Power 2013 07

Vol. 157 • No. 7 • July 2013

Dealing with Drought Power in Indonesia Fuel Delivery System Upgrades ORP Predicts WFGD Chemistry ELECTRIC POWER Conference Reports

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Established 1882 • Vol. 157 • No. 7

July 2013

ON THE COVER Severe and record-setting droughts around the world have resulted in significantly reduced power generation in some nations. Worldwide, generators at both thermal and hydropower plants—including Hoover Dam, on the border of Arizona and Nevada, pictured here with a visibly low water level in the impounded Lake Mead in November 2010—are looking at ways to cope with increasing constraints on water supplies. Courtesy: Gail Reitenbach

COVER STORY: WATER MANAGEMENT 28 Water Issues Challenge Power Generators Drought, resulting in low inland water body levels and higher temperatures, has forced operational adjustments and even plant shutdowns. Both thermal and hydro plants are exploring waterwise strategies to cope with what is starting to look like the new normal. We review some recent technology installations, as well as R&D projects, designed to minimize freshwater use.

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SPECIAL REPORTS POWER POLICY

34 Indonesia: Energy Rich and Electricity Poor Imagine trying to plan and operate an electricity system in a nation consisting of more than 17,500 islands. Even though it boasts significant coal and natural gas reserves, Indonesia’s generation and transmission assets struggle to keep up with the pace of economic development.

WATER TREATMENT

40 ORP as a Predictor of WFGD Chemistry and Wastewater Treatment Measurement of oxidation-reduction potential (ORP) enables you to predict wet flue gas desulfurization (WFGD) absorber chemistry and could help you predict process equipment corrosion and wastewater treatment requirements.

PLANT DESIGN

44 The Case for Utility Boiler Fuel Delivery System Upgrades An ASME subcommittee has investigated potential fuel delivery system upgrades on three typical 500-MW wall-, tangential-, and cyclone-fired boilers. Its suggested upgrades have a simple payback of no more than two years. What are you waiting for?

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FEATURES ASSET MANAGEMENT

50 EMP: The Biggest Unaddressed Threat to the Grid Electromagnetic pulse (EMP) is a force of nature that can wreak havoc with much of our modern electronic infrastructure, and credible sources claim that at least one nation has been working on a super-EMP nuclear weapon for over a decade. So why has there been no federal-level response?

53 Beacon Power Makes a Comeback In the power generation and delivery industry, being ahead of your time—particularly if you’re ahead of regulations—can prove disastrous for business. This is the story of one such company that’s getting a second chance. Good thing, too, as the need for its services is only going to accelerate.

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ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY

56 Gas-Electric Integration “Swamps” All Other Issues This year’s roundup of selected ELECTRIC POWER Conference sessions starts with the ever-popular State of the Industry keynote and Executive Roundtable discussion. Gas got a lot of air time, as you’d expect, but there was one threat on the industry’s horizon that almost nobody wanted to address.

60 Is Gas Getting Too Hot to Handle?

Gas-fired generation has a lot going for it, especially for fast-response and distributed generation needs, but the volatile generation market is revealing some unwelcome effects on both gas-fired plants and their owners.

62 What Does the Market Expect from Gas Plants?

Even with favorable natural gas prices, building new gas-fired plants can be a challenge. The reasons, in the U.S., vary with the region.

64 The Beguiling Promise of the HTGR High-temperature gas-cooled reactors (HTGRs) are back as the next new thing (after small modular reactors) because they promise a laundry list of desirable features and benefits.

65 Wind Resources Face Market and Policy Headwinds It’s a familiar story: The boom-bust construction cycle is fueled by an on-again/offagain federal production tax credit for wind generation.

66 Fighting Transformer Fires Transformer fires can be especially unpredictable and deadly—unless you heed this sound advice from a Consolidated Edison presenter.

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NUCLEAR POWER

67 Too Dumb to Meter, Epilogue Here’s the conclusion of POWER’s exclusive serialization of the book Too Dumb to Meter: Follies, Fiascoes, Dead Ends, and Duds on the U.S. Road to Atomic Energy

by Contributing Editor Kennedy Maize.

DEPARTMENTS SPEAKING OF POWER

6 Four Strange-but-True Stories GLOBAL MONITOR

8 12 13 14 16

Get More POWER on the Web In the Features section of the online issue, you’ll find a web-exclusive report by Senior Writer Sonal Patel on the American Wind Energy Association conference—“The State of Wind Power.”

And remember to check our What’s New? segment on the homepage regularly for just-posted news stories covering all fuels and technologies.

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Power Sector Laments Europe’s Uncertain Future Energy Policy THE BIG PICTURE: Parched Turkey Prepares to Host First ATMEA 1 Nuclear Reactors Energy Storage Developments and Demand Ramp Up E.ON Avoids Shuttering Ultramodern German Combined Cycle Units Despite Profit Concerns 18 POWER Digest FOCUS ON O&M

20 Industrial Wireless Sensors: A User’s Perspective LEGAL & REGULATORY

26 Exporting Natural Gas

By Steven F. Greenwald and Jeffrey P. Gray, Davis Wright Tremaine

71 NEW PRODUCTS COMMENTARY

76 Bridging the Gap Between Company and Community

By John G. Waffenschmidt, Covanta Energy Environmental Science and Community Affairs

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POWER July 2013

Foto: Knut Laubner, Bonn

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POWER July 2013

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SPEAKING OF POWER

Four Strange-But-True Stories ast month’s column, “Opinions à la Carte,” prompted an unusually high number of emails from readers. Unexpectedly, the responses to the different format were universally favorable. In my decade of writing these editorials, this was the first time reader response was unanimous. It seems you favor bite-sized appetizers rather than a single, large portion of opinion. To assuage your appetite, these four stories caught my eye over the past month. My virtual door is always open. Send your comments or ideas to me at robertp@powermag.com.

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new off-shore locations, often as not in the U.S. Load migration coupled with lucrative feed-in tariffs paid mostly by residential rate payers has accelerated rate increases, with no end in sight. Also, the EU’s moribund economy has deflated the cost of CO2 emission allowances, from about €35.90 in 2008 to about €3 today, which means coal-fired generation is now the country’s cheapest electricity supply option.

Ironically, the same German environmentalists who succeeded in coaxing trillion-dollar subsidies for wind and solar

UK Green Madness Continues The coal-fired Drax power station, the largest in the UK, burns 38,000 tons of coal a day and supplies 7% of the UK’s power needs. New UK renewable standards forced the plant to shut down the first unit in April to begin a $1.1 billion conversion of its six boilers from burning coal to burning wood chips. Here’s the rub: The plant will ultimately burn 60% more than the entire UK annual wood supply, so most of the wood chips will be harvested from U.S. forests, shipped by boat 3,000 miles across the pond, and then hauled by train to the plant site.

The idea seems ludicrous until you follow the money. To boost the use of “carbon neutral” fuels, the UK government agreed to give the same near-100% “renewable subsidy” that now goes to onshore wind farms to coal plant owners that make the fuel switch. A new UK carbon tax, starting at $24.80 per metric ton and doubling by 2020, took effect April 1 and also spurred the conversion decision. UK news sources reported that about half a million people were unable to pay their rising energy bills last winter; many resorted to burning used books in their hearths because it was cheaper than burning coal.

Loan guarantees have produced only 1,188 permanent jobs—a cost of $13.46 million per job!

Environmentalists Trigger German Coal Rebound The rapidly increasing price of electricity in Germany (currently 35¢/kWh for households, 17¢/kWh for industry, on average) has flattened that country’s economy and forced many large industrial companies to find 6

and convinced the government to close the country’s nuclear plants have unpredictably caused German utilities to build more coal-fired plants—up to 25 new plants were reported by one German news source. It’s no wonder that the Washington Post calls the EU energy policy the “greenenergy basket case.”

EPA’s “Sue and Settle” Sidesteps Congress Since 2008, environmentalists have adopted the tactic of filing lawsuits to further their overreaching regulatory goals rather than pursuing change through the legislative or regulatory process, as Congress intended. The process only works when you have an administration that is sympathetic to the goals of those filing the suits.

The sue-and-settle process sidesteps the regulatory rule-making process by bring suit against the Environmental Protection Agency (EPA), for example, for missing a regulatory deadline. The EPA then enters negotiation with the group that brought the lawsuit to reach a settlement, which is then approved by the federal court. The agency next goes into overdrive to produce new regulations to comply with the court order, all the while blaming the environmental group or the court for “requirwww.powermag.com

ing” the new regulations.

In 60 sue-and-settle cases filed from 2009 through 2012, the EPA never defended itself in court, allowing the demands of the organization that brought the lawsuit to prevail (34 of these cases alone were filed by the Sierra Club). In each case, the EPA failed to disclose the lawsuits to Congress, stakeholders, or the Office of Management and Budget, as required by law, until the consent decree was finalized. So much for President Obama’s January 2009 promise that his administration would be

“committed to creating an unprecedented level of openness in government.” Congress is now considering legislation to put an end to this practice.

Job Creation Promise Falls Flat Do you remember when in 2008, President Obama promised to create 5 million jobs over 10 years by investing stimulus funds into “shovel ready” projects? You are surely familiar with the many companies that have gone bust after taking taxpayer money (Solyndra is just the most infamous). Often overlooked are those job creation promises. In early May, the Department of Energy (DOE) quietly released on its website a list of loan guarantee projects with the number of documented permanent jobs created. A quick analysis of the data shows that for the $15.99 billion spent on renewable projects since 2009, DOE Section 1705 (renewable projects) loan guarantees have produced only 1,188 permanent jobs—a cost of $13.46 million per job! The data once again evidences that the federal government cannot compete with private enterprise when it comes to picking technology winners and permanent job creation. ■ —Dr. Robert Peltier, PE is POWER’s editor-in-chief.

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POWER July 2013

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Power Sector Laments Europe’s Uncertain Future Energy Policy Energy policy in the European Union (EU) is in upheaval as concerns mount over the impact of energy costs on the competitiveness of the power industry. Over April and May, the EU voted on but failed to pass several crucial climate measures, from setting a renewables target for 2030 to boosting the carbon price of its floundering Emissions Trading System (ETS). Industry groups have said the policy uncertainty could prove expensive.

On May 22, EU leaders held the first of a special series of thematic discussions on economic sectorial and structural issues, but ensuing draft conclusions from that debate on how to limit the impact of energy costs seem to prioritize industrial competitiveness over climate change, calling on member states to ensure “competitive” energy prices and a diversification of energy supply. The conclusions also reportedly pledge to review the causes of Europe’s soaring energy prices by the end of the year.

Separately, the European Commission in May reportedly drew up a draft action plan asking member states to consider removing or temporarily freezing taxes, including renewable and network levies, on energy-intensive industry for a period of two years.

Just a day before that summit (May 21), the European Parliament failed to set a renewables target for 2030 in the 40% to 45% range, approving instead a nonbinding resolution that says the EU should try to achieve a share of renewables in the overall energy mix of more than 30%. The bloc currently has three 2020 climate targets: an improvement of 20% on the continent’s carbon dioxide emissions, a 20% share of renewables, and a 20% improvement in energy efficiency.

And in April, by a 334–315 vote, European Parliament members rejected a proposed reform to reverse the sinking price of carbon and subsequent glut of permits in the ETS carbon trading program, Europe’s flagship climate policy that has seen a turnover that reached €90 billion in 2010. The proposed reform, also known as “backloading,” would have withheld 900 million carbon allowances and steepened an annual decline in allowance numbers to shore up carbon values. “We believe that backloading is now politically dead and it is very unlikely that any political intervention in the scheme will be agreed during the third phase [2013–2020],” said Stig Schjølset, head of EU Carbon Analysis at Thomson Reuters Point Carbon. “We do not envisage prices rising much above the current €3 mark and they may well drop lower at least until the end of the third phase. The focus will now shift towards structural, more long-term oriented measures but certainly this vote makes the EU ETS irrelevant as an emissions reduction tool for many years to come,” he said.

The events have prompted Europe’s electricity industry association EURELECTRIC, an entity whose members represent the power sector in 32 European countries, to decry current EU climate and energy policies as a source of “confusion, not clarity.

Today’s policy framework is half European, yet still half national; half market-based, but also half command-and-control; and seems to be only half committed to the ETS,” says a May letter to EU heads of state from EURELECTRIC president and CEO of ENEL, Fulvio Conti.

Conti called on leaders to put an end to investor uncertainty and “urgently agree on a coherent top-down package of proposals which establish an ambitious, firm, long-term, economy-wide greenhouse gas reduction target for 2030 up to 2050, in line 8

with the European Council goal.” It is imperative, he said, that the body work out the “regulatory disorder” not just to avoid windfall taxes and retroactive changes, but also to give investors a foundation through long-term policy. Without early investment signals, Europe could face a “lost decade” of climate and energy policy inaction between 2020 and 2030, and this would require a costly sprint to decarbonize in the last two decades before 2050, the group said, citing a report titled “Power Choices Reloaded” that it published in mid-May. Among “serious” measures that should be tackled is an improved market design, including a European coordinated approach to capacity mechanisms in which “all assets contributing to the security of supply” are “fairly remunerated,” Conti and the heads of Gasterra, GDF Suez, Iberdrola, Eni, RWE, E.ON, and Gasnatural Fenosa urged in a separate release. Also required is a “more sustainable approach” to the promotion of renewables “so as to reduce costs to citizens and favour a greater convergence between member states.”

