july 2016 international

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Vol. 160 • No. 7 • July 2016

New Ways to Address Environmental Issues

“Show Me” State Plant Wins PRBCUG Plant of the Year

Can Coal Refuse Be Environmentally Friendly?

New Reasons to Consider Waste-to-Energy

BUSINESS & TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRY SINCE 1882

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July 2016 | POWER www.powermag.com 1

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Established 1882 • Vol. 160 • No. 7 July 2016

SPEAKING OF POWER

Power’s Environmental Issues Then and Now 6

GLOBAL MONITOR

Rwanda’s Power Production Triumph over a “Killer Lake” 8

TVA Submits Pioneering Application for SMR Early Site Permit 9

THE BIG PICTURE: China’s Power Glut 10

China’s CAP1400 Clears IAEA Safety Assessment 12

One of the World’s Biggest Biomass-Fired CHP Plants Is Inaugurated 12

Employing Fuel Cells for Carbon Capture 13

POWER Digest 14

FOCUS ON O&M

Boiler Tube Failure Thermohydraulic Analysis 16

LEGAL & REGULATORY

Securing Pipeline Infrastructure for Gas-Fired Generation in New England 18By Glenn S. Benson and Walker Stanovsky, Davis Wright Tremaine

COVER FOCUS: ENVIRONMENTAL ISSUESGenerators Grapple with ELG Implementation 20

Early compliance with the Environmental Protection Agency’s Effluent Limita-

tion Guidelines (ELGs) for steam electric power generating units has raised

new equipment, monitoring, operational, and labor issues that are proving

challenging for some plants.

Evaluating the Use of CEMS for Accurate Heat Rate Monitoring and Reporting 24If the Clean Power Plan survives legal challenges, many plants will be looking

for cost-effective ways to monitor heat rate. Electric Power Research Institute

researchers explain what they’ve learned about using continuous emissions

monitoring systems (CEMS) for just that purpose.

Simplify MATS Compliance with Particulate Matter Continuous Emission Monitors 27 Four years into the Mercury and Air Toxics Standards (MATS) compliance era,

enough historic data and improved monitors exist to potentially change the

particulate matter (PM) compliance strategy to one that uses a PM monitor

instead of quarterly PM stack testing.

Emissions Catalyst Issues for Fast-Start Combined Cycle Power Plants 31Among the less-familiar consequences of frequent and faster starts at com-

bined cycle plants are challenges associated with fast start of the emissions

catalyst systems, especially given that best available control technology limits

required by regulations are not practical where cycling occurs.

Circulating Fluidized Bed Dry Scrubber Effectively Reduces Emissions 34By taking an unconventional route, a small Midwest generator is meeting

emissions requirements and enjoying one of this industry’s top-performing

retrofit units for SO2 reduction.

8

34

12

ON THE COVEROpened in 1974 on the Navajo Nation,

the 2,250-MW Navajo Generating Sta-

tion burns Powder River Basin coal to

serve electric customers in Arizona, Ne-

vada, and California. It is operated by Salt

River Project. Courtesy: Gail Reitenbach

www.powermag.com POWER | July 20162

Real-Time Environmental Data Integration Improves Air Quality Reporting 37As with so many other plant functions these days, greater operational com-

plexity in the environmental regulatory compliance realm requires new ways

of working. Real-time data integration and management can offer multiple

benefits.

Weighing the Environmental Impacts of Wind and Solar 40Even renewable energy technologies have environmental impacts. As manu-

facturers and developers gain experience with wind and solar technologies,

they’re also working to minimize negative consequences.

Avoiding Wildlife Impacts From Renewable Energy in Europe 43Europe, which has a longer history than the rest of the world with renew-

ables—especially offshore wind and marine power projects—is also a leader

in determining how to minimize danger to creatures on land and in water.

SPECIAL REPORT: PRB COALPRB Coal Users’ Group Plant of the Year: Ameren’s Rush Island Energy

Center 52The Powder River Basin Coal Users’ Group gave its top award this year to a

plant recognized for innovation and implementation of “best practices and

best available technologies” for burning PRB coal.

FUELS

The Coal Refuse Dilemma: Burning Coal for Environmental Benefits 56Using waste coal—which has been piling up from hundreds of years of min-

ing—as a fuel can reduce the environmental damage these piles create, but

the low-grade feedstock still faces environmental and economic challenges.

Energy from Waste: Greenhouse Gas Winner or Pollution Loser? 59Power market economics in the U.S. have not been friendly to waste-to-en-

ergy plants, but new environmental data—as well as state and federal poli-

cies—could help spur new growth in the sector.

Understanding and Mitigating Metallurgical Effects of Coal Blending and Switching 63Many plants change fuel sources for environmental and economic reasons,

but unless you understand the consequences of such changes, you could add

new operational and maintenance headaches.

COMMENTARY

China’s Coal Industry: Status and Outlook 68By Dr. Niu Dongxiao, Song Zongyun, and Xiao Xinli, North China Electric

Power University

■ Watts Bar Unit 2 Nuclear Plant Synchronized to Power Grid■ Exelon Makes Good on Threat—Quad Cities and Clinton Nuclear Plants to

Close■ Uranium Production Near Historic Lows as U.S. Reactors Look to Russia■ Moniz: Incentives Needed to Alleviate Nuclear Power Woes■ For Sale: Partially Constructed Bellefonte Nuclear Power Plant■ Experts: Gas Power’s Expansion Riddled with Roadblocks■ SaskPower Carbon Capture Facility Operating More Reliably■ Fire Is Latest Hurdle for Ivanpah Concentrating Solar Power Plant■ D.C. Circuit Delays Clean Power Plan Case Hearing by Months, Opts for En

Banc Review■ EIA International Outlook to 2040 Foresees Decoupling of Power Demand

and Economic Growth

SPRING BROUGHT PLENTY OF NUCLEAR NEWS TO POWERMAG.COM

52

56

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Group and the Women in Power

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SPEAKING OF POWER

Power’s Environmental

Issues Then and Now

Discussions about environmental is-sues related to power plants and the regulations governing their opera-

tion are as old as the industry, I discov-ered while thumbing through the bound July through December 1914 issues of POWER. The specifics of the environmen-tal concerns have become more detailed and complex as scientific knowledge, monitoring technologies, and mitigation solutions advance. However, the general arguments—environmental control versus efficiency, for example—and the human nature demonstrated in the debates, are remarkably similar 102 years later.

Smoke and AshesSeveral articles in 1914 addressed mini-mizing smoke from power and steam plants both big and small (and there were more of the latter).

The August 11 issue ran a one-page sto-ry titled “Rules for Firing without Smoke,” with this synopsis: “How to build, clean and bank fires. In carrying a thick fire the coal is dumped in piles instead of being spread over the grate. The volatile matter is distilled in amounts which the furnace can care for and less smoke is produced.” This editor’s note was included at the end: “It is to be remembered that Mr. Monnett is smoke inspector of Chicago and that the rules in the above, as well as the recom-mendations in the previous articles of this series, apply particularly to conditions in the region where they burn the soft Illi-nois coal which is high in volatile matter. Further, being smoke inspector, the au-thor’s principal effort is naturally toward smoke prevention, rather than economy or efficiency, which are more or less of sec-ond consideration.”

But POWER clearly appreciated efforts to reduce smoke pollution, and on Octo-ber 6 advocated more adequately staffed city “smoke inspection departments,” concluding, “What is an appropriation of two, or twenty thousand dollars to reduce the cause of annual damage amounting to millions in most large cities?”

And in the September 8 issue the editor praises the Mellon Institute at the Univer-sity of Pittsburgh for its bulletin “Some

Engineering Phases of Pittsburgh’s Smoke Problem.” He notes the institute previ-ously addressed smoke’s “damage to laun-dry, buildings, vegetation and its psychic effect upon individuals.” The latest bul-letin addresses the “causes and abatement of the smoke evil” and finds that of 152 plants observed, “the underfed type of stoker [gave] smokeless combustion when properly handled.” The editorial adds, “One cannot read the report without again being reminded that plenty of available cheap fuel is sometimes an evil as well as a blessing to a large city, for as long as it is cheap, gross negligence and resulting smoke accompany its use.” Similar argu-ments about the downside of cheap fuels continue to this day.

Though ash management has become an especially sticky problem given recent reg-ulatory action (see “Coal Combustion Re-siduals Rule Compliance Strategies” in last month’s issue), ash-handling has always been a matter of concern, at least from a material-handling perspective. One let-ter in 1914 commented on an article that had described a new vacuum ash-handling system. The writer calculated operating and depreciation costs and concluded that with few exceptions, “handling with wheelbarrows where the length of travel is moderate” was economically preferable. A few issues later, another reader took is-sue with those calculations—the sort of commentary that these days takes place in the online comments section of POWER articles or on social media.

Legislating SafetyIn the early days of the industry, it was a struggle to get codes and standards and licensing requirements in place. It really was a Wild West of boiler operators, and just as in the Wild West, many died—as a result of boiler explosions and other cata-strophic malfunctions. When an editorial in Hotel World protested against “passing laws for examining and licensing station-ary engineers to handle heating boilers,” claiming that explosions were uncommon, a POWER editorial countered with the fact that there had been more than 500 such accidents in the previous year.

The hoteliers’ magazine was concerned about the added cost of paying for “li-censed” men to operate the hotels’ steam heat systems. POWER responded: “Taking the worst figures cited, it would cost a ho-tel $450 a month instead of $25 to $50. Is not that a terrible price to pay for the increased safety of its guests during the winter? If the journal we are criticizing fairly reflects the attitude of its field, the editor of this paper hopes to do all his traveling in the summer, when he can stop at a hotel without feeling that he is sleep-ing over a gunpowder mine.”

As you can see, warranted sarcasm is nothing new in POWER editorials. And, because my father was a licensed boiler operator for an educational institution’s campus at the beginning of his career, I’m grateful that sensible laws eventually passed.

Although today’s regulation of the power industry is broader and more com-plex—one can’t see immediate effects of airborne mercury pollution in the way one can see bodies maimed by plant explo-sions—similar cost-benefit debates con-tinue. Most recently, they’ve focused on the regulation of CO2 emissions. (Back in 1914, the only concern about CO2 was fig-uring out why it might be too low in flue gas, and how to improve combustion.)

Always Room for ImprovementThe July 21, 1914, issue of POWER in-cluded this random, one-line observation: “So called waste material is in reality good material in the wrong place.” That’s essen-tially the premise of using waste coal for fuel, an issue with both environmental pros and cons, as explained in this issue’s “The Coal Refuse Dilemma: Burning Coal for Environmental Benefits.” As that fea-ture and every other article in this issue demonstrates, finding the sweet spot for maximizing operational and economic ef-ficiency while operating cleanly and safely remains the goal of the best power plants today. We hope you will learn from the new technologies and techniques offered in the following pages. ■

—Gail Reitenbach, PhD is POWER’s

editor.

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Rwanda’s Power Production Triumph over a “Killer Lake”Lake Kivu, the 1,040-square-mile “killer lake” that stretches over the border be-tween Rwanda and the Democratic Repub-lic of Congo (DRC), has long been a source of trepidation.

Because it sits between two volcanic regions in the western branch of the Great Rift Valley, the deep, perpetually strati-fied lake’s bottommost waters absorb high concentrations of carbon dioxide (CO2) from magma-heated springs deep underground, and microbes convert much of the CO2 to methane. These dissolved gases are held in solution by pressures in the depths of the lake but can emerge if zones of high concentration move to-ward the surface, a process known as a limnic eruption, or “overturn.” Because the region is regularly subject to large-magnitude seismic events and volcanic discharges—and considering that meth-ane has a high partial pressure—Lake Kivu is known to experience violent over-turns. Geologists believe they occur at Lake Kivu about every 1,000 years—and that the lake is ripe for another.

Limnic eruptions occurred at much smaller Lakes Monoun and Nyos across the continent in Cameroon in 1984 and 1986 respectively, killing more than 1,700 peo-ple by asphyxiation. But an overturn at Kivu could be catastrophic and endanger millions of people living around its shores on both sides of the border because it contains far more dissolved gases than those two lakes.

Rwanda’s government has for years sought to extract the methane from Kivu’s depths, both to mitigate the risk of such a calamity and to generate power. Its ef-forts first came to fruition in 2008, when the country’s first methane-extracting and power-producing plant, a 3-MW pilot proj-ect, started operations.

Since then, the government has nego-tiated several methane gas concessions. Later in 2008, U.S.-based ContourGlobal, a firm that owns about 4,000 MW of ca-pacity in 20 countries, including in Africa, entered into a partnership with the Rwan-dan government to transform the menace of the lake’s gas deposits into a 25-MW power plant, dubbed KivuWatt. The proj-ect subsequently garnered financial back-ing from the African Development Bank, the Emerging Africa Infrastructure Fund,

the Netherlands Development Finance Co., and the Belgian Investment Co. for Devel-oping Countries. In 2011, ContourGlobal contracted Finnish energy technology firm Wärtsilä to supply an engine-based plant with full engineering, procurement, and construction delivery.

The plant, which has been operational since December 2015 but was inaugurated in May, relies on two processes: methane

extraction and power production. The gas extraction process, performed on a barge anchored 13 kilometers (km) offshore in Lake Kivu (Figure 1), brings gas-rich wa-ters from a depth of 300 meters (m) and 35-bar pressure, reducing pressure to 2 bar in a gas separator, where gas bubbles are extracted from the water. Raw gas is then washed in four wash towers, ContourGlob-al explained.

1. A killer lake reformed. Methane is drawn from Rwanda’s Lake Kivu at a depth of 300

meters by a special barge anchored 13 kilometers offshore. Courtesy: Werner Krug

2. Harnessing lake methane. Rwanda’s KivuWatt power plant runs on methane gas

that is lifted from the depths of Lake Kivu, an “exploding lake.” The plant comprises three 20-cyl-

inder 34SG gas-powered engines supplied by Wärtsilä. Courtesy: Werner Krug


The clean gas is then transported to the power plant (Figure 2) via pipeline, where three Wärtsilä 34SG engines use it as fuel. According to Wärtsilä, the engines are op-timized to run on Lake Kivu’s gases, which have a lower heating value than standard natural gas. “This has helped to downsize the size of the extracting barge and opti-mize the costs of producing electricity,” it said in a statement.

ContourGlobal noted that the design and technology is performing “even bet-ter than expected,” and projects that the gas extraction facility will support at least an additional 9 MW of power generation, likely by the end of 2016.

For Rwanda, the project is proving valu-able beyond its power production, under-scoring its contribution to the region’s socioeconomic development. Contour-Global is working with the local popula-tion, training and developing local workers to run KivuWatt and future installations. The project has also generally promoted peace with the DRC (the border area has suffered from intermittent conflict for de-cades), which is also reportedly consider-ing a similar project, the government said.

Rwanda is now planning a second phase

that will involve two or three barges to generate an additional 75 MW.

TVA Submits Pioneering Application for SMR Early Site PermitThe first-ever early site permit (ESP) ap-plication for a small modular reactor (SMR) was submitted to the U.S. Nuclear Regula-tory Commission (NRC) this May, marking a resurgence for the fledgling nuclear en-ergy technology that has seen a number of setbacks in recent years.

The Tennessee Valley Authority (TVA) submitted an ESP application for a poten-tial future SMR plant at its Clinch River site, 25 miles northwest of Knoxville in eastern Tennessee. The pioneering move could result in an operating plant at the site by 2026 if the TVA chooses to pursue development, experts from the Nuclear En-ergy Institute said.

The federally owned corporation’s ex-ploration of SMR technology is part of efforts to diversify its fleet, moving it toward low-carbon energy. The TVA also said that the project’s main objective is to demonstrate that SMRs can be used to meet generation needs in an “incremental

fashion” while addressing critical energy security issues and tackling carbon reduc-tion goals. The U.S. Department of Energy (DOE) is partially funding the TVA’s regula-tory review process.

The NRC has so far received seven appli-cations for ESPs—certification that a site is suitable for construction of a nuclear plant—and all but Clinch River have been focused on full-size reactors. But most ap-plicants have chosen to defer their license applications, citing economic reasons. For the TVA, the value of an ESP application is to reduce licensing uncertainty when it applies for a combined license by reach-ing early conclusions on siting and envi-ronmental issues. However, it said, a final decision to proceed—still “several years away”—will also hinge on economics.

The company has yet to choose an SMR technology. In 2011, the TVA joined forces with Babcock & Wilcox (B&W) to design and license its 180-MW mPower SMR, but that company slashed funding for the mPower program in April 2014, citing un-favorable market conditions. A number of other light-water SMR designs are under development in the U.S., including those by BWX Technologies, Holtec, Westing-



Over the past decade, driven by a booming energy-intensive industry, China’s thermal power generation capacity has seen a

compound annual growth rate of about 11.1%. But now that the country is facing a more sluggish economy and power

demand has softened, and as it battles rampant air pollution and has accelerated renewable power capacity additions, it is

facing a massive coal power glut. (See also this month’s Commentary at the back of the issue.) The National Energy

Administration (NEA), the National Development and Reform Commission’s energy management arm, estimates nearly 300

GW of coal-fired capacity has been approved or is under construction around the country—but it has determined that no

more than 190 GW of new capacity will be needed before 2020. In April, the government took the drastic measure to halt

construction of coal-fired power plants in 13 provinces where capacity is in surplus and forced developers to stall construc-

tion of already approved plants in another 15 provinces. Sources: China National Bureau of Statistics, China Electricity

Council, NEA —Copy and artwork by Sonal Patel, a POWER associate editoror

A key indicator of China’s

surplus is its utilization

rate. The hours that China’s

thermal plants operate

have fallen sharply in

recent years. Generally, the

industry regards more than

5,500 hours of thermal

plant operation as a signal

that it is facing a power

supply pinch, while less

than 4,500 hours indicates

a power surplus. In 2015,

the utilization rate was

4,329 hours—a new

69-year low.

Estimated

new thermal

capacity*

Existing thermal

capacityTotal installed

capacity

Non-thermal

capacity

*Figures are drawn from official published data. Totals year

to year may not be consistent with data from previous

years, most likely to due to rounding and retirements of

older generation.

2012

1,147GW

2013

1,247GW

2014

1,360GW

2015

1,507GW

52GW

37GW

47GW

64GW

762GW

New and

existing

thermal:

71% of total

installed

capacity

4,329hours

Change from

2012:

–13%

4,706hours

Change from

2012:

–6%

5,012hours

Change from

2012:

+1%4,982hours

333GW

385GW

445GW

517GW

826GW

New and

existing

thermal:

69% of total

installed

capacity

868GW

New and

existing

thermal:

67% of total

installed

capacity

926GW

New and

existing

thermal:

66% of total

installed

capacity

THE BIG PICTURE: China’s Power Glut


house, and NuScale Power, whose design and licensing is also backed by $217 mil-lion in DOE match funding over five years (Figure 3).

Ultimately, the technology decision will be heavily influenced by the SMR de-sign’s attractiveness as it relates to safety, cost, and operability, TVA Senior Manager for SMRs Dan Stout said. “Other consid-erations include the developer’s financial strength, capabilities and commitments that influence the attractiveness of the business case.” Depending on technology selection, the total electrical output of the site will be a maximum of 800 MW, he added. “The application establishes a plant parameter envelope that includes all four domestic light-water small modular reactor designs. This envelope could sup-port multiple reactors from each of the SMR vendors, up to four mPower reactors, four Holtec reactors, 12 NuScale reactors, or three Westinghouse reactors,” he said.

China’s CAP1400 Clears IAEA Safety AssessmentChina’s CAP1400—a reactor design based on Westinghouse’s AP1000 pressurized water reactor—has successfully passed the International Atomic Energy Agency’s (IAEA’s) Generic Reactor Safety Review.

The milestone is significant for China, which plans to deploy the advanced reac-tor design in large numbers (Figure 4) as well as export the technology.

The IAEA’s review assesses the safety cases of new reactor designs that are not yet in the licensing stage against appli-cable IAEA safety standards.

According to China’s State Nuclear Pow-er Technology Corp. (SNPTC), the 1,500-MWe (gross) reactor has a design life of 60 years and a design annual availability of more than 93%. Refueling would be needed every 18 months, and it has pas-sive safety features, including a passive core cooling system, a passive contain-ment cooling system, and a passive main control room habitability system. As de-signed, the company envisions construc-tion would span about 56 months, though it is working to trim that to 48 months.

SNPTC says China has spent about $2 billion on research and development of the reactor. Among its major developers were Westinghouse, which provided de-sign consultation; Lockheed Martin, which participated in the protection and safety monitoring system development; Ohio State University, which helped with test verification; and KSB and Curtiss-Wright’s Electro-Mechanical Division, which partic-ipated in the development of the reactor coolant pump.

One of the World’s Biggest Biomass-Fired CHP Plants Is InauguratedFortum Värme, a company jointly owned by Finnish energy firm Fortum and the city of Stockholm on May 9 inaugurated a new biomass-fired combined heat and power (CHP) plant on the shores of Värtan, a strait in Sweden’s capital city.

The Värtan CHP8 (130 MWe, 280 MWth), which began construction in 2013, will

begin commercial operations in the fall (Figure 5). According to its developers, the plant will use forest residues and wood waste—sawdust, bark, and logging residues from local and regional sources around the Baltic Sea—as well as recov-ered heat from data centers to produce district heat for nearly 200,000 house-holds. The plant is also designed for fuel flexibility to allow it to use new fuels from the developing bioenergy market, Fortum said. Daily consumption of wood chips will be about 12,000 m3.

Building the plant in the middle of Stock-holm—a city with a population of about 1.4 million people—involved multiple challenges, including working with limited space and requiring closed-fuel systems to avoid dust emissions and noise. The plant uses an old rock cavern—previously used for oil storage—that was converted into a massive underground wood chip storage facility. It is able to store about 60,000 m3, or five days of fuel demand.

While the Värtan site has full access to road, rail, and sea transportation, the current fuel procurement plan is based on getting 40% by rail from Nordic biomass suppliers and another 60% by ship from the Baltic Sea region and Russia. “The aim is to ensure the security of supply and ac-cess to a wide geographic biomass market over time,” Fortum explained.

To ensure adequate supply by sea, the company built a new 200-m pier in the harbor area to accommodate two vessels up to Panamax size. On average, the plant requires three to four shipments per week to meet its fuel demand, as well as five trainloads per week, each with a capac-ity of about 4,600 m3. All fuel is unloaded and processed indoors within a closed system before delivery to the power plant. All logistics are coordinated in-house to control supply risks.

The company’s decision to use biomass was complicated by an emerging debate in the European Union (EU) about how sustainable the fuel source is. Fortum noted in an April 2016 energy review that biomass is now the most common form of renewable energy in the EU, and it is the only source that can replace every type of fossil fuel in all energy markets—heating, cooling, electricity, and transport—but concerns are growing about competition for resources and security of supply.

In the EU, while sustainability and traceability concerns are primarily related to biomass imports from other continents, the 27-member bloc has yet to issue a uni-form sustainability policy on all bioenergy (current EU sustainability criteria only ap-

3. New design. Oregon-based NuScale

Power is preparing to submit a design certifi-

cation application for its 50-MW small modular

reactor (SMR) to the Nuclear Regulatory Com-

mission this fall. The SMR developer is the

only one to have an active customer deploy-

ment project: The first NuScale facility is due

to be completed in 2024 in Idaho for UAMPS,

a municipal utility. In March, the company—

whose primary investor is Fluor Corp.—un-

veiled a modified AREVA HTP-2 fuel design for

the SMR, dubbed “NuFuel HTP2.” This image

shows a full-scale mockup of the upper part of

a NuScale SMR. Courtesy: NuScale Power

4. On the nuclear horizon. An artist’s

rendering of a future CAP1400 nuclear reactor

facility. Courtesy: SNPTC


ply to biofuels and bioliquids, not solids), and that has hindered investments in bio-mass. “Harmonised sustainability criteria for all bioenergy would increase the pre-dictability and stability of the operating environment, ensure proper functioning

and transparency of the biomass markets, increase the use of sustainable biomass in energy production, and promote the tran-sition from fossil fuels to renewable and carbon-neutral biomass fuels,” the Fortum review added.

The EU’s policy, which is currently under public consultation, should apply to the origin of all bioenergy regardless of end use, be legally binding, and be applicable to plants exceeding 20 MWth. Ultimately, it should enable increased use of biomass while minimizing administrative burdens or related costs. “The new criteria should not decrease the competitiveness of bio-mass: in many cases, biomass competes with fossil fuels, which generally have no requirements to demonstrate sustainabil-ity,” it said.

—Sonal Patel, associate editor

Employing Fuel Cells for Carbon CaptureFuel cells are a rapidly expanding option for distributed generation, with fuel cell–based power plants now being deployed in capacities into tens of megawatts (see “59-MW Fuel Cell Park Opening Heralds Robust Global Technology Future” in the May 2014 issue). But as the technology improves and costs begin to scale, oppor-tunities for other applications are being explored.

One such application may even go be-yond power generation. Danbury, Conn.–


5. A biomass CHP giant. Finnish energy firm Fortum and the city of Stockholm have

inaugurated a new biomass-fired combined heat and power (CHP) plant near Värtan, a strait in

Sweden’s capital city. Värtan CHP8 is one of the largest of its type in the world. Courtesy: Fortum


based FuelCell Energy (FCE), one of the largest suppliers of fuel cells worldwide, and ExxonMobil in May announced a part-nership to explore the possibilities for us-ing fuel cells for carbon capture.

According to Kurt Goddard, FCE’s vice president of investor relations, the ap-plication will depart from the traditional method of powering the fuel cells with ambient air and methane. Instead of air, it uses coal- or gas-plant flue gas.

Normally in FCE’s carbonate fuel cells, methane is reformed in the cell anode to create CO2 and H2, which is then used to generate electricity by combining with ox-ygen from ambient air to create an electric current and exhaust streams of water va-por and CO2 (Figure 6). The carbon-capture fuel cell will still be powered by methane, but by using flue gas instead of ambient air, the chemical reactions in the cell can concentrate up to 90% of the incoming CO2, which flows with the CO2 generated in the reforming process into the normal exhaust stream, where it can easily be separated from the water vapor.

