international april 2012

Vol. 156 • No. 4 • April 2012

Waste-to-Energy Options Increase

Fukushima: One Year Post-Disaster

Sustainable Water Resources

Could Boiler MACT Benefit Biomass?

Intelligent Control of FBC Boilers

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April 2012 | POWER www.powermag.com 1

ON THE COVERThe Lee County (Fla.) waste-to-energy plant burns wastes at more than 1,800F, generat-ing up to 53 MW of electricity. It operates as a zero-liquid-discharge facility using recycled wastewater from a municipal wastewater treatment plant. Ash remaining from the com-bustion of trash is transported to a landfill. The facility also recycles about 1 million pounds of electronics each year, among other recyclable waste streams, ranking Lee County as number one for recycling in Florida. Photo courtesy: HDR Inc.

COVER STORY: RENEWABLE ENERGY30 Waste-to-Energy Technology Options Increase but Remain Underutilized

Though the U.S. lags in maximizing the potential of state-of-the-art waste-to-energy (WTE) technologies, those technologies are widely recognized by government agen-cies around the world as effective resource management solutions. Coupled with recycling and other waste-reduction measures, they can decrease the volume of landfilled municipal solid waste by roughly 90% while generating energy that sub-stantially reduces emissions of methane, a potent greenhouse gas. HDR Inc. reviews the potential for WTE as well as its fuels, processes, and technologies.

SPECIAL REPORTS

BIOMASS POWER

40 Has Boiler MACT Improved the Future for Biomass Power?Recent and forthcoming environmental regulations, plus the demand for more re-newable resources, have brightened the economic outlook for new biomass power plants in the U.S.

NUCLEAR POWER

44 Happy Days for Nuclear Power?Our report on a recent nuclear industry conference and the impact of the Fukushima disaster on Japan’s prospects for nuclear generation concludes that nuclear power is still in the race, but it’s not going to be the pace-setter for the foreseeable future.

FEATURES

PLANT CONTROLS

48 Intelligent Control of FBC BoilersThe number and size of fluidized bed combustion (FBC) boilers used for power gen-eration is growing. Two 100-MW FBC boiler plants burning 100% biomass are now under construction in the U.S. Here’s the latest on recommended combustion con-trol approaches.

WATER MANAGEMENT

52 Promoting Sustainable Water Usage in Power GenerationPOWER talked with representatives from an energy research institute, a leading na-tional energy laboratory, a U.S. water and energy technology manufacturer, and a large consulting firm. From regulations to technical innovations, these experts ad-dressed the growing interdependence of water and power.

Established 1882 • Vol. 156 • No. 4 April 2012

30

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www.powermag.com POWER | April 20122

value chain—from repairs, coatings and design engineering, to machining, fi eld services and the world’s most

PLANT COOLING

58 Clever “Helper” Tower Solves Cooling Water DilemmaWater shortages and regulatory requirements are turning up the heat on genera-tors to manage water use more carefully. This article offers suggestions for thinking through your options for addressing those imperatives and includes a case study of a plant that found an effective and creative approach to dealing with them.

INDUSTRY COMMUNICATION

63 POWER Gets Social Social media platforms are no longer just for college kids. If you’re not using at least some of them to enhance your industry knowledge and visibility, you may be miss-ing out. We offer a quick intro to how POWER can help you get connected profes-sionally with the various digital tools.

DEPARTMENTS

SPEAKING OF POWER6 Technology Trumps Policy

GLOBAL MONITOR8 Less-Familiar Generation III+ Reactors Make Inroads

10 An “Exploding Lake” Becomes a Power Source

12 THE BIG PICTURE: Nuclear Aftershocks

14 New South Korean and Russian Reactors Go Online

14 Two New Offshore Farms Turning Despite Stagnant Global Wind Market

18 India’s Chronic Coal Shortages Threaten Coal Power Ambitions

18 POWER Digest

FOCUS ON O&M22 Safe Work Practices in Confined Spaces at Power Plants

24 Preventing Downtime by Picking the Best Switch Technology

LEGAL & REGULATORY28 Suing for (Pipeline) Safety

By Vidhya Prabhakaran, Davis Wright Tremaine LLP

64 NEW PRODUCTS

COMMENTARY68 Natural Gas: Secure Supply for Today and the Future

By Jim Johnson, president of Chesapeake Energy Marketing Inc.

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

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Over 100 years experience,and still looking to the future.

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SPEAKING OF POWER

Technology Trumps Policy

An energy policy should be the result of inclusive debate and a consensus approach to the means to leverage

all of a country’s energy assets, including innovation and technology, to the advan-tage of its citizens. Current U.S. energy policy fails on all counts.

In this column last month, I used gov-ernment source materials to dispel the myth that the U.S. has limited reserves of fossil fuels. I concluded that we are not short of fossil fuels but short on policies that will allow responsible de-velopment of those fossil fuel resources. In particular, natural gas reserve predic-tions, admittedly a moving target, are voluminous. The numbers are so large that the current debate is about how many hundred years’ worth of gas is in the ground rather than when gas sup-plies will be depleted.

New Technology Directions Some readers wrote saying that these enormous natural gas reserve estimates should be sufficient reason to quickly move toward a natural gas–based econ-omy. T. Boone Pickens agrees with that conclusion, and I certainly lean in that direction. However, writing energy policy in the age of rapid technology advances is much like steering an accelerating car while looking only in the rear view mir-ror—you can only see where you’ve been and not where you are going. And therein lies the tension between energy policy and technology: The schedule for future tech-nology breakthroughs, such as the drilling technology advances that are producing a bounty of natural gas unimaginable just a decade ago, is not predictable.

There are thousands of ideas germinat-ing in researchers’ laboratories today, and a few will become the next big thing. Per-haps the next game-changing technology will be in the field of solar photovoltaic (PV) cells. Alta Devices, for example, just announced that its tests of a new gallium arsenide–based solar panel reached 23.5% efficiency, the highest achieved to date by any solar cell. Chris Norris, the CEO of Alta Devices, has said that the company’s goal

is to “compete with fossil fuels without government subsidies” and get to a level-ized cost of energy of $0.06 to $0.07 per kilowatt-hour.

Should Norris reach his cost goal (and when teamed with some form of efficient, small-scale electricity storage technol-ogy), then the impact on the electricity industry could be meaningful. Perhaps load migration from grid sources to be-hind-the-meter PV panels will accelerate, thereby causing all sorts of unanticipated policy problems for utilities and regula-tors. Like the Alta Devices solar cells, the most promising technologies will be funded by private industry because a free market amply rewards the best ideas.

Playing FavoritesThere is little chance of renewed debate on a new national energy policy (ignor-ing President Obama’s recent “all-of-the-above” strategy rhetoric) because the president doesn’t want to negotiate an energy policy with Congress. I’m con-vinced that Obama’s de facto strategy is to fracture and marginalize the legislative branch while he moves in the two policy

directions of his liking: first, dabbling in the market by dangling tax credits, cash incentives, and loan guarantees to spur development of government-favored, yet market-spurned technologies, and second, letting loose the regulators on out-of-fa-vor, yet low-cost fossil fuel technologies. Today, coal-fired generation is suffering death by a thousand cuts at the hands of the Environmental Protection Agency, and there are at last count a dozen govern-ment agencies diligently developing new fracked gas regulations. All the while, Congress remains but a spectator.

The only real energy policy is one in which government policies encourage de-velopment of all forms of domestic energy supplies and avoids becoming the arbiter of which technology is a market winner or loser. The best ideas will always find private investors because the potential rewards in a free market are substantial. Until an unfettered market returns in the future, be thankful that the laws of phys-ics and not politics guide technology and innovation. ■

—Dr. Robert Peltier, PE is POWER’s

editor-in-chief.

Introducing a New Editor and GAS POWER

The best magazine edi-

torial team in the power

generation industry just

got stronger. I’m pleased

to announce that Thomas

W. Overton, JD has joined

the POWER editorial staff

as our gas technology editor. Tom has over

15 years of experience in scientific and

professional publishing and is a licensed

California lawyer specializing in copyright

and intellectual property issues. Before

joining the publishing world, Tom served

in the U.S. Navy as a nuclear-qualified ma-

chinist’s mate, so he also has a hands-on

understanding of power generation tech-

nology. I urge you to contact Tom if you

have gas industry news to share or an

article idea. Tom works from his office in

California and can be reached at tomo@

powermag.com and followed on Twitter

@thomas_overton.

Tom’s primary responsibility is heading

up POWER’s newest electronic publication,

GAS POWER, which focuses on the specific

information needs of the gas-fired power

generation industry. GAS POWER joins COAL

POWER, MANAGING POWER, and POWERnews

in our family of electronic newsletters. The

first issue of GAS POWER Direct was dis-

tributed Feb. 28 and can viewed at www

.powermag.com. A free subscription to the

bimonthly newsletter is available by click-

ing on the “Sign up now” link below the

editorial links or by using the Subscribe

button at the top of our home page.

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Less-Familiar Generation III+ Reactors

Make Inroads

Following key regulatory approvals in the UK and U.S. of Westing-house’s AP1000 and AREVA’s EPR Generation III+ reactor designs, France’s nuclear safety authority in February determined that the little-known ATMEA 1 reactor design met international safety cri-teria for Generation III+ reactors. The reactor is a 1,100-MW pres-surized water reactor (PWR) developed and marketed by ATMEA, a 2007-created joint venture between France’s AREVA and Japan’s Mitsubishi Heavy Industries (MHI).

France’s Autorité De Sûreté Nucléaire (ASN) noted that the 18-month review of the safety options of what ATMEA calls a “mid-size reactor” was requested by AREVA and MHI. The review was therefore not performed as part of a licensing procedure for the reactor design but “in the same conditions as those appli-cable to the creation of basic nuclear installations in France,” it said, concluding the project would “on the whole satisfy the French requirements.”

The “positive opinion” followed 2011 approvals from France’s advisory committees for nuclear reactors (GPR) and for nuclear pressure equipment (GPESPN) concerning the safety options for this new reactor. The reviews took into account internal and ex-ternal hazards as well as lessons learned from the Fukushima accident.

ATMEA describes the ATMEA1 as a three-loop PWR that uses the same steam generators as AREVA’s 1,630-MWe EPR reactor design. The ATMEA1 with a 60-year design life also has extended fuel cycles, 37% net thermal efficiency, 157 fuel assemblies, and a capacity to use mixed-oxide fuel only (Figure 1). With emphasis on its smaller size, the reactor design has so far been marketed to developing countries with nuclear power ambitions.

Interest is growing, however. French company GDF Suez, owner of seven Belgian nuclear plants, recently expressed interest in de-veloping the first ATMEA1 reactor in France’s Rhone River Valley. AREVA and MHI have also been contending with Russian and Ca-nadian companies to sell a reactor to Jordan for a $4.5 billion contract. Meanwhile, majority French government–owned AREVA in February signed a key agreement with state-owned China Guang-

dong Nuclear Power Group to develop another midsize PWR, pos-sibly based on that company’s Chinese-designed CPR1000. Officials told reporters in February that AREVA will persuade China to base the 1,000-MW nuclear reactor on the ATMEA1 model. “It would be a shame to have two 1,000-megawatt reactors on the mar-ket,” AREVA’s senior vice-president for reactors and services, Claude Jaouen, said.

Interest in midsize Generation III+ reactor designs marks a new era in the evolution of nuclear reactor technology, which has been pronounced over the past five decades. Generation IV designs are still in the conceptual stage and may not be opera-tional before 2020, while the first generation of reactors—those developed in the 1950s and 1960s—are almost obsolete.

Only two first-generation plants (550-MW Magnox reactors, which are pressurized, carbon dioxide–cooled, graphite-moderated reactors using unenriched uranium as fuel and magnox alloy as fuel cladding) are currently operating at the Wylfa nuclear power station, on Anglesey, in the UK. But these are to be shut down later this year, close on the heels of shuttering the UK’s two other Magnox reactors at the Oldbury nuclear power station near Bristol. That 45-year-old station—the world’s oldest nuclear plant—was permanently shut down at the end of February (Figure 2).

Generation II reactors—a class built up to the end of the 1990s that characteristically includes PWRs, Canadian-invented CANDUs, boiling water reactors (BWRs), British advanced gas reactors, and Russian-built VVERs—are widely used all around the world.

Meanwhile, the first set of Generation III and III+ reactors have been put into operation in Japan and several others are under construction in China, Europe, and the U.S. Prominent de-signs include Westinghouse’s AP1000, AREVA’s EPR, GE’s advanced boiling water reactor and ESBWR, and MHI’s APWR.

The focus has been narrowed on these five designs presum-ably because of highly publicized design certification processes in various countries. But several lesser-known Generation III

1. A small fish in a big pond. French regulators in February

deemed safe the ATMEA1, a Generation III+ reactor design developed

and marketed by an AREVA–Mitsubishi Heavy Industries joint venture.

Courtesy: AREVA

2. A generation gap. The last of the 1967-opened Oldbury twin re-

actors near Bristol in the UK was shut down in late February, after generat-

ing 137.5 TWh of power. The plant was one of 11 based on the pioneering

post–World War II Magnox design, the first reactor design in the world to

generate power on a commercial scale. Oldbury was also the first reactor

in the world to have a concrete pressure vessel. Ten Magnox plants are

now in various stages of decommissioning; only Wylfa on Anglesey still

operates. Oldbury and Wylfa are potential sites for new reactors. The Ho-

rizon consortium intends to build at least 6 GW of new nuclear capacity

there. Courtesy: UK Nuclear Decommissioning Authority

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designs exist, and technologies such as Gidropress’ AES-92 and AREVA’S Kerena have even been certified in accordance with safety criteria set out by the European Utilities Requirements. The AES-92 from Gidropress—a Rosatom enterprise—is already under construction in China and India, and it will be the reactor of choice for Unit 1 of Bulgaria’s Belene Nuclear Power Plant. The reactor with a 60-year-lifetime is described as a late-model VVER-1000 pressurized water reactor with four first-stage coolant circulation loops per reactor. It is rated at 3,000 MWt.

AREVA’s 1,250-MWe (3,370 MWt) Kerena reactor is a BWR whose design is based on the Siemens-built Gundremmingen plant. AREVA, which says the reactor with a 60-year-design life is ready for com-mercial deployment, sought U.S. certification of the reactor in 1999 but then postponed its decision. Kerena joins a list of reactor designs whose preapplication reviews with the U.S. Nuclear Regulatory Com-mission (NRC) seem to be at a halt. (The NRC has said that it is so busy that it won’t work on applications for technologies that lack a firm U.S. customer.) Other designs include Atomic Energy of Canada Ltd.’s ACR-700, a 700-MWe design that is supposedly 40% cheaper than the CANDU-6; Westinghouse’s IRIS reactor; the South African–developed Pebble Bed Modular Reactor; Toshiba’s 4S; and General Atomics’ GT-MHR.

Then there are obscure Asian-certified Generation III designs. Perhaps the most significant is South Korea’s APR-1400 advanced PWR, whose trademark is owned by Korea Hydro & Nuclear Power Co. That reactor design, certified by the Korean Institute of Nu-clear Safety in 2003, is already under construction at Shin-Kori 3 and 4, and could become operational by 2013. The reactor design has also been chosen as the basis of the United Arab Emirates nuclear program. The design’s developers are reportedly discuss-ing applying for U.S. certification later this year, and plans could soon be under way to develop a European version of the reactor.

An “Exploding Lake” Becomes a Power SourceRwanda’s Lake Kivu has a nickname: “Killer Lake.” The shimmer-ing 1,040–square mile body of freshwater on the western branch of the Great East African Rift that straddles the Democratic Re-public of Congo and Rwanda (Figure 3) has had a bloody history. Not only was it the site of atrocity during the 1994 Rwandan genocide, but scientists say that it is also one of three known “exploding lakes.”

Along with Lakes Nyos and Monoun in Cameroon, Lake Kivu’s lake bed lies over the expanding rift, which contains massive amounts of gases beneath its surface, including 61.4 cubic miles of carbon dioxide from volcanic rock below, and an estimated 15.5 cubic miles of dissolved methane, produced by bacteria on the lake bed.

If a volcanic eruption were to occur, as scientists claim could happen within the next 100 to 200 years, the results could be catastrophic, dwarfing similar events at the two other exploding lakes, because an estimated 2 million people live in the lake ba-sin. In 1986, for example, when Lake Nyos exploded, it released a 1.6 million metric ton cloud of carbon dioxide that asphyxi-ated an estimated 1,746 people, 3,000 cattle, and countless wild animals, birds, and insects over a 12-mile radius of the 1-square-mile lake. Just two years earlier, in 1984, a loud boom heard from Lake Monoun was caused by a limnic eruption—a rare disaster also known as lake overturn, in which a gas suddenly erupts from deep in the lake—that suffocated 37 people.

Acutely aware of the lethal risks posed by the lake, Rwanda’s gov-ernment has sought to mitigate the environmental hazards by reap-ing the estimated 13 cubic miles of methane thought to be dissolved

at a depth of 984 feet (the lake is 1,594 feet deep), instead of vent-ing gases, as was done at Lake Nyos in 2001. In 2009, the govern-ment signed a $325 million deal with U.S.-based Contour Global for a two-phase plan that will comprise integrated methane gas extraction and production facilities and an associated power plant with capaci-ties reaching 100 MW.

The first $142 million phase of the project, dubbed “KivuWatt,” entails a 750-ton barge that will house a gas extraction facility and a 25-MW power plant comprising three gas engine generator sets. It is expected to be completed in the fall this year. Phase 2 will add another 75 MW of capacity, via another nine gensets and three new

3. Killer lake. The 1,040–square mile Lake Kivu in Rwanda on the

expanding Eastern African Rift Valley, adjacent to active Nyiragongo

Volcano, contains massive amounts of dissolved carbon dioxide and

methane that could prove catastrophic for nearly 2 million people who

live in the lake basin if the lake “overturns” and gas suddenly erupts

from deep in the lake. In 1986, a carbon dioxide cloud emanating from

1-square-mile Lake Nyos asphyxiated 1,700 people. Source: NASA

4. Harnessing lake methane. Wärtsilä’s 20-cylinder 34SG gas-

powered engine will power the first 25-MW phase and future 75-MW

phase at a plant under construction by U.S. energy firm Contour Global

that will burn methane sourced from saturated waters at Rwanda’s

Lake Kivu. The $142 million first phase, which will be completed in

October this year, has garnered the backing of international banks be-

cause it also seeks to avert the threat of an eruption of carbon dioxide

and methane at the lake. Courtesy: Wärtsilä

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THE BIG PICTURE: Nuclear AftershocksIn the year following the Fukushima accident in Japan, the nuclear sector has seen several setbacks (text in orange) as well as major

milestones (white). Background image from video of the Daiichi plant in the early morning hours of March 12. Courtesy: TEPCO

—Sonal Patel is POWER’s senior writer.

Feb. 9: NRC issues � rst nuclear combined construction and operation license for new AP1000 reactors to the Vogtle expansion in Georgia.

Feb. 22: Kuwait scraps plans for four new Japanese-built reactors.

Feb. 23: South Korea’s two newest reactors, Shin Kori 2 and Shin Wolsong, are connected to the grid.

March 11, 2011: A magnitude 9.0 temblor and 130-foot-high tsunami waves kill 25,000 people and inundate Tokyo Electric Power’s (TEPCO’s) Fukushima Daiichi plant. Cores of Daiichi 1, 2, and 3 largely melt within the � rst three days of the crisis.

March 18: Israel drops plans for new nuclear plant.

March 28: The Chinese government reduces its nuclear capacity targets by about 10 GW from the 90 GW previously expected by 2020.

April 13: Taiwan halts plans for new reactors.

April 19: NRG Energy pulls � nancial backing for the South Texas Project expansion of two new advanced boiling water reactors.

May 12: Pakistan’s third nuclear plant, Chashma Unit 2, begins commercial operation.

May 25: Switzerland abandons plans to build new reactors, while European Union regulators agree on a framework for stress-testing theirs.

May 30: German Chancellor Angela Merkel endorses blueprint to shut down all 17 German reactors by 2022.

June 11: Italy overwhelmingly votes to abandon nuclear power.

Aug. 3: UK announces closure of its Sella� eld Mixed Oxide Plant.

Aug. 7: China’s Ling Ao Phase II-2 unit officially begins commercial operation.

Aug. 18: Tennessee Valley Authority Board authorizes utility to complete Bellefonte nuclear plant in Alabama.

Aug. 24: 5.8-magnitude Virginia quake rattles eastern U.S., prompting 11 nuclear stations to report unusual events to the Nuclear Regulatory Commission (NRC).

Sept. 22: Siemens announces it will quit the nuclear business.

Sept. 29: Construction completed at Atucha II, Argentina’s third nuclear plant, 30 years after work began.

Nov. 3: Taiwan rejects plans to operate its two existing nuclear plants beyond their planned 40-year lives in effort to make the island “nuclear free.”

Nov. 3: Mexico abandons plans to build as many as 10 new reactors and focuses on new natural gas plants after gas discovery boosts.

Nov. 18: Post-quake restart at North Anna nuclear plant (Va.).

Dec. 5: Indonesia approves construction of its � rst nuclear plant.

Dec. 6: TEPCO technical analysis concludes fuel in Daiichi 1 mostly melted out of reactor pressure vessel (RPV) and into primary containment vessel. Fuel melted in Units 2 and 3 but remained in RPVs.

Dec. 12: Russia begins commercial operation of new Kalinin Nuclear Plant Unit 4 in the Tver region.

Dec. 12: Canada’s Bruce Power abandons plans to build a new nuclear plant in Alberta.

Dec. 14: UK regulators issue interim design approvals for EPR and AP1000, Gen III+ reactors.

Dec. 17: Japan’s government and TEPCO declare Daiichi 1, 2, 3 are in cold shutdown.

Dec. 23: NRC approves Westinghouse’s AP1000 reactor design.

Jan. 6: Spain’s new conservative government asks nuclear safety council to consider operation of 42-year-old Garoña plant until 2019. Spain also chooses small town Villar de Cañas as site of future waste storage facility.

Jan. 18: UK nuclear safety regulators grant interim acceptance to Areva EPR and Westinghouse AP1000.

Jan. 26: U.S. Energy Secretary Steven Chu’s Blue Ribbon Commission releases its � nal report on how to manage and dispose of spent fuel waste.


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barges (one for every 25 MW of capacity). Finnish company Wärtsilä will supply the 20-cylinder 34SG gas-powered engines; delivery of the first 25-MW phase is expected this spring (Figure 4).

Wärtsilä, which will also build the plant on a turnkey basis, said it conceived the idea for the plant and proposed it to Con-tour Global after learning about a much smaller Lake Kivu power project run by beer-maker Heineken. That company pipes water and methane up from the lake, separates the gas, and burns it in a combined heat and power plant dedicated to one of its small breweries. KivuWatt is expected to be the first large-scale at-tempt to harness power from the lake’s methane.

And there could be much more to come. According to Wärt-silä’s regional director for Africa, Tony van Velzen, the methane trapped at Lake Kivu is growing at a rate that could fuel about 80 MW per year. “This is why the project has been sized at 100 MW. Actually there is enough gas to run the plant indefinitely,” he said. “A future idea is to raise power generating capacity to 300 MW, which will sustainably reduce the pressure of the lake. If it works it will be incredible.”

The project also includes a floating pipeline to transport the fuel gas ashore from each barge and an onshore gas-receiving facility. Power produced by the project will be sold under a 20-year purchase agreement to Rwanda’s national utility, the Energy, Water, and Sani-tation Authority (EWSA), which says the electricity is badly needed to drive Rwanda’s burgeoning economy. Only 6% of the population had access to power in 2008, by EWSA’s estimates. However, the electricity could also be exported to neighboring power-stricken countries like Uganda in the future, Contour Global says.

New South Korean and Russian Reactors Go OnlineThree nuclear reactors under construction in the Eastern Hemi-sphere reached major milestones over the past few months. South Korea’s Korea Hydro and Nuclear Power Co. connected its 960-MW Shin-Wolsong 1 reactor near Nae-ri to the grid on Jan. 27 and, a day later, its sister plant, the 960-MW Shin Kori 2 (Figure 5) in the southwest city of Gori. Both units are expected to become commercially operational this summer. And last December, Rus-sia began commercial operation of its 950-MW Kalinin 4 plant, a V-320 model VVER 1000.