Siemens Energy, too, has voiced concerns about European en-

1. More efficiently siting renewables. A study by Siemens Energy analyzing power-producing systems across Europe identifies considerable potential for optimization and concludes that if renewables installations were built at sites in Europe that offer the highest power yields (as shown in this image, which includes associated extension of the power grid), nearly €45 billion of investment could be saved by 2030. Several hurdles would need to be overcome, however, including implementation of a European Union–wide integrated electricity market. Courtesy: Siemens

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POWER July 2013

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ergy policy direction. A study that the global power equipment and services company is conducting along with the Technical University of Munich to ascertain the utilization rate of resources of energy systems worldwide and how reliable that supply is suggests that billions are being wasted every year as a result of inefficiencies in worldwide systems and markets—and particularly in Europe’s. For example, “[i]f [renewables] installations were built at the sites in Europe that offer the highest power yields, some €45 billion of investment in renewables could be saved by 2030,” Siemens concludes (Figure 1).

But such a feat would require, among many other complex needs, a strongly centralized structure that could necessitate a single integrated energy market for Europe. In preparation for a presentation of the findings of Siemens’ study, and to offer possible solutions to future energy challenges at the World Energy Congress in South Korea this October, Michael Süß, CEO of Siemens’ Energy sector, has been engaging in a series of six roundtables with industry, policy-makers, and experts. The takeaway from the very first one in Brussels this May: Creating one European market is indeed an idealistic experiment, and its foremost challenge will lie in harmonizing 27 diverse European energy landscapes and creating political consensus among member states on how to proceed.

In another related development, ambitions to import solar power generated from North Africa to Europe, as initially proposed by the Desertec Industrial Initiative (Dii), have deflated.

In late May, Dii CEO Paul van Son told EU media portal Euractiv .com that the initiative had abandoned “one-dimensional” thinking about the €400 billion plan to source 15% of Eu-

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rope’s renewable power from the Maghreb by 2015. Dii is instead looking at a business model that creates integrated renewables markets.

Susanne Nies, head of Energy Policy and Generation at industry association EURELECTRIC, put it into better perspective. “Firstly, at a very basic level, we are still missing lines and capacities for export. Building these is technically difficult because of the deep waters in the Mediterranean,” she said. Beyond the link between North America and Europe, consideration should be given to how some countries, such as Spain, are already struggling with excess renewables capacity, and to cross-border interconnection lines, which are also congested.

“Secondly, it is difficult to argue that the EU needs the additional [renewable energy supply] capacity,” she pointed out.

Renewables in Europe are already competing to replace existing conventional plants, and importing more renewable power would require “solving plenty of system issues,” a move that could require “giving time to the technical, economic, and regulatory framework to adjust.”

Finally, North Africa’s own power consumption is slated to grow tremendously, and it already exceeds demand, she said. “It would be a big mistake for Africa to neglect its own, indigenous power generation and risk its own security of supply for the sake of satisfying the demand of Europe.”

The 56-member Dii continues to have supporters—including RWE, E.ON, Deutsche Bank, ABB, and the German reinsurer Munich RE—even though it saw the high-profile withdrawal of Siemens and Bosch, and Spain’s reluctance to engage in deals given its current austerity measures.

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POWER July 2013

THE BIG PICTURE: Parched Water scarcity as it relates to energy use is becoming a major concern. Cooling water accounts for more than 50% of national water withdrawals in several developed countries (Eurostat 2010), and it is becoming more important as developing countries become more energy-intensive. At a river basin level, dry periods have triggered rolling blackouts, and not just because hydropower plants are forced to operate at dangerously low levels. POWER takes a look at more recent droughtrelated outages around the world.

–Copy and artwork by Sonal Patel, Senior Writer

In 2011, Texas experienced one of the most extreme droughts in the state’s history. In December 2011, sources of cooling water supplies were at historic lows for almost 11,000 MW of generating capacity. In addition, market electricity prices rose dramatically in August 2011, during the height of the drought and peak electricity demands: real-time electricity prices on Texas’ wholesale market hit the state’s market cost cap of $3,000/MWh on five days in August.

Drought events in 2003 and 2006 in Europe required the shutdown or curtailment of a number of thermoelectric units. During the 2003 event, France was forced to shut down as much as 25% of its nuclear fleet.

Some parts of China are critically vulnerable to drought, but though it is pursuing plans to massively increase generation capacity, including coal, nuclear, and hydro plants, China's per-head freshwater resources are only one quarter of the global average. During 2009, painful water shortages in southwest China crippled the region's rich hydropower supplies. In 2011, the country implemented power rationing stricken by low water levels in the mighty Yangtze River.

In 2010, Venezuela warned of a power system collapse as a drought pushed water levels precariously low in the country's biggest hydropower dam.

Brazil this winter suffered its worst drought in 50 years, which impacted power generation in the country that depends on hydropower for 67% of supplies. Its power sector's vulnerability to drought was especially highlighted by the 2001-2002 energy crisis.

East Africa had critical power cuts as water levels in the hydropower-dependent region reached their lowest levels in 60 years in 2010 and 2011, including in Kenya, Uganda, Tanzania, and Ethiopia (which plans to increase its hydro capacity to 15 GW from 1 GW within the next decade)

inches of water per year

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-60 Source: NOAA/GFDL CM2.1

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New Zealand in 2008 urged households to cut power consumption by 15%, concerned about low water levels in the country's lakes. The public was also asked to save power for similar reasons in 2001, 2003, and 2006.

THE WORLD’S WATER RESOURCES The total volume of water on Earth is about 1.4 billion cubic kilometers (km³). Freshwater resources make up around 35 million km³, or just about 2.5% of the total volume.

Of these freshwater resources, about 24 million km³ or 70% is in the form of ice and permanent snow cover. Freshwater lakes and rivers contain only around 0.3%of the world's freshwater. The remaining 30% is groundwater.

70% of the world’s blue water withdrawals at a global level go to irrigation, 20% for industry use, and 10% for domestic use

CHANGE IN PRECIPITATION BY END OF 21ST CENTURY Research suggests that over the next century, wet areas will get wetter and dry areas drier.

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The vast grid failure that shut off the lights to half of India's 1.2 billion citizens in August 2012 was blamed in part to low rainfall that restricted hydropower generation.

From 2000 to 2010, southeastern Australia experienced a “one in a thousand year drought.

Generation at three coal plants was curtailed in 2007 to protect municipal supplies.

Source: UNEP

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POWER July 2013

Turkey Prepares to Host First ATMEA 1 Nuclear Reactors An agreement signed by Turkish Prime Minister Recep Tayyip Erdogan and Japan’s Prime Minister Shinzo Abe this May could pave the way for the world’s first ATMEA 1 reactors to be built in Turkey in the 2020s. Construction of four reactors using the midsize nuclear reactor design developed through the collaboration of French nuclear firm AREVA and Japan’s Mitsubishi Heavy Industries (MHI) could cost as much as $21 billion, begin as early as 2017, and be completed by 2023.

The Gen-III+ pressurized water reactor (PWR) design developed by the Atmea French-Japanese joint venture that was established in 2007 has a capacity of 1,100 MWe (Figure 2). Developed to be marketed to countries embarking on new nuclear programs, the design has three active and passive redundant safety systems and an additional backup cooling chain, like AREVA’s EPR. It also has a 37% net thermal efficiency, 157 fuel assemblies, a 60-year life, and the capacity to use mixed-oxide fuel only. French nuclear regulator ASN approved the general design in February 2012.

If the agreement proceeds, the proposed reactors could make up Turkey’s second nuclear power plant in the northern city of Sinop on the Black Sea. An international consortium of Japan’s MHI, Itochu Corp., French utility group GDF Suez, and the Turkish Electricity Generation Co. (EUAS) would further develop the project. ATMEA would provide the nuclear island for the plant construction contract.

Turkey imported much of its energy in 2012 at a cost of about $60 billion, and its future energy policy stresses energy efficiency and security. Development of nuclear power is expected to slash reliance on Russian and Iranian gas for power. But though a nuclear

power program has been under development since the 1970s, plans to build the country’s first nuclear plant at Akkuyu, near the port of Mersin, were only made concrete in August 2009, when two agreements between Turkish Atomic Energy Authority (TAEK) and Russia’s Rosatom were inked for the construction of four 1,200-MWe AES2006 units. That $25 billion project is expected to break ground this September, and the first unit could come online by 2019.

According to developers AREVA and MHI, the ATMEA 1 reactor design is under consideration in Jordan and Vietnam. Media reports suggest Jordan could soon decide which nuclear technology

2. The first of its kind. An agreement between Japan and Turkey this May paves the way for the construction of four ATMEA 1 reactors in Turkey’s northern city of Sinop, on the Black Sea. ATMEA 1 is a midsize Generation III+ pressurized water reactor of 1,100 MWe net, developed by ATMEA, the Mitsubishi Heavy Industries and AREVA joint venture. Courtesy: ATMEA

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it will use to build two planned nuclear reactors, one expected to begin construction this year and be completed by 2020, and the other for operation by 2025. Along with the ATMEA 1 design, Jordan is evaluating AtomStroyExport’s AES-92 model VVER-1000.

Energy Storage Developments and Demand Ramp Up Despite technical and financial hurdles, annual global demand for grid-scale energy storage is expected to soar to 185.4 GWh by 2017, which means a possible 231% average year-on-year demand growth between 2012 and 2015, according to Lux Research. A report recently released by the research firm projects that Japan, China, the UK, Germany, and the state of Arizona will lead the world in grid storage, accounting for about 58% of global demand in 2017.

By 2017, who uses energy storage will also vary, the firm forecasts, projecting that ancillary services and renewable energy integration will only account for 1.4% of global demand while renewable energy time shifting will take up a 54% share. Among technologies that will lead the surge in demand for energy storage are vanadium redox batteries, followed by sodium-sulfur, sodiumnickel chloride, and zinc-bromine flow batteries. Lithium-ion batteries will take a smaller share, while flywheels will retain just 2% of the market in 2017, Lux predicts. (See “Beacon Power Makes a Comeback” on p. 53 for more on flywheel generation.)

The month of May alone saw several key developments for energy storage. The U.S. Senate reintroduced bipartisan legislation that would create an investment tax credit for energy storage technologies of all types, closely mirroring a bill recently introduced in the House. The Storage Technology for Renewable and Green Energy (STORAGE) Act was originally introduced in the 112th Congress in both chambers with bipartisan support. The measures follow

3. Hybrid geothermal compressed air storage.

A site identified by the U.S. Department of Energy’s Pacific Northwest National Laboratory (PNNL) and federal power company the Bonneville Power Administration, called Yakima Minerals, is about 10 miles north of Selah, Wash. It could house a geothermal compressed air energy storage facility with a capacity to generate 83 MW and store 150 MW. Courtesy: PNNL

4. A pilot project. The California Energy Commission and Pacific Gas and Electric Co. (PG&E) unveiled the Yerba Buena Battery Energy Storage System Pilot Project, a system that charges a utility-scale sodium-sulfur battery, shown here. Courtesy: PG&E

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legislation to provide Master Limited Partnership parity to extend a pass-through corporate structure and tax treatment to several renewables sectors as well as to energy storage.

Possible Compressed Air Energy Storage Sites. Also in May, the U.S. Department of Energy’s Pacific Northwest National Laboratory (PNNL) and federal power company the Bonneville Power Administration (BPA) said they identified two possible sites in eastern Washington state to build compressed air energy storage (CAES) facilities that could temporarily store the Northwest’s excess wind power. CAES plants use a large air compressor that is powered when electricity production is abundant, which pushes pressurized air into an underground geologic storage structure.

Later, when power demand is high, the stored air is released back up to the surface, where it is heated and rushes through turbines to generate electricity. CAES plants can regenerate as much as 80% of the electricity they take in, according to PNNL. Only two CAES plants exist in the world today, however—one in Alabama and one in Germany—and both use manmade salt caverns to store excess electricity. The PNNL-BPA study examined a different approach: using natural, porous rock reservoirs that are deep underground to store renewable energy. Analysis identified two particularly promising locations in eastern Washington. One, dubbed the Columbia Hills Site, is just north of Boardman, Ore., on the Washington side of the Columbia River and has a storage capacity of 231 MW. The second, called the Yakima Minerals Site, is about 10 miles north of Selah, Wash., in an area called the Yakima Canyon and has a storage capacity of about 150 MW. The Columbia Hills Site could access a nearby natural gas pipeline, making it “a good fit for a conventional compressed air energy facility.” Such a conventional facility would burn a small amount of natural gas to heat compressed air that’s released from underground storage, PNNL said. The Yakima Minerals Site, however, has little easy access to natural gas. So the research team devised a hybrid facility that would extract geothermal heat from deep underground to power a chiller that would cool the facility’s air compressors, making them more efficient. Geothermal energy would also reheat the air as it returns to the surface (Figure 3).

BPA is now expected to use the performance and economic data from the study to perform an in-depth analysis of the net benefits CAES could bring to the Pacific Northwest. The results could be used by one or more regional utilities to develop a commercial CAES demonstration project.

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Sodium-Sulfur Battery Pilot. In the U.S., also this May, the California Energy Commission and Pacific Gas and Electric Co. (PG&E) unveiled the Yerba Buena Battery Energy Storage System Pilot Project, a system in east San Jose, Calif., that charges a utility-scale sodium-sulfur battery (Figure 4) manufactured by NGK Insulators when demand is low and then sends reserved power to the grid when demand grows. “The system has the potential to provide important services for balancing energy supply and demand, [and] helping to support greater integration of intermittent renewable generation,” the commission said in a statement. The project has a 4-MW capacity that can store more than 6 hours of energy. PG&E is working with the Electric Power Research Institute to study how sodium-sulfur battery energy storage can improve power quality and reliability.