A critical difference—and bonus—in this process is that rather than being a parasitic drain on the plant, it actually generates additional power. In addition, the process destroys roughly two-thirds of the NOx in the flue gas.

How much CO2 can be captured depends on how many fuel cells are employed. A

typical 500-MW combined cycle plant would need around 120 MW of fuel cells to achieve 90% capture, Goddard said, while an equivalent coal plant might need around 400 MW of fuel cells because of its lower efficiency and higher CO2 emissions. Commercial deployment is still years away, but representatives from both companies are optimistic about the potential.

The possibilities of employing fuel cells to reduce power plant emissions for both coal plants and natural gas combined cycle plants, and potentially capture CO2, have drawn research attention in recent years, though applications have typically involved placing the fuel cells in front of the turbines or replacing typical combus-tion processes altogether. The FCE-Exxon-Mobil initiative is among the first to look at placing the fuel cells after combustion.

ExxonMobil began working with FCE on this project several years ago, Goddard said, beginning with informal discussions that led to more formal testing. With the potential now clear, the two companies have gone public with the initiative. The partnership will focus initially on how to further increase efficiency in separation and concentration of the CO2 from gas tur-bine exhaust. That is expected to take one to two years.

FCE and ExxonMobil scientists will be working to better understand the chemical processes that are taking place and how

they respond to different compositions of flue gas. Assuming success, the second phase will move to a small-scale pilot proj-ect for additional testing, then integration into a larger-scale pilot facility.

—Thomas W. Overton, JD, associate

editor

POWER DigestFuel Loading Begins at Kudankulam 2. Nuclear Power Corp. of India (NPCIL) began loading the first of 163 fuel assem-blies into the core of the second VVER-1000 reactor of the Kudankulam nuclear power plant in Tamil Nadu, India, on May 11. The 1,000-MW unit will begin gener-ating power pending approval from the Atomic Energy Regulatory Board. The unit is the second supplied by Rosatom subsidiary Atomstroyexport. The first Russian-built reactor at the plant, Ku-dankulam 1, started commercial operation in December 2014, and state-owned firm NPCIL is readying to build Units 3 and 4 at the site after delays concerning India’s nuclear damage liability law. India is also in discussions with Russia on costs to build Units 5 and 6, Indian news media reported in May.

Saudi Arabia Starts Up $3B Oil-Fired Power Plant. State-controlled Saudi Elec-tricity Co. (SEC) in mid-May grid con-nected and started commercial operations at the first 660-MW unit of its 2,640-MW Jeddah South Thermal Power Plant. The $3.12 billion oil-fired project that was announced in 2012 makes history in the kingdom for its use of highly efficient su-percritical boilers. South Korea’s Hyundai Heavy Industries built the plant while Ja-pan’s Mitsubishi Heavy Industries sup-plied the equipment. SEC hasn’t confirmed when it anticipates all units to be com-pleted, though it said that the project will help meet power demand from the west-ern region, particularly during the fasting month of Ramadan (which starts in June) in the holy cities of Mecca and Medina.

NuGen Delays UK Nuclear Plant Start-up by a Year. UK nuclear company NuGen-eration (NuGen), a joint venture between Toshiba’s Westinghouse (60%) and EN-GIE (40%), has delayed first power from a proposed nuclear plant in Cumbria to the end of 2025, a year later than planned. The company plans to build three AP1000 reactors with a combined capacity of up to 3.8 GW at the site near Sellafield in west Cumbria but has yet to make a fi-nal investment decision, likely to come in 2018. However, if the plant comes online in 2025, it could overtake EDF’s Hinkley Point C project, which has been billed as

6. Game changer? Fuel cells powered by natural gas could potentially function as carbon

capture technology by using power plant flue gas instead of ambient air. Courtesy: FuelCell

Energy


the first new nuclear plant to begin opera-tions in the UK in a generation.

The UK needs the new plants to help re-place its coal plants and its aging nuclear fleet, which will be shuttered by 2025. As experts point out, NuGen still needs to secure approval for its AP1000 reactor under the country’s Generic Design Assess-ment approval process. EDF, meanwhile, in May announced that the Hinkley Point C project could take nearly 10 years to build once a decision has been made, also likely in 2018. The UK expects a third nuclear plant, Hitachi’s Horizon, to come online over the next decade.

CB&I Bows Out of Agreement to Build South Texas Project Nuclear Units. Toshiba Corp. and CB&I on May 11 agreed to terminate a series of agreements re-lated to the development and execution of an engineering, procurement, and con-struction (EPC) contract for South Texas Project (STP) Units 3 & 4, and on a global strategic partnership to promote Toshiba’s Advanced Boiling Water Reactor (ABWR). Toshiba America Nuclear Energy (TANE), CB&I, and Nuclear Innovation North America (NINA), the entity that owns the STP nuclear units, agreed that CB&I will be relieved from any further obligations related to the units. The agreement termi-nation means that TANE now becomes the sole EPC contractor for the proposed units, though Toshiba noted NINA may not plan to immediately start construction owing to “current economic drivers in Texas and other related issues.” The project received a combined construction and operating li-cense in February 2016.

Shaw Group, which became a CB&I subsidiary after its acquisition in 2013, entered into the alliance with Toshiba in 2010 to promote the Japanese com-pany’s ABWR design in markets world-wide. In December 2015, Westinghouse Electric Co. agreed to acquire CB&I’s Stone & Webster unit, recognizing that “CB&I’s business strategy is now focused on sectors other than nuclear new build projects.”

South Australian Royal Commission Backs International Nuclear Waste Stor-age Facility. As suggested in tentative findings issued this February, South Austra-lia’s Nuclear Fuel Cycle Royal Commission in May recommended that the state establish a facility that would be used for the interim storage and disposal of used nuclear fuel from all over the world (see “Commission Backs Plan to Store World’s Nuclear Waste in Australian Outback” in the April 2016 issue). The state “has the necessary attri-butes and capabilities to develop a world-

class waste disposal facility, and to do so safely,” the commission said, noting that such a facility could generate more than A$100 billion in income over its 120-year lifetime.

Royal Commissioner Kevin Scarce told reporters in May, after the final report’s release, that the state has a number of competitive advantages such as stable geology, a strong international reputation for a good regulatory environment, and a vast amount of land. Before a final deci-sion can be made, however, the state will need extensive community consultation, he said. A referendum or election wasn’t the best way to gain consent because the planning period for the proposed state government–owned facility would take more than a decade. “There isn’t one sil-ver bullet solution to this,” he was widely quoted as saying.

Eskom Looks to Extend Coal Plant Lifetimes. Power-strapped South Africa’s state-owned utility Eskom has decided to renew, rather than decommission, its ag-ing coal fleet. Eskom’s board in late April approved a fleet renewal strategy that will extend the life of a station by replacing components when they reach the end of their lives, as long as it is economical to

carry out the replacement. The utility will begin carrying out 18-month-long pre-fea-sibility studies to assess renewal options for four of its oldest power stations: Koma-ti, Camden, Hendrina, and Arnot.

Marubeni Signs Deals to Boost Power Capacity in Southeast Asia. Marubeni Corp. on May 16 agreed with South Ko-rean firms Korea Midland Power Co. and Samtan Co., and Indonesian coal miner PT Indika Energi Internasional to joint-ly develop the 1-GW ultrasupercritical Cirebon 3 coal plant adjacent to the 660-MW Cirebon Steam Power Plant, which began operations in 2012, and the 1-GW Cirebon 2 plant, which is under construc-tion in the district of Cirebon, West Java province, Indonesia. Indonesia’s govern-ment wants to boost its power capacity 35 GW by 2019 to meet increasing de-mand, which has prompted a flurry of bids from foreign independent power pro-ducers. Marubeni on May 24 also signed a memorandum of understanding with Italy’s Enel to cooperate in evaluating power generation project opportunities in Southeast Asia, especially in Indone-sia, Philippines, Thailand, Myanmar, Viet-nam, and Malaysia. ■

—Sonal Patel, associate editor



Boiler Tube Failure Thermohydraulic Analysis

Eskom operates 23 power stations in South Africa with a total capacity of more than 42 GW. It supplies about 95% of all the electricity used in the country. One of its coal-fired power stations was experiencing frequent boiler tube fatigue failures in the hopper section—the bottom part of the boiler—of all six units.

The boilers were designed with a com-plex support beam structure that cradles and surrounds the boiler. Pivoting attach-ment mechanisms exist between the sup-port beam structure, or buckstays, and the tube wall to allow for thermal expansion while still providing adequate support on all four sides.

The boiler can expand up to a meter downwards during a startup sequence. Buckstays join at corner junction locations of the hopper where the slope walls and front/rear walls join. They are connected to each other using hinged members re-ferred to as buckstay connection links.

These junctions necessitate the rerout-ing of the surrounding front/rear wall tubes, leading to discontinuities in tube layout. High tube failure rates were iden-tified at these tube manipulations and the areas were considered to be possible high-stress locations.

Modeling Boiler StressA suspected cause of the repeated tube failures (Figure 1) was that cyclic op-eration of the plant to accommodate increased intermittent renewable en-ergy resources and reduced electric-ity demand during off-peak hours was

causing cyclic fatigue in the tube mate-rial. Because the plant was designed for consistent operation at full load, the cyclic fatigue was leading to compo-nent damage and reliability problems. The failures resulted in unscheduled shutdowns, emergency repairs, and un-expected costs.

It was also believed that the delayed effect of cooling water being supplied between two adjacent boiler tubes of different tube banks could be a con-tributing factor to thermal fatigue fail-ure. The argument presumed that a column of water from the economizer outlet would reach the closest tube bank first, the second bank next, and so forth. It was alleged that this would cause a significant fluid temperature differential between the first bank’s outermost tube and the adjacent tube of the second bank.

To test the hypotheses, a unique one-way fluid structure interaction (FSI) methodology was developed to model and predict the induced fatigue loading during a boiler startup cycle. Fluid flow and heat transfer was transiently mod-eled using a 1-D pipe flow modeling tool supplied by Flownex Simulation Environ-

ment and validated against experimental data. The 1-D flow solver was a thermo-fluid simulations software package used to predict, design, and optimize flow rates, temperatures, and heat transfer in fluid systems. The one-way FSI model-ing approach allowed a transient ther-mal load, or any user-selected transient step, to be coupled with a 3-D finite element analysis (FEA) software sup-plied by ANSYS to evaluate the thermal-induced stress.

Validation Offers AssuranceHalf of the four boiler hopper walls were modeled to obtain a representative sam-ple of the complete hopper section. In-strumentation, including thermocouples and strain gauges, was also installed in the modeled area of the hopper section to obtain measured plant data. The Flownex model consisted of 1,219 tubes and 1,858 vertices/nodes.

Flownex’s capability to fundamen-tally calculate flow and heat transfer behavior of both fluid and tube wall material during steady state and dy-namic conditions was considered an ideal fit for the testing. Using the same economizer outlet temperature profile

1. Fatigue failure. This image shows a

typical boiler tube failure location at the Es-

kom-owned plant. Courtesy: Flownex SE

300

250

200

150

100

50

0

Tem

pe

ratu

re (

C)

Time (hr)0 2 4 6 8 10 12 14

■ Tc13 ■ Tc14 ■ Tc15 ■ Tc16 ■ FNX Tc13 ■ FNX Tc14 ■ FNX Tc15 ■ FNX Tc16

2. Flownex model validation. The 1-D solver results (denoted as FNX Tc13 through

FNX Tc16) correlated very closely with the data from installed thermocouples (denoted as Tc13

through Tc16). Courtesy: Flownex SE


as obtained during the plant measure-ment sequence, together with adjusted gas-side heat transfer properties, a dynamic startup scenario was modeled to validate the results from the mod-el against that of the measured plant data. A number of other scenarios were also successfully modeled.

The results obtained from the model corresponded very well with the mea-sured plant data (Figure 2). The strong correlation enabled the model to be used for various postulated plant conditions and operating sequences. The tempera-ture distribution results from Flownex were then imported into ANSYS, where the structural stress analysis was per-formed (Figure 3).

The methodology allowed the exami-nation of various scenarios to evaluate

causes of failures without affecting plant operations. It also facilitated the model-ing of the massive boiler structure, which could not have been done economically using 3-D computational fluid dynamics simulations.

Simulation Leads to Answers

The results from the developed model indicated that the delay in water supply between the first tube bank’s outermost tube and the adjacent tube of the second bank did not induce perturbing stresses as postulated. The maximum temperature differential was calculated to be only 2.2C. This proved to be due to the con-duction and thermal inertia of the tube walls and webbing, which resulted in a smooth transition in adjacent tube wall temperatures.

Having ruled extreme temperature differentials out, the effects of struc-tural support members in the form of welded support plates at the buckstay junction locations were evaluated. The developed methodology facilitated comparisons between two cases consid-ered: first, where the buckstay sliding joint plates were present, and second, a case where these plates were removed (Figure 4). In evaluating these sce-narios, the model clearly showed that stress worsened in the presence of the plates.

With this new knowledge, Eskom was able to make modifications to the boil-er structure to reduce induced stress. Plates were removed, which greatly re-duced tube wall stress without compro-mising the integrity of the surrounding structure.

Initial data taken following the modi-fication indicated that strain at the lo-cations previously susceptible to damage had been reduced. Strain data collected over a two-year period prior to solution implementation was compared to data collected after the changes. From the time-averaged data, it was shown that average strain and subsequent stress-induced fatigue loads have been reduced by approximately 50%.

A Valuable Tool

The ability to eliminate, through simula-tion, non-contributors to failure and iden-tify potential new failure mechanisms has proven to be a powerful engineering tool. The developed one-way FSI methodology has been demonstrated to be effective in solving problems of thermal-induced stress fatigue loading as a result of fluid-coupled thermal flow. Obtaining a thermal field from 3-D computational fluid dynam-ics, as used for structural FEA boundary conditions, is not practical due to the size of the problems considered. 1-D to 3-D one-way FSI coupling is not only a fea-sible alternative, but it also is an effective and efficient solution.

Similar problems have been reported at various other Eskom power stations. Identifying the main contributing fac-tor to these stresses may lead to the mitigation of numerous outages due to tube failure repairs, which in turn will result in a significant financial benefit to Eskom and improved reliability for customers. ■

—Marius Botha and Michael P. Hindley were members of Eskom’s Research Test-

ing and Development team tasked with solving the plant’s tube failure problem.

3. Mapping procedure. A 1-D line geometry created in a computer-aided drafting pack-

age was imported into Flownex simulation software to obtain thermal results, which were

exported to ANSYS software for stress analysis. Courtesy: Flownex SE

4. Stressed out. Contour plots colored by maximum principal stress at the buckstay junc-

tion location are shown here for both cases where the sliding joint plate is present (left) and

removed (right). Courtesy: Flownex SE

Plant drawings Digitize to computer-aided

drafting format

Finite element analysis computer-aided

drafting geometry pre-processor

Finite element analysis simulation

*.pcf file export

Temperature field

1D transient pipe

solver


Glenn S. Benson Walker Stanovsky

Securing Pipeline Infrastructure for Gas-Fired Generation in New England

Increased reliance on natural gas as a fuel for electric genera-tion has prompted regulatory reforms by the Federal Energy Regulatory Commission (FERC) to improve coordination be-

tween the two industries. Many in the power industry believe critical constraints in gas pipeline infrastructure serving New England pose a significant threat to electric reliability and prices during periods of peak load in this area. To address this perceived threat, electric distribution companies (EDCs) in the region have teamed up with Algonquin Gas Transmission on its Access North-east pipeline project, which would carry up to 1 billion cubic feet (Bcf) per day of Marcellus gas to the Northeast. The project depends on an innovative but highly controversial effort to se-cure regulatory approvals and financing by relying on the EDCs’ balance sheets and subsidization by electric ratepayers.

Approximately 16,000 MW of gas-fired generation are currently connected to the New England market. Yet few generators have entered into long-term firm pipeline transportation contracts to ensure reliable supplies of gas. This means many of them may be unable to obtain needed gas supplies on peak days or may have to pay an exorbitant premium to get it, threatening electric reliability in the region and stable prices for ratepayers due to limited electric transmission import capability.

Regional grid operator ISO New England has sought to ensure the reliability of its electric capacity resources on peak days by adopting strict capacity performance requirements and penalties for non-performance. This has spurred increased dual-fuel capa-bility by new generators but not long-term firm pipeline trans-portation agreements. Without such contracts, pipeline projects cannot be financed and built.

Stepping Up to the PlateInto this void have stepped Algonquin and EDCs owned by Na-tional Grid and Eversource Energy. Despite being pure electric distribution companies, these EDCs have taken the novel step of signing long-term pipeline precedent agreements for capacity on Access Northeast and requesting that their state regulators ap-prove those contracts as benefitting the EDCs’ ratepayers. Algon-quin, in turn, has petitioned FERC to allow EDCs who subscribe for pipeline capacity on its system to resell that capacity, on a preferential basis, to electric generators through state-regulated electric reliability programs—assuming states ultimately adopt these programs. Any contract costs not recovered through such resales would be passed through to the EDC’s electric ratepayers.

Not surprisingly, these regulatory efforts face broad opposition on a variety of grounds at both FERC and the state level. The Electric Power Supply Association, New England Power Generators Association, Natural Gas Supply Association, the Massachusetts Attorney General, and a number of large electric utilities, gen-erators, gas marketers, and gas producers oppose the proposed

measures, arguing, among other things, that:

■ Preferential releases would be unduly discriminatory and would harm competitive markets

■ Access Northeast would get built regardless■ New England generators do not want special treatment and can

secure reliable fuel supplies without it■ The EDC contracts are legally infirm under state law■ There is more than adequate gas delivery infrastructure in the

region ■ There is a conflict of interest because Eversource and National

Grid propose to own 60% of Access Northeast■ The FERC petition is premature because the states have not yet

acted

Assuming the EDC contracts and electric reliability programs are approved by at least some of the New England states, the Algonquin petition would appear to present FERC with a choice between two of its highest priorities: ensuring electric reliabil-ity and adequate pipeline infrastructure on the one hand, and safeguarding competitive markets, policing undue discrimina-tion, and promoting transparency on the other. Faced with this conundrum, FERC will likely chart a middle course.

Splitting the Difference?One such path forward would be to grant Algonquin’s petition subject to conditions. FERC might require that Algonquin revise its proposal, narrowly tailoring it to do no more than necessary to promote electric reliability and ensuring that all of the terms un-der which preferential releases to generators would be conducted are fully fleshed out in the pipeline’s tariff. FERC also might re-quire that before any EDC releases its capacity to a generator for longer than 31 days, the EDC post the capacity on Algonquin’s electronic bulletin board for bidding by other generators.

This would preserve transparency and at least some measure of competition in the capacity release market, while allowing the EDC-supported capacity to be re-sold first to generators, as it is on behalf of them that the EDCs are contracting. While such a result may seem a fair compromise to some, a solution that satis-fies all will almost certainly prove elusive. FERC held a technical conference in early May on Algonquin’s petition and may take its time reaching a decision in light of these issues, the pend-ing state proceedings, and the fact that Algonquin is targeting fourth quarter 2018 for service commencement. ■—Glenn S. Benson ([email protected]) is a partner in Davis

Wright Tremaine LLP’s Energy Practice in the firm’s Washington, D.C. office. Walker Stanovsky ([email protected]) is an associate in the firm’s Energy Practice, working out of the firm’s

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ENVIRONMENTAL ISSUES

Generators Grapple with ELG Implementation

For more than three decades, the Envi-

ronmental Protection Agency’s (EPA’s)

Steam Electric Power Generating Efflu-

ent Guidelines (or effluent limitation guide-

lines, ELGs), which govern wastewater dis-

charges from electric power plants, were a

fixed, known quantity. The last update was in

1982. But in the 2000s, the EPA began look-

ing at an update, a process that took more

than 10 years of study and comment. The

final rule, finalized in September 2015, is

long and complex, setting the stage for a lot

of confusion and uncertainty. (For more on

the specifics of ELG compliance, see “Take

These Five Steps Now to Ensure ELG Com-

pliance at Your Power Plant” in the Decem-

ber 2015 issue.)

What does this mean for generators?

The answer will no doubt evolve over time,

but the new rule has a lot of people con-

cerned. In February 2016, a group of power

sector environmental experts representing

both generators and consulting firms con-

vened at the Energy, Utility, and Environ-

ment Conference in San Diego to offer

their early thoughts on compliance with the

updated rule.

Where to Start?Not surprisingly, most generators have al-

ready begun compliance efforts, work that

began even before the rule was final. Fur-

ther, it’s well understood that ELG compli-

ance will be intimately related to compliance

with the new Coal Combustion Residuals

(CCR) rule (see “Coal Combustion Residu-

als Rule Compliance Strategies” in the June

2016 issue or at powermag.com. Bill Ska-

litzky, manager of generation compliance

for Alliant Energy, noted that his company

has already gone ahead and dredged out an

ash pond at a plant that had been converted

to natural gas. “So we already have one of

our ponds secured and closed. We’re look-

Plant wastewater treatment is not what it once was, and changes in the Environ-mental Protection Agency’s effluent limitations guidelines (ELG) have added a host of new wrinkles. A panel of power plant experts discussed what plant managers are planning and doing to keep things running smoothly within the new rules.

Thomas W. Overton

Courtesy: RoyalBroil/Wikipedia/Creative Commons 4.0

1. A time for change. Westar Energy is

transitioning its coal fleet, including the 2,155-

MW Jeffery Energy Center in St. Marys, Kan.

(which was POWER’s 2014 Water Award win-

ner) toward compliance with new rules for

disposal of wastewater and coal combustion

residuals. Courtesy: Westar Energy



ing at a lot of different methods,” ranging

from excavating to enclosure; “we’ve been

planning for a few years now.”

Jared Morrison, manager, water & waste-

water programs for Westar Energy, also

said, “We’ve been planning for that for quite

some time.” But he noted that first steps

varied across different plants (Figure 1). “I

think the first activity was trying to under-

stand how we can close surface impound-

ments and how we can clean them. That

was the biggest issue at those sites. At other

sites, the first activity was understanding the

water balances.”

Compliance with the ELGs will require

some substantial lead times for both equip-

ment and the time needed to install it, the

speakers noted—in the range of 12 to 18

months.

“There are some risks associated with

that,” Morrison said, “and we are seeing

those lead times get longer and longer.”

Though there is a natural impulse to

want to delay capital expenditures, doing

so is risky. Where it is necessary, Block

Andrews, director of strategic environ-

mental solutions for Burns & McDonnell,

recommended working closely with regu-

lators, “so they understand your side of

the story.”

Groundwater Monitoring The groundwater monitoring required by the

CCR rule can help with ELG compliance,

several noted. Skalitzky said Alliant is in-

stalling monitoring equipment at several of

its sites in Wisconsin. “We already have some

groundwater monitoring data for constituents

of concern.”

Morrison said Westar has been aggres-

sive in assessing its surface impoundments

and installing monitoring equipment.

“Those areas where we felt we were at a

pretty high risk of having some sort of hit

that would trigger closure, we went ahead

and closed those prior to the deadline.”

Only the impoundments that were viewed

as low risk remained open. “We felt that if

they did have an issue, we could respond

quickly to cease using those within six

months.” Those impoundments, he said,

were mainly bottom ash.

With respect to groundwater monitor-

ing, Morrison said they have a lot of par-

tial historical data that may or may not

be current because of past monitoring for

various reasons. “We’re installing wells

today so that we can start our background

samples” this year, he said.

Equipment ChallengesBoth rules provide pressure to move to bot-

tom ash handling systems that are either

completely dry or that use mechanical de-

watering. But there is concern about the in-

dustry’s ability to produce and deploy such

systems in time.

“Honestly, this is a concern,” Andrews said.

“I don’t know how many utilities are going to

be approaching these projects, but there is a

limited capacity to address them, maybe 10 or

15 spots in a year, maybe 20, but the suppliers

will need to ramp up to do that. We’ll see them

step up to the plate, but I would certainly state

that we will see some delays.”

Andrews noted a trend toward zero-liquid

discharge (ZLD, Figure 2) was on the way,

but not many people have gone that direc-

tion yet.

“That would probably not be something

you would be looking at if you’ve got a pretty

large body of water to deal with. It’s going to

be the people on the smaller side.”

Skalitsky noted that maintenance of

submerged drag chain systems was a ma-

jor challenge. “We’re definitely looking

toward a dry system,” he said, mentioning

FGD purge from

hydroclones

AlkaliOrgano-

sulfideFerric

chloridePolymer

Hydrochloric

acid

Equalization

Filtrate

sump

Treated

wastewater

Gravity

filtration

RX1 RX2

Clarification

Filtrate

Recycle sludge

Sludge

Sludge tank Cake

Backwash reject

Dewatering

(to discharge and

also used for

backwash)

2. A big zero. The zero-liquid-discharge system supplied by Aquatech for Southern Co.’s

Kemper County Integrated Gasification Combined Cycle Plant in Mississippi uses a combina-

tion of ultrafiltration, reverse osmosis, conventional demineralization, and thermal evaporation.

Courtesy: Aquatech

3. Just the beginning. Though typical flue gas desulfurization (FGD) wastewater treat-

ment systems produce a certain amount of effluent, as shown here, changes in the Effluent

Limitations Guidelines are creating pressure on generators to move to full zero-liquid-discharge

systems. Source: Siemens



wear and tear on the drag chains and the

availability of replacement parts. “We’ve

looked at a number of things, and in most

cases we’re going to try to move toward a

totally dry system.”

Morrison agreed. “The ash transport systems

require a lot of maintenance. It’s not something

you enjoy dealing with,” he said. “We will eval-

uate the dry system, and if it’s feasible economi-

cally, we will move forward on it.”