The Korea Electric Power Co. (KEPCO) subsidiary’s plants are OPR-1000 pressurized water reactors (PWRs), which evolved from the domestically designed Korean Standard Nuclear Power Plant. South Korea has 23 operating reactors, some of the first PWRs of Westinghouse, Framatome (now AREVA), and CANDU designs. Seven OPR-1000 reactors went online between 1998 and 2011. Shin Kori 2, Shin Wolsong 1, and Shin Wolsong 2, also OPR-1000s, are expected to start commercial operation between mid-year 2012 and September 2013.

Three new reactors are under construction, and six are being planned. South Korea hopes to increase its nuclear capacity to 27.3 GW and supply 43.4% of its capacity through nuclear power, up from the current 34.6%. By 2030, the government has fore-cast nuclear power could supply 59% of its power. All planned reactors are third-generation APR-1400s. The first two of that reactor designs are being built at Shin-Kori Units 3 and 4 and should be completed between 2013 and 2014.

The new Russian plant has a longer history. Work on Russia’s Kalinin 4 began in 1986 but stalled in 1991 when the plant was barely 20% complete. The plant is expected to provide power for the Tver region. Russia sources 17% of its power from 33 nuclear plants, but it has 10 projects under construction on Russian soil and at least 21 units under construction in other countries.

In related news, Russia this January completed the first phase of a centralized “dry” interim storage facility at Zheleznogorsk, near Krasnoyarsk, Siberia, where it plans to store 8,129 metric tons of used fuel from its RBMK-1000 Leningrad, Kursk, and Smo-lensk plants and VVER-1000 Balakovo, Kalinin, Novovoronezh, and Rostov plants. The first phase of the facility is expected to be full to capacity within eight to 10 years. The complete interim storage facility will ultimately store 38,000 metric tons of fuel for at least 50 years. Media reports say that Russia, a country that reprocesses about 16% of its used fuel, has plans to reprocess all its used fuel by 2020.

Russia’s nuclear plans also reportedly include privatizing Rosa-tom—the massive state-owned entity that oversees the country’s nuclear power, engineering, and research enterprises—as part of a modernization effort. In particular, the firm’s civil nuclear assets—its nuclear fuel, reactor technology, supply chain, power plant operation, services, and waste management—could become public liability companies with shares that will be sold off. The proposal by Vladimir Putin, who was recently reelected as Rus-sia’s president (after serving the maximum two terms as president from 2000 to 2008), seeks to curb corruption and improve the legal and investment environment.

Two New Offshore Farms Turning Despite Stagnant Global Wind Market The UK opened two massive offshore wind farms this February on the Irish Sea off the UK’s Cumbrian coast. DONG Energy, SSE, OPW, and a consortium of Dutch pension fund service provider PGGM and Ampere Equity Fund began commercially operating the 367-MW Walney wind farm, estimated to cost $1.58 billion, and Danish wind firm Vattenfall inaugurated the Ormonde Offshore Wind Farm.

Walney uses 102 Siemens turbines that were installed in a record five months 15 kilometers (km) off Walney Island. The development included foundations, turbines, export and array cables, offshore substations, and onshore connection to grid.

Vattenfall’s 8.6 square-km wind farm, located about 10 km from the Barrow-in-Furness shore in the Irish Sea, comprises 30 5-MW REpower wind turbines and is expected to generate 500 GWh annually (Figure 6). The two-year-long project is unusual

5. New reactors. In January, Korea Electric Power Co. (KEPCO)

subsidiary Korea Hydro and Nuclear Power Co. grid connected the

960-MW Shin Kori 2 plant shown here and sister plant Shin Wolsong

1 in the southwest city of Gori. Shin-Kori Units 3 and 4, which are also

under construction at the site, are the first of at least nine Generation

III+ South Korean–designed APR-1400 reactors that will be built as

South Korea expands its nuclear capacity. Courtesy: KEPCO

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because it uses fairly new technology. Only six REpower 5-M turbines have been so far installed in the German test field alpha ventus, partly owned by Vattenfall, and two others in the Beatrice demonstra-tion test field in the UK. The turbines, with a rotor diameter of 126 meters and three rotor blades—cover the area of two soccer fields. Each nacelle is the size of two houses.

The wind farms are part of the UK’s ef-forts to boost its power capacity to 18 GW

by 2020 to meet increasing demand for energy and to meet European Union (EU) renewables targets and cut emissions 34% from 1990 levels. The UK already has more than 1,500 MW of nameplate offshore wind capacity, and it plans to spend bil-lions of dollars more to increase offshore generation more than 10-fold by 2020, Bloomberg reported in February.

According to European renewables think tank EurObserv’ER, however, key wind energy markets like the UK “may be

showing fault lines.” Asia was the world’s biggest wind market in 2011, taking a 52% share, ahead of Europe (24.5%) and North America (19.7%), it says in a newly released study. Though Europe had the largest wind power capacity in the world with 40.6% of the world’s total in 2011, it “attracts less than a quarter of the newly installed capacity and could be overtaken by Asia in 2012.”

The EU market is “wavering between the flagging onshore market and the lo-gistics, technology and industrial prepara-tions for the huge, offshore wind energy market with its rich pickings,” the study says. The EU market could further decline on the back of delayed loans stemming from the recession. Moreover, many gov-ernments have reduced domestic mar-ket growth both with slowed permitting and increased administrative procedures (Spain’s preallocation plan, for example).

Even China, the world’s biggest wind power market, saw installations level off for the first time in 2011, EurObserv’ER says. This was due to a slew of new regula-tions imposed by Chinese authorities in a bid to improve control over growth of the country’s domestic renewable energy mar-ket. Some regulations, for example, divest China’s provinces of their independence to decide on the siting of wind farms of less than 50 MW. Projects now require gov-


6. The wind’s changing course. Vattenfall in late February completed com-

missioning work on its 30th turbine of the

Ormonde Offshore Wind Farm off the UK’s

Cumbria coast. The facility is expected to gen-

erate 500 GWh annually. Courtesy: Vattenfall

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ernment approval in consultation with the grid operator. New technical standards have also been imposed to facilitate grid integration of wind turbines.

The U.S. wind sector’s long-term development, meanwhile, hangs in the balance for lack of agreement on continuation of the current incentive system, which consists of a production tax credit of 2.2¢ per kWh for wind generation, the study notes.

Globally during 2011, offshore wind power fared the worst, EurObserv’ER says. Only 788.1 MW were installed, compared to 1,139 MW in 2010. “The decline recorded in 2011 however, will not drive the off-shore sector’s future development off course,” it forecasts, saying 18 projects under construction should be completed over the next three years and raise the EU’s offshore capacity to more than 9 GW. “The sector’s growth is set to ac-celerate from then on,” it concludes, citing claims that 40 GW of offshore capacity should be installed by 2020, which will cover 4% of the EU’s electricity demand.

India’s Chronic Coal Shortages Threaten Coal Power Ambitions India has been besieged by a coal shortage of unprecedented sever-ity that has forced privately owned and money-strapped state-owned coal-fired power plants alike to rely on expensive imports from Indo-nesia and South Africa to replenish woefully inadequate stocks.

The situation, which intensified last October, was said to stem from heavy rainfall in August and September in key mining areas that affected six of seven subsidiaries belonging to Coal India, the central government–controlled mining company, and caused a shortfall of 17 million metric tons of coal. The scarcity—already severe for the nation, which sources 55% of its power from coal generation—was further exacerbated by strikes by Coal India em-ployees, a derailment of a big consignment of coal, and floods in eastern states.

The fuel shortages have frozen plans for $36 billion of new power plants and stunted India’s $1.7 trillion economy. In late February, India’s Power Ministry told the Planning Commission that the nation’s coal availability during the 12th Plan period (2012–2017) was suggestive of a “very bleak” scenario and that the shortages raised questions about achieving the targeted 9% economic growth for the period.

Coal India production over the period was projected at 615 million metric tons—way below the 12th plan requirement of 842 million metric tons, the ministry said. That much coal would only support about 19,000 MW of Coal India–linked new capacity during the five-year period, half as much as the 38,000 MW required to sustain economic growth. For those reasons, the ministry urged the commission to pare down its total generation capacity targets for the period from 76,000 MW to 57,000 MW. India’s total capacity addition ambitions of 76,000 MW during the 12th Plan consisted of 62,695-MW coal capacity, 2,800 MW of nuclear power, 9,200 MW of hydro-power, and 1,086 of gas-fired power.

And it’s just the beginning of a downward spiral, some experts suggest, saying that the deficit between the demand and supply of domestic coal in India may rise as high as 150 million metric tons by 2014 if the country fails to increase local supplies by at least 6% this year.

State-run power generation companies from Maharashtra, Karnataka, Andhra Pradesh, and Tamil Nadu—entities that rely on Coal India for adequate supply—have already begun depending on expensive imports, while private generators such as Tata Power (Figure 7) and Adani Power have sub-stantially increased coal imports, reported India’s Financial Chronicle in late February.

But some analysts assert that India’s plan was doomed from the start. Even with the shortages from last summer, Coal In-dia reported only a 2.7% drop in production to 291.2 million metric tons in the nine months leading up to Dec. 31, ac-cording to a Feb. 13 statement. Meanwhile, a recent report by Standard Chartered Bank suggests that even if India received 60% of the coal it needs from its own mines, it would still need 106 million metric tons of coal capacity within the next five years—double Australia’s planned expansion and two-thirds of Indonesia’s. That is one reason Indian companies are scrambling to secure coal resources, buying coal projects in Indonesia, Australia, and Mozambique, it said. Moreover, if a 10% growth in generation capacity were assumed, imports would have to grow by a stunning 125% to 164 million metric tons by 2015—a development that could ultimately cause coal prices to surge beyond $200/metric ton.

Meanwhile, India must compete with coal-hungry devel-oping nations like China for fuel. India is already poised to surpass China as the world’s biggest thermal coal importer, according to The Financial Express, which reported that In-dia’s imports could exceed 118 million metric tons this year—substantially more than last year’s 81.1 million metric ton imports of steam coal, and much higher than China’s im-ports of 102 million metric tons this year. One reason for this, experts note, is that China is developing twice as much coal-production capacity this year as in 2011. At the same time, India’s government may force Coal India to begin imports en masse by imposing penalties on power producers should de-liveries fall to less than 80% of the contracted quantity.

POWER DigestCSP Giants Form Alliance. Concentrating solar power com-panies Abengoa, BrightSource Energy, and Torresol Energy in early March formed the Concentrating Solar Power Alli-ance, an organization dedicated to educating U.S. regulators, utilities, and grid operators about the unique benefits of concentrating solar power (CSP) and of thermal energy stor-age. The U.S. has more than 500 MW of operating CSP plants

7. Dealing with the dearth. India has been stricken by a severe

coal shortage that has forced state-run generators and private compa-

nies to import coal—circumstances that could compel the country to

scale down its new coal capacity targets. Despite being built to over-

come chronic power shortages that are stunting economic growth,

newly opened plants like Tata’s 1,050-MW Maithon Right Bank Ther-

mal Power Plant in Jharkhand aren’t receiving enough coal to reach full

capacity. Courtesy: Tata Power


and more than 1,300 MW of CSP plants under construction. The International Energy Agency estimates that CSP projects in development or under construction in more than a dozen countries (including China, India, Morocco, Spain, and the U.S.) total 15 GW.

JSC Institute Hydroproject to Refurbish Russian Hydro Plant. RusHydro subsidiary JSC Institute Hydroproject in March began an all-inclusive project to modernize the Kams-kaya hydropower plant, which is part of the Volga-Kama cas-cade in Russia. About 17 of 23 new vertical hydraulic units have been already upgraded. JSC Institute Hydroproject will develop the all-inclusive modernization project taking into consideration the previous projects for reconstruction of hy-droturbines, hydro and auxiliary equipment, hydro units, and dams. Design works will be finished in 2014.

APS Launches Pilot Battery Project. Arizona Public Service Co. on Feb 23 began testing a new 1.5-MWh ship-ping container–size energy storage system. The goal of the company’s two-year pilot project in Flagstaff, Ariz., will be to determine the benefits of storing electricity and putting it onto the grid during times of peak demand. In 2012, the system developed by lithium-ion battery maker Electrovaya Inc. will reside in an electrical distribution substation. At a later date, the system will be trucked a few miles up the road to support a 500-kW solar power plant, the Doney Park Renewable Energy Site.

Fortis to Acquire CH Energy Group in $1.5B Deal. Canada’s largest investor-owned distribution utility, Fortis, announced in mid-February that it entered into an agree-

ment to acquire CH Energy Group for about $1.15 billion. CH Energy Group is an energy delivery company headquartered in Poughkeepsie, N.Y. Its electric assets (which constitute approximately 77% of its total assets) include approximately 9,600 miles of distribution lines and more than 600 miles of transmission lines.

AEP Starts Up Ohio Gas Plant. American Electric Power (AEP) on Feb. 1 began commercial operation of the Dresden natural gas–fired power plant, a nominal 580-MW combined cycle generating unit. located near Dresden, Ohio. Including startup of the Dresden plant, AEP has added more than 4,800 MW of natural gas–fired capacity to its generating fleet in the past decade. Natural gas accounts for 24% of AEP’s total generating capacity. AEP purchased the partially constructed Dresden plant in 2007 for approximately $85 million from Dresden Energy LLC, a subsidiary of Dominion. AEP acceler-ated construction of Dresden in January 2011. Total costs for the plant were approximately $366 million.

Key EPC Contracts Signed for Texas Clean Coal Proj-ect. Summit Power Group’s Texas Clean Energy Project on Feb. 14 signed engineering, procurement, and construction (EPC) contracts and a 15-year operations and maintenance contract for its 400-MW power/poly-gen gasification proj-ect with 90% carbon capture near Odessa, Texas. The deal takes the project another step closer to financial closing and groundbreaking. The two, firm-price, turnkey EPC contracts that guarantee price, schedule, and performance for the inte-grated coal gasification combined cycle project were finalized in December by the project’s three EPC contractors: Siemens

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Energy Inc.; Selas Fluid Processing Corp., a subsidiary of The Linde Group; and SK Engineering & Construction, a major Korean contractor. The total value of the EPC contracts is approximately $2 billion.

Alstom Wins Contract for Malaysian Supercritical Coal Plant. Alstom on Feb. 27 secured a €830 million ($1.1 bil-lion) contract as part of a consortium that includes Malaysian companies Mudajaya and Shin Eversendai that will build a coal-fired power plant in Tanjung Bin, Malaysia. Alstom will construct and commission the 1,000-MW supercritical steam turbine and generator and install a supercritical boiler, power plant auxiliaries such as mills and air preheaters, as well as proprietary environmental control systems. The power plant is scheduled to be commissioned in 2016. The Tanjung Bin power plant is the French energy company’s second contract for a supercritical coal-fired unit in Malaysia, following the order to build the Manjung power plant in March 2011, which is scheduled to come online in 2015.

DONG Energy to Sell 50% Stake in German Offshore Farm. Danish power company DONG Energy on Feb. 24 agreed to sell its 50% stake in the German offshore wind project, Borkum Riffgrund 1, in an agreement worth DKK4.7 billion ($841 million) to Kirkbi (for a 32% stake) and the Oticon Foundation (18% stake). Upon completion, the proj-ect will consist of 77 3.6-MW turbines supplied by Siemens Wind Power.

Dominion Mulls New $1B Gas Plant. Dominion Virginia Power on Feb. 29 said it would build a $1 billion combined cycle, natural gas–fired power station in Brunswick County,

Va. The company will seek approval from the Virginia State Corporation Commission later this year to build the 1,300-MW plant on a 205-acre site. When complete in 2016, the plant will replace power generated by coal units at two eastern Virginia stations that are slated for retirement.

Siemens to Supply Components for 4-GW Saudi Gas Plant. Siemens Energy on Feb. 21 said it received an order from the Hajr Project Co. worth more than $1 billion to sup-ply components for the 4-GW IPP Qurayyah combined cycle power plant in Saudi Arabia. The order was placed by Sam-sung C&T, which will act as engineering, procurement, and construction contractor for the project. Siemens will provide 12 SGT6-5000F gas turbines, 18 generators of the SGEN6-1000A series, and six SST6-4000 steam turbines together with the associated electrical systems. Commissioning of the six blocks is scheduled for 2014.

Toshiba, JSW Joint Venture to Supply Equipment for Indian Supercritical Plant. On Feb. 21, Toshiba JSW Tur-bine and Generator—a 75:25 joint venture between Japan-based Toshiba Corp. and India-based conglomerate JSW Group—received a contract from Indian state-owned energy service provider NTPC to supply equipment for the Kudgi Su-per thermal power project, Stage-I, in Karnataka, India. The value of the contract is estimated at Rs23bn ($468.6 mil-lion). Under the terms of the agreement, the firm will sup-ply three 800-MW supercritical steam turbine and generator island packages for the project. Delivery of the equipment is expected to start in 2013. ■

—Sonal Patel is POWER’s senior writer.

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Safe Work Practices in Confined Spaces at Power Plants

Confined space work is often considered to be one of the most dangerous types of work performed in power generation settings. Confined spaces may contain hazardous atmospheres, they can trap entrants, and they generally can increase the hazards associated with otherwise common tasks. When the risks are not recognized, workers all too often regard incidents as surprises, but the hazards of working in confined space can be predicted, monitored, and mitigated. These “accidents” are caused by unsafe conditions, unsafe acts, or both; all accidents are preventable.

Several common dangers found in confined spaces include the hazards of

working with electrical equipment, en-gulfment, and releases from pipes con-taining fluids or gases.

Electrical. Electrical energy poses sev-eral threats to the health and safety of entrants going into confined spaces. For spaces with a potential for flammable at-mospheres, both the equipment already in the space and the equipment used in the work performed may become ignition sources.

Arc flash, thermal burns, and other electrical hazards are particularly dan-gerous in a confined space because it may be difficult for the worker to avoid accidental contact or proximity. In most settings, policy dictates that such equipment simply be de-energized and lockout/tagout procedures put into effect. (For more information on the hazards of arc flash, see “Arc Flash Protection Should Be Job No. 1” in the February 2007 issue, or in POWER’s on-line archives at www.powermag.com.) However, this is not always possible in a power generation environment. In-stead, complex operational controls and tagging systems must be used to ensure proper safety (Figures 1 and 2).

Engulfment. Many materials have the potential to engulf an entrant. When small solids are in motion, they begin to act like a liquid. Coal, sand, dirt, and other ma-terials flow, following the shape of their container. The presence of materials with a combination of fluid and semi-rigid properties makes storage areas potentially hazardous. This is an especially important concern for coal-fired plants, where em-ployees must walk across loose coal. A parallel hazard is bridging. When an auger operates, material flows out of the bottom of the storage area. Material at the top may not flow down evenly, forming a tem-porary bridge out of the material. Walking over the surface of bridged material can lead to immediate engulfment.

Pipes Containing Fluids or Gases. Pipes that carry liquids or gases also pres-ent several potential hazards. The condi-tion of a pipe may be hazardous, as a leak could quickly create a dangerous situa-tion. Valves, piping, and infrastructure in confined spaces may be hard to access and are inspected infrequently, so it is im-portant to consider that the risk posed by leaks may be unknown.

Materials being transported in lines and piping, such as steam or coolant,

may be at extreme temperatures. Even without a release, such pipes are poten-tially hazardous if entrants must work in close proximity, as this scenario increases the likelihood of unintentional contact. Gases being vented or brought to a pro-cess can quickly create a hazardous at-mosphere. Even without obvious damage to lines, leakage usually occurs in most piping systems.

Otherwise nonhazardous fluids, such as water, may not be immediately threatening, but the introduction of any fluid to a confined space creates poten-tial hazards. Fluid may conceal trip/fall hazards, come into contact with ener-gized equipment, or may fill the space. Entrance into lines themselves is always potentially dangerous, and dead or de-caying matter in those lines can cause a buildup of hazardous gasses in short amounts of time. Lines used to transport saltwater are particularly vulnerable to such organic matter, even if filters and other measures are taken to clean the incoming supply. Valves normally under pressure from liquids in a line may not seal as well as expected when the lines are drained, so air quality testing is in-credibly important in these areas.

Spaces such as large tanks present the possibility of a stratified gaseous atmosphere. Gases have different den-sities and can rise or sink relative to each other. Gases like carbon dioxide tend to pool, while gases like meth-ane and acetylene rise. Depending on the temperature and source of the gas, or whether the atmosphere inside the space is disturbed, these hazards may be found anywhere in a confined space. When left for some time, the atmo-sphere in confined spaces will tend to separate out. The air must be tested at small intervals in a potentially strati-fied atmosphere. Any suspected areas of reduced ventilation, such as behind a baffle or an internal barrier, should be tested as well. Always use a remote probe or sampling tube, and allow work-ers to advance into the space only as far as the atmosphere has been tested.

Successfully Evaluate Potential RisksThe situations mentioned above are just a few of the potentially hazardous con-ditions that warrant a stringent evalu-ation procedure when an employee will

1. Restricted access. When dealing with

confined spaces in power generation settings,

operational controls and tagging systems

must be used to protect the safety of work-

ers. Courtesy: New Standard Institute Inc.

2. On alert. Confined space work at power

plants requires the identification and removal

of unsafe conditions, if possible; controlling ac-

cess where conditions are inherently danger-

ous; and training entrants to prevent unsafe

acts. Courtesy: New Standard Institute Inc.


be working in a confined space. This evaluation should also include measur-ing the size of the space as well as ac-cess and egress availability. Oxygen, carbon monoxide, hydrogen sulfide concentrations, and the percentage of the lower explosive limit (LEL) in the confined space must be measured and analyzed. The atmosphere within the confined space should be measured in terms of its LEL; typical permissible ex-posure level (PEL) and time-weighted average exposure (TWA) for different gases are illustrated in Figure 3.

Even the slightest potential for a change in air quality or hazardous at-mosphere is cause for concern. A space that has walls that converge inward or floors that slope downward and taper could trap or asphyxiate an entrant. Area inspections must identify all of these potential conditions so that ef-forts can be made to mitigate or control any and all hazards before work begins. It should be considered likely that the space will require a permit entry pro-gram, though efforts to control the con-dition will make entry far safer.

As important as what is evaluated is who does the evaluation. Make sure the group is properly trained and qualified to perform evaluations. If a contractor has his or her own designated safety personnel performing evaluations, make sure they are qualified as well as au-

dited. Many power plants are stepping up their safety programs and requir-ing all outside contractors to comply with internal programs and use certi-fied equipment. The fact of the matter is that people may cut corners to save time and money; however, there is no acceptable compromise when it comes to safety. Audits should be frequent and unscheduled, and each work site should have an internal person assigned to that task.

Emergency communications should be well defined and centralized. A phone number or radio frequency needs to be on every document and work order so no one has to look far in the event of an emergency. Attendants must be in continuous communication with work-ers. Special attention will be required if the space or work performed will be cre-ating excessive noise and workers must wear hearing protection.

Layout of the workspace can be criti-cal as well. If workers are not visible from outside the confined space, al-ternate means must be employed. Ra-dios, video monitors, or other methods should be considered. Some systems of communication, such as tugging on a safety line or rapping on the barrier of a space, are prone to error or misinter-pretation and should be considered a backup method that is only suitable for use in an emergency.

Customizing Safety Programs for Power PlantsConfined space work requires the identification and removal of unsafe conditions, controlling access where conditions are inherently dangerous, and training entrants to prevent unsafe acts. This can be an especially difficult task for power generation facilities. Be-sides the usual confined spaces found in many industrial settings, power plants have additional challenges, including high-voltage hazards, tunnels, tanks, coolant lines, and dozens of other safety threats. The U.S. Occupational Safety & Health Administration’s 1910.146 stan-dard sets out the requirements upon which safety specialists and operational managers should base safety programs for their individual plants’ operations.

—Contributed by Michael Konopka ([email protected]),

product development manager at the New Standard Institute Inc. This article is

adapted from the New Standard Institute’s confined spaces computer-based training.