Undersea Pumped Storage. Norwegian research scientists announced they would attempt to realize a concept of storing electricity at the bottom of the sea using high water pressure. The idea entails use of an underwater pumped hydroelectric power plant. “Imagine opening a hatch in a submarine under water. The water will flow into the submarine with enormous force. It is precisely this energy potential we want to utilize,” explains Rainer Schramm, inventor and founder of the company Subhydro AS to Gemini.no. Schramm is collaborating with Scandinavian research firm SINTEF on the concept. “Many people have launched the idea of storing energy by exploiting the pressure at the seabed, but we are the first in the world to apply a specific patent-pending technology to make this possible,” he adds.

Schramm’s concept essentially converts mechanical energy using a reversible pump turbine, as in a normal pumped storage 5. Storage under the sea.

Norwegian researchers are working to realize a concept that stores power using an undersea pumped hydroelectric power plant. To use the water pressure on the sea bed, mechanical energy is converted by a reversible pump turbine, as in a normal pumped storage hydroelectric plant. Source: Knut Gangåssæter/Doghouse

hydroelectric plant (Figure 5). “A pumped storage power plant is a hydroelectric plant which can be ‘charged’ up again by pumping the water back to the upper reservoir once it has passed through a turbine. This type of power plant is used as a ‘battery,’ when connected to the power grid,” the inventor explains. The plant’s turbine will be connected to a tank on the seabed at a depth of 400 to 800 meters. The turbine is fitted with a valve, which when opened, allows water to flow in and start turning the turbine. The turbine drives a generator to produce electricity. When the tanks are full, the water is removed by running the turbine in reverse, so that it functions as a pump.

“One can connect as many tanks as one wishes. In other words, it is the number of water tanks that decides how long the plant can generate electricity, before the energy storage capacity is exhausted,” Schramm says, noting that calculations indicate an electric storage efficiency of about 80% round trip.

A “normal-size” plant could produce about 300 MW for a period of 7 to 8 hours.

E.ON Avoids Shuttering Ultramodern German Combined Cycle Units Despite Profit Concerns German energy giant E.ON in late April narrowly averted idling its Irsching 4 and 5 units in Bavaria, Germany—its most technologically advanced gas-fired generating units that began operations just three years ago at a cost of €400 million.

The 569-MW Irsching 4 (a 2011 POWER Top Plant) was the world’s first to feature a Siemens H-class turbine (Figure 6) and boasts an efficiency of 60.4%. The 860-MW Irsching 5, commissioned in 2010, has an efficiency of 59.7% and is a multi-shaft plant with two steam turbines, each one with a waste heat recovery boiler.

But E.ON had said the highly efficient combined cycle units were unprofitable because, while Europe’s wholesale

6. The 60-Hz H-Class. E.ON’s Irsching 4 unit in Bavaria was the test site of Siemens’ advanced 50-Hz “H-class” SGT5-8000H gas turbine until the end of 2009, when it was expanded into a combined cycle gas turbine plant by adding a waste heat recovery boiler and a steam turbine. The first of three 60-Hz versions (SGT6-8000H, shown here) of the gas turbine was successfully started at Florida Power & Light Co.’s $900 million Cape Canaveral Next Generation Clean Energy Center in Port St. John, Fla., last November. Cape Canaveral began commercial operations on April 24. The 274-MW turbine is also capable of reaching efficiencies topping 60% in combined cycle operation, Siemens says. Courtesy: Siemens Energy

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power prices had fallen by 50% since 2009, low-cost coal imports and low carbon trading prices had squeezed profit margins of power plants burning much pricier natural gas to near zero.

An agreement reached between E.ON, Germany’s Federal Network Agency, and the local network operator Tennet TSO this April ensures, however, that E.ON will receive “acceptable compensation” for its fixed costs of the two units. Tennet said the units were needed to enable support of tremendous renewables growth in the country and for redispatch measures, if necessary.

Germany’s Federal Network Agency recently ordered that fixed costs should be paid to power plants that are operated more than 10% of the time on demand of transmission operators. A paradigm market design in Germany was still necessary, as E.ON CEO Johannes Teyssen said in a statement, particularly one that provides acceptable compensation for maintaining technologically advanced, climate-friendly generating capacity. Germany is still “too fixated on megawatts,” installing wind turbine after wind turbine and solar panel after solar panel “in the belief that by doing so it has already transformed its energy system,” he added.

The traditional distinction between generation, transmission, distribution, and consumption is “dissolving,” Teyssen said, pointing to the evolution of smart grids. The focal point of these grids isn’t the traditional energy utility but rather the customer. “Customers can now choose whether they want to buy energy from the grid or make it themselves and perhaps even market it to others.” E.ON is part of that transformation, he said, and that will create a greater earnings strength and lasting value for its shareholders.

POWER Digest Saudi Arabia and Egypt Sign $1.6 Billion Agreement to Link Electricity Grids. Under an agreement signed on June 1, Saudi Arabia’s majority stateowned utility, Saudi Electricity Co., and Egypt’s state power company, Egyptian Electric Holding Co., will share the cost of building a 3,000-MW undersea transmission cable to link their electricity grids. The $1.6 billion deal anticipates the 20-kilometer-long network will be finished by 2015. Egyptians currently suffer intermittent blackouts during the day as a result of inadequate 18

supply. About 45% of Saudi Arabia capacity is idled during the cooler winter, while cooling accounts for more than 50% of electricity demand in summer.

Both countries see a demand surge during the holy month of Ramadan, which begins this year in July.

Scotland Approves World’s Largest Wave Power Farm. Scotland’s government approved Aquamarine Power’s 40-MW wave farm—to date, the largest in the world—off the northwest coast of Lewis, Scotland, marking a major milestone for the fledgling marine power sector. The green light from the government and its regulator, Marine Scotland, follows onshore planning approved last September, and it means the Edinburgh firm’s subsidiary, Lewis Wave Power Ltd., could begin installing its near-shore Oyster wave energy machines at the site in the next few years, once necessary grid infrastructure has been put in place. The project envisions deployment of between 40 and 50 Oyster devices along the coast at Lag na Greine, near Fivepenny Borve.

Aquamarine Power is currently testing a second-scale wave machine known as the Oyster 800 at the European Marine Energy Centre in Orkney, which is now grid-connected.

Philippines Experiences Major Blackout. Half of Luzon, the largest island in the Philippines, suffered a 10-hour-long blackout on May 8 after the Calaca-Bian 230-kV line “tripped” and triggered a system disturbance that knocked six power plants offline. The blackout affected the capital city of Manila and several adjacent provinces.

Grid operator National Grid Corp. of the Philippines (NGCP)—which was privatized in 2007 and is now co-owned by the Chinese government—initially attributed the failure of the transmission lines to a “generation deficiency,” but a later investigation by the country’s Department of Energy suggested the event could have been caused by a bush fire in Talisay, Batangas.

The problem is thought to have first affected a unit of Semirara Mining Corp.’s 600-MW Calaca Coal Power plant, then the 1,218-MW Sual coalfired power station in Pangasinan, the 1,200-MW Ilijan combined cycle power plant, First Gas Power’s 1,000-MW Santa Rita and 500-MW San Lorenzo plants, and the 460-MW Quezon power plant.

Reports suggest about eight other plants may have been affected. The DOE has asked NGCP to explain why its autowww.powermag.com

protection system did not prevent the outage from spreading. Industry groups in the country have, meanwhile, warned that Philippine’s power consumption is growing at 4.5% per year and that the country could see even more frequent blackouts if it does not add at least 600 MW by 2015.

UAE Begins Construction on Second APR-1400 Reactor. Construction officially began on the United Arab Emirates’ (UAE’s) second new nuclear power reactor on May 28 at the Barakah site in western Abu Dhabi. A South Korean consortium headed by Korean Electric Power Corp. will build and manage the APR-1400 reactor for the Emirates Nuclear Energy Corp. (Enec), one of four planned for that site. Bechtel is to provide project management for the plant. Construction of Barakah 1 began in July 2012. Construction licenses for both units have been awarded by the Federal Authority for Nuclear Regulation, and Enec plans to apply for operating licenses for Units 1 and 2 in 2015. All four units are expected to be completed between 2017 and 2020.

Japanese Reprocessing Facility Moves Closer to Operational Start.

Japan’s delay-plagued Rokkasho reprocessing facility in Japan’s northern Aomori Prefecture this May completed a test that proves its vitrification lines, marking a milestone that moves it closer to commercial operation. The facility owned and operated by Japan Nuclear Fuels Ltd. was scheduled to start up in 2008, but commissioning has been halted 19 times because of technical and financial problems, particularly problems in the locally designed vitrification plant for high-level waste, according to the World Nuclear Association.

Spent nuclear fuel has been accumulating at the site since 1999. The plant requires a license from the Nuclear Regulation Authority before it can begin operating to produce about four tonnes of fissile plutonium per year, enough for about 80 tonnes of mixed oxide fuel. Though only two nuclear reactors remain operational following the Fukushima Daiichi accident, and Japan’s future nuclear power policy is in limbo, the country’s waste management focus continues to be on reprocessing before underground disposal. Japan’s government and private companies have invested more than $21 billion in the Rokkasho facility since construction began in 1992. ■ —Sonal Patel is POWER’s senior writer.

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Industrial Wireless Sensors: A User’s Perspective There are many reasons to anticipate that the use of wireless instrumentation in industrial settings will increase dramatically in the next few years. However, certain stumbling blocks could curtail this deployment. As usual, cost and availability are critical factors when considering potential deployments.

Installed and operating costs of the wireless instruments must be competitive with their wired equivalents if these instruments are to have widespread deployment.

Similarly, wireless offerings must be readily available in a timely manner, preferably from multiple manufacturers, to be able to get deployment traction. In addition, deployment of such instrumentation in an industrial setting—where security and robustness criteria are much more stringent than in residential settings—hinges on user acceptance of verified performance and security requirements as well as those mentioned above. As is the case for many technologies that they utilize, industrial users are typically not wireless system experts but rather technical staff members who have a measurement application for which wireless technology appears to be a viable option.

In 2013, as in recent years, these industrial users need to evaluate many factors when considering a wireless sensor network, including radio performance, battery life, interoperability concerns, standards compliance, and security. With many industrial users considering widespread deployment of wireless instruments, it is imperative that accurate information for applying the technology to real-world applications be available to the end user.

Wireless Sensor Applications Sensing applications for which wireless sensor technology is a good solution are numerous in all types of process and manufacturing plants. Plant designers and plant operators

1. Remote data collection. The blue device in the center of the photo is a wireless sensor used to collect vibration data on a pump that was not previously monitored. Courtesy: Southern Company Services Inc.

are continually searching for new technology to improve their plant operation, performance, and reliability. But before making a significant investment in a new technology such as wireless sensor networks, a plant needs assurance that the technology is ready for industrial use and that the technology provides a clear advantage over an existing technology or provides a function not available with current technology. Which applications fit these criteria depends on many factors, including whether the installation will be at a new plant or an existing facility. Several potential applications are discussed below primarily from the retrofit perspective.

One of the most common wireless sensor applications today is enhanced equipment condition monitoring of critical plant machinery such as pumps, fans, and motors (Figure 1).

Plant maintenance practices have become much more analytical in recent years, but the analysis depends on processand maintenance-type data being readily available. In many situations that type of data is not easily available or not available at all. When most existing plants were built, it was not economically justifiable to install sensors on much of the less-critical machinery. Retrofitting wired sensors to collect the data is still too expensive, and periodically collecting the data manually is not an option due to staff reductions in recent years. Wireless sensors may greatly reduce the installation cost, enabling more data collection and resulting in improved proactive maintenance practices.

Another example of industrial use of wireless sensors, and specifically wireless sensor networks, is in the power plant performance testing area (Figure 2). Performance tests are run periodically to determine the plant efficiency using special test instruments and data collection systems that may only be deployed for several days. Considerable labor costs and time are associated with running cables to all the test instruments. The use of wireless sensors could significantly reduce the time and effort required to set up and tear down test instruments for each test.

Probably the most common use for wireless sensors today is to monitor remote equipment where long wiring runs would be cost-prohibitive. These types of installations tend

2. Wireless layout. This diagram documents conducting wireless sensor testing in preparation for utilizing wireless sensors for performance testing. Source: Southern Company Services Inc.

One device inside PEECC and one outside on platform

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These two devices were on the ground near concrete columns

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POWER July 2013

to be point-to-point applications using proprietary protocols and do not use the wireless sensor networks such as ISA-100.11a or WirelessHART. Currently, the use of wireless sensors in industrial applications appears largely limited to monitoring functions rather than closed-loop control tasks. The use of wireless sensors for closed-loop control application will probably be very limited for several years until there is considerable experience using the technology on monitoring-only applications.

Barriers to Acceptance of Wireless Sensors Whenever a new technology is introduced there are always barriers to its acceptance, and wireless sensors are no exception. The barriers include new technology, increased cost, standards confusion, concerns about the robustness of the products, and cybersecurity.

New Technology. There is always some inherent resistance to change due to uncertainty about the performance of a new technology. Industrial users can be very leery of deploying serial number 1 of anything, especially something as complex as a wireless sensor network.

Once a technology has success in a similar environment, its adoption in the industrial world can increase dramatically and rapidly.

Increased Cost. Some of the early projections for wireless sensor costs were quite low, and this has led many industrial users to expect wireless sensors to have lower installed (lifecycle) costs than traditional wired sensors. However, based on the authors’ experience, so far that does not appear to be the trend with industrial sensors. The wireless portion of the sensor is merely added on to an existing wired sensor, which results in higher costs. The increased component cost can easily exceed the cost savings associated with wiring, particularly for those transmitters that are expected to be deployed for many years (it is not atypical in a power plant for a transmitter to be in one location for 50 years).