Labor and Outage ImpactsAnother concern was the added training that

will be necessary for operators of new ash-

handling and biological treatment systems.

The limited number of existing systems

means a limited talent pool to draw on, and

biological treatment requires a skill set not all

plant operators will possess.

“There are just not a lot of biological

treatment systems out there,” Morrison said.

“Keeping the bugs happy, it is going to take

someone with some knowledge of chemis-

try. It works, but you have to have someone

who is well trained and really watching the

systems to make sure it’s operating. It’s just

additional operators with experience on those

systems.”

Skalitzky noted that conversion need not

require a lot of outage time where it’s possi-

ble to prefabricate many of the components.

On one unit, Edgewater Generating Station

(shown in the header photo), he said, “We

anticipate it’s going to take about three days

of changing out some pumps to convert to a

dry system.”

Different planning is needed to get various

wastewater streams (for example, from the

flue gas desulfurizer, FGD, Figure 3) segre-

gated so they can be managed under both sets

of rules.

“We’re looking at putting in some kind

of tank system where we can collect all this

water from the FGDs and utilizing that wa-

ter back into the scrubber,” Skalitsky said.

“We’re trying to get down, as best we can, to

a zero-liquid discharge, especially on some

of the plants where we have restrictive water

quality systems.”

Morrison noted that managing and moni-

toring these systems requires a lot more at-

tention to minutiae like water flow rates in

the ash-handling system. “That’s not histori-

cally something that was built in as a concern

at our facilities.”

Operational ImpactsAdapting to new methods of handling waste-

water takes time and effort, and getting to

smooth operations is a lengthy, ongoing pro-

cess, Morrison said. “It takes time to train

people, it takes time to get them up to speed.

All of these are significant issues.”

Skalitsky said most of Alliant’s plants

have wastewater operators in place, but ad-

ditional hiring is likely to be necessary. Be-

cause Wisconsin requires these staff to be

certified for managing wastewater, that cre-

ates an additional step for new staff that may

be needed for the new systems. “We’re going

to have to have those operators certified for

those type of operations.”

Morrison said Westar has had to reach

out beyond its existing staff to manage these

new challenges. While they have chemists

on staff, they did not have the specific ex-

pertise necessary to manage wastewater

chemistry and had to bring in an outside

expert. “We were missing that knowledge

in the company, so we had to go and find

that expertise. That has been a challenge. It

is hard to rely on an external company to do

that for you. We need the same consistent

presence on a day-to-day basis. It’s not re-

ally the best situation.” ■

—Thomas W. Overton, JD is a POWER

associate editor.

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Evaluating the Use of CEMS for Accurate Heat Rate Monitoring and Reporting

Continuous emissions monitoring sys-

tems (CEMS) are used to monitor

power plant flue gas emissions as a

means to comply with federal and state air

emission standards. Through various meth-

ods, they determine the concentration and

amount of key emissions, including nitrogen

oxides, sulfur dioxide, carbon monoxide, car-

bon dioxide (CO2), hydrogen chloride, par-

ticulate matter, mercury, and volatile organic

compounds (Figure 1).

CEMS are required in all U.S. fossil-fired

plants greater than 25 MW. They are a mature

technology, and most have been widely used

for more than 20 years.

The CEMS data provides an official record

of the key power plant flue gas emissions.

In the U.S., this data is reported to the En-

vironmental Protection Agency (EPA). Plant

owners/operators are required to maintain the

systems and ensure that results meet the letter

of the law. A portion of that requirement is to

conduct an annual relative accuracy test audit

(RATA) to determine the status and ability of

the CEMS to comply with EPA requirements.

More Than EmissionsIn addition to emissions, CEMS also provide a

value for boiler heat input—and, therefore, very

easily permit the determination of heat rate.

Heat rate is a key measure of power plant

efficiency. It is the ratio of heat input and

power output. The lower the heat rate, the

better the efficiency.

Measurement of heat rate is likely to be-

come a critical issue in the coming years, be-

cause the Clean Power Plan, finalized by the

EPA in 2015, will rely, in part, on coal plant

heat rate improvements to reduce CO2 emis-

sions by reducing the amount of fuel burned.

The EPA is anticipated to use the heat input

values reported by power plants’ CEMS to

determine if the plants have reduced their

heat rates to the required levels.

The ability to accurately measure the two

key parameters to the heat rate equation—

the flue gas CO2 concentration and the stack

volumetric flow rate—will thus be of key

importance.

However, determination of heat input for

solid fuel power plants is difficult to measure

directly with sufficient accuracy because coal

flow is difficult to measure. That coal flow

rate is the key parameter in the determination

of the heat portion of heat rate. Coal constitu-

ents do not remain constant over time, espe-

cially for plants that blend coal from different

sources. Therefore, the real-time measure-

ment of coal heating value becomes another

important parameter with a one-to-one effect

on heat input.

Many plants have instrumentation and

monitoring systems sufficient to determine

boiler heat output (and turbine performance)

on a continuous basis, but very few have the

capability of accurately determining boiler

Power plants are familiar with using continuous emissions monitoring systems (CEMS) to monitor pollutants, but these devices also may be able to measure heat rate—which could be handy for future compliance with the Clean Power Plan.

Sam Korellis and Chuck Dene

Courtesy: Gail Reitenbach



efficiency on a continuous basis, which

would be needed to complete the heat rate

calculation. One method of accurately deter-

mining boiler efficiency, the heat loss meth-

od, requires installation and maintenance of

instrumentation to sample gas concentration

and temperature at the air heater inlet and

outlet. However, adequate sampling grids are

expensive to install and difficult to maintain.

CEMS, which are capable of measuring

the concentration of CO2 in the stack gas

and calculating the flow rate of the exhaust

gas, have the potential to offer an alternative

method for a real-time (continuous) unit heat

rate calculation without additional instru-

ments or labor-intensive processes.

The issue with CEMS, though, is that the

accuracy required for a meaningful heat rate

value is much tighter than current CEMS

practices. With typical uncertainties greater

than 5%, CEMS could not be used to identify

a heat rate change of 2% to 4%, which will

potentially be required by the Clean Power

Plan (assuming it survives the current legal

challenges).

Understanding the Uncertainty of CEMS Heat Rate MeasurementsOver the last several years, researchers at

the Electric Power Research Institute (EPRI)

have conducted several studies to identify the

technology gaps and to propose and evaluate

actions required to use CEMS for heat rate

monitoring. These studies have sought to

better understand the current uncertainty of

CEMS measurements and the drivers of the

differences in uncertainty between CEMS

and a precision boiler efficiency test.

In 2014, EPRI and a member utility con-

ducted a series of precision performance tests

at the member’s 350-MW coal-fired unit to

investigate how accurately the actual boiler

heat input could be determined when quality,

nonbiased CEMS data are available. First, a

series of boiler efficiency test runs were un-

dertaken to calculate boiler efficiency and net

unit heat rate by methods based on ASME’s

Performance Test Codes (PTC) 4 and 46.

Then, the values calculated from the test re-

sults were compared to those obtained from

the CEMS. The tests were conducted at full,

medium, and minimum load—approximately

the same unit load levels utilized for the most

recent RATA testing at this unit.

The results were further refined through

the calculation of uncertainty of the boiler

efficiency and heat rate calculated by each

method. These uncertainty calculations were

performed by methods described in ASME

PTC 19.1, Test Uncertainty.

For the full-load test, gross heat rate cal-

culated by the CEMS method was slightly

higher than with the PTC 46 method. For the

medium-load test, the heat rate was almost

equal for the CEMS and PTC 46 methods.

With the minimum-load test, the heat rate for

the CEMS method was much lower than for

the PTC 46 method. The reasons behind the

non-predictable differences in heat rate were

not identified.

The uncertainty analysis showed that the

uncertainty of the boiler efficiency value

using the CEMS method was greater than

5%, compared to an uncertainty of 0.29%

using the ASME PTC 4 test method. Im-

provements in the accuracy of the CEMS

could greatly reduce the uncertainty, but the

uncertainty of boiler efficiency determined

by this method is dependent on both the ac-

curacy of the CEMS measurements and the

instrumentation used to measure the heat

output of the boiler.

While this plant site operated and main-

tained its CEMS beyond the minimum EPA

requirements, the large differences in results

and the uncertainties of the results strength-

ened the notion that CEMS could not be used

to monitor or report heat rate with confi-

dence. The key contributor to the high mea-

surement uncertainty was the measurement

of stack gas flow rate.

Best Practices GuidelineTo address this issue, in 2015, EPRI devel-

oped a best practices guide to improve the

accuracy of the measurement of stack gas

flow rate.

The project team sought to evaluate avail-

able information on the performance of CO2

CEMS and continuous flow monitors, and

to identify the uncertainty and biases of

measurement system parameters with the

greatest effect on measurement data quality.

Then, using the knowledge gained regard-

ing the uncertainty and biases of the system

parameters, the project aimed to recommend

enhancements to the operation, calibration,

maintenance, and auditing of these systems

that would extend the usefulness of the

CEMS and flow monitors to provide a pri-

mary means of unit heat rate determination.

In support of this effort, EPRI developed

a multi-faceted approach to identify the state

of current industry best practices as well as

a methodology for achieving reduced uncer-

tainty in the measurements. The approach

involved conducting an open literature

search pertaining to CEMS operation; con-

tacting end-users for supplemental informa-

tion regarding CEMS operation, calibration,

tune-ups, and maintenance practices; de-

termining industry best practices related to

pre-RATA flow monitor calibrations, refer-

ence methods used, and pre-RATA adjust-

ments; summarizing the effects of different

reference method practices on measurement

uncertainty; and establishing target uncer-

tainties and identifying whether the instru-

mentation can achieve these.

A model was developed to estimate the

uncertainty contributions for the heat rate

calculation. The model allows estimation

of the uncertainties of the various measure-

ments used to calculate a unit heat rate—as

well as hourly heat input, including flue gas

flow rate, flue gas CO2 concentration, the

carbon-based fuel factor, and the power out-

put (Figure 2). The model then propagated

The key contributor to the high measure-ment uncertainty was the measurement of stack gas flow rate.

1. A continuous emissions moni-toring system. Courtesy: EPRI



these individual measurement uncertainties

to the final heat rate result. The results of the

model were used to focus the best practices

guide on the areas responsible for the largest

contributions to uncertainty.

Project results were reported in a “best

practices” guide for operating, calibrating,

and maintaining a CO2 CEMS and associated

flow monitors to provide the highest degree

of data accuracy practical with currently

available instrumentation and hardware.

Recommendations are included on sampling

systems; analyzers; calibration gases; instru-

ment types, calibration, and placement; stack

diameter determination; and RATA test tech-

niques. (See A Best Practices Guideline for

Understanding and Minimizing Uncertainty

in CO2 and Stack Flow Measurements, EPRI

report no. 3002006147.)

Application of Best PracticesSubsequently, a further study applied the best

practices for CEMs RATA reference methods

to a full-scale CEMS heat rate measurement

on a 670-MW coal-fired utility boiler.

The host site had an optimal CEMS sys-

tem that greatly exceeded EPA requirements.

The CEMS installation location for this site

was also near ideal with respect to flow, and

the CO2 instrumentation was well calibrated.

The guidelines promulgated in the EPRI

best practices guide were followed in the

preparations for and the execution of a special

RATA test. The sampling, analytical, quality

assurance, and quality control procedures fol-

lowed during the RATA program were above

and beyond the minimum EPA requirements.

The study findings demonstrated that very

good relative accuracy can be obtained, im-

proving the uncertainty of the CEMS heat

rate values. The additional effort needed to

comply with the best practices was not con-

sidered significant and could be achieved at

most sites.

Continuing this study, researchers con-

ducted an “enhanced” CEMS audit test—

which they nicknamed “super RATA”—to

calculate correction factors to be applied to

the values of the flow and CO2 concentra-

tion reported by the CEMS. This enhanced

RATA measurement was performed using

best practices for minimizing the uncertainty

of CO2 and flow measurements. The preci-

sion heat rate testing was conducted immedi-

ately thereafter, again in full compliance with

ASME PTC 4 and 46.

The uncertainties were calculated for

the boiler efficiency and heat rate val-

ues determined by each method using the

methods described in ASME PTC 19.1,

Test Uncertainty. The gross heat rate value

calculated by the CEMS method, after ap-

plying the correction factors for flow and

CO2 concentration, was compared to that

determined via the precision test (PTC 46)

method for all test runs.

The heat rate indications obtained from

the CEMS and those obtained through pre-

cision testing were comparable. The differ-

ence in those values was smaller than the

uncertainty determined for the measure-

ments conducted by either method. (See

Stack Flow and CO2 Reference Method

Measurements for Continuous Emissions

Monitoring Systems (CEMS) Heat Rate

Determination: Application of Best Prac-

tices, EPRI report no. 3002007186, and

Evaluation of the Application of Continu-

ous Emissions Monitoring Systems for

Boiler and Heat Rate Monitoring, EPRI

report no. 3002007187.)

Ongoing WorkIn 2016, to further optimize the process and

fully understand the best possible uncer-

tainty, an intense lab calibration of the flow

measurement equipment will be done at ven-

dor and National Institute of Standards and

Technology facilities. Those calibrations will

permit EPRI and its members to better under-

stand the costs and time involved to further

reduce the measurement uncertainty asso-

ciated with stack gas flow measurements.

Plans are to use these optimally calibrated

instruments during another “super-RATA” to

quantify any improvements in flow measure-

ment and unit heat input. ■

—Sam Korellis, PE ([email protected]) is a principal project manager of EPRI’s Heat

Rate Improvement program. Chuck Dene

([email protected]) is a principal project manager in EPRI’s Integrated Environmen-

tal Controls Program.

2. Flue gas sample ports and probe. Courtesy: EPRI



Simplify MATS Compliance with Particulate Matter Continuous Emission Monitors

Starting with the Clean Air Act of 1970

and its updates, compliance for util-

ity and industry stationary sources has

only increased in complexity. The Environ-

mental Protection Agency (EPA) has targeted

many industries that emit criteria pollutants

and hazardous air pollutants (HAPs) and has

written regulations to ensure that affected

industries control the release of pollutants

by implementing the most effective control

technologies.

Most recently, the Mercury and Air Toxics

Standards, known as MATS, has been added

to the list of regulations. MATS establishes

emission limits for three HAP categories:

mercury, non-mercury metals, and acid gas-

es. Importantly, particulate matter (PM) is a

surrogate for non-mercury metals.

This article focuses on the EPA’s require-

ment for Maximum Achievable Control

Technology (MACT) as it applies to electric

generating units (EGUs). An EGU must dem-

onstrate compliance with the MATS limits,

and MATS offers options for demonstrating

compliance. An EGU can use continuous

emission monitoring systems (CEMS) or a

combination of CEMS and periodic testing

using conventional reference methods. By

understanding these options, source owners

can implement strategies that allow facilities

to set their source-specific operating limit

closer to their PM compliance limit, which

will help limit the risk of noncompliance.

MATS was promulgated in February 2012

and the industry had three years to demon-

strate compliance (with a possible one-year

extension in some cases). Coal- and oil-

fired source operators had to analyze the

regulations and define a strategy for mercury,

non-mercury HAP metals, and acid gases

compliance, based on the type of existing

equipment they operated and the potential for

add-on abatement equipment.

When considering non-mercury metal

HAPs, the choice of PM as a surrogate sim-

plified the strategy for many sources. Given

that many PM monitor vendors were devel-

oping monitors to comply with this new reg-

ulation and historic data using PM monitors

for compliance demonstration purposes in

the U.S. was limited, many source owners

defaulted to the quarterly PM stack testing

option until PM monitor data, history, and

resources could be researched.

Now, four years into the MATS compliance

era, enough historic data and improved moni-

tors exist to potentially change the PM com-

pliance strategy to one that uses a PM monitor

instead of quarterly PM stack testing.

CEMS vs. CPMSTo comply with the non-mercury HAP met-

als limits, an EGU can conduct quarterly

manual reference method testing for metals

or manual reference method testing for PM,

the surrogate for non-mercury metal HAPs.

Alternately, if the EGU chooses to use PM

as a surrogate, it can install a continuous PM

monitor and operate it as either a CEMS or

a continuous parametric monitoring system

(CPMS).

If the PM monitor is operated as CEMS,

a correlation curve must be generated by

statistically comparing CEMS data to refer-

ence method data as set forth in Performance

Specification 11. If the PM monitor is oper-

ated as a CPMS, reference method PM test-

ing is used to demonstrate compliance with

the MATS PM limits at normal operation.

The response of the PM monitor that cor-

responds to this reference method PM test-

ing is recorded and is considered to be the

source-specific operating limit. As long as

the 30-day rolling average output of the PM

monitor stays below the source-specific oper-

ating limit, the source is considered in com-

pliance with MATS for non-mercury metal

HAPs using PM as a surrogate.

The Changing Role of Pollutant Monitors Pollutant monitors play a critical role in

demonstrating continuous compliance.

Now that power plant operators have some experience under their belts related to Mercury and Air Toxics Standards (MATS) compliance, it’s time to reevaluate the options for demonstrating compliance.

Rick J. Krenzke




These monitors, based on a range of analyti-

cal detection technologies, can qualify and

quantify target compounds, and when qual-

ity assurance and maintenance procedures

for the systems are defined, they can provide

defensible emissions data.

Gaseous monitors are the most common

CEMS, but recent technological advances

have expanded the availability of PM moni-

tors beyond those used to measure opacity.

Importantly, modern PM monitors can ex-

press PM emissions as a concentration, thus

allowing comparison to a PM emissions

limit.

Here’s a condensed timeline of PM moni-

toring development:

■ 1950s and 1960s: The Germans pio-

neered and began studying PM detection

technologies.

■ 1970s: PM technologies came to the U.S.

in the form of opacity monitors. Opacity

was considered a surrogate for PM and

Performance Specification 1 (also known

as PS1) was promulgated in 1975.

■ 1996: The Hazardous Waste Combustion

MACT rule was the first to require the use

of PM monitors. The need for a perfor-

mance specification to validate PM moni-

tor data was proposed (PS-11).

■ 1999: The Portland Cement MACT stan-

dard mandated PM monitors, but not until

PS-11 was promulgated (2004).

■ 2012: MATS was promulgated, allow-

ing certain PM CEMS detection tech-

nologies for filterable particulate matter

(FPM) compliance demonstrations. The

PM monitors could be used as a true PM

CEMS or PM CPMS.

PM monitoring technologies include: light

scattering, beta attenuation (the two most

commonly deployed technologies), probe

electrification, optical scintillation, and light

extinction. From these measurement tech-

nologies and the diligent work of instrument

vendors, today PM monitors can detect and

indicate changes in the amount of FPM in

exhaust gases and are accurate and durable

enough to be utilized as CEMS.

Unlike traditional gaseous monitors, PM

monitors cannot be calibrated like a CEMS

that measures gaseous pollutants. Instead of

using calibration gases, the monitor output

signal must be correlated to a physical PM

measurement that is obtained using an EPA

reference method stack test for PM.

In general, the PM detection principle is a

function of the size, shape, color, concentra-

tion, and material of the PM and is therefore

source specific. Accordingly, PM monitors

must be evaluated for each source over a

range of operating conditions. Furthermore,

PM monitors are different from traditional

gaseous monitors.

It’s important to note that MATS allows

choices in how the PM monitor can be used.

When the regulation was first enacted, power

companies had to quickly choose a com-

pliance strategy. Among the choices were

the use of a PM monitor as a full CEMS or

the use of a PM monitor as a CPMS. Now,

with the experience gained through various

approaches, the time is right to revisit com-

pliance demonstration strategies using con-

tinuous PM monitors as CEMS or CPMS.

Three Options Table 1 details the three options for power

Options Pros Cons

Quarterly stack monitoring No initial capital expense for

PM monitor and installation. No

maintenance costs.

Can only see a snapshot of emis-

sions once per quarter. It can be

challenging to schedule emission

testing firm during busy seasons.

Do not know results until a week

after the testing is complete.

PM CEMS: full continuous

emissions monitoring system

calibrated by a correlation

curve (PS-11)

Continuous data and can be used

over full calibration range, so

operating limit is the MATS PM

allowable.

Correlation testing (calibrating

monitor) can be difficult on highly

controlled sources. Have to conduct

tests over three distinct emission

levels. Correlation testing can be

expensive, especially if PM spiking

is necessary.

PM CPMS: continuous param-

eter monitoring system

Continuous data and the correlation

testing (setting the source-specific

operating limit) is comparatively

easy.

The source-specific operation limit

will always be set below the MATS

PM limit, so the source will not

have as much flexibility in emission

variation before corrective actions

must be taken.

Table 1. Summary of PM measurement options. Source: TRC Companies Inc.




plant operators to consider with respect to

demonstrating compliance with the non-

mercury metal HAP limit using PM as a

surrogate.

Most have followed periodic manual test-

ing or the use of a PM continuous monitor

as a PM CEMS. But the time has come to

take another look at the overlooked option of

using a PM continuous monitor in a CPMS

mode.

What’s needed to get started?

To begin, the facility must determine

the PM limit from MATS. PM limits vary

based on fuel type and whether the source

is new or existing. MATS allows PM to be

measured and reported in lb/MMBtu or

lb/MWh, and the EGU should select the

most favorable reporting option. The facil-

ity will then need to conduct performance

testing using EPA Reference Methods to

demonstrate compliance with the MATS

PM emission limit.

The next step is to establish a source-spe-

cific operating limit. To do this, the facility

will need to perform the following tasks:

■ Conduct a performance test.

■ Record all CPMS output values (milli-

amps or other signal).

■ Determine 1-hour average CPMS output

readings (milliamps) during the perfor-

mance test. (Note: If you perform three

3-hour test runs, you generate nine 1-hour

CPMS averages.)

■ Set a source-specific operating limit based

on these results.

■ Operate and maintain equipment to

achieve a 30-day PM CPMS average that

does not exceed the established operating

limit. (MATS allows the monitor output

signal that correlates to the highest 1-hour

CPMS output for existing units only; for

new EGUs it is the average output.)

■ Reset the source-specific operating limit

annually.

The mechanism selected for determining

the source-specific operating limit will de-

pend on the results of the performance tests.

Once again, the source has choices. Under

MATS, if a PM monitor is being used as a

CPMS, setting the source-specific operating

limit is different for a new source than it is for

an existing source. For a new source, if the

performance tests indicate PM emissions are

less than 75% of the MATS limit, the source-

specific operating limit can be extrapolated

to equal 75% of the MATS limit. Only new

sources are eligible for this extrapolation.

If the performance test results are greater

than or equal to 75% of the MACT limit, the

average PM CPMS output value (milliamps)

will be the source-specific operating limit.

If the 30-day rolling average output of the

PM CPMS exceeds the source-specific oper-

ating limit, the source must take corrective

actions as follows:

■ Within 48 hours of an exceedance, a vi-

sual inspection of the air pollution control

device (APCD) must be performed. If the

inspection identifies the cause, corrective

action must be taken and the PM CPMS

must be returned to operation.

■ Within 30 days of the exceedance, or at

the time of the annual performance (com-

pliance) tests, whichever comes first, a

PM performance test must be conducted

to demonstrate compliance with the PM

MACT limit and to reestablish the source-

specific operating limit.

■ The compliance demonstration and reset

of the operating limit must be implement-

ed within 45 days of the exceedance.

■ Additional testing is not required for any

exceedance that occurs between the initial

exceedance and the performance test trig-

gered by that exceedance.

Before devising a strategy for setting

source-specific operating limits make sure

you:

■ Apply the proper PM MACT limit based

on the source type.

■ Have an instrument that indicates the pres-

ence of and changes in PM in the exhaust.

Option Task Cost

Quarterly stack monitoring Using PM as a surrogate for non-Hg

metals HAPs

$7K–$10K per quarter

Testing for total non-Hg metals

HAPS or individual non-Hg metals

HAPs

$15K–$18K per quarter

Using PM as a surrogate for

non-mercury (Hg) metals haz-

ardous air pollutants (HAPS),

installing a PM monitor, and

using it as a continuous emis-

sion monitor (CEMS). Use of

monitor as CEMS would require

certification (correlation curve)

by PS-12.

Purchase and install PM monitor Depends on type of monitor and

installation contractor

Annual PM monitor maintenance Depends on type of monitor and

plant maintenance crew

Develop PS-12 correlation curve

(minimum of 15 test runs across

three specific grain loading condi-

tions)

$24K–$30K, assuming the three

specific grain loading conditions

can be easily provided

Fly ash spiking to generate grain

loading conditions needed to build a

correlation curve that meets PS-12

guidelines

$50K–$100K, depending on how

many attempts are made at gen-

erating the required grain loading

condition

Annual Relative Response Audit

(RRA). The RRA is three test runs

to determine compliance with the

MATS limits and determine if the

resulting PM is still predicted accu-

rately by the correlation curve.

$7K–$10K

Using PM as a surrogate for

non-Hg metals HAPS, install-

ing a PM monitor and using

it as a continuous parameter

monitoring system (CPMS).

Use of monitor as CPMS would

require setting a source-spe-

cific operating limit (monitor

output signal) that would not be

exceeded by the 30-day rolling

average output.

Purchase and install PM monitor Depends on type of monitor and in-

stallation contractor

Annual PM monitor maintenance Depends on type of monitor and

plant maintenance crew

Initial testing to determine compli-

ance with MATS and set the source-

specific operating limit

$7K–$10K

Annual testing to determine com-

pliance with MATS and reset the

source-specific operating limit

$7K–$10K

If source exceeds the source-spe-

cific operating limit with the 30-day

rolling monitor output and correc-

tive action is needed, the source

will need to conduct testing to de-

termine compliance with MATS and

reset the source-specific operating

limit

$7K–$10K

Table 2. Range of costs for purchasing and maintaining PM systems. Source: TRC Companies Inc.



■ Understand the ways to establish the PM

CPMS operating limits.

■ Understand what triggers corrective action.