Preventing Downtime by Picking the Best Switch TechnologyCommon fuel-handling problems in the power industry often result in produc-tion downtime, costing the owner per-haps up to $200,000 per hour. There are many areas within a coal-fired power plant where mishaps can cause stop-page of material flow. Here we discuss how to select the best switch technol-ogy to reduce the possibility of coal flow stoppages.

Efficient Coal HandlingCoal-handling systems in a power gen-eration station are designed to process coal from large pieces into powdered form. Raw coal is delivered from the yard to the boiler island’s coal feed silos, usually by a dispensing system known as a tripper car. The tripper car is filled by a conveyor from the fuel pile and then moves from one silo to the next dispensing coal. It is very impor-tant for reliable plant operations that a continuous and accurate coal level is measured within these silos. When fuel silos are kept fully stocked, the boiler’s appetite for coal can be satisfied and the plant can operate reliably at rated capacity.

A good operating practice is to have some type of point detection devices that will provide operators early notice of silo levels in order to prevent either

Note: LEL = lower explosive limit, PEL = permissible exposure level; TWA = time-weighted average exposure.

3. Understanding the risks. Before a worker enters a confined space at a power gen-

eration facility, the plant safety officer should measure and analyze gases present to determine

if the space has an explosive atmosphere or is otherwise a danger to human occupants. Cour-

tesy: New Standard Institute Inc.


an overfill of material or indicate that material is no longer flowing out of the silo, signaling a stoppage. If the level of coal in the silos gets low before the blockage can be repaired, then the plant must either reduce load or shut down to clear the blockage.

Another problem when handling dusty and dirty coal is its affinity for absorb-ing moisture. Once coal becomes wet or moist, a coating and buildup of a film of coal on the surface of the chutes will eventually block the flow through the silo transport chutes. When chute block-age occurs, it can create an overflow of coal from the conveyor belts. Not only does the blocked chute stop production, but it also can cause severe injury to plant personnel and result in fines by state regulatory agencies. We have also seen damage caused by plugged chutes and the resulting overflow of coal from conveyors to other process equipment.

Pick the Best TechnologyWith the potential for lost genera-tion and equipment damage caused by blockages in fuel-handling systems, it’s surprising that more plants don’t have the instrumentation to sense impend-ing blockages. Many different types of point level devices on the market today are used for blockage detection and pre-vention on coal transfer chutes, includ-ing a variety of switch, microwave, and acoustic wave technologies.

Switch Technology. Favorites are the few switches that are sufficiently robust to operate in these solids-handling ap-plications that operate 24/7. Whether the technology is capacitance, vibra-

4. Undercover switch. A mill cyclone

feed level switch covered with a coal ash coat-

ing often causes a false trip. Courtesy: Hawk

Measurement Systems

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tory, rotating paddle, or tilt switches, all are exposed to heavy, abrasive raw materials that cause excessive wear and tear to contacting switches. The coating from the wet, moist coal dust can also adhere to the contact probes, causing a false trip. Even though these switches are fairly inexpensive, their reliability for plug chute detection application is rather low, and the cost of downtime is too high to rely on an exposed switch (Figure 4).

In our experience, microwave and acoustic wave point detection provide the most reliable operation in solids ap-

plications, such as plugged chutes. Ei-ther of these technologies can be used for point level detection or flow/no flow in a process chute.

Microwave Technology. Microwave technology has been in existence for many years and as a plugged chute detector for the past 15 years. If the conditions or an area of the process is free of moisture from water sprays, then microwave technology is very reliable, maintenance free, and should provide a lifetime of operation. It is not the right solution if there is a possibility of mois-ture from water sprayers in the process due to the potential of coating the in-strument with a dust film (Figure 5).

This technology makes use of a sender and receiver transducer through-beam design that is mounted outside of the material and transmitted through a transparent, wear-resistant window. Once the material fills the chute, the microwave beam is broken and the prod-uct sends a signal to the control system to quickly provide an indication of the blockage.

Since this technology does not make any intrusion into the chute wall, but rather, through a high-grade ceramic window, the material cannot wear down the sensor face. Even under high tem-peratures in excess of 160F, the sensors can be remotely mounted with a wave-

guide extension to direct the signal to a remote amplifier.

Sensors using microwave technology for reliable dry solids point detection to eliminate the chances of a plugged chute have become the standard in many min-ing facilities around the world. There is a 75% chance that one transfer chute will become blocked over the course of one month in every mining facility, and that means a reliable plugged chute de-tector that will not fail under duress is required.

Acoustic Wave Technology. Acous-tic wave technology relies on a very low frequency (15 kHz), high-powered transducer pair that creates a pressure wave on the sensor face of each trans-ducer. The technology requires a pair of transducers to be located apart but aligned with each other. The transduc-ers both pulse and receive signals from each other, and as soon as the signal is blocked by wet or dry solids material, the attenuated acoustic signal is ampli-fied and sent to the plant-monitoring system (Figure 6).

The low-frequency, high-power signal applied to the sensors also has a self-cleaning feature when the pressure wave is created. This pulsing pressure wave keeps material from adhering to the face and provides for maintenance-free operation in critical applications. By installing the transducer system in the optimal location, plant personnel will get an early detection of chute plugging in order to take corrective action. Pre-vention is the best method for ensuring that flow continues unhindered through the power generation process.

Pick Your Switch

If it’s a reliable point level detection de-vice that you’re looking for in a transfer chute that is going to be immersed in a moist, dusty coal environment and reli-ability is very important, then acoustic wave technology may be your best op-tion. If the process material is dry, then the microwave detection switch may be your best choice.

Regardless of the application, it’s best to thoroughly understand your process conditions before picking a switch tech-nology. Be cautious, explore all the avail-able technologies and their track record in harsh coal-fired plant applications, and then make an educated decision. ■

—Contributed by Jerry Boisvert ([email protected]),

a mining specialist with Hawk Measurement Systems.

5. Microwave switch. A microwave blocked chute switch is best used in applications

where the flowing material is dry. Courtesy: Hawk Measurement Systems

6. Acoustic switch. An acoustic blocked

chute switch can be used in moist or dry ma-

terial flow applications. Courtesy: Hawk Mea-

surement Systems

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Suing for (Pipeline) Safety

As a Valentine’s Day present to federal regulators, San Francisco City Attorney Dennis Herrera took the unusual step of suing the U.S. Pipeline and Hazardous Mate-

rials Safety Administration (PHMSA). The complaint alleges that the PHMSA has “abjectly failed to oversee the [California Public Utilities Commission’s (CPUC’s)] pipeline safety pro-gram or to ensure that federal pipeline safety standards are enforced.” The complaint chastises the PHMSA for “shirking that duty for over a decade, if not longer.”

The complaint links these failures by the PHMSA to the natural gas pipeline disasters recently experienced in the Bay Area. These incidents, most infamously, the horrible tragedy in 2010 in San Bruno that killed eight people and injured more than 50 others and destroyed or damaged more than 100 homes, involve pipelines owned and operated by Pacific Gas and Electric Co. (PG&E). The complaint asserts a direct causal nexus: “[b]y abdicating its duties as a regulator and by improperly delegating those duties to gas pipeline opera-tors like PG&E, PHMSA has placed the lives and property of millions of men, women and children—including hundreds of thousands of men, women, and children in San Francisco—at substantial and unnecessary risk.”

The complaint also criticizes what it asserts to be ineffec-tiveness by the CPUC in regulating PG&E and other operators of natural gas pipelines. Interestingly, it does not name the CPUC as a defendant and actually compliments the CPUC’s “actions to restructure and increase its pipeline safety en-forcement resources” as “ostensibly designed to address the concerns raised” by the City of San Francisco.

The complaint expresses the city attorney’s hope that the CPUC “will conduct a thorough and independent examination of its own failures and adopt meaningful reforms to its own practices,” but it also expresses the concern that the CPUC “will revert to its past practice of failing to fulfill its duty to enforce federal pipeline safety standards in compliance with its certification [at the PHMSA].” However, the complaint contrasts the CPUC’s limited actions thus far with what it deems to be the total lack of any response by the PHMSA to similarly correct any of its own failings.

The lawsuit seeks injunctive relief directing the PHMSA to comply with its “duty to oversee certified state authorities and to ensure that federal pipeline safety standards are enforced as required by the [Pipeline Safety] Act.” It further requests that the court enjoin the PHMSA “from improperly delegating their authority to do so to gas pipeline operators like PG&E.” In other words, the San Francisco city attorney is requesting that a federal judge in San Francisco direct PHMSA to “do its job.”

Ensuring Pipeline Safety Is Complicated To grant the relief the complaint demands, the court must find that the PHMSA has failed to fully discharge its statutory

responsibilities. Any such determination is inextricably inter-twined with a policy debate encompassing the proper level of safety oversight Congress intended the PHMSA to provide and the appropriate safety standards the PHMSA should enforce to fulfill its mandate to promote pipeline safety.

Resolving these issues is well beyond the proper ambit for a judicial body. Society’s desire for perfection with respect to pipeline safety demands that robust debates assessing such critical safety issues as hydrostatic testing, proper pipe engineering and installation, and future infrastructure investment should be conducted. However, allowing these debates to be conducted by legal adversaries, decided by a single judge, and based on legal precedents will not yield optimal results. Rather, the debates should be conducted by legislators and regulatory agencies that are sensitive to the necessary tradeoffs between ensuring reliable natural gas supply at the lowest possible cost while best ensuring public safety.

Litigation Produces Illusory Bene� tsWe assume that the San Francisco city attorney sincerely be-lieves that prevailing in the litigation will increase pipeline safety and thus directly benefit his constituents and at least indirectly benefit the greater populace. However, the sup-posed linkage between a judicial declaration directing the PHMSA to act in accordance with its statutory responsibilities and advancing the objective of increased safety is at best an abstract theory predicated on the dubious assumptions that perfection in promulgating and enforcing regulations can be achieved and that achieving such perfection will guarantee absolute safety.

In any event, while the possible benefits of prevailing in the litigation are amorphous at best, the costs are real and detri-mental. The PHMSA’s defense of the City of San Francisco lawsuit will require it to divert already constrained financial and human resources from enforcing safety regulations to producing docu-ments and being deposed.

Instead, lobbying Congress to provide the PHMSA with suf-ficient funding to accomplish its statutory responsibilities would provide the City of San Francisco with a more positive approach to reach the results that it seeks through this law-suit. After all, an agency can only take steps to ensure safety if it is correspondingly provided a sufficient budget.

Just as the San Bruno tragedy served to jumpstart the na-tional debate on pipeline safety, the City of San Francisco’s lawsuit may at least serve to ensure that the focus of national lawmakers is not diverted from this very important issue with the passage of time. However, actual tangible benefits de-rived directly from the lawsuit seem unlikely. ■

—Vidhya Prabhakaran ([email protected]) is an as-sociate in Davis Wright Tremaine’s Energy Practice Group.

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RENEWABLE ENERGY

Waste-to-Energy Technology Options Increase but Remain Underutilized

Waste-to-energy (WTE) technolo-

gies convert the chemical energy

stored in residues associated with

human activities into heat, steam, and elec-

tricity. Primary fuel sources include munici-

pal solid waste (MSW) and other materials

diverted from disposal facilities as well as

gases rich in methane that are generated

when organic substances decompose in the

absence of oxygen.

Among the many available fuel-processing

and energy conversion technologies, incin-

eration of MSW and derived fuels in boilers

is commercially mature and in common use

around the world, as are combustion-based

systems that fire gases resulting from un-

controlled anaerobic decomposition of waste

buried in landfills and from controlled pro-

cessing of organic materials in purpose-built

digesters. Advanced thermal conversion tech-

nologies such as gasification and pyrolysis—

which transform MSW into versatile fuels

suitable for high-efficiency energy produc-

tion or direct end use—are finding increasing

application but are not yet proven.

Overview of TechnologiesState-of-the-art WTE technologies are

widely recognized by government agencies

as effective resource management solutions

and renewable generation options. When

incorporated within integrated MSW plans

emphasizing reduction, reuse, recycling, and

composting, they provide an environmentally

sound means of recovering energy from the

residual wastes while decreasing the volume

of material that must be landfilled by roughly

90%. At landfills, agricultural facilities, and

wastewater treatment plants, they gener-

ate useful energy while substantially reduc-

ing emissions of methane, a greenhouse gas

(GHG) with high global warming potential.

Globally, WTE capacity has expanded

significantly in recent years, driven largely

by policy considerations. First and foremost,

many nations have forsaken landfilling as

inefficient and environmentally undesirable,

leading to a steady increase in the annual ton-

nage of MSW subjected to energy recovery.

For example, a 1999 European Union di-

rective essentially banned the landfilling of

combustible MSW fractions in order to con-

trol methane emissions, avoid nonproductive

use of land and other resources, and prevent

water and soil contamination.

In Europe, Asia, and elsewhere, such

policies—along with climate change miti-

gation and renewable energy targets—have

motivated the construction of hundreds of

mass-burn incinerators, the early commercial

application of various advanced thermal con-

version technologies, and the proliferation of

smaller-scale landfill gas (LFG) and digester

gas systems. Frequently, these WTE plants

supply heat or are combined heat and power

(CHP) facilities; in fact, 18% of the district

heating load in Denmark is served by MSW

combustion. Across Europe, WTE facilities

produced 56 terawatt-hours (TWh) of renew-

able energy in 2006, including 31 TWh of

heat and 25 TWh of power.

A far different situation exists in the U.S.,

where public concern over pollutant emis-

sions from incinerators has yet to dissipate,

despite the stringent air quality control re-

quirements imposed more than 15 years ago

by the U.S. Environmental Protection Agency

(EPA). No new MSW energy recovery plants

have been constructed since the mid-1990s,

and no commercial-scale MSW gasification

or pyrolysis facilities have been built. The

modest WTE capacity additions—largely of

LFG facilities—have been motivated by fed-

eral air quality regulations and, more recent-

ly, state renewable portfolio standard (RPS)

requirements, rather than by waste manage-

ment policies.

According to data from the U.S. Energy

Information Administration (EIA), load-serv-

ing WTE capacity exceeded 4.1 GW in 2008,

but the amount running on MSW has de-

clined slightly since 2003, falling to 2.2 GW.

However, recent growth in LFG deployment

helped to keep WTE’s share of nonhydro re-

newable capacity near 11%, third-largest be-

hind wind and wood biomass.

Courtesy: HDR Inc.

WTE technologies offer cost-effective, near-term solutions for producing baseload electric power, meeting renewable energy targets, and reducing greenhouse gas emissions in the U.S. and other countries. They also present opportunities for im-proving resource management practices, increasing energy security, enhancing environmental quality, and supporting climate policy goals around the world.

By Stan Rosinski, Electric Power Research Institute Inc.

RENEWABLE ENERGY


As baseload, dispatchable units, WTE

plants continue to play an important role in

U.S. renewable energy generation, even ac-

counting for the fact that capacity has stag-

nated and the EIA includes only the fraction

of output attributable to biogenic sources

such as green power. WTE technologies sup-

plied 15.4 TWh of renewable energy to the

grid in 2008, equivalent to 16% of nonhydro

renewable generation, second only to wind.

Of this total, MSW incinerators and fluid-

ized bed combustion (FBC) units produced

7.2 TWh from biogenic fuels, which make up

roughly 55% of the total U.S. waste stream

by heat input. Counting output attributable to

the combustion of plastics and other nonbio-

genic materials, these plants produced rough-

ly 13 TWh, pushing overall generation from

WTE technologies above 20 TWh.

Independent power producers—among

them waste management firms and munici-

palities—own the majority of load-serving

WTE capacity, while more than half of the

methane-rich fuel produced at U.S. landfills,

agricultural operations, and wastewater treat-

ment plants is applied to generate on-site heat

and power.

Conventional incinerators typically

collect MSW from a broad area, operate

on must-run status, and offer availabili-

ties exceeding 90%. LFG and digester

gas facilities—collectively referred to as

anaerobic-digestion-to-energy (ADTE)

plants—are distributed resources sited,

sized, and run according to fuel availabili-

ty and production rate. Both MSW-derived

fuels and digester gases may be cofired in

fossil plants, but this may have operational

and regulatory implications.

MSW projects have a unique attribute: As

an alternative to landfilling, they typically

charge a tipping fee to municipalities and

other entities (Figure 1). This translates into

a negative fuel cost—and a revenue source—

that may help offset the high capital costs as-

sociated with fuel handling and environmental

control systems and the high operations and

maintenance (O&M) costs attributable to the

variable composition, high moisture and ash

content, high contaminant level, and low en-

ergy density of waste materials. ADTE plants

also require a steady supply of no-cost fuel to

justify the expense of collection, treatment,

and conversion systems.

The economics of WTE plants are ex-

tremely site-specific, depending on tipping

fees, MSW characteristics, environmental

regulations, byproduct management practic-

es, and many other factors. WTE installations

often benefit from the investment and produc-

tion tax credits granted to renewable energy

sources. However, MSW plants sometimes

are granted no, or partial, incentives because

a significant percentage of their energy pro-

duction results from the combustion of plas-

tics and other nonbiogenic materials.

The economic viability of ADTE instal-

lations is strongly influenced by policy driv-

ers. Policies requiring control of air pollutant

and greenhouse gas emissions from landfills,

agricultural operations, and wastewater treat-

ment plants improve economics by reducing

the incremental cost of adding generating

capacity. Depending on site-specific circum-

stances, these projects also may yield revenue

streams in the form of marketable renewable

energy certificates and carbon credits.

Globally, more than 1 billion tons of post-

recycling MSW continues to be disposed of

in landfills each year, including more than

130 million tons in the U.S. While European,

Asian, and other nations move forward with

strong commitments to energy recovery, the

U.S. faces mounting MSW management

challenges, including the declining capac-

ity of existing landfills, growing opposition

to new disposal sites, high per-capita waste

generation rates, low recycling rates, and air

and water pollution concerns.

Electric Power Research Institute (EPRI)

modeling studies of the U.S. electric sector

performed using the National Electric System

Simulator & Integrated Evaluator (NESSIE)

project a fourfold increase in load-serving

MSW capacity to almost 9 GW and a three-

fold expansion in load-serving LFG capacity

to more than 4 GW over the next two decades

under market-based climate policies.

Other countries that have not yet incorpo-

rated energy recovery as a key component in

1. Turning trash into treasure. At

waste treatment facilities, the tipping fees

offset the operation, maintenance, labor, and

capital costs of the facility along with the fi-

nal disposal costs of any unusable residues.

The fee can be charged per load, per ton, or

per item, depending on the source and type

of waste. This photo shows the Lee County

waste-to-energy facility’s tipping floor, which

is the designated receiving area where waste

collection vehicles discharge their loads.

Courtesy: HDR Inc.

2. Benefits of expanding WTE deployment. Global adoption of integrated resource

management strategies could dramatically increase deployment of incinerators and advanced

conversion technologies. This development would reduce landfilling and associated emissions

of methane, while expanded landfill gas capture and energy production could further reduce the

carbon footprint of waste management practices. Source: Lauber & Themelis, 2010

Present Future

WTE

Landfill

Methane

emissions

•800 plants•160 million metric tons

•1 billion metric tons

•45 million tons

•2000 plants•400 million metric tons

•300 million metric tons

•5 million tons

RENEWABLE ENERGY


MSW management provide analogous deploy-

ment potential. China, for example, has indi-

cated that WTE technologies will be employed

to handle more than 30% of its MSW by 2030,

a huge increase over current practice.

Figure 2 illustrates how a global transfor-

mation in MSW management—encompass-

ing increases in recycling, energy recovery,

and other practices to levels already being

achieved in many countries—could lead

to more than double current WTE capacity

while decreasing the amount of MSW being

landfilled by more than two-thirds (despite

the growing waste volume associated with a

growing population). If this transformation

were to include expanded energy recovery

from LFG, then a ninefold reduction in meth-

ane emissions also could be realized. To grow

the role of WTE in meeting energy needs, ad-

vances are required in resource management,

fuel processing, power generation systems,

O&M techniques, and environmental con-

trols. Supportive policies and incentives, and

greater public acceptance, also are needed.

Resource ManagementWaste differs from other energy sources in

that MSW management practices, along

with producer and consumer behavior, de-

termine the volume and characteristics of

fuels suitable for conversion by individual

technologies. Figure 3 displays a solid waste

management hierarchy, with environmental

efficacy declining from top to bottom.

Traditionally, integrated MSW manage-

ment plans have focused on decreasing the

amount of material that must be disposed of

via incineration or landfilling. More recent-

ly, “zero waste” strategies have come to the

fore, emphasizing prevention and materials

recovery but also sharpening the focus on

energy recovery as an approach for securing

additional environmental benefits, including

reductions in land use and emissions. In fact,

the small physical footprint of incinerators

and other WTE plants, relative to landfilling,

is an important driver behind their widespread

deployment for MSW disposal in heavily

populated European and Asian countries.

Furthermore, although modern landfills

are engineered and operated to avoid or

minimize environmental releases of meth-

ane, volatile organic compounds, hazardous

air pollutants, and leachate, control systems

are nonexistent or inadequate at many loca-

tions, while even new landfills may capture

as little as 60% of life-cycle methane emis-

sions. Globally and in the U.S., landfills thus

remain the second-largest anthropogenic

source of methane, which has a global warm-

ing potential many times that of carbon di-

oxide (CO2). WTE plants avoid methane and

leachate production, and flue gases generally

are subject to stringent air quality controls.

On average, modern, electricity-only in-

cinerators also yield roughly an order of mag-

nitude more net energy per ton of MSW than

LFG plants. Energy recovery from MSW thus

is capable of displacing larger amounts of

fossil generation. Additional emission reduc-

tions occur when materials removed from the

incoming fuel feed and/or metals recovered

from combustion byproducts are recycled.

This avoids emissions attributable to the ex-

traction and processing of virgin materials.

A frequently cited resource management

concern is that WTE facilities may under-

mine recycling programs, but the European

experience shows that countries with high

energy recovery rates also exhibit higher-

than-average recycling rates. In 2006, 41%

of the MSW stream across Europe was re-

cycled or composted, 19% was delivered to

more than 400 WTE plants, and 40% was

landfilled. In 2008, the U.S. recycling rate

was 33%, 13% of MSW was delivered to a

total of 87 WTE incinerators and FBC units,

and 54% was landfilled, according to the

EPA. Similarly, the post-recycling energy

recovery rate is more than 30% across Eu-

rope, less than 20% for the U.S., and even

lower in China and many other nations. By

contrast, this rate ranges from 70% to 80%

in Japan and exceeds 90% in Denmark and

the Netherlands, highlighting the potential

for increased WTE deployment.

Fuels and Processing MethodsAs a fuel, MSW poses a number of challeng-

es. It is produced on a distributed basis, and

its composition is highly variable, including

a mix of organic and inorganic constituents.

Hazardous and toxic waste stream compo-

nents pose health and safety risks. Low en-

ergy density and high moisture, chlorine, and

ash content lead to handling, combustion,

slagging and fouling, corrosion, and byprod-

uct management issues.

Lightly processed, post-recycling MSW

received at mass-burn WTE plants has a heat-

ing value in the range of 4,500 to 5,500 Btu/

lb. High-intensity processing yields refuse-de-

Reduction

Reuse

Recycling

Composing & digestion

Energy recovery

Landfill & methane capture

Landfilling

Was

te t

o

ener

gy

Environmental hierarchy for

solid waste management

3. Greening up MSW manage-ment. Incineration and advanced thermal

conversion of the residual waste remaining

after recycling and composting represent en-

vironmentally sound municipal solid waste

(MSW) management options. Digestion-

based waste-to-energy technology also may

be deployed to extract useful energy from

compostable materials and from landfill gas

that is captured to reduce pollutant and green-

house gas emissions. Source: EPRI

4. From refuse to electrons. When raw municipal solid waste (MSW) is transformed into

refuse-derived fuel (RDF) that can be used to generate electricity, large amounts of inorganic and

organic materials are recovered for recycling and composting. The end result is a higher-quality

fuel with more uniform content and significantly improved handling and combustion performance.