There appear to be opportunities for low-cost sensors on many applications, but that may require a mindset change at many plants.

Standards Confusion. The fact that multiple incompatible wireless sensor standards currently have products in the market causes concerns for users that they may choose a standard that eventually will become extinct.

There is also considerable uncertainty

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July 2013 POWER

about what compliance with a standard means. For example, does compliance (or certification) with a standard ensure interoperability between vendors devices, and does it provide some certainty about security?

Uncertainties Concerning Robustness. Industrial products are expected

to be near 100% reliable by most users and, for many users, there is not enough operating experience or pub-

lished test results with the new wireless sensor networks to know whether they meet that expectation. Arguments that wireless networks can be made more reliable than their wired counterparts are difficult to make given that many consider (often incorrectly) the wired networks nearly 100% reliable, if not 100% reliable.

Cybersecurity. In power plants today, all wireless network products are

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subject to extreme scrutiny for cybersecurity vulnerabilities due to the NERC CIP standards. Because the wireless sensor networks are less familiar to IT personnel, they receive even more attention. In some companies, the wireless sensor network will only be allowed to communicate with the plant digital control system using nonroutable protocols, such as serial MODBUS. NERC standard CIP-005-2 Cyber Security Electronic Security Perimeter requires that each facility establish an electronic security perimeter for all critical cyber assets, but it is not clear how to do this for a wireless sensor network that is connected to the plant distributed control system. This hurdle will probably be an issue for several years to come.

Despite all these barriers, there are always a few companies that are willing to experiment with new technologies that show significant promise. These companies in some ways serve the industry as beta testers, and if the equipment performs as expected, other companies will eventually begin to use the new technology.

Multiple Standards Compete Industrial standards play a very important role in today’s highly technical society. Many years ago standards were usually developed after several competing technologies were already established in the marketplace. Today in many cases, standards are developed before products reach the marketplace and actually drive the development of many commercial markets. Such is the case with wireless sensor networks. Three main “standards” have been developed, with each attempting to drive the development of wireless sensors in a particular direction.

The majority of wireless industrial sensor approaches now being deployed or being considered for deployment are based on these three different “standards”: the HART Communications Foundation’s WirelessHART (IEC 62591), the International Society of Automation’s ISA100.11a, and the Industrial Wireless Alliance of China’s WIA-PA (IEC 62601). Aside from these industrial automation standards, users must also be aware of the underlying wireless network standards IEEE 802.11, IEEE 802.15.4, and IEEE 802.15.3a and their interactions with the three principal industrial automation protocols mentioned previously. The main questions being asked by end users revolve around interoperability, reliability, and security.

If there were a worldwide wireless sensor “czar,” then there would probably only be one industrial wireless sensor standard, but in a real, market-driven environment, that will not be the case. Although the presence of multiple standards may be a barrier to industrial acceptance, it is the reality that users must accept, at least for the near future.

A single standard for wireless may not be critical, as the airwaves (unlike wires) are pretty forgiving of multiple protocols. Smart phones today support four or five different wireless protocols, but the user sees a common interface in spite of the underlying protocol variability.

A number of standards issues remain that cause concern for users.

Is one standard “better” than another? With complex systems like wireless sensor networks and varying end-user requirements, there probably is no right answer to this question. The more pertinent question is, Does one or more of the standards meet the industrial user’s current and future needs?

Even this question can be a challenge to answer without actually investing in a system and testing it thoroughly.

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3. Swapping out wired transmitters. The typical end user has high confidence that this approach will work all the time. Source: Taft Engineering

Vendor A wired sensor

Vendor B wired sensor

4. Swapping out wireless transmitters. The typical end user has less confidence that this transition will work. Source: Taft Engineering

Vendor A wireless sensor

Vendor B wireless sensor

5. Multi-vendor wireless sensor network. This

arrangement must ensure that full functionality is possible for all the sensors.

Source: Taft Engineering

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Vendor A wireless sensor Gateway vendor C

Vendor B wireless sensor

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It is even more difficult being a seer and knowing that a technology will succeed in the marketplace and be available decades down the road. Although there is a wealth of technical information published on wireless sensor networks, most of it is not written to the industrial user audience and does not address the most fundamental end-user questions, namely cybersecurity and interoperability. Also, little of the published material is written by an unaffiliated author.

Though skepticism is not always warranted, the end user often sees such material as advancing a vendor agenda and being biased.

Are standards useful? From an industrial user perspective, the most useful aspect of a standard is the strong expectation that compliance with a communications standard will ensure seamless interoperability between different vendors’ products (Figures 3, 4, and 5). The current wireless standards are quite complex, and there may be too little user experience to assess interoperability.

Based on limited testing by the authors, it appears that a third-party gateway will read the wireless sensor process variable reliably, but other secondary information may not be fully available. For example, if one vendor’s sensor is intended to measure vibration, can another vendor’s gateway bring back the spectrum information, or is the information limited to only the 1x or other aggregate values? Also, does compliance with one of these standards provide any guidance to the end user on the security of these devices?

Does it matter whether the standard is a consensus, industrial consortia, or de facto standard? Many people consider consensus standards—those produced by ANSI accredited standard-writing organizations—to be the only true standards. However, many commonly used and very successful standards have been developed by industrial consortia. Each method has its own strengths and weaknesses, but for most users, the standard development process is less important than the final outcome and manufactures’ adherence to the standard.

Is certified compliance necessary? Many questions are related to standards compliance, particularly with complex standards such as WirelessHART and ISA100.11a. Ideally, a trusted certification organization would thoroughly test all devices submitted, and those that pass would receive a certification that the device complies with the standard. This certification would be available to the user to provide assurance that the device is in compliance and meets some minimum functionality defined by the standard. This minimum standard should be clearly defined by the standards organization.

In reality, it is more complicated than that because the standards have a plethora of implementation options, which are very difficult to completely test. As a result, only a very limited set of options, often called a profile, is tested. If a user’s application requires a different set of options, then the certification may not be very useful. Similarly, it would be beneficial for any device labeled as compliant to be tested by the compliance organization to ensure it is, and to be “registered” as having complied.

Is there an independent and published assessment of the cybersecurity of wireless devices? This is perhaps the most important question that should be asked today. Ask not only if a device adheres to a standard but also if good coding practices and other design features are available that will make the device more intrusion-resistant. Also, does the 24

compliance organization have a role to play in these security assessments, or is this best handled by an independent, third party? If the compliance organization is the exclusive assessor, there could be the appearance of bias. Whether handled by the standard compliance organization or an independent, third party, the methodology used to test cybersecurity should be made available to the end user.

Standards can certainly have an impact, either beneficial or deleterious, on future widespread deployment. If standards are clear to the end user and have verifiable compliance by certification or other means, they will reduce uncertainty and allow the end user to make informed decisions, thus reducing the technological risk. Having multiple, competing standards for wireless transmitters is in itself not a problem, as long as the marketplace is still robust and not so fractured that, in effect, a standard becomes one manufacturer’s proprietary workspace, locking end users into that single manufacturer.

Suggestions for Users Given the current state of the wireless sensor technology, standards, and the market, what is an industrial user to do?

First, as with most other new technology issues, users should clearly define their needs for sensors and consider whether wireless sensors are really the best option. This may seem so 1990s, but twisted-pair, copper wires and 4-20 mA signals could still be the best communication network and protocol for some applications. Users should gather as much technical information as they can consume from a variety of sources, including vendors, other users, technical interest groups, and the web. The idea is not to become an expert but rather to understand some of the terminology and be aware of some key technical issues.

Along these lines, it would be useful if an independent organization could produce an independent and vendor-agnostic user’s guide to wireless sensors.

Don’t wait for a single standard to emerge victorious, because that is unlikely to happen.

Finally, we suggest that users, after a reasonable investigation, purchase a small wireless sensor system and apply it to a noncritical application in their plant. There is nothing like actually using a system to increase one’s level of understanding and expose the system’s strengths and weaknesses.

Wireless sensors networks have the potential to significantly alter the industrial sensing landscape in the next decade, but before that happens, users must be comfortable applying the technology in their plants. Three major “standards” are currently vying for users’ affection, and it is very unlikely that a single standard will emerge in the next several years, so waiting is not a good choice. There are certainly barriers to the adoption of wireless sensor or any new technology, but with good preparation and cooperation from manufacturers, these barriers can be overcome.

Users should do their due diligence before making a major commitment to the technology. Part of the due diligence should include installation and testing of a small wireless sensor network system before committing to a complete system. ■ —Contributed by Wayne Manges (mangesww@ornl.gov), Oak Ridge National Laboratory; John N. Sorge (jnsorge@southernco.com), Research and Technology Management, Southern Company Services Inc.; and Cyrus W. Taft (cwtaft@taftengineering.com) principal of Taft Engineering.

This article is based on a paper presented at the 55th Annual ISA POWID Symposium.

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WHERE WATER and POWER MEET C U S T O M I Z E D WAT E R S O L U T I O N S T H AT F I T YO U R P O W E R P L A N T

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Steven F. Greenwald

Jeffrey P. Gray

Exporting Natural Gas

he transformative increases in current and expected future domestic natural gas production have spawned yet another energy debate: Should the U.S. should export natural gas? In May, the Department of Energy (DOE) conditionally approved Freeport LNG’s application (submitted December 2010) to export 1.4 Bcf/d from its existing liquefied natural gas (LNG) terminal at Quintana Island, Texas, for 20 years. Asia represents the most likely market for LNG, particularly China and Japan. The authorization remains subject to environmental review by the Federal Energy Regulatory Commission.

The policy implications of the DOE’s decision are underscored by the 19 export applications pending at the agency.

Opponents of the exportation of natural gas contend that it will increase domestic prices, harming U.S. manufacturers and consumers, and that expanding the market for natural gas will promote production of and increase reliance on fossil fuels. In literally his first moments as secretary of energy, within days following the DOE’s approval of Freeport’s application, Ernest Moniz expressed an intent to revisit the export of natural gas: “[E]verything is on the table until I have done my analysis.”

Secretary Moniz’s intervention portends a further intrusion of politics into energy policy, economic assessments, and law. It is unlikely that Secretary Moniz’s personal “analysis” will change the outcome; Freeport and other export projects should obtain export authority.

More importantly, any further extension of the already prolonged regulatory process will not improve the quality of the decision-making and will likely engender uncertainties in the market.

T

The Law and DOE Policy The Natural Gas Act (NGA) requires that the secretary of energy authorize any export of natural gas. The NGA further directs the granting of export authority, unless the secretary finds that the request will “not be consistent with the public interest.” The law creates a rebuttable presumption that the export of natural gas advances the public interest, obligating opponents to present an affirmative showing that the export will be adverse to the public interest.

The DOE assesses requests for export authority based on its 1984 Policy Guidelines, which favor market resolutions: “The market, not government, should determine the price . . . of [exported] natural gas. . . . The federal government’s primary responsibility in authorizing [exports] should be to evaluate the need for the gas . . . while minimizing regulatory impediments to a freely operating market.”

Freeport asserted that exports would provide economic benefits through increased domestic natural gas production and a “material improvement” in the nation’s balance of trade. It also maintained that the exports would have only a “minimal impact” on domestic natural gas prices. Freeport also advocated that the exports would facilitate natural gas’s ability to displace coal and gasoline and thus reduce greenhouse gas emissions globally.

The EIA and NERA Studies The DOE commissioned the Energy Information Administration (EIA) to assess the impacts of additional natural gas exports on 26

domestic production and prices. It also retained NERA Economic Consulting to assess the macroeconomic impact. Their studies found that increased exports would: Yield overall “net economic benefits”—the greater the export level, the greater the benefit.

■ Increase domestic natural gas prices, but only modestly; increased domestic production and the need for the delivered price (that is, adding LNG transport costs) to remain competitive with alternative foreign sources would restrain prices.

■ Benefit certain industries and workers and be detrimental to others.

■

The DOE accepted the studies’ finding of “net economic benefits” and agreed that international market forces should appropriately constrain domestic prices. With respect to arguments based on exports injuring segments of society, the DOE sagely responded: [T]he public interest requires us to look to the impacts to the U.S. economy as a whole, without privileging the commercial interests of any industry over another[;] . . . resource allocation decisions . . . are better left to the market, rather than the Department, to resolve.”

Time for Decision Assessments of the economic consequences of regulatory decisions, particularly on a global stage, can never promise 100% accuracy; human judgment is not infallible, and basic assumptions inevitably change. Thus, opponents can readily challenge any regulatory decision supported by economic studies based on the uncertainties inherent in predicting the future. Policy makers must distinguish between legitimate questions that demonstrate analytical deficiencies that may taint a study and simply partisan opposition to the conclusions of a study.

Correspondingly, unless studies are completed and implemented in nanoseconds, “updated” data will always be available. Opposition to policy decisions on the ground that the data relied upon is “outdated” ignores that comprehensive studies require time. Pleas to delay regulatory decisions to allow “data updates” should be resisted, absent a most compelling showing that intervening events have demonstrated critical deficiencies in the operative assumptions.

Hopefully, Secretary Moniz’s suggestion that his agency suspend further action on natural gas exports pending his “own analysis” represents simply a rookie mistake made without appreciation of the completeness of the record. The DOE decision encompasses more than 100 pages, adheres to the existing law and DOE policy, and is supported by comprehensive studies by nationally recognized entities. The DOE analysis appreciates that the market will respond to any regulatory decision and recognizes the market’s “invisible hand” best promotes the greater good (as opposed to the regulator protecting one group at the expense of all). Ideally, Secretary Moniz’s personal analysis will expeditiously concur. ■ —Steven F. Greenwald (stevegreenwald@dwt.com) leads Davis Wright Tremaine’s Energy Practice Group. Jeffrey P. Gray (jeffgray@ dwt.com) is a partner in the firm’s Energy Practice Group.

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SEPTEMBER 30 OCTOBER 3, 2013

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WATER MANAGEMENT

Water Issues Challenge Power Generators

Drought and competing uses for water continue to challenge power plant operators worldwide. In response, innovative approaches for reducing water use are being explored from South Africa to China.

Courtesy: NV Energy

By David Wagman

W

ater is essential to thermoelectric power generation, but drought and growing competition for water from myriad other uses can have major effects inside the power plant, impacting operations and, ultimately, reliability.

Consider these recent examples. Dominion’s Millstone nuclear plant in Connecticut had to shut down a reactor last August because the water it drew from Long Island Sound was too warm. In response, Dominion asked the Nuclear Regulatory Commission in May this year for permission to use the seawater at 80F, up from 75F. A decision is expected in 2014, following a technical review.

Also last summer, Exelon’s two-unit Braidwood nuclear station near Chicago needed special permission to operate after the temperature in its cooling water pond rose to 102F, four degrees above its normal limit.

Elsewhere in the U.S., low water levels on parts of the Mississippi stalled coal barges headed to power plants, forcing the U.S. Army Corps of Engineers to dredge channels to maintain commercial barge traffic.

Droughts in Europe in 2003 and 2006 forced the shutdown or curtailment of a number of thermoelectric units. During the 2003 drought, for example, French nuclear opera28

tors had to shut down as much as 25% of the country’s nuclear fleet.

Drought conditions affect hydroelectric generation, too. As POWERnews reported in March, Brazil, which sources 67% of its power from hydro, has suffered the worst drought in 50 years, causing dams in the northeast to fall to 32% of capacity. Both power generators and electricity consumers have seen price spikes as a result.

One of the most dramatic examples in the U.S. is the visibly lower water levels in Lake Mead and Lake Powell, along the Colorado River. The light-colored rock in this issue’s cover photo shows how far below historic levels Lake Mead—which supplies water for generation at the iconic Hoover Dam near Las Vegas, Nev.—was in November 2010.

As of mid-May, Lake Powell storage behind Glen Canyon Dam in Utah was 11,396 thousand acre-feet, around 47% of normal.

Lake Mead storage was 12,887 thousand acre-feet, or 49% of normal. The April–July forecast for water flows along the Colorado River was 3.00 million acre-feet, or around 42% of average. Despite the low levels, the U.S. Bureau of Reclamation (USBR), which operates Glen Canyon and Hoover Dams, has been able to meet its contractual obligations.

However, Ron Smith, USBR acting power www.powermag.com

manager for the Lower Colorado Region, explained that lower water levels mean lower pressure and less generation potential, so the units have been derated further.

To help address the impacts of lower lake level on generation at Hoover Dam, the USBR has installed a “wide-head” turbine (sometimes called a “low-head” turbine) on the Nevada side of the dam. N8, as it is called, is rated at 130 MW but is currently derated to 115 based on the lake level. “It’s been a very successful installation,” Smith told POWER, “and the plan is to install more,” because this type of turbine enables generation across a wider range of rated capacity, making for more efficient generation under low-head conditions.

Growing Water Scarcity Drought can seem extreme in the U.S., but a 2011 report from the National Energy Technology Laboratory (NETL), “Reducing Freshwater Consumption at Coal-Fired Power Plants: Approaches Used Outside the United States,” says that water-short areas can be more widespread in countries such as China, South Africa, and Australia. China, for example, ranks as the world’s third-driest country.

The NETL report says that by 2030, China’s annual water demand could reach 216 trillion

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POWER July 2013

WATER MANAGEMENT gallons, one-third of it for industrial demand driven by thermal power generation. Water supplies in China for 2030 are estimated at roughly 164 trillion gallons. As a result, demand is on track to exceed supply by about 52 trillion gallons in 2030. By comparison,

total water withdrawals in the U.S. in 2005 were 150 trillion gallons.

Reducing water consumption at all types of steam power plants has been a worldwide concern for years, sparking a wide range of efforts to cut water use

Global investment. Efficiency improvements along with supercritical and ultrasupercritical technologies are gaining favor in countries that face water constraints. Source: NETL

Country

Electricity generated by coal

Drivers for reducing freshwater consumption

Approaches for reducing freshwater consumption

South Africa

85%

Abundant coal resources. Coal resources and power plants are in dry regions.

Use efficient supercritical technologies, dry cooling, advanced control systems, dry bottom ash handling, and desalination.

Participate in water infrastructure development, incentives, and water metering.

China

80%

Large coal resources, so coal is to be the dominant fuel for decades. China is world's third-driest country, and there are specific policies for reducing freshwater consumption.

Replace, retrofit small, inefficient plants. Increase use of supercritical and ultrasupercritical units. Use dry cooling. Explore integrated gasification combined cycle (IGCC) technology. Use desalination at power plants.

Australia

70%

Coal is likely to supply more than half the total electrical generating capacity through 2035. Many areas are subject to long drought. Groundwater use is restricted.

Supercritical steam cycles. Dry cooling.

Turbine upgrades. Coal drying. In-plant water recycling.

India

70%

More power is needed than is available.

Coal is expected to remain the dominant fuel through at least 2050.

Increase efficiency. Use advanced supercritical steam parameters. Replace/retrofit old, inefficient plants. Reuse and recycle wastewater. Research IGCC.

Denmark

50%

No domestic coal resources.

Supercritical and ultrasupercritical plants.

Cogeneration.

Germany

49%

Coal is to remain a significant power generation fuel for several years. About half of coal-fired generation is from low-rank lignite, and power plants are aging.

Replacement of old, inefficient plants with new, efficient plants, including ultrasupercritical. Research into plants with high steam parameters and new materials. Lignite drying.

Japan

25%

Imports all fuel. It is often difficult to obtain water from local governments.

Use supercritical and ultrasupercritical technologies and low-water-consuming emissions control equipment.

Italy

13%

Coal-fired power generation is to increase due to coal’s lower costs; coal is expected to provide about one-third of generation as of 2013.

Replace/retrofit old plants with ultrasupercritical technology.

1. Fourteen gallons of water.

NV Energy’s 530-MW Walter M. Higgins Generating Station in Nevada uses a dry-cooling system that enables it to use 14 gallons of water for each megawatt of power produced. A conventionally cooled power plant might use up to 650 gallons.

Courtesy: NV Energy

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July 2013 POWER

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while meeting growing demand for electricity (see table).

Steam-electric plants in the U.S. account for around 40% of the nation’s freshwater withdrawals. Much of that water is returned to its source, however. That leaves actual net consumption for power generation at around 3% of the nation’s overall freshwater consumption.

Much of the net consumption stems from evaporation and drift losses from cooling systems. Research published by the Electric Power Research Institute (EPRI) suggests that water use rates at plants with closedcycle, wet cooling systems might not be sustainable in some locations as thermal discharges from once-through cooling face increasing regulatory scrutiny. Some plants already operate under water use restrictions or are being required to install water-conserving technologies. What’s more, siting new capacity can be difficult due to water supply constraints.

The net result is that cooling and water treatment technologies to reduce water consumption, the use of reclaimed water, and the reuse of internal water and even wastewater streams are gaining traction in the generation sector. (See also “New Coal Plant Technologies Will Demand More Water” in the POWER archives at powermag.com.)

For example, NV Energy’s Walter M. Higgins Generating Station in southern Nevada (Figure 1 and the photo at the top of this story) is a 530-MW combined cycle power plant that uses two Westinghouse 501FD combustion turbines and an Alstom STF30C steam turbine. The plant entered service in 2004 and, unlike conventional power plants, uses a six-story-high dry cooling system. Similar to a car radiator, 40 fans (each 34 feet in diameter) condense the steam and cool plant equipment. The plant uses 14 gallons of water for each megawatt produced. By contrast, a conventionally cooled power plant of similar size might use as much as 650 gallons of water per megawatt. The Higgins Station also saves water by reusing “gray water” from three nearby casinos.

NV Energy is one of the most experienced generators in the U.S. when it comes to dry cooling. Its 1,102-MW Chuck Lenzie Station, 30 miles north of Las Vegas, ranks as one of North America’s largest dry-cooled power plants. The plant includes two side-by-side power production blocks outfitted with GE 7FA combustion turbines. The exhaust from the four turbines produces steam for two GE D-11 steam turbines. As part of its water use strategy, the Lenzie station also uses a water clarifier system that recaptures and recycles about 75% of the process water.

29

WATER MANAGEMENT Operational and Economic Consequences One of the biggest effects that drought has imposed on electricity production stemmed from a 2001 drought in California and the Pacific Northwest. Although power outages were largely avoided, significant financial impacts were tallied. For example, the Northwest Power and Conservation Council estimated in 2005 that the total regional economic impacts totaled between $2.5 billion and $6 billion.

The southeastern U.S. drought of 2007– 2008 posed a risk to baseload thermoelectric generation facilities. Tennessee Valley Authority, for example, had to shut its Browns Ferry nuclear generating plant temporarily, and generation was reduced all across the region during August 2007. Low water levels led to a rise in water temperature, which began to bump up against discharge temperature limits set in operating licenses.

A 2011 report from Argonne National Laboratory, “Analysis of Drought Impacts

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on Electricity Production in the Western and Texas Interconnections of the United States,” noted that hydro generation in general is far more significantly affected by drought than thermoelectric generation. It explained that hydro generation varies widely, depending upon hydrological conditions. In fact, reports on droughts in the West in the mid-1970s and in 2001 indicated little significant impact on thermoelectric generation. The greater risk, at least in California and the Pacific Northwest, stemmed from reliance on hydroelectric generation.

Three other studies from Argonne looked at potential impacts of drought on power generation. The first looked at cooling-water intake heights as an indicator of drought risk for thermoelectric power plants. Of some 423 plant analyzed, 43% were identified as having cooling-water intake heights less than 10 feet below the typical water level of their water source. The second study looked at U.S. coal plants and ranked them by their vulnerability on the basis of 18 different water supply and demand-related indicators. Of the 580 plants evaluated, 60% (representing roughly 90% of total coal generating capacity) were said to be vulnerable on the basis of either supply- or demand-related criteria.

A third study, published in 2009, modeled a drought scenario in the western U.S. to estimate the impact on electricity prices and CO2 emissions. The model simulated supply to match historical hourly load data. The results showed increases in electricity prices ranging from 4% to 35%, depending on the month and year. The researchers also estimated a 5% increase in CO2 emissions in the drought scenario, resulting from an increase in natural gas generation to make up for lost hydroelectric generation.

A 2010 EPRI report, “Freshwater Needs for Thermoelectric Generation,” said the largest demand for water in thermoelectric plants is cooling water for condensing steam. The process of thermoelectric power generation is well known, but the basics are worth reviewing to focus more narrowly on how water is used. Thermoelectric generation relies on a fuel source (fossil, nuclear, or biomass) to heat water to steam that is used to drive a turbine. Steam exhausted from the turbine is condensed and recycled to a steam generator or boiler. This steam condensation typically takes place in a shell-and-tube heat exchanger known as a condenser. The steam is condensed by the flow of cooling water through tube bundles that are located within the condenser.

Cooling System Options In general, three types of cooling system designs are used for thermoelectric power

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POWER July 2013

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Get the latest power industry news, trends, and business & regulatory info right at your fingertips.

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Go to The App Store on your iPad and search POWER magazine For more information on POWER magazine, visit www.powermag.com

WATER MANAGEMENT plants: once-through, wet recirculating, and dry. In once-through systems, the cooling water is withdrawn from a lake, river, or ocean. This water then is warmed as it passes through the power plant and finally is discharged back to the water body after having passed through the surface condenser. As a result, plants outfitted with once-through cooling water systems have relatively high water withdrawal but low overall water consumption.

Two basic technologies are used to support wet recirculating cooling systems, wet cooling towers and cooling ponds. The most common type of recirculating system uses wet cooling towers to dissipate heat from the cooling water to the atmosphere.

In wet recirculating systems, warm cooling water is pumped from the steam condenser to a cooling tower. There, heat from the warm water is transferred to air flowing through the cooling tower. In the process, a portion of the warm water evaporates and forms the commonly observed water vapor plume. The cooled water then is recycled back to the condenser. Because of evaporative losses, some of the cooling water needs to be discharged from the system—a process known as blowdown—to prevent the buildup of minerals and sediment that could adversely affect performance.

For a wet recirculating system, only makeup water needs to be withdrawn from the local water body to replace water lost through evaporation and blowdown. As a result, plants equipped with wet recirculating systems have relatively low water

withdrawal, but high water consumption, compared to once-through systems.

Wet cooling towers follow two basic designs: mechanical draft and natural draft.

Mechanical draft towers use a fan to move air through the tower. By contrast, natural draft towers rely on the difference in air density between the warm air in the tower and the cooler ambient air outside the tower to draw air up through the tower. In both designs, warm cooling water is discharged into the tower for direct contact with the ambient air. A cooling pond serves the same purpose as a wet cooling tower, but it relies on natural conduction/convection heat transfer from the water to the atmosphere as well as evaporation to cool the recirculating water.

Dry cooling systems can use either a direct or indirect air-cooling process. In direct dry cooling, the turbine exhaust steam flows through tubes of an air-cooled condenser (ACC). The steam is cooled via conductive heat transfer using ambient air that is blown by fans across the tubes. As a result, cooling water is not used in this system. For indirect dry cooling, a conventional water-cooled surface condenser is used to condense the turbine exhaust steam.

However, a dry cooling tower, similar to an ACC, transfers heat from the water to the air via conduction. As a result, no evaporative loss of cooling water occurs. What’s more, water withdrawal and consumption both are minimal.

In the U.S., existing thermoelectric power plants use all of these types of

2. Cooling systems by technology and water source.

Estimates suggest that 42.7% of generating capacity uses once-through cooling, 41.9% relies on wet recirculating systems, 0.9% employs dry cooling technology, and 14.5% depends on cooling ponds. Source: NETL

32

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systems, with estimates suggesting that around 43% of generating capacity uses once-through cooling, 42% wet recirculating, 0.9% dry cooling, and 14% cooling ponds (Figure 2).

Plant type is an important factor in the amount of water required. Of the fossil-fueled plants, coal units have the highest heat rates (or lowest efficiencies), as well as the highest requirements for water over and above that for condenser cooling, due to the in-plant power and water requirements for coal pulverization, flue gas scrubbing, and ash handling.

Simple cycle gas turbine plants have a condenser cooling load of zero, as a result of their design. For combined cycle plants, anywhere from one-third to onehalf of the electric power output is generated with the steam portion of the power cycle. In this case, the unit’s condenser cooling requirements correspond to the output of the steam cycle. However, virtually all combustion turbine plants have additional water requirements, including gas turbine inlet air cooling, steam or water injection in the gas turbine compressor inlet, and, in the case of integrated gasification combined cycle plants, water for the gasification process.

Some renewable energy plants, such as solar photovoltaic and wind, have no steam condenser cooling requirements. However, solar thermal and biofuel-fired power plants typically use Rankine steam cycles similar to the steam cycles at fossil plants. What’s more, solar plants almost always require water for collector surface cleaning.

Rethinking Water Use In February 2011 and June 2012, EPRI issued requests for information to invite what it called early-stage, out-of-the-box, and innovative ideas and technologies to reduce freshwater use in power plants. Between 2011 and 2012, more than 100 proposals were submitted. This year, a possible joint solicitation between EPRI and the National Science Foundation (NSF) aimed at advancing water-conserving cooling technologies is planned. Winning proposals will be funded by both organizations through collaborative but independent funding approaches, as NSF awards grants and EPRI awards contracts.

One initiative, from the Gas Technology Institute (GTI) and partners, suggests developing an advanced cooling tower fill to enable evaporative cooling of hot water from the steam condenser at near dew point temperature. This approach is based on a method of evaporative cooling called M-Cycle that allows cooling water

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POWER July 2013

WATER MANAGEMENT to be cooled below the ambient wet-bulb temperature (the current limit of cooling temperature), or even to the dew point temperature of the incoming air, with substantially lower water and energy consumption requirements.

To achieve this low cooling temperature, an airflow/tower fill arrangement is proposed. Incoming airflow is drawn through dry passages arranged in the fill to be indirectly precooled by evaporating water. The GTI team says this process differs from conventional cooling tower fills, which have wet evaporation channels only.

The advanced cooling tower fills have dry channels between the evaporation channels to allow incoming ambient air to be precooled by evaporation to about dew point temperature before the air turns into adjacent wet channels to remove heat from the water. The precooled air enables evaporation at a much lower temperature, resulting in cooled water temperature close to dew point temperature and below the ambient air wet-bulb temperature.

The lower temperatures and decreased evaporative losses compared to conventional cooling towers result in 15% to 20% less cooling water and makeup water usage, according to the GTI. Based on modeling results, EPRI said it expects to initiate engineering, fabrication, and proof-of-concept evaluation of an experimental section of cooling tower fill

this year, in collaboration with the GTI and a commercial manufacturer. Parallel engineering and economic modeling will be done to compare cost and performance for the advanced fill system and a conventional cooling tower in both retrofit and new construction applications at 500-MW plants.

This will include assessing possible heat rate improvements associated with operation at lower turbine back-pressure. Results from these activities are expected to support the launch of field demonstration projects by the end of 2014.

Global Water Initiatives Efforts are also under way outside of North America to address water consumption issues. NETL said that countries aggressively implementing dry cooling technology include China, South Africa, and Australia.

China has adopted dry cooling for many new plants. The Huaneng Qinling Power Plant provides an example of how dry cooling is being used in China. In Shanxi Province, water shortages are hindering development of the central Shaanxi plain, consequently, the 1,300-MW Huaneng Qinling Power Plant uses an indirect dry cooling system. The technology relies on a traditional steam surface or jet condenser and a circulating water system to transfer waste heat to the natural draft concrete cooling towers using air-cooled heat exchanger bundles. The system also uses a

3. Air-cooled in South Africa. Eskom’s six-unit, 3,600-MW Matimba Station uses direct closed-circuit cooling technology, which enables it to use 0.1 liters of water per kWh produced.

Courtesy: Eskom

two-level cooling arrangement designed to increase cooling efficiency. This two-level arrangement was also used at the 1,320MW Huaneng Shanxi ZuoQuan Power Plant. The cost of the cooling system is estimated at $33 million.

South Africa’s state-owned electric utility, Eskom, has implemented dry cooling technology on power stations, where feasible, despite the loss of efficiency, which may be on the order of 1% to 1.5%, as at the 750-MW Kogan Station in Australia, which also uses dry cooling. Eskom operates one of the world’s largest indirect dry-cooled power plants (the 4,116-MW Kendal plant) and one of the largest direct dry-cooled plants (the six-unit, 3,600-MW Matimba Plant, see Figure 3).

The Kendal Power Station uses an indirect dry cooling system. In this system, water from a standard condenser is circulated to the tower, where it enters a series of heat-exchange elements at the base. Air enters the bottom periphery of the tower, passing over the heat-exchange elements.

Inside the tower, the heated air rises, pulling in more cooled air. Fans are not required. Water consumption at the Kendal Plant is about 0.08 liters per kWh. The Matimba Power Plant uses a direct closed-circuit cooling technology. Water consumption is about 0.1 liters per kWh. That compares with about 1.9 liters on average for wet-cooled stations. The choice of dry-cooled technology for Matimba was largely influenced by a scarcity of water in the area.

In Australia, dry cooling is used in two Queensland power stations (Millmerran and Kogan Creek). The 850-MW supercritical Millmerran plant opened in 2003 and is one of the most energy-efficient plants in Australia. It uses air cooling to condense steam from the turbine exhaust and consumes 90% less water than conventional coal-fired power projects. Recycled wastewater from a nearby sewage treatment plant is treated on site and used as makeup water. All runoff water is contained on site and reused. The 750-MW supercritical Kogan Creek power plant in Queensland began operations in 2007. It has an air-cooled condenser that uses up to 90% less water than conventional plants.

Drought conditions are only one factor driving worldwide interest in reducing water consumption for electric power generation. Competing uses make it almost imperative for the sector to rethink how it uses water and to take steps to reduce its use as much as possible. ■

—David Wagman is executive editor of POWER.

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July 2013 POWER

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POWER POLICY

Indonesia: Energy Rich and Electricity Poor Even though it enjoys sizeable coal and natural gas reserves, Indonesia struggles to provide electricity to its growing economy. Geography is its most obvious challenge. Others include evolving international markets and an energy sector that remains highly politicized.

By Sonal Patel

A

vast Southeast Asian archipelago of more than 17,500 islands that straddles the equator, Indonesia has become an established and crucial player in the world’s energy markets. It is endowed with some of the world’s largest reserves of fossil fuels, and in 2011, it was the world’s largest steam coal exporter and the eighth-largest natural gas exporter. Yet, today, energy security has become Indonesia’s paramount challenge.

And it appears it will be the country’s preoccupation until at least 2020.

At the heart of the issue is that the economy of world’s fourth-most-populous country (after China, India, and the U.S.), with 243 million people, has been booming at an enviable annual rate of 6% since 2010.

But so has its domestic energy consumption, which surged by more than 50% over the past decade on the back of an emerging consumer class. This consumption growth has forced the country to halt exports of oil, temper its natural gas exports, and redirect nearly a quarter of produced coal for domestic production of electricity.

On the other hand, compounded by its geographic complexity, without available electricity imports, and reluctant to rely on diminishing domestic oil supplies that fuel off-grid diesel generators on the nation’s 6,000 inhabited islands, the country has been stricken by a critical undersupply of power. Though it is one of Southeast Asia’s biggest economies, it has one of the lowest electrification rates in the region. This dilemma is underscored by forecasts suggesting that between 2009 and 2019, national electricity demand will increase by an average 9% per year and reach 328.3 TWh in 2020—more than double last year’s figure of 162.4 TWh. The government’s solution is to seek massive power capacity increases, and it recently embarked on an ambitious plan to add at least 55.3 GW of new capacity and at least 49,299 kilometers of new transmission lines within the next decade. Can Indonesia 34

bypass a number of hurdles and resolve its energy dilemma?

public.” ±±One pervading issue is that the governance structure is based on the dominance of state-owned enterprises, and until recently the government functioned on a constitutional mandate as the sole provider of electricity for the nation. Under the authoritarian regimes of former Presidents Sukarno (1945–1967) and Suharto (1967– 1998), the principles of bureaucratization were reinforced and did little to change the structure of state-owned power entity Persero-Perusahaan Listrik Negara (PLN), which held an iron-grip monopoly on the country’s generation, transmission, and distribution.

Only after the Asian financial crisis of 1997–98 and the fall of Suharto’s regime did fundamental changes in the power sector come, Purra says. The new era of democratization of political process achieved, among its most notable changes, passage of Energy Law No. 30 in 2009 (Figure 1). The landmark law allows independent power produc-

Addressing an Existing Crisis It is important to note that the country has been long-steeped in a festering electricity crisis characterized by rolling blackouts lasting, on a national average, about 3.8 hours per day, according to 2009 figures. As Dr. Mika M. Purra of the Center on Asia and Globalization at the National University of Singapore points out, power shortages have been routine since Indonesia’s independence from the Netherlands in 1949. Moreover, Purra asserts that while modernization of the power sector has been a specific goal of the government since 1998, a “historical narrative reveals repetitive attributes that have continuously stalled any serious efforts to reform the sector, thus causing significant harm to the state, its economy and the general

1. Major players. In a power market regulatory upheaval, Indonesia’s Energy Law No. 30, passed in 2009, allowed independent power producers (IPPs) to begin generating and selling electricity. But state-owned power company Perusahaan Listrik Negara (PLN) generated about 75% of all power in 2012, remains heavily subsidized, holds a monopoly on transmission and distribution grids, and functions as the system operator. This chart shows the major players in Indonesia’s electricity system and how PLN generates revenues and receives subsidies. Source: Differ Group, “The Indonesian Electricity System—A Brief Overview,” differgroup.com/analysis, 2012 kWh Regional government Supply Feed-in tariff Licensing or cooperation

IPP Generation Distribution

kWh Internal price

Customers Captive

kWh Ministry of Energy and Mineral Resources Planning Funding Regulating

Feed-in tariff

Social benefits subsidy

Tariff kWh

Funding Subsidies

Ministry of Finance Subsidizing PLN, maintaining social benefits system

kWh

PLN Electrification Generation Transmission Distribution

Customers Business Industry Public Residential Social

Tariff

Electricity Payment for electricity www.powermag.com

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POWER July 2013

POWER POLICY ers (IPPs) to generate and sell electricity to end users in the Indonesian market, ending PLN’s 60-year-long monopoly as the single electricity supplier in Indonesia.

Trickling Change The election of President Susilo Bambang Yudhoyono in 2004 ushered in more reforms, including policies to create an at-

2. Indonesia’s power system today. In 2012, 41.5% of Indonesia’s 200,291 GWh was consumed by households. Industry and commercial users consumed a combined 52.4%.

Source: PLN Self-use 6,560 GWh

Industry 60,176 GWh (34.6%)

PLN 149,783 GWh (75%) Total generation 200,291 GWh IPPs 50,508 GWh (25%)

Transmission 193,730 GWh Self-use 94 GWh

Distribution 188,6998 GWh Self-use 280 GWh

Commercial 30,988 GWh (17.8%) Public 10,694 GWh (6.1%) Residential 72,133 GWh (41.5%)

3. An achievement. Between 2006 and 2011, PLN increased total annual generation from its power plants by 37%, to 142,739 GWh. Though solar, wind, and gas engines are included, their contribution to the total is too small to show up. Courtesy: Handbook of Energy and Economic Statistics of Indonesia (2012)

4. PLN power purchases from captive power plants and IPPs. Also between 2006 and 2011, PLN increased the amount of power purchased from emerging independent power producers and captive power plants, for a total in 2011 of 183,419 GWh—a 38% increase compared with 2006. Courtesy: Handbook of Energy and Economic Statistics of Indonesia (2012)

tractive climate for investment in energy infrastructure, to mitigate pollutant emissions, and to scale up renewables. But Purra isn’t convinced that the sector has been transformed enough. “Despite numerous and on-going attempts to reform, restructure and vitalize the sector, the sector continues to suffer from grave inefficiencies that bear on market participants’ profitability, hinders overall economic growth, and maintains an untenable and uncertain environment for foreign investors,” he points out.

One gripe is that today PLN continues to be the sole purchaser of electricity and the second-largest state-owned enterprise in Indonesia. It still owns and operates about 75% of the country’s generating capacity, it has retained its monopoly on the transmission system, and it continues to function as its system operator (Figure 2). Moreover, the entity is responsible for the country’s electricity supply through the “right of first refusal” clause, and IPPs can only serve areas that have been declined by PLN and are not included in PLN’s plans for electrification. Decentralization following implementation of the new energy law has, meanwhile, increased the autonomy of regional authorities for the sake of increasing rural electrification, to ease the implementation of new projects, and to stimulate collaboration between regional authorities and private actors.

Some improvements are certainly apparent, however. In 2005, recognizing that PLN could not independently fund infrastructure growth because it heavily depends on government subsidies, and to attract private investment to the sector, the government enacted new Public Private Partnership (PPP) legislation. The following year, it announced stage 1 of a “fasttrack” program that would be followed by a second program in 2010; each stage seeks to accelerate development of 10 GW of new capacity, and the second part is specifically geared to the growth of IPPs and renewable energy. Though stricken by debilitating delays and regulatory hurdles, both measures have been arguably successful. Compared with 2006, PLN increased its total annual generation by 37% in 2011 (Figure 3), while generation from IPPs also increased substantially (Figure 4).

In 2011, meanwhile, coal, oil, and gas power plants made up 46% of Indonesia’s power capacity. Diesel, used to fuel offgrid capacity on remote islands, held the second-largest share at 15% (Figure 5).

Pressing Forward Propelled by an ambition frequently reiterated by the decade-old administration

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July 2013 POWER

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35

POWER POLICY of President Yudhoyono to transform the country into one of the world’s 10 major economies by 2025—and lift millions of its citizens out of poverty—Indonesia in 2011 published the “Master Plan for Acceleration and Expansion of Indonesian Economic Development.” It includes more than 500 projects throughout the country as well as six development corridors aimed at creating economic clusters in various industrial sectors. Among its key elements is a $96 billion injection to boost the country’s ailing power infrastructure. It calls for the installation of least 55.1 GW of new generation capacity and 49,299 km of new transmission lines by 2020 (Figure 6).

Modeled on the master plan, PLN later released its own business plan, outlining how the nation’s power supply could be more than doubled over the decade-long planning period. Significantly, it specifies that IPPs will contribute 43% of the total capacity needed: PLN will add 31.5 GW and IPPs will add 23.8 GW by 2020.

Coal. Sitting on at least 6.1 billion short tons of recoverable coal reserves—mostly bituminous or subbituminous and located primarily in Sumatra and East and South Kalimantan—Indonesia in 2011 overtook Australia to become the world’s largest exporter of coal by weight. Though the bulk of the country’s mined coal is exported, the government has encouraged coal-fired power generation by setting a 20% domestic market obligation for producers and

5. Installed capacity, 2011. In 2011, Indonesia’s installed power capacity amounted to 39.9 GW, the bulk (16.3 GW) of which was steam (coal-, oil-, and gas-fired) power.

The nation also had 5.5 GW of diesel capacity, more than hydro’s 3.9 GW share. About 1.25 GW of nameplate renewable capacity—including geothermal, wind, solar, and mini and micro hydro—had been installed.

Source: Handbook of Energy and Economic Statistics of Indonesia (2012)

touting use of its relatively abundant domestic supplies as one way to reduce dependence on expensive diesel and fuel oil.

However, most projects outlined by PLN’s plan to install at least 35.6 GW of new coal-fired capacity by 2020 have been plagued by delays. About 17 coal plants (almost 3 GW) are under construction. At least 10 of these 17 (a total of 1,700 MW), most in Kalimantan and the eastern part of the country, are expected to come online this year, while the remaining seven should be completed next year. Construc-

tion on another 10 coal-fired plants with a total capacity of 2.4 GW will also begin this year, PLN indicates, including those in Pacitan, East Java (630 MW); Pelabuhan Ratu, West Java (1,050 MW); Barru, South Sulawesi (100 MW); and Nagan Raya in Aceh (220 MW).

Last year saw the completion of two new 660-MW units at the Tanjung Jati B power plant in Central Java (a POWER Top Plant—see the October 2012 issue).

The 815-MW PTLU Paiton Unit 3, a supercritical plant in East Java, also came

6. Banking on coal.

To ensure economic growth, Indonesia projects it will need to develop at least 55.1 GW of new power plant capacity by 2020. State-owned utility PLN will add at least 31 GW, while independent power producers are expected to add another 24 GW. At least 65% of the new additions will be coal-fired, while about 12.2 MW will be from renewables. Source: PLN

7. At the top of the heap. At least 17 new coal-fired power plants with a combined capacity of about 3 GW are under construction in coal-rich Indonesia. In July 2012, Japanese firm Marubeni Corp. and partners Indika Energy, Korea Midland Power Co., and Santan Co. began commercial operation of the single-unit 660-MW PT Cirebon Electric Power station, shown here. The $877 million plant in West Java was built under the independent power producer program. A second unit at the site is being discussed. Courtesy: Marubeni

Coal gasification <1% Waste <1% Other renewables <1%

Gas engine 1% Geothermal 3%

Hydro 11%

Combined cycle 12%

Steam 46%

Simple cycle 12% Diesel 15%

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POWER July 2013

POWER POLICY online, making the 2,035-MW Paiton complex the biggest IPP project in the country, while Japan’s Marubeni Corp. recently completed the 660-MW supercritical Cirebon Electric Power station in West Java (Figure 7).

Among notable projects in the pipeline are foreign investment consortium PT Bhimasena Power Indonesia’s 2-GW ultrasupercritical plant in Central Java. That $4 billion project, the first procured under PPP regulations, is on track to come online by 2017, even though developers are struggling to acquire the approximately 226 hectares of land (they have acquired 186 hectares) the planned plant needs.

Several local landowners have reportedly accused the government of using forms of violence and intimidation when acquiring their land. An official with the coordinating economic ministry was widely quoted this May as saying the government would do everything to ensure the project proceeds as planned, saying failure would deter prospective foreign investors that could boost Indonesia’s infrastructure.

Natural Gas. Indonesia is among the world’s five biggest natural gas producers and, with 141 trillion cubic feet of proven natural gas reserves (as of January 2012), it has emerged as a major exporter of pipeline and liquefied natural gas (LNG), more than half of which is relayed to Japan.

Since 2004, however, domestic consumption of natural gas has more than doubled.

Compounded by production problems, this has forced the country to buy spot cargoes of LNG to meet export obligations and has prompted the country to consider imposing a moratorium on gas exports. Meanwhile, policy makers last year initiated four studies to assess the nation’s shale oil and gas potential, though no blocks have been yet awarded to investors.

One reason for increased domestic gas consumption, which accounted for 42% of total production in 2011, is the country’s declining oil production and reliance on natural gas for transportation. Government policies also emphasize that the country’s gas resources should support the nation’s economic development and prosperity, and the government allocates gas supply in a hierarchical order, led by the petroleum operation sector, the fertilizer feedstock sector, and then the power sector. Additionally, plans suggest that future new generation will be largely dependent on coal instead of gas.

Even so, PLN’s plans for capacity growth call for at least 3.3 GW of new combined cycle power and 4.1 GW of gas thermal power. This March, Australian

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July 2013 POWER

firm Energy World Corp. put into service the first of two 60-MW phases to expand the 255-MW Senkang Combined Cycle Power Plant in South Sulawesi.

Renewables. The primary reason coaland gas-abundant Indonesia is looking to renewables is because the government predicts that in the “near future,” fossil fuel energy reserves “will run out and Indonesia will heavily depend on imported energy,” as Energy and Mineral Resources (EMR) Vice Minister Rudi Rubiandini said in a statement in December. The government had recently accelerated efforts to develop renewable energy sources, which had much potential but were vastly underdeveloped, he noted. A 2006 presidential decree, for example, mandates the increase of renewable energy production to 15% by 2025. Though the Master Plan outlines substantial growth for hydro, wind, and solar, geothermal and biomass are slated to see the most growth.

Geothermal. Situated in the volcanic “Ring of Fire” that circles the Pacific Ocean, Indonesia has one of the world’s largest geothermal resource potentials, estimated at about 27.5 GW. Less than 5% of this potential has been developed so far, or about 1.2 GW, centered in six geothermal fields in Java (Figure 8), North Sumatra, and North Sulawesi. The government has outlined goals to install 9.5 GW of geothermal capacity by 2025, so that the resource will account for about 6% of the country’s energy consumption.

Four private sector–financed projects have so far managed to conclude power purchase agreements under the Fast Track II program. This April, U.S.-based Ormat Technologies became the fifth, as it began developing the three-phase 330-MW Sarulla geothermal power project in Tapanuli Utara, North Sumatra. The $254 million project will be the largest single geothermal contract when completed, as expected by the end of the decade.

Biomass. Biomass resources have an estimated production potential of 49,810 MW, but fewer than 1,000 MW have been developed to date. However, several companies have tapped into fast-growing crops such as cassava, jatropha, and sweet sorghum for biofuel development.

GE, in partnership with PLN, has begun developing a pilot program that will use wood chips to fuel the U.S. company’s integrated biomass gasification technology to generate 1 MW. The project is expected to demonstrate the viability of biomass to generate power in remote areas such as Sumba and other islands.

Hydro. Indonesia’s mountainous island www.powermag.com

topography makes it ideal for large and small hydropower facilities, but though PLN estimates 75 GW of power potential for hydro, only 5 GW have been developed. While the Master Plan calls for at least 2.8 MW of new micro-hydro capacity by 2020, PLN last year identified 96 potential hydroelectric power sites that could offer at least 12.8 GW. Several projects are now under construction, including the World Bank–financed 1,040-MW pumped storage plant at the catchment of the Upper Cisokan River in West Java. The $800 million plant is slated for completion in 2016. Chinese state-owned firms, in particular, are spearheading development of large-scale hydro plants such as the 110-MW Jatigede plant (Figure 9) in West Java. In late May, China Power Investment Corp. proposed a $17 billion, 7-GW hydroelectric plant in

8. A mountain to climb. The 220-MW Wayang and Windu power station 200 km south of Jakarta is Indonesia’s biggest geothermal power producer. The plant in a volcanic region carpeted with tea and quinine plantations is named for Mt. Wayang and Mt. Windu in West Java. The power is sold into the state-owned power utility’s West Java high-voltage grid. Courtesy: Business Wire

9. Streaming in. The

110-MW Jatigede Hydropower plant under construction on the middle reaches of the Cimanuk River in Sumedang Region, West Java Province, is expected to be completed in early 2014. China’s Sinohydro Corp. is building the $227 million plant under a concession loan from the China Exim Bank. Courtesy: Sinhydro

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POWER POLICY Indonesia’s North Kalimantan region, and work is expected to begin next year.

Nuclear. Though nuclear capacity is not included in PLN’s plans, a 2006 presidential decree calls for four nuclear power plants to be built in Indonesia by 2025.

The country already has three experimental nuclear reactors and at least two uranium mines. Despite the Fukushima accident in March 2011, the quake-prone country seems determined to build new “modern” (possibly thorium) reactors.

According to media reports, the Indonesian government has $8 billion earmarked for the reactors that could be built in Central Java and Bangka Island, off the north coast of southern Sumatra.

Grid. Consisting of eight domestic interconnected systems and 600 isolated grids—all operated by PLN—Indonesia’s power grid is characterized by high transmission losses and electricity theft.

Meanwhile, plans are under way by leaders of the Association of South East Asian Nations (ASEAN), a geopolitical and economic organization, to develop a grid that will interconnect its 10 resourcerich Southeast Asian country members by 2020. The project consists of 14 links, at least two of which will link Indonesia to Peninsular Malaysia and to the Asian mainland.

A Need for Higher Power Tariffs The EMR’s Rudi in December warned that along with minimizing the supply gap to avert a future energy crisis, the nation would have to push for energy efficiency measures. Rudi recognized that complicating Indonesia’s challenges is a government commitment to electrify 99% of the country by 2020—up from about 76% in 2012.

Subsidizing energy “caused Indonesian behavior trends to be consumptive and wasteful on energy use,” he cautioned.

Several funding entities have echoed Rudi’s concerns, saying that PLN’s income from operations alone is “insufficient” to achieve Indonesia’s goal to extend electricity to nearly 20 million citizens. The problem’s cause is simple: Tariffs have been set low by the government for social reasons, but the “cost of generation is much higher than the average tariff,” notes the Asian Development Bank.

To bridge the deficit, the Ministry of Finance (MoF) provides funding to PLN, which is referred to as the Public Services Obligation (PSO). But because the PSO is critical to PLN’s solvency, that means for IPPs like Japan’s Marubeni—which recently built the Cirebon supercritical plant—arranging long-term dollar-de38

nominated project finance requires “certain government guarantee/support to be issued from the MoF to assure PLN’s payment obligations,” a spokesperson told POWER. Analysts note, however, that government support is now only available for projects within the “fast track” Stage II or PPP programs.

Change is under way, albeit slowly.

Recognizing the burden on progress posed by artificially depressed power tariffs, the House of Representatives has made good on efforts to increase tariffs by 15% this year, starting with a 4.3% increase in January and an additional increase every three months. This hasn’t boosted PLN’s bottom line yet, however. As the Jakarta Post reported in April, the utility reported a 41% drop in net income last year, losing $330 million on foreign exchange losses, increased operating expenses, and rising fuel costs. Though it saw a revenue hike of about 12%, about 44% of PLN’s revenue came from state subsidies, the newspaper reported.

Land Acquisition and Finance Hurdles Nevertheless, reforms to encourage foreign investment in the country’s power sector seem to have been successful. Currently, no “major” regulatory or legal impediments involve foreign investment in the power sector, experts claim, though they outline a list of hurdles that must be overcome beyond that. Among them, as a recent analysis from the U.S. Embassy in Jakarta notes, are “[a]ccess to financing, protracted land acquisition processes and legal uncertainties,” which “can still cause bottlenecks in infrastructure projects in the sector and serve as a deterrent to doing business in Indonesia.”

These are serious issues that are hindering even PLN from gaining ground on its fast-track program. The company’s construction director, Nasri Sebayang, told the Jakarta Post this April that at least 36 out of 52 geothermal projects in the second stage of the program are lagging and would not meet the projected 2016 deadline. Six plants with a total capacity of 360 MW are delayed because they are located in conservation forests, while 16 other projects with a capacity of 1,510 MW face technical issues. Of the 9.9 GW projected for the first stage of the first-track program, only about 45% are in operation, while just 46% (about 4.7 GW) of the second stage was on track to come online on time.

Attracting IPPs has been Indonesia’s most vital challenge as it tackles the growing demand for power, the strain on the www.powermag.com

cost structure system, and the underutilization of energy resources. In 2010, a presidential regulation (amended in 2011) established the Fast Track II program, which consists of 44 coal, gas, geothermal, and hydropower power projects totaling 10.1 GW—3 GW of which have been reserved for IPPs. Some IPP projects are procured under the country’s 2011-amended PPP framework, which could provide infrastructure guarantees and may provide fiscal and nonfiscal government support to improve their feasibility.

Recent liberalized laws also allow power generators to sell electricity to entities other than PLN, though a 2010 regulation stipulates that foreign ownership of any power project above 10 MW is limited to 95%; Indonesian entities or individuals must own the remaining 5%.

Other factors that could temper enthusiasm for developing power projects in the country involve land acquisition and permitting. PLN generally expects developers to acquire all land needed for a plant site and transmission lines needed to connect to the nearest substation (a corridor typically 20 km to 40 km in length) before the financial closing date. However, the process of land acquisition can be complicated, given that Indonesian law broadly recognizes numerous forms of unregistered land, including Adat (or native title), which sometimes makes it difficult to ascertain the identity of land owners. And because the law forbids foreign-owned companies to hold unregistered land, converting rights to registered land can be a lengthy and expensive process.

Among the permits required—which are prone to delay or blockage—are those from the Ministry of Forestry to “borrow” forest area to build power projects. Then a variety of permits are required from government departments or ministries, including the approval of an environmental impact assessment, a business license, an electricity business license, and a certificate of operation worthiness.

Nevertheless, several experts agree that Indonesia’s economic fundamentals and emerging regulatory framework are beginning to synchronize. Some even express “renewed optimism” in the investment sector.

But others decry the high degree of politicization of the system, pointing to a failure to reform PLN, which, as Purra describes it, has become an “untouchable behemoth that is allowed to continue to dictate the future direction of Indonesia’s electricity sector.” ■

—Sonal Patel is POWER’s senior writer.

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POWER July 2013

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WATER TREATMENT

ORP as a Predictor of WFGD Chemistry and Wastewater Treatment Recent studies have shown that system oxidation-reduction potential (ORP) is not only an important factor for predicting wet flue gas desulfurization (WFGD) absorber chemistry but also may be a predictor of process equipment corrosion and wastewater treatment requirements.

By S.R. Brown, R.F. DeVault, and D.B. Johnson, Babcock & Wilcox Power Generation Group Inc.

P

urge streams of wet flue gas desulfurization (WFGD) units, which are one byproduct of controlling SO2 emissions from coal combustion, are being increasingly subjected to stricter wastewater regulations. Consequently, coal-fired power generators need a method for controlling the operational chemistry of these WFGD units.

Upon implementation of a suitable control method, WFGD bleed stream chemistry and flow rate may be optimized, thereby resulting in improved performance of one or more downstream unit operations. A further benefit is reduced reagent and additive costs in various devicies, including the WFGD unit.

One control parameter of interest is the oxidation-reduction potential (ORP) of the bleed stream. Much like pH, the measurement of ORP can be taken in real time and integrated with other plant-monitoring data. By incorporating ORP measurements into a process control scheme for limestone forced-oxidized WFGD absorbers—along with various other control variables such as SO2 removal, absorber pH, reagent flow rate and/or one or more reaction stoichiometries, and/or gypsum purity—generators are able to manage the oxidation states of various dissolved metals in the slurry and the potential reemission of mercury. (Also see “How to Measure Corrosion Processes Faster and More Accurately,” May 2009 in the POWER archives and “Mercury Control: Capturing Mercury in Wet Scrubbers, Parts I and II,” July and September 2007, respectively, in the COAL POWER archives—both available at powermag.com.)

A further benefit is control of the corrosion rate of the absorber recirculation tank (ART) and other alloy parts within the system. Many utilities have had ORP excursion events in WFGD wastewater discharge where the ORP readings changed from 150 millivolts (mV) to 300 mV to a reading above 500 mV. Previously, these fluctua40

tions have gone largely unexplained. We have determined that this magnitude of change in ORP, in an ART, due to coal composition and upstream air quality control system (AQCS) effects on WFGD absorber chemistry, can accelerate corrosion.

One potential solution to fluctuating ORP readings is to use integrated process controls designed to tune the upstream operation of the AQCS train to produce consistent inlet flow parameters to the WFGD tower, rather than operating each as an independent process. The control of the ORP level in a WFGD system may produce improved plant operations by reducing the amount of wastewater treatment necessary and helping mitigate mercury reemission.

Fundamentals of ORP ORP is a measure of the potential for a chemical species either to acquire or release electrons. The potential is commonly measured by an ORP probe in units of millivolts, which can be measured in real time under online plant process conditions.

Positive readings are indicative of a system operating in oxidizing conditions; negative readings indicate a system operating in reducing conditions. If a material comes into contact with a solution that has a higher oxidative potential, then a chemical reaction may occur in which the solution is reduced and the material is oxidized.

The ORP of WFGD slurry and effluent is driven by the presence or absence of strong oxidizers. Many WFGD units operate at a moderate ORP range of about 100 mV to 300 mV, thereby achieving, or yielding, a rather stable voltage reading over time. The range of 100 mV to 300 mV is referred to as “low” ORP in this article. Such WFGD units often have oxidizer concentrations within the slurry below 200 ppm. Other WFGD units operate at higher ORP values, often above 500 mV. Slurries with high www.powermag.com

ORP almost always contain a high concentration of at least one strong oxidizer such as persulfate (S2O8-2), peroxymonosulfate (HSO5-), or hypochlorite (OCl-).

Persulfate has been identified and quantified using ion chromatography on absorber slurry samples collected at several sites. This anion is the most powerful oxidant of the peroxygen family of compounds, and it becomes a more effective oxidizer at scrubber process temperatures above about 120F due to free radical formation. In several instances, strong oxidizers were measured at total residual concentrations over 1,000 ppm in WFGD absorber slurry samples exhibiting high ORP after the samples were removed from the system and analyzed in the laboratory. Operating WFGD units are observed to swing from one process condition to the other (high to low ORP), but few, if any, hold at an intermediate value for an extended period of time. The rate and magnitude of these changes in slurry chemistry are indicative of upstream process changes affecting absorber chemistry.

Once you determine the WFGD slurry ORP, you can predict the dominant oxidation state for the various constituents that may be present in the absorber slurry. For many metals, solubility is a function of the oxidation state. Therefore, once the ORP of a solution has been determined, a prediction can be made of the preferred oxidation state for a given chemical species in a solution. The predominant species of various metals, and other compounds or ions, can thus be determined. Using this knowledge, the ORP in WFGD slurry can then be controlled in order to control the speciation of various metal ions, as well as other compounds and ions.

The range of potential electrochemical states of a given material can be found within a Pourbaix diagram for a given chemical species and presented as a function of pH and electrochemical potential versus pH.

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POWER July 2013

WATER TREATMENT For example, a variety of general predictions about the various phases of mercury, selenium, and manganese based upon ORP and pH can be made (see the table).

Dominant forms of mercury, selenium, and manganese for approximate ORP levels. Source: Babcock & Wilcox Power Generation Group Inc. ORP Level

Dynamic Chemical Processes By monitoring the ORP of WFGD absorber process slurry, changes within the system process and chemistry can be determined.

Estimations of various parameters of WFGD absorber chemistry can also be determined, including the dominant oxidation states and phases of metals within the slurry, the potential reemission of mercury, and the risk of accelerated corrosion of the alloy vessel.

Measurement of the system ORP also alerts operators to the likelihood of problems in downstream wastewater treatment (WWT) systems, especially the ratio and concentration of selenate ions to selenite ions within an effluent stream.

The chemistry inside a WFGD absorber is a complex system of hundreds of potentially changing ionic species and distinct compounds existing simultaneously throughout the slurry. The modeling of WFGD absorber slurries has been based on equilibrium thermodynamics to date. However, we have determined that in operating units, WFGD absorber slurry chemistry is more likely to be kinetically controlled. Most absorbers are operating at an unsteady state. Due to kinetic interaction, mercury could become reduced to the elemental state, thereby becoming vaporous and exiting the system boundaries in what is called mercury re-emission.

Another important aspect of ORP with relation to WFGD process chemistry is the reaction of any of the one or more strong oxidizers present with one or more halide ions present in solution, thereby resulting in increased demand for reagent in the absorber and a possible lowering of pH in the purge stream after the solids have been removed.

Because persulfate is a powerful oxidant, it has the ability to convert some halide anions to their respective elemental state. Specifically, some chloride may convert to chlorine under high-ORP conditions:

Similar reactions occur between the oxidizer(s) and other halide species present (for example, bromide, iodide, and the like). Thus, the concentration of chlorine in absorber slurry is present as three species in equilibrium within the aqueous phase: dissolved gas (Cl2), hypochlorous acid, and ionic hypochlorite:

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July 2013 POWER

Mercury

Selenium

Manganese

Vapor

Selenite

Aqueous ion

0-300 mV

Aqueous ion, with the solids

Selenite

Aqueous ion

300-500 mV

Aqueous ion, with the solids

Selenate

Aqueous ion

>500 mV

Aqueous ion, with the solids

Selenate

MnO2 solid

<0 (mV)

Within the typical WFGD operating range, equilibrium favors HOCl. The formation of H+ ions associated with this chemical reaction will cause a decrease in pH as halogencontaining species are liberated from the scrubber. In WFGD systems that are operating in pH control mode, the reagent feed controls will respond to the lower pH by adding more reagent. In systems with high ORP levels, gypsum formation may occur without the addition of oxidation air when sulfite reacts with strong oxygen containing oxidizing agents. Higher gypsum purity can result as excess limestone, normally an impurity within the gypsum product, is reacted to buffer the system from dropping pH. Due to the electro-reactive nature of mercury, ORP levels are a main driver in controlling reemission, dissolution into the slurry, and solid phase retention. Higher ORP values in the ART are favored in order to maintain dissolved mercury. ORP levels above 500 mV often favor an increase in the dissolved mercury, with constant total mercury content in the slurry. A decrease in the ORP in an ART is an indication of a less-oxidizing environment, leading to elemental mercury formation and potentially release (or reemission).

A possible chemical pathway for mercury reemission to occur is shown in Equation 3:

Swings in ORP value may also cause mercury to enter the elemental state and be reemitted from a WFGD tower.

Staying in Compliance WWT systems are tuned to control metals present in influents and to produce effluents within a certain concentration range. Changes in the influx of these metals to WWT may disrupt performance if controls and operational parameters cannot respond quickly. As swings in WFGD and/or WWT process occur, ORP may ultimately produce changes in the dominant state of regulated metals, thus permitting the WFGD effluent flow rate to affect the mass flux of each species. In this situation, detrimental fluctuations in ORP may result in minimal removal of some metals and potentially result in out-of-compliance operation. www.powermag.com

Controlling process ORP can lead to improved efficiency of WWT systems related to selenium removal. WFGD effluent ORP controls the precipitation of many regulated metals, particularly selenium. At low ORP, selenium exists mainly as selenite (SeO3-2) and can be removed by many WWT methods including chemical precipitation. At higher ORP levels (greater than about 300 mV,) selenium will predominantly occur as selenate (SeO4-2), which passes through many WWT systems.

The combined effects of over 1,000 ppm of total oxidizers and low pH potentially associated with high-ORP WFGD effluent streams can result in damage to bioreactor stock and/ or increased reagent costs in WWT systems.

Strong oxidizers present within WFGD effluent have the potential to upset biological processes.

During high-ORP conditions, the WFGD would essentially be feeding bleach (hypochlorite), peroxide, and stronger oxidizers to downstream systems; such oxidizers can damage microbial health when fed to biological treatment units.

Furthermore, high ORP in a WFGD effluent can result in low pH of WWT influent. As described earlier, oxidizers will continue to react with halide ions in solution, thereby liberating a hydronium ion and thus lowering pH. When excess carbonate is available, it may buffer such impacts. Once unreacted limestone is removed from the slurry filtrate during dewatering, the pH buffering capacity of the system rapidly decreases while oxidizer and halide ion concentrations remain and are fed to WWT.

Materials Must Resist Corrosion Materials coming into contact with WFGD slurry and effluent should be selected with careful consideration to the corrosive potential of high-ORP slurries containing ionic manganese.

Strong oxidative content is present in high-ORP slurry leaving the scrubber, and very low pH levels may be seen downstream in conjunction with high ORP. While industry focus has been given to WFGD ART corrosion, the potential exists for similar corrosion to occur in process pumps, dewatering operations, vacuum systems for gypsum production, as well as in process piping and WWT equipment.

Alloy 2205 duplex stainless steel (UNS S32205) is proving susceptible to accelerated corrosion from slurries that contain precipi41

WATER TREATMENT tated, or non-solubilized, manganese species and/or high ORP levels. Within the WFGD absorber, the majority of the corrosive attack is observed below the slurry level in the ART. Under high-ORP conditions, the rate of corrosion can accelerate. When the ