase in coal OPEX

is only a fraction of the present 3% CAPEX

savings achieved in building a CFB plant that

uses lower-grade coal.

Optimizing the DesignLow-grade coal can be used advantageously

for power generation. Although CFB plants

offer some operational flexibility with respect

to coal, PC plants are also capable of utilizing

low-grade coal profitably, depending on the

specific circumstances of the project.

In practice, limitations exist on the amount

of information available to a developer/own-

er at project conceptualization to perform

studies. There also are limits on the feasi-

bility studies that can actually be performed

economically. The result of being unaware of

techno-economic considerations early in the

project development phase is often a subop-

timal project. Though this may not be a fatal

flaw, it may account for irrecoverable and

substantial losses in profitability.

Finally, the use of low-grade coal is de-

pendent on the specific circumstances of

the power generation project; using high-

er-grade coal ultimately may be a better

option for long-term plant viability and

profitability. ■

—Chudi Egbuna is a thermal-mechanical

engineer for power generation and works

for Parsons Brinckerhoff Africa.

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Expanded Honolulu WTE Plant Delivers Triple Benefits for Oahu Covanta Energy and the City and County of Honolulu recently completed a $300 mil-lion expansion of a 20-year-old waste-to-energy (WTE) facility. The plant is now capa-ble of processing up to 3,000 tons of municipal refuse daily, recycling all the metals, and generating up to 90 MW—enough to supply nearly 10% of Oahu’s electricity.

By Dr. Robert Peltier, PE

Oahu or “The Gathering Place” is the

most populated of the islands in the

State of Hawaii with just under one

million permanent residents. Aptly named, the

island hosts up to six million visitors each year

who expect fun in the sun and a swim in clear

ocean waters. One reason the island remains

a tourist paradise—its pristine beauty—can

be attributed to the solid waste, recycling, and

energy management programs designed by the

City and County of Honolulu.

High population density on an island

of less than 600 square miles leaves little

open space for new development, and set-

ting aside space for a new landfill is out of

the question, so the million tons of solid

waste produced each year pose a signifi-

cant concern. The island is also searching

for new sources of electricity, because the

State of Hawaii has no indigenous fossil

fuel resources. Historically, electricity was

generated by burning imported liquid fuels

from the mainland and elsewhere. Today,

there is a rapidly growing biofuels indus-

try plus geothermal, photovoltaic, and

wind energy plants offsetting imported

liquid fuels. There’s also one of the largest

and most flexible waste-to-energy (WTE)

plants in the U.S. The Honolulu Program

of Waste Energy Recovery, or H-POWER,

located on a 28-acre site in Kapolei, is the

cornerstone of the City and County of Ho-

nolulu’s long-term efforts to reduce fuel

oil imports, significantly reduce the vol-

ume of landfilled materials, and recycle

metals found in solid waste (Figure 1).

H-POWER entered service in 1990 and

is owned by the City and County of Ho-

nolulu (which encompasses the entire is-

land). It has been operated since 1993 by

Covanta Energy Corp. On Oct. 9, 2012,

the 900-ton-per-day expansion that pushed

plant capability up to 90 MW was dedi-

cated. According to City and County of

Courtesy: Covanta Energy

1. Expanded facility. The new Boiler 3 is

shown in the center of the photo. The existing

refuse-derived fuel Boilers 1 and 2 are behind

Boiler 3 in the enclosed building shown in the

photo. The two steam turbines are housed in

another enclosed building behind Boilers 1 and

2. The plant is capable of processing 3,000 tons

per day of municipal solid waste, producing up

to 90 MW, and recycling all of the entering fer-

rous and nonferrous metals. A time-lapse video

of the construction can be viewed at www

.youtube.com/watch?v=NdxKLu2c-Hg. Cour-

tesy: Covanta Energy

FUELS


Honolulu Refuse Division Chief Manny

Lanuevo, the plant is now capable of pro-

cessing 85% of Oahu’s post-recycled mu-

nicipal solid waste and supplying up to10%

of the island’s electricity needs (Figure 2).

The renewable power produced by the

plant is sold to Hawaiian Electric Co.

(HECO), offsetting its need to import about

one million barrels of oil each year. HECO

purchases electricity based upon a time-of-

day rate linked to a price index plus a 5

cents per kWh capacity payment. Unique-

ly, the contract purchase price is lower than

HECO’s current avoided cost, and HECO

passes the purchased electricity through to

its customers.

The original plant consists of two water-

wall furnace boilers (Boilers 1 and 2) with

reverse-traveling stoker grates that can

process up to approximately 2,100 tons per

day of refuse-derived fuel (RDF). The two

boilers produce steam for a single 57-MW

steam turbine (Turbine 1). Boilers 1 and 2

are fitted with a semi-dry flue gas scrub-

ber with lime injection and a fabric filter

baghouse.

The RDF is prepared by first preprocess-

ing municipal solid waste through a series

of conveyers and shredders for removal

of any nonprocessible and nonburnable

materials. The preprocessing system uses

magnets to pull ferrous metals (tin cans)

and uses eddy current separators to extract

nonferrous metals (aluminum cans) from

the waste stream for recycling. The volume

of ash produced by the boilers is one-tenth

of the volume of municipal waste volume

combusted (Figure 3).

A continuous emissions monitoring

system (CEMS) measures the stack gas

for emissions, such as carbon monoxide,

sulfur dioxide, nitrogen oxides, oxygen,

and opacity. The CEMS also sends signals

to the control room so that operators can

continuously monitor flue gas quality and

the performance of each boiler. The CEMS

data is electronically saved, reviewed, and

summarized into routine reports submit-

ted to the Hawaii Department of Health.

For the entire plant, exceedances are rare,

and the plant is routinely recognized by

the State of Hawaii for reliably meeting its

emissions limits.

Burn What ComesCovanta Energy received a contract from

the City and County of Honolulu to design,

build, and operate the expanded facility in

mid-2009. Covanta hired Parsons Corp. as its

general contractor in December 2009 for the

fast-track project. Parsons was responsible

for plant design and engineering, installation,

and commissioning—all without interfering

with operation of the existing facility. Burns

& Roe provided process design services and

technical support to Covanta for direct pur-

chase of the plant’s major equipment.

The expansion project added a China-

based Anhui Jinding Boiler Co. Ltd. mass-

burn boiler (Boiler 3) and a Siemens 33-MW

steam turbine (Turbine 2) that increased the

plant’s solid waste processing capacity to

about 3,000 tons per day and electricity ca-

pacity to 90 MW.

Additional equipment installed during

the expansion project included a Martin

GmbH reverse reciprocating grate system

that is integrated with the boiler, a tipping/

receiving building, and an AMEREX spray

dryer absorber (SDA) and a fabric filter

baghouse. The SDA uses a lime/water slur-

ry mixture to neutralize and cool acid gases,

such as sulfur dioxide and hydrogen chlo-

ride. The fabric filter baghouse removes

particulate matter (fly ash) and provides a

secondary acid gas neutralization surface

on the filter cake. The stack of Boiler 3 is

monitored with a CEMS like that used on

Boilers 1 and 2. A Jervis B. Webb material-

handling system collects the ash produced,

ready for transportation to the landfill.

The addition of a mass-burn boiler adja-

cent to the two existing RDF-fueled boil-

ers provides increased operating flexibility

to the plant and is unique among the 40

municipal waste-fired plants that Covanta

owns and/or operates. Instead of prepro-

cessing solid wastes prior to burning, the

mass-burn boiler burns anything and every-

thing that is placed on the traveling grate.

For example, a mattress or tire placed on

the grate will burn to completion, and the

steel that remains is recycled, not sent to

the landfill. Covanta operators are now

able to direct large waste items to the new

Boiler 3 instead using landfill disposal, as

in the past (Figure 4).

Unique Operations SchemeIncreased operating flexibility is achieved

by using a combined steam header system;

that is, the steam from all three boilers is

piped to a common header from which

2. Outdoor plant. The structural steel in the center of the photo houses the new Boiler 3.

Moving from the boiler to the right is the spray dryer absorber (SDA) scrubber, the fabric filter

baghouse, and the stack. A continuous emissions monitoring house is located on top of the

stack inlet ductwork. The enclosed Boilers 1 and 2 are located behind Boiler 3, and the steam

turbine building is located in between. Courtesy: Covanta Energy

3. Remote fuel handling. Waste enter-

ing the new section of the building is man-

aged by a remote-controlled overhead bridge

crane with an electro-hydraulic orange-peel

grapple directed by manipulation of joysticks

located in the new main control room. The

fuel for Boilers 1 and 2 is pushed on the floor

to the in-feed conveyors by loaders and bull-

dozers. Courtesy: Covanta Energy

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EDITOR-IN-CHIEF: Dr. Robert Peltier, PE Moderator, Industry Leaders Roundtable & “The Three R’s: Rules,

Regulations and Reactions” Mega Session

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FUELS


each of the two steam turbines receives

900 psig, 830F superheated steam. For ex-

ample, Covanta expedited startup of Boiler

3, placing it in service before the steam tur-

bine system, due to a new power purchase

agreement delay. The steam produced by

Boiler 3 was added to the common steam

header to produce additional electricity

from Turbine 1, as the original plant was

boiler-limited. Excess steam produced by

Boiler 3 was desuperheated and bypassed

around the steam turbine directly to a by-

pass condenser.

Turbine 1 operates on steam header pres-

sure control, but Turbine 2 operates on speed

control when synchronized to the HECO

grid, through a single electrical interconnec-

tion point. This requirement is peculiar for

several reasons: the small size of the plant

compared to all other HECO resources, the

plant is typically operated as a baseload re-

newable energy resource, and the unique

electrical interconnection requirement for

HECO’s power distribution system.

There were a few growing pains with

the large mass-burn boiler during startup,

but the problems were resolved prior to

commercial operation. For example, ad-

ditional reciprocating grate temperature

thermocouples and wider-angle air- and

water-cooled cameras were added to re-

solve combustion problems experienced

early in the Boiler 3 startup. The recipro-

cating grate system on Boiler 3 is the larg-

est ever produced by Martin GmbH.

A Long-Term ViewThe City and County of Honolulu reached

agreement with HECO in June 2012 for a re-

vised and expanded 20-year power purchase

agreement for electricity produced by the

H-POWER plant. Earlier, Covanta had nego-

tiated a new 20-year operating and mainte-

nance agreement with the City and County of

Honolulu that became effective in 2012.

H-POWER’s historical performance met-

rics certainly justified its investment in the

expansion project. The numbers are the envy

of any fossil fuel–fired power plant manager.

According to Facility Manager Robert Web-

ster, the plant operates 24/7 like any baseload

utility plant with an average capacity factor

in the range of 93% to 94%. The new ad-

dition (Boiler 3 and Turbine 2) is predicted

to operate at 97.5%. The availability of the

older plant averages around 90%, but the

new equipment is expected to enable 94%

availability. The value of the common steam

header design is apparent.

More importantly, power generated by

the expanded facility will offset the need

to import about one million barrels of oil

each year. According to Webster, during its

22 years of operation, H-POWER has al-

4. Mass-burn boiler added. Boiler 3 is a

mass-burn boiler, which means it will consume

any combustible objects, even mattresses and

tires. Any metal remaining after combustion is

recycled. Courtesy: Covanta Energy

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FUELS


ready processed 13 million tons of waste,

eliminating 15 million barrels of imported

oil and saving 500 hundred acres of land

that would otherwise be used for landfills.

The plant has also recovered 450,000 tons

of metals for recycling, about the weight of

four aircraft carriers.

Only the problem of ash disposal remains

for the City and County of Honolulu to re-

solve before closing the loop on its entire

solid waste and recycling ecosystem. Ash

produced from the three boilers currently

goes to the local landfill. Covanta and the

City have completed some pilot testing to

show its viability for use as building prod-

uct additives, much as the ash produced

from coal-fired plants is used in road con-

struction and brick products. Reuse of the

ash as a construction material is governed

by very strict regulations, even though the

ash is “sterilized” and is inert, having been

combusted at furnace temperatures near

2,000F. An environmental review of a pro-

posed ash reuse plan presented by Covanta

is ongoing, and a positive result is expect-

ed, particularly as historical ash toxicity

tests have always been negative. The posi-

tive economic and environmental rewards

make ash reuse a key business objective for

both the City and County of Honolulu and

Covanta.

Award-Winning PlantH-POWER has been recognized often for its

contributions to the business and technolo-

gy of producing electricity from municipal

waste. In 2007, H-POWER was designated

as an Occupational Safety and Health Ad-

ministration Voluntary Protection Program

Star Facility, and the following year it was

awarded first place for excellence in safe-

ty and health by the American Society of

Safety Engineers and Hawaii Occupational

Safety and Health. The facility was recog-

nized as a Top 250 Hawaiian Business by

Hawaii Business Magazine in 2011. Most

recently, in late 2012, it received a “Facil-

ity of the Year” award from the American

Society of Mechanical Engineers for its

metals and energy recovery.

Mayor Peter Carlisle summed up the

project well in his comments presented at

the plant dedication (Figure 5). The project

team built a plant that “ranks among the

very best waste-to-energy conversion plants

in the entire world. This is something we all

should be proud of, it’s good for the envi-

ronment, it’s good for the taxpayers.”

Ho‘omaika‘i ‘Ana (congratulations) to the

City and County of Honolulu and to the staff

of H-POWER for a job well done. ■

—Dr. Robert Peltier, PE is POWER’s

editor-in-chief.

5. Cutting of the ribbon. On Oct. 9,

2012, Mayor Peter Carlisle dedicated the new

facility at the H-POWER plant. From left to

right, Director of Environmental Services Tim

Steinberger, former Mayor Mufi Hannemann,

current Mayor Peter Carlisle, and Covanta En-

ergy COO Seth Myones. Courtesy: State of

Hawaii, Governor’s Office

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FUELS

Many U.S. industrial coal users and

utilities are investigating alternative

generation options as the regulatory

squeeze on coal-fired combustion increases.

Some of these options include natural gas con-

version of solid fuel steam generators, decom-

missioning of existing coal-fired steam genera-

tors and replacement with natural gas combined

cycles, and the use of renewable fuel sources.

Given the historic volatility of natural gas prices

and suppressed energy demand growth in re-

cent years, many utilities have been reluctant

to make the switch to a completely natural gas

fleet. Some are considering biomass, because

the many new environmental rules and regula-

tions that call for reductions of coal-fired power

plant emissions—the Mercury and Air Toxics

Standards (MATS), Carbon Pollution Standard,

Cross-State Air Pollution Rule (CSAPR), and

Greenhouse Gas Tailoring Rule—exempt bio-

mass combustion.

Like natural gas, biomass fuels are uniquely

situated as a potential replacement for coal, par-

ticularly where retrofits of existing solid fuel

boilers already have air quality control equip-

ment. Although biomass may not be the opti-

mal fuel for combustion in a steam generator

designed for coal combustion, the operational

issues experienced with biomass combustion

are well understood. Additionally, 30 of the 50

states plus the District of Columbia have renew-

able portfolio standards (RPS) that give the bio-

mass plant certain benefits, in addition to federal

production tax credits.

Each state has a unique RPS eligibility time-

line that generally falls between 2015 and 2025.

Each RPS will also have a different standard

or requirement for generation from renewable

sources, ranging from 10% to 33%. With such

a large portion of energy potentially coming

from renewable sources, energy producers must

focus on developing baseload renewable power

generation in the future.

Wind and solar power generation are inter-

mittent and often unpredictable resources that

depend on nature’s cooperation. Hydroelectric

and geothermal resources offer baseload op-

tions but are not universally accepted RPS tech-

Why Aren’t Construction and Demolition Wastes Considered Biomass Fuel?You may be surprised to learn that even with the increased demand for biomass fuels for power generation, construction and demolition fuel is classified as solid waste, not biomass. Reconsidering this designation is critical as U.S. environmental regulations tighten emission profiles for solid waste combustion units and renew-able portfolio standards expand.

By Brandon Bell, PE, KBR Power & Industrial

Courtesy: Public Service of New Hampshire

FUELS


nologies. Hydroelectric power, for example, is

restricted by technology (pumped storage does

not qualify in all states or existing plants are not

counted) and in some states is restricted by the

amount of potential generation.

Biomass power generation on the other hand,

is an acceptable technology under all RPSs and

offers a historically reliable baseload generation

option. So, why haven’t more industrial facili-

ties and utilities made the conversion of existing

coal steam generators to biomass?

A Challenging FuelThe sourcing of biomass fuels is not a straight-

forward design or operational problem. Bio-

mass fuel types and supplies vary significantly

by region, and long-term fuel contracts are very

difficult to secure. Furthermore, fuel density,

morphology, and moisture content can dramati-

cally affect transportation costs and often dictate

the best combustion technology. It is because

of these design and availability challenges that

many potential users are hesitant to make the

leap to biomass power.

The most commonly considered biomass fuel

is virgin wood chips due to their wide regional

availability, although several other sourcing op-

tions do exist. Agricultural byproducts such as

corn stover act as an opportunity fuel during the

harvest season but are not typically available on

a year-round basis. Processing byproducts such

as bagasse and rice husks are typically available

year round and have very few uses but are usu-

ally only available in small quantities. Purpose-

grown energy crops such as miscanthus and

switch grass are also a viable solution, but as

with agricultural byproducts, they will not pro-

vide a stable year-round fuel source (Figure 1).

Despite these challenges, the quantity of

biomass fuel required to provide the amount

of power required by large industrial users and

utilities cannot be ignored. Because of the lower

energy content of biomass fuels, the volumetric

throughput is typically between three and six

times that of coal. In addition to handling large

volumes of fuel, reduced boiler efficiency from

unprocessed fuels such as wood lead to reduced

boiler efficiencies and increased mass flows of

fuel. Typically, one million tons of virgin wood

chips are required on a yearly basis to provide a

net output of 80 MW.

Procuring such large amounts of fuel is chal-

lenging, but there are ways to work around that

problem. For example, Portland General Elec-

tric is proposing a full biomass conversion on its

585-MW Boardman Plant. The utility is inves-

tigating the use of a purpose-grown energy crop

called giant cane as a replacement for the coal

now used. The project was prompted by a settle-

ment of legal challenges brought by the U.S.

Environmental Protection Agency (EPA) and

the Sierra Club. As a result of this resolution, the

Boardman Plant has installed new environmen-

tal control systems and must stop using coal at

the plant by December 31, 2020.

To control the amount of material that will

be handled by the facility, the giant cane will be

processed by the torrefaction method prior to

combustion in the steam generator. Torrefaction

will heat the biomass fuel in a sub-stoichiometric

atmosphere at temperatures between 400F and

600F to drive off moisture and superfluous vola-

tiles but will not combust the char left behind.

The volatiles lost in the process will be collected

and combusted to provide the heat needed for

torrefaction. The resulting material is typically

pelletized to provide an energy-dense material

with a heating value similar to that of subbitumi-

nous coals. Approximately 8,000 tons a day of

biomass will be needed to maintain Boardman’s

design power output.

The substantial amounts of biomass required

will force agricultural expansion in the region

to support the plant’s fuel needs. Even with the

required agricultural expansion, Boardman is

fortunate to reside in a location that can sup-

port the considerable amount of fuel required

to maintain a baseload biomass plant. Neverthe-

less, the plant will have its operations affected if

droughts or other upsets to growing conditions

occur. Secondary biomass fuel supplies need to

be considered in the event that growing condi-

tions are not optimal. In the case of Boardman, a

utility spokesperson has said that after it switch-

es to biomass, the plant will likely run only dur-

ing summer and winter peak seasons.

Most biomass conversion projects also will

require substantial investment in new capital

equipment. The transportation, receiving, dust

suppression, storage, and sizing equipment for

wood-related fuels differ significantly from

equipment found at coal plants. Coal tends to

be dry and has a high energy density for a solid

fuel, whereas wood tends to be low in energy

density and high in moisture. Existing air qual-

ity equipment may also require upgrades to

match the new fuel.

Biomass conversions are not always an at-

tractive option for large industrial facilities and

utilities, particularly because of the large supply

of biomass fuel required and the challenges as-

sociated with securing long-term fuel contracts.

Classifying C&D FuelConstruction and demolition (C&D) fuel is typi-

cally categorized as a biomass fuel as it largely

consists of wood. Because of its woody compo-

sition, C&D fuel is analogous to that of a typical

pelletized biomass fuel and, as such, biomass

material-handling systems can be properly de-

signed to handle the fuel. The classification of

C&D fuels is necessarily broad and generally

includes building-related debris, disaster debris,

and land-clearing debris. Unfortunately, these

potential renewable fuel sources are not classi-

fied as a biomass fuel by the EPA, and therefore

they are not exempt from more stringent envi-

ronmental regulations.

The current Non-Hazardous Secondary Ma-

terials That Are Solid Wastes Rule classifies

C&D as a “solid waste” and as such makes it

subject to the Commercial and Industrial Solid

Waste Incineration Units (CISWI) standard un-

der Section 129 of the Clean Air Act (CAA).

Section 129 was specifically added in 1990 to

address emissions from solid waste combustion.

Because solid waste incineration units were

added to the CAA, the EPA is required to set

new source performance standards (NSPS) for

new units, establish emission guidelines (EG)

for existing units, and use a maximum available

control technology (MACT) type of approach

for both new and existing units.

1. Processing wood fuel. A typical biomass material-handling system is shown. The fuel-

handling system must be designed with a particular fuel in mind. Courtesy: KBR Power & Industrial

FUELS


The Regulatory HistoryThe recent promulgation of the CISWI (Dec. 20,

2012) is an update of a decade-old rule. On Dec.

1, 2000, the EPA promulgated NSPS and EG for

CISWI units. On Jan. 30, 2001, the Sierra Club

filed a petition challenging the CISWI rule. As a

result of a federal court decision that addressed

the method by which the EPA set MACT floors

(see Cement Kiln Recycling Coalition v. EPA

[255 F.3d 855, DC Cir. 2001]), the EPA volun-

tarily vacated the CISWI. On Sept. 22, 2005, the

EPA issued the CISWI Definition Rule to better

define the term “solid waste.”

Almost two years after promulgation of

the CISWI Definition Rule, on June 8, 2007,

the courts vacated and remanded it due to its

inclusion of all facilities combusting any sol-

id waste material. The December 2012 final

decision incorporates updates to the Defini-

tions Rule and the voluntary vacatur of the

2000 CISWI (Table 1).

Solid Waste ClassificationIf C&D were to be granted a classification

change from a solid waste to a biomass fuel,

facilities wishing to use the fuel for power

generation would have less-stringent emission

limitations. These facilities would be regulated

by the recently promulgated (Dec. 21, 2012)

National Emission Standards for Hazardous Air

Pollutants for Major/Area Sources: Industrial,

Commercial, and Institutional Boilers and Pro-

cess Heaters (Boiler MACT) under Section 112

of the CAA. This is a significant change, as the

Boiler MACT regulations for biomass combus-

tion are far less onerous than the limits imposed

by the CISWI for burning the same materials

(see Tables 2 to 5 for a comparision of the differ-

ence in emission limits).

As part of the Non-Hazardous Secondary

Material Rule (NHSMR), C&D can be re-

classified from a solid waste to “clean” C&D

if it can pass the EPA’s “Legitimacy Criteria”

evaluation. The requirements to reclassify

C&D fuel as a nonwaste fuel are fourfold:

the material must be “managed as a valuable

commodity; have a meaningful heating val-

ue; be used as a fuel in a combustion unit that

recovers energy; and contain contaminants at

levels comparable to or lower than those in

traditional fuels which the combustion unit is

designed to burn.”

The first NHSMR test requires a fuel man-

agement plan that shows C&D waste is a “valu-

able commodity.” This plan must meet three

standards as outlined by the EPA:

■ The storage of the nonhazardous second-

ary material (C&D) prior to use must not

exceed reasonable time frames.

■ Where there is an analogous fuel, the nonhaz-

ardous secondary material must be managed

in a manner consistent with the analogous

1990 2000 2001 2005 2007 2012

Section 129 of the Clean Air Act created ■

CISWI Rule promulgated ■

Voluntary EPA vacatur of CISWI Rule ■

CISWI Definition Rule promulgated ■

CISWI Definition Rule vacated and remanded ■

CISWI Rule (voluntary vacatur & definition rule) promulgated ■

Table 1. The long history of the CISWI Rule. Source: EPA

Pollutants Incinerators ERUs, solids Waste-burning kilnsSmall, remote incinerators

HCl (ppmv) 29 0.20 (biomass units) / 13 (coal units)

3.0 300

CO (ppmv) 17 260 (biomass units) / 95 (coal units)

110 (long kilns) / 790 (preheater/precalciner)

64

Pb (mg/dscm) 0.015 0.014 (biomass units) / 0.14 (coal units)

0.014 2.1

Cd (mg/dscm) 0.0026 0.0014 (biomass units) / 0.0095 (coal units)

0.0014 0.95

Hg (mg/dscm) 0.0048 0.0022 (biomass units) / 0.016 (coal units)

0.011 0.0053

PM, filterable (mg/dscm) 34 11 (biomass units) / 160 (coal units)

4.6 270

Dioxin, furans, total (ng/dscm) 4.6 0.52 (biomass units) / 5.1 (coal units)

1.3 4,400

Dioxin, turans, TEQ (ng/dscm) 0.13 0.12 (biomass units) / 0.075 (coal units)

0.075 180

NOx (ppmv) 53 290 (biomass units) / 340 (coal units)

630 190

SO2 (ppmv) 11 7.3 (biomass units) / 650 (coal units)

600 150

Table 2. CISWI emission limits for existing units. Source: EPA

Pollutants Incinerators ERUs, solids Waste-rurning kilnsSmall, remote incinerators

HCl (ppmv) 0.091 0.20 (biomass units) / 13 (coal units)

3.0 200

CO (ppmv) 17 240 (biomass units) / 95 (coal units)

90 (long kilns) / 190 (preheater/precalciner)

13

Pb (mg/dscm) 0.015 0.014 (biomass units) / 0.14 (coal units)

0.014 2.0

Cd (mg/dscm) 0.0023 0.0014 (biomass units) / 0.0095 (coal units)

0.0014 0.67

Hg (mg/dscm) 0.00084 0.0022 (biomass units) / 0.016 (coal units)

0.0037 0.0035

PM, filterable (mg/dscm) 18 5.1 (biomass units) / 160 (coal units)

2.2 270

Dioxin, furans, total (ng/dscm) 0.58 0.52 (biomass units) / 5.1 (coal units)

0.51 1,800

Dioxin, furans, TEQ (ng/dscm) 0.13 0.076 (biomass units) / 0.075 (coal units)

0.075 31

NOx (ppmv) 23 290 (biomass units) / 340 (coal units)

200 170

SO2 (ppmv) 11 7.3 (biomass units) / 650 (coal units)

28 1.2

Table 3. Boiler MACT emission limits for existing biomass units. Source: EPA

FUELS


fuel or otherwise be adequately contained to

prevent releases to the environment.

■ If there is no analogous fuel, the nonhaz-

ardous secondary material must be ad-

equately contained to prevent releases to

the environment.

The fuel management plan standard was

set as a means to differentiate typical wastes

from those that have some economic value.

Therefore, if C&D waste is used as a nonhaz-

ardous secondary material, it must be handled

in the same manner as a facility using wood

chips as its fuel source.

Most C&D wood is typically not transported

directly to the plant from the location where it

originated; usually, it has an intermediate stop

where sorting and processing occurs to clean up

the final product. The sorting process identifies

wood containing contaminants such as treated

wood (for example, railroad ties) or non-wood

materials, removes these items from the mate-

rial stream either with a mechanical separator or

by human sorting. Technologies such as x-ray

fluorescence analyzers are used to identify any

painted or treated wood that the initial separation

missed. After removal of contaminated C&D,

the remaining material is typically reduced in

size and compacted to a specific density to meet

the purchaser’s specifications. After preprocess-

ing the fuel, there is no difference between tradi-

tional biomass fuels and processed C&D waste

fuel, thereby demonstrating that the fuel has

economic value.

The second NHSMR test is to verify that the

C&D fuel has a meaningful heating value. As

defined by the EPA, a fuel that has a meaning-

ful heating value is one with an as-fired heat

content of 5,000 Btu/lb. For comparison, the

heating values for unprocessed virgin chipped

wood range from 4,100 Btu/lb to 4,900 Btu/

lb—below the definition of meaningful heat-

ing value as outlined by the EPA. Typically, the

heating value of C&D will vary greatly, depend-

ing on the source, but a reasonable estimate

ranges from 6,700 Btu/lb to 9,000 Btu/lb, with

an average heat content of 8,200 Btu/lb. This

places C&D well above the minimum require-

ments and confirms that it has a heating content

of meaningful value, and in the range of that for

lignite or subbituminous coal.

The third qualifying test requires the unit to

recover energy, which is a given for a developer

of a new power generation plant or the conver-

sion of an existing plant. Any existing unit that is

currently being operated in a manner for power

generation will qualify as a combustion unit

that recovers energy. A new unit that is being

designed would need to have the same charac-

teristics as a boiler or process heater to meet this

qualification.

The final qualifying test is if the fuel produc-

es contaminants at levels comparable to or lower

than those in traditional fuels. This is where the

opportunity for using C&D as a biomass fuel

becomes challenging.

The definition of “contaminants” is such that

the C&D fuel, which has a multitude of pol-

lutants by its very nature, is the same as virgin

wood or “clean cellulosic biomass.” As defined

by the EPA, a contaminant is defined as “all pol-

lutants listed in Clean Air Act sections 112(b) or

129(a)(4).” Section 112(b) of the CAA defines

the 187 pollutants that have been classified as

hazardous air pollutants (HAPs) while Section

129(a)(4) defines nine pollutants consisting of

criteria pollutants and HAPs. Likewise, virgin

wood emissions will vary depending on what

species of wood is used. The EPA has not pro-

vided guidance as to what baseline emissions

for virgin wood will be used to set the emission

standard. Using clean cellulosic biomass to set

the air emissions contaminant loadings that are

indistinguishable from virgin wood is an unrea-

sonable burden for C&D waste.

Lost OpportunitiesThe EPA contends that no analysis that meets its

expectations has yet been provided to show that

C&D is of a quality on par with virgin wood—

even after C&D waste has been processed and

sorted to remove contaminated waste. Without

being able to clear this last hurdle, C&D mate-

rials do not meet the nonhazardous secondary

material requirements and retain their solid

waste classification.

Additionally, partial use of C&D wastes as

a biomass fuel is problematic, as using any per-

centage of solid waste in the combustion process

will automatically reclassify a unit as a commer-

cial and industrial solid waste incineration unit.

As defined by the EPA, such unit redesignation

occurs if “any commercial or industrial facility

that combusts, or has combusted in the preced-

ing six months, any solid waste.”

Classifying C&D as biomass would open up

many new fuel sources that can provide valu-

able baseload renewable power generation;

more utilities and industrial users would find

the conversion of coal-fired steam generators

to biomass plants attractive. Unfortunately, the

EPA’s unreasonable emission rule interpretation

effectively eliminates C&D fuels from any con-

sideration as a future renewable fuel source. ■

—Brandon Bell, PE ([email protected]) is a principal mechanical engineer with KBR Power and Industrial, Chicago.

Table 5. Boiler MACT emission limits for new units. Source: EPA

Subcategory

Filterable PM (or total selected

metals) (lb/MMBtu heat input)

HCl (lb/MMBtu heat input)

Mercury (lb/MMBtu heat input)

CO (ppm @ 3% O2)

Alternate CO CEMS limit

(ppm @ 3% O2)

Wet stoker/sloped

grate/other

0.037 (2.4 E-04) 0.022 5.7 E-06 1,500 720

Kiln-dried stoker/sloped

grate/other

0.32 (4.0 E-03) 0.022 5.7 E-06 460 ND

Fluidized bed 0.11 (1.2 E-03) 0.022 5.7 E-06 470 310

Suspension burner 0.051 (6.5 E-03) 0.022 5.7 E-06 2,400 2,000

Dutch ovens/pile burners 0.28 (2.0 E-03) 0.022 5.7 E-06 770 520

Fuel cells 0.020 (5.8 E-03) 0.022 5.7 E-06 1,100 ND

Hybrid suspension grate 0.44 (4.5 E-04) 0.022 5.7 E-06 2,800 900

Note: ND = no data.

Table 4. CISWI limits for new units. Source: EPA

Subcategory

Filterable PM (or total selected

metals) (lb/MMBtu heat input)

HCl (lb/MMBtu heat input)

Mercury (lb/MMBtu heat input)

CO (ppm @ 3% O2)

Alternate CO CEMS limit

(ppm @ 3% O2)

Wet stoker/sloped

grate/other

0.030 (2.6 E-05) 0.022 8.0 E-07 620 390

Kiln-dried stoker/sloped

grate/other

0.030 (4.0 E-03) 0.022 8.0 E-07 460 ND

Fluidized bed 0.0098 (8.3 E-05) 0.022 8.0 E-07 230 310

Suspension burner 0.030 (6.5 E-03) 0.022 8.0 E-07 2,400 2,000

Dutch ovens/pile burners 0.0032 (3.9 E-05) 0.022 8.0 E-07 330 520

Fuel cells 0.020 (2.9 E-05) 0.022 8.0 E-07 910 ND

Hybrid suspension grate 0.026 (4.4 E-04) 0.022 8.0 E-07 1,100 900

Note: ND = no data.


WATER TREATMENT

however, implementation of this program

was sometimes confusing, and some of the

units operating on equilibrium chemistry

still experienced failures, but now the fail-

ures were linked to hydrogen damage.

The latest revision to this long history of

phosphate drum water treatment programs is

the phosphate continuum (PC) treatment pro-

gram introduced by EPRI in 2004. Two forms

of phosphate treatment are provided for un-

der the PC program—phosphate continuum

low (PC(L)) and phosphate continuum high

(PC(H))—but there is no distinct boundary

distinguishing the two treatments, neces-

sitating the term “continuum” to describe

the program. PC(L) treatment is designed

for units using high-quality demineralized

makeup water using low levels (0.2 to 3 mg/l)

of phosphate to deal with low-level impuri-

ties in the cycle. PC(H) treatment is designed

for units using lower-quality makeup water

and increased amounts (approximately 3 to

10 mg/l) of phosphate to deal with impurities

in the cycle.

PC chemistry requires the addition of TSP

and sodium hydroxide (NaOH) to the steam

drums/evaporators, ammonia and/or an

amine to the condensate/feedwater system to

control the pH of these streams, and possibly

an oxygen scavenger to the condensate/feed-

water system for dissolved oxygen control.

The operating ranges of pH and phosphate in

the steam drums/evaporators are bounded by

the ratio of sodium (Na) to phosphate (PO4) =

3 and TSP + 1 mg/l NaOH (Figure 1).

Caustic Treatment Programs. Caustic

treatment (CT) programs have been used

successfully in drum-style units where dif-

ficulties with phosphate hideout have been

experienced. CT programs have been his-

torically more popular in European countries

than in the U.S.; many U.S. units abandoned

the use of these treatment programs in the

1960s due to caustic gouging problems in

higher-pressure units. Recently, however,

this type of treatment program has been re-

gaining popularity in the U.S. as plants inves-

tigate solutions to deal with the challenges

encountered in utilizing phosphate treatment

programs.

In CT programs, a low concentration

of sodium hydroxide is added to the drum/

evaporator water to achieve the recommend-

ed pH in the drum and provide protection

against corrosion. As in phosphate treatment

programs, ammonia and/or an amine is also

added to the condensate/feedwater system

for controlling the pH of these streams, and

an oxygen scavenger may be added to the

condensate/feedwater system for dissolved

oxygen control.

The sodium hydroxide dosage rate is

determined based on drum operating pres-

sure to control the amount of sodium car-

ryover in the steam to a target of less than

2 µg/l. As drum pressure increases, the

dosage rate of sodium hydroxide decreas-

es along with the protection level that this

treatment program provides. Therefore,

CT programs are impractical for imple-

mentation in units operating above 2,400

psi (Figure 2).

All-Volatile Treatment Programs. All-

volatile treatment (AVT) programs have

a long history of successful application in

conventional fossil units and are applicable

to combined cycle power plants that operate

1. Phosphate continuum control chart. The chart provides a visual interpretation of

the phosphate continuum operating ranges illustrating target pH and phosphate concentrations.

Source: Derived from “EPRI Cycle Chemistry Guidelines for Combined Cycle/Heat Recovery

Steam Generators,” Technical Report 1010438, March 2006

10.2

10.0

9.8

9.6

9.4

9.2

9.0

8.8

8.6

pH

at

25C

mg/l PO4

0 1 2 3 4 5 6 7 8 9 10

PC(L) PC(H)

TSP +1 ppm NaOH

Na/PO4 = 3.0

2. Caustic injection control chart. This is a visual interpretation of the sodium hydroxide

dosing rates recommended by EPRI. Source: Derived from “EPRI Cycle Chemistry Guidelines for

Combined Cycle/Heat Recovery Steam Generators,” Technical Report 1010438, March 2006

So

diu

m h

ydro

xid

e (

pp

m N

aO

H)

Drum pressure (psia)

109876

5

4

3

2

10.90.80.70.60.5

0.4

0.3

0.2

0.1600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400

Normal operating level


WATER TREATMENT

Selecting a Combined Cycle Water Chemistry Program The lifeblood of the combined cycle plant is its water chemistry program. This is

particularly true for plants designed for high pressures and temperatures as well as fast starts and cycling. Even though such plants are increasingly common, no universal chemistry program can be used for all of them.

By Colleen M. Layman, HDR Inc.

In 1957, just a little more than 50 years

ago, the first heat recovery steam genera-

tor (HRSG) was connected to a gas tur-

bine and the combined cycle power plant was

born. However, it was not until the mid-1970s

that advances in high-temperature materials

and air-cooling of gas turbine blades made

the combined cycle power plant commer-

cially attractive. Development of the com-

bined cycle power plant design has rapidly

improved, and today a variety of both simple

and complex plant configurations exist.

As designers strive to optimize cycle ef-

ficiency and heat recovery, the designs grow

more intricate, involving multiple pressure

circuits, complex piping arrangements, and

exotic materials. These increases in cycle

complexity and efficiency have also been

associated with increases in the number of

HRSG tube failures. Data compiled by the

Electric Power Research Institute (EPRI) in-

dicated that of the top five modes of HRSG

tube failure, four (flow-accelerated corrosion,

corrosion fatigue, under-deposit corrosion,

and pitting) had links to or could be influ-

enced by cycle chemistry. (See the sidebar

for additional resources on these subjects.)

In the past, many attempted to apply the

same guidelines established for industrial wa-

ter tube drum-type boilers to combined cycle

power plants. For instance, in 1994 the ASME

Research Committee on Water and Steam in

Thermal Systems published a “Consensus on

Operating Practices for the Control of Feed-

water and Boiler Water Chemistry in Mod-

ern Industrial Boilers” (ASME Publication

CRTD-34), but in 2001 it issued errata exclud-

ing HRSGs used in combined cycle power

plants from this original consensus document.

As the volume of operating experience

on HRSG and combined cycle power plants

grew, it became clear that this class of power

generating equipment had unique chemistry

considerations that needed to be addressed

in a different fashion than typical water-tube

drum-type industrial or power boilers. In fact,

last year the ASME Research Committee on

Water and Steam in Thermal Systems issued

recommendations specific to combined cycle

power plants.

What Makes Combined Cycle Plants Special?There are so many different design configura-

tions that selecting the proper chemistry plan

and establishing optimal chemistry operating

limits can be challenging. Therefore, it is im-

possible to develop universal guidelines.

Unlike most conventional fossil or nuclear

power units, combined cycle power plants

generally operate at several temperatures

and pressures. Multi-pressure HRSG circuits

(low pressure [LP], intermediate pressure

[IP], and high pressure [HP]) within a com-

mon HRSG casing are the norm rather than

the exception, and these different circuits

may be drum circuits, once-through circuits,

or a combination of both styles.

Combined cycle plants also are designed

with complex flow patterns; during startup,

some tubes in the HRSG may sit stagnant

or even flow in the opposite direction from

operation. IP steam may be utilized for com-

bustion turbine cooling. The unit may be de-

signed for fast starts or rapid cycling, which

can strain a chemistry program by restricting

the plant’s ability to tolerate chemistry holds,

which have been standard fare in traditional

fossil units. A whole host of design and oper-

ation variations can exist and may affect the

choice of chemistry program and limits.

By carefully considering each specific

unit’s design and operational parameters,

however, a solid chemical treatment plan

can be developed that balances the top con-

cerns of plant operators today: flexibility,

cycling service, economics, and ease of use

coupled with the need to protect and main-

tain plant assets.

Today’s Treatment ProgramsFour basic types of cycle chemistry pro-

grams are described by EPRI, ASME, the In-

ternational Association for the Properties of

Steam and Water, and other entities. They are

phosphate treatment, caustic treatment, all-

volatile treatment, and oxygenated treatment

programs. Phosphate and caustic treatment

programs are only applicable to drum-style

units, while oxygenated and all-volatile pro-

grams can be implemented on once-through

or drum-style units.

Phosphate Treatment Programs. Phos-

phate treatment programs for boiler waters

have been around for nearly 70 years and

are probably the most commonly utilized

treatment programs in drum-style units. Co-

ordinated phosphate chemistry was first in-

troduced in the 1940s by Whirl and Purcell

and was based on the addition of trisodium

phosphate (TSP) to the drum water.

In the 1950s, congruent phosphate treat-

ment was introduced. This program, which

was based on maintaining a sodium-to-phos-

phate ratio in the range of 2.2 to 2.8, was

designed to combat the problem of caustic

gouging that many plants operating on coor-

dinated phosphate programs were experienc-

ing. Despite the successes that many plants

experienced operating on the congruent

phosphate program, some units, particularly

those operating at higher pressures (greater

than 2,000 psi) and with higher heat fluxes,

developed problems with phosphate hideout.

The 1990s brought another phosphate

treatment program in response to those units

that were having difficulty with phosphate

hideout: equilibrium phosphate treatment.

The theory behind equilibrium phosphate

treatment was that each unit must indepen-

dently determine its own equilibrium point

for phosphate. This approach considers the

different operating conditions of each boiler,

such as boiler firing rate, unit cleanliness,

heat flux, and fuel variations, all of which

can affect the maximum concentration of

phosphate that a unit can tolerate without

scale building up on boiler surfaces.

The shift to equilibrium phosphate treat-

ment was a positive step for many opera-

tors dealing with phosphate hideout issues;


WATER TREATMENT

with high-quality demineralized water and

very good feedwater quality. There are two

basic variations of AVT programs utilized in

plants today: oxidizing all-volatile treatment

AVT(O) and reducing all-volatile treatment

AVT(R). Full-flow condensate polishing is

strongly recommended for units designed

to operate using either AVT(O) or AVT(R)

chemistries due to the extremely limited abil-

ity of units operating under these chemistry

regimes to tolerate contaminant ingress. Pol-

ishers are especially necessary for units de-

signed with seawater or high total dissolved

solids (TDS) circulating cooling water.

AVT(O) is only applicable to units de-

signed with all-ferrous metallurgy and uti-

lizes ammonia or a neutralizing amine to

elevate the pH of the condensate and feed-

water to maintain a pH greater than 9.4 in

the LP drum, thus minimizing flow acceler-

ated corrosion (FAC). This typically requires

that the pH of the condensate/feedwater be

controlled to a minimum level of 9.6. A pH

adjustment chemical is the only additive for

the cycle in this treatment scheme. The dis-

solved oxygen concentration in the system is

controlled solely through mechanical means,

creating a slightly oxidizing environment and

a slightly positive oxidization reduction po-

tential (ORP).

AVT(R) is recommended for units de-

signed with copper alloys in the system and

units with steam hosts. Like AVT(O), this

program utilizes ammonia or a neutralizing

amine to elevate the pH of the condensate

and feedwater. However, the pH under this

treatment scenario is limited to a maximum

of 9.1 in order to minimize copper transport

in the system. An oxygen scavenger such as

hydrazine or carbohydrazide is also added

to the condensate/feedwater to control dis-

solved oxygen in the system and provide

protection of the copper-based alloys. The

addition of the oxygen scavenger creates a

reducing environment and a corresponding

negative ORP.

Oxygenated Treatment Programs.

Oxygenated treatment (OT) programs are not

commonly utilized in combined cycle power

plants due to the cycling nature of most plant

designs, but these treatment programs may

be applicable for some baseloaded plants or

for plant designs that include once-through

HRSG pressure circuits.

OT programs, also sometimes called com-

bined water treatment (CWT) programs, use

oxygenated high-purity water to minimize

corrosion and FAC in the feedwater system.

This type of chemistry is only suitable for

units that contain all-ferrous metallurgy in

the cycle and that do not experience routine

cyclic operation. Full-flow condensate pol-

ishers are required in the design to maintain

the feedwater purity required to employ these

treatment regimes.

OT utilizes ammonia or a neutralizing

amine to elevate the pH of the condensate

and feedwater. Copper alloys in the cycle,

downstream of the condensate polisher, are

not compatible with OT programs, as the

presence of oxygenated water will result

in dissolution of those alloys at an acceler-

ated pace. In a drum-style circuit, the pH is

maintained within the range of 9.0 to 9.4;

in a once-through style circuit, a lower pH

range is frequently permitted, approximate-

ly 8.0 to 8.5.

The optimal pH of the circuit must be de-

termined in the field and should be based on

minimization of iron transport in the cycle.

An oxidant is also fed to the condensate/

feedwater to create the oxidizing conditions

in the cycle that promote formation of the

protective cover layer on the ferrous ma-

terials. The most commonly used oxidant

is oxygen gas. Air and liquid oxygen are

also utilized in some plants. Air, however,

contains undesirable contaminants such as

carbon dioxide and, therefore, its use is gen-

erally discouraged.

Chemistry Selection RecommendationsIdeally, selection of the proper chemistry

protocol should be done early in a project’s

design phase, and material selection and

component specification should be per-

formed with the specific chemistry-monitor-

ing and control requirements in mind. Design

parameters for the unit and the chemistry

program need to go hand-in-hand; there is no

one-size-fits-all chemistry program, and even

the best treatment program cannot compen-

sate for improper material selection or poorly

designed system components.

The process of selecting the chemistry

treatment program needs to keep the unique-

ness of the combined cycle plant in mind

and should consider many plant parameters,

including steam purity requirements, con-

denser cooling system design, presence and

type of condensate polishers, potential for

condensate contamination, condensate and

feedwater system metallurgy, cycle design,

operating pressure, the use of duct burners,

cycling service or quick-start requirements,

and the availability of a chemist to quickly

implement corrective action—should it be

required.

HRSG and Steam Turbine. In selecting

the best cycle chemistry treatment program

and deriving operational chemistry limits

specific to a given unit, one should begin by

compiling and analyzing the steam turbine,

HRSG, and combustion turbine original

equipment manufacturers’ (OEM) specified

chemistry limits. The easiest way to do this,

in general, is to begin with the steam turbine

OEM limits and work backwards through the

cycle to calculate the chemistry required in

the HRSG and condensate/feedwater to meet

these limits, considering the manner in which

Looking for More HRSG Water Chemistry Resources?

The POWER online archives are an excellent resource for those re-

searching plant water chemistry topics, as well as other plant de-

sign, operation, and maintenance issues. For example, the following

are 10 related articles, in alphabetical order, that discuss real-world

experience with plant water chemistry and tube corrosion.

■ “Condensate Polishers Add Operating Reliability and Flexibility,”

August 2008

■ “Consider Startup Controls to Avoid Boiler Deposits and Under-

deposit Corrosion,” May 2009

■ “Cycle Chemistry Commissioning Deserves Its Own Strategy,”

September 2012

■ “Designing HRSGs for Cycling,” March 2006

■ “Designing Steam Cycles to Avoid Corrosion,” April 2006

■ “Make Your Plant Ready for Cycling Operations,” August 2011

■ “Organics in the Boiler and Steam: Good or Bad?” September 2006

■ “Put a Lid on Rising Chemical Costs,” September 2008

■ “Ten Years of Experience with FAC in HRSGs,” September 2010

■ “Water Chemistry an Important Factor to Consider for Cycling

HRSGs,” May 2007

You can search the archives by issue (at the Archives link) or

by keyword, using the Search box in the upper right corner of our

homepage, www.powermag.com. The updated search feature now

automatically searches POWER and all sister publications—COAL

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WATER TREATMENT

the plant is designed to operate.

In some instances, however, the HRSG or

combustion turbine components may have

limits based on their design or operation that

are more stringent than the chemistry require-

ments dictated by the steam turbine limits.

One specific example is a combustion turbine

design where IP steam is utilized for cooling.

In this instance, the purity of the IP steam to

meet the combustion turbine requirements

is more stringent than the purity that would

normally be required based on steam turbine

OEM limits. This is why it is important to

collect and review all chemistry guidelines

supplied by the OEMs for all major pieces

of equipment.

The addition of multiple separate pressure

circuits to the HRSG to supply IP or LP steam

for services such as deaeration and feedwa-

ter heating has been an important improve-

ment in the steam cycle efficiency and has

been applied to most combined cycle power

plant designs. Steam from these IP and/or

LP circuits replaces the steam extraction

regenerative feedwater heating design used

in conventional steam power cycles. This

design combines separate HRSG circuits

with varying operating pressures within a

common HRSG casing but typically utilizes

a common condensate/feedwater system to

supply water to all of the circuits.

It’s true that IP and LP circuits may have

less-stringent chemistry requirements than

the HP circuit strictly based on operating

pressure under standard water tube boiler

guidelines. But the intermingling of conden-

sate, feedwater, and steam systems within

the combined cycle power plant generally

requires all HRSG circuits to be restricted

to the same chemistry limits as the highest

pressure circuit.

Although originally intended to improve

simple cycle plant efficiency by absorbing

and utilizing the waste heat from a gas tur-

bine or turbines in a steam turbine, many

HRSGs are now designed to incorporate the

routine use of duct burners. The use of duct

burners can significantly increase the operat-

ing pressures of all HRSG circuits and con-

siderably increase the unit’s steaming rate.

When choosing operating chemistry limits

and the appropriate treatment for the HRSG,

operators and designers need to consider

these higher operating pressures as limiting

design conditions.

Operating experience has shown that the

most prevalent cause of phosphate hideout

in a HRSG is operation of the duct burners.

The degree of hideout experienced general-

ly varies with the firing capacity of the duct

burners: The greater the rate at which a unit

is duct fired, the more severe the hideout is-

sues experienced generally are. Frequency

of duct burner use should be factored into

the chemistry selection process, and unit

testing during duct burner operation should

be performed to determine how a given

unit will respond if a phosphate treatment

program is selected for application at the

facility. If phosphate hideout is severe and

maintenance of proper drum chemistry be-

comes a challenge, the operator may be bet-

ter served by implementing a caustic or AVT

program at the plant.

Several once-through HRSG designs are

available that do not include a steam drum

in one or more of the various HRSG pres-

sure circuits. Drum-type units utilize a steam

drum not only for water/steam separation but

also for concentration and removal of impu-

rities in the system. Once-through units, on

the other hand, are designed such that feed-

water is pumped into the HRSG in the liquid

phase and is converted to steam as it passes

through the heat exchangers in the HRSG.

No provisions are provided in this design for

concentration and mechanical removal of

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WATER TREATMENT

impurities. Whatever contaminants are pres-

ent in the feedwater are transported to the

turbine in the steam. Therefore, condensate

and feedwater must be maintained very pure

and must match the steam turbine OEM’s

steam purity requirements. Condensate pol-

ishing is crucial to establishing and main-

taining this high level of purity in the cycle,

and chemistry choices are limited to OT and

AVT programs.

At drum pressures of 2,400 psi or higher,

contaminants such as sodium and chloride

present in the boiler water easily vaporize

with the steam and carry over to the steam

turbine. This is due to the “partition coef-

ficient,” or the ratio of the concentration of

these contaminants in the steam versus in the

water, which begins to increase rapidly at

pressures above 2,400 psi. Due to concerns

with carryover, phosphate and/or sodium

hydroxide addition is not recommended for

HRSG drums operating 2,400 psi or higher

drum pressures.

Condensate/Feedwater System. Selec-

tion of a cycle chemistry treatment program

is significantly simplified when the system

metallurgy is all ferrous and no copper alloys

are present in the cycle. This includes the

condenser tubes, feedwater heater tubes, con-

densate and feedwater pumps, and any heat

exchangers belonging to a host that receives

steam supply from the plant. Copper alloys

possess excellent heat transfer characteristics

but are susceptible to ammonia attack and,

therefore, the presence of these alloys in the

system limits operating pH in the condensate

and feedwater to approximately 9.1. Opera-

tion at this lower pH does also increase the

system’s risk of FAC. Systems with copper

alloy components can not operate on AVT(O)

or OT. Chemistry treatment programs for

these units are limited to AVT(R), phosphate,

or caustic.

For all-ferrous units, all four types of

treatment programs are applicable. However,

it is strongly recommended that oxygen scav-

engers not be utilized in all-ferrous systems

due to the potential link between a reducing

environment in the condensate/feedwater and

single-phase FAC. Two-phase FAC, on the

other hand, which is common in many HRSG

LP evaporator circuits, is not impacted by re-

ducing or oxidizing chemistry (the addition

or absence of an oxygen scavenger). To pro-

tect against two-phase FAC, boosting the pH

of the LP evaporator by adding sufficient am-

monia (in AVT programs), TSP (in phosphate

treatment programs), or sodium hydroxide

(in phosphate and/or caustic programs) di-

rectly to the LP drum to increase the pH of

the drum water above 9.6 is recommended.

Adding phosphate or caustic, however, is

not always possible in the LP evaporator. The

chemical treatment of the LP drum varies

depending on HRSG arrangement. In some

configurations, each of the HRSG drums

receives feedwater in parallel from the con-

densate/feedwater system. In other configu-

rations, some of the drums are in series with

drum water from one drum (usually the LP)

providing feedwater to other steam drums

(usually IP and HP drums). In configurations

where the LP drum is the feedwater source

for higher-pressure (IP and HP) drums, phos-

phate or sodium hydroxide cannot be added

to the LP drum to provide protection against

two-phase FAC. The same challenge exists

in designs where water from the LP drum

is used for steam attemperation. In designs

where water from the LP drum is used for

steam attemperation, the LP drum water

must meet the same purity requirements as

the steam itself and, therefore, the addition of

caustic or phosphate to the LP steam water is

not permitted.

Whether or not the condensate system

is designed to include condensate polishers

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WATER TREATMENT

has a big impact on the selection of the cycle

chemistry program. The design of any unit

must include a means to handle the ingress of

any impurities that may enter the system via

condenser tube leaks, air in-leakage, makeup

demineralizer operational issues, and the

like. If condensate polishers are included as

part of the plant design to remove any impu-

rities that find their way into the system, AVT

and OT chemistry programs can be utilized.

If no condensate polishers are included in the

plant design, phosphate or caustic treatment

programs should be employed to buffer or

neutralize any ingress of impurities and mini-

mize corrosion and deposition in the system.

Plant Operating Regimes Must Be ConsideredThe proper water treatment process must

be selected for the operating conditions and

type of equipment, as just discussed. How

the equipment is operated is equally impor-

tant, as the water treatment process may be

remarkably different at a baseload plant, a

cycling plant, and one of the new generation

of fast-start plants.

Cycling Service Considerations. Al-

though phosphate treatment programs are

designed to provide good buffering capabil-

ity for drum units, cycling operation while

utilizing these treatment regimes has been

linked historically with phosphate hideout

problems, where the concentration of the

phosphate in the boiler/HRSG seems to “dis-

appear and reappear” as the unit makes sig-

nificant load changes. When the phosphate

“disappears,” operations staff typically try to

correct the situation by adding more chemi-

cal, which usually results in an overfeed

situation when load changes again and the

phosphate “reappears.”

Any drum-level control problems that re-

sult as part of the load swings can also result

in mechanical carryover of phosphate and

sodium from the drum to the superheater

sections and the steam turbine, leading to po-

tential deposition and corrosion. Oxygenated

treatment programs are also best suited for

steady load–type operations, whether the unit

is a drum or once-through type boiler.

Boilers operating in a cycling mode are

best served chemistry-wise by employing an

AVT program coupled with full-flow conden-

sate polishing to remove any contaminants

that may enter the cycle. Units with copper-

bearing alloys in the steam system should

employ AVT(R) chemistry, where ammonia/

amine is added to the condensate/feedwa-

ter to control pH and an oxygen scavenger

is also added to the condensate/feedwater

to minimize dissolved oxygen concentra-

tion. Ferrous-only units are best served by

implementing an AVT(O) chemistry program

where ammonia/amine only is added to the

condensate/feedwater. It is recommended

that inorganic chemicals (such as ammonium

hydroxide and hydrazine) be used as the pH

adjuster and oxygen scavenger, but there are

numerous organic substitutions on the market

today that will also yield good results when

properly applied under the advice of a water

treatment expert.

Fast-Start or Rapid-Response De-

signs. Several “fast-start” or “rapid-re-

sponse” HRSG designs have made their

way into the combined cycle market in

recent years. These units—developed usu-

ally through collaborative efforts among

the steam turbine, gas turbine, and HRSG

OEMs—feature combined cycle power plant

designs that are intended for quick startups

and/or very quick and frequent load swings.

These designs, while providing the swift re-

action to the electric grid needs that today’s

power market demands, also complicate

steam cycle chemistry issues.

Chemistry, like the HRSG and steam tur-

bine equipment, must now also be flexible

enough to respond to fast startups and/or

very quick and frequent load swings. These

plants cannot tolerate chemistry holds that

have been standard in traditional fossil units

and still meet their startup time or load swing

guarantees. Therefore, use of high-quality

makeup and maintenance of condensate/

feedwater purity are primary concerns for

projects that utilize a fast-start or rapid-re-

sponse design.

Such plants should ideally include per-

manent condensate polishers as part of their

standard design to maintain condensate and

feedwater purity and minimize chemistry

holds. For Siemens’ once-through Benson

boiler design, for instance, condensate pol-

ishers are required because the HP portion

of the HRSG is designed to operate on OT

chemistry, and therefore condensate polish-

ers are a key part of this chemistry treatment

program. For other fast-start designs, AVT

chemistry programs coupled with a conden-

sate polisher are generally the best choice to

maintain a clean cycle and respond rapidly

to changes.

Other Water Chemistry Issues Plants incorporating an air-cooled condenser

(ACC) for condensation of the steam turbine

exhaust have unique requirements for their

cycle chemistry treatment program.

The ACC design consists of a very large

surface area for condensation of the exhaust

steam. Though this large surface area works

well for heat transfer purposes, it can up-

set the steam-water cycle chemistry. Newly

erected ACCs are difficult to completely

clean and tend to contribute a substantial

amount of contaminants to the cycle during

initial startup and even during unit restart if

vacuum has been broken. The large surface

area also increases the likelihood of iron

transport in the system, particularly during

initial startup and during unit restarts, and

the potential for air in-leakage in the system.

Owners should seriously consider including

a condensate polisher when using an ACC.

FAC concerns are also common in the

ACC. In order to minimize FAC in an ACC,

the pH in the early condensate must be in-

creased above that required for an equivalent

water-cooled condenser. HP feedwater pH

should be maintained in the range of 9.6 to

9.8 to minimize FAC in the ACC. This may

require supplemental chemical injection for

the HP steam drum or HP feedwater.

Steam from auxiliary boilers is frequently

utilized in combined cycle power plants for

purposes such as pegging the deaerator dur-

ing startup, holding vacuum overnight, or

hotwell sparging. The purity of the steam

coming from the auxiliary boiler must be

the same as the steam produced in the main

cycle. Therefore, the chemical treatment pro-

gram utilized for the auxiliary boiler must be

compatible with the operating pressure and

temperatures of the main cycle, even though

the auxiliary boiler typically operates at low-

er pressures and temperatures.

For instance, nonvolatile oxygen scaven-

gers are frequently used in industrial boilers

operating at low pressures (less than 800 psi).

However, if the industrial boiler is serving as

an auxiliary boiler that is supplying steam to

an HRSG with a HP pressure of over 800 psi,

volatile oxygen scavengers such as hydrazine

or carbohydrazide must be used in treating

the auxiliary boiler, just as in the main steam

cycle.

Consider Plant Staffing The plant staffing plan and operating expe-

rience level of the team may also affect the

choice of chemistry treatment for a unit. Man-

aging a high-performance chemistry program

(AVT or OT) requires tighter operating con-

trols, more supervision of plant makeup wa-

ter treatment systems and chemical additions,

and a higher-level knowledge of steam cycle

chemistry practices. An operations team sup-

ported by a dedicated on-site plant chemist

or chemistry technician specifically trained

in these practices is preferable. If the facil-

ity is unable to provide this level of support

and supervision of steam cycle chemistry, the

better option is to use a phosphate chemical

treatment program, which can be more for-

giving when system upsets occur. ■

—Colleen M. Layman ([email protected]) is the energy-water manage-

ment practice director for HDR Inc.

3Global Business Reports // POWER MEXICOMarch 2013

www.gbreports.com

Global Business ReportsPOWER MEXICO

3Global Business Reports // POWER MEXICO

an extension and embodiment of gov-

ernment energy policy. In contrast to

PEMEX, however, CFE has arguably been

more successful at developing collabora-

tion between public and private interests

and fostering foreign investment. There

are, for example, no issues in the power

industry comparable to the dearth of re-

ining capacity that forces Mexico to ex-

port oil and import gasoline. On the con-

trary, CFE’s igures are strong across the

board: 98% of the population have access

to electricity; interruption time per cus-

tomer (ITC) was 9.3 minutes per annum

in 2012, compared to 59 minutes in 2010;

and the connection of new customers to

the grid has similarly fallen from 6.9 days

in 2009 to 1.5 days today, whilst industry

has seen the improvement from a 37 day

waiting time to three. Though CFE de-

fends the Mexican people’s right to have

access to electricity as cheaply as possi-

ble, in recent years, thanks to the intro-

duction of IPPs and Public Finance Works

(OPFs) – which are similar to Build, Lease,

Transfer agreements (BLT) – the Mexi-

can power sector has nonetheless been

able to diversify and develop the best

practices that private sector competition

can promote.

Independent Power Producers

The 1992 Electricity Public Service Law

allows for some private investment in

generation, provided that the energy

generated is not for public use but for

self-supply, co-generation, export, or for

sale to CFE through a long-term power

purchase agreement (PPA). Both export

and sale to CFE come under the banner

of independent power production, a term

covering any authorized power plant of

over 30 MW and catering to those two

markets. Co-generation and self-supply,

on the other hand, are variations of the

same thing: the consumer generates the

power used, in some cases with the help

of an external company in which the gen-

eration project, for the purposes of legal-

ity, is treated as a joint venture. Avoiding

competition with CFE, private participa-

tion in essence cannot have direct access

Manufacturing Excellence: Air Compressor in the Mexico City factory of Atlas Copco

birth in 1937. Perhaps ironically, the state-

owned monopoly was conceived as a way

of protecting Mexican end-users from

the exploitation of a foreign-owned

monopoly (85% of investment in trans-

mission and distribution from 1900 to 1910

was British).

Mexico’s Balancing Act

Like PEMEX, the government-owned oil

and gas giant, CFE is a company that is

4 Global Business Reports // POWER MEXICO March 2013

www.gbreports.com



www.gbreports.com



www.gbreports.com


ing system has resulted in the distortion

of market signals, making investment

more dificult and less proitable. “Mex-

ico has the potential to produce a lot

more conventional and non-conventional

gas – shale – and as you produce more,

the argument for infrastructure obvi-

ously increases. There is an interest

right now in importing more shale gas,

which is also a justiication for increased

infrastructure. Mexico has a system

in which energy prices, especially

the fuels from the oil industry –

gasoline, crude oil, fuel oil and natural

gas – have had their prices linked histori-

cally to the prices in the United States;

in other words, the reference price.

Essentially, if you have a cubic meter of

natural gas in Mexico, why would you

sell it in Mexico for $2 when you can

sell it in the US for $4? As a result, the

prices have been linked and this is a

system that has worked reasonably well

in the past. However, with natural gas,

this system starts to have cracks; the

natural gas at $3 per cubic feet in

Mexico relects conditions in the US

market in which there is a glut of natural

gas, where there is vast infra-

structure that we do not have in

Mexico. The price of natural gas

in Mexico of $3 per cubic feet is artii-

cial; it does not relect the realities of the

Mexican market, nor does it relect infra-

structure and supply. It is a gas price that

is causing demand to rise with no ability

to in fact meet that demand,” he says.

Despite these fears, Calvillo, CEO

of Fermaca, is quietly conident of

his company’s ability to retain competi-

tive costs, a key advantage which allowed

Fermaca to win the Chihuahua bid.

Calvillo’s focus is on the opportunities

he sees in the market during “the golden

age of gas.”

“Once these pipelines are built and on-

line, Fermaca will be responsible for the

transportation of 20% of Mexican gas

consumption. In the past three years,

our growth has been phenomenal; we

are 10 times bigger in terms of company

value. Now we’re seeking to win several

of these projects and position ourselves

as the most important natural gas pipe-

line company in Mexico. We have in-

vested $600 million in the past four years

and have been very fortunate to close

our inancing.”

The Impact of Subsidies

Another factor that continues to

make gas extremely attractive in Mexi-

co is the presence of subsidies, which

affect the market in a number of ways.

The CFE tariff structure is designed

to subsidize the cost of electricity that

is consumed by residential and agricul-

tural end-users and offers preferential

rates to low consumption households

whilst penalizing high consumption

households. However, as a direct method

of tackling poverty this is ineffective. In

2009 The World Bank claimed that “the

subsidies delivered through the tariff

structure are regressive, with the poor-

est 40% of households capturing only

about 30% of the subsidies. This is

signiicantly less than they would receive

if subsidies were randomly distributed

to all utility customers. In contrast, the

richest 40% of households receive 50%

of the subsidies.”

These subsidies also create an unfa-

vorable regulatory environment for re-

newables which, whilst already seen to

be more expensive and less proitable

than conventional fuels, must in addition

compete within the Mexican market on

an uneven playing ield.

The Renewables Sector: In need of a helping hand?

Whilst some countries in Europe have set

aside subsidies for technologies whose

appropriateness is not immediately appar-

ent, Mexico does not have subsidies for

renewables yet possesses some of the

best resources in the world. The develop-

ment of renewables has become headline

news as climate change fears grow, but

it also plays an important role in protect-

ing against price shocks through a diver-

siied energy basket. Estefano Conde,

manager of social communication for

CFE, highlights the achievements in the

sector to date: “Former President Calde-

ron aimed to increase the participation of

renewables in the energy matrix to 25%

and, at the close of his administration,

CFE met that goal. A key factor in

this is the development of major hydro-

electric projects.”

Mexico’s further aim to source of 35%

of its energy from clean energies by 2026

will be achieved through the market’s

unique synergy between political will and

private means.

Vicente García Montero, commercial

director of Isolux Corsan Mexico, the

Spanish engineering giant, explains the

balance as it applies to the Isolux Corsan:

“Our main client is CFE as they are the

main player. Now that the private sector

is increasingly important due to co-gener-

ation and self-supply, we are diversifying

our client base into the private sector. We

offer assistance in transmission and wind

farms projects for example.”

IPPs supply 23.1% of Mexico’s energy,

which represents 12,213 MW, but with

IPPs aside, the private sector permits

represent an extra 10,011 MW of installed

capacity, 48% of which is self-supply and

33% is co-generation (the rest consists

Prospective Shale Gas BasinsSource: US Energy Information Administation

300km

GULF OF MEXICO

Maltrata

Pimienta

Eagle Ford,

La Casita

Pimienta Tamaulipas

PACIFIC OCEANOO NNCC


www.gbreports.com



of projects too small to count under the

IPP scheme, along with export and import

projects). Despite the lack of subsidies,

the renewables sector has seen good

growth and an inlux of foreign direct in-

vestment (FDI). In 2012, there were 200

plants for renewable power generation

either open or under construction, and

between 2003 and 2012, despite CFE’s

hold over the industry, FDI in renewables

reached $6.9 billion. The majority of these

investors have come from Spain, US,

France, Japan, and Denmark, and their

investments center around the states

of Chihuahua, Baja California (which

has strong solar potential), Nuevo León,

Tamaulipas, and Oaxaca (both of which

have strong wind potential).

The Competitive Edge

Renewables have a number of competi-

tive advantages contributing to investor

interest. In remote areas of Mexico in

which connection to the grid is dificult

and expensive, renewables are cheaper.

In addition, the stability of renewables

and their downward trend with regards

to costs allows for long-term energy plan-

ning in a way that the more volatile prices

of gas make dificult. Lastly, and perhaps

ironically, the very thing that may discour-

age the use of renewables for some us-

ers – the CFE tariff subsidies – are also

what can make renewables more attrac-

tive to others. High consumption users

in the manufacturing sector that require

energy during peak hours are heavily

charged and will ind self-supply schemes

and co-generation projects better value

for money than buying directly from CFE.

Co-generation

Co-generation, as distinct from IPPs, is

being used with success by Mexico’s

industries as an alternative to relying

on CFE, whilst nonetheless avoiding di-

rect competition. The 250-MW Eurus

wind project was developed by Acciona

Energy for CEMEX, a Mexican multi-

national cement producer. Grupo Bimbo,

Mexico’s main bread producer, is sup-

plying its plants with energy generated

from a 90MW wind plant in partnership

with Renovalia’s subsidiary Desarrollos

Eólicos Mexicanos. Small, private hydro-

power projects have also been developed

and represent 292 MW of capacity. Partly

due to private investment and partly due

to CFE’s own commitment to the devel-

opment of renewables, installed capac-

ity has increased from 12,092 in 2006

to 14,095 MW. Pedro Pradanos, director

general of Dalkia, a co-generation and en-

ergy eficiency company, explains what

400 kV Substation Julie - Veracruz I Mexico, Courtesy of Isolux

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Dalkia can offer to its clients: “Co-genera-

tion, which we regularly get involved in, is

one of the main solutions available in the

Mexican energy market and can generate

electrical, thermal, and/or other energies.

Dalkia’s co-generation projects represent

nearly 5000 MW of installed capacity

worldwide. In Mexico, we are currently

developing a co-generation project in

Queretaro with an industrial client. Here,

we are installing the 2 MW CHP system

and will maintain and operate it for the

next seven years. This will allow the cli-

ent to achieve more than 30% in savings.

The project started off with an energy

analysis, after which we presented a vari-

ety of options and solutions to the client.

We recommended one, and developed it.

We are not committed to a single tech-

nology; we seek a comprehensive tailor-

made solution for each case and each cli-

ent in particular.”

Rushing Wind Wind power potential in Mexico is es-

timated at 71,000 MW and in the past

few years has seen strong growth. Due

to the meteoric conditions, wind is the

strongest of all the renewables in Mex-

ico. Adrian Katzew, general manager for

Vestas Mexico, Central America and the

Caribbean, one of the market leaders of

wind turbine manufacturing in the world,

details the factors that have drawn Vestas

and similar companies to Mexico: “The

move away from subsidies for renewa-

bles in Europe, along with the expiry of

the production tax credits in the US next

year, has shifted demand from mature

markets to emerging markets. It is a

phenomenon that is extremely interest-

ing; growing up in Mexico, I would have

never thought that Mexico would become

a leading, world-class example of macro-

economic and inancial management, and

yet here we are. Mexico is attracting for-

eign investment and we are seeing a new

wind market emerge. Wind power today

from a cost point of view is more attrac-

tive than any other alternative; there are

no subsidies, and yet wind power is suc-

ceeding in Latin America and the Carib-

bean. In addition, the dificulties of inan-

cial institutions in Europe has resulted in

a dificulty in inancing projects, but the

role of multilateral agencies in supporting

development in emerging markets allows

the inancing of projects. As a result, it

is easier to inance projects in emerging

markets, which is fueling our growth. In

Mexico, CFE and self-consumers are in-

vesting in wind power because they have

found that it is more competitive.”

Solar’s First StepsSolar, in contrast to wind, has yet to be

developed. The cuts in subsidies in Eu-

rope have caused a glut of solar panels

that has pushed the price of equipment

down, and the attractiveness of the tech-

nology up. As a result, solar companies

typically report a year-on-year growth of

up to 100%, though this percentage is

taken from a very low baseline and the

market is still immature. The potential,

however, is very strong. Mexico is locat-

ed across the ‘Sun Belt’ and is among the

countries with the highest solar power

generation potential worldwide. The so-

lar radiation potential in the northwest

of the country can exceed 6 kWh/m2

per day. In addition, Mexico is the main

supplier of photovoltaic solar modules in

Latin America, with a production capacity

of more than 276 MW, which also opens

up opportunities to supply the near-by

US market. “Latin America overall, and

Mexico in particular, has declared its in-

terest in this source of renewable energy

and there is a lot of growth potential in

this area. Taking this into account as well

as the global decrease in the price of the

panels, we believe that 2013 will be the

year that will offer many possibilities for

the photovoltaic sector. However, in or-

der for the photovoltaic developments to

be proitable we need to make sure that

the tariffs offered in the Mexican market

are competitive not only with respect to

the ordinary sources of energy but also

with respect to the wind power tariffs,”

says Miguel Angel Alonso Rubio, director

general of the Mexican chapter of

Spanish renewables giant Acciona.

Yes(ca) to Hydro-power Hydroelectric power is, of all renewables,

the most developed and widely accepted

as competitive. With a hydroelectric po-

tential of 53,000 MW, Mexico conirmed

its commitment to hydropower with the

opening of La Yesca, arguably the most

important infrastructure project of the

Calderon administration. Built by con-

struction irm ICA, La Yesca has a capac-

ity to hold 2.39 billion square meters of

water and an installed capacity of 750

MW. CFE’s ambitions cannot be realized

without private sector help. Raul Casas,

service and rehabilitation manager at An-

dritz Hydro, an international hydropower

equipment design and manufacturing

company, describes the context of the

market: “The Mexican market is not a

ixed volume market; it is cyclical and de-

pends on the political situation. It is dif-

icult for CFE to maintain a well-deined

agenda of scheduled projects. CFE is cur-

rently trying to deine the next big project

after La Yesca. We work mainly with the

operational side of CFE, and the coordi-

nation of hydro to improve, maintain, and

enhance, the performance of existing

hydroelectric plants.”

Geothermal and BiogasProjects of the scale of La Yesca are not

conined to hydropower however; at

750MW, the Cerro Prieto Geothermal

Power Station is the largest of its kind in

the world and geothermal energy poten-

tial in Mexico is greater than 40,000 MW.

Biomass is also a rapidly growing sector

that has a number of attractive opportu-

nities, many of which are in the Veracruz

area. Gaston Aragon of CAT explains:

“Opportunities are in the north where

there are large ranches with cows and

horses which allow us to produce energy

from the waste using biogas process-

es. In this way, companies can reduce

their energy bill. It is an emerging mar-

ket in the whole of Latin America that

consists of natural waste that is subject

to anaerobic digestion, which as a result

produces biogas that can be used to

power motors. A whole technology must

be built around maintaining a stable envi-

ronment so that the bacteria do not die;

temperature and food supply must always

be kept optimal to maintain the levels of

biogas produced.”

The Forks in the RoadThe exact breakdown of the projected

35% of clean energies has been split by

SENER into three possibilities scenarios:

Firstly – and arguably the easiest way of

achieving the 2026 aim – is to develop

a matrix with a focus on nuclear, which

would account for 18.1% of Mexico’s en-

ergy. Vicente Estrada-Cajigal, president

of the National Solar Energy Association

(ANES) disapproves: “The National En-


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Services: A Key Area for Private Participation

Services and energy eficiency are two

key areas in which the private sector can

be involved in the power industry in Mex-

ico. Whilst according to CFE, IPPs will re-

main a secondary method of generation

despite their advantages, the only limits

on the need for services are the size and

demand of the industry itself. 2012 was

a comparatively quiet year for contrac-

tors and suppliers as CFE hesitated to

increase spending during an election

year, preferring to wait until the political

change was inalized before making

signiicant budgetary decisions. As a

result, though the market has slowed

in the past year, with the advent of

business-friendly President Peña Nieto

and CFE’s own aims of extending

and maintaining its services, CFE’s

spending will be renewed in 2013. In

a speech given to the industry at the

Technological Museum of CFE (MUTEC)

on 17th October 2012, former President

Calderón explained: “One of our priorities

over the last years has been to modern-

ize the Mexican energy industry. This has

been very important for us as it has a direct

effect on the competition in the industry,

the economic growth and the overall wel-

fare of our society. We know that our coun-

try relies heavily on the energy industry

and that it is key for the development of

our country and this is why we have taken

well planned steps that will have direct ef-

fects on its advancement.”

Growth projections It is this will to modernize and advance

within the federal government, and by ex-

tension CFE, that will push demand in the

private sector. Lillian Lopez, general man-

ager at Marley Mexicana which provides

water-based cooling systems and solutions

for power plants, is positive about the mar-

ket’s opportunities for Marley’s business.

“Compared to last year, this year has seen

a lot of movement in the industry which

has given many small businesses the budg-

ets to invest in our types of products. We

now cover 65% of the market, which is a

very good position to be in. Our hopes for

growth this year may appear conservative

at 15%, but this is a natural stutter caused

by the election. With political stability re-

stored, these igures will pick up again.

From 2011 to 2012 our growth was 35%,”

she explains.

Alejandro Gutierrez Vera, general manag-

er of Mexican company Serpro, is also very

positive: “Over the past 10 years we have

achieved a growth of about 100%, and

since 2010, we have grown 20%. 35% of

the electricity produced by the CFE is regu-

lated by Sepro products. Pemex and the

CFE are our biggest customers in Mexico

and we also serve customers in Guatema-

la, the Dominican Republic, Chile, Argen-

tina, Colombia and El Salvador. We are a

Mexican company with Mexican engineers

and have great expectations for growth.”

Energy eficiencyAnother key area in which there is growth

within the energy services industry is the


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energy eficiency sector. In a market in

which high consumption users are heavily

penalized through the tariff structure, an ini-

tial investment in streamlining a company’s

electrical infrastructure means larger sav-

ings in the long term. Speaking at MUTEC,

Calderón highlighted CFE’s commitment

to eficiency: “CFE, together with National

Finances, is working on a program that will

allow more than 200,000 SMEs [small and

medium enterprises] to implement energy

eficient practices by changing their lamps

or their machinery, for example. The SMEs

are vital for the future of any economy and,

in Mexico, they generate eight out of 10

working opportunities. We have provided

these companies with the opportunity

to take credit to improve their energy ef-

iciency and reduce their operating costs,

which will ultimately beneit the inal con-

sumer. This program has already resulted in

a savings as high as 60 million kW and a de-

crease of carbon emissions of 26,000 mt.”

The private sector also provides

high eficiency solutions, whether through

installing smart lighting that switches

off in areas of buildings that are not be-

ing used, more frequent cleaning of air

conditioning equipment, and switching

to more modern heating and cooling

systems. Multinationals such as Schnei-

der Electric and General Electric have a

wide array of solutions to offer, but lo-

cal companies are nonetheless able to

play a role. As both CFE and the private

sector come to realize the advantages

of energy eficiency, the sector will

continue to grow. “Right now there is

a wonderful opportunity in the Mexican

energy market for energy eficiency

companies as the CFE tariff structure is

already expensive for medium industrial

users. On the other hand, the current

price of gas is cheap mainly because of

the inluence of shale. As a result, there

is an impetus for companies to seek other

options, whether energy supply or

co-generation. In addition, the new climate

change law encourages renewable and

co-generation projects which adds to the

Dalkia’s potential in the Mexican market,”

Pradanos of Dalkia says.

Within both the power sector and the

manufacturing sector, energy eficiency

goes hand-in-hand with eficiency of pro-

duction, as the production (and generation)

process increasingly incorporates smarter

operating systems. “Automation today in

Mexico is a necessity, as Mexico needs

to compete globally. As a result, eficiency

and productivity need to increase,

and automation is one key method that

can achieve this. Mexico used to be

very famous for its cheap labor, but this

work method is not eficient. It is automa-

tion that has the most relevance for the

future of Mexico. The automation sec-

tor will continue to grow, and we will be

able to generate added value for our end

customers,” asserts Jose Luis Salinas,

Key Accounts Manager for Oil and Gas,

Chemical and Energy at Festo Mexico, the

automation multinational whose cutting-

edge work has included brain–computer

interface (BCI).

Though 2012 was a period of reduced

CFE spending due to the uncertainties

of the political climate, 2013 will be


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a year of renewed development and growth

in the CFE supply sector. Its key players are

primed to make the most of the opportuni-

ties available.

Mexico’s Vision

SENER’s Program for Works and

Investments in the Energy Sector (POISE),

which is an outline of Mexico’s energy

strategy for the next 15 years, is ambitious

in its vision. It identiies 43,992 MW of

additional capacity that must be in-

stalled to meet with demand. 6,462 MW

of this is already accounted for by

projects that are currently in the construc-

tion phase or have entered the bidding

process, but another 37,529 MW is for

future projects that have yet to be

deined. In addition, 539 MW of

modernization must take place. During

this period, the government plans to

invest 100 billion pesos each year

(approximately just under $8 billion),

with the bulk of it dedicated to

generation at 52%, whilst distribution

accounts for 20%, transmission 14.1%,

and maintenance 13.3%. This inlux

of investment suggests a strong

commitment to POISE’s aims and, for

the investor and company willing to work

within a market shaped by an SOE, there

are a lot of opportunities arising.

Santiago Barcon, managing director

at Arteche, a global company offering

automation solutions, is positive: “In the

energy sector, the next 20 years will be

extraordinary. Population growth, prod-

uct consumerism linked to new lifestyles,

and equipment obsolescence will all

trigger opportunities for growth in a

wide range of industries, including of

course our own. For example, there will be

a need to renew parts of already installed

wind farms. There is economic stability

and availability of labor, which allows one

to plan with fewer worries. We currently

export products, but my dream is to export

engineering. We are in the same time

zone as the USA and our engineers are

as good or better as the ones from the

United States; we can compete. Rather

than watching fatalist and overly negative

news reports, Mexicans and the wider

international community must realize

there is a lot to be done and that can

be done in Mexico.”

Though the energy sector remains and

will remain for the foreseeable future under

state control, the industry has nonetheless

been able to implement the best practices

that the private sector can provide, and in

addition has succeeded in attracting the

foreign investment that is vital to meet

both the growing needs of the Mexican

population and the clean energy require-

ments. With CFE behind the sector and

committed to pushing the development of

both gas infrastructure and renewables for-

ward, the future for Mexico is bright. •

For additional and up-

to-date information on

Mexico’s Power Industry, visit Mexico’s periodi-

cal publication at http://energiahoy.com


EMISSIONS

Rethinking Wind’s Impact on Emissions and Cycling CostsRecent reports by the National Renewable Energy Laboratory and others suggest

that the emissions-reducing benefits of renewable energy sources such as wind and solar may have been overstated and the cost of cycling fossil-fueled plants underestimated. These findings may change how utilities and policymakers weigh the costs and benefits of wind and solar energy.

By David Wagman

The American Wind Energy Associa-

tion (AWEA) said in early January that

1,833 MW of wind power capacity

had been installed during the third quarter of

2012. Those additions brought total installed

wind capacity for the first three quarters of

the year to 4,728 MW and pushed the total

installed wind capacity in the U.S. to 51,630

MW, from more than 40,000 turbines. AWEA

also reported that as of September 2012, more

than 8,400 MW of capacity were under con-

struction in 29 states and Puerto Rico. What’s

more, the wind industry has added more than

35% of all new U.S. generating capacity dur-

ing the past five years, second only to natural

gas.

All of that new wind capacity is aimed, at

least in part, at displacing fossil-fueled gen-

erating sources and reducing atmospheric

and greenhouse gas emissions such as ni-

trous oxide (NOx), sulfur dioxide (SOx), and

the still-unregulated carbon dioxide (CO2).

Wind generation has inherent benefits: The

turbines produce no emissions during their

operating lifetimes and have no fuel cost. But

some industry observers contend that adding

intermittent resources such as wind and solar

energy to the system actually increases rather

than decreases greenhouse gas emissions.

Those observers point out that many

power generators add fast-start gas-fired

generating units (generally aeroderivative

gas turbine and gas-fired engines) to back

up renewable resources and generate power

during the times when the sun doesn’t shine

or the wind doesn’t blow. Those fossil-fueled

resources are variously available as spinning

reserves or as fast-start machines that can

rapidly ramp to respond to changing output

from renewable resources. Observers also

contend that cycling or turndown operations

at baseload coal and natural gas–fired plants

to accommodate wind and solar also may

increase air emissions because those fossil-

fueled plants end up operating at less-than-

optimal levels.

A fact sheet published by AWEA said that,

on average, adding 3 MW of wind energy to

the U.S. electric grid reduces emissions from

fossil power plants by 1,200 pounds of CO2

per hour. It said adding this amount of wind

would “at most require anywhere from 0 to

0.01 MW of additional spinning reserves,

and 0 to 0.07 MW of non-spinning reserves.”

AWEA said it is likely that those reserves

would be provided by zero-emission hydro-

electric resources, but even under a worst-

case scenario in which a fossil fuel plant

with an efficiency penalty of 1.5% must be

used for reserves and all of the non-spinning

reserves would be activated, the increase in

emissions would “still be less than 1 pound of

CO2.” Given that hydropower is always dis-

patched first and seldom cycled, and coal still

provides around 40% of the electricity nation-

wide and is being cycled, this is a narrow and

highly unlikely scenario (see sidebar).

AWEA said that although the wind may

suddenly slow down at one location and

cause the output from a single turbine to

decrease, regions with high penetrations

of wind energy may have hundreds or even

thousands of turbines spread over hundreds

of miles. As a result, it typically takes min-

utes or even hours for a region’s total wind

energy output to change significantly. Yet

when the resource does unexpectedly drop,

the amount of that reduction must be added

immediately to the grid, first with spinning

reserve capacity or with fast-start assets.

The unpredictability of the resource ex-

plains the large number of gas-fired assets

built over the past several years. The trade

group said that gas-fired units make it “rela-

tively easy for utility system operators to ac-

commodate these changes without relying on

reserves.” It said the task of accommodating

variations in output can be made easier by us-

ing forecasting, which allows system opera-

tors to “predict changes in wind output hours

or even days in advance with a high degree

of accuracy.”

Assessment ShortcomingsDespite the AWEA fact sheet, industry observ-

ers have found room to question the claimed

environmental benefits of wind energy. For

example, two researchers, Warren Katzenstein

and Jay Apt of Carnegie Mellon University,

wrote in 2009 that life-cycle assessments of

renewable energy projects often failed to ac-

count for emissions from backup and cycling

fossil-fired generation sources. The pair found

that CO2 emission reductions from a wind or

solar photovoltaic (PV) system coupled with a

natural gas system are likely to be 75% to 80%

of those assumed by policymakers. Even for

the best system they analyzed, NOx reductions

with 20% wind or solar PV penetration were

30% to 50% of those expected.

To estimate emissions from fossil-fueled

generators that are called on to compensate for

variable wind and solar power, the Carnegie

Mellon authors modeled a combination of

variable renewable power with a fast-ramping

natural gas–fired turbine. They used a regres-

sion analysis of measured emissions and heat

rate data taken at 1-minute resolution from two

types of gas turbines to model emissions and

heat rate as a function of power and ramp rate.

They next determined the required gas turbine

power and ramp rate to fill in the variations in

1-minute data from four wind farms and one

large solar PV plant, and, finally, computed

the emissions from the regression model.

The research team obtained 1-minute reso-

lution emissions data for seven General Elec-

tric LM6000 natural gas combustion turbines

(CTs) and two Siemens-Westinghouse 501FD

natural gas combined cycle (NGCC) turbines.

The LM6000 CTs had a nameplate power

limit of 45 MW and utilized steam injection

to mitigate NOx emissions. A total of 145 days

of LM6000 emissions data was used in the re-

gression analysis. The Siemens-Westinghouse

501FD NGCC turbines had a nameplate pow-

er limit of 200 MW with GE’s dry low-NOx

(DLN) system and an ammonia selective cata-

lytic reduction (SCR) system for NOx control.


EMISSIONS

The Facts About Wind Energy’s Pollution Reductions

Editor: The American Wind Energy Association (AWEA) recently con-

tacted POWER to request an opportunity to respond to the editorial

“Under Siege” published in the December 2012 issue. The following

is AWEA’s response to that editorial.

As wind energy’s growth has continued, spurred by improving

technology and declining costs, wind energy’s role in reducing

harmful pollution has become even clearer. Empirical data for the

United States and Europe clearly indicates not only that wind

energy results in the expected pollution reductions by directly

offsetting the use of fossil fuels at power plants, but that by

displacing the most expensive and therefore least efficient power

plants first, wind energy results in even larger pollution savings

than expected.

There is no dispute that every MWh of wind energy added to the

power grid displaces a MWh that would have been produced by the

most expensive power plant currently operating, which is typically

the least efficient fossil-fired power plant. However, some have

attempted to claim, without support, that adding wind energy

to the power system can negatively affect the efficiency of other

power plants, reducing the emissions savings produced by wind

energy.

Fortunately, a large body of real-world data is now available

to assess how wind energy affects the efficiency of other power

plants, allowing one to approach the question from multiple an-

gles. To start with, the U.S. Department of Energy collects detailed

data on the amount of fossil fuels consumed at power plants, as

well as the amount of electricity produced by those power plants.

By comparing how the efficiency of power plants has changed in

states that have added significant amounts of wind energy against

how it has changed in states that have not, one can test the un-

supported hypothesis that wind energy has a negative impact on

the efficiency of fossil-fired power plants.

The data clearly shows that there is no such relationship, and

in fact, states that use more wind energy have seen the effi-

ciency of their fossil-fired power plants fare slightly better than

states that use less wind energy. Specifically, coal plants in the

20 states that obtain the most electricity from wind saw their av-

erage efficiency decline by only 1.00% between 2005 and 2010,

versus 2.65% in the other 30 states. Increases in the efficiency

at natural gas power plants were virtually identical in the top

20 wind states and the other states, at 1.89% and 2.03% im-

provement respectively. The efficiency of fossil-fired power plants

fared comparably well in the top 10 wind states (which obtain

between 5% and 16% of their electricity from wind), with coal

plant efficiency increasing by 0.51% in the top 10 wind-using

states and declining by 2.65% in the other 40 states, while gas

plant efficiency improved by 0.78% in the top 10 wind states and

2.17% in the other 40 states.

Similar results can be found in International Energy Agency

data for Europe, which shows that the top 5 wind countries (which

obtain between 7% and 23% of their electricity from wind) saw

the average efficiency of their natural gas power plants increase

by 11% as they ramped up their use of wind energy from 1999-

2010, larger than the 7% increase in efficiency seen across all of

OECD Europe. Over that time period, coal plant efficiency fell by

1% in the top 5 wind countries and remained unchanged across all

OECD Europe countries.

Another method to assess whether wind energy is producing

the expected emissions savings is to calculate whether increases

in the use of wind energy are correlated with decreases in the

amount of carbon dioxide emitted per MWh produced. A correla-

tion coefficient of 0 would indicate that there is no statistical

relationship between wind energy output and emissions inten-

sity, a coefficient of -1 would indicate that wind output increases

always coincided with increases in emissions, and the observed

coefficients of nearly +1 indicate that increases in wind output

nearly always coincided with major decreases in emissions. The

correlation between increasing wind energy output and declin-

ing emissions intensity in the leading wind energy countries over

the period 1999 to 2010 was extremely strong, with a correlation

coefficient of .77 for Denmark, .82 for Germany, .86 for Portugal,

.90 for Spain, and a whopping .96 for Ireland.

These correlation coefficients were far higher than for any other

possible explanatory factors for the observed decreases in emis-

sions intensity, such as increased use of hydroelectric or nuclear

energy, increased use of natural gas instead of coal, changes in

the efficiency of fossil-fired power plants, or changes in electricity

imports or exports. If wind energy were causing large declines in

the efficiency of fossil-fired power plants, zero or negative corre-

lations would have been found, instead of correlations approach-

ing 1.

These findings are further confirmed by the preliminary results

of a new report from the National Renewable Energy Laboratory

that uses empirical data from another source, EPA’s network of

power plant continuous emissions monitors, to evaluate the im-

pact of wind energy on the efficiency of all fossil-fired power

plants in the Western U.S. The in-depth, multi-year, and peer-re-

viewed analysis found that even in a scenario with wind providing

25% of all electricity in the Western U.S., wind’s total impact on

the efficiency of fossil-fired power plants would be “negligible,”

accounting for less than 0.2% of the emissions savings produced

by wind energy. As a result, carbon dioxide emissions declined by

29–34% in the 25% renewable energy case. Moreover, the analy-

sis found that adding wind energy to the grid actually slightly

increases the average efficiency of coal and natural gas combined

cycle power plants by offsetting the least efficient plants.

No matter how one approaches the question, the data is clear

that wind energy greatly reduces fossil fuel use and pollution.

Moreover, the results discussed above are in addition to a large

body of independent grid operator, utility, and government analy-

ses and data that have already examined how wind energy inter-

acts with the power system and unanimously found that wind

energy produces pollution savings that are as large or larger than

expected.

—Michael Goggin is the manager of transmission policy at the

American Wind Energy Association.


EMISSIONS

Emissions data for 11 days was obtained for

the 501FD combined cycle machine. The re-

newables data included 1-second, 10-second,

and 1-minute resolution and was from four

wind farms and one large solar PV facility

in the Eastern Mid-Atlantic, Southern Great

Plains, Central Great Plains, Northern Great

Plains, and Southwest regions of the U.S.

Based on their analysis, the authors con-

cluded that the conventional method used to

calculate displaced emissions was inaccurate,

particularly for NOx emissions. They said that

if system operators recognize the potential for

ancillary emissions from gas generators used

to fill in for variable renewable power, they

can take steps to produce a greater displace-

ment of emissions. They said that “by limiting

generators with GE’s DLN system to power

levels of 50% or greater, ancillary emissions

can be minimized.” Operation of DLN con-

trols with existing firing modes that reduce

emissions when ramping may be practical.

They also said that on a time scale compat-

ible with renewable portfolio standard imple-

mentation, design and market introduction of

generators that are more appropriate from an

emissions viewpoint may be feasible to pair

with variable renewable power plants.

Utility PerspectiveUtilities that have relatively high and grow-

ing amounts of intermittent renewable re-

sources on their systems also have analyzed

renewable integration costs, paying particu-

lar attention to the cost of wear and tear on

equipment and increased maintenance at ex-

isting conventional facilities.

For example, Public Service Company

of Colorado (PSCo), a unit of Xcel Energy,

prepared a report for state regulators in Au-

gust 2011 that said the utility would add

around 700 MW of wind power to its sys-

tem by 2015, in line with its 2007 Colorado

Resource Plan. That additional wind capacity

meant PSCo would have around 1,934 MW

of nameplate wind generation capacity on

its system. One shortcoming of its planning

process, however, was its failure to consider

wind-induced cycling costs. With growing

amounts of wind on its system, the utility

said the cost impacts both of unit cycling and

wind curtailments will increase, making it

important to consider those costs as part of its

future planning decisions. The importance of

such calculations was highlighted for a single

hour last spring when wind energy supplied

57% of the Colorado system’s electricity.

“With an ever-larger wind portfolio, the

depth and frequency of cyclical operation of

baseload units will increase and affect more

and more generators,” the PSCo report said.

“Coal-fired units that have historically been

base loaded will be required to turn-down

to their minimum capacity, or possibly turn

off entirely. These cycling evolutions will be

occurring more rapidly and more frequently

with greater levels of wind generation.”

The study said that any plant cycling causes

component wear-and-tear costs. In particular,

when a thermal generator is turned off and

on, the boiler, steam lines, turbine, and aux-

iliary components endure large thermal and

pressure stresses. Eventually, those stresses

can cause component failures and drive up

maintenance costs. During low-load opera-

tion, pressures and temperatures fluctuate

in pipes and tubes, causing fatigue and, ul-

timately, early failure. Fatigue further erodes

the designed stress tolerances of full-output

operation, or creep tolerance. PSCo identi-

fied this creep-fatigue interaction as “one of

the most important phenomena” contributing

to component failure.

Wind-induced cycling costs among PSCo’s

coal-fired fleet pose an additional “hidden”

cost of integrating wind generation onto the

system, the report said. “It is appropriate to

determine this additional wind integration cost

and appropriately burden incremental wind

power with this cost in future resource plan-

ning efforts.” A sample of the cost findings is

shown in Table 1.

The study evaluated two coal plant cycling

protocols. The first (referred to as “curtail”)

involved cycling coal plants down to their

economic minimum generation levels to ac-

commodate wind and curtailing wind in ex-

cess of the level needed to meet system load.

The second protocol (referred to as “deep

cycle”) involved cycling coal plants down to

their lower emergency minimum levels to ac-

commodate wind and curtailing wind in ex-

cess of the level needed to meet system load.

Although the analysis identified no signif-

icant difference in the cost of each protocol,

the deep-cycle protocol was found to maxi-

mize wind output while minimizing coal burn

and associated CO2 emissions. PSCo said

this protocol may result in reduced system

reliability as a result of routinely operating

baseload coal units down to their emergency

minimum loading levels. It said such a con-

dition would increase the wear and tear on

these units and possibly lead to more coal

unit outages. In contrast, the curtail protocol

would result in slightly less wind generation

than the deep-cycle protocol but would avoid

deep cycling the coal units and the potential

downside of reduced system reliability under

a deep-cycle protocol.

PSCo chose deep cycling as the preferred op-

erational protocol for its system in the near term,

given that there was no distinct cost advantage

to either protocol. However, it stopped short of

considering some additional factors that it said

could influence total costs. In particular, chang-

es in SO2 and NOx emissions that may occur to

accommodate wind due to reduced coal burn or

coal units operating at suboptimal generating

levels were not considered.

Reevaluating ImpactsThe Carnegie Mellon and PSCo studies,

among others, urge a systemwide approach

to understanding wind and solar energy’s

effects on emissions. These studies helped

lead researchers at the National Renewable

Energy Laboratory (NREL) to acknowledge

in 2012 that many efforts to assess the emis-

sions benefits of wind had failed to account

for ancillary emissions from generating units

that cycle or ramp to compensate for the re-

newable resources’ intermittent generation.

In a paper given at the IEEE Power and En-

ergy Society General Meeting in San Diego

last July, NREL researchers, along with ana-

lysts from Intertek-APTECH (IA), said that

regional integration studies have shown that

wind and solar may cause fossil-fueled gen-

erators to cycle on and off and ramp more

frequently. They identified increased cycling,

deeper load following, and rapid ramping as

leading to potential wear and tear on fossil-

fueled generators. They said this additional

wear and tear can lead to higher capital and

maintenance costs, higher equivalent forced

outage rates, and degraded performance over

time. What’s more, they said that heat rates

and emissions from fossil-fueled generators

may be higher during cycling and ramping

than during steady-state operation.

The conference paper concluded that “the

impacts of generator cycling and part-loading

Table 1. PSCo scenario results from 2011 to 2025. The dollar values are shown

as present value. Source: “Wind Induced Coal Plant Cycling Costs and the Implications of Wind

Curtailment for Public Service Company of Colorado,” August 2011

Installed wind

Cycling protocol

Cycling cost component ($,

million)

Curtailment cost component ($,

million)

Total levelized annual cost ($,

million) Total levelized cost ($/MWh)

2 GW Curtail 3.60 1.20 4.82 0.77

2 GW Deep cycle 5.10 0.10 5.21 0.83

3 GW Curtail 5.00 3.30 8.30 1.03

3 GW Deep cycle 8.20 0.60 8.75 1.08


EMISSIONS

can be significant; however, these impacts are

modest compared with the overall benefits of

replacing fossil-fueled generation with vari-

able renewable generation.”

The NREL/IA team along with GE En-

ergy built on this initial work with a second,

more comprehensive study using continuous

emissions monitoring (CEM) data obtained

from the Environmental Protection Agency to

model ramping and cycling effects across the

Western Interconnection based on a variety of

scenarios of solar and wind penetration. The

impacts of solar- and wind-induced cycling on

emissions proved to be mixed, one of the re-

port’s authors told POWER in an interview.

“My conclusion regarding SO2 is there is

hardly any increase at all, since SO2 is con-

trolled by scrubbers,” said Steve Lefton, di-

rector of power plant projects at IA. He said

plant operators can control SO2 emissions

during ramping and cycling events by bring-

ing more scrubber modules online sooner.

Lefton said that analysis of hundreds of coal-

fired units showed that SO2 limits were ex-

ceeded only a few times and only for brief

periods of time during startup or ramping.

NOx emissions, by contrast, are a function

of temperature, meaning their production

likely will be higher until temperatures at the

SCR inlet reach around 500F. He character-

ized the resulting increase in NOx emissions

as “minor” and said that it takes time to raise

SCR inlet temperatures high enough to sup-

port efficient catalytic reduction.

Dr. Greg Brinkman, an NREL mechani-

cal engineer and analyst, and report coauthor

with Lefton, said that NOx emission rates

(in pounds per megawatt-hour) from a typi-

cal coal-fired unit would be 14% less when

operated at part load compared to operating

the unit at full load. For gas units, NOx emis-

sions are roughly 10% to 20% higher during

part-load operation compared to full-load

operation. NREL modeled the response of

the electric power system to renewable pen-

etration, considering part-load, startup, and

ramping emission penalties. “Most emission

rates at fossil-fueled generators changed by

less than 2%,” he said.

“CO2 emissions rates from the average

coal plant don’t change; SO2, and NOx emis-

sions rates from average coal, gas combined

cycle, and gas combustion turbine plants

increase or decrease by up to 2%, depend-

ing on plant type and the mix of wind and

solar. SO2 emissions rates from coal plants

increased or decreased depending on the mix

of wind and solar. Viewed from the perspec-

tive of avoided emissions, CO2, SO2, and NOx

benefits from wind and solar were all within

5% of what we expected based on the typical

emission rates of the displaced generators,”

Brinkman said.

Effects on Maintenance CostsAlthough any change in emissions appears to

be relatively minor, the same cannot be said

for maintenance costs due to ramping and

cycling.

“From all reports, I’d say we’ve either

been spot on or under-projecting cycling-re-

lated damage” that results from fossil-fueled

units following intermittent renewable sourc-

es, said Lefton. “Yes, wind is a great thing,

but it’s not free.”

Turbine blade damage and generator fail-

ures were linked to ramping. These findings

came after Lefton and his team analyzed

some 400 data sets that included long-term

operating and maintenance costs and cycling

data. The findings showed that even combus-

tion turbines and reciprocating engines de-

signed for quick starts, ramping, and cycling

showed higher maintenance costs, elevated

numbers of forced outages, and increasing

numbers of generator failures.

“Generator failures used to be rare, but

now they rank third in insurance claims filed

for combined cycle machines,” Lefton said.

He noted higher incidences of heat recovery

steam generator tube failures as well as more

frequent turbine overhauls. Other maintenance

issues linked to cycling include thermal barrier

coatings that spall off, leaving the base metal

exposed and vulnerable to cracking.

Dr. Debra Lew, an analyst with NREL and

coauthor of the report, said while coal units

cost the most to start up, gas-fired combustion

turbines appear to be the most susceptible to

higher maintenance costs as a result of ramp-

ing and cycling caused by wind and solar

penetration because these units are started the

most often. She said that wear and tear as a

result of cycling to follow renewable energy

may increase operations and maintenance

costs for all types of fossil generation by $35

million to $157 million a year across the West-

ern Interconnection, as shown in Table 2, for

wind and solar penetrations up to 33%.

Last November, Lefton and several of

his colleagues at IA presented a paper, “The

Increased Cost of Cycling Operations at

Combined Cycle Power Plants,” at the Inter-

national Conference on Cyclic Operation of

Power Plants & CCGT. The paper reported

that higher penetration of renewables on the

North American grid is increasing the num-

ber of on-off and load-cycling operations,

which the authors said will increase the need

for spinning reserve megawatts, their costs,

and the startup charges for putting combined

cycle plants online.

The desire for faster online times increas-

es the severity of damage during gas turbine

starts and is increasing thermal transients

with more rapid gas turbine acceleration

and higher mass gas flows at higher exhaust

temperatures that reach heat recovery steam

generators (HRSGs). The paper said these

factors affect the gas turbine and the HRSGs,

as well as the balance of plant and water

chemistry, ultimately reducing overall plant

reliability. The average starts on these gas

turbines/combined cycle units are increas-

ing, and run times are generally decreasing.

Though capacity factors may be decreasing,

production costs will likely rise significantly

due to cycling operations. The paper sug-

gested that cost estimates made by industry

often underestimate by a large margin the ac-

tual costs that cycling operations can incur,

as shown in Table 3.

Wind Farm Life ExpectancyWind farm life expectancy also may reduce cal-

culated environmental benefits and increase the

Scenario

Cycling and

ramping costs

Increased cycling and ramping

caused by renewables

Increase in cycling and ramping

cost compared to no renewables

No renewables $271–$643 million NA NA

High wind $321–$769 million $50–$126 million 18%–20%

High mix $306–$738 million $35–$95 million 13%–15%

High solar $324–$800 million $53–$157 million 20%–24%

Table 2. Renewables increase cycling and ramping costs. Source: NREL

Unit type

Typical industry value (without

consideration of true costs) Potential range of total costs

Small drum $5,000 $3,000–$100,000

Large supercritical $10,000 $15,000–$500,000

GT simple cycle $100 $300–$80,000

GT combined cycle $200 $15,000–$150,000

Table 3. Estimated cycling costs are often wrong. Costs provided in this table

are per cycling event. Source: Steve Lefton, et al.


EMISSIONS

total investment needed to achieve environmen-

tal goals, particularly in the UK and Europe.

A December 2012 report, published by the

UK-based Renewable Energy Foundation and

written by Gordon Hughes of the University

of Edinburgh, scrutinized wind farm lifecycle

emission benefits. The foundation in the past

has criticized the UK government’s Renewables

Obligation policy, saying the subsidy distorts

markets as well as the generation mix.

The Hughes study examined wind farm

performance in the UK and Denmark and con-

cluded that, after allowing for variations in wind

speed and site characteristics, the average load

factor of wind farms declines as they age, prob-

ably due to wear and tear. By 10 years of age,

the contribution of an average UK wind farm

to meeting electricity demand was said to have

fallen by as much as one-third.

The report said this performance decline

means that it is “rarely economic to operate

wind farms for more than 12 to 15 years.”

Investors who expect a return on their in-

vestment over 20 to 25 years will be “dis-

appointed,” the report said. What’s more,

policymakers who expected wind farms built

before 2010 to contribute toward CO2 targets

in 2020 or later should allow for the possibil-

ity that the total investment required to meet

those targets will be much larger than previ-

ous forecasts suggested.

The study based its findings on data reflect-

ing the monthly output of wind farms in the

UK and Denmark. Normalized age-perfor-

mance curves were estimated using statistical

techniques that allowed for differences be-

tween sites and over time in wind resources,

and other factors. The normalized load factor

for UK onshore wind farms was found to de-

cline from a peak of about 24% at age one to

15% at age 10 and 11% at age 15. The decline

in the normalized load factor for Danish on-

shore wind farms showed a fall from a peak

of 22% to 18% at age 15. For offshore Danish

wind farms, the normalized load factor was

shown to fall from 39% at the start of com-

mercial operation to 15% at age 10.

Hughes said that the reasons for the ob-

served declines in normalized load factors

could not be fully assessed using the data

available, but he speculated that “outages due

to mechanical breakdowns” appeared to be a

contributing factor.

Hughes said that analysis of site-specific per-

formance showed that the average normalized

load factor of new UK onshore wind farms at

age one “declined significantly” between 2000

and 2011. In addition, he found that larger wind

farms had worse performance than smaller wind

farms. Adjusted for age and wind availability,

the overall performance of wind farms in the

UK has “deteriorated markedly” since the be-

ginning of the century, he found.

According to Hughes, these findings have

implications for policy toward wind generation

in the UK. First, they suggest that the current

government subsidy is “extremely generous”

if investment in new wind farms remains prof-

itable despite the decline in performance due

to age and over time. Second, meeting the UK

government’s targets for wind generation will

require a much higher level of wind capacity

and capital investment than current projections

imply. Third, the structure of contracts offered

to wind generators may require modifications,

because few wind farms will operate for more

than 12 to 15 years.

In releasing the report, the Renewable En-

ergy Foundation said that policymakers who

were expecting wind farms built before 2010

to contribute toward CO2 targets in 2020 or

later “must allow for the likelihood that the

total investment required to meet these tar-

gets will be much larger” than previous fore-

casts suggested. ■

—David Wagman is executive editor

of POWER.

For more information, call Wright’s Media

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PLANT DESIGN

Steam Turbine Blade Reverse Engineering, Upgrade, and Structural Design Steam turbine blade cracking often suggests the need for an upgraded blade

design. Follow the process of reversing engineering a failed blade to pro-duce a more reliable and efficient design.

By Eugene A. Chisley, PhD, PE and Eric Prescott, Alstom Thermal Services

Blade reverse engineering is widely

recognized as a crucial step in the

product design cycle. Blade surface

reconstruction is an iterative process to de-

velop mathematical models from existing

physical objects for finite-element analysis

(FEA), computational fluid dynamics, and

rapid prototyping in order to reduce product

design lead time.

In this process, precise data point mea-

surement is important to create a valid shape.

Due to the complexity of blade shape, the re-

sultant model geometry change can lead to a

large alteration in turbine performance (see

sidebar). Therefore, blade shape control is

critical in the design process. In essence, the

blade is a complex cantilever beam, and gen-

erating an accurate simulation result makes

turbine blade analysis challenging.

Finite-element analysis is the accepted

tool for turbine blade structural analysis.

Both the model development upgrades and

analysis will be discussed.

Turbine Blade Design FundamentalsTurbine blade design involves blade solid

model development, thermo-aerodynam-

ics, and structural mechanics disciplines.

The process of reverse engineering begins

with determining the function of the ma-

chine part (referred to as “capturing design

intent”). The accuracy of reverse engineer-

ing is limited by the applied measurement

and computer-aided modeling techniques.

A few of the major limitations are wear of

the part; numerical, sensing, and approxi-

mation errors; and manufacturing meth-

ods. In order to ensure and enhance blade

efficiency, optimizing the shape design of

rotating and stationary blades is essential.

The necessary steps for turbine blade re-

verse engineering are similar to those used

in a new-product development practice

(Figure 1).

The process for steam turbine blade design

from concept to actual product is an iterative

one that includes computer-aided design

(CAD) models, including blade surface for

computer-aided manufacturing, FEA—and,

if necessary, computational fluidized dy-

namics; reliability performance analysis;

and design modification. The following case

study presents an industrial application of an

integrated reverse engineering approach to

turbine blade design. The study describes a

developed engineering approach to designing

and upgrading a steam turbine blade from an

existing part.

Data Point, Surface, and Cross-Section GenerationTurbine blades present challenges to manu-

facturers to produce and maintain the blade’s

complex free-form surfaces and seemingly

convoluted shapes. Contact measuring devic-

es cannot gather enough data points to cre-

ate an accurate surface profile of the airfoil’s

irregular shape. Laser scanning is the best

measurement method to capture the turbine

blade’s entire complex features. After scan-

ning the blade from multiple perspectives,

the points of cloud data are rotated into the

same reference frame and assembled into an

exact 360-degree, 3-D model of the scanned

part.

The data points for this case study were

edited using Geomagic Studio software.

Following that, the blade’s entire 3-D sur-

face was generated in the same environ-

ment. A “perfect” CAD model is necessary

for machining and FEA because turbine

blades must be highly consistent in shape,

1. Process steps. Schematic of the blade model development process. Source: Alstom

Thermal Services

Laser scan of the blade Hard gauge measurement

Blade reverse engineering

Input sample blade

CMM profile & general data

Airfoil model generation Blade root design

Assemble blade model by links (base, blade, tenon)

Blade manufacturing Quality check Blade finite element analysisYes

No


PLANT DESIGN

weight, and geometry in order to avoid vi-

bration and other performance-impeding

characteristics. The entire CAD model

can be compared with the original part to

ensure the model’s quality. The inspection

for this case study was performed with

Geomagic Qualify engineering software.

Inspection of the model and the original

part indicated very good agreement (~±0.1

mm).

Tenon Inspection, Analysis, and InstallationQuality inspection of the turbine shaft as-

sembly extends to the wheel steeple and the

blade in order to collect information about

the parts’ structural integrity and to draw a

conclusion about the repair process, which

can include actual repair or redesign. In

this case, nondestructive testing (NDT) of

the blade’s tenon revealed that a crack had

initiated at the root of the tenon radius area

(Figure 2).

The crack in the area of the tenon root

at the base of the existing blade probably

was caused by an improper size root radius,

which could initiate cracking after the rivet-

ing process. The cracks appear to propagate

after every cycle of the turbine operation se-

quence. Analysis was needed to determine

the crack initiation mechanism at the root of

the tenon.

A 2-D FEA indicated a distortion at the

tenon root radius area after peening, as

shown in Figure 3. Peening the tenon in-

volves deliberate plastic deformation, mak-

ing it easy to understand the importance of

high ductility in the blade material.

Low ductility may create serious prob-

lems during the peening process, including

cracks and even fractures in the tenons. The

most critical process is riveting the tenon

to deform it into the classic “river” shape

as part of the shroud attachment process;

without this step, the tenon could not be

attached. Clearly, correct assembly of the

shroud band segments and riveting of the

tenons are critical to long-term reliability.

The accepted refurbishment technique for

blade tenon assembly is to reattach or rese-

cure the cover band. Weld repair for blades

where the crack was detected is one tech-

nique that was applied for purposes of this

case study. Additional use of under-cover-

band brazing further increased security of the

attachment.

Alstom’s Long Turbine Blade

Alstom introduced its LP75 Last Stage Blade1 (LSB) last November

for nuclear steam turbines. Alstom claims this 75-inch blade is

the longest in the world and its exhaust area of 58 square meters

is the largest of any on the market. Designed for use in the low-

pressure section of Alstom’s Arabelle nuclear steam turbine, the

LP75 builds on Alstom’s existing LP69 turbine blade to improve

performance and achieve the best possible efficiency from nuclear

steam turbines (Figure 4).

The LP75 provides a reduction of one-fifth in exhaust losses

compared with the existing LP69. This means that energy waste is

minimized while electrical output can be maximized. Depending on

project-specific conditions, an output gain of 10 MW is expected.

With this new blade, the Arabelle LSB line now offers three sizes

(LP57, LP69, and LP75) and greater flexibility in plant design.

Featuring the same welded rotor technology and lightweight LSB

design of those earlier models, the LP75 also uses similar manu-

facturing processes and shares many parts, the result of a progres-

sive product evolution.

4. Longest in the world. Alstom claims that the 75-inch-long

last stage blade on its Arabelle nuclear steam turbine is the lon-

gest in the world. The Arabelle steam turbine currently powers six

nuclear units and is under various stages of construction in another

18 units in four countries. Courtesy: Alstom

2. Tenon crack. Comparison of the origi-

nal part with the developed model revealed a

crack that began at the root of the tenon ra-

dius area. The areas with the highest stress

are shown in red. The three figures on the

right represent the blade cross-section near

the root, mid-section, and tip. Source: Alstom

Thermal Services

3. Distortion revealed. 2-D ANSYS

model of the blade tenon after peening. The

lower graphic indicates some distortion of

the root radius after peening. Source: Alstom

Thermal Services


PLANT DESIGN

Shaft Steeple Inspection and Redesign NDT of the steeple revealed that a crack initi-

ated at the root of the steeple hook’s radius

areas and appeared in every hook. In order

to modify the stress field at the cracked area

of the steeple hooks, a “fir tree” steeple con-

figuration was proposed at the joint between

the turbine blade and the disk. This joint rep-

resents the most critical load path within that

assembly. A fir tree hook blade configuration

has been commonly implemented in turbines

because this design can accommodate mul-

tiple areas of contact over large contact loads.

Figure 5 displays the proposed fir tree blade-

steeple configuration as a possible repair so-

lution. The new blade base design is shown

in Figure 6.

Design of the fir tree geometry was car-

ried out using a commercially available CAD

package. The model was defined parametri-

cally in order to incorporate changes through-

out the design optimization process. Every

step of the modeling process was checked

to make sure an adequate geometry could be

produced; otherwise, a geometry failure was

a signal to the optimizer to cancel or modify

the model and the analysis. The blade root

and the disk-steeple geometry were defined

in the same way as the basic tooth, with fur-

ther parameters and rules needed.

Because the fir tree steeple cross-sectional

geometry is constant along the root center

line, it is possible to assume that stress is

present in two dimensions, although the load

is actually in three dimensions. Nonetheless,

it is still possible to assume that each section

behaves essentially as a 2-D axial-symmetric

problem with different loading applied on the

hooks.

In order to verify the feasibility of the

fir tree configuration, comprehensive 2-D

axial-symmetric (steeple) and 3-D (blade)

FEAs were executed on the original and the

updated fir tree region of the blade disk as-

sembly. Two main goals of these analyses

were to create a geometric feature capable

of fitting into the existing steeple domain (in

other words, the part can be machined into

the existing straight hook geometry) and to

decrease significantly the notch stress con-

centration in order to increase the structure’s

low cycle fatigue life.

A 2-D finite element model was de-

veloped using commercial ANSYS code,

and axial-symmetric boundary conditions

were applied. High mesh density was used

throughout the interface region where a steep

5. Proposed configuration. Schemat-

ic of the proposed fir tree configuration and of

the original part comparison. Source: Alstom

Thermal Services

6. New blade base design. The de-

sign of the proposed fir tree base of the blade.

Source: Alstom Thermal Services


PLANT DESIGN

gradient in stress and strain was expected.

The 2-D models were meshed with eight-

node quadrilateral elements that provided a

much better solution. The results of the FEA

indicated that the peak stresses at the notch

areas were reduced significantly using the fir

tree root configuration.

With the aim of ensuring accuracy of the

finite-element model solution, a 3-D blade

model was developed. The turbine stage was

made up of 20 pieces of seven-pack blade

assemblies. To obtain an accurate finite-ele-

ment model solution, it was crucial to recre-

ate real working conditions, especially when

modeling a part of a large assembly. A cyclic

boundary condition was applied to the model

to analyze the entire stage, and frictional con-

tact elements were installed (with a friction

factor = 0.15) between the blade-steeple in-

terface surfaces. The model was meshed with

10-node tetrahedron elements, where the

contacting surfaces and the hook radius areas

were refined to increase accuracy. All mod-

els were subjected to centrifugal loading by

allowing the disk and the attached blades to

rotate with a specific angular velocity. In this

study, the angular velocity was 3,600 revolu-

tions per minute.

The equivalent stress distribution of the

base line and the fir tree blade hooks is

shown in Figures 7 and 8. The results in-

dicate that by applying fir tree root con-

figuration, the overall stress level is reduced

significantly. It can be seen that reduction in

the maximum notch stress on the order of

25% can be achieved for fir tree root design,

and the low cycle fatigue life is increased

proportionally.

In multistage turbomachinery, the interac-

tion between the nozzles and the blades gen-

erates an excitation force on the blades, which

comes from the wake of the upstream/down-

stream nozzles. The fundamental frequency

of the excitation force due to the interaction

between the nozzle and the blade is the ro-

tor speed multiplied by the nozzle count. If

the blade’s natural frequency coincides with

the frequency of the excitation forces, the re-

sultant stress may cause blade failure due to

high-cycle fatigue.

Modal analysis is a powerful tool to as-

sist in identifying and eliminating this fa-

tigue problem. In this study, FEA was used

to investigate turbine blade responses under

running conditions. Finite-element modeling

can be used to predict vibratory natural fre-

quencies and mode shapes. The rotor speed

at which significant forced vibration may oc-

cur is predicted with frequency speed. The

natural frequency of each blade vibration

mode predicted by modeling and the forc-

ing frequencies as the function of the rotor

speed can be displayed on a single graph.

The intersection of the curves generated by

this analysis indicated the integral order reso-

nance points at which the possible vibratory

stresses exist. ■

—Eugene A. Chisley, PhD, PE, and Eric Prescott are with Alstom

Thermal Services.

7. Reducing stress. The base line blade

hooks’ equivalent stress distribution is illus-

trated. Areas in red represent the presence

of very high stresses during operation and

where the cracks occurred in the root radius.

Source: Alstom Thermal Services

8. Improving fatigue life. The fir tree

blade hooks’ equivalent stress distribution

has been significantly reduced with the new

attachment design. Source: Alstom Thermal

Services

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

New HRSG Line for 100-MW Gas TurbinesATCO Emissions Management (ATCO) announced the addition of heat recovery steam generators (HRSGs) to its line of gas turbine auxiliary equipment for the power, oil, gas, and cogeneration markets. The new HRSG product, an energy recovery heat exchanger that recovers heat from a hot gas stream, will initially serve facilities with gas turbines up to 100 MW. The company’s nitrogen oxide and noise reduction technologies with heat recovery have enabled it to offer all acoustic, air emissions, and heat recovery scope on gas turbine projects, it says. Each HRSG is custom-designed in Minneapolis, then fabricated in OEM-approved manufacturing facilities around the globe. (www.atcoem.com)

EPA-Compliant Particulate MonitorFiltersense’s new continuous particulate emissions monitor and baghouse leak detector incorporates “Automatic Zero and Span Checks” to eliminate manual calibration audits, as required by the U.S. Environmental Protection Agency (EPA) for Maximum Achievable Control Technology (MACT) standards and other regulations for fabric filter particulate emissions monitoring. In addition to internal self-checks, the company’s field-proven induction-sensing and protected-probe technologies may also provide enhanced reliability over older opacity and triboelectic technologies, particularly in difficult applications such as coal, steel, and cement spray dryers. Benefits include EPA compliance, eliminating cleanup costs, preventing the escape of valuable powders, and protecting downstream equipment such as blowers and HEPA filters. (www.filtersense.com)


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POWER

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Advertisers’ indexEnter reader service numbers on the FREE Product Information Source card in this issue.

Abresist Kalenborn . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 . . . . . . . 14 www.abresist.com

Applied Bolting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 . . . . . . . 22 www.appliedbolting.com

Baldor electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 . . . . . . . 11 www.baldor.com

Beumer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 . . . . . . . 13 www.beumer.com

Brand energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 . . . . . . . . 6 www.beis.com

Burns & Mcdonnell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 . . . . . . . 15 www.burnsmcd.com

Carver Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 . . . . . . . 17 www.carverpump.com

exxon/Mobil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 . . . . . . . . 8 www.exxonmobil.com

Foster Wheeler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 4 . . . . 23 www.fwc.com

Hytorc inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 . . . . . . . . 7 www.hytorc.com

insituform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 . . . . . . . . 2 www.insituform.com

Martin engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 . . . . . . . 20 www.martin-eng.com

nol-tec systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 . . . . . . . . 9 www.nol-tec.com

Orion instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 3 . . . . 24 www.orioninstruments.com

Paharpur . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 . . . . . . . 16 www.paharpur.com

Pentair valves & Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 . . . . . . . . 5 www.pentair.com

Phillips 66 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 . . . . . . . . 3 www.phillips66lubricants.com

Power industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 . . . . . . . . 4 www.piburners.com

sealeze . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 . . . . . . . 12 www.sealeze.com

sturtevant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 . . . . . . . 18 www.sturtevantinc.com

teAM industrial servce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 . . . . . . . 10 www.teaminc.com

victory energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 . . . . . . . 19 www.victoryenergy.com

Westinghouse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 2 . . . . . 1 www.westinghousenuclear.com

Page

Reader Service Number

ClAssiFied Advertising Pages 72-74 . to place a classified ad, contact diane Hammes,

512-250-9555, dianeh@powermag .com

Page

Reader Service Number

14_PWR_030113_Classified_p72-75.indd 75 2/13/13 7:07:35 PM


COMMENTARY

Biogas: An Alternative Energy SourceBy Sarah K. Walls

Most professionals in the energy industry know about bio-mass; fewer of us are conversant with biogas. This com-mentary explains the basics of biogas, with a focus on its

current use and future potential as a source of electrical power.

What Is Biogas?Biogas is produced from anaerobic digestion of biodegradable or-ganic matter, or “biomass.” Bacteria present in, or added to, the biomass ferments it anaerobically (without oxygen), through bio-chemical reactions. The constituents of biogas include methane (60% to 80%), carbon dioxide (20% to 40%), and trace amounts of hydrogen sulfide, nitrogen, and other impurities. Cleaning to remove impurities and moisture is necessary before biogas can be used as an energy source for certain alternatives, such as compressed natural gas. This purification is known as “upgrad-ing” the biogas. Rendering biogas to be at least 98% methane produces a product known as “biomethane.” Biomethane per-forms identically to conventional fossil fuel natural gas, with all the same benefits and uses, and is one of the cleanest and most efficient alternative energy sources.

Major sources of biogas include municipal wastewater treat-ment plants, industrial waste treatment facilities, landfills, and agricultural sources such as manure and energy crops. In the past, such facilities used anaerobic digestion for stabilization, pathogen reduction, and volume reduction of wastes prior to disposal or land application. In many cases, biogas was simply flared.

Biogas now is developing into a significant alternative energy source. Using biogas to produce electricity satisfies several regu-latory concerns at once. Greenhouse gas emissions are reduced, because the release of methane is prevented; green and renew-able energy is produced; volumes of waste requiring storage and disposal are reduced.

Uses of BiomethaneAdvantageous uses of biomethane include combined heat and power (CHP), boiler fuel, and injection into natural gas pipe-lines, along with use of compressed biomethane and liquefied biomethane for vehicle fuels. CHP systems, which produce both mechanical and thermal energy, can use biogas to produce elec-tricity. The electricity produced can be used on-site, which reduces the facility’s electrical costs, or fed into mainstream power grids. CHP uses for biogas include internal combustion engines, combus-tion gas turbines, microturbines, fuel cells, and steam turbines.

In other countries, especially in Europe, where the cost of electricity is much higher than in the U.S., anaerobic digestion for biogas production is used widely. Anaerobic digestion facili-ties utilizing “energy crops,” such as corn, are already built or in progress in Germany, Sweden, Poland, Hungary, and Denmark. These facilities produce biogas, whereas in the U.S., energy crops are being used for production of fuel alcohol or ethanol. The

production of biogas from energy crops is much more energy-efficient than the production of ethanol: For the same quantity of energy crop converted to alternative energy, the net energy value produced is greater with biogas.

The Kyoto Protocol has pushed other countries to establish renewable energy targets and promote development of renew-able energy technologies. Germany was the first nation to enact feed-in-tariff (FIT) laws promoting biogas. The FIT legislation requires utilities to buy the electricity produced by biogas gen-erators. Even German farmers can generate electricity from bio-gas and sell it to the grid.

Slow Start in the U.S. Certain barriers have prevented broader use of biogas in the U.S. These barriers include less-than-favorable economics, lack of capital, technical complications, and air permitting delays. How-ever, while the up-front capital investment necessary is high, benefits over the entire life cycle can exceed the initial costs.

The Village Creek Water Reclamation Facility in Fort Worth, Texas, is a prime example of using biogas to produce electricity. This cutting-edge municipal facility uses low-Btu methane bio-gas generated as a by-product of its anaerobic sludge digesters, six of which have been upgraded to take in high-strength liquid industrial wastes to supplement biogas production. The raw, un-treated biogas, combined with biogas contributed by a nearby landfill, passes through a dehydrator prior to being burned as fuel in two 5.2-MW combustion turbines. The waste heat from the engines is combined with additional biogas in a duct burner to fire boilers, which produce steam. The steam is used to oper-ate two steam turbines that operate two of the 1,000-horsepow-er blowers, which provide aeration for the activated biological treatment part of the facility. Once all units are operating, the facility will produce more biogas than is needed for its own op-eration and will have additional electricity to sell to the grid or trade for uses at other facilities.

Bright Future in the U.S. The future of biogas in the U.S. will depend to a large extent upon the price of natural gas. Last year, President Obama’s Ex-ecutive Order 13624 recognized the barriers that have led to under-investment in CHP and directed certain agencies and ex-ecutive departments to convene stakeholders with the goal of accelerating investment in industrial energy efficiency, and in CHP in particular. A national goal was set of 40 GW of new, cost-effective CHP by the end of 2020—a 50% increase from today.

Biogas has much potential, and there has never been a better time for owners, state and federal government leaders, lenders, and utilities to work together to accomplish this challenging goal. ■

—Sarah K. Walls ([email protected]) is a partner with Cantey Hanger LLP.

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