RDF also may be pelletized to improve transport. Sources: EPA and Scoullos et al., 2008

31% paper

59.2% paper

12% plastic

27.5% plastic

5% textile4.9% glass

11% textile

8.4% metals

12.7% food scraps

13.2% yard waste

6.6% wood

Recycling

RDF composition

Composting

MSW composition

RENEWABLE ENERGY


rived fuel (RDF)—also known as solid recov-

ered fuel—which is more amenable to firing

in FBC units and advanced thermal conver-

sion systems and offers the potential for high-

rate cofiring in pulverized coal plants.

Mechanical, magnetic, thermal, biologi-

cal, and other techniques may be applied to

isolate and process combustible fractions.

Residual waste—mainly a mixture of pa-

per and plastics—is pulverized and dried to

form a fluffy material of relatively uniform

consistency with a heating value of roughly

5,500 to 6,500 Btu/lb (Figure 4). RDF may

be packed as cubes or pellets for easy storage

and transportation.

Processed engineered fuel (PEF) refers to

higher-grade RDF produced from sorted and

mechanically processed wastes, such as pack-

aging materials and tires, and from custom

blends of paper, plastic, and other materials.

The higher energy density, improved han-

dling characteristics, and reduced moisture

and ash content of derived fuels translate into

lower heat rates and O&M costs. Of course,

realizing these benefits has impacts, in that in-

stalling and operating fuel-processing systems

at the plant site imposes energy and cost pen-

alties. Centralized manufacturing of higher-

grade fuels offers potential economies of scale,

while source-based production creates oppor-

tunities to reduce hauling costs and facilitate

long-distance trade. RPS eligibility remains an

issue for individual fuel formulations.

For ADTE technologies, the digestion pro-

cess relies on anaerobic bacteria that break

down organic materials into sugars, acids,

and then gases, leaving behind liquid and sol-

id residues. Decomposition occurs over years

to decades in landfills and days to weeks in

purpose-built digesters.

Produced at atmospheric pressure and

saturated with water, digester gas typically

must be compressed, dehydrated, and treated.

Depending on the fuel and power generation

option, extensive pretreatment may be re-

quired to remove siloxane, hydrogen sulfide,

and other constituents with potential to cause

corrosion, erosion, environmental control,

and odor problems. Further cleaning and pu-

rification are necessary to achieve the quality

required for injection of pipeline-quality re-

newable fuel in natural gas delivery systems.

Generation TechnologiesWTE technologies come in different forms,

offer a variety of outputs, and are in various

stages of development, but they have two

common objectives: to both manage waste

and generate energy. Conventional combus-

tion-based processes transform solid wastes

into heat for direct use or further conversion

into steam and electricity, while advanced

conversion processes convert solids into gas-

eous or liquid fuels offering broader utility.

Figure 5 displays the status of a broad range

of WTE technologies, showing the extent to

which public-private investment is required

to yield commercially mature systems.

Comparing the economic, energy, and en-

vironmental performance of individual WTE

technologies on a consistent basis is extreme-

ly difficult. Traditionally, incineration and

other options have been evaluated on the ba-

sis of $/ton of MSW disposed in comparison

to the cost of landfilling or on their ability

to meet the objectives of integrated resource

management plans, rather than on the $/kW

and $/MWh metrics commonly used in the

power industry.

From an energy recovery perspective,

producing hot water for direct use in district

heating is the simplest and highest-efficiency

approach for MSW, with a net level exceed-

ing 60%. Generating steam for district or in-

dustrial process heating or CHP applications

is somewhat less efficient, while cofiring

RDF and PEF in coal plants further reduces

conversion efficiency to around 30%. Steam-

electric power generation in a dedicated

incinerator or FBC plant offers low efficien-

cy—around 20% or less—due primarily to

fuel properties, boiler design and size, and

heat losses, as well as reduced net power

export due to parasitic energy consumption

required by environmental control systems.

MSW conversion processes yielding gas-

eous fuels suitable for firing in combustion

turbines and combined-cycle plants offer

potential for substantial gains in electricity

production efficiency.

Conventional Thermal ConversionMass-burn incineration, the simplest and

lowest-cost option for electricity production,

also accounts for the overwhelming majority

of installed WTE capacity.

FBC technology offers higher conversion

efficiency and lower pollutant emissions, but

its application has been constrained by the

limited availability and higher cost of RDF.

Higher-quality fuel is required to maintain

stable combustion conditions in these sys-

tems because they have a much shorter resi-

dence time.

For both types of plants, steam serves a tur-

bine-generator train, and power flows through

a transmission-class substation onto the grid,

as shown in Figure 6. Net electrical output is

roughly 550 to 600 kWh/ton of MSW. Turbine

exhaust is directed to a condenser for cooling,

but in cogeneration applications heat may be

extracted and water or steam fed to a distri-

bution system for district or process heating.

Conventional wet cooling systems may re-

quire significant amounts of water. Air-cooled

condensers can reduce water consumption by

up to 90% while imposing parasitic loads that

increase generation costs.

Advanced Thermal ConversionFor advanced thermal conversion technolo-

gies, design goals are to increase materi-

als recovery and recycling rates, improve

the quality of recyclables, simplify flue gas

cleanup, and reduce the quantity and improve

the quality of solid byproducts that must be

disposed of via landfill. There are three ad-

vanced thermal conversion processes of im-

portance:

■ Pyrolysis involves energy-assisted heating

of MSW in the absence of oxygen within a

range of about 400C to 800C. Byproducts

include volatile liquids and syngas—with

relative proportions determined by process

temperature—plus a blend consisting pri-

marily of metals that may be recycled and

char that may be used for energy recovery

or beneficial applications.

MSW pretreatment

An

tic

ipa

ted

co

st o

f fu

ll-s

ca

le a

pp

lic

ati

on

Carbon capture

MSW natural gas hybrid cycles

Renewable gas for transportation

MSW plasma arc gasification

MSW pyrolysis

MSW gasification

Advanced emission controls

ADTE-LFG & digester gasRDF/PEF cofiring

High-efficiency energy-materials

recovery

MSW mass burn

Research Development Demonstration Deployment Mature technology

Time

Notes: ADTE= anaerobic digestion to energy, LFG= landfill gas, MSW= municipal solid waste,

RDF= refuse-derived fuel, PEF= process-engineered fuel.

5. Maturing at different rates. WTE technologies are at varying stages of development

and commercial maturity, as shown by this Grubb curve. Source: EPRI

RENEWABLE ENERGY


■ Gasification involves heating of mixed

MSW or derived fuels at temperatures ex-

ceeding 700C in the presence of sufficient

oxygen to allow partial oxidation, but not

enough for full combustion. This energy-

assisted process yields a syngas mixture of

hydrogen, carbon monoxide, water vapor,

methane, and other constituents.

■ Plasma arc gasification is a technology

developed for hazardous waste incinera-

tion. It involves the use of a gasification

reactor in combination with high-voltage

electrodes that create a plasma torch.

The torch operates at about 1,200C, well

below the temperatures employed to de-

stroy hazardous waste but sufficient to

transform the complex gas mixture into a

simpler syngas.

Once treated, MSW-derived syngas may

be fired in internal combustion engines sized

in 1-MW increments or, far less commonly,

in steam-electric boilers. With additional

processing, it may be used in combustion tur-

bines or combined cycle units. Units gener-

ally are sized at 20 MW or less, and electric

generation efficiencies of 25% to 40% are

achievable. Energy recovery may yield re-

cyclable slag, residual material that must be

landfilled, or both.

Biological ConversionDigestion relies on biological processes to

produce gaseous fuels exhibiting consider-

able utility and energy density. Processes

occurring within landfills generally are un-

controlled, while those occurring in enclosed

plastic, concrete, or metal structures may be

managed by altering feed characteristics and

rates, controlling physical conditions, and

making chemical and biological additions.

LFG is commonly collected and used to

serve on-site needs for energy. At wastewa-

ter treatment plants, digester gas arising from

processing of the solid fraction of domestic

sewage traditionally has been fired for pro-

cess heating, but a growing number of plants

are using it for CHP applications. Manure

from large-scale cattle, pig, and poultry op-

erations increasingly is being employed to

generate fuel for energy production consis-

tent with some RPS mandates.

Digestion of biogenic MSW fractions is

an emerging approach to solid waste man-

agement. For this application, mechanical

pretreatment may be used to separate out re-

sidual recyclables and noncombustibles and

isolate the organic materials to be introduced

to the digester.

Reciprocating engines—the most com-

monly employed generation option for

digester gas—may be installed in 1-MW

increments to match the on-site fuel supply.

Both smaller and larger engines are available.

Small combustion turbines may be deployed

in the range of 1 to 5 MW or at microturbine

scale, while fuel cells may be employed for

fuel meeting tight quality standards. Steam-

electric and combined cycle plants are suited

only to sites with fuel supplies capable of

supporting central-station generation. In

many cases, ADTE installations are backed

by natural gas or propane firing capability to

ensure consistent energy production.

Cofiring and Hybrid CyclesMSW-derived solid fuels, syngas, and digest-

er gas may be cofired in fossil plants, and hy-

brid cycles involving distinct waste and fossil

fuel feeds are being explored. Depending on

the fuel characteristics and policy environ-

ment, these approaches may provide options

for reducing fuel costs and GHG emissions

as well as generating renewable energy.

Proper fuel specifications are critical for

successful MSW cofiring applications. Experi-

ence indicates that PEF with heating values in

the range of 8,500 to 11,500 Btu/lb (wet weight

basis) may successfully contribute up to 30% of

the input energy in coal-fired boilers.

Renewable GasLFG, digester gas, and syngas may be up-

graded and injected into natural gas networks

for direct use in heating or transportation ap-

plications. LFG from the Fresh Kills Landfill

in New York, for example, has been treated

to increase methane concentrations, meet

other pipeline-quality criteria, and feed the

local gas distribution system for more than

30 years.

A number of utilities and agencies are

exploring renewable gas production as an

option for GHG mitigation and enhanced en-

ergy recovery because modern heating sys-

tems achieve efficiencies of 80% to 90% and

higher—far above those achieved in power

generation applications.

Operations and MaintenanceModern WTE plants offer availabilities ex-

ceeding 90%, comparable to those of other

baseload generating options. Sensor and

control systems, operating environments,

degradation mechanisms, and maintenance

needs also are generally similar. Many of the

O&M challenges unique to WTE capacity

arise from the characteristics of MSW as a

fuel source.

Difficulties in MSW handling and feeding

increase labor and maintenance requirements

and, along with variations in fuel quality,

complicate process control in incinerators.

Mass-burn

incineration

Advanced thermal

conversion

ECS Stack

Grid

GeneratorSteam turbine

Boiler

Ash

MSW

ECSStack

Grid

Generator

Steam turbine

Generator

Cleanup

Cooling

Slag

Gasification/ pyrolysis reactor

Combustion turbine

RDF

6. Conventional and advanced thermal conversion technologies. Conventional mass-burn incinerators typically operate on

as-received or lightly processed municipal solid waste and are based on mature steam-electric generation systems. In contrast, advanced ther-

mal technologies require higher-quality refuse-derived fuel or processed engineered fuel and involve a multi-step process, whereby solid fuel is

transformed into syngas that must be cooled, cleaned, and then fired to generate electricity. Source: EPRI

Notes: ECS= environmental control systems, HRSG= heat recovery system generator, RDF= refuse-derived fuel.

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RENEWABLE ENERGY


High slagging and fouling rates necessitate

frequent removal of ash deposits, while non-

combustible materials and aggressive chemi-

cal conditions lead to accelerated rates of

erosion and corrosion.

Environmental ControlsModern incinerators have lower life-cycle

pollutant and GHG emissions than landfill-

ing. In general, WTE plants have output-

based emission rates for conventional air

pollutants roughly comparable to those of

existing coal-fired capacity but higher than

those of gas-fired units. On a per-MWh ba-

sis, overall CO2 emissions from incinerators

typically exceed those of coal-fired plants

due to high moisture content, other fuel

properties, and low conversion efficiencies.

However, the substantial percentage of these

releases attributable to combustion of bio-

genic fuel fractions is commonly subtracted

from the total under conventional life-cycle

analysis frameworks.

Stack emissions and other releases from

WTE plants generally are subject to stringent

regulation, such as the maximum available

control technology mandate under the Clean

Air Act that required large U.S. incinerators

to install dry flue gas desulfurization (FGD)

scrubbers, fabric filter baghouses, activated

carbon injection, selective noncatalytic re-

duction, and other measures by 2000. This

largely has eliminated harmful emissions

from existing MSW capacity, at the cost of

increased parasitic energy consumption and

higher O&M costs.

Figure 7 illustrates the dramatic reduction

in dioxin and furan releases—from 8,877

toxic equivalents (TEQ) in 1987, when incin-

erators accounted for more than 60% of total

U.S. airborne emissions, to 12 TEQ in 2002.

This 99.9% decrease was complemented by

absolute reductions in emissions of mercury,

lead, cadmium, and hydrochloric acid of

more than 90% and of sulfur dioxide and par-

ticulate matter by more than 85%. For some

contaminants, source reduction has made

important contributions. Many mercury-con-

taining products have been phased out, and

recycling programs in communities served

by WTE facilities are keeping mercury out of

the MSW stream.

Capturing and recovering energy from

LFG substantially reduces pollutant and

GHG emissions, relative to landfilling. Lim-

ited data are available on air emissions as-

sociated with energy recovery from digester

gas generated from wastewater, manure,

MSW organics, and other biogenic wastes.

A variety of pretreatment, combustion-based,

and post-combustion technologies are avail-

able. Odor management measures include

enclosures, filters and treatment methods at

air intakes and exhausts, and negative pres-

sure control.

Solid byproducts from MSW combus-

tion and control processes include fly ash,

bottom ash, slag, and FGD solids. Ferrous

and nonferrous metals typically are extract-

ed from bottom ash as recyclables, and the

remaining ash then may be recycled as an

aggregate material. Fly ash and FGD solids

often contain relatively high concentrations

of heavy metals and other contaminants.

This may limit opportunities for beneficial

reuse in concrete, fill, gypsum, and other

applications and require disposal in a dedi-

cated landfill, at significant cost.

Conventional treatment technologies

are available for liquid wastes and thermal

discharges generated during fuel storage,

dewatering, steam-electric conversion, en-

vironmental control, and cooling operations

associated with WTE capacity.

Future Directions in the Develop-ment of WTE TechnologiesMany European and Asian nations have high

energy recovery rates, while mature WTE tech-

nologies have experienced relatively modest

application in the U.S. and many other coun-

tries. To expand deployment in the U.S. and

elsewhere, common misconceptions regarding

the environmental performance of WTE tech-

nologies must be eliminated, and decision-

makers must treat post-recycling MSW as an

asset for energy recovery, emission reduction,

and baseload renewable energy production

rather than as a liability for disposal.

7. Cutting out dioxins and furans. State-of-the-art environmental control sys-

tems have reduced dioxin and furan emis-

sions from U.S. incinerators by 99.9% since

the mid-1980s, and they allow these facilities

to routinely comply with air quality standards

tighter than those faced by coal-fired plants.

Source: Psomopoulos et al., 2009

10,000

9,000

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

01987 1995 2002

Tox

ic e

qu

iva

len

ts

8. Untapped potential. Given the very

low energy recovery rates and high landfilling

rates in many regions of the country, the U.S.

has many promising prospects for successful

WTE deployment. Sources: Michaels, 2007;

Simmons et al., 2006

New England

Mid-Atlantic

South

Great Lakes

Midwest

West

29%

36% 35%

33%49%

18%

22%69%

9%

31%65%

4%

22%

77%

1%

14%

85%

1%

38%60%

2%

Rocky Mountains

Incinerators by state

MSW management by region

Landfilling Recycling Waste-to-energy

IS YOUR PLANT OR

SMART GRID PROJECT

A WINNER?

2011 MARMADUKE AWARD:

CFE’s CTG Universidad Unit 2

2011 PLANT OF THE YEAR:

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Nominate it for a Award today!

The Plant of the Year award will be presented to a plant that leads our industry in the successful deployment of advanced

technology—maximizing effi ciency while minimizing environmental impact. In short, the Power Plant of the Year, featured in the August issue of POWER, is the best of class over the past year.

If you know of a power plant or upstream smart grid

project that’s worth bragging about, nominate it for

one of POWER magazine’s annual awards. Projects

anywhere in the world are eligible.

For award criteria details, see the online nomination forms. Award fi nalists and winners will be selected by the editors of POWER

based on nominations submitted by you and your industry peers—suppliers, designers, constructors, and operators of power

plants and smart grid projects.

The Marmaduke Award, named after the legendary plant troubleshooter whose exploits have been chronicled in POWER since 1948, recognizes operations and maintenance excellence

at existing power plants. The Marmaduke Award winner will also be profi led in the August issue.

Top Plants Awards recognize the best in class over the past year in each of four generation categories: gas (September), coal-fi red

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NOMINATIONS ARE DUE MAY 21, 2012.

Read about all the 2011 winners and

download entry forms from www.powermag.com

(under “Also from POWER Magazine”).

RENEWABLE ENERGY


In addition, the costs and risks of existing

and emerging WTE options must be reduced

through investments in research, develop-

ment, and demonstration (RD&D) to improve

cost-performance characteristics and through

consistent policy and market frameworks that

account for their attributes as renewable en-

ergy and climate mitigation options.

As shown in Figure 8, most U.S. re-

gions continue to landfill much more than

50% of their solid waste. Almost half of

the existing MSW-firing plants are sited in

densely populated northeast states, where

landfill space is at a premium. Since 1996,

no new incinerators have been deployed in

the U.S., leading to an increase in intra-

state MSW transport from sending areas

lacking landfill capacity to more rural re-

ceiving areas. Despite the fact that long-

distance hauling and landfilling result in

higher levels of pollutant and GHG emis-

sions than would energy recovery from a

nearby WTE facility, this trend may con-

tinue as existing disposal sites are closed

and challenges associated with permitting

new landfills in developed areas grow.

Countering this trend is the recent ex-

pansion of a WTE plant in Lee County,

Fla. (Figures 9 and 10), where generating

capacity was augmented from 40 MW to

60 MW to handle the increasing MSW vol-

ume from Ft. Myers and nearby commu-

nities. Efforts to expand existing facilities

are under way elsewhere, and new plants

are being considered across the country.

However, a number of U.S. states main-

tain bans on new MSW incinerators and

are considering extending these bans to

include advanced WTE technologies such

as gasification and pyrolysis.

Relative to landfilling, energy recovery

offers much lower GHG emissions, requires

much less land, and boosts recycling rates.

Stringent regulations, advanced control tech-

nologies, and other measures hold pollutant

emissions from modern incinerators below

the permit limits established to protect envi-

ronmental and human health. Handling prac-

tices—such as using rail rather than truck

transport, employing covered containers, and

unloading MSW inside buildings with nega-

tive pressure control—help address noise,

litter, and odor concerns. WTE technologies

deployed at landfills, treatment plants, and

farms offer an advantage in that they may be

seen as part of an ongoing municipal or agri-

cultural operation.

Comprehensive life-cycle analyses evalu-

ating energy recovery within waste manage-

ment, energy supply, and climate mitigation

contexts are needed to document the benefits

of WTE technologies, while proactive com-

munication with decision-makers, stake-

holder groups, and the public is required to

address concerns and increase acceptance

for individual projects as elements within

integrated resource management strategies.

Science-based information and educational

outreach also are necessary to help ensure

that WTE options are eligible for the invest-

ment and production incentives granted to

renewable energy sources and are designated

as qualifying technologies under RPS man-

dates and other directives.

Cost reduction and further improvement

in environmental performance represent ad-

ditional RD&D priorities. At present, MSW

incinerators are much more costly to build

and operate than coal-fired steam electric

capacity and other baseload generation, and

most WTE plants are economically viable

only because their fuel provides a source of

revenue in the form of tipping fees.

New source separation and MSW pro-

cessing technologies are needed to remove

potentially harmful constituents and to

produce derived and engineered fuels of-

fering improved handling characteristics,

increased energy density, and decreased

moisture and ash content, and reduced

emissions of pollutants and GHGs. These

advances would reduce the capital invest-

ment required for fuel feed and environ-

mental control systems, as well as lower

heat rates and O&M costs for incinerators.

In addition, they would facilitate long-dis-

tance fuel transport, potentially leading to

the siting and construction of larger, more

cost-efficient WTE facilities in rural areas.

Improved fuels also would enable high-

rate MSW cofiring in coal-fired plants, a

potentially low-cost approach for reducing

carbon emissions from existing capacity

while generating renewable energy.

To support deployment of advanced con-

version processes and hybrid plant concepts,

successful commercial-scale demonstrations

are needed to confirm the ability of individ-

ual technologies to handle large amounts of

waste on a reliable basis, in an environmen-

tally sound manner, over an extended period.

Current EPRI projects address several

key areas for growing the role of WTE tech-

nologies in meeting U.S. needs for clean, af-

fordable, reliable, and sustainably produced

electricity. EPRI plans to continue collabora-

tive work with utilities, agencies, and other

stakeholders to identify and pursue near-,

mid-, and long-term RD&D needs and op-

portunities. ■

—Stan Rosinski ([email protected]) is program manager of Renewable Gen-

eration at the Electric Power Research Institute Inc. (EPRI). To access EPRI’s full

“Waste-to-Energy Technology” white paper, go to http://tinyurl.com/7jc4sxs.

9. Leading the way. The Lee County

waste-to-energy (WTE) and recovered materi-

al processing plant, one of the most advanced

solid waste management systems in the U.S.,

burns waste at more than 1,800F. The plant is

equipped with extensive air-pollution control

systems, such as the scrubber shown in the

photo. The Lee County WTE plant is the first

U.S. plant built with a permanent activated

carbon injection system for controlling mer-

cury emissions. Courtesy: HDR Inc.

10. Once is not enough. Adding an ad-

ditional layer of sustainability, the Lee County

WTE plant operates as a zero-discharge facility.

The clarifier at the plant is used to treat recycled

wastewater from a nearby municipal wastewa-

ter treatment plant. Courtesy: HDR Inc.

Energy Products of Idahois now Outotec

www.outotec.com/energyproducts

Outotec innovates, develops and delivers sustainable technology and service solutions to minerals, metals, chemical and energy

industries. Outotec collaborates lifelong with its customers in order to optimize the utilization of raw materials and

energy efficiency as well as to minimize the environmental impact and operating costs.

Outotec Oyj is listed on the NASDAQ OMX Helsinki.

We know you have come to trust EPI for high quality and reliable fuel thermal oxidation and gasification technologies to recover energy from biomass and wastes, and we are committed to making sure that trust only grows stronger.

Under the Outotec umbrella, we increase our global presence and expand our capabilities allowing us to even better meet customer needs worldwide. Now operating as Outotec Energy Products, we can also grow our service offerings for our large existing base of installed technology only further improving the overall quality of service and support you have come to expect.

Contact us: Tel. +1 208 765 1611email: [email protected]

Energy Products of Idahois now Outotec

www.outotec.com/energyproducts

Outotec innovates, develops and delivers sustainable technology and service solutions to minerals, metals, chemical and energy

industries. Outotec collaborates lifelong with its customers in order to optimize the utilization of raw materials and

energy efficiency as well as to minimize the environmental impact and operating costs.

Outotec Oyj is listed on the NASDAQ OMX Helsinki.

We know you have come to trust EPI for high quality and reliable fuel thermal oxidation and gasification technologies to recover energy from biomass and wastes, and we are committed to making sure that trust only grows stronger.

Under the Outotec umbrella, we increase our global presence and expand our capabilities allowing us to even better meet customer needs worldwide. Now operating as Outotec Energy Products, we can also grow our service offerings for our large existing base of installed technology only further improving the overall quality of service and support you have come to expect.

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BIOMASS POWER

Has Boiler MACT Improved the Future for Biomass Power?The impact of recently released air emissions regulations has stirred heated

debate about forced coal plant closures and the possibility of reduced grid reliability in some regions. Biomass power may be an unexpected benefi-ciary of the new rules.

By Brandon Bell, PE, KBR Power & Industrial

On Dec. 23, 2011, the U.S. Environ-

mental Protection Agency (EPA) re-

leased proposed changes to the Pro-

mulgated Rule of the National Emission

Standards for Hazardous Air Pollutants,

also referred to as Boiler MACT, for both

“Major Source” and “Area Source” facili-

ties. When Boiler MACT was promulgated

on Mar. 21, 2011, the EPA recognized

some provisions might be too stringent

for facilities covered by the regulation.

Therefore, the very same day, the agency

issued a notice of its intent to reconsider

certain provisions of the just-released rule.

A formal extension of the effective date of

Boiler MACT was announced on May 18,

2011, with a request to the public to supply

data to assist the EPA in its reconsidera-

tion efforts. Affected industries still have

until 2015 to comply with the rule.

The EPA next released the final Mercury

and Air Toxics Standards (MATS) on Dec.

21, 2011. Proposed changes to the Cross-

State Air Pollution Rule (CSAPR) were

released Dec. 23, 2011, and immediately

stayed by the U.S. Court of Appeals for the

District of Columbia Circuit on Dec. 30,

two days before the rule’s effective date.

Unfortunately, the sometimes-heated

discussions of MATS and CSAPR and

their impact on the reliability of the na-

tion’s power supply have obscured the

possibly positive impact of Boiler MACT

on biomass plants.

Rules Benefit BiomassIt may surprise you to learn that this in-

creased pressure from the EPA on coal-

fired generators (expected to cause 40 GW

to 50 GW worth of coal plant closures),

coupled with the demand for renewable

energy sources, is having an unexpected

side effect: It’s making biomass a more at-

tractive power generation alternative. Fur-

thermore, the changes the EPA is expected

to make to the Boiler MACT rule will fa-

vor biomass power much more than in the

earlier version. Those expected improve-

ments are discussed in greater detail later

in this article.

The revised Boiler MACT regulation

appears to favor biomass power in the im-

pact it has on required emission reduction

technologies. As it stands, the promulgated

rule will require the addition of multiple

emission reduction systems in order to

meet pollutant limitations. The proposed

regulation removes and reduces many of

the limitations, thus the positive impact on

the economics of biomass plants.

There are three categories of hazardous

air pollutants (HAPs) in the promulgated

Boiler MACT rule, under Major Sources,

that place new limitations on pollutant

emissions from both existing and new bio-

mass facilities: hydrogen chloride, mer-

cury, and dioxins/furans (Table 1).

Determining an uncontrolled emission

rate for each of the three HAPs is a major

concern with meeting these limitations.

Biomass typically does not have consis-

tent characteristics because it is not always

procured from the same source. Due to

sourcing inconsistencies, environmentally

regulated constituents in the fuel may vary

greatly. For new biomass plants, there is

some consistent data for woody biomass

that could be used to produce baseline

emissions to estimate reduction percent-

ages. However, for many other biofuels

(including switchgrass, corn stover, and

miscanthus) there is sparse, if any, infor-

mation pertaining to the regulated HAPs.

Even with the lack of data, control tech-

nologies will be required to meet the Boil-

er MACT requirements.

HAPs Ripe for RemovalFor biomass combustion, the control of

mercury and dioxin/furan emissions is

most effective when using a powdered

activated carbon (PAC) injection system.

Mercury can be a particularly difficult pol-

lutant to control and is generally found in

low concentrations in biomass fuel. After

completing the combustion process, mer-

cury exists in three forms: an elemental

state (Hg0), a divalent state (Hg++), or as

particulate.

Mercury in a particulate form is the

easiest to control, as it will be captured

Table 1. Summary of hazardous air pollutants and their limits in the promulgated Boiler MACT rule. Source: EPA

Combustion technology

Hydrogen chloride

limitation (lbm/106 Btu)

Mercury limitation

(lbm/106 Btu)

Dioxin/furan

limitation (ng/dscm)

Fluidized bed, existing 0.0350 0.000005 0.020

Fluidized bed, new 0.0022 0.000004 0.020

Stoker/other, existing 0.0350 0.000005 0.005

Stoker, new 0.0022 0.000004 0.005

Dutch oven/suspension, existing 0.0350 0.000005 0.200

Dutch oven/suspension, new 0.0022 0.000004 0.200

Fuel cells, existing 0.0350 0.000005 4.000

Fuel cells. new 0.0022 0.000004 0.003

Suspension/grate, existing 0.0350 0.000005 0.200

Suspension/grate, new 0.0022 0.000004 0.200

Notes: dscm = dry standard cubic meter, lbm = pound mass, ng = nanogram.


BIOMASS POWER

in particulate control devices. Oxidized

mercury is water-soluble and will readily

be adsorbed using activated carbon tech-

nologies. Elemental mercury is a very

stable molecule and difficult to remove

from flue gas. Typically, elemental mer-

cury must be forcibly oxidized in order

to promote its capture; otherwise, it most

likely will pass through the boiler and air

quality control systems and be released

into the environment.

Sparse testing for dioxin/furan emis-

sions of biomass sources has been con-

ducted; however, the results of available

data show that emissions for all species of

dioxins and furans are generally insignifi-

cant. Because of the low emission rates,

it is impractical to destroy dioxin/furan

emissions by means of thermal oxidation.

The more realistic removal technique is

sorbent capture and removal by a particu-

late control device. This is another reason

why dioxin/furan emissions for biomass

facilities are best controlled by using PAC

systems. A PAC system will absorb the di-

oxins and furans, which will then be col-

lected in the particulate control device.

The capital cost of a PAC system is es-

timated to be in the $21 to $42/kW range.

Additionally, the average cost for activated

carbon is in the range of $1,000 to $1,500/

ton of sorbent. For industrial-size plants,

this adds a significant capital cost plus a

high operational cost.

Hydrogen chloride (HCl) emissions will

vary greatly, depending on the source of

the biomass fuel. Recent data suggests that

clean woody biomass can achieve uncon-

trolled HCl emissions in the 0.004 to 0.006

lbm/million Btu range. Although these

emissions rates are low, the promulgated

regulation requires additional reduction to

maintain compliance. If a facility requires

control of sulfur dioxide (SO2) emissions,

then control of HCl should not be an issue.

This is because sorbents used to control

SO2 have a greater affinity to react with

HCl over SO2. Therefore, reduced HCl

emissions will be a byproduct of SO2 con-

trol. Biomass fuels, however, are naturally

low in sulfur and do not always require

control of SO2 emissions.

In the absence of SO2 controls, a dry

sorbent injection (DSI) system using lime-

stone, hydrated lime, or sodium-based sor-

bents is most economical and can achieve

the required HCl control. Limestone (cal-

cium carbonate) requires a substantial

amount of heat to reduce hydrogen chlo-

ride into calcium chloride. For this reason,

milled limestone is typically injected into

the furnace for maximum removal effi-

ciency. Hydrated lime (calcium hydrox-

ide) requires less heat for the removal of

HCl and is typically injected into the flue

gas downstream of the furnace. Figure 1

shows the complete reaction for hydrogen

chloride mitigation using limestone and

hydrated lime.

Sodium sorbent injection (trona and

sodium bicarbonate) has also proven ef-

fective for reducing hydrogen chloride

emissions. This class of sorbents requires

a moderate amount of heat (650F to 900F

at the injection point) to effectively re-

move hydrogen chloride. Injection points

will vary from upstream of the economizer

to downstream of the air heater. Figure 2

shows the full reaction, including the cal-

cination of the sodium sorbents.

Unfortunately, some wood fuels and

other biomass fuels contain levels of chlo-

rine that can be an order of magnitude

higher than in clean, woody biomass. In

these cases, sodium-based sorbents may be

the only solution for controlling HCl emis-

sions to regulatory limits. A DSI system

for control of HCl will add an additional

$28 to $63/kW of capital cost to a proj-

ect. Sorbent prices will also vary greatly,

depending on sorbent type and location of

the facility, but will contribute to a signifi-

cant increase in operating cost.

Fortunately, with release of the new

proposed Boiler MACT for Major Sourc-

es, all of these limitations have been re-

moved. If the new proposed regulation is

1. Reducing HCl with lime. Limestone or hydrated lime can be injected into the furnace

to reduce HCl emissions from the burning of biomass. Source: KBR Power & Industrial

Calcium hydroxide (Hydrated lime)

Ca(OH)2

Hydrogen chloride2HCI

Calcium chlorideCaCI2

Carbon DioxideCO2

Water2H2O

+ +

+

HCI removal with limestone

Calcium carbonate (limestone)

CaCO3


+Calcium chloride

CaCI2

WaterH2O

+

HCI removal with hydrated lime


Carbon DioxideCO2

+

+

CalcinationTrona2• (NaHCO3 • Na2CO3 • 2H2O)

Water5H2O

+

Sodium bicarbonate2NaHCO3

Calcination

Sodium sorbents

Sodium carbonate3Na2CO3

Sodium carbonateNa2CO3

Carbon DioxideCO2

WaterH2O

+

+

HCI acid mitigation

Sodium carbonateNa2CO3

Carbon DioxideCO2

Sodium chloride2NaCI

+

2. Reducing HCl with sodium sorbents. HCl can also be removed from stack

emissions of a biomass-fired furnace by injecting the sorbents trona and sodium bicarbonate.

Source: KBR Power & Industrial

The control of mercury and dioxin/furan emissions is most effective when using a powdered activated carbon injection system.


BIOMASS POWER

finalized as written, it will impact the eco-

nomics of biomass power plants in a very

positive way.

However, when analyzing the emissions

issues associated with a given plant con-

cept, there are also two criteria pollutants

regulated under Boiler MACT that must be

examined to determine the overall effect of

the proposed regulation.

CO and PM Limits RevisedThe promulgated Boiler MACT regulation

put in place new limitations on particulate

matter (PM) and carbon monoxide (CO)

emissions. In a similar fashion to HAPs

emissions, the regulations were placed on

combustion technology rather than biomass

units as a whole. The proposed revision is-

sued Dec. 23, 2011, did not remove these

restrictions. However, it did modify the

original limitations in a manner more fa-

vorable to biomass units. Table 2 provides

a summary of the values from the rule pro-

mulgated on March 21, 2011, and Table 3 is

a summary of the revised limitations.

Comparing the emission limits found

in the March 21 promulgated rule (Table

2) and those in the Dec. 23 proposed rule

(Table 3) illustrate that, in almost all cat-

egories of emissions, the limits were in-

creased, additional combustion technology

categories were added, and more testing

options were provided.

In the category of PM emissions, the

owner/operator will now have the option

to choose a limit on either filterable PM

emissions or on total selected metals. The

list of “total selected metals” will include

arsenic, beryllium, cadmium, chromium,

lead, manganese, nickel, and selenium.

Both options will be required to show

compliance based on a three-run average.

Carbon monoxide limitations for new

fluidized bed boilers decreased slightly,

but CO limitations for stoker units in-

creased significantly. In addition to chang-

ing emission limitations, the facilities

will have the option of showing compli-

ance with a three-run average or by using

a 10-day rolling average monitored by a

continuous emission monitoring system.

Changes to the PM and CO limitations re-

sult in added flexibility and reduced cost.

Area Source Limits UnchangedAnother revision to Boiler MACT for fa-

cilities categorized as Area Sources was

also released on Dec. 23, 2011. For bio-

mass facilities, though, the regulations

already put in place in March remained

unchanged. The only regulated emission

for Area Sources is filterable particulate

matter. All combustion technologies with

a heat input rated between 10 million Btu/

hr and 30 million Btu/hr will be required

to meet a 0.07 lbm/million Btu limitation.

Those units with a heat input rated at 30

million Btu/hr and greater will be required

to meet a filterable PM emission limitation

of 0.03 lbm/million Btu. Note that these

limitations will only apply to new biomass

facilities; existing facilities will not be af-

fected by this regulation.

The biomass industry is hopeful that the

new limitations proposed in the December

draft regulation will replace the current

limitations released in March last year.

Regardless, if the proposed draft regula-

tions are an indication of the direction the

EPA is taking toward regulating emissions

from biomass facilities, then this is a very

positive development. With the removal of

stringent HAP regulations and the changes

proposed for PM and CO limitations, the

economics of biomass facilities would

change drastically.

If adopted as final, the updated regula-

tions—coupled with the recent release of

MATS and, eventually, CSAPR—should

continue to make new biomass facilities

an economic power generation option for

many years to come. ■

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


Particulate matter limitation

(lbm/106 Btu)

Carbon monoxide limitation

(ppm @ 3% O2)

Fluidized bed, existing 0.0390 430

Fluidized bed, new 0.0011 260

Stoker/other, existing 0.0390 490

Stoker, new 0.0011 160

Dutch oven/suspension burner, existing 0.0390 470

Dutch oven/suspension burner, new 0.0011 470

Fuel cells, existing 0.0390 690

Fuel cells, new 0.0011 470

Suspension/grate, existing 0.0390 3,500

Suspension/grate, new 0.0011 1,500

Table 2. Summary of PM and CO Biomass Emission Limitations (March 21, 2011 rule). Source: EPA


Filterable

particulate

matter

limitation

(lbm/106 Btu)

Total selected

metals

(lbm/106 Btu)

Carbon

monoxide

limitation

(ppm @ 3% O2)

Alternate

carbon

monoxide CEMS

limitation

(ppm @ 3% O2)

Fluidized bed, existing 0.1100 0.001200 370 NA

Fluidized bed, new 0.0098 0.000042 230 180

Wet stoker, existing 0.0290 0.000057 790 410

Wet stoker, new 0.0290 0.000026 590 410

Kiln-dried stoker, existing 0.3200 0.004000 250 NA

Kiln-dried stoker, new 0.3200 0.004000 250 NA

Suspension burner, existing 0.0510 0.001100 58 1,400

Suspension burner, new 0.0510 0.001100 58 1,400

Dutch oven/pile burner, existing 0.0360 0.000240 810 440

Dutch oven/pile burner, new 0.0360 0.000041 810 440

Fuel cells, existing 0.0330 0.000049 1,500 NA

Fuel cells, new 0.0110 0.000049 210 NA

Hybrid suspension grate, existing 0.4400 0.000490 3,900 730

Hybrid suspension grate, new 0.0260 0.000490 1,500 730

Notes: CEMS = continuous emissions monitoring system, dscm = dry standard cubic meter, lbm = pound mass, ng = nanogram.

Table 3. Summary of PM and CO Biomass Emission Limitations (Dec. 23, 2011 revision). Source: EPA

WE

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NUCLEAR POWER

Happy Days for Nuclear Power?The first license to construct a new nuclear power plant in the U.S. in 34 years

was granted by the Nuclear Regulatory Commission on Feb. 9. Has the elusive nuclear renaissance finally begun?

By Kennedy Maize

There was justification in early Febru-

ary for the U.S. nuclear industry to

be humming the famous Depression-

era song “Happy Days Are Here Again.”

Feb. 9, 2012, in Washington’s Maryland

suburbs was a bright but chilly day fol-

lowing a quick blast of cold Canadian air

and a dusting of snow that stuck on lawns

and fields but not roads. At noon, the U.S.

Nuclear Regulatory Commission (NRC)

voted 4-1 to approve a combined construc-

tion and operating license for Southern

Co.’s two new units at its existing Vogtle

nuclear station in Georgia (Figures 1 and

2). It marked the first new construction

license for a nuclear plant since Jan. 27,

1978, when Carolina Power & Light won a

construction license for its Shearon Harris

Unit 1 in central North Carolina.

That February moment was sweet. The

industry’s long nuclear nightmare ap-

peared to be over. The long-depleted proj-

ect pipeline was getting an injection. The

NRC was expected to soon approve a li-

cense for another new two-unit project, in

South Carolina.

Industry Insiders MeetAcross a busy Rockville Pike from the

NRC at a swanky Marriott hotel, Platts

was holding its 8th Annual Nuclear Energy

conference Feb. 9 to 10. Despite the NRC

action, there was a slightly bittersweet

aftertaste that colored the Platts gabfest.

The version of the Happy Days song that

seemed most appropriate for the nuclear

business that day was Barbra Streisand’s

slow-tempo, ironic, and somewhat som-

ber 1960s version, not the ebullient 1929

original that became the theme song for

Franklin Delano Roosevelt’s successful

campaign for president in 1932. Depress-

ing the nuclear buoyancy was the night-

mare of Fukushima.

The NRC vote, a pro-forma affirmation

of action the NRC had already discussed

and taken informally, came in the context

of the catastrophe in Japan just 11 months

earlier. NRC Chairman Gregory Jaczko

made the connection clear both in his key-

note address at the Platts conference and at

the commission meeting where he dissent-

ed on the Vogtle license. Jaczko told Platts

event attendees that the U.S. atomic power

industry is at a crossroads, where it can

fully understand and embrace the meaning

of the Fukushima disaster and move for-

ward, or it can give only lip service to the

lessons learned and go on with business as

usual. Down one path, he said, is a vital,

1. Long time coming. The NRC granted a combined construction and operating license

for Southern Co.’s Vogtle Units 3 and 4 on Feb. 9, 2012. The construction site for the new Units

3 and 4 is shown with Units 1 and 2 visible in the background. Courtesy: Southern Co.

2. Reactor construction under way. Southern Co. received an Early Site Permit and

Limited Work Authorization (LWA) from the NRC in August 2009. The LWA allowed safety-relat-

ed construction at the site prior to receiving the combined construction and operating license.

Shown is the assembly of the Unit 3 containment vessel lower ring. The photo was taken Jan.

30, 2012. Courtesy: Southern Co.


NUCLEAR POWER

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growing industry that enjoys public sup-

port; down the other is stagnation.

Three hours later, in his dissent, Jaczko

detailed his position: “I cannot support

issuing this license as if Fukushima had

never happened,” he said with no show of

emotion. In written comments attached to

the NRC order, he elaborated, “I simply

cannot authorize issuance of these licenses

without any binding obligation that these

plants will have implemented the lessons

learned from the Fukushima accident be-

fore they operate.” (The sidebar offers a

time line of events that led up to the Fuku-

shima accident and looks at the disaster’s

ongoing impact.)

The other four commissioners respect-

fully disagreed, arguing that the lessons

from Fukushima that the NRC staff has

identified will be incorporated into op-

erating procedures at Vogtle and across

the industry, without the need to put the

Southern Co. application on hold. Com-

missioner Kristine Svinicki said, “There

is no amnesia, individually or collectively,

regarding the events of March 11 and the

ensuing accident at Fukushima.”

Given the turmoil that has characterized

the NRC in recent months, including pub-

lic complaints by the other commission-

ers about Jaczko’s allegedly authoritarian

and temperamental management style, the

meeting was calm, not confrontational.

Svinicki, frequently Jaczko’s chief adver-

sary, congratulated him on the “orderly

manner” he displayed leading the years-

long Vogtle proceeding.

Fukushima Not ForgottenAll five of the NRC members appear to un-

derstand the significance of the challenge

brought by the March 11, 2011, destruction

of the Fukushima Daiichi nuclear power

station in Japan. It was a $40 billion act of

a capricious nature, reminding everyone in

the power industry that “low probability”

decidedly does not mean “no probability.”

The specter of Fukushima was clearly part

of the backdrop, from Jaczko’s opening ad-

dress at the Platts meeting to the vote at the

commission to the final Platts session the

following morning.

But it is not just a terrible accident in

Japan that has tempered optimism in the

nuclear business, despite the positive

boost from the landmark Vogtle vote. The

context for the nuclear industry today in-

cludes low growth in electricity demand,

record and sustained low natural gas pric-

es, uncertainty about nuclear waste, public

policy preferences for renewable electric-

ity generation, and an economy that may

or may not be recovering from the worst


NUCLEAR POWER

Fukushima: The Death of Nuclear Power in Japan?On March 11, 2011, a massive earthquake and

an enormous 45-foot-high battering ram of

water utterly destroyed three of the six General

Electric boiling water reactors (BWRs) sharing

a site in Japan’s Fukushima prefecture on the

island nation’s west coast. The horrific, totally

unexpected events produced vivid images of

the plants literally blowing apart in conse-

quence of the temblor and tsunami. They may

also have spelled the end of atomic energy in

Japan (Figure 3).

Unlike the 1986 Chernobyl explosion, the

world learned of Fukushima as it was occur-

ring, with blogs and tweets following the in-

timate details and stunning videos instantly

showing up on YouTube (for example, see

http://tinyurl.com/7ddka2r). The Japanese

government, despite its insular nature, is

still far more open than was the former So-

viet Union. And if Japan had been inclined to

cover up the events—and no doubt there were

those in industry and government who were so

inclined—modern technology rendered those

instincts anachronistic and futile.

Accident SummaryThe quake, the worst in Japan’s earthquake-

filled history, was far beyond the design ba-

sis of the six elderly GE boilers with (except

for Unit 6) outmoded lightbulb-and-donut

pressure suppression containments. The

accompanying liquid assault from the sea

produced one of the accident scenarios that

keep nuclear safety experts pacing the floor

at night. It’s known as “station blackout,”

the complete loss of on-site and off-site

electric power necessary to keep cooling

pumps and safety systems working during a

loss-of-coolant accident.

The Fukushima plants didn’t lack backup

power. As with all modern nuclear plants, banks

of large diesel generators—13 in all—were

available to kick in automatically should the

plant lose electricity from the grid. Backstop-

ping those were ranks of batteries designed to

provide enough standalone electricity to keep

the plants safe until engineers could link up

another source of power.

Hindsight, of course, often improves one’s

vision. Looking back on the accident from

a year‘s distance reveals that the backup

diesels were vulnerable to the tsunami’s ef-

fects, the batteries were inadequate for the

unimagined task they faced, and plant de-

signers did not adequately address the risks

of earthquake followed by a total inunda-

tion of immense force.

Unit 1 was the oldest of the Fukushima re-

actors, a 439-MW machine that went into com-

mercial service in 1971. Next door, Units 2 and

3 were both 760-MW reactors; Unit 2 began

generating electricity for the grid in 1974 and

Unit 3 in 1976. Units 4 and 5 were also 760-

MW BWRs; both began operating in 1978. The

1,067-MW Unit 6 went into service in 1979,

the year of the Three Mile Island accident in

the U.S. All were owned and operated by Tokyo

Electric Power Co., one of the largest, most so-

phisticated utilities in the world, colloquially

known as Tepco.

When the 9.0 magnitude earthquake hit at

14:46 Japan Standard Time (JST) on March 11,

2011, Units 1, 2, and 3 were operating nor-

mally. Unit 4 was shut down and held no fuel,

while 5 and 6 were out of service for mainte-

nance but were fully loaded with nuclear fuel.

As reconstructed by Tepco and Japan’s nuclear

regulators, the Nuclear and Industrial Safety

Agency (NISA), the three reactors scrammed,

or automatically shut down, as they should

have, when the earthquake hit. The plants lost

their normal sources of power as the earth-

quake damaged the regional electric grid. Each

unit had two back-up diesel generators, which

kicked on, as designed.

About 50 minutes later, the stupendous wall

of water hit the site, overwhelming the 19-foot

seawall the company had put in place when

the plant was designed and built to ward off a

projected 18-foot wave. Water swept over the

site, flooding the battery banks and emergency

diesel generators. It all went bad, very bad,

from that point on. The following chronology

follows a detailed timeline published in No-

vember by the U.S.-based Institute for Nuclear

Power Operations (Figure 4).

Accident TimelineTo condense the events considerably: All three

units lost core cooling. The residual heat in

the fuel resulted in a complete meltdown, lib-

erating explosive hydrogen in the process. The

hydrogen collected in the top of the reactor

buildings. The hydrogen mixed with oxygen

soon ignited and the units exploded, one af-

ter the other. Unit 1 was the first, at 15:36

JST March 12, as the sidewalls of the building

blew apart, leaving an eerie, skeletal steel hulk

standing. Some 4.5 hours later, the govern-

ment ordered the utility to use fire trucks to

pump seawater into the Unit 1 core in order to

cool the glowing mass of fuel.

Events at Unit 3 followed a similar pat-

tern. Loss of coolant exposed the core, which

melted. A steam-zirconium reaction liberated

hydrogen, which accumulated in the top of the

reactor building. At 11:01 JST on March 14,

Unit 3 exploded, a blast larger than that from

Unit 1 and one felt some 40 miles away. The

explosion injured six workers.

Around 6:00 JST March 15, workers heard a

“loud noise” from Unit 2, shortly after a hy-

drogen explosion in Unit 4. Workers thought

the noise from Unit 2 was also an explosion,

although later, experts decided it was not. But

the explosion in Unit 4 and the unknown event

in Unit 2 led to even greater radiation levels on

3. Earthquake and tsunami damage. This satellite image shows damage to the

Fukushima Daiichi Power Plant caused by an earthquake and tsunami. It was taken at 11:04

a.m. local time, March 13, 2011, 3 minutes after an explosion. Courtesy: DigitalGlobe


NUCLEAR POWER

contraction since “Happy Days Are Here

Again” made its debut in 1929.

Chip Pardee of Exelon Generation told

the Platts meeting that he recalled being

at similar events in 2007 when his job

was “to get up before a group of people

and talk about the advantages of nuclear

power.” That was an easy task at the time.

Today, five years later, he said, “It’s not

impossible, but it is more difficult.” Five

years ago, he noted, the talk was about the

security of nuclear plants in the face of ter-

rorist threats; today, it’s about nuclear ac-

cidents. Five years ago, the environmental

concern was greenhouse gases; today, it is

nuclear waste.

Westinghouse’s Jim Ferland comment-

ed that Fukushima “has pushed out ‘new

build’” as a current topic and moved it into

the future, although the NRC vote gave his

company a major victory.

The heart of the Vogtle project is the

Westinghouse AP1000 advanced reactor,

which won NRC approval Dec. 30, after

years of review and multiple redesigns.

Four projects using the AP1000 reactor—

the two approved in February and the two

planned for Scana Corp.’s application,

which will likely face the NRC next—are

on the stage in the U.S.; four are under

construction in China. “It would help a lot

if we can bring those in on schedule and

under budget,” Ferland said with ironic un-

derstatement.

Five years ago, the phrase “nuclear re-

naissance” was on the lips of many in the

industry, as the NRC geared up to license

as many as two dozen new units. Art Lem-

bo of URS recalled that one of the press-

ing questions then, “when we were on the

doorstep of renaissance,” was whether the

industry could find the skilled people it

needed to support that endeavor. Today,

those plant numbers have been dramatical-

ly reduced; meeting the demand for human

resources is no longer daunting.

Marvin Fertel, a realist who heads the

Nuclear Energy Institute, the industry’s

Washington lobby, told the Wall Street

Journal after the NRC Vogtle vote that

the Southern Co. plants in Georgia and

Scana’s planned South Carolina units are

probably the only new nuclear plants that

will get built in the U.S. before 2020. Ul-

timately, Fertel said he believes that the

prospects for nuclear power will rebound.

“The long-term fundamentals haven’t

changed,” he told the newspaper. One can

almost hear the words in his head: “Let us

sing a song of cheer again.” ■

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

MANAGING POWER.

site. Most workers on the site were evacuated,

leaving only 70 to deal with events at the reac-

tors. By this point it was abundantly clear that

radiation was not confined to the reactor site.

The Fukushima prefecture government on

March 11 ordered an evacuation of people

within 2 kilometers (km) of the plant, some

1,800 individuals. Within hours, the central

government expanded the evacuation zone to

3 km. By the next day the evacuation zone ex-

tended 20 km, then 30 km. By March 13, some

179,000 to 200,000 people had been ordered

to evacuate. Many may never be able to return

to their homes.

A cascade of failures characterized the ac-

cident, and Tepco spent much of the rest of

the year working to stabilize the site. Condi-

tions of intense radioactivity limited the time

workers could spend on and around the site.

Extensive damage made recovery and cleanup

difficult. It was months before the government

and Tepco acknowledged that the fuel had ac-

tually melted down.

This was similar to what occurred at Three

Mile Island, where the utility consistently

underestimated the damage to the reactor

fuel. Indeed, The Economist observed that

Fukushima was “a bit like three Three Mile

Islands in a row, with added damage in the

spent-fuel stores.”

Accident UpdateLast December, Japan declared that the Fuku-

shima nuclear reactor site was finally stable,

which could lead to the return of some 80,000

evacuees and allow the utility to begin dis-

mantling and decommissioning the wrecked

plant. But that claim may have been prema-

ture. Reuters reported in February that Tepco

had uncovered a leak of slightly radioactive

water inside the containment of Unit 4, which

was largely undamaged during the March ac-

cident. The 8 metric tons (8.5 cubic meters)

of leaked water did not get outside the reac-

tor and will be drained into storage, the wire

service reported.

Not long after that, Tepco reported that

temperatures in the crippled Unit 2 have been

rising, although they are still below the 93C

that defines “cold shutdown.” The rising tem-

peratures suggest the possibility of re-critical-

ity. Bloomberg quoted Tetsue Ito, head of the

Atomic Energy Research Institute at Kinki Uni-

versity, as saying, “It was too early to say the

plant is safe in December. They declared cold

shutdown even though nobody is sure about

the location of melted fuel.”

At its peak, Japan had 54 operating nuclear

units, supplying some 30% of the country’s

electricity. Japan had a reputation as one of

the safest, most careful nuclear power regimes

in the world.

At this writing, only three units are operat-

ing in Japan; those are scheduled to come out

of service soon. As you read this, Japan may

not be getting any power at all from its once-

proud, now-humbled nuclear enterprise. That

enterprise now faces intense opposition in a

country that justifiably has mixed emotions

about the power of the atom. Many observers

predict that none of Japan’s nuclear units will

ever operate again.

4. Complete devastation. An unmanned drone took this aerial photo of the Fukushima

Daiichi nuclear power plant on March 20, 2011. Unit 1 is at the top of the photo, Unit 4 is at the

bottom. Courtesy: Air Photo Service Co. Ltd., Japan


PLANT CONTROLS

Intelligent Control of FBC BoilersOptimizing combustion control is critical to reducing emissions and increasing

plant operating efficiency, particularly for fluidized bed combustion (FBC) boiler plants burning biomass fuel that has unpredictable moisture con-tent. The secret: measuring actual energy flow.

By Roger Leimbach, Metso Automation

Plant designers must differentiate solid

fuel combustion applications such

as fluidized bed combustion (FBC),

grate firing, and pulverized coal because

each requires unique control strategies. It

is also important to develop control strate-

gies for each application that are simple to

implement and support in the field. These

strategies should also be easy to understand

by plant staff, and equipment maintenance

should not require a high level of instrumen-

tation and control expertise.

The control system strategy employed

must also be compatible with the overall

boiler control system strategy, not be plat-

form restricted, and not be solely dependent

upon mass fuel flow to function properly. It is

our experience that the best performing con-

trols systems are based on the measurement

of actual energy flow, which is described in

more detail later in this article.

The boiler control strategy must also be ca-

pable of dynamic operation so that changing

load at maximum rate will not cause boiler

upsets or instability. This well-known strat-

egy uses the boiler output plus the derivative

of boiler drum pressure to predict the energy

required to change to the new load setpoint

(see “Drum Pressure the Key to Managing

Boiler Stored Energy” in the June 2007 issue

of POWER). Furthermore, a nonregenerative

feedforward signal should be used to deter-

mine the overall firing rate demand. The con-

trol system should be able to run in automatic

generation control (AGC) or continuously at

design load. AGC is important to all utilities

that have remotely dispatched plants, and it is

now expected to be an integral part of boiler

and turbine control systems. As one utility

engineer recently told me, “We won’t build

it if we can’t dispatch it.”

The sidebar describes two 100-MW

net biomass plants now under construc-

tion for which Metso supplied the boiler

island and integrated control system with

features described in this article. For more

information on FBC strategies when burn-

ing biomass, see the October 2010 article,

“FBC Control Strategies for Burning Bio-

mass” in the POWER archives at www

.powermag.com.

Conventional Boiler-Turbine CoordinationIn many industrial installations there are

multiple boilers supplying steam to a pro-

cess and/or steam turbines driving electric

generators. The turbines can be connected

to a steam network and operate in backpres-

sure mode or condensing mode. There are

as many different combinations as there are

plants. However, what is typically missing

is the coordination of the turbines and steam

hosts with the boilers. The need to balance

operation of the numerous boiler-turbine

configurations must also be addressed in any

robust industrial control system strategy.

The normal approach for a plant with

multiple steam turbines fed from a common

steam header that’s fed by one or more boil-

ers is to control the header pressure. In too

many cases, the turbines and pressure-reduc-

ing stations are operated in pressure mode

(sometimes called turbine follow mode). In

this case, each boiler’s fuel flow rate is con-

trolled to produce the necessary steam flow

and the steam header pressure is maintained

by the governor valves of each turbine.

The control strategy for this industrial sys-

tem is straightforward. The boiler demand

should be based upon steam header pressure

and a feedforward signal, which is divided

among the various boilers according to their

relative size and efficiency. The control sys-

tem should allow for manual bias by the op-

eration of individual boiler demands.

The nonregenerative feedforward should be

the primary control for the boiler. The pressure

control should provide minimal integral action.

Integral control should be used sparingly in the

boiler demand. The feedforward should not be

steam flow, as this is a regenerative feedforward

because regenerative feedforwards in the con-

trol system of a solid fuel–fired boiler tend to

drive the demand in the wrong direction when

an upset occurs or if fuel quality changes. In

other words, a boiler upset condition will cause

the pressure control to oppose the corrective

change in the boiler controls and cause further

upsets and destabilization (Figure 1).

Header pressure

Header pressure setpoint

Boiler constraints

Boiler A steam flow

Boiler B steam flow

Boiler N steam flow

Non-regenerative

energy demand

Boiler A energy flow

Boiler A participation

Boiler A airflow

Boiler B participation

Boiler N participation

Excess air correction

Boiler protection

Fuel controlAirflow control

Boiler optimizer

Boiler B demand

Boiler N demand

Secondary air participation

Primary air participation

Overfire air participation

Secondary air demand

Primary air demand

Overfire air demand

Boiler A fuel demand

1. Robust industrial boiler control strategy. An advanced boiler control in an indus-

trial configuration with the energy flow computation and boiler control system optimizer has the

ability to accurately control the output because it knows the input energy flow. Note that each

boiler on the header has a “participation algorithm,” which allows for apportioning the demand

according to its individual size, efficiency, and response. Also, the operator has the ability to

manually bias the firing rate of each boiler, if required. Source: Metso Automation


PLANT CONTROLS

FBC Boilers Are UniqueFBC boilers are used for a wide variety of

mostly industrial applications, with several

boilers working together on sophisticated steam

networks that have rapidly changing demand.

The boilers acting in parallel can also be un-

controlled, where the boiler steam production

is completely dependent upon the rate of waste

fuel supply, which may not be measurable.

FBC boilers also are likely to use relatively

hard-to-burn fuels such as combinations of

biofuels and waste coal, all of which will have

a wide range of possible fuel constituents and

moisture content. Biofuels are not necessarily

homogeneous; often they are a mixture of dif-

ferent fuels such as bark, forest cuttings, agri-

waste, and waste building materials. A typical

FBC will fire a wide range of solid fuels to

minimize overall plant fuel cost.

FBC boilers burning these fuels require a

much different approach to boiler control de-

sign. For example, the fluidized bed of sand

and ash within the furnace has a very large in-

ertia, limiting the dynamics of the boiler. On

the other hand, the large fluidized bed of sand

and ash enables the FBC boiler to burn up to

60% high-moisture-content fuels. While the

fuel properties may change quickly, the fuel

also burns relatively fast, even though there is

still a wide range in the fuels’ combustibility

(the time to evaporate the water, pyrolyze the

solid fuel, and complete combustion).

How quickly the combination of fuels is fed

into the FBC is the responsibility of the fuel

feed system controls, a critical function of the

overall combustion control system. The fuel

feed system must be capable of handling mul-

Heat balance

circulation

Fuel-handling

valve

Oxygen consumption calculation

Metered fuelFuel power

(Btu/hr)Fuel control

Steam temperature

control

Airflow control

+

+

x

+/–

2. Best of both worlds. Some combustion control designs use airflow (as a proxy for

oxygen flow) and an air/fuel ratio to estimate the energy entering a boiler—a process that is fast

but error-prone. Others measure the actual fuel consumed—a slow but accurate approach. In

combination, a much more accurate estimate of the energy entering the FBC boiler is possible.

The Fuel Power Compensator computes the energy input by measuring oxygen consumption

and mass balance. The result is used by the fuel control, airflow control, and steam temperature

control loops. Source: Metso Automation

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PLANT CONTROLS

tifuel combustion because the heating value and

bulk density of the individual fuels will vary

greatly. Even so, the total energy flow must be

maintained at a consistent rate to make sure

header steam pressure is maintained at setpoint

and energy flow out of the boiler is at required

demand. Changes in energy flow to the boiler

can cause fluctuations in combustion and steam

production. If not precisely controlled, these

fluctuations will reduce power generation and

can risk plant availability.

FBC boilers do not produce high levels of

emissions, such as SOx and NOx. However,

those that fire coal require limestone as an ad-

ditive to capture SOx. Limestone is expensive

to use and is an expense to overall operations

that can reach several million dollars each

year, depending upon the size of the boiler.

Because FBC boilers operate at lower temper-

atures, NOx production from an FBC boiler is

minimal, but if the bed temperature rises above

the NOx threshold, more ammonia is required

as a mediating additive. These emissions are

Two Fluidized Bed Boilers Under Construction in the U.S.Metso has sold a complete 100-MW net

biomass boiler island and plant automation

system to two wood biomass plants in the

U.S. Both projects are under construction

and will soon share the title of largest bio-

mass plants in the U.S.

Texas Wood Fires Future Record-HolderThe Nacogdoches Generating Facility is

owned and operated by Southern Power, a

subsidiary of Southern Co. Southern Pow-

er is among the largest wholesale energy

providers in the Southeast, meeting the

electricity needs of municipalities, electric

cooperatives, and investor-owned utilities.

Power from this new plant, located near

Sacul in Nacogdoches County, Texas, will be

sold to Austin Energy, the municipal utility

owned by the City of Austin, under a 20-

year contract (Figure 4).

The bubbling bed boiler is designed to burn

about one million tons of combustible forest

residue from the wooded areas of East Texas,

wood processing residues, and clean munici-

pal wood waste annually. The biomass fuel

will be sourced within a 75-mile radius of the

plant and will normally be delivered by truck.

The fuel-handling system consists of three

truck tippers, two sets of screens and hogs,

an automatic stacker/reclaimer system, and a

manual stacker/reclaimer system to maintain

two 15-day fuel storage piles.

Bubbling fluidized bed boilers are well-suit-

ed to burn high-moisture-content fuels such

as biomass and are generally simpler to op-

erate than a conventional solid fuel–burning

boiler, as the temperature of the 6-foot-deep

sand bed can be controlled through combus-

tion air staging. The boiler produces super-

heated steam that is used in a single steam

turbine with four stages of feedwater heating.

The steam turbine exhausts axially into the

condenser. A wet evaporative cooling tower

provides condenser cooling. The boiler gas

side is equipped with a baghouse for particu-

late matter control plus an aqueous ammonia

injection selective noncatalytic reduction sys-

tem for NOx control.

American Renewables handled develop-

ment and initial planning for the Nacogdo-

ches project and sold it to Southern Power

in 2009. Construction of the plant began in

2009; commercial service is scheduled to

begin later this summer.

Waste Wood Not Wasted by Florida PlantThe Gainesville Renewable Energy Center

(GREC) will supply electricity to Gainesville

(Fla.) Regional Utilities (the city-owned

utility) under a 30-year power purchase

agreement. As with the Nacogdoches Gen-

erating Facility, the boiler will use bubbling

fluidized bed technology and annually burn

about a million tons of waste wood from log-

ging and mills as well as urban wood waste

from clearing, tree trimming, and pallets—

all sourced from a 75-mile plant radius.

Gainesville Renewable Energy Center LLC

was developed by American Renewables.

Zachry Engineering Corp. is providing de-

sign engineering and procurement services

as part of the engineering, procurement,

and construction team. Fagen Inc. is the

construction contractor for both projects.

Commercial operation of this $500 million

Florida plant is scheduled for late 2013.

4. New title holder. When startup is

completed later this year, the 100-MW Na-

cogdoches Generating Facility will become

the largest biomass-fired power plant in the

U.S. Courtesy: Southern Power

3. Well-controlled Nordic biomass plant. The 240-MW Alholmens Kraft Power Sta-

tion is the largest biomass power plant in the world and burns a combination of coal and waste

biomass fuels. The plant uses the Fuel Power Compensator (FPC) to optimize FBC boiler per-

formance. In this recording, the operator is manually adding coal in 10% to 15% steps while

the fuel control is responding to the FPC and driving the biomass flow downward to maintain

constant energy output. Note how the steam flow remains unchanged during the fuel split

change. Source: Metso Automation

Steam flow

O2

Coal

BiomassCoal flow (0%–100%)

Steam flow (635,00 – 1.6 Mlb/hr)

O2 (1%–4%)

Biomass flow (50%–250%)

16-30-00 17-00-00 17-30-00 18-00-00


PLANT CONTROLS

all bed temperature–sensitive and require ex-

treme optimization to maintain low levels of

emissions. Thus, fuel control—without any

compensation for changes in moisture, com-

position, or heating value—is problematic.

How to Manage EnergyThe FBC is capable of multifuel operation

because the control strategy includes a com-

putation called the Fuel Power Compensator

(FPC). The FPC was developed for the world’s

largest biomass-fired boiler, Alholmens Kraft

Power Station, a 240-MW unit operating in

Finland since 2002. This unit can reliably burn

any combination of biomass and coal. Its bio-

mass is a combination of peat, bark, and wood

residue. Coal is the backup fuel.

The continuous measurement of oxygen

consumption by the actual fuel consumed and

the boiler energy balance calculations are the

essence of the FPC. Oxygen consumption is es-

timated by the excess air ratio and combustion

airflow. Both computations are required because

the energy balance calculation is based upon

averages and is relatively slow, but it is very ac-

curate. The oxygen consumption calculation is

relatively fast, often taking milliseconds, but it

has errors because of the transport delay from

combustion to oxygen measurement. Combin-

ing the two measurements provides an accurate

view of what is happening in the furnace in real

time (Figure 2).

The FPC has been used on many multifuel

boilers with excellent results. For example,

Figure 3 is a strip chart of several perfor-

mance parameters of the Alholmens biomass

plant, which uses the FPC algorithms.

Optimize FBC Boiler OperationThere are many different types of optimiza-

tion programs available that are based upon

model predictive control, fuzzy logic, and

neural networks. We suggest that you select

a technology that meets the control strategy

objectives of the plant, as discussed above.

The selection should mesh with the existing

control system and provide biases to set-

points in the control system. It should also be

capable of running on a PC or on the control

system controller. The best selection will use

standard and/or existing process instrumen-

tation in the plant, such as oxygen analyzers,

flow and pressure transmitters, and online

emission analyzers.

Figure 5 provides an overview of the basic

controls used on a typical FBC boiler. The

load is controlled by the steam demand in

the form of a non-regenerative feedforward

based upon steam flow, steam header pres-

sure, and steam header pressure setpoint.

These are incorporated in the boiler demand

calculation that includes dynamic compen-

sation, a requirement for AGC. While the

boiler integrates the difference between the

energy input and energy output of the boiler,

the pressure error is primarily only a pro-

portional process. The long FBC boiler time

constant does not permit pressure control to

operate as an integral control. The change in

boiler demand is due primarily to the change

in the feedforward. Other changes to boiler

demand result from fuel quality changes.

The most unique control loop associated

with a FBC boiler is the bed temperature.

The bed is composed of many tons of hot

sand and ash that is fluidized by primary air.

The fluidization process is very important to

the control of emissions and to minimizing

limestone consumption in a coal-fired FBC.

Furthermore, bed temperature is a function

of fuel quality and changing boiler load be-

cause it is a function of the thermal balance

of the bed. This is perfect for the application

of a fuzzy logic controller, which is outside

the scope of this article. Nevertheless, it can

be said that these advanced control functions

work extremely well in a biomass plant where

the fuel constituents and moisture content are

unpredictable (Figure 6). ■

—Roger Leimbach ([email protected]) is director of sales and mar-

keting for Metso Automation USA Inc.

5. Basic FBC boiler controls. This is a typical control strategy for an FBC boiler with a

gas recirculation fan. If a steam turbine is connected to the header, a more complex demand

computation involving the steam turbine first-stage pressure and steam flows is employed.

The biggest difference between this control system and that used in a conventional solid fuel–

burning plant is the bed temperature and fuel feed control loops. In this design, the fuel demand

signal goes to the fuel feeder control (11) and the airflow control (3), where excess air is used

to trim airflow demand to the secondary air control (6) and the primary control (7). The ratio of

secondary to primary air is set by the operator or the optimizer control (5). The induced draft fan

controls furnace pressure according to a feedforward from the airflow demand (8). Bed tem-

perature control is maintained by recirculating flue gas into the bed. The flue gas tends to slow

combustion and reduce the bed temperature. Source: Metso Automation

Non-regenerative feedforward pressure control dynamic compensation

x

÷

(1) (8)Furnace pressure control

Steam flow

Steam header

Drum

Superheater

Furnace waterwalls

FD fan

ID fan

Air heaterEconomizer

(3)Gas recirc. fan

(4)

Oxygen control

(6)

Sec. air control

(6)

Fuel control

(7)Fuel feeder

(10)

Primary air control

Primary air fan

Fuel power compensator

Bed temp. optimizer

(5)

6. Fuzzy logic the clear winner. The

objective of advanced bed temperature control

is stable bed temperature. In this FBC boiler

test, the average bed temperature recorded

during a one-week reference period (upper

line) is compared with the performance of the

same FBC during another one-week test pe-

riod, but running with advanced bed tempera-

ture control algorithms (lower line). Source:

Metso Automation

900850800750700650

900850800750700650

0 100 200 300 400 500 600 700 800 900 1000

0 100 200 300 400 500 600 700 800 900 1000

21.10.2003 06:00 - 28.10.2003 06:00 (samples: 600 s average)

6.11.2003 06:00 - 13.11.2003 06:00 (samples: 600 s average)


WATER MANAGEMENT

Promoting Sustainable Water Usage in Power GenerationGrowing concern about water usage by U.S. electric power generation is being

prompted by a number of factors, including projected increases in power demand due to population growth, competing uses for water, and recent drought conditions in various parts of the country. Our overview presents di-verse perspectives from industry experts about current and future challenges of balancing power generation needs with declining water availability.

By Angela Neville, JD

In our modern world, water and energy

production are inextricably connected.

The treatment and delivery of water

for human consumption and industrial pur-

poses require large amounts of electricity.

Conversely, many of the power generation

facilities that produce electricity—such as

coal-fired, solar thermal, and nuclear power

plants—use large amounts of water.

In most power plants, water is taken from

nearby water bodies—including oceans, riv-

ers, and lakes—and then returned to the wa-

ter source via a once-through (open loop)

cooling water system. The use of water in-

take cooling systems promotes maximum

capacity and efficiency for a given thermal or

nuclear power plant technology. The cooler

intake water enables power plants to operate

with lower vacuum pressures in the steam

turbine condensers, which, in turn, maximiz-

es the power extracted by the low-pressure

section of the steam turbines and provides

the highest possible fuel efficiency.

POWER has written extensively on the

need to develop more efficient cooling water

technologies. Examples (all available at www

.powermag.com) include “Appraising Our Fu-

ture Cooling Water Options” (June 2010), “De-

termining Carbon Capture and Sequestration’s

Water Demands” (March 2010), “Conserve

Water by Improving Cooling Tower Efficiency”

(January 2009), “New Coal Plant Technolo-

gies Will Demand More Water” (April 2008),

and “Costlier, Scarcer Supplies Dictate Making

Thermal Plants Less Thirsty” (January 2008).

In order to tackle this complicated topic

from a variety of viewpoints, in February,

POWER interviewed industry leaders from

an energy research institute, a leading na-

tional energy laboratory, a U.S. water and

energy technology manufacturer, and a large

consulting firm. From regulations to techni-

cal innovations, our experts offer insights

into trends concerning the interdependence

of water and power.

Water Availability Issues in Power Production“Water availability already is an issue across

the U.S., affecting nearly every region,” said

Kent Zammit, senior program manager of the

Environment–Water and Ecosystems Divi-

sion at the Electric Power Research Institute

(EPRI). “In addition to over-allocation, cli-

mate variability (including droughts) is caus-

ing regional shortages, as we have seen in

Texas, across the Southeast, and other areas.”

As existing power plants using a once-

through cooling process are retired, they

will likely be replaced by plants using closed

cycle cooling because of new fish protection

regulations, he explained. For wet cooling

systems (cooling towers), it is preferable to

use freshwater, but some installations are

now using degraded water sources. Others are

adopting dry cooling or hybrid cooling sys-

tems, but each of these has drawbacks, such

as higher capital costs, lower unit efficiency,

higher parasitic load (due to fan horsepower),

and additional maintenance.

Barbara Carney is the chemical engineer/

project manager of the Existing Plants Divi-

sion, Strategic Center for Coal at the U.S.

Department of Energy’s National Energy Tech-

nology Center, also known as the National

Energy Technology Laboratory (NETL). She

pointed out that increased concern for water

usage comes from, among other things, the ad-

dition of carbon capture technology on power

plants that requires increased water usage and

additional power generation capacity due to the

power loss associated with carbon capture. She

also noted that requirements of the Clean Wa-

ter Act 316(b) tend to result in decreased water

withdrawals (from, for example, once-through

cooling) but increased consumption (for exam-

ple, for evaporation from cooling towers). Her

center has initiated research in three main areas:

advanced cooling technologies, water reuse and

recovery, and use of nontraditional sources of

process and cooling water.

According to Heiner Markhoff, president

and CEO of water and process technolo-

gies for GE Power & Water, the current and

near-term challenges related to cooling re-

quirements of thermal power generation are

the amount of freshwater that is taken into a

cooling system and the volume and salinity

of water that is eventually discharged back

into the original waterway.

The problem related to salinity was also

mentioned by William Heins, general man-

ager of thermal evaporative technology in the

water and process technologies division of

GE Power & Water. “In a power plant, as you

cycle up the cooling water, it gets increas-

ingly concentrated with salt. If the cooling

tower blowdown is discharged back into the

river, then you are increasing the salinity, or

the salt content, of the river. Therefore, if you

can reduce or eliminate the water that you are

discharging back to the river, you have suc-

ceeded in lowering the amount of salt that re-

enters the river, thereby improving the water

quality,” he said.

Bill Kemp, vice president of Black & Ve-

atch’s management consulting division, fo-

cused on the impact of water scarcity on the

power generation sector. Increasing shortfalls

in water supplies could result in numerous

new restrictions or limitations on both ther-

mal and hydroelectric capacity. “We could

see new or additional restrictions on the sit-

ing of thermal plants, reduced hydroelectric

generation, and limited withdrawals from

rivers during the summer,” Kemp said. “In

periods of more serious drought, the physical

ability of major coal or nuclear power plants

to obtain sufficient cooling water could be

threatened. Generation operators are realiz-

ing this situation is not so far-fetched.”

Water Supply CompetitorsAgriculture is by far the largest consumer of

water, if one takes into account that a large

portion of the water used by power plants is


WATER MANAGEMENT

for once-through cooling that is returned to

its source water body, although at a slightly

elevated temperature, according to Zammit.

Other water-intensive sectors include mu-

nicipalities and industrial manufacturing.

U.S. Geological Survey data shows national

averages (Figures 1 and 2), but sector use can

vary dramatically from watershed to water-

shed.

There are many ways to address water

shortages as they occur, Zammit pointed

out. Each sector has options, and some sec-

tors have already begun to address water use.

For instance, agricultural irrigation practices

have improved dramatically. Municipalities

are now using treated sewage effluent for

irrigation and groundwater recharge. Power

companies are adopting water conserva-

tion technologies and using degraded water

sources such as effluent and mine water.

“In addition to the electric power genera-

tion sector in North America, two of the fast-

est growing sectors that GE focuses on for

wastewater reuse and recovery are the un-

conventional gas industry and the heavy oil

recovery industry,” Markhoff said.

The unconventional natural gas industry

and the heavy oil recovery industry are rap-

idly growing and are also related to the power

industry in that either natural gas or oil is be-

ing recovered. Both industries are fairly big

water users and are focusing on recovering

and reusing those waters to minimize the

amount of freshwater used and amount of

water that is discharged back into the water-

ways (Figure 3).

“The unconventional gas industry recov-

ers different forms of gas,” Heins said. “For

instance, in the Marcellus Shale in Pennsyl-

vania, there are fracking operations where

rock is fractured underground to allow gas

to come up and be recovered. This uncon-

ventional gas recovery uses a fair amount of

water.”

When the natural gas is captured from

these wells, the water used to fracture the rock

flows back with the gas. Heins explained. GE

has developed technologies—both mobile

technologies and fixed plants that treat and

reuse the wastewater—that have a number

of impacts (Figure 4). One benefit is using

a lot less freshwater; another is the need to

dispose of a lot less wastewater. In the past,

wastewater would be taken by truck over

long distances to be disposed of. “For exam-

ple, in some instances, water would have to

be trucked from Pennsylvania to Ohio to be

disposed of via deep well injection,” Heins

said. “Therefore, by recovering and reusing a

lot more of that water, we minimize not only

the amount of water that is discharged, but

also the trucking of the water.”

Almost every sector that produces a prod-

uct or uses energy also requires water in one

form or another, said Ralph Eberts, executive

vice president of Black & Veatch’s global

water business. “Today, we see a growing

number of manufacturers and global brands

investigating how their respective operations

1. Domestic and industrial water withdrawals. A large portion of the wa-

ter used by power plants is for once-through

cooling, where cooling water is returned to

the source water body at a slightly elevated

temperature. Courtesy: EPRI

Irrigation; 39%

Power generation; 38%

Domestic; 13%

Industrial; 6%

Livestock; 2%

Mining; 1%

Commercial; 1%

2. Conspicuous consumption. Agri-

cultural irrigation is by far the largest consum-

er of freshwater in the U.S. In recent years,

however, the agricultural sector has improved

irrigation practices in order to cut down on wa-

ter use. Courtesy: EPRI

Irrigation; 82%

Domestic; 7%

Livestock; 3%

Mining; 1%

Power generation; 3%

Commercial; 1%Industrial; 3%

3. Recycling produced water. Grizzly Oil Sands selected GE’s water evaporation tech-

nology for its Algar Lake project near Fort McMurray, Alberta, Canada. By using GE’s water

evaporation process, the company expects to recycle up to 97% of the produced water from

the bitumen production project. Courtesy: General Electric

4. Have evaporator, will travel. The

GE mobile evaporator is a 50-gallons-per-

minute, truck-mounted, mechanical vapor re-

compression system. It is designed to enable

on-site frack water recycling, reducing the

volume of wastewater and freshwater that

needs to be hauled to and from natural gas

production sites. The mobile evaporator will

enable natural gas producers to significantly

decrease their transportation and water dis-

posal costs. Courtesy: General Electric


WATER MANAGEMENT

can become water-neutral. The recent winner

of the Stockholm Water Prize for Industry

was Nestle. This is a company that has real-

ized that water represents a significant cost

and a significant limitation to its operations

and as a company has become more consci-

entious in its use of water,” Eberts said.

Discharge Constraints Due to New Regulations The U.S. Environmental Protection Agency

(EPA) is in the process of revising effluent

guidelines for steam electric plants under the

Clean Water Act, Zammit explained. The fo-

cus to date has been on flue gas desulfuriza-

tion system wastewater.

“In addition, stricter water quality criteria

and new Total Maximum Daily Load stan-

dards are providing new challenges for the

removal of trace metals and other constitu-

ents from wastewater,” Zammit said.

Some regulators are also writing in strict-

er limits for National Pollution Discharge

Elimination System permits around thermal

discharge for once-through cooling. Zammit

emphasized that “all of these rules are creat-

ing more constraints on the operation of ex-

isting and new power plants and also creating

difficulties with the retrofit of required air

quality control equipment in cases where it

impacts wastewater quality.”

“Many power plants, especially in the

southwestern United States, have turned to

zero–liquid discharge technology, which

means you are recovering and reusing 100%

of the wastewater and discharging nothing,”

Heins said. “With the zero–liquid discharge

process, the wastewater is recovered and re-

used, usually with an evaporation or a distil-

lation process.”

Regulations that limit or eliminate the use

of water intake cooling systems are likely

to require power plant owners to install

less-effective cooling systems or shut down

their plants, Heins said. Assuming the power

plant’s remaining usable life and other eco-

nomic and physical space factors support the

investment in a new cooling system, the total

power plant capacity and efficiency will be

reduced. Heins asserted that “this reduced

capacity and efficiency would require more

fuel to be consumed to generate an equiva-

lent amount of electricity, resulting in in-

creased generation costs, and in the case of

fossil generation, increased emissions of

greenhouse gases and other pollutants.”

Markhoff added that with a broad program

of eliminating water intake cooling systems,

the resulting reduction of total plant capaci-

ties would require a corresponding invest-

ment in new plant capacity.

“Making predictions regarding the type

and magnitude of this ‘replacement’ plant ca-

pacity would not be prudent,” Markhoff said.

“However, most plants that use water intake

cooling systems operate at high capacity fac-

tors, implying that intermittent sources such

as renewables may not meet grid operation

requirements, and higher–capacity factor

generation may be more suitable.”

Andy Byers, associate vice president of

Black & Veatch’s global energy business,

pointed out that individual states are setting

more and more stringent water quality stan-

dards for streams and lakes, which often cre-

ate challenges for thermal power plants that

discharge effluents to these water bodies.

Because many plant processes may result in

not only adding, but also concentrating, pol-

lutants already present in the water supply

before returning them to the regulated wa-

ter body, power plant effluents often cannot

meet the new water quality limits without

further treatment.

“In some cases, the additional treatment

to meet these in-stream standards may be so

challenging or costly that plants may chose

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WATER MANAGEMENT

to install a zero–liquid discharge system

where most all of the wastewater is reused,

consumed, and/or evaporated on-site,” By-

ers said. “While this serves to maintain the

stream’s water quality, it also reduces its

flow, and therefore may be counterproductive

to addressing other water scarcity issues.”

The EPA is expected to finalize its pro-

posed new cooling water intake rulemaking

for existing facilities by July 2012, Byers

explained. Because the cooling water intake

flow applicability threshold was dropped to 2

million gallons per day, this rule as proposed

will regulate not only power plants with once-

through cooling but also some with closed

cycle cooling tower systems. Depending upon

the final requirements, many power plants

may be able to achieve compliance by upgrad-

ing their intake design and operations to mini-

mize impacts to fish and aquatic species.

“The final regulations, however, may

force some plants to convert from once-

through cooling to closed cycle cooling tow-

ers, which, in addition to being costly, will

also result in a reduction of plant efficiency

and power output,” Byers said.

Before the EPA released its proposed rule

in March 2011, many analysts who had as-

sumed the rule would require all power plants

with once-through cooling systems to convert

to closed loop cooling towers forecasted that

the associated costs would force a significant

number of plants to shut down entirely. Byers

pointed out that “while the rule as currently

proposed may still (alone or in conjunction

with other EPA regulatory drivers) induce

some plants to retire, the proposed rule’s re-

quirements provide more options for contin-

ued operation, and in any event, the five-year

phase-in period for compliance, would not

force those decisions until closer to the end

of the current decade.”

Trends in the Power Sector’s Water UsageZammit explained that water resources vary

“dramatically from watershed to watershed,

depending on current uses, allocation (over-

allocation), changes in land use and runoff,

overdraw of groundwater aquifers, and the

aforementioned climate changes.”

Although EPRI has water management

risk analysis tools that can be used to exam-

ine sector water requirements, sustainability

goals, and conservation options for a given

watershed, it is difficult to predict what im-

pacts will be related to each sector. For in-

stance, much of the new power generation

in the arid Southwest has been natural gas

combined cycle units with air cooling, which

reduces utility water use per net megawatt-

hour. Zammit added that “this trend is ex-

pected to continue with lower natural gas

prices. Also, wind and solar photovoltaic are

playing roles in reducing power sector water

use. Municipal demands are growing, but so

is effluent reuse” (Figures 5 and 6).

Developing Generation Technologies That Conserve WaterNETL’s advanced cooling technology projects

are attempting to increase the efficiency of

cooling processes, including using less water

and making dry cooling less power intensive.

Carney pointed out that “water recovery from

power plants has been most successful in con-

densing the water from the flue gas and not

only capturing this water but also capturing

some of the energy lost with the water and

putting it back into the power cycle.”

Traditionally, power plants are located

next to large rivers, and water is withdrawn

as needed for cooling, Carney said. Newer

sources of water are reclaimed wastewater,

underground mine pool water, produced wa-

ter from oil and natural gas production, and

other sources that may need treatment prior

70,000

60,000

50,000

40,000

30,000

20,000

10,000

01950 1960 1970 1980 1990 2000

Wa

ter

use

(g

all

on

s/M

Wh

)

5. Cutting water use in power generation. New technological developments in

power generation are helping to reduce water use. For example, much of the new power gen-

eration in the arid Southwest has been from natural gas combined cycle units with air cooling,

which reduces utility water use per net MWh. Courtesy: EPRI

Boiler makeup Scrubbing Ash handling Inlet air cooling

CT injection Fuel processing Cooling

900

800

700

600

500

400

300

200

100

0Nuclear Coal Oil Gas Simple

CTCombined

cycleIGCC Solar

thermalSolar PV Wind Biofuel

Wa

ter

use

(g

all

on

s/M

Wh

)

6. A range of water footprints. Water use varies widely among the different power

plant types. For example, nuclear power generation is the most water-intensive, while solar

photovoltaic and wind energy use no water to generate electricity. Analysis assumes closed

cycle wet cooling towers are used. Courtesy: EPRI


WATER MANAGEMENT

to usage. Many projects have inventoried

these sources, tested the waters, investigated

impediments to use, and explored treatment

methods to increase usage.

“Alternative water sources continue to re-

place freshwater usage for cooling for power

plants, and this is probably the biggest trend

in water management in the power sector,”

Carney said. “Although no specific projects

can be cited, it is likely that many of the

NETL projects on alternative sources have

assisted in this implementation.”

For example, Nalco Co., working with

NETL, recently completed testing of a proto-

type electrodeionization (EDI)/scale inhibi-

tor that would allow more alternative water

sources to be used. Carney pointed out that

“although the EDI process is not commercial-

ized yet, they did have improvements to scale

inhibitors for calcite, gypsum, and silica that

will be used at power plants.”

Another successful technology, not yet

used commercially, is a flue gas drying pro-

cess that was demonstrated at the pilot scale

by Lehigh University, Carney said. The con-

densing heat exchangers dealt with the acid

environment in the flue gas, and calculations

show that they are cost-effective when the

recovered heat is used to preheat boiler feed-

water. The recovered water could be used to

replace 10% to 33% of required cooling wa-

ter. The process may also be used to dry flue

gas for carbon capture applications.

Another recent NETL project Carney

mentioned is the prototype Air2Air Water

Conservation Cooling Tower that was con-

structed by SPX Cooling Technologies at the

San Juan Generating Station in New Mexico

(Figure 7). It was tested from 2008 through

2009 and provided cooling for 35 MW of

power production.

The tower saved 18.5% of the water lost in

cooling at this location with no degradation

of thermal performance on the condenser and

no freezing problems. Carney said, “depend-

ing on climate, this technology could save

10% to 25% of the water lost to evaporation

from cooling towers.”

The commercial product arising from this

work is called the ClearSky Plume Abatement

Tower; it can be viewed at www.spxclearsky

.com. Carney pointed out that, although the

technology is currently marketed as plume

abatement, some customers are interested in

it due to the water savings.

Although not a part of this prototype tower,

it is possible to collect the water that is con-

densed, which is very clean and nearly pure,

resulting in an inexpensive, low-energy water

treatment method, Carney explained. With the

technology’s current configuration, the water

just flows back into the tower and replaces

withdrawals and decreases the amount of salty

blowdown water that needs to be discharged.

Additional improvements to Air2Air Technol-

ogy will be finished in 2012.

“Currently, NETL is receiving no funding

for power plant water issues,” Carney said.

“Funding for thermoelectric power plant cool-

ing/water management was discontinued in

2009, and the remaining projects will wrap

up shortly. The research focus for the Existing

Plants Program has shifted to carbon capture.

There is some research now in the carbon se-

questration program for water usage.”

New Initiatives to Promote Sustainable Water UsageRecently, the U.S. government made some

moves nationally to deal with water scar-

city, and state governments also have taken

action, especially in arid areas and those

that are most heavily affected by freshwater

shortages, Markhoff said. Areas such as the

Southwest, including California, currently

have very serious demands on their water

supplies and have already taken measures to

require zero liquid discharge at power plants.

He emphasized: “As the dynamics change

throughout the rest of the country in the

coming years, however, we expect eventual

changes in policy and more stringent require-

ments to appear in other states as well.”

Technology solutions exist to overcome

challenges related to water scarcity, according

to Kemp. The key challenge is economics and

understanding what solution will best balance

water, economics, and environmental factors

for a specific plant in a specific location. Op-

tions include air cooling technology, similar to

what was deployed by Pacific Gas & Electric

for its Gateway Generating Station in Anti-

och, Calif. The Gateway plant’s dry cooling

technology uses 97% less water and produces

96% less discharge than a conventional water

cooling system and avoids the use of river wa-

ter. Kemp added that hybrid systems that use

a combination of dry and wet cooling are an-

other technology option.

“There is no free lunch, however,” Kemp

said. “The cooling technologies that use less

water are more expensive to install, reduce

the performance efficiency of the generating

technology, and end up increasing fuel con-

sumption and greenhouse gas emissions per

MWh generated.”

An area of potential growth in the U.S. is

the use of recycled or reclaimed water. Kemp

pointed out that “this is used in other parts

of the world, particularly Singapore, with tre-

mendous success. The Calpine power genera-

tion station in Mankato, Minn. is also a good

example of the benefits of using recycled wa-

ter for cooling thermal power stations.”

Eberts also has some strong opinions

about what future steps need to be taken in

the U.S. to deal with increasing challenges

related to water availability. “First and fore-

most, we must increase education and aware-

ness about the true value of water,” he said.

“We need to start making positive steps to-

ward cost recovery for water treatment and

water transmission infrastructure and not be

reliant on subsidies that are reliant on pub-

lic will. We need to continue to invest in our

water infrastructure. History shows us that it

is better to plan, maintain, and invest, rather

than wait until a crisis to act. Delaying and

deferring could result in paying two to three

times more for infrastructure than what it

would have cost under a reasonable and

planned schedule.”

Eberts said that state and federal govern-

ments need to recognize the value of water

and the need for investment in our country’s

buried infrastructure. He added that “state-to-

state regulations for water varies widely—we

need more consistency for water use when

siting power plants.”

Likewise, Byers pointed out that from an

environmental regulatory standpoint, the na-

tion as a whole would benefit from a more

coordinated and comprehensive national

policy that balances the goals of improving

water quality and stemming water scarcity.

7. A cool way to conserve water. The

prototype Air2Air Water Conservation Cooling

Tower that was constructed by SPX Cooling

Technologies at the San Juan Generating Sta-

tion in New Mexico in collaboration with the

National Energy Technology Laboratory is on

the left. It is larger and has no plume, as com-

pared with the existing cooling towers on the

right. It was tested from 2008 to 2009 and

provided cooling for 35 MW of power produc-

tion. The ambient temperature was 27F with

a relative humidity of 65% when this photo-

graph was taken. Source: National Energy

Technology Laboratory


WATER MANAGEMENT

Where technology may advance one goal,

economics may drive us in another direction.

The demand for energy and water will only

continue to grow with increasing population,

and the interdependency of energy and water

must be recognized in managing the future

of the U.S.

“The extent to which we can ensure suf-

ficient water remains available for appropri-

ate use in efficient energy production will

be essential to securing reliable delivery of

electricity, which in turn is critical to our

continued global economic prospects and in-

dividual well-being,” Byers said.

Long-Term Water Management ChallengesGiven the complexity of the water/energy in-

terdependence issue, it’s not surprising that

our experts had a variety of views about how

water scarcity problems will be addressed

over the next 25 years.

For example, Kemp pointed out that util-

ity leaders from across the country rated

water supply as the top environmental con-

cern in Black & Veatch’s “2011 Electric

Utility Industry Survey” (www.bv.com/

electricutilitytrends). Water effluent was also

among the top five environmental concerns.

Kemp emphasized that survey respondents

viewed water management as having the

greatest potential to significantly impact the

electric power industry in the near term. The

industry’s concerns about water supplies

have risen considerably over the past five

years during which the annual survey has

been administered.

“Water supply, water effluent, and water

management will all be primary areas of con-

cern and risk mitigation for the foreseeable

future for power and natural gas producers,”

Kemp said.

In contrast, other experts we spoke with

were optimistic that over the next 25 years,

through innovative technologies and sensible

governmental policies, the power industry

will be more successful in protecting our na-

tion’s water resources.

For example, Markhoff commented that

in the long term, the importance of mini-

mizing freshwater make-up and the impor-

tance of eliminating salty water or saline

water discharge back to those waterways

will become significantly more important,

even in areas that do not have significant

regulation today.

“In the next 25 years, you will see an

increase in those trends and regulations to

minimize the amount of discharge and mini-

mize the amount of freshwater make-up,”

Markhoff said. “In the short term, it will be a

slow progression. However, the areas that are

the most affected, like the southwest United

States, already have a lot of those regulations

in place, and in the near term you will see

those trends continue.”

In a similar vein, Zammit emphasized that

“we are seeing this as a serious short-term

problem in some watersheds and isolated

regions of the country. But, as mentioned

before, as power generation is retired and

replaced with less-water-intensive genera-

tion technologies, we should see the electric

power industry decrease its water intensity

over the long term.”

In order to meet our future electricity

and water needs here in the U.S., we have

to begin planning now and determine what

investments we need to make in upgrading

our nation’s generation technologies and wa-

ter treatment infrastructure. Our public and

private entities must work together to suc-

cessfully create reliable, cost-effective, and

sustainable sources of energy and water that

help promote growth in the U.S economy. ■

—Angela Neville, JD, is POWER’s

senior editor.

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PLANT COOLING

Clever “Helper” Tower Solves Cooling Water DilemmaGone are the days when ocean or river water for once-through cooling of

a new power plant was assumed to be available. Today, more than 500 fossil-fueled and 38 nuclear plants use once-through cooling. However, regulators in several states are aggressively pushing what is essentially a ban on the use of once-through water cooling, forcing a conversion to closed-cycle cooling.

By Jeffrey S. Mallory PE, Sargent & Lundy

The availability of open-cycle cooling

water was usually the determining

factor when siting a new power plant

in years past. Along the coasts, seawater

was available; river water was favored else-

where. If a suitable river wasn’t available,

then a cooling lake was created. Technical

advances in cooling technology, often driv-

en by emerging regulatory requirements,

soon made historic cooling water sources

more problematic.

By the 1970s, new plants used large-scale

cooling towers for cooling a plant’s con-

denser. Today, plants that still rely on open-

cycle cooling are exploring how to make the

transition to closed cooling systems because

of tightening regulatory requirements with

respect to protecting aquatic life, reducing

the thermal discharge into the water, and con-

cerns about protecting water supplies.

This article focuses on evaluating power

plant thermal discharges. A previous article

presented many of the aquatic protection tech-

nologies available to plant owners to comply

with National Pollutant Discharge Elimina-

tion System (NPDES) permit requirements

(see “CWA 316(b) Update: Fish Guidance

and Protection” in the October 2011 issue or

in the archives at www.powermag.com).

Cooling Water TrendsThe responsibility for meeting Clean Water

Act (CWA) section 316(b) requirements to

protect aquatic life and manage thermal dis-

charges through technology-based solutions

is delegated to the states. The states manage

individual water discharges through the issu-

ance of NPDES permits.

The current trend concerning revisions in

NPDES permits requires reducing the amount

of thermal energy rejected or reducing the

cooling water outlet temperature, or both.

Short of reducing plant load, reducing the

thermal energy discharge is a euphemism for

converting all or part of the cooling water heat

rejection process from once-through cooling

to one of the many closed-cooling options.

The only other option is plant closure.

The challenge for designers asked to make

an assessment of the feasibility and eco-

nomics of a conversion from open to closed

cooling is that there is no one-size-fits-all so-

lution. Each plant presents a unique design

challenge. In fact, many plant owners have

received poor advice about cooling system

conversions, resulting in inaccurate cost esti-

mates, overly aggressive construction sched-

ules, and unrealistic operational expectations.

Additionally, plant owners often fail to con-

sider their plant’s unique design and opera-

tions features and are unaware of the many

new technology solutions now available.

Why Are Cooling Towers Added or Replaced?New cooling towers are added and existing

ones are replaced if the current cooling sys-

tem heat rejection capability is inadequate or

emerging regulatory requirements make the

conversion a requirement.

In California, for example, the State Water

Resources Control Board (SWRCB) adopted

“Water Quality Control Policy on the Use

of Coastal and Estuarine Waters for Power

Plant Cooling,” which became effective Oct.

1, 2010. The policy effectively requires all

19 of the state’s coastal plants (including two

nuclear plants) to transition to closed cool-

ing to meet the state’s best technology avail-

able requirement under CWA section 316(b).

Implementation plans prepared by fossil

plant owners were submitted to the SWRCB

on April 1, 2011, and implementation dates

are under negotiation. A “Scope of Work Re-

port” outlining consultant qualifications and

study requirements for the two nuclear plants

was completed on Nov. 7, 2011. Selection of

the consulting engineering companies to per-

form the studies is pending (Figure 1).

1. Cooling system conversions. California’s San Onofre (pictured) and Diablo Canyon

nuclear power plants have been tasked with evaluating technologies and strategies to comply

with Clean Water Act section 316(b) best technology available requirements, including the op-

tion of switching from an open cooling system to a closed or dry cooling system, among many

other requirements. Source: Southern California Edison/Nuclear Regulatory Commission


PLANT COOLING

Noncoastal regions appear to be more

concerned with reducing the thermal load

placed on a river (million Btu/hr) and

the temperature of the cooling water dis-

charge. A good example of a plant that

has made a conversion is PPL’s Brunner

Island plant, located in York County, Penn.

The owners of the three-unit, 1,546-MW

plant invested approximately $100 million

to install perhaps the largest forced-draft

cooling towers in the world to reduce the

thermal loading and discharge temperature

to the Susquehanna River. The new cool-

ing towers began operation in April 2010

(Figure 2).

Before You Make the SwitchA feasibility study for a potential once-

through cooling system conversion to a

closed system in order to reduce cooling

water discharge temperature and thermal

load begins with asking questions de-

signed to help develop an understanding

of the actual condenser heat exchange re-

quirements and the current state of repair

of plant equipment. It makes no sense to

add new equipment until all the possible

plant performance has been extracted from

existing equipment.

Other questions will help determine

if the existing cooling water system per-

formance is marginal or if it has any sur-

plus capacity. If a cooling water system

has been the victim of inadequate main-

tenance, then a renovation may be cost-

effective because a smaller cooling tower

or a less-complicated solution may be all

that is needed. What about the condition

of the steam turbine? A steam turbine up-

grade or overhaul may reduce the thermal

duty on the cooling water system, improve

steam turbine reliability, and produce a net

increase in plant efficiency, avoiding ad-

ditional major plant cooling water system

modifications.

Many other questions must be answered

before the true condition of a plant’s cooling

water system can be determined and repairs

or upgrades can be recommended. Other ar-

eas of the existing plant must be explored for

degradation of the existing cooling water sys-

tem caused by:

■ Intake system fouling (intake screens, in-

take area silt deposition, and mechanical

equipment degradation).

■ Fouling and pluggage of cooling water

system pipelines.

■ Cooling water pump performance deg-

radation.

■ Condenser tube fouling, failure, and

pluggage.

■ Chemical treatment regimens that are

limited due to direct discharge to a body

of water.

■ Steam turbine blade erosion or copper

plating of blades (resulting in higher cool-

ing system heat load).

■ Impact on the cost of operations and

maintenance.

Some facilities that already have a closed

cooling water system are also being asked

to reduce thermal loading and cooling water

discharge temperatures. If your plant falls

into that category, then you must also explore

other potential sources of system degradation

and repairs required before identifying new

system upgrades. Sources of degradation of

existing cooling towers include:

■ Cooling tower fill fouling (including bio-

fouling, scaling, improper spray patterns,

trash, or silt pluggage).

■ Regular tower structural or piping-related

failures due to age, biological, and chemi-

cal attack on members.

■ Operation at high cycles of concentration

resulting in material failures, large mineral

deposits, and the like.

■ Legacy issues such as cooling towers

that never met original performance

guarantees.

■ Lack of discipline in circulating water

chemistry treatment or insufficient make-

up water pretreatment.

■ Repeating failures of unreliable components.

Finally, in addition to the previously men-

tioned issues, the engineering analysis must

consider several additional factors, such as:

■ Several (10 or more) years of historic

weather datasets for the site to allow pro-

jection of cooling tower performance. This

may be provided from site records or from

nearby data collection sites.

■ Historic station data on cooling system

performance and/or performance tests of

towers, circulating water pumps, condens-

ers, and steam turbine(s).

■ Recent evaluations of current cooling sys-

tem performance.

■ Plant operability limitations (such as tur-

bine backpressure limits, vacuum system

capability, and water usage restrictions).

■ Project financial inputs (including re-

quired return on investment and financing

interest rates).

■ Value of electrical power, preferably on a

monthly basis.

Over the years, we have seen utilities pro-

ceed directly with a new cooling tower project

without a thorough analysis that considered

2. Cooling tower retrofit completed. PPL’s Brunner Island power plant added forced-

draft cooling towers to reduce the thermal loading and discharge temperature of the cooling

water discharge to the Susquehanna River. The 34-cell cooling tower requires four 3,500-hp

pumps to deliver about half a million gallons every minute. The cooling towers are used during

the nine warmest months of the year, from March through November. Courtesy: PPL


PLANT COOLING

all these factors. The resulting projects were

initiated without understanding their true cost

and scope. By not first repairing or upgrad-

ing existing infrastructure, these plants didn’t

operate optimally after the modification. The

inevitable result of adding much new equip-

ment was an overly expensive closed cooling

water system that was suboptimized for its

intended purpose.

A proper evaluation will present several

feasible approaches from which the owner

may select one that will optimize perfor-

mance of the overall plant. Plant-specific

factors must also be addressed in the anal-

ysis, such as specific limitations imposed

by regulators, constructability issues re-

lated to plant site constraints, different

contracting options, and economic factors

peculiar to the project.

Project Case StudyA series of engineering studies was recently

completed for a four-unit coal-fired station

with once-through cooling provided by an

adjacent river. This plant exemplifies the

complicated nature of once-through cooling

system conversions. The units are small, each

less than 200 MW, and total plant capacity

is just over 600 MW. (We are intentionally

40,000

35,000

30,000

25,000

20,000

15,000

10,000

5,000

0

100

90

80

70

60

50

40

30

20

10

0

1 2 3 4 5 6 7 8 9 10 11 12Month

Th

erm

al

dis

ch

arg

e (

MB

tu/d

ay)

Tem

pe

ratu

re (

F)

Thermal discharge limit Units 1&2 thermal load River temp. limit

3. Heat-limited plant. Owners of a four-unit, approximately 600-MW plant using once-through

cooling were evaluating the potential requirement to reduce both the plant’s cooling water discharge

temperature and thermal discharge limit to a river, in million Btu/day. Shown in orange is the proposed

maximum allowable thermal load to be applied to all four units. Shown in dark blue is the typical

thermal load from only Units 1 and 2 at full power. Note how the thermal load from only two units ex-

ceeds the proposed limit during the entire year, except for part of May. Also included is the anticipated

downstream river temperature limitation for the station. Plant operation has resulted in downstream

river temperatures up to 120F in the past. Source: Sargent & Lundy

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PLANT COOLING

vague on the plant description to keep the

plant anonymous.) The river is compara-

tively small and experiences periods of low

flow and high natural temperatures that have

severely limited plant generation capability

in the past.

The customer was facing extensive loss

of station power production when com-

plying with thermal load and discharge

temperature restrictions anticipated in

the plant’s new water discharge permit.

Different consultants conducted several

studies in the past to find ways to allevi-

ate the derating problems; however, none

of the recommendations had been en-

acted. One engineering study considered

limiting plant operations to comply with

downstream river temperature limitations

by shutting down Unit 3, an unacceptable

alternative. In addition to the limit on river

temperature, the customer was faced with

a potential limit on thermal discharges af-

fecting the entire plant (Figure 3).

Our first study of this plant’s cooling

water system options assumed that a river

discharge temperature limit and a thermal

discharge limit were to be imposed on the

plant. The worst-case thermal discharge limit

was identified to evaluate future operation of

the units. As can be seen in Figure 3, the only

option without installation of helper cooling

capacity was to maximize power generation

(in this case, from only Units 1 and 2) up to

the thermal discharge limitation (Table 1).

Operation of other combinations of units is

also possible.

A second (separate) engineering evalu-

ation was subsequently conducted based

on a different set of proposed limits of

river water temperatures. We examined

historic plant operating data as a means to

develop a mathematical relationship that

would allow us to predict maximum allow-

able generation based on river flow rate,

upstream river temperature, and permit-

ted downstream river temperature. With

these empirical relationships determined,

the theoretical maximum generation was

calculated (Table 2) assuming a maximum

cooling water exit temperature of 109F or

120F while meeting the maximum down-

stream river temperatures shown in Fig-

ure 3 (Table 2). Downstream river water

temperatures were not evaluated for the

months of January through April, Novem-

ber, and December due to the minimal

predicted generation losses during these

months.

Reducing plant load to decrease down-

stream river water temperatures is the least

capital-intensive but perhaps the most un-

economic option. However, there are other

technical options that allow the plant to

operate unfettered by river water tempera-

tures that may have much improved over-

all economics.

The obvious option is converting the

once-through cooling water system to a

closed cooling water system using one of

the many cooling tower technology options.

Other less-obvious options are bypass of

cold river water around the plant, mechan-

ical chilling of the discharge stream, spray

modules in the river, and smaller, “helper”

cooling tower cells or modules.

In this particular analysis, the econom-

ics leaned toward a closed-cycle cooling

conversion. However, an analysis using a

helper cooling tower (a tower that operates

in parallel with the once-through cooling

system when required to maintain the re-

quired river water temperature) showed

economic promise (Figure 4). A plant de-

Period Units 1 and 2 average load Units 1 and 2 average MW Generation (MWh)

Jan. 1–31 33.70% 86.95 64,690

Feb. 1–28 36.76% 94.85 63,741

Mar. 1–31 88.85% 229.23 170,546

Apr. 1–15 96.51% 248.99 89,636

Apr. 16–30 96.51% 248.99 89,636

May 1–15 64.34% 165.99 59,757

May 16–31 100.00% 258.00 99,072

June 1–15 79.66% 205.51 73,985

June 16–30 79.66% 205.51 73,985

July 1–31 41.36% 106.71 79,392

Aug. 1–15 38.30% 98.81 35,570

Aug. 16–31 38.30% 98.81 37,941

Sept. 1–15 30.64% 79.04 28,456

Sept. 16–30 30.64% 79.04 28,456

Oct. 1–15 30.64% 79.04 28,456

Oct. 16–31 30.64% 79.04 30,353

Nov. 1–15 32.17% 83.00 29,879

Nov. 16-30 27.57% 71.14 25,610

Dec. 1–31 26.04% 67.19 49,988

Total 1159148

Average 132.32

Table 1. Thermally limited operation. By limiting the thermal energy rejection to a

river, and without any source of helper cooling, this plant would be forced to limit power gen-

eration by shutting down two of its four units and limiting operation during eight months. Many

other operating scenarios are possible with the four units. Source: Sargent & Lundy

Theoretical generation

at 120F discharge

temperature (MWh)

Theoretical generation

at 109F discharge

temperature (MWh)

Difference

(MWh)

Actual generation

(MWh)

May 481,368 481,368 0 246,819

June 430,993 346,137 84,856 280,331

July 390,034 261,245 128,789 328,175

Aug. 293,256 181,682 111,574 275,506

Sept. 282,573 181,880 100,693 251,984

Oct. 448,177 398,359 49,818 313,033

Total 2,326,401 1,850,671 475,730 1,695,848

Table 2. Temperature-limited operation. Downstream maximum river water tem-

perature limits will also require units to operate at part-load for about half the year but with no

operating limits anticipated during the remainder of the year. The amount of power generated is

a function of the average downstream river water temperature selected and the combination of

units selected to operate. Source: Sargent & Lundy


PLANT COOLING

rate analysis was performed to determine

the optimum number of cooling tower

cells required to produce a 109F and a

120F river water temperature downstream

of station discharge. When the discharge

requirement is 109F, adding more than

eight cooling tower cells (modules) pro-

vided negligible economic benefit.

Not surprising, the site layout did not

consider the future possibility of adding

a large cooling tower. Existing infrastruc-

ture was carefully considered to properly

locate the new cooling tower as well as

to minimize installed and operating costs.

Options for converting all four units, as

well as only two of the units, were also

investigated. The ultimate recommended

tower location was different than that sug-

gested by other consultants due to the po-

tential for icing of the switchyard. The new

location benefited from the ability to reuse

existing cooling water piping, although it

was directly adjacent to a busy haul road

and the coal pile.

After detailed discussions with tower

vendors, it was determined that as long as

a low clog-type tower fill was selected, the

amount of sludge to be removed during ba-

sin cleanings would increase, but the dusty

location would not otherwise affect tower

performance. Furthermore, plume abate-

ment was required due to the proximity of

the tower to a nearby bridge, which could

experience dangerous fogging and icing

from a tower plume.

The proper design point for the plume

abatement system was selected and the

corresponding additional cost was in-

cluded in the project budget. The customer

now has a solid plan ready to implement

should regulators add new river water ther-

mal discharge and/or temperature limits to

the plant’s NPDES permit in the future. ■

—Jeffrey S. Mallory, PE ([email protected]) is a project engineer I for

Sargent & Lundy.

4. Lend a helping hand. A “helper” cooling tower with perhaps eight cells was found

to be the best economic option for the case study plant if it must operate under a downstream

river water temperature limitation of 120F. Source: Sargent & Lundy

500,000

450,000

400,000

350,000

300,000

250,000

200,000

150,000

100,000

50,000

00

Lost

ge

ne

rati

on

(M

Wh

)

5 10 15

Number of rental cooling tower cells

Wind

Solar

Bioenergy

ocean

geothermal

WaSte to energy

hydro

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www.retech2012.comHosted by: Organized by:


INDUSTRY COMMUNICATION

POWER Gets SocialDo you have professional insights to share with others in the industry—or

questions for those with a particular expertise? Do you want to get news and information from POWER more than monthly or weekly? Then join POWER on these social media platforms.

By Dr. Gail Reitenbach

The tagline for POWER is “Business and

technology for the global generation in-

dustry.” These days, technologies in our

industry are becoming increasingly digital. In

the plant, you see digital tools everywhere,

from handheld monitoring devices to complete

digital control systems. Beyond the plant, the

entire electric system is slowly adding digital

information and communication technologies

all along the chain, from production through

transmission and distribution to consump-

tion—an updating process commonly referred

to by the shorthand term “smart grid.”

Social MediaCommunication, even social interaction, has

also gone digital, so POWER has entered the

social media realm. It’s just one more way

we provide valuable information to, and hear

from, our audience. If you use one or more

of the popular social media platforms, here’s

how you can join the POWER community.

Twitter. “Tweets,” as posts to this public

platform are known, are limited to 140 char-

acters. Anyone can see anyone else’s tweets,

but most users select a number of other users

to “follow” so those posts automatically show

up on their home page. It’s a good way to see

what others in a niche market or a broad in-

dustry are announcing and talking about. The

main POWER handle is @POWERmagazine.

You can also follow our gas technology editor,

Tom Overton, @thomas_overton. If we tweet

about something you like or find interesting,

retweet. We post from events we attend as well

as timely news items and reminders.

Facebook. Because Facebook allows lon-

ger posts than Twitter, it’s an easier place to

comment on stories or videos we link to, from

our own publications and other sources. When

you “Like” our Facebook fan page (facebook

.com/POWERmagazine), you can comment

on posts. However, unlike personal Facebook

pages, you cannot post directly to our wall.

Google+. This is one of the newest social

media platforms, but it shows some real prom-

ise for both individuals and businesses. The

Hangouts feature, for example, is a handy and

free videoconferencing tool. Add “POWER

magazine” (see Figure 1 screenshot) to your

Google+ circles and follow our posts so you

hear about any future Hangouts. We’re also

using Google+ for industry updates and re-

quests for information, but our use of this

platform is sure to evolve.

LinkedIn. This professional networking site

is home to thousands of groups for every in-

dustry and interest imaginable. POWER spon-

sors two: “POWER magazine” and “Women in

Power Generation.” These are “closed” groups,

so you must be a LinkedIn member to join. Col-

leagues in our media company who cover the

chemical engineering industry demonstrated

that a LinkedIn group can be a great way for

members to ask for advice, share best practices,

and generally develop a sense of a professional

community. (Remember to post job openings to

the Jobs tab and event promotions to the Promo-

tions tab rather than in the Discussions area.)

Though we try to cover the full spectrum

of issues in the global generation market-

place, we can’t cover it all, and we realize

that our audience is full of experts. These

LinkedIn groups are a great way for you to

contribute your expertise (but no sales pitch-

es, please). We hope you will join one or both

of our groups and use them to share your ex-

perience, insights, and sound advice.

Virtually SocialOur fleet of publications—POWER, POWER-

news, COAL POWER, MANAGING POWER,

and GAS POWER—is produced by a busy staff

of just five full-time editorial staff members.

That means we don’t have the bandwidth to re-

spond to or comment on all posts; however, we

do keep an eye and an ear on the social buzz.

When necessary, we will moderate and block

inappropriate posts, so please, keep all com-

ments professional; save anything else for your

personal social media pages.

Remember that you can still comment on in-

dividual stories by using the “Comment” feature

on all our stories online or by sending email to

[email protected]. That address reaches

all of the editors and is also the best address to

use for industry press announcements. Given

the volume of messages we receive daily, we

cannot respond to them individually. If some-

thing is of interest for a feature story, an editor

will follow up, and our marketing staff periodi-

cally posts selected press releases to that section

of powermag.com.

Social media can be a useful way to broaden

your professional network and share lessons

learned. It’s also faster and cheaper than real-

world interactions. However, there are some

in-person events you don’t want to miss. The

most important for our industry is the ELEC-

TRIC POWER Conference & Exhibition (pre-

sented by POWER’s parent company, TradeFair

Group, an Access Intelligence Company). This

year, ELECTRIC POWER will be held May

15–17 in Baltimore. We hope to see you there.

Until then, we’ll see you online! ■

—Dr. Gail Reitenbach is POWER’s managing editor.

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Jeffrey Rader. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 . . . . . . . . . 14

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Outotec . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 . . . . . . . . . 18

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Paharpur. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 . . . . . . . . . 12

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Prize Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 . . . . . . . . . 10

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Rentech Boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 2 . . . . . . . . . . 1

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Roberts & Schaefer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 . . . . . . . . . 17

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SMA-America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 . . . . . . . . . 16

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STF S.p.A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 . . . . . . . . . 21

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Tyco Flow Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 . . . . . . . . . . 3

www.tycoflowcontrol.com

URS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 . . . . . . . . . 11

www.urs.com

Westinghouse. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 . . . . . . . . . 19

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COMMENTARY

Natural Gas: Secure Supply for Today and the FutureBy Jim Johnson

Ten years ago, I could not have written this column. The natural gas industry was different—limited domestic supply resulted in unstable prices. However, recent advancements

in drilling technology have enabled the industry to discover, ac-cess, and produce abundant sources of natural gas in America. Because the industry has changed, the country’s energy future is now more secure. In the electric utility sector this increase in natural gas supply means less price volatility, and producers are now able and willing to enter into longer-term contracts, which minimize risk to utilities and, ultimately, ratepayers.

Overview of Today’s U.S. Gas ReservesSecure supply should be at the core of any conversation about fuel switching. With a dramatic supply shift in the past decade, it is important to understand the natural gas reserves picture as it stands today. At year-end 2010, the Potential Gas Committee es-timated the current available natural gas resource base as 1,898 trillion cubic feet (Tcf), with a future supply of 2,170 Tcf. This is an almost 70% increase from the committee’s 2000 forecast and the highest resource evaluation reported in the organization’s 46-year history. According to a North American Resource Devel-opment Study, the U.S. has enough natural gas supply to fuel our country for 100 years, even anticipating the highest potential demand. Due to this supply discovery, some industry experts call the U.S. the “Saudi Arabia of natural gas.”

Hydraulic fracturing, combined with horizontal drilling, has enabled the production of this abundant resource directly from “the kitchen” where natural gas is “cooked.” This technology contributes to an efficient drilling and completion process, al-lowing for targeted recoveries, controlled capital expenditures, and consistent well performance. Comparing the production of two recent shale discoveries provides a telling example of this efficiency. The Barnett Shale was discovered in the late 1990s, and its production spans 12 years. After eight years of production in the Fort Worth, Texas, area, the shale achieved its full produc-tion capacity, and production stabilized. Compare that with the Marcellus Shale, located in West Virginia, Pennsylvania, and New York, and discovered in late 2007. The Marcellus Shale reached the same degree of production growth in just four years, or half the time of the Barnett Shale. This efficiency, coupled with state-of-the-art technology utilized by Chesapeake Energy Corp. and others to pinpoint resource basins, allows for reliable production for the power generation sector.

The Beneits of Supply and Price StabilityEfficient production and proven supply work in tandem to stabilize prices. In early 2012, natural gas hovered at $2.50/MMBtu, a 10-year low. This low price is consistent with the in-dustry’s history since the advancements in drilling technology, as is modest price fluctuation. From January 2009 to January

2012, the Henry Hub price ranged between $3 and $6/MMBtu despite extreme weather conditions. This three-year time period included the summer of 2011, which had the highest demand for cooling needs on a power-generated basis, and last winter, which was the second-coldest in 10 years. This combination of hot summers and cold winters created one of the most robust energy demand periods ever recorded, yet natural gas prices re-main consistently low. In fact, the U.S. Energy Information Ad-ministration (EIA) projects natural gas prices will remain below $7/MMBtu until 2025.

While supply and price stability are benefits across all sectors, long-term contracts provide certainty for electric utilities. To-day, natural gas companies are willing to enter into longer-term contracts. As an example, Chesapeake Energy Marketing Inc. has contracts with terms up to 10 years covering the sales of natural gas under a variety of pricing structures.

Environmental and Efficiency AdvantagesFrom an operational standpoint, natural gas offers environmen-tal and efficiency advantages. Because it is a cleaner-burning fuel, natural gas allows electric generation facilities another op-tion for long-term environmental compliance. The fuel emits no mercury and fewer pollutants than other sources. Also, natural gas–fired generation is load-following and flexible, making it a natural choice for baseload power to accommodate the aggres-sive build-out of renewable generation across the county.

In 2010, the natural gas power plant fleet ran only about 28% of the time. Given the increased reserves of natural gas, the U.S. could systematically ramp up its natural gas fleet to a load factor of at least 50% over time. Using the average emissions charac-teristics of the coal fleet and gas fleet, and the most recent EIA data, this conversion would eliminate: more than 450 million tons of carbon dioxide (implicated in climate change concerns); more than 530,000 tons of nitrogen oxide (which exacerbates respiratory and heart diseases); more than 2.5 million tons of sulfur dioxide (the main ingredient of acid rain); thousands of tons of mercury (a toxic substance, and nonexistent in natural gas); and millions of tons of particulates.

As our population grows, technology expands, and power needs increase, the utility industry can meet demand with a re-source better for the bottom line and the environment. Electric power producers can have confidence in natural gas for baseload and peaking power as a source that can provide ancillary services to accommodate renewable generation, and as a resource with a stable price and enough supply to fuel America’s future. ■

—Jim Johnson ([email protected]) is president of Chesapeake Energy Marketing Inc., which provides natural gas marketing services including commodity price structuring, contract ad-

ministration, and nomination services for Chesapeake Energy and its partners.

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international april 2012

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