■ Understand how operational variables af-

fect PM emissions (PM CPMS output).

■ Are aware that operating limits are reset

every year or when an exceedance occurs.

Using measurement results and what’s

known about the effects of unit operation on

the CPMS output, source owners can develop

a strategy for setting source-specific operat-

ing limits that provide the facility with the

most flexibility to operate the source.

The strategy selected will depend on how

close emissions are to the PM MATS limit

under normal operations. As an example, the

following scenarios could shape the strat-

egy for setting the source-specific operating

limit:

■ If the PM performance test results are

above or equal to 75% of MACT limit

(new or existing units), this is the operat-

ing limit. It may be useful to adjust operat-

ing parameters to produce PM emissions

closer to the MATS limit.

■ If the PM performance test results are be-

low but close or equal to 75% of MACT

limit (new units only are candidates for

extrapolation), there may be no benefit

to extrapolating to 75%. It may be useful

to adjust operating parameters to produce

PM emissions closer to the MATS limit.

■ If the PM performance test results are well

below the 75% of MACT limit, extrapolate

to 75% (if the unit is a candidate) or adjust

operating parameters to produce PM emis-

sions closer to the MATS limits when set-

ting the source-specific operating limit.

Many source owners set the source-spe-

cific operating limits near the MACT limit

because it provides more room for operation-

al variations, reduces the need for APCD

maintenance, and can avoid costly corrective

action exercises. But this can lead to compli-

cations.

For example, when annual compliance

and operational limit reset time comes

around, this strategy relies on being able

to set the unit near the same emission rate

(same monitor output) for each annual test.

If the PM CPMS calibration (correlation

between the monitor output and the actual

PM emission rate) stays the same, this is

not an issue, but if it changes, there is a

chance that the facility will fail the perfor-

mance test.

This strategy usually requires some in-

house or preliminary PM testing to verify or

confirm that the PM CPMS output as com-

pared to actual PM emission limits is still ac-

curate, especially if the target is a value very

near the MACT limit.

Cost ComparisonIn addition to compliance risk, it’s also im-

portant to understand the costs associated

with each of the three approaches described.

Table 2 provides a comparison of the three

options for demonstrating compliance with

the PM standard.

Each of these approaches has advantages

and disadvantages that must be considered

when determining a MATS compliance

strategy. Working with an expert air pollu-

tion monitoring firm allows fossil fuel–fired

power generators to develop a compliance

strategy based on sound measurement data.

Prudent power generators will capitalize on

the choice that the MATS regulations provide

when determining compliance. The source

can select a surrogate for a class of HAPs

(acid gases and non-Hg HAP metal). The

source can then choose if it wants to comply

by using manual testing methods or a pollut-

ant monitor and, in the case of using PM as

a surrogate for non-Hg metals and using a

PM monitor to demonstrate compliance, the

owner can choose how to use the PM moni-

tor—as a CEMS or a CPMS.

The success of any compliance strategy is

proven over time. As more data are generated

and operators understand how fuel variations

and operating parameter changes affect the

compliance status of a unit, the compliance ap-

proach and strategy for a facility will be refined.

The U.S. industrial and regulatory com-

munities are investing heavily in the goal

of reducing power plant HAP emissions

through MATS. This investment and subse-

quent operating history may be creating the

road map for other countries to accomplish

the same goals. ■

—Rick Krenzke ([email protected]) is a project director in TRC Com-

panies Inc.’s Air Measurement Services Practice in Austin, Texas.

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PM monitors must be evaluated for each source over a range of operating conditions.



Emissions Catalyst Issues for Fast-Start Combined Cycle Power Plants

Traditionally, many combined cycle gas

turbine (CCGT) power plant units were

designed and permitted for a baseload or

similar operating profile. Startups and shut-

downs were expected but typically were in the

tens per year. These were often an equal com-

bination of cold, warm, and hot starts.

Lower total demand in many markets,

coupled with higher fuel prices, resulted in

many units needing to change to two-shift

cycling service. Plants would shut down for

a few hours overnight and then start to meet

daytime loads. Units with 200 to 250 starts

per year were not uncommon.

Not only did frequent starts stress plant

systems and components with respect to ther-

mal loads, but operational issues such as con-

trol of steam temperatures and water and gas

side chemistry also became more difficult.

Furthermore, regulators began to pay more

attention to higher stack emissions during

frequent startups. More recently, higher use

of renewables such as wind and solar gen-

eration created a demand for fast-responding

backup and reserve capacity.

In response, suppliers began to offer

fast-start CCGT plants to meet this demand

with equipment specifically designed for

fast start and loading. Existing plants began

to implement extended range burners in the

GT systems so that lower unit loads could be

maintained while in emissions compliance.

Some plants could shift from two-shift cy-

cling to a low-load parking condition.

Figure 1 compares the operating profile of

a conventional combined cycle baseload unit

with that of a modern cycling unit.

Figure 2 shows operating data for a large

combined cycle frame turbine unit. Load

swings of 50% in less than 30 minutes are

common several times each day to meet de-

mand requirements. Also common are daily

shutdowns during periods of low demand, of-

ten during daytime hours, when renewable en-

ergy such as solar is available or at night when

combined heat and power demand is reduced.

Key Features of Fast-Start and Extended Range CCGT PlantsFast-start plants rely on rapid start and loading

of the GT to reach full power as well as com-

pliant emissions status for the combustors.

This rapid loading puts large amounts of hot

gas into a relatively hot/warm/cold heat recov-

ery steam generator (HRSG). The HRSG then

begins to increase steam pressure and flow

with heat-up. This flow increase lags the GT

ramps and challenges the limits on pressure

rise in the high-pressure steam system. Both

flow and temperature of the produced steam

are controlled/bypassed to meet the initial

conditions of the steam turbine startup.

The turbine exhaust gas (TEG) condi-

tions from the turbines reflect the lower ef-

ficiency at part loads with higher exhaust

temperatures. These temperatures can make

it difficult to control steam temperatures with

sprays or other attemperation methods such

as steam bypass or dilution air.

For recirculating evaporator plants with

steam drums, pressure ramps are typically

set by the allowed thermal stress imposed on

the steam drum. High-pressure (HP) steam

drums can be from 5 to 7 inches thick, de-

pending on size and maximum design pres-

sures. This thick steel wall can easily have

large thermal stresses as the interior surface

heats up or cools down. Control of pressure

by bypass or other venting is the method of

moderating the thermal stress. Lower pres-

sures produce lower saturation temperatures,

which result in lower TEG temperatures at

the NOx catalysts. This tends to produce a

temperature lag at the catalyst during startup.

For HRSGs with once-through HP steam

generators, feedwater flows once through econo-

mizer, evaporator, and superheater segments of

the same tube flow path. There is less thermal

mass in the HP evaporator segments and no

steam drum. Fast-start plants often use once-

through sections for this reason. For these plants,

temperatures at the NOx catalysts approach tar-

get temperatures faster during startups.

Low-Load Parking PlantsMost CCGT units with new extended range

turbine systems can decrease GT load to

about 40% of full power. TEG temperatures

are often greater at the inlet to the HRSG,

but mass flow is considerably reduced.

Drum pressures are usually regulated at the

floor pressure of the system (typically 1,000

to 1,200 psig). These set a floor for tempera-

tures into the catalysts of 550F to 570F. Op-

eration of emissions controls at lower mass

flows must be carefully controlled to avoid

excessive ammonia slip.

Some GT systems like the Alstom GT24/26

with sequential combustion can go to very

low loads (10% to 20% of full power). This

can produce low TEG temperatures at the HP

evaporator exits. Figures 3 and 4 (see the on-

line version of this article at powermag.com)

show the temperature profile at full load and

at parking load of a GT26. Temperature at low

load is 520F. This plant was in a jurisdiction

not requiring emissions catalyst, but this tem-

When gas-fired plants are required to cycle more than they were designed for, added stress on plant components isn’t the only consequence. You also need to pay closer attention to turbine catalyst systems.

David S. Moelling, PE and Daniel W. OttCourtesy: Gail Reitenbach




perature and low mass flows could be an issue

for current catalyst designs.

Challenges for Emissions Catalyst OperationCatalyst-based systems for control of CO,

NOx, and volatile organic compounds (VOC)

are strongly affected by the conditions of the

turbine exhaust gas. Oxidation catalysts are

passive catalysts used to oxidize CO and VOC

to CO2. Selective catalytic reduction (SCR)

systems are active catalyst systems that re-

quire injection of a reagent containing ammo-

nia (NH3) to reduce NOx to N2 and H2O.

Prior to 2001, turbine catalyst systems were

designed primarily for steady-state, basel-

oad operation. These systems had generous

startup/shutdown windows, normally of 1 to

3 hours, and typically operated above 80% of

maximum load. Between 2001 and 2005, the

startup/shutdown windows were reduced to

30 to 60 minutes. Today, these systems can be

required to start up or shut down in 10 min-

utes, while at the same time dealing with more

frequent cycling, faster ramp rates, and wider

load swings than ever before.

As a unit cycles, the temperature, flow rate,

and concentration of emissions in the turbine

exhaust entering the SCR/CO catalyst system

vary. Exhaust temperatures will often depend

on the pressure and steam production in the

HP steam system and can vary by +/–100F en-

tering the catalyst system. Also, because the

lower-load operation introduces lower flow

into the same fixed cross-section, the flow dis-

tribution differs from baseload, imparting gas

velocity, ammonia concentration, and temper-

ature variations at the catalyst inlet.

Turbine exhaust NOx and CO also spike

during load changes, which can affect the

stack emissions and require greater emis-

sions reduction to maintain compliance

during short averaging periods. Maintain-

ing peak SCR system performance and low

levels of both stack NOx and ammonia slip

through these cycles requires precise control

of ammonia injection. In some cases this may

require updates to the ammonia flow control

logic or even upgrades to the equipment and

additional monitoring hardware.

An example of SCR operation with turbine

cycling is shown in Figure 5. The variations

from cycling operation are most apparent in the

ammonia slip (the unreacted ammonia), shown

in orange. Variations of 3 to 4 ppm are com-

mon. These variations in ammonia slip are most

often caused by a lag in response time of the

ammonia vaporization and injection system in

reacting to changing ammonia demands. Some

progress is being made to improve response

times, but more improvement is needed.

In the permitting phase for modern cycling

unit sites, permit applications must take into

account these variations, but they currently do

not. Regulations at the state and federal levels

have reduced best available control technology

(BACT) guidelines for turbines to between 2

and 5 ppm NOx and 2 to 5 ppm ammonia slip,

both with averaging times as little as 30 minutes.

In ozone nonattainment areas, air permit limits

of 2 ppm NOx and 2 ppm ammonia slip are nor-

mal. These BACT limits required by regulations

are not practical in cases with cycling operation,

as illustrated in Figure 5.

Fast-start combined cycle systems are ca-

pable of startup in 10 minutes. Conventional

SCR/CO system designs have demonstrated

startup in approximately 30 minutes. Though

the difference of 20 minutes may seem small,

much happens in those 20 minutes, includ-

ing heating of the SCR catalyst and ammo-

nia vaporization system that are required for

optimum performance. Figures 6 and 7 com-

pare a conventional SCR system start (with a

1-hour startup window) to a modern fast-start

system (with a 10-minute start requirement).

Even with a warm start, the fast-start system

struggles to achieve compliance within 15 min-

utes. In many cases, particularly for cold starts,

SCR systems cannot meet, or have difficulty

meeting, the 10-minute startup requirement.

1. Conventional baseload vs. cycling operation. Courtesy: Environex Inc.

80

70

60

50

40

30

20

10

0

Op

era

tin

g h

ou

rs (

%)

Op

era

tin

g h

ou

rs (

%)

80

70

60

50

40

30

20

10

0

Below 60 60 65 70 75 80 85 90 95 100Load (% of baseload)

Below 60 60 65 70 75 80 85 90 95 100Load (% of baseload)

120

100

80

60

40

20

0

Ex

ha

ust

flo

w (

klb

/hr/

10)

Time (days)

60

50

40

30

20

10

0

Loa

d (

MW

/10)

an

d C

T e

xit

NO

x/E

xit

CO

(p

pm

vdc

)

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0

■ Exhaust flow (klb/hr/10) ■ Load (MW/10) ■ Turbine exit NOx (ppmvdc) ■ Turbine exit CO (ppmvdc)

Conventional baseload unit

Modern cycling unit

Time (days)

2. Typical cycling operation of a modern frame turbine unit. Courtesy:

Environex Inc.



To bridge this gap between conventional and

fast-start requirements, SCR system designs are

being modified to remove thermal mass, im-

prove response times of the ammonia injection

and continuous emission monitoring systems

(CEMS), and use modified catalyst products/

designs that can reduce start times. Even with

the modifications, 10-minute starts are often not

achieved in practice from the SCR/CO system

perspective, as shown in Figure 7. Some of these

modifications include:

■ Ammonia vaporizers with preheat capability.

■ Smaller ammonia vaporization chambers

without packing and with more heat trans-

fer surface to minimize heating time.

■ Catalyst designs that offer improved for-

mulations with wider operating tempera-

ture windows.

■ Catalyst frame/seal designs that allow for

more rapid temperature ramp rates.

■ CEMS systems and NOx analyzers with

faster response capability, as little as 5 sec-

onds compared to 30 to 120 seconds for

extractive sampling systems.

■ Improved controls systems that are more

capable of analyzing/predicting transients

in catalyst system performance.

■ In some cases, where practical, a return to

anhydrous ammonia systems to eliminate the

need to vaporize the water (up to 80% water

by weight) in aqueous ammonia solutions.

Modern emissions control systems are

required to convert a greater percentage of

emissions in engine exhaust, meet lower

stack emissions limits, and do so over short-

er averaging periods. All of these changes

require greater engineering and higher cost

for both new and retrofit systems. Opera-

tors of modern turbines need to provide ad-

ditional oversight and maintenance of their

emission control systems to ensure they

continuously provide reliable performance.

Integrated Fast-Start Management RequiredHigher ammonia slip and potentially greater

SO2 conversion in cycling and fast-start units

create additional challenges for control of

sulfur-bearing deposits in the colder HRSG

areas. Low-pressure evaporators and econo-

mizers are particularly at risk.

Both current cycling and high-cycling

fast-start units can be at risk. Units in reserve

or standby for rapid start can experience high

corrosion levels in fin tubes (Figure 8), as the

deposited material tends to be hygroscopic

and corrosive in humid environments. More

frequent cleaning of gas-side tube surfaces

may be required to prevent excessive back-

pressure and corrosion on HRSG systems.

Because the response of emissions cata-

lysts to fast startups is a key element in plant

performance and longevity, the HRSG, steam

cycle, and emissions control systems in cy-

cling and fast-start CCGT plants must be

considered as a single system with multiple

operational limits and goals. ■

—David S. Moelling, PE ([email protected]) is chief engineer for Tetra Engineering Group Inc. and Daniel W. Ott

([email protected]) is president of Environex Inc.

70

60

50

40

30

20

10

0

35

30

25

20

15

10

5

00 12 24 36 48 60 72 84 96 108

Time (hours)

Loa

d, a

mm

on

ia f

low

, SC

R t

em

pe

ratu

re

Sta

ck

NO

x, t

urb

ine

ex

it N

Ox a

nd

a

mm

on

ia c

on

ce

ntr

ati

on

■ Load (MW/10) ■ Stack NOx (ppmvdc) ■ Ammonia flow (lb/hr/10) ■ Turbine exit NOx (ppmvdc)

■ SCR temperature (°F/10) ■ Ammonia slip (ppmvdc)

5. SCR operation for a cycling turbine unit. Variations from cycling operation are

most apparent in the ammonia slip (the unreacted ammonia), shown in red. Variations of 3 to 4

ppm are common. Courtesy: Environex Inc.

60

50

40

30

20

10

00 10 20 30 40 50 60 70

■ Stack NOx (ppmvdc) ■ Ammonia slip (ppmvdc) ■ Turbine exit NOx (ppmvdc) ■ SCR temperature (˚F/10)

■ Load (MW/10)

7. Modern fast-start SCR system startup. Courtesy: Environex Inc.

6. Conventional SCR system startup. Courtesy: Environex Inc.

60

50

40

30

20

10

00 10 20 30 40 50 60 70

■ Stack NOx (ppmvdc) ■ Ammonia slip (ppmvdc) ■ Turbine exit NOx (ppmvdc) ■ SCR temperature (˚F/10)

■ Load (MW/10) ■ Stack CO (ppmvdc)

8. Bad environment. Units in reserve

or standby for rapid start can experience high

corrosion levels in fin tubes, as shown here,

because the deposited material tends to be

hygroscopic and corrosive in humid environ-

ments. Courtesy: Tetra Engineering Group Inc.

Time (minutes)

Time (minutes)



Circulating Fluidized Bed Dry Scrubber Effectively Reduces Emissions

Like many coal-fired power plants in

the early 2010s, the Big Stone Plant in

eastern South Dakota was faced with a

question: What should be done at the plant in

order to meet new federal and state emissions

requirements? Its 40-something-year-old de-

sign would need an air quality control system

(AQCS) upgrade if it intended to continue

operating in the future. Choosing what tech-

nology to install was a key decision. In the

end, Big Stone’s decision-makers opted for

circulating dry scrubbing technology rather

than selecting a wet scrubber or more “tradi-

tional” dry scrubber design.

“The comfortable thing to do would

have been to choose the technology that

has been around for decades,” said Kirk

Phinney. “But we did our homework and

concluded that a circulating dry scrubber

would help us well into the future. Today,

we have one of this industry’s top-perform-

ing retrofit units in terms of SO2 reduction.

We know we made the right decision.”

Phinney was the commissioning manager

for the Big Stone AQCS project (Figure 1).

He transferred to Big Stone in the hope of

being part of the undertaking—a nearly $400

million investment—and quickly became

a vital member of Project Manager Mark

Rolfes’ team.

The first step for Rolfes was to obtain

permits and approvals from the three states

that regulate the Big Stone Plant (Minnesota,

North Dakota, and South Dakota). Phinney

set to work during that time helping review

all the specifications and layouts, gathering

operating data, and meeting with technology

suppliers in order to obtain accurate bids for

the project. He later supported the construc-

tion phase and served as commissioning

manager.

“It has been very exciting to be involved

with the project all the way through,” Phin-

ney said.

Phinney’s employer, Otter Tail Power

Co., is the majority (53.9%) owner of Big

Stone, with NorthWestern Energy and Mon-

tana-Dakota Utilities also holding shares.

Otter Tail people staffed the project and op-

erate the 495-MW power plant, which burns

subbituminous coal and has been online

since 1975.

Deciding on the Best Available Retrofit TechnologyThe driving force for the project was the

need for Big Stone to meet upcoming fed-

eral regulations, including new mercury

standards and regional regulations to reduce

haze over Minnesota’s Boundary Waters

Canoe Area, a popular outdoor recreational

area. The existing air pollution control sys-

tem on the boiler was a baghouse—effective

at removing dust and particulates, but not

gaseous emissions or mercury. After doing a

thorough evaluation of the best available ret-

When owners of the Big Stone Plant researched air quality control system technology, they considered all available options and eventually settled on a design that was not in widespread use. Now that the three-year $384 million project is complete, they have no regrets that they chose a circulating fluidized bed dry scrubber.

Robert Puhr

Courtesy: ANDRITZ


July 2016 | POWER www.powermag.com 35July 2016 | POWER www.powermag.com 35

rofit technology, Big Stone’s management

decided to pursue a dry scrubber (shown in

the opening photo).

“Flue gas cleaning with a dry scrubber is

today an attractive alternative to wet scrub-

bers, even for large coal-fired boilers,”

said Paul Petty, director of Applications

and Technology for ANDRITZ’s air pol-

lution control business in North America.

“It was impossible to make that statement

when I started in the business. But much

has changed.”

Spray dry absorber (SDA) technology

had been the traditional dry scrubbing solu-

tion for power plants requiring large SO2 re-

moval rates. The downside of SDA systems

is the potential for corrosion due to the cre-

ation of lime slurries and the need to quickly

dry the slurry droplets in the scrubber ves-

sel. Another drawback is that SDA systems

are able to remove only about 85% to 95%

of the SO2.

“Plants today are looking to remove 98%+

which, before the advent of circulating dry

scrubbing technology, was only possible with

much more expensive wet scrubbing technol-

ogy,” Petty said.

“The most important advantage of circu-

lating dry scrubbing is the ability to achieve

this 98%+ reduction of SO2 and other acid

gases,” Petty continued. “Other important

benefits are a lower capital cost, simpler

design, lower water use, no wastewater dis-

charge, and the ability to remove all pollut-

ants, except carbon monoxide and nitrous

oxides, in one step.”

“We went through a very rigorous process

to evaluate the technical offerings,” Phin-

ney said. “Our evaluation concluded that the

circulating dry scrubber had further room to

perform than the SDA and would not put us

at the limits of the technology.”

In evaluating suppliers, it came down to

experience. “ANDRITZ had six installations

at that time—not a huge number, but enough

for us to feel confident,” Phinney said. “The

other supplier had one.”

The Circulating Fluidized Bed ScrubberThe way the system works is by direct-

ing flue gas into the bottom of a circulat-

ing fluidized bed (CFB) vessel, where it is

turned upwards and passes through a grid

of venturis. Hydrated lime and recirculated

byproduct is introduced below the venturis

and gets evenly mixed and dispersed into

the flue gas.

Cooling water spray (which can be waste-

water from boiler blowdown) is added above

the venturi section, independent from the

reagent feed. The byproduct is collected

downstream in a pulse jet fabric filter (Fig-

ure 2) and then metered to recirculate some

back into the scrubber vessel (Figure 3). The

remainder is diverted into the ash-handling

system for disposal.

ANDRITZ’s project scope included sup-

plying the 34-foot-diameter CFB scrubber,

gas humidification system, reagent system,

gas recirculation system, byproduct recircu-

lation/removal system, pulse jet fabric filter

(Figure 4), powder-activated carbon injection

system for enhanced mercury capture, and

waste ash removal and storage system. The

company also supplied ductwork, piping, ac-

cess points, platforms, logic for the distrib-

uted control system, and support steel for the

scrubber and lime silo.

“In simple terms, the contract we had with

Big Stone was for everything above the foun-

dations for the scrubbing and waste ash han-

dling,” said Scot Ojard, project manager for

ANDRITZ.

One twist at Big Stone was that the CFB

scrubber needed to be a dual-train configura-

tion due to its size. The practical limit for a

single train is around 400 MW. This was the

first dual-train installation in North America

for ANDRITZ.

1. Big Stone Plant’s air qual-ity control system. (Left to right) Erik

Fladhammer, project engineer; Kirk Phinney,

commissioning manager; and Scot Ojard,

ANDRITZ project manager, with part of the

circulating dry scrubber and pulse jet fabric

filter in the background. Courtesy: ANDRITZ

2. Removing particulate. Fly ash and byproduct from the circulating fluidized bed

scrubber is collected in the pulse jet fabric filter hoppers, shown here. Courtesy: ANDRITZ



“Supporters of SDA technology told us

that we would have problems with the dual

fluidized beds fighting each other and the

induced draft fans fighting each other and

things would be out of sync,” Phinney re-

called. “I can tell you that has not been the

case.”

A Team Effort“There has never been a worry during this

project,” said Erik Fladhammer, project

engineer for Otter Tail. “It has been a very

good relationship. The discussions have al-

ways been open. Scot and his team came up

through the technical side. Their suggestions

are practical and it is clear that these guys

knew how to build and run scrubbers.”

Construction began in spring 2013. The

plant was taken offline in early 2015 for a

planned outage to do all the tie-ins and ex-

tensive boiler work to increase the surface

area. “When we came back online, we moved

along quite well,” Phinney said.

“During the commissioning process, we

used our newest computational flow dy-

namic model studies to optimize the turn-

ing vanes at the bottom of the scrubber

inlet to improve the dispersement of recir-

culated byproduct materials. This improves

Big Stone’s ability to run efficiently at low

loads,” Ojard said. “Since then, the custom-

er has taken over operations and signed all

acceptance certificates.”

“ANDRITZ gave us excellent perfor-

mance guarantees for SO2 removal, availabil-

ity, and lime consumption,” Phinney said. “If

I had to do it all over again, I would do it the

same way and with the same suppliers. The

people are technically smart, practical, and

no-nonsense. They fit the company personal-

ity at Otter Tail very well, and we did good

work together.”

Although Otter Tail wasn’t willing to re-

lease actual scrubber performance data, the

company did acknowledge that Big Stone’s

uncontrolled monthly average SO2 emission

rate in 2014 was 0.910 lb/MMBtu. It said

the ANDRITZ-supplied equipment has had

no problems meeting the plant’s current per-

mit limit of 0.09 lb/MMBtu. Otter Tail also

reported that the equipment met all perfor-

mance requirements during its recently com-

pleted 120-day guarantee run, and that the

plant has met all NOx and mercury emissions

requirements.

“The original budget was over $400 million

for the project,” said Rolfes. “The upgrade is

now expected to close out 21% below the bud-

get due to our procurements and engineering

work coming in below anticipated cost. Plus,

we have been able to reduce the contingency

reserves. That is good news for our customers,

owners, and shareholders.”

Opting for circulating dry scrubbing

technology turned out to be the right choice

at the right time. With its new AQCS, the

Big Stone power plant has reduced emis-

sions of NOx and SO2 by about 90% and

mercury by about 80%. The project allows

the plant to be a viable power resource well

into the future. ■

— Robert Puhr is principal of Ad Hoc Communications Inc.

4. Puffing bags. The air reservoir and pulse valves for the pulse jet fabric filter bag cleaning

system are shown here. Courtesy: ANDRITZ

3. Scrubbing emissions. This image shows the scrubber vessel’s waste ash pickup

point, including the fluidizing air ring and ash transport lines. Courtesy: ANDRITZ



Real-Time Environmental Data Integration Improves Air Quality Reporting

The electrical power generation sec-

tor is reportedly the largest source of

greenhouse gas emissions in the U.S.

As such, it is the focus of the Environmen-

tal Protection Agency’s (EPA’s) Clean Power

Plan, part of the president’s larger, ambitious

Climate Action Plan to reduce carbon emis-

sions. The two clearly demonstrate a trend of

environmental regulations that place a high

level of importance on the quality of the un-

derlying data, not just on emissions values

that are reported. This means increasingly

stringent reporting requirements and more

data collection.

Increasing Demand for Quality DataThe Acid Rain Program (ARP), established

in the amendments to the Clean Air Act in

1990, created the world’s first large-scale

emissions trading system. Designed to re-

duce sulfur dioxide and nitrogen oxides

(NOx) from electric generating units (EGUs),

this program used a market-based, cap-and-

trade approach for achieving reductions. The

goal of the program was to allow individual

companies to determine the pace of necessary

modifications for compliance that met their

specific business needs. They could either

spend money for emissions control devices

or defer installation and purchase allowances

from companies that had already achieved

reductions through their capital expenditures.

Regulations known as New Source Per-

formance Standards (NSPS), defined under

Title 40 in the Code of Federal Regulations

(CFR) Part 60, previously existed for EGUs.

This part initially governed the quality assur-

ance (QA) checks of instrumentation used to

measure the concentration of pollutants. The

EPA recognized that the transformation of in-

strument data from monitoring into a finan-

cial instrument suitable for allowance trading

required a new level of detailed reporting and

data QA.

For this reason, the EPA created a new

set of regulations for allowance trading

programs that governed the level of QA

checks and the required reporting level for

data streams that were used in the genera-

tion of market-quality data. 40 CFR Part

75 incorporated many facets of Part 60 but

expanded the number of quality checks on

the instruments. It also augmented the focus

of QA checks beyond the emission monitor-

ing instruments to include checks on other

types of instruments such as flow monitors

providing additional data needed for calcu-

lating emissions.

Existing NSPS regulations focused on

reporting periods of noncompliance and the

steps taken to correct the underlying issues.

Part 75 increased the requirements to include

the submission of all data at an hourly fre-

quency, not just noncompliant periods.

NSPS required EGUs to report times

when instrumentation readings could not be

considered statistically accurate. Part 75 re-

quired EGUs to report increasingly higher

emissions based on the length of time it takes

to return their monitoring equipment to prop-

er working order.

Due to the massive amount of data that

must be collected, the EPA has developed an

electronic reporting platform, the Emissions

Collection and Monitoring Plan System, to

collect a comprehensive set of emissions as

well as supplementary information such as

As power plant reporting requirements for emissions regulations increase in number and complexity, yesterday’s data collection and reporting systems can make the job harder than it needs to be.

Philip Black, PE

Courtesy: Wood Group



records of every test (completed and failed)

along with facility-specific monitoring plans.

While at times optional in the past, all utili-

ties are now required to submit their data

electronically, which is available for public

review.

Part 75 has proven to be a successful

model to ensure data quality. Consequently,

additional, non-EPA regional market-based

programs such as the Regional Greenhouse

Gas Initiative, Western Climate Initiative,

and the California Air Resources Board refer

to Part 75 data requirements.

The scope of Part 75 is not static. As the

number and types of parameters to report ex-

pand, the level of QA checks and documenta-

tion expands as well.

Problems Caused by Increased Data CollectionThis trend toward increased reporting pa-

rameters continues to grow, placing an

enormous burden on facility environmental

departments. The volume of data that needs

to be collected, aggregated, and reported to

satisfy requirements is staggering. Even

a small electric power facility (of around

100 MW) requires more than one million

complex calculations daily from its air

emissions monitoring sources within its

property boundaries.

Due to the amount of high-frequency data

that has to be reported, data acquisition and

handling systems (DAHS) were developed

and have been directly connected to environ-

mental analyzers located within the process

control network to provide the capabilities

for generating electronic reports. Due to the

locations of the monitoring systems at the

units throughout the facility, control room

operators are typically responsible for moni-

toring real-time compliance, with environ-

mental staff managing the regular reporting

and providing any necessary updates to man-

agement.

Although large amounts of data are pro-

cessed and stored at each monitoring loca-

tion, integration capabilities are lacking at

many facilities. Commercial DAHS have

existed since the beginning of the ARP and

track compliance to generate necessary fed-

eral reports for the unit where they are de-

ployed. However, due to the varying age of

monitoring equipment and the different man-

ufacturers of systems that can be present in

any given facility, a lack of integration leaves

many environmental departments gathering

data manually into Excel spreadsheets for

any unique corporate or state requirements.

This can often be the protocol at small and

midsize facilities. Complex macros or time-

consuming manipulation can be required to

aggregate the results. After the data collec-

tion and manipulation are completed and

passed to others, the spreadsheets are then

stored on network drives or within email

archives, where they become useless for fur-

ther analysis.

There are limitations to the effectiveness

of these traditional methods. As new regu-

lations are released, it becomes even more

challenging for environmental departments

to keep current in their coordination with

operations. Rather than becoming more ef-

ficient, aggregation of information from

multiple continuous emissions monitoring

systems using different protocols increases

with the growth in specialized emissions

monitoring systems. Due to the larger va-

riety of systems, some facilities even find

it easier to request their own data from the

EPA or third-party sources rather than try-

ing to gather significant amounts of infor-

mation from their multiple facilities. This

limits the flexibility and use of the informa-

tion that is available.

Environmental departments are not the

only groups struggling with the need for bet-

ter transfer of information. Larger market

forces such as deregulation have also led

to the necessity of establishing methods to

share many types of data that formerly never

left internal company networks. To help fa-

cilitate broader-based data sharing, many

large power generation facilities are develop-

ing centralized information storage reposito-

ries. These systems are designed to interface

with multiple data sources, consolidate the

information, store it efficiently, and then dis-

seminate it as needed in a format suited for

specific audiences.

Unfortunately, the creation of interfaces

of environmental data to these systems has

been slow, and the information remains in

silos, only to be retrieved for compliance

monitoring. The stumbling block has been

a lack of real-time connectivity between

multiple systems storing environmental

data and the environmental departments and

management.

Integration AdvantagesThe growing awareness of the value of Part

75–related environmental data, combined

with the lack of connectivity between sys-

tems isolated on the process control net-

work, has led to the increased adoption of

middleware solutions. Some DAHS vendors

are creating cloud-based portals that receive

the information from multiple instances of

their monitoring tools in order to provide a

combined view of compliance. Larger utili-

ties have leveraged their existing informa-

tion systems to provide wider access. These

custom solutions are typically based on con-

necting data historians (such as OSISoft PI)

to the Enterprise Reporting Planning solution

using commercial middleware packages such

as Microsoft’s BizTalk.

In other cases, facilities with strict data se-

curity requirements or those facing resource

constraints are considering a third option.

These solutions, currently being used in the

refining and petrochemical industry, are opti-

mized for the long-term storage and efficient

transfer of environmental data. Referred to

as real-time environmental data management

systems (RT-EDMS), these solutions act as

custom middleware that provides convenient

interfaces to multiple external systems.

They also allow the processing of data

based on unique environmental reporting

procedures with custom notification capabili-

ties. RT-EDMS serve as the bridge between

islands of data contained within multiple

DAHS. They enable the retrieval of data by

users from multiple locations who might oth-

erwise be restricted from connecting to infor-

mation stored on the control network. They

also provide information in a format acces-

sible to wider platforms (Figure 1).

RT-EDMS have been successfully field-

proven in many refining and petrochemical

facilities. Users of these systems have consis-

tently shown reductions in time spent com-

piling custom reports by as much as 90%.

While large power generators might have

sufficient resources to develop custom solu-

tions for complete electronic reporting, our

research indicates that small to midsize gen-

erators (of about 1,000 MW capacity) can

especially benefit from these specialized

systems in three distinct ways: enterprise

awareness, anywhere access, and advanced

analytics.

Expanded Awareness Across the En-

terprise. Environmental groups and regula-

tory agencies are not the only stakeholders

1. Multiple data and access points. Real-time environmental data man-

agement systems (RT-EDMS) serve as the

bridge between islands of data. Courtesy:

Wood Group



requiring timely information. While plant

operations staff typically have good visibility

of real-time compliance information at their

facility, corporate environmental staff and

executives don’t always have direct access.

They are forced to request spreadsheets with

the information from sites. If they need data

from multiple facilities, the same information

frequently arrives in different formats. The

result is that custom reports contain the mini-

mal amount of data in aggregate form only.

The time it takes to consolidate the informa-

tion limits the ability to provide on-demand,

up-to-date data.

An efficient data management and integra-

tion solution like an RT-EDMS allows every

audience to access and analyze the entire da-

taset. Groups that track NOx allowances to

evaluate the need to buy or sell offsets can

instantly access the most recent information

without forcing a specific request (Figure 2).

Allocations can be evaluated across multiple

facilities to more easily make allowance trad-

ing decisions. Employees in operations who

field requests for data do not have to spend

valuable time trying to gather information

that may not be directly useful to them. Com-

prehensive information requests from regula-

tory agencies become less time-consuming to

respond to.

Access to Critical Information from

Anywhere. With the increased amount of

time many people spend away from their

computers, it becomes more important to

provide information in a manner that is eas-

ily accessible and in a format that can easily

be consumed on smaller devices. This is es-

pecially true for field technicians who rotate

among remote facilities. With better connec-

tivity comes the ability to monitor instrument

issues and review warnings to determine if

an immediate trip is necessary or if the is-

sue can be addressed during the next planned

shutdown.

The benefits extend to management as

well. As the trend toward mobile devices in-

creases, having access to software installed

only on a desktop PC significantly limits

the attention that is given to environmental

information. Environmental information on

mobile executive dashboards with current

status, drill-down capabilities and historical

summaries is important to maintain a high

awareness of the importance of environmen-

tal performance. Having that information

within familiar tools further facilitates regu-

lar review.

Ability to Leverage Advanced Ana-

lytics Technology. The exposure of a con-

tinuous compliance historical data record

from all units across multiple facilities

to business intelligence tools opens the

possibility of exploring new techniques

to find hidden causes of recurring prob-

lems. From surveying EGUs, we found

that fewer than 25% of large, midsize, and

small utilities provide any environmental

information directly to outside software

packages. The ones that do primarily ex-

pose mass emissions to limited groups for

allowance projections.

The ability to analyze the results of every

QA/QC test on all instrumentation opens up

possibilities of identifying trends before they

become a problem, alerting management and

the responsible department. Combining this

information with predictive maintenance sys-

tems provides another way to more efficient-

ly identify problems with equipment.

Identifying Specific ValueTo determine if facilities can achieve these

benefits with an implementation of RT-ED-

MS software, it is reasonable to first answer

these questions:

■ Is there a lack of connectivity between

systems? Reporting can be instantaneous,

comprehensive, and available for wide-

spread use with an RT-EDMS. Calculating

the number of current data requests and

the time required to produce them can pro-

vide one way to monetize the benefit of an

RT-EDMS.

■ How many systems need interfacing,

and what is the age of each system? In-

formation from older and legacy equip-

ment, especially at small EGUs, can be

more challenging to gather. Investing in

integration quickly reduces the report-

ing effort.

■ Are there additional reporting require-

ments beyond those required by Part 75

that are difficult to meet with existing

systems? Is there some equipment in the

facility where exclusive Part 60 reporting

is still important? How difficult to un-

derstand is any logic embedded in Excel

macros that were developed to meet those

unique requirements? With the increasing

movement of talent and resources, knowl-

edge needs to be embedded in systems that

are easily understood by others who were

not the initial creators.

■ Has there been a history of enforcement

actions by regulatory agencies? To re-

spond to the increased scrutiny and scope

of regulatory audits, better reporting soft-

ware and systems can offset future penal-

ties and improve plant safety and relations

with the community.

As the EPA and other regulatory agencies

continue to augment their reporting require-

ments and enhance the frequency and scope

of their audits, data volume increases and

consistency is required. The necessity of im-

plementing a transparent, real-time, and fully

integrated system becomes more imperative.

In addition to the reporting agencies, this ap-

proach better serves facility employees, man-

agement, and the public. ■

—Philip Black, PE ([email protected]) heads the environmental

practice for Wood Group Mustang, a full-service consulting and systems integra-tion firm, where he has helped develop the company’s ENVision environmental

management and analytics software suite.

2. Dashboard convenience. A real-time environmental data management system can

provide multiple users with clear access to data from multiple facilities. Courtesy: Wood Group

www.powermag.com POWER | July 201640 www.powermag.com POWER | July 201640


Weighing the Environmental Impacts of Wind and Solar

Iceland might be about the last place you

would look for innovation in solar energy,

but if so, you’d be missing something

significant—and it concerns Iceland’s own

energy supply, as you’ll soon see. But first,

some background.

Solar energy is often hailed as the most en-

vironmentally benign source of electricity, and

once a solar plant is in place, this is arguably

true. But getting there has more environmental

impacts than you might think. And it starts with

the silicon that forms the substrate of the most

common types of solar photovoltaic (PV) cells.

Silicon is one of the most common ele-

ments in Earth’s crust—about 90% of which

is composed of silicate minerals—but pro-

ducing elemental silicon pure enough for

solar PV cells is no simple matter. For one

thing, it requires an enormous amount of

electricity—roughly half of the energy re-

quired to produce a PV cell is consumed in

the silicon manufacturing process. Metal-

lic silicon is typically produced by reacting

high-purity silica sand in an electric arc fur-

nace, which can require as much as 120 kWh

per kilogram of elemental silicon from input

to final product. To the extent that electricity

is produced with fossil fuels—consider all

the PV panels manufactured in China, where

coal is the number one generation source—

it can negate some of the carbon avoidance

from solar energy.

Second, turning raw silicon into finished

wafers pure enough for solar cells involves a

number of toxic and corrosive materials. The

most common method for producing poly-

crystalline silicon, known as the Siemens

Process, involves converting elemental sili-

con into gaseous form and then growing the

silicon crystals through chemical vapor de-

position. This process requires hydrochloric

acid, and the resulting gas, trichlorosilane, is

toxic, explosive, and corrosive. The process

also produces silicon tetrachloride, another

toxic substance that must be recovered and

recycled. Several tons of silicon tetrachloride

are produced per ton of polycrystalline sili-

con, and though it can be recycled to produce

silicon and hydrochloric acid, the process is

difficult and expensive, so not all manufac-

turers perform it.

Reducing Toxic ByproductsConcerns about this process have been raised

in a variety of quarters, from both support-

ers and opponents of renewable energy. But

a San Jose–based company has developed a

completely different, much more environ-

mentally friendly method of producing solar

silicon that has the added benefit of costing

half as much as traditional processes and us-

ing one-third the energy.

Silicor Materials is planning a facility in

Renewable generation is usually characterized as more environmentally friendly than fossil fuels, and in many respects, that’s true. But there is a growing recog-nition that solar and wind generation have their own impacts, and an increasing number of manufacturers and generators are looking for ways to minimize them.

Thomas W. Overton, JD

Courtesy: Silicor Materials


July 2016 | POWER www.powermag.com 41July 2016 | POWER www.powermag.com 41

Iceland to make it happen. Why Iceland? The

island’s abundance of cheap hydroelectric

and geothermal power has made it a mecca

for metals processing despite its remote lo-

cation—the tiny nation in fact ranks 11th

worldwide in production of aluminum. And

it’s the aluminum smelting process that Sili-

cor uses to produce its silicon.

Silicor Chairman and CEO Terry Jester

explained the method to POWER. Rather

than using gaseous silicon, Silicor’s method

partners with the island’s aluminum smelters

to extract silicon from the aluminum smelt-

ing process, where silicon is viewed as an

impurity. Metallurgical-grade silicon is dis-

solved into an aluminum smelt, and the sili-

con will crystalize out before the aluminum

solidifies as the mixture is cooled (shown in

the header photo). The crystallized silicon

flakes still contain a coating of aluminum,

but this is then removed using hydrochloric

acid. Unlike traditional silicon production,

however, this process produces polyalumi-

num chloride, a nontoxic compound that is

used in water purification, among other pro-

cesses. The remaining silicon flakes are then

re-melted, and what little aluminum remains

forms a thin layer on top of the silicon ingot

that can easily be removed (Figure 1).

According to Michael Russo, Silicor’s

executive vice president of sales, marketing,

and commercial business development, the

factory is set to break ground in Grundar-

tangi, Iceland, this fall and will have a capac-

ity of 19,000 metric tons of solar silicon (all

of which has been committed to customers)

when it reaches full output in 2019. In ad-

dition to the environmentally friendly manu-

facturing process, its location in Iceland will

allow it to source 100% of its electricity from

renewable energy.

Raising AwarenessBut solar PV cells are more than just silicon.

The PV manufacturing process involves a

range of toxic substances such as hydroflu-

oric acid, and it produces substantial waste-

water and solid waste streams. Treating and

recycling that waste costs money, and there

have been examples of a few PV manufactur-

ers cutting corners by dumping wastewater

rather than treating it. In one widely reported

incident, protests over dumping outside a

Chinese manufacturer’s plant in 2011 turned

violent and the company later faced legal ac-

tion over it.

Concerns about these issues led the

Silicon Valley Toxics Coalition (SVTC), a

nonprofit organization that tracks environ-

mental impacts in the tech industry, to begin

publishing an annual scorecard ranking PV

manufacturers on the transparency and sus-

tainability of their manufacturing processes.

To achieve a positive score, the manufacturer

needs to support PV panel recycling, clear-

ly report emissions across its supply chain,

make efforts to reduce module toxicity and

use of heavy metals, and keep in place mod-

ern health and safety standards for its work-

ers, among other criteria.

Not surprisingly, scores since the SVTC

began the scorecard in 2010 have fluctu-

ated widely given the substantial number of

mergers, bankruptcies, and new companies

entering the field. And, since the scorecard

relies on self-reported data, manufacturers

that did not participate in the survey tend to

have low scores. Still, the scorecard shows

that at least some manufacturers are making

substantial efforts to reduce the impacts of

their manufacturing processes. Three major

companies—SunPower, SolarWorld, and

Trina—all achieved scores above 90 on the

2015 scorecard (see http://bit.ly/1PAHV1O

for the full list).

Other efforts to reduce solar PV impacts

include an embrace of extended producer re-

sponsibility (EPR). EPR is a term used for the

idea that the environmental costs of a product

throughout its life cycle should be reflected

in its market price, typically with some sort

of surcharge. (If you bought a computer re-

cently, you may have seen such a fee added

on to the purchase price.) While the Euro-

pean Union has an EPR scheme that funds

disposal costs for PV panels, no such scheme

exists in the U.S. However, the SVTC reports

that a number of panel manufacturers have

asked the Solar Energy Industries Associa-

tion to work on this issue.

Birds and Bats and Turbines, Oh MyUnlike solar PV cells, wind turbine manu-

facturing is relatively benign, or at least little

different in impact from traditional turbine

generators, since many of the same compo-

nents are used. Wind turbines using permanent

magnets require rare earth elements such as

neodymium, the extraction of which can have

serious environmental consequences because

of the acids used in refining and the frequent

occurrence of uranium and thorium in the

ores. However, the percentage of neodymium

going to wind turbine manufacturing is a small

component of worldwide demand for this ele-

ment, which is used in a wide variety of con-

sumer products as well as electric vehicles.

Much more controversial has been the is-

sue of bird mortality at operating wind farms

(Figure 2). Though the scope of the impact

has been heavily studied, the reported ranges

are quite large. Estimates of bird mortality in

peer-reviewed studies vary from wind farm

to wind farm, and range from 0 (that is, no fa-

talities were found) to as many as 10 or more

birds killed per turbine per year. Nationwide,

a 2013 study reviewing published data con-

cluded that 573,000 birds and 888,000 bats

were killed each year at U.S. wind farms in

2012, while another study in 2014 estimated

bird deaths at 140,000 to 328,000.

It is worth noting that generalized totals do

not give an accurate picture of the true im-

pact of bird mortality for a variety of reasons.

Deaths in different regions and over different

periods of the year have different effects on

the environment. Mortality rates for different

species are not clear, even though deaths of

different species also have different impacts.

For example, the loss of 10,000 sparrows will

have far less effect on the ecosystem than the

loss of 10,000 bald eagles.

1. Clean and clear. Silicor Materials

has developed a manufacturing process for

polycrystalline silicon that uses substan-

tially less energy with no toxic byproducts

by partnering with aluminum smelters. The

company is preparing to build a large factory

in Iceland that will begin operations in 2018.

Shown here are finished ingots of silicon.

Courtesy: Silicor Materials

2. Avian impact. This red kite was killed

by a wind turbine blade at the Montes del

Cierzo wind farm in Spain. Courtesy: Gurelur



Data suggest that migratory birds tend to

suffer the greatest mortality from wind tur-

bines, accounting for around 75% of all fa-

talities, according to several studies. Some

authors have suggested that deaths for these

species are underreported because these birds

tend to be small and their carcasses are more

easily scavenged and thus less likely to be

found during site studies. However, because

these species also represent some of the

largest bird populations, many studies have

concluded that these deaths are ecologically

insignificant, especially when viewed in con-

text with deaths suffered by collisions with

power lines, buildings, and other structures,

and predation by domestic cats.

On Wings of EaglesThough raptors (eagles, hawks, and related

species) make up a small portion of the to-

tal bird fatalities (the 2013 study mentioned

above estimated 83,000 per year), these

deaths are much more significant because

these birds are typically apex predators and

their population has a direct effect on a wide

variety of other species. Thus, it is not sur-

prising that wind turbine raptor deaths have

garnered most of the attention.

There is evidence that raptors are attracted

to wind turbines as nesting sites, and they are

likely more vulnerable to blade impact be-

cause of their habits of staying aloft longer

and floating on thermal patterns while hunt-

ing for prey. One oft-cited study estimated as

many as 100 or more raptors being killed at

the Altamont Pass Wind Farm in California

every year, though this high level of mortality

has not been seen at other wind farms.

Some studies have suggested that this dis-

parity exists because most of the turbines at

Altamont were constructed before bird mor-

tality was an issue considered during wind

farm development and little thought was

given to reducing risks. Studies have shown

that wind farm location can have a dramatic

effect on avian mortality, with poorly sited

projects killing far more birds than ones built

with more responsible planning.

Older wind farms tend to be higher density

than newer projects, grouping turbines much

more closely, which can increase avian risk.

Such farms are also more likely to have lat-

tice-frame towers instead of the monopoles

used by modern turbines, as well as above-

ground transmission lines (Figure 3), both of

which are known to attract birds.

Adjust Cut-In Speed to Cut MortalityThough the data are not extensive, there

is growing evidence that proper planning

and design can substantially reduce avian

mortality. A 2010 study from the U.S. Fish

and Wildlife Service (FWS) makes a num-

ber of recommendations (see http://1.usa.

gov/1OKpKgd). Among these are assess-

ing avian populations in the area during the

planning process, with particular attention

to nesting sites, migration routes/stopovers,

and the potential for fragmenting existing

habitats. Where such factors exist, other sites

should be considered. As specific sites are

identified, more detailed studies of potential

impacts are recommended, particularly of

species behavior in the area.

When building the farm, the study rec-

ommends placing turbines outside of areas

identified as crossing routes and using only

strobe lights that fire simultaneously rather

than continuous lighting. (This is to avoid at-

tracting insects that in turn attract birds and

bats. Several mass mortality events at wind

farms have been linked to the use of high-

intensity lighting.) Measures should also

be taken to avoid creating potential habitats

for prey animals such as rabbits and ground

squirrels, as these will attract raptors. During

operation, avian mortality should be moni-

tored and recorded, and in areas where sig-

nificant mortality is found, further mitigation

efforts should be explored.

One mitigation measure that has been

identified is increasing blade cut-in speed,

that is, raising the minimum wind speed at

which the turbine begins operating. Many

birds and bats are more active during periods

of low wind, and keeping turbines motionless

or at low speed in these conditions has been

shown to reduce mortality.

The effectiveness of deterrent devices

such as those that generate ultrasonic noise

is unclear. Some studies have shown reduced

bat mortality, but the data are not extensive.

Accordingly, the Department of Energy is

currently funding several studies, including

one by GE, of deterrent devices to determine

whether they could be effective in reducing

bat mortality.

Other approaches include using radar to

detect approaching birds and automatically

shutting down or slowing turbines, but the

effectiveness of this method is also not yet

known.

Meanwhile, the federal government is

struggling with how to regulate avian mortal-

ity at wind farms, since many avian species

killed by wind turbines—such as bald and

golden eagles—are protected by federal law,

and causing such deaths is normally cause

for prosecution. Duke Energy was fined $1

million in 2013 and PacificCorp was fined

$2.5 million in 2014, both for eagle deaths

in Wyoming, but enforcement actions have

otherwise been rare. (Duke has since taken

steps to reduce avian and bat mortality at its

16 wind farms, such as slowing down blades

in low wind.)

In 2013 the FWS issued a rule allowing

wind farm owners to apply for 30-year per-

mits to kill limited numbers of eagles (tech-

nically referred to as “incidental take”), a

regulation that was successfully challenged

in court by several conservation organiza-

tions. In May 2016, the FWS proposed a new

rule that would require active monitoring

and mitigation of avian mortality, with the

permits being reviewed every five years. The

proposed rule is open for comment through

July 5. ■

—Thomas W. Overton, JD, is a POWER

associate editor.

3. Double trouble. The San Gorgonio Pass Wind Farm north of Palm Springs, Calif., was

developed beginning in the 1980s. Its closely placed turbines (some with lattice-frame towers) and

above ground transmission lines can pose multiple threats to birds. Courtesy: Gail Reitenbach



Avoiding Wildlife Impacts from Renewable Energy in Europe

As more renewable energy systems come

online, providers hope to both make

money and protect the environment

simultaneously. However, some environmen-

tal scientists and conservationists are sound-

ing alarm bells over impacts that onshore and

offshore wind farms and new wave and tidal

energy systems may have on avian and marine

wildlife—in particular, birds, bats, whales,

dolphins, and other sea mammals.

There is empirical evidence that onshore

wind production has negative impacts on

birds and bats (see the article “Weighing the

Environmental Impacts of Wind and Solar”

in this issue). But a bigger unknown is how

increasing numbers of offshore wind devel-

opments will affect marine as well as bird

populations. Europe leads the world in off-

shore wind development, and plans are un-

der way to continue to ramp up. Including

offshore production, Europe’s installed wind

capacity could surpass 200 GW by 2020. In-

deed, worldwide, wind energy of all forms

is, well, blowing up. Though unquestionably

renewables are better for the environment

than fossil-fueled power plants, the enduring

struggle between economics and stewardship

is still part of the equation.

For maximum output and profitability,

wind farms are sited in open, exposed areas

where there are higher-than-average wind

speeds. This means that they are frequently

proposed in upland and coastal areas, poten-

tially affecting important habitats for breed-

ing, wintering, and migrating birds. In the

same way turbines utilize the kinetic energy

of the wind, birds often use that wind as their

propellant or even as “superhighways.” The

degree to which wind farms can safely co-

exist with avian life is still an unknown, es-

pecially as ever-larger wind turbines on- and

offshore are deployed.

Additionally, as humans keep develop-

ing coastal, tidal, and deep ocean regions,

the noises created during exploration and

development processes become highly am-

plified in the undersea environment. Many

species of marine life, particularly mam-

mals, depend heavily on sonar-like systems

to navigate, and those systems are greatly

affected by the sounds created during un-

dersea energy development and construc-

tion. In much the same way that dolphins,

porpoises, and whales have been affected by

undersea oil exploration, they are getting hit

again as both offshore wind, tidal, and other

marine renewable energy systems expand

(see sidebar).

But precisely because most of these ener-

gy systems are new, the extent of their actual

impacts is still relatively unknown. Without

much of an established body of peer-re-

viewed scientific research, environmentalists

and developers are just now creating baseline

study frameworks and guidelines for future

projects. Given Europe’s longer history with

renewable rollouts, a large portion of the pub-

lished research emanates from there. What

are some lessons that have been learned, and

what can renewable energy providers else-

where do to avoid the worst mistakes of their

pioneering predecessors?

Europe has been in the forefront of renewable energy development, and though the scientific research on wildlife impacts is limited, European envi-ronmentalists and developers are beginning to create baseline frameworks and guidelines. Developers around the world can learn from their experience.

Lee Buchsbaum

Courtesy: Ad Meskens/Wikimedia Commons



Wind Turbines Can Be Bird and Bat KillersAs one might expect, most of the impacts

of wind infrastructure are not due to direct

clearing of land or habitat loss but to bird and

bat collisions. Birds can be killed not only

from collisions with rotors but also by col-

liding with towers, nacelles, and associated

structures such as guy cables, power lines,

and meteorological masts. Estimates of bird

and bat collisions vary from site to site, de-

pending on the location, the technology used,

and the abundance of birds locally. Some

studies suggest that birds may be killed at a

rate of between three to five individuals per

MW per year, while bat collisions at some

sites are as common as 30 per MW per year.

However, the authors of a December 2014

European Commission publication entitled

“Science for Environment Policy Future

Brief: Wind & Solar Energy and Nature Con-

servation” (see http://bit.ly/1DkTGFl), cau-

tion that the number of bird deaths arising

from turbine collisions overall “represents a

tiny fraction of the total bird deaths caused by

humans: pet cats, windows and transmission

lines kill many more.”

Recent research suggests that newer-

generation turbines sited with appropriate

planning generally pose lower risks. How-

ever, comparisons between sites are difficult

because different sites have distinct avian

populations, and species composition and

behavior can affect the risks. In other words,

planners and site developers have to be care-

ful not to over-generalize. Each site requires

its own specific analysis.

Better Site Selection Is KeyThe consensus among European experts is

that the best solution for energy developers as

they seek to avoid wildlife impacts is likely

Tidal Power Draws Concern

Coming on strong are a variety of newly de-

ployed marine renewable energy systems,

or MRE technologies (Figure 1). Accord-

ing to “Environmental Effects of Marine

Renewable Energy Development Around

the World,” a report from Annex IV—a col-

laborative initiative of the Ocean Energy

Systems under the International Energy

Agency Technology Network (see http://

tethys.pnnl.gov/publications/state-of-the-

science-2016)—the world’s oceans have

the current technical potential to produce

9,100,000 GWh annually using established

MRE technologies for tidal, wave, and

ocean current extraction.

One of the main advantages of MREs

compared to wind and solar is that their

electrical output is more constant. With a

greater potential for reliability, there are

even greater profits to be made once the

system is operational.

Scotland, with its rocky, beautiful shore-

lines, fierce coastal winds, and huge bird

populations, is both a vast potential source

of tidal and wind energy and a significant

venue for avian conflict. Scotland is work-

ing with both Ireland and Northern Ireland

to construct one of the world’s first large-

scale marine renewable energy systems.

The Irish-Scottish Links on Energy Study

project is set to reach 6.2 GW by 2020. The

project, known as ISLES, will use all three

of the major marine renewable energy

sources—offshore wind, wave, and tidal—

and will provide much-needed data on the

technology and its effects on the environ-

ment (see www.islesproject.eu). Dozens of

different types of tidal energy prototypes

have been tested throughout the past de-

cade by Scotland’s European Marine Energy

Centre.

Because tidal energy is both so new

and potentially disruptive to marine life,

a group of researchers, environmentalists,

and stakeholders formed Annex IV to study

the environmental effects of marine renew-

able energy development. By sharing data

and synthesizing results through its State

of the Science reports, Annex IV hopes to

reduce risk for marine energy technologies,

avoid duplication of research and monitor-

ing efforts, promote sustainable develop-

ment of MRE technologies, and ensure that

accurate and up-to-date information is

available to regulators, industry members,

and scientists worldwide. (The comprehen-

sive report, however, sticks to MREs and

does not address the effects of offshore

wind.)

The 2016 report summarizes research

findings regarding the collision of marine

animals with undersea turbines. Other ar-

eas of study were the effects of underwater

noise from turbines and electromagnetic

fields from undersea cables used to carry

power. The consensus is that deployments

composed of single units are not expected

to harm marine life. The report also looks

at the health of seafloor habitats and

reefs, changes in sea flow patterns around

turbines, and biodiversity of marine eco-

systems. In addition, the report includes

four case studies on the long permitting

and consenting process that the first gen-

eration of MRE devices has encountered,

and it suggests areas for future marine en-

ergy monitoring and research.

1. The tide is rising. The 1.2-MW SeaGen tidal power system in Strangford Lough in

Northern Ireland, which began operations in 2008, was the world’s first commercial-scale,

grid-connected tidal stream turbine. Courtesy: Siemens



improved site selection, as the international

avian conservation group BirdLife reported

in one of its recent studies, “Meeting Eu-

rope’s Renewable Energy Targets in Harmo-

ny With Nature” (see http://bit.ly/1Y3FDjQ).

According to the BirdLife report, a use-

ful approach is mapping wind resources

(such as speeds and patterns) together with

maps of environmentally sensitive zones,

such as migration corridors and protected

wildlife areas. Doing so can create a prac-

tical tool for development decisions based

on the most extensive and up-to-date data.

These can also be useful for policy making

and planning.

Robust and objective baseline studies

are also necessary as part of this process to

minimize negative effects on birds, other

wildlife, and their habitats. They also support

post-construction monitoring at completed

wind farms where environmental concerns

exist. BirdLife and the European Commis-

sion studies state that, where at all possible,

energy providers should not develop in areas

with:

■ “High densities of wintering or migratory

waterfowl and waders, where important

habitats might be affected by disturbance,

or where there is potential for significant

collision mortality.”

■ “[A] high level of raptor activity, especial-

ly core areas of individual breeding ranges

and in cases where local topography fo-

cuses flight activity, which would cause a

large number of flights to pass through the

wind farm.”

■ “Breeding, wintering or migrat-

ing populations of less abundant spe-

cies, particularly those of conservation

concern, which may be sensitive to

increased mortality as a result of colli-

sion or more subtle effects on survival

and productivity due to displacement.”

When developers build their turbines,

BirdLife and the European Commission sug-

gest they:

■ “Group turbines to avoid alignment per-

pendicular to main flight paths and to pro-

vide corridors between clusters, aligned

with main flight trajectories, within large

wind farms.”

■ “Where possible, developers should install

transmission cables underground (subject

to habitat sensitivities and in accordance

with existing best practice guidelines for

underground cable installation).”

■ “Developers should mark overhead cables

using deflectors and avoid their use over

areas of high bird concentrations, espe-

cially for species vulnerable to collision.”

Another suggestion BirdLife has is that

wind producers halt turbine operations “dur-

ing peak periods of activity or during mi-

gration,” even though that means taking a

potential hit on income.

After the turbines have been sited, among

the best solutions to avoid accidental avian

deaths is the installation and usage of bird-

and bat-sensitive radar systems. Several

international manufacturers now provide

systems with supporting software that can

be used to scan the sky for large groups of

birds and bats and automatically shut down

turbines before flocks pass through genera-

tion areas. For older wind farms that have

been sited along migratory routes, this could

prevent bird formations from “sleep-flying”

directly into harm’s way.

Additional operational adjustments such

as changing the cut-in speed or the angle of

blades relative to the wind may also reduce

collisions. However, somewhat counterin-

tuitively, for birds with poor maneuverabil-

ity such as griffon vultures, it may be that

slower rotation speeds are more problem-

atic because the associated low wind speed

makes avoidance of the turbine blades more

difficult. On the other hand, according to

the European Commission report, data from

several studies suggest that bat collisions

are halved when turbine cut-in speed is in-

creased by 1.5 meters per second above the

manufacturer’s speed. “This may be because

bats are more active at lower wind speeds”

since the insects they feed on do not fly in

high winds.

Other Potential Impacts of Off-shore Wind FarmsBecause of its location in marine environ-

ments, offshore wind development brings

with it another set of environmental impacts.

Turbine foundation construction and under-

sea cable installations, as well as other steps

in the construction of high-capacity wind

farms, can generate high levels of noise

(Figure 2). The impact of noise on marine

mammals can be divided into three levels:

those that cause fatal injury; those that cause

non-fatal injury such as deafness and other

auditory damage such as “temporary thresh-

old shift”; and those that cause behavioral

change (such as avoidance and cessation of

feeding).

The focus should not solely be on avoiding

deaths, however. “A porpoise is doomed to

die if its hearing is shattered,” Kim Detloff, a

marine expert at German nature conservation

group NABU told Renewable Energy World

in a 2012 story. In Germany, comprehensive

noise control measures must be used dur-

ing the construction phase, especially when

foundation structures are driven into the sea-

floor. This is necessary to protect porpoises,

2. Boom times. Erecting offshore wind turbines can create substantial undersea noise

during the construction of foundations and driving of pilings, noise that can have harmful effects

on marine life. Proper mitigation efforts, such as air-bubble curtails, may be able to reduce those

impacts. Courtesy: RWE Innogy



which are sensitive to noise and protected by

animal conservation laws, as well as other

marine mammals. Regulators “must sanc-

tion developers if they repeatedly violate the

noise limit,” said Detloff.

While data demonstrate that construc-

tion will have effects on mammals and

fish, which can detect pile-driving noises

over considerable distances, there are very

few equivalent data available for birds.

Adequate avian ecological survey data is

generally still unavailable for most off-

shore areas, according to BirdLife. In order

to remedy this, they recommend, prior to

development, year-round baseline data col-

lection over a minimum of two years for all

affected bird species to cover breeding and

non-breeding distributions.

Mitigating Undersea Noise ImpactsEnvironmental best practices often trail de-

velopment, only evolving as real impacts are

actually felt. Beginning several years ago,

as German energy provider RWE AG began

construction of its massive Nordsee offshore

wind farm complex, the firm shifted to using

technologies that reduced noise from driv-

ing turbines into the seabed after conserva-

tion groups complained about impacts on

porpoises. RWE’s Nordsee Ost wind farm,

which has a capacity of approximately 295

MW, is one of the largest commercial wind

farm projects off the German coast. A total

of 48 Senvion wind turbines, each with a ca-

pacity of 6 MW, were initially installed. Cur-

rently the company is jointly developing the

next phase, the Nordsee One project. With 54

more wind turbines, Nordsee One will have

an overall capacity of 332 MW.

Recent news releases from RWE state

that the foundations for Nordsee One’s wind

turbines and the substation were recently

completed. The installation of the facility’s

main submarine cable is scheduled to begin

in June. The transformer substation at sea is

also slated to be installed during the summer.

Finally, the wind turbines are due to be in-

stalled in early 2017, and the wind farm will

then go into operation next year.

According to other published reports, dur-

ing the initial construction phase, RWE used

a large perforated hose to produce a curtain

of air bubbles around each of the first 48 tur-

bine foundations at Nordsee Ost. RWE has

also undertaken many onshore and offshore

ecological surveys to identify the location of

habitats and species of all the affected marine

and avian life that could be impacted by the

development. Extensive boat and aerial sur-

veys collected two years’ worth of data on

bird activity offshore.

“We have also completed one year of ma-

rine mammal surveys using a combination of

survey techniques,” RWE said in a statement.

“We have also collected over 10,000 hours of

continuous acoustic monitoring for marine

mammals from static moorings. In addition,

we have completed surveys for fish and other

marine species which live on, or within, the

seabed.” The survey data will be used in con-

junction with other existing data to establish

the ecology of the area.

No doubt, as development proceeds, many

more lessons will be learned as new regula-

tions are phased in. Now as the U.S. begins

development of its first large offshore wind

farm, operators in conjunction with their

Dutch partners have announced their intent

to draw on lessons learned throughout the

North Sea. �

—Lee Buchsbaum (www.lmbphotography.com), a former editor and contributor to

Coal Age, Mining, and EnergyBiz, has covered coal and other industrial subjects

for nearly 20 years and is a seasoned industrial photographer.

www.electricpowerexpo.com

The ELECTRIC POWER committee has issued an industry-wide call for participation for the 19th Annual

ELECTRIC POWER Conference + Exhibition, which will be held April 10-13, 2017 in Chicago, IL.

The conference committee is looking for case studies showcasing technologies, improvements, techniques and

experiences that provide solutions and improve operations for the power plant of tomorrow.

Do you have experience and insight to share on these topics?

u Solutions and lessons learned to increase power plant performance and profi tability

u New and proven solutions to meet environmental compliance guidelines

u Case studies on technology solutions or advancements

u Power plant resiliency—From performance management to cyber security and more

u Combined Heat & Power—Best practices shared

u Grid stability and integration experience or insights

If “YES” popped into your head while reading this list, we want

to hear from you!

Deadline for submission is August 12, 2016—go online

today and submit your abstract for consideration!

April 10–13, 2017

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PRB COAL

PRB Coal Users’ Group Plant of the Year: Ameren’s Rush Island Energy Center

“Without continual growth and progress,

such words as improvement, achieve-

ment, and success have no meaning,”

Benjamin Franklin once said. Franklin, in-

ventor and statesman, knew the value of im-

proving electricity systems and in the process

of his electricity experiments coined terms

such as “battery,” “charge,” “condenser,” and

“armature,” among many others. Franklin

began with an idea that would benefit so-

ciety (he never patented an invention) and

then slowly perfected the product. The best-

performing power plants, such as Ameren’s

Rush Island Energy Center (RIEC), reap the

rewards of following Franklin’s example.

In May, RIEC celebrated 40 years of pro-

viding reliable, safe, and low-cost power to

its Missouri customers. Over 20 years ago,

RIEC began making the switch to Pow-

der River Basin (PRB) coal because of the

coal’s environmental and economic advan-

tages (the coal contains very low amounts

of sulfur and is the lowest $/Btu fuel). The

plant has burned 100% PRB coal since

1996. Today, PRB coal is further refined on

site with the addition of proprietary chemi-

cals that “refine” the coal in order to reduce

NOx production at a cost of about $4 million

per year. RIEC’s two units routinely score

first and second nationally for the lowest

NOx produced by units without selective

catalytic reduction (SCR).

RIEC is located about 45 miles south of St.

Louis, Mo., on a 500-acre site, on the west side

of the Mississippi River. Each unit has a gross

generating capacity of approximately 645

MW. The two units began commercial service

in 1976 and 1977 and represent the last coal

plants constructed for the Ameren Missouri

generating fleet. The tangentially fired boilers

were originally designed to burn high-sulfur

Illinois coal (11,600 Btu/lb versus 8,400 Btu/

lb for PRB coal). The plant produces electric-

ity with two Westinghouse turbine-generators,

recently upgraded with Alstom rotors.

The Powder River Coal Users’ Group

(PRBCUG) Board of Directors toured RIEC

in mid-December 2015 to learn first-hand

about the plant’s progress toward implement-

ing best practices for managing risk, ensuring

a safe working environment, efficient combus-

tion, and PRB coal handling. Board members

shared their observations with POWER, many

of which are included in this article. The com-

mon denominator reported by each member of

the review team was the plant’s commitment

to a process of continuous improvement in all

areas of plant operations.

Excellence in plant operations is a pro-

cess, not an end state, although Plant of the

Year honors certainly represent a significant

milestone in the life of the plant (see side-

bar). The board noted three important areas

where the plant distinguishes itself among its

peers: environmental performance, plant op-

erations, and a culture of safety.

Rush Island Energy Center has successfully fired Powder River Basin (PRB) coal for two decades, as proven by the plant’s excellent performance stats, dedication to minimizing its environmental footprint, and sterling safety record. The PRB Coal Users’ Group top award recognizes the plant staff’s long-term dedication to continuously improving its safe handling and ef-ficient combustion of PRB coal.

Dr. Robert Peltier, PE

Courtesy: Rush Island Energy Center, Ameren Corp.


PRB COAL

Environmental ExcellenceNOx emissions are managed by overfired air

and a Griffin neural net combustion optimiza-

tion system. The permit limit for NOx emis-

sions is 0.40 lb/MMBtu, although actual

average annual NOx emissions have remained

below 0.10 lb/MMBtu over the past decade,

without an SCR. For 2015, NOx emissions av-

eraged 0.081 lb/MMBtu. Particulates are cap-

tured with an electrostatic precipitator on each

unit (there is no baghouse).

The plant’s sulfur emissions rely on the

efficient burning of the ultra-low-sulfur PRB

compliance coal. Permitted SO2 emissions are

2.3 lb/MMBtu, although the plant’s average

annual emissions have tracked under 0.75 lb/

MMBtu for the past 20 years, dipping to be-

low 0.5 lb/million Btu in 2014 as combustion

systems were continuously optimized.

Mercury emissions are reduced by in-

jecting activated carbon upstream of the air

heaters and a mercury continuous emissions

monitoring system analyzes the stack gas.

The plant closely manages opacity exceed-

ances and had only 46 six-minute exceed-

ances in 2014.

The plant operates today with a capacity

factor over 80% and an equivalent availabil-

ity just short of 90%.

Impeccable Plant OperationsRIEC’s two units consume about 5.5 million

tons of PRB coal each year, which represents

about one 145-car unit train every day. Coal

is sourced from Peabody Energy’s North An-

telope Rochelle, Seam “C,” located in Wyo-

ming. A loop track around the storage area

reduces the coal train unloading cycle time.

The plant stores about 1.1 million tons

of coal on site (equivalent to about 60 to

65 days of consumption). Coal is deliv-

ered using pneumatically actuated bottom-

dump cars that drop coal onto feeders. An

“A-frame” structure supports a vibratory

shaker that, with an electric heater, is able

to remove sticky, wet, or frozen coal from

the rail cars. Dry roto-clone systems keep

the dust produced during the unloading pro-

cess well under control. A surfactant is also

sprayed on the coal during unloading for

dust control, when required.

The “A” side coal unloading system is con-

figured with below-grade dump hoppers out-

fitted with vibratory feeders that direct coal

onto conveyor belt systems that terminate at

the radial stacker-reclaimer centrally located

in the main coal storage pile (Figure 1). The

conveyor belt is protected with a fixed nozzle,

open spray deluge system monitored and trig-

gered by a thermistor wire. The coal bins are

located indoors, although the filter houses are

outdoors. Once coal is delivered to the pile,

three Caterpillar D10 dozers keep the coal

PRBCUG Recognizes Its 2016 Plant of the Year

The annual Powder River Basin Coal Users’

Group (PRBCUG) meeting was held in April in

conjunction with the 2016 ELECTRIC POWER

Conference & Exhibition in New Orleans, La.

This year the PRBCUG recognized the Rush

Island Energy Center as its Plant of the Year

for the plant’s innovation and implementa-

tion of “best practices and best available

technologies” for burning PRB coal. Plant

of the Year recipients are inducted into the

group’s Power Plant Hall of Fame.

Selections are made by the group’s

board of directors, with input from mem-

bers. PRBCUG membership comprises us-

ers of PRB coals as well as prospective

consumers (generating companies or

industrial energy consumers). Associate

members from companies supplying coal,

equipment, or services also participate in

the selection process. Visit www.prbcoals.

com for more information about the group

and its Plant of the Year selection process.

1. Black gold. The Rush Island Energy Center consumes about 5.5 million tons of very low

sulfur Powder River Basin coal each year. The coal pile holds about 1.1 million tons of fuel—

enough for 60 to 65 days of operation. Courtesy: Rush Island Energy Center


PRB COAL

storage area well-groomed. The reclaim sys-

tem collects coal from the pile and conveys it

to the transfer house, where magnetic metal

separation occurs. Coal is then conveyed to

the surge bin located on each unit, which, in

turn, sends coal to one of the six unit silos. The

“B” side system, which is virtually identical in

operation, provides redundancy.

The single coal supply incline from the

transfer house to the boiler island contains

two independent conveyor systems (Figure

2). The twin conveyors run through an engi-

neered opening in the stack’s shell structure,

through the stack, across the boiler house,

and to the tripper (cascade) floor and the coal

silos. The open conveyors are the cause of

minor combustible dust releases within the

building that are ably handled by the house-

keeping staff.

As part of the plant’s conversion to PRB

coal, conveyor side panels and under-convey-

or dribble and sluice pans were installed on

the two conveyors. The side panels prevent

coal particles from escaping into the boiler

house, and the dribble and sluice pans help

capture and direct washdown slurry to a con-

tainment area outside the boiler building.

Washing of these conveyors occurs every two

weeks, or more often, as needed.

A crew of 10 laborers are assigned house-

keeping duties for the fuel unloading and

delivery systems. The normal practice is to

wash down unloading areas of combustible

dust after each train is unloaded. Washdown

in the fuel unloading area relies on hoses.

Washdowns on the tripper deck with hoses

and a floor deluge system are conducted once

a week. Monthly housekeeping audits are

also performed by craft supervisors.

Fire protection water is supplied by three

pumps; two are electric drive and one is

driven by a diesel engine. Pumps are tested

weekly. The plant’s fire control panel is lo-

cated within the combined control room and

is monitored around the clock by the control

room operators.

Organized for SuccessRIEC employs 141 full-time employees. The

plant’s operations and maintenance (O&M)

staff is organized with five rotating opera-

tions teams, plus 45 maintenance craft work-

ers and 10 fuel operators. All plant operators

are also cross-trained in a maintenance skill

and spend approximately one-half of their

shift performing plant maintenance. Ameren

also has a traveling maintenance group of ap-

proximately 70 craft workers that augment

the plant maintenance staff during major

maintenance outages.

Boiler outages are scheduled every six

years and turbine outages every 12 years.

The plant’s annual O&M budget (less fuel)

is approximately $24 million, and the capital

budget is about $2.5 million, which doesn’t

include major capital projects.

The plant’s outstanding safety record is

demonstrated by just six lost work accidents

occurring over the past 10 years. An effective

safety culture begins at the top. Litzinger hosts

a monthly all-hands safety meeting that is also

video recorded for replay by shift workers.

Other important safety programs include:

■ The Plant Safety Steering Committee—

consisting of senior plant staff, a craft

representative, and a corporate safety

representative—meets monthly. The craft

safety representative is elected to serve in

that position by peers.

■ The plant safety director conducts a daily

safety tour of the plant, and all plant em-

ployees are trained to be vigilant in identi-

fying potential safety issues.

■ “Stop work” authority is delegated to all

employees when an unsafe condition is

observed.

■ Contractors must submit a safety plan for

approval prior to beginning work.

■ Of the 141 plant employees, 135 are emer-

gency response trained.

■ The plant has a 40-member fire brigade

for interior firefighting, and all employees

are trained in incipient firefighting.

Workers participate in a safety observation

program called Crew to Crew (C2C). C2C re-

quires workers to complete a job briefing and

hazard recognition form prior to the start of

each job. If hazards are identified, they must

be escalated to a supervisor for resolution.

C2C also requires daily supervisor visits to

every location in the plant where work is be-

ing performed. It is the supervisor’s respon-

sibility to talk with those doing the work and,

by using a prescribed check sheet, to identify

emerging safety issues that require immedi-

ate attention, develop modifications to exist-

ing job plans, and/or identify future training

needs.

Finally, IMPROVE, the plant’s work

management system, is used to capture rec-

ognized hazards and near misses. The feed-

back is then reviewed by the appropriate craft

supervisor and safety supervisor. The safety

supervisor is responsible for recording,

tracking, and disseminating all safety-related

issues to the plant director and to other Ame-

ren facilities.

Current Coal ChallengesRIEC has made many PRB coal-related im-

provements since converting the plant to burn

PRB coal 20 years ago. Prime examples are

the improvements made to its coal-handling

systems, such as explosion-proof electrical

system upgrades, installing semi-automatic

washdown systems, dust suppression system

additions, improved chute and skirt board

seals, and fire protection system upgrades.

The plant also installed passive and fixed

fire detection suppression systems through-

out the plant and on its fuel-handling sys-

tems. Flow-controlled transfer chutes were

installed so that the fuel-handling system

would efficiently handle the increased coal

flow. Upgrades were made to the plant’s bun-

kers, silos, and bins (silos) to reduce bridging

and rat-holing. Erratic flow through silos is

2. Stuck in the middle. The arrangement of the two-unit plant required the two main

fuel transfer conveyors to pass through the common plant stack and through the boiler house

to reach the fuel silos located on the opposite side of the boiler house. Courtesy: Bill Konefes,

PRBCUG


PRB COAL

especially troublesome as PRB coal is more

prone to spontaneous combustion during

coal flow stoppages. Finally, coal conveyors

along with the support structures were retro-

fitted with automatic fixed sprinkler systems.

For 2016, the plant’s continuous improve-

ment program is focused on improving plant

operations in two important ways: reducing

boiler fouling and reducing fly ash dusting

originating at coal mill primary air ducts.

Reduce Furnace Fouling. Effective fur-

nace sootblowing is required in order to keep

the furnace tubes clean. Each unit uses 80

steam wallblowers and long retractable blow-

ers (recently increased from 18 to 66) for tube

wall cleaning, a mixture of Copes-Vulcan and

Clyde Bergemann designs. Three additional

long retractable sootblowers are currently

planned for installation on each unit. Steam is

the sootblowing medium of choice.

The Griffin intelligent combustion con-

trol system is also used for intelligent soot-

blowing (ISB). The ISB is principally used

to determine cleaning times and intervals,

although operators must occasionally manu-

ally run select blowers to manage steam

temperature control. Periodic load drops are

intermittently required for slag shedding,

particularly during summer months after a

long run at—or long periods of operation at

or near—full load. Online boiler washdowns

are scheduled about twice a year.

Routine maintenance of sootblowers was

problematic, so a few years ago RIEC set up

a dedicated sootblower maintenance shop.

Sootblower availability was greatly improved

as a result of having the dedicated mainte-

nance shop. On the day of the visit, Unit 1

had only three of 80 wall blowers out of ser-

vice, three more wall blowers were available

for local start only, and only one long retract-

able sootblower was out of service. On Unit

2, only three wallblowers were out of service.

Reduce Fly Ash Leaks. The plant main-

tenance staff has been fighting leaks in the

primary air ducts that cause fly ash to be

exhausted into the boiler house for the past

three years. The problem often overwhelms

the plant’s housekeeping staff because air-

borne fly ash tends to settle everywhere in

the boiler house, and the turbine deck often

receives a light dusting as well. Recent work

completed on Unit 1 is expected to signifi-

cantly reduce the dusting problem, and Unit

2 modifications will be completed during the

unit’s next major outage. Fly ash does not

have the fire hazard potential of PRB coal

dust, so the presence of fly ash is principally

a worker respiratory hazard concern.

More InformationCongratulations from the editorial staff of

POWER to the management and staff of

Ameren Missouri’s Rush Island Energy Cen-

ter for being chosen as the 2016 PRBCUG

Plant of the Year! For further information

on RIEC or the plant improvement projects

outlined in this article, please contact Plant

Director Mark Litzinger (314-992-9201 or

[email protected]). Additional infor-

mation on the PRBCUG and its awards pro-

gram is available at www.prbcoals.com. ■

—Dr. Robert Peltier, PE is POWER’s consulting editor. The members of the

PRBCUG board of directors that visited the

Rush Island Energy Center and contrib-uted to this report include Bill Konefes

(Georgia-Pacific and Chairman, PRBCUG); Andrew Dobrzanski (DTE Energy and

Vice Chairman-Genco); Jim Wiseman (Wiseman Consulting Services and Vice

Chairman-Industry); Erick Dieperink (Lumi-nant); James Rauba (FM Global); Jeff Kite

(Diamond Power International Inc.); and Greg Krieser (OPPD Omaha Public Power

District).

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25967


FUELS

The Coal Refuse Dilemma: Burning Coal for Environmental BenefitsThe niche alternative energy industry that generates power from hazardous

piles of coal waste that litter the U.S. is facing an environmental Catch-22.

Sonal Patel

The torrent of coal mined and processed

in the U.S. since the mid-1700s—

first sorted by the little, raw fingers

of “breaker boys” (Figure 1) and, later, by

machinery—has produced hundreds of mil-

lions of tons of coal “refuse” that was dis-

carded for its very low heat content. This

waste coal—also known as culm, gob, or

boney, and often mixed in with rock, shale,

slurry, slate, clay, and other materials—has

been randomly stockpiled high on thousands

of acres of abandoned mine lands (AML),

scattered across landscapes in coal country,

sometimes filling up entire valleys with dark

gray moonscape-like formations.

But over the years, the environmental im-

pact of these dumps has also crested. Refuse

mounds, toxic to plant life, are barren and

therefore highly erosive. Unstable coal re-

fuse piles can collapse, becoming potential

disasters. And bituminous piles, in particular,

can leach concentrated levels of acid mine

drainage. “The cost of reclaiming these piles

using conventional AML techniques is high,

and the extremely poor water quality is often

beyond the reach of current passive treatment

technology,” noted ARIPPA, a trade organi-

zation that started as the Anthracite Region

Independent Power Producers Association

but that has since adopted its acronymic

name, along with a broader mission to pro-

duce power from all varieties of the nation’s

coal refuse.

In Pennsylvania alone, where coal min-

ers have extracted about 16.3 billion short

tons of anthracite and bituminous coal

since commercial mining began in 1800,

the state is scarred by more than 5,000

abandoned, unreclaimed mining areas that

cover 184,00 acres. Coal refuse piles at

these mines undulate over an aggregate

area of 8,500 acres and contain a total vol-

ume of more than 200 million cubic yards.

And that’s a conservative estimate: AR-

IPPA guesses the amount of coal refuse in

the state is actually about 2 billion cubic

yards, split equally between the anthracite

and bituminous coal regions. The Pennsyl-

vania Bureau of Abandoned Mine Recla-

mation (PBAMR), meanwhile, estimates

that a complete cleanup of AML sites will

cost about $16.1 billion.

Then, there’s the ever-present, exorbitant

risk of fire. In 2014, PBAMR paid (using

emergency funds in a trust partially funded

by the coal industry via fees paid per ton of

mined coal) Pennsylvania firm Minichi Inc.

$2.2 million to snuff out a stubborn blaze at

the 100-foot-high, 4-acre bank of the Simp-

son Northeast coal refuse pile. The fire,

which started out smoldering and ignited into

flames at the periphery of a vastly larger coal

refuse area, took nearly six months to extin-

guish, requiring material excavation, mil-

lions of gallons of water, and thousands of

gallons of firefighting foam (Figure 2).

That’s just one example. At least 40 other

coal refuse piles—not including underground

mine fires—are currently burning just in

Pennsylvania and will need to be addressed

at some point, the state agency says.

There’s not much the commonwealth can

do, beyond reclamation—which is a com-

plicated task that requires addressing water

pollution from run-off and acid mine drain-

age discharges, site stabilization, covering

the pile with soil, and planting vegetation. In

1968, Pennsylvania became the first state to

pass a law to address air pollution associated

with coal refuse disposal.

On a federal level, it’s a similar struggle,

ARIPPA noted. “Laws were enacted in the

late 1970s that now require coal mining com-

panies to reclaim the sites that they currently

mine. But by the time these laws were en-

acted, a billion tons of coal refuse had been

stockpiled, thousands of mine sites were

abandoned—and the former legally respon-

sible parties had vanished,” it explained.

From Refuse to ResourceThat’s why, ARIPPA says, its solution to use

coal refuse as fuel at power plants sited near

piles across the nation is indispensable.

1. Breaker boys. This photo from 1911 captures a view of the Ewen Breaker of the Pa. Coal

Co., where boys—most aged eight to 12—spent 10 hours a day, six days a week, breaking and

sorting coal, and picking out slate and other impurities, which were then dumped in coal refuse

piles. The record notes that the “dust was so dense at times as to obscure the view.” Source:

National Archives and Records Administration


FUELS

In its simplest sense, the process entails re-mining coal refuse piles

in accordance with surface mining regulations, and then processing

that material at the mine site by screening to remove rock and other

inert materials. The finer material—typically 75% or more of the coal

refuse—is used as fuel in a fluidized bed combustion boiler or circu-

lating fluidized bed (CFB) boiler. Combustion ash from the boiler—

which meets beneficial use criteria—is then returned to the mine site

and mixed with unusable coal refuse material as a way of neutralizing

any remaining acidic materials. The materials are then compacted in

place to contours as described in the surface mining permit. “As such

the concentration of the acidity as well as the metals such as iron,

aluminum, and manganese in surface and groundwater releases are

significantly reduced,” says ARIPPA.

The coal refuse–to-power solution was conceived in the aftermath

of the oil embargo of the 1970s. Just as Congress was preparing to

vote for the Public Utility Regulatory Policies Act (PURPA) in 1978,

CFB technology was being developed and showing a capability to

convert low–heating value carbonaceous material (such as coal re-

fuse) into energy.

The first CFB plant designed to convert large quantities of coal

refuse into power—the 30-MW Westwood Generating Station in

Schuylkill County, Pa.—came online in 1987. Eighteen more proj-

ects have since been grid-connected, 13 in Pennsylvania alone (Fig-

ure 3); two are in West Virginia, one in Montana, one in Utah, and

one in Illinois.

The plants are owned by a diverse mix of companies, including

NRG Energy, Exelon, Olympus Power, Babcock & Wilcox Co., Fos-

ter Wheeler, Northern Star Generation, Pacific Gas and Electric, Kim-

berly Clark, Cogentrix Energy, Olympus Power, Schuylkill Energy

Resources, Waste Management, Southern Illinois Power Cooperative,

and Colstrip Energy. Most power produced is sold in the PJM whole-

sale and capacity markets. Today, these plants—with a total capacity

of 1,767 MW (see http://www.powermag.com/plants-that-turn-coal-

refuse-to-power/ for a slideshow of the plants)—have removed a

purported 214 million tons of coal refuse from the environment at no

expense to taxpayers.

But the sector that has been the darling of most coal-producing

states—and lauded even by the Environmental Protection Agency

(EPA)—for its potential to eradicate coal refuse piles and reclaim

thousands of disfigured acres is facing new, debilitating challenges.

Lucrative power purchase agreements signed under PURPA are

beginning to expire, forcing plants to compete in the open market.

Then, as Vincent Brisini, director of environmental affairs at Olympus

Power, recently told congressional lawmakers, because coal refuse

piles close to existing coal refuse plants have been successfully re-

moved, generators must source coal refuse from piles at ever-greater

distances, which has added to transportation costs. And, as with con-

ventional coal plants, the economics of existing coal refuse plants

have suffered in the advent of “abnormally low natural gas prices,”

and a “sluggish economy [that is] stifling electricity demand,” the

trade group told POWER.

An Environmental MuddleLately, that economic burden has gotten even heavier owing to “fed-

eral regulatory policies that dramatically and unnecessarily increase

environmental compliance costs,” ARIPPA said.

For the coal refuse generation sector, air pollution in particular poses

an environmental Catch-22 with no resolution in sight. The EPA em-

phasized, when questioned by POWER in May, that coal refuse piles

are a marked environmental worry for their acid seepage and leach-

ate production, spontaneous combustion, and low soil fertility. It also

acknowledged that “[u]nits that burn coal refuse provide multimedia

environmental benefits by combining the production of energy with

the removal of coal refuse piles and by reclaiming land for productive

use.” However, the agency underscored, they are still coal-fired power

plants. They still emit hazardous air pollutants that the agency has de-

termined are “significant” public health disadvantages.

Critics of the niche industry, like the Pennsylvania arm of the En-

ergy Justice Network project, contend that coal refuse plants aren’t

just inefficient, they also are far more polluting than new coal plants.

“The large new waste coal burning power plants planned for western

2. The long inferno. Crews spent six months dousing open

flames at the Simpson Northeast coal refuse fire near Fell Township,

Lackawanna County, Pa., in 2014. Temperatures fell into the single dig-

its for almost a month while crews worked. Source: Office of Surface

Mining Reclamation and Enforcement/Department of Interior

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FUELS

[Pennsylvania] were granted permits in 2005

to release higher levels of [sulfur dioxide

(SO2) and nitrogen oxides (NOx)] and other

air pollutants than the normal pulverized coal

power plant proposed near Morgantown,

W.Va.,” the group pointed out. Also, “If 100

tons of waste coal are burned, 85 tons will

remain as waste coal ash,” it said.

A better solution to the coal refuse problem

would be to plant beach grass, which it says,

citing research from the Natural Resources

Conservation Service, “has been shown to

bring life back to long-dead waste coal piles for

only 6-10% of the cost of conventional meth-

ods. Within a few years, beach grass enabled

native plants to take over, allowing organic

matter to accumulate around plants, forming

a plant layer that stopped erosion, held water,

cooled the surface, and looked better.”

ARIPPA contests the air pollution charge,

saying its members take precautions to con-

trol emissions of SO2, NOx, air toxics, filter-

able particulate matter, and total particulate

matter. Coal refuse power plants use CFB

boilers, which use limestone injection for

acid gas control, and they are also equipped

with fabric filter systems to control filterable

particulate matter emissions, it explained.

The nation’s coal refuse plants are also the

lowest emitters of mercury of all coal genera-

tion facilities, even though coal refuse may

be higher in mercury content, ARIPPA said,

noting that multiple coal-refuse units were

included in the EPA’s Maximum Achievable

Control Technology (MACT) floor calcula-

tions (top 12% performing units) used to

establish the emission standards for mercury

and non-mercury metals as outlined in its

Mercury and Air Toxics Standards (MATS).

Meanwhile, the emissions of greenhouse

gases (GHGs) from these units can be con-

sidered as offset due to the eventual in-place

burning of coal refuse piles, ARIPPA said.

“Coal refuse fires also result in the uncon-

trolled release of the same pollutants that

these plants control with high removal rates.

Because these units provide electricity to the

grid they also reduce emissions from other

fossil fuel–fired [electric generating units

(EGUs)] which otherwise would be operat-

ing. The reclamation and re-vegetation of

coal refuse sites also results in the expansion

of green spaces which aids in the sequestra-

tion of GHGs,” it said.

The EPA told POWER that it has con-

sidered and requested comment on separate

emission standards for coal refuse generators

for various proposals. “In fact, EPA has es-

tablished subcategory SO2 and NOx emission

standards for new, modified and reconstruct-

ed coal refuse-fired EGUs,” it said.

However, in the final MATS rule, the EPA

noted that the waste coal hazardous air pol-

lutant emissions are not sufficiently different

from other coal-fired generators to warrant

further subcategorization. “There are EGUs

firing bituminous, subbituminous, and coal

refuse among the top performing units for

mercury emissions. EGUs firing bituminous,

subbituminous, lignite, and coal refuse are

also all among the top performers for the acid

gas and non-mercury metallic emissions.

This indicates that the MACT floor limits es-

tablished based on these units are achievable

by units burning all ranks of coal,” it said.

This approach, the EPA noted, was upheld

by the D.C. Circuit’s April 2014 decision in

White Stallion v. EPA. The court, in that case,

said that the “EPA reasonably decided that

separate standards for coal-refuse-fired CFBs

were not warranted.”

Looking to Congress for a ResolutionUnderscoring its message that “one regula-

tion does not fit all plants the same,” the in-

dustry has continued its fight to keep afloat

amid the deluge of environmental rules tar-

geting coal plants. Its cause has now been

taken up in Congress.

Rep. Keith Rothfus (R-Pa.) last Octo-

ber introduced the Satisfying Energy Needs

and Saving the Environment (SENSE) Act,

legislation that would modify the EPA’s

Cross-State Air Pollution Rule (CSAPR) by

allocating additional SO2 allowances for coal

refuse generators (but reducing allowances

elsewhere so the overall program cap does

not change). The bill also creates an alter-

native means of demonstrating compliance

with the hydrochloric acid (HCl) standard

under MATS by assuming that a 93% reduc-

tion in SO2 demonstrates compliance with

the HCl standard.

But the Obama administration has threat-

ened to veto the bill, raising concerns that

it chooses “winners and losers” because it

favors coal refuse generators over other fa-

cilities. At a House Subcommittee on Energy

and Power hearing on the bill this February,

speaking on ARIPPA’s behalf, Brisini refuted

that argument, underscoring that coal variet-

ies have unique characteristics.

Anthracite refuse plants can meet the

CSAPR alternative 2.0 standard because sul-

fur content in coal refuse from the anthracite

region is lower, but bituminous plants cannot,

he said. “It is not because the technology is

different or they have anything special and it is

part of the problem when you lump all of these

things together not recognizing the [technical

differences] in these kinds of fuels.” Mean-

while, he noted, only two bituminous coal

refuse plants can meet the HCl requirements

under MATS. “No other plants, whether they

are bituminous coal refuse [or] anthracite coal

refuse, they don’t do it,” he said.

The bill continues its course through Con-

gress and is currently under consideration by

the Senate. Brisini remains hopeful that the

acid gas issue is resolved by the SENSE Act

or other regulatory amendments.

If all fails, “the measures that would have

to be taken by bituminous coal refuse–fired

electric generating units to allow them to

meet the acid gas limit would likely prevent

them from successfully participating in the

PJM wholesale electric market, with the ex-

ception of the last coal refuse fired facility

built,” he noted. ■

—Sonal Patel is a POWER associate editor.

3. Plying the pile. The 102-MW Colver Power Project in Cambria County—a bituminous

coal mining region in western Pennsylvania—began operations in May 1995. The plant, owned

by independent power producer Inter-Power/AhlCon Partners, is equipped with a large circulat-

ing fluidized bed boiler. It is one of the state’s newest bituminous coal refuse power plants.

Courtesy: ARIPPA


FUELS

Energy from Waste: Greenhouse Gas Winner or Pollution Loser?Is waste-to-energy the best greenhouse gas fighter among electric generating

technologies? Or do trash burners spew dangerous air emissions? The answer may be a surprise.

Kennedy Maize

What electricity-generating technol-

ogy results in net greenhouse gas

(GHG) reductions, not just zero

new emissions? According to the U.S. Envi-

ronmental Protection Agency (EPA), it’s not

nuclear, not wind, not solar.

Give up? Waste-to-energy (WTE, known

to some as “trash-to-cash”), according to the

EPA and a recent analysis by the Depart-

ment of Energy’s National Renewable En-

ergy Laboratory (NREL) is the only electric

generating technology that actually reduces

GHG emissions as it makes power. Mega-

watts up; GHGs down.

According to the EPA, municipal solid

waste (MSW) burners, using trash and gar-

bage to generate electricity, separating out

recyclable materials, will “actually reduce

the amount of [GHG emissions] in the atmo-

sphere compared to landfilling. The savings

are estimated to be about 1.0 tons of GHGs

saved per ton of MSW combusted.”

The EPA bases its calculations on methane

emissions from landfills. Methane is a much

more potent GHG than carbon dioxide (CO2)

in the short term (although methane spends

less time than CO2 in the atmosphere). Burn-

ing the trash that produces methane in land-

fills reduces overall GHGs.

A 2011 NREL analysis looked at lifecycle

GHG emissions from electricity generat-

ing technologies. It found that wind has very

small lifecycle emissions, with nuclear a bit

above those, followed by solar. While all of

the conventional low-carbon technologies were

slightly positive in terms of GHG emissions in

lifecycle terms (the energy that went into mak-

ing and erecting the technologies as well as

emissions from operations), energy from waste

was the only option that reduced GHGs. WTE

projects prevent landfill methane emissions,

according to NREL; the other renewable tech-

nologies simply avoid new emissions.

Clean Power Plan Would Support WTEA little-noticed element of the EPA’s Clean

Power Plan, generally seen as a way to back

out coal-fired power and boost conventional

renewables such as wind and solar, reflects

this analysis of the ability of WTE to yield

net negative GHG emissions. Paul Gillman,

senior vice president and chief sustainability

officer at Covanta, a leading waste manage-

ment company in the U.S., told POWER that

the EPA’s Clean Power Plan tells states they

can consider energy from waste “as a mitiga-

tion tool” to meet requirements under the new

regulations.

Covanta, with 43 WTE plants (41 in North

America and two in Europe), is now pitching

GHG reductions as among the reasons to em-

ploy the technology. It turns MSW into a stream

of saleable recycled commodities—such as

aluminum, copper, and plastics—along with

electricity and process steam that can be sold to

industrial users or district heating systems. All

this while reducing landfill methane. Gillman

notes that Europe and Asia, which signed on to

the 1997 Kyoto Protocol—which the U.S. re-

jected and which is now a dead letter—spurred

WTE for GHG reductions.

International Support for WTE

European nations that signed on to the Kyoto

agreement saw WTE as a way to reduce meth-

ane-generating landfills while increasing re-

cycling and energy production. “In Germany,”

Gillman said, “less than 1% of waste goes to

landfills.” Denmark has banned landfills, turn-

ing entirely to recycling and WTE for manag-

ing its waste stream (Figure 1).

Compared to the U.S., European countries

have greater population densities and less

territory available for landfills. They often

have government-owned waste management

agencies, which can streamline development

of landfill alternatives. In Denmark, for ex-

ample, WTE plants are owned by municipali-

ties or multiple-municipal agencies.

In Asia, particularly China, noted Gill-

man, the Kyoto Protocol mechanisms cre-

ated an economic incentive to reduce GHGs

in order to generate reduction credits saleable

to the European Union countries. According

to Gillman, more than 300 WTE projects are

now operating in China, and more than 100

are under construction (see sidebar “World’s

Largest Waste-to-Energy Plant”). China, he

1. Not just blowin’ smoke. The Amager Resource Center waste-to-energy plant is

under construction in Denmark, which has banned landfills. The plant has gained notoriety for

integrating an artificial ski slope on the roof and a stack that will blow a water vapor “smoke

ring” each time 250 kilograms of carbon dioxide are released. Courtesy: Bjarke Ingels Group


FUELS

said, has about the same land mass as the

U.S. but four times the population—a strong

incentive against landfills and for WTE.

In the U.S., land for waste disposal is

cheap and plentiful. WTE plants compete

with landfills for the trash disposal dollar.

According to the Energy Recovery Council,

the industry’s Washington-based lobbying

group, the U.S. has 84 WTE plants (four are

idled but able to come into service), with

about 2,800 MW of baseload electricity gen-

erating capacity. The two dominant WTE

companies are publicly traded Covanta,

based in Morristown, N.J., with more than

40 plants, and privately owned Wheelabra-

tor Technologies, located in Hampton, N.H.,

with 16 U.S. plants.

The first new WTE project in the U.S. in

20 years went into commercial operation in

July 2015, in West Palm Beach, Fla., owned

by the Palm Beach County Solid Waste Au-

thority. The 95-MW facility joined an exist-

ing 20-year-old waste combustion and energy

unit. A consortium of Babcock & Wilcox and

KBR designed and built the new plant.

Covanta commissioned the most recent

plant in North America in January this year

in the Canadian province of Ontario, the

Durham York project (Figure 3), which burns

436 metric tons of MSW per day to produce

15.7 MW of baseload power.

Wheelabrator’s latest project is the Fer-

rybridge “multifuel” project in North York-

shire in the UK, a 68-MW generator burning

MSW, industrial waste, and wood waste,

co-located with an existing and retiring coal-

fired power plant.

Challenging U.S. Economics for WTE Why is the U.S. slow in turning waste into en-

ergy? It’s a matter of market competition, said

Ted Michaels, head of the Energy Recovery

Council. He told POWER, “Our industry is

strong, the facilities operate well; it’s a ma-

ture, not nascent, industry. But the industry is

operating in difficult economic conditions.”

WTE businesses in the U.S. face a triple eco-

nomic whammy, according to Michaels. First,

the chief economic driver of WTE is waste, not

energy. The facilities compete against landfills.

Landfills charge a tipping fee for waste deliv-

ered to their facilities. That becomes the price

WTE plants must meet to divert waste from the

landfill to the energy project.

“Power is a secondary function of the eco-

nomics of a waste-to-energy plant,” Michaels

said. “Our largest market is waste manage-

ment. That’s entirely different than wind

turbines, or biomass.” Michaels noted that in

the U.S., “Landfills remain cheap. That’s our

primary source of competition.”

To attract trash (aka fuel), a U.S. WTE

project must offer a lower tipping fee than a

landfill. The waste incinerators use offsetting

revenues from recycling and electric genera-

tion (and industrial steam in some cases) to

support their bids for the waste stream. Of

late, commodity prices for materials such

as metals, paper, and plastic have been his-

torically low, undermining the ability of the

recycling portion of the facility to compete

against landfills.

The crash in commodities prices has been

devastating to recyclers and WTE generators

across the board. The Washington Post noted

last year, “In short, the business of American

recycling has stalled. And industry leaders

warn that the situation is worse than it ap-

pears.” Waste Management, the nation’s larg-

est recycler, called it a “nationwide crisis.”

World’s Largest Waste-to-Energy Plant

China has picked two Danish architectural

firms—Schmidt Hammer Lassen Architects

and Gottlieb Paludan Architects—to de-

sign the world’s largest waste-to-energy

(WTE) plant for the city of Shenzhen. The

project would burn some 5,000 tons of

municipal solid waste per day—about a

third of the waste generated by the city of

20 million, reports Deezen.com, a website

covering architecture and design news.

Last December, a Shenzhen construc-

tion-waste dump collapsed, killing what

press accounts said were “dozens of peo-

ple.” Plans for the new WTE plant quickly

followed.

According to the architects’ website,

the circular facility a mile in diameter will

“boast a 66,000-square meter roof, two

thirds of which will be covered with solar

photovoltaic panels, allowing the building

to generate its own sustainable supply of

energy.” The circular structure of the plant

(Figure 2) will include a ramp that snakes

from the ground to the roof, along with a

rooftop visitors center.

The Deezem article quotes Chris Hardie,

head of the Schmidt Hammer Lassen of-

fice in Shanghai, as saying, “The project

firstly aims to provide a clean, simple and

modern technical facility to deal with the

city’s growing waste. At the same time it

aims to educate visitors to this growing

waste challenge by taking them on an

elevated walkway tour of the plant that

ends with a 1.5 kilometer panoramic view

of both the surrounding mountains and

the 66,000-square-meter roofscape that

will be geared to producing actual renew-

able energy.”

The companies’ descriptions and the

press accounts do not indicate how much

electric capacity the project will provide

or what the project will cost, typical of

announcements out of China on develop-

ing energy projects. The project is sched-

uled to be operational in 2020, according

to press reports.

2. Full circle. This design for a waste-

to-energy facility in Shenzhen, China, in-

cludes a rooftop visitors center. Courtesy:

Schmidt Hammer Lassen

3. Clean lines. Ontario’s Durham York 15.7-MW waste-to-energy plant burns 436 metric

tons of municipal solid waste daily. Courtesy: Covanta


FUELS

The company, based in Houston, said its re-

cycling division posted a $16 million loss in

the first quarter of 2015, and it has shut 10 of

its largest recycling facilities. The Washing-

ton Post article concluded, “A storm of fall-

ing oil prices, a strong dollar and a weakened

economy in China have sent prices for Amer-

ican recyclables plummeting wordwide.”

On top of that, low natural gas prices have

driven down the wholesale price generators

of electric power can reap in competitive

markets. “Natural gas is a big driver of waste-

to-energy economics, lowering the price for

wholesale power,” Michaels said. The global

economic crash of 2008 also slowed the econ-

omy, drove down electricity demand, and cut

into the price of recycled commodities.

The Environmental DebateEnvironmental opposition also burdens WTE

plants. Fervent opponents of the projects assert

that incinerating waste produces dangerous

levels of airborne pollutants such as dioxins

and heavy metals, and that the resulting ash is

hazardous. In Minnesota, three local groups—

the Sierra Club, the Minnesota Public Interest

Research Group, and Neighborhoods Organiz-

ing for Change—are trying to shut down the

Hennepin Energy Recovery Center in Min-

neapolis, claiming it harms the environment,

according to the Waste Dive online newsletter.

The Minnesota Public Utilities Commission

continues to back the project. The state has

nine WTE plants, the most in the region.

Claims about harms from waste incinera-

tion and energy recovery are based on out-

dated data, according to the industry and

government regulators. The EPA has given

both air emissions and ash toxicity a green

light. In addition to reducing landfill methane

emissions, proponents claim, WTE projects

reduce CO2 emissions by shipping waste to

incinerators by rail, a less–energy intensive

and less–transportation intrusive approach

than trucks hauling trash to landfills.

Maryland Rejects New Baltimore Waste-to-Energy Plant

Maryland has traditionally been friendly toward turning trash into

electricity, and the Northeast Maryland Waste Disposal Authority,

a quasi-governmental group aimed at helping Maryland communi-

ties meet their waste disposal needs, has long been an advocate

of waste-to-energy (WTE) projects.

Cars driving into Baltimore from I-95 and the Baltimore-

Washington Parkway for over 30 years have seen a large stack,

originally bearing the letters “BRESCO” down its side and, more

recently, “BALTIMORE” (Figure 4). That’s the exhaust stack for a

large WTE plant, commissioned in 1985, now operated by Wheela-

brator Technologies, and long a target of environmental activists

for alleged air pollution problems. The project has survived mul-

tiple environmental reviews over three decades.

A small WTE project in Harford County, north of Baltimore near

the Department of Defense’s (DOD’s) Aberdeen Proving Ground,

closed down last March when its lease with the DOD expired and

the Pentagon chose not to renew it. The plant began operations

in 1988 and attracted little local notice.

At about the same time as the Harford County plant’s lease ex-

pired, a proposal for another large Baltimore WTE project, years in

the works, collapsed. The Baltimore Sun reported that the Maryland

Department of the Environment told developer Energy Answers In-

ternational of Albany, N.Y., that a 2010 permit for a project in south

Baltimore’s Curtis Bay neighborhood was no longer valid.

The project would have been the largest in the U.S., converting

some 4,000 tons of solid waste per day into 160 MW of baseload ca-

pacity. The project drew opposition from local activists, who claimed

that the plant would harm schools and parks in the neighborhood,

as well as homes in the area. Opponents said the project would be

a prodigious producer of oxides of nitrogen and particulate pollu-

tion, although the plant would have met all federal Environmental

Protection Agency NOx and particulate emissions standards.

Baltimore activist Destiny Watford last April won a $175,000

“Goldman Environmental Prize” for organizing community opposi-

tion to the WTE project, along with kudos from New York Times en-

vironment blogger Andy Revkin. The citation read, “Curtis Bay is

a highly industrialized community in south Baltimore with a his-

tory of displacing people to make room for oil refineries, chemical

plants, sewage treatment plants, and other facilities that emit

pollution. Those left to live within breathing distance of industry

have long suffered from respiratory problems such as asthma and

lung cancer. In fact, a 2013 study on emissions-related mortality

rates found Baltimore to be the deadliest city, with 130 out of

every 100,000 residents likely to die each year from long-term

exposure to air pollution.”

Ted Michaels of the Energy Recovery Council had a different

take on the events in Baltimore. He told POWER that cancellation

of the 2010 state license for the Curtis Bay project came because

the developer hadn’t lived up to the terms of the permit. “Mary-

land withdrew the permit because not enough construction activ-

ity had occurred. The terms of the permit had been violated,” he

said. The Baltimore Sun reported that state environmental regula-

tors concluded that the developers of the project had not met the

permit requirements for “continuous construction.”

Are activists’ objections to mass-burn technologies technically

valid? In the online news site Huffington Post, science writer

Shawn Lawrence Otto wrote, “Today’s waste-to-energy (WTE)

plants are not your granddaddy’s trash burners. . . . Some lib-

eral groups, like the Center for American Progress, are starting to

look at the actual science and reevaluating long-held assumptions

in light of new information and increasing concern over climate

change. When they do, they are finding that today’s waste-to-

energy plants look surprisingly good for the environment and for

fighting climate change.”

4. Trash power plant target of trash talk. This Mary-

land waste-to-energy plant has been the target of environmental-

ists’ claims that it causes pollution, though it has survived three

decades of environmental reviews. Courtesy: Wheelabrator


FUELS

Nevertheless, opponents of waste-burning

projects repeatedly raise pollution issues, such

as the claims of the Global Alliance for Incin-

erator Alternatives (see sidebar “Maryland Re-

jects New Baltimore Waste-to-Energy Plant”).

Changing Fate for U.S. WTEIn the U.S., the 1978 Public Utility Regula-

tory Policies Act (PURPA) boosted the WTE

sector because it encouraged non-utility and

unconventional electric generating technolo-

gies. The act also gave birth to today’s inde-

pendent power sector, largely powered by

natural gas.

The 1978 law galvanized WTE projects,

which were able to meet the Federal En-

ergy Regulatory Commission’s criterion for

“qualifying facilities,” giving them access to

subsidized rates. Many of the WTE projects

in the U.S. started up in the 1980s and early

1990s as a result of PURPA’s push for alter-

natives to conventional generation.

Since then, a combination of factors, in-

cluding low-cost coal plants, low prices for

natural gas, and a decline in demand for elec-

tricity slowed the WTE business. The col-

lapse of the U.S. (and worldwide) economy

in 2008, along with the unexpected devel-

opment of fracking technologies to produce

soaring natural gas production, reducing

U.S. natural gas prices, put another burden

on WTE economics.

A classic example occurred in Frederick

County, Md., a neighbor to Montgomery

County (home of pricey Washington, D.C.,

suburbs and a 1985-built 52-MW Covanta

WTE plant burning 1,800 tons per day of

trash, sitting next door to an elderly 850-MW

coal-fired plant). Maryland in the 1980s ad-

opted a policy of no new landfills in the state,

which meant either local incineration or ship-

ping waste out of state. Maryland joined a

growing list of states banning local landfills.

Connecticut, Covanta’s Gillman noted, “has

no operating landfills.”

Fast-growing Frederick County, home of

the second-largest city in the state after Bal-

timore, saw its decades-old landfill reaching

capacity. The county signed a $471 million

contract with Wheelabrator in 2008 to build

a WTE incinerator, shared with nearby Car-

roll County. The project got the needed state

permits in 2012.

By that time, the project had become politi-

cally controversial. In 2014, an opponent of the

project won election as Frederick County ex-

ecutive. She vowed to kill the deal. The county

commissioners scrapped the project, instead,

signing a contract to haul the county’s solid

waste to an out-of-state landfill for five years.

New Reasons to Consider WTEWhat’s the future for waste-to-energy in

the U.S.? It’s uncertain. WTE lobbyist Mi-

chaels notes that “31 states, the District

of Columbia, and two territories have de-

fined waste-to-energy as renewable energy

in various state statutes and regulations,

including renewable portfolio standards.”

Twenty-two states specifically classify

WTE as meeting the requirements of their

renewable goals. Michaels argues that the

drive for GHG reductions will yield oppor-

tunities for waste projects.

Covanta’s Gillman says businesses may

push the U.S. toward more use of WTE.

“Lots of businesses have been issuing sus-

tainability goals,” he said, “and they see

improvements to the bottom line. Energy

conservation has been the first tier, then on-

site production and water resource manage-

ment. Now they’re moving in the direction

of making waste management more sustain-

able. ‘We want to reduce our greenhouse

gas footprint,’ the executives are saying.

‘Let’s look to waste.’ ”

Some businesses are also seeing waste

incinerators as a source of low-cost process

steam, which is common in Europe. These

projects, says Gillman, “are a very reliable

source of steam,” with the plants operating

in continuous baseload mode. “Industries are

attracted to that reliability,” said Covanta pu-

bic information official James Regan.

In the U.S., the sector’s future may lie in

rebutting and overcoming the conventional,

anti-pollution mantra of local opponents to

waste incineration. The liberal and environ-

mentally oriented Center for America Prog-

ress (CAP) made its case for WTE recently:

“It is environmentally unsustainable to take

garbage and bury it in the ground at land-

fills, where it decomposes and releases po-

tent greenhouse-gas pollution. What’s more,

some trash has to be transported by diesel

trucks or trains to landfills several hundred

miles away, further exacerbating its pollution

footprint. Though garbage is not something

we tend to actively think about on a daily

basis, specifically as it relates to climate

change, the United States must begin de-

veloping policies to limit the environmental

consequences that result from our generation

of garbage.”

The path to that policy, says CAP: “The

United States must begin developing national

policies to deal with the waste-management

problem our country faces every day. Do-

ing so will ultimately reduce emissions that

cause climate change.” ■

—Kennedy Maize is a long-time energy journalist and frequent contributor to

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FUELS

Understanding and Mitigating Metallurgical Effects of Coal Blending and SwitchingFuel blending and switching has become the norm in response to regulatory

and market forces, but many older boilers were designed for a particular fuel. Understanding the effects of different fuels on combustion system metals is crucial for ensuring smooth operations.

Rama S. Koripelli, PhD

Is there a clear distinction between good

and bad fuel to burn in a particular boiler?

Apparently not! Some fuels may contain

higher heating values, but they may also

possess characteristics that cause emissions

problems, as well as operational and reliabil-

ity challenges. Other fuels may be more envi-

ronmentally friendly, but may contain higher

moisture content and lower heating values.

Ideally, the “right fuel” is that for which a

boiler is designed or retrofitted to specifi-

cally burn.

Congress extensively amended the Clean

Air Act in 1990. Following those changes, the

Environmental Protection Agency began im-

posing more stringent emissions regulations

in the mid-1990s, which led to fuel blend-

ing and switching becoming the norm. Of

course, there are other factors—such as cost,

availability of mines, and meeting full-load

requirements in a dynamic environment—

that have also influenced fuel blending or

switching decisions.

Pros and Cons of PRB CoalThe use of Powder River Basin (PRB) coal,

whether as a blend or a switch, has tremen-

dously increased in response to economic

and regulatory changes. PRB coal gained

a tremendous amount of interest for its

abundant availability, as well as its lower

sulfur content, which results in lower SOx

emissions.

PRB coal has higher moisture content

than other coals due to its porous structure.

For that reason, PRB coal offers a lower heat-

ing value (around 8,000 Btu/lb) compared to

high-sulfur bituminous coals (about 13,000

Btu/lb). Even so, PRB coal often has eco-

nomic advantages over the latter.

There can also be significant fuel flex-

ibility advantages when blending coal. The

low-sulfur characteristics of PRB coal and its

relatively low cost make it attractive for the

power industry.

Some other major differences between

PRB and bituminous coals are found in con-

centrations of ash, calcium oxide, and mag-

nesium oxide. The concentrations of these

oxides in PRB coal are much higher than in

bituminous coals, which affects the ash melt-

ing temperature and radiant heat absorption

capacity in the furnace area. Reduced radiant

heat absorption capacity in the furnace area

is a product of higher reflectivity or lower

emissivity of the deposit. This reduced heat

transfer capacity in the furnace impairs the

thermal efficiency by raising the furnace exit

gas temperature (FEGT).

Slagging and Fouling ProblemsSlagging and fouling may be elevated in

high-temperature superheater or reheater cir-

cuits due to a combination of staged combus-

tion and higher FEGT (Figure 1). Low-NOx

burners and overfire air can further exacer-

bate this situation.

The reducing conditions formed during

staged combustion promote the formation

of hydrogen sulfides and porous metallic

sulfides on the pressure parts of the boiler

or furnace. These sulfide scales are more

porous and less protective than oxides. Re-

ducing conditions also promote carburiza-

tion of T91 (Figure 2) and stainless steel,

resulting in a loss of corrosion and oxida-

tion resistance.

Although PRB coal contains lower ash

content, it requires higher throughput to

meet full-load conditions. Therefore, ero-

sion problems may be exacerbated because

1. Bridging the gap. Secondary combustion contributes to high furnace exit gas temper-

atures, resulting in slagging and fouling in high-temperature circuits. Courtesy: David N. French

Metallurgists


FUELS

of these lower heating values when switching

from high-ranked coals. Higher FEGTs due

to a combination of reduced emissivity and

delayed combustion significantly affect the

finite life of dissimilar-metal welds (DMWs,

Figure 3).

These material transitions are in place for

a particular reason: specifically, to support

limited allowable stresses in high-tempera-

ture circuits. Any additional thermal loading

due to higher FEGTs reduces the remain-

ing useful life of DMWs and materials used

in primary superheat and reheat circuits.

These often contain carbon and carbon-

molybdenum steels, which are susceptible

to metallurgical degradations, specifically

graphitization (Figure 4) and spheroidiza-

tion, at elevated temperatures.

Sulfur and Chlorine ChallengesWith scrubbers in place, Illinois basin coal

saw tremendous demand for its higher heat-

ing value when compared to PRB coal, but it

comes with its own troubles. It contains sig-

nificant sulfur (about 4%) and chlorine (the

typical range is 0.2%–0.3%, but some results

have been up to 0.5%).

Sulfur and chlorine are detrimental to

the environment because they produce SOx

and hydrochloric acid (HCl) emissions.

Interestingly, chlorine helps mercury (Hg)

catalyze into oxidized Hg, which is very

soluble in wet flue gas desulfurization sys-

tems, thus reducing Hg emissions. Howev-

er, the presence of chlorine still produces

harmful HCl emissions (see “Operational

Considerations When Burning Higher-

Chlorine Coal” in the February 2015 issue

and online at powermag.com).

Chlorine is like sulfur in that it promotes

significant corrosion issues in the waterwall

and high-temperature circuits. A reducing

environment exacerbates chlorine corro-

sion. The question of how much chlorine is

too much is interesting and rather subjective.

Some plants have managed to burn fuel con-

taining 0.3% chlorine with limited corrosion

effects, while other units have experienced

severe corrosion even when less than 0.2%

chlorine is present in the coal.

In general, a majority of industry experts

seem to accept about 0.2% chlorine as the

threshold to mitigate corrosion problems.

Nevertheless, there are other factors that

influence chlorine corrosion, such as tem-

perature, slag accumulation, the reducing

environment, and fuel blends, so individual

results vary.

It is commonly believed that a blend of

low-sulfur coal and high-chlorine coal tends

to reduce corrosion issues. However, this be-

lief is based on largely anecdotal evidence.

Using blends of high-chlorine and low-sulfur

coals also increases liquid ash corrosion, and

high levels of chlorine can react with miner-

al-rich coals, resulting in the formation of a

corrosive environment.

Coal Condition Is ImportantA great deal of research must be completed

prior to blending or switching to different

coals. Decision makers must gather infor-

mation on the characteristics of fuels to be

blended or switched. The fact that individual

fuel characteristics can be much different

than the blended characteristics makes this a

difficult task.

Implementing improved operational,

maintenance, and repair strategies can help

minimize adverse effects of fuel blending

or switching. Blending is rather more com-

plicated than just mixing two or more fuels

together. Improper mixing of fuel blends

may cause load swings due to variable heat

content in the coal pockets. A more homog-

enized blend will reduce various adverse ef-

fects on boiler metallurgy. Better mixing of

coal and increasing coal fineness reduces

carbon carryover, which minimizes second-

ary combustion issues.

Improper blending promotes slagging

issues in the high-temperature circuits

and the formation of localized reducing

conditions. Metallurgical and corrosion

properties of metals and alloys used in

high-temperature circuits will not be com-

promised under oxidizing conditions and

designed FEGT. It is evident that second-

ary combustion causes several issues in the

waterwalls as well as in the superheater

and reheater circuits.

According to the modern standards in

coal-fired units, the following coal fineness

2. A closer look. This image is a microscopic picture showing carburization of T91 steel

tube, which reduces corrosion and oxidation resistance of the material. Courtesy: David N.

French Metallurgists

3. Jeepers creepers. This image shows

creep damage in the heat-affected zone of the

T22 side of a dissimilar-metal weld. Courtesy:

David N. French Metallurgists

4. Degrading conditions. This scan-

ning electron microscope image shows chain

graphitization in carbon-molybdenum steel.

Courtesy: David N. French Metallurgists


FUELS

is recommended: at least 75% of weight

should pass through a 200-mesh sieve

(0.0029-inch opening) and 0%–0.2% weight

may remain in a 50-mesh sieve (0.0117

inch). Coarse coal tends to increase carbon

carryover and loss on ignition. Reducing the

coal particle size increases the surface area

to mass ratio, effectively making the coal

more reactive. Consequently, improved coal

fineness will improve a plant’s efficiency

and reduce emissions (see “Coal Pulverizer

Maintenance Improves Boiler Combustion”

in the December 2015 issue and online at

powermag.com). Inputs to burners should

be accurate and dynamic in response during

load swings.

Solutions to Common ProblemsImproper blending may cause higher

FEGT, localized reducing conditions, and

secondary combustion. Decreasing sec-

ondary combustion reduces hot-ash corro-

sion, resulting from reduced superheat and

reheat temperatures. Maintaining oxidiz-

ing conditions inside the furnace potential-

ly eliminates the formation of porous iron

sulfide scales. Incorrect burner angles may

result in localized reducing conditions.

Therefore, burners should be adjusted per

design to have the correct stoichiometric

mixture.

Installation of low-NOx burners in coal-

fired boilers has resulted in accelerated wa-

terwall wastage. Low-NOx burners result

in more H2S being produced in the com-

bustion gas rather than SO2 or SO3; this

promotes increased corrosion rates. Weld

overlays of more corrosion-resistant alloys

like Inconel 622 and 625 have proven to be

a suitable long-term solution for reduced

tube wastage.

To prevent failures related to higher

FEGTs, DMW joints can be relocated to a

position where they are exposed to lower

temperatures. Also, the use of DMWs made

with nickel-based filler metal (EPRI P87

or Inconel) is recommended, specifically

in creep-strength-enhanced ferritic steels.

Nickel-based filler metal lessens the effects

of the thermal expansion differences be-

tween stainless steel and ferritic steel. Ma-

terial transitions in the superheat and reheat

circuits should be evaluated and adjusted

to ensure a satisfactory life. Superior-grade

steels may need to be extended during com-

ponent replacements to accommodate for

increased FEGT.

Many plants implement time-based clean-

ing of the pressure parts rather than informa-

tion-based cleaning. Time-based cleaning

causes several adverse effects on plant per-

formance and reliability. For one thing, ad-

ditional heat input is required to remove

moisture introduced during the cleaning

process, reducing the plant’s efficiency. Fur-

thermore, excessive sootblowing of relatively

clean areas causes erosion and fatigue prob-

lems, which results in increased maintenance

and reduced reliability.

It is recommended that an intelligent

cleaning system be deployed for boilers to

more efficiently clean the pressure parts

when and where required. The effective

cleaning of furnace tubes solves many sec-

ondary problems such as slagging or fouling,

high FEGT, and excessive usage of attem-

perator sprays. Thermal efficiency and reli-

ability are improved when smart cleaning

systems are used.

Fuel blending or switching can be a sound

economic decision. However, it demands

proper studies and implementation of opera-

tional and maintenance changes. Otherwise,

it can easily become a nightmare. ■

—Rama S. Koripelli, PhD ([email protected]) is technical director

for David N. French Metallurgists.

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COMMENTARY

The years between 2002 and 2012 are called Golden Decade for the coal industry in China. After May 2012, the coal industry fell into depression.

In the Golden Decade, a large amount of social capital inflow was attracted by increasing market demand and coal prices, but it also resulted in overproduction. The recession in downstream industries, including the steel industry and building materials industry, and the squeeze from non-fossil energy sources mainly contributed to the slump in the coal industry. The coal industry in China is undergoing a very tough period.

ChallengesHere is a brief summary of some of the coal industry’s challenges.

Demand and Supply Decline. For the first 11 months in 2015, the coal supply in China was 3.55 billion tons, declining by 14.67% compared to 2014. For the first 10 months of 2015, coal demand was 3.23 billion tons, a drop of 4.7%. The high-speed growth in investment and excessive expansion in capacity from 2002 to 2012 resulted in unbalance between coal supply and demand. With continued high levels of coal production even since 2012, the supply-demand ratio in 2014 reached its peak at the value of 1.18.

Price Slump. Since 2012 coal prices in China have been on the decline. The price of coal with a calorific value of 5,500 kcal/kg at Qinghuangdao Port fell by 20.89%, 0%, 13.93%, and 28.57% each year from 2012 to 2015. The price of coal in 2015 dropped to 370 CNY/ton, which was back to the level it saw in 2004.

Benefits Shrink. In 2015, more than 85% of coal enterprises were in a deficit state. Profit declined to 40.08 billion CNY, equal to the level in 2005. And, according to the latest data from the China National Coal Association, the average asset-liability ratio in the coal industry has reached 67.7%—the highest level in the past 16 years.

Investment Declines. Weak coal prices and lower profits have compressed investment in the industry. Fixed-asset investments slowed down beginning in 2013. In 2015, investment was 400.8 billion CNY, 14.4% lower than in 2014.

OpportunitiesTo be optimistic, opportunity coexists with the challenges.

Electric Power Substitution. Electric power substitution means to substitute electricity for coal burning in end-use processes. Using electricity can improve coal-use efficiency, decrease decentralized coal pollution, and rationalize energy consumption. It can improve the consumption ratio of thermal coal in total consumption, which will stimulate the rational uti-lization of coal. What’s more, substituting electricity for decen-tralized coal use benefits larger and more efficient enterprises and contributes to eliminating less-modern facilities.

Belt & Road. India and Southeast Asia import large amounts

of coal. The Silk Road Economic Belt and the 21st Century Mari-time Silk Road (Belt & Road)—a development strategy proposed by President Xi Jinping to increase exports, especially to Eur-asia—can increase China’s coal exports to these countries. In addition, the infrastructure in some underdeveloped areas like Africa and Central Asia can’t satisfy their needs for economic development. China can provide them with steel, building ma-terials, and other energy-intensive products, which can stimu-late domestic coal consumption and then relieve the pressure of oversupply. Belt & Road also provides a big chance for coal enterprises in China to exploit the international coal market and participate in international competition.

Energy Internet. The energy internet is an energy equiva-lence exchange and sharing network, which links the coal net-work, oil network, gas network, and other energy networks by using information technology, intelligent management technol-ogy, to realize energy bidirectional flows. The energy internet is end user–focused, so those who have the most customers will win. With the background of an energy internet and electric power system reform in China, coal enterprises can set up elec-tricity companies and sell electricity. This provides coal enter-prises with a chance to dominate both the coal and end users in energy market.

Support PoliciesThe Chinese government has issued lists of policies to help the coal industry recover, which are mainly focused on elimi-nating “backward capacity” (polluting, unsafe, inefficient, and other suboptimal enterprises), controlling the amount of coal produced (“yield control”), supporting clean coal development, and the like. For example, Opinions on Solving Excessive Capac-ity and Recovering Coal Industry (issued by State Council on February 5, 2016) indicates that backward capacity that doesn’t conform to industrial policies will be eliminated. Notifications on Implementing the Treatment Measures on Illegal Coal Mines (issued by National Development and Reform Commission on May 26, 2015) points out that if thermal power enterprises purchase coal produced by illegal coal mines, the amount they are allowed to generate will be reduced, as punishment.

The coal industry in China has suffered from serious depres-sion since 2012, and the tragedy continues in 2016. Fortunately, the opportunities above have provided great support, and the coal industry is striving to work its way out of the depression. The coal industry in China still has bright prospects. ■

—Niu Dongxiao, PhD, a professor at North China Electric Power University (NCEPU), has been named distinguished Cheung

Kong Scholar by the Ministry of Education and has outstanding achievements in the field energy management, load forecast-ing, energy system evaluation, and more. Song Zongyun and

Xiao Xinli are doctoral students in the School of Economics and Management, NCEPU.

China’s Coal Industry: Status and OutlookNiu Dongxiao, Song Zongyun, and Xiao Xinli

to subscribe to the e-letter, please visitwww.powermag.com/e-letter-signup

26032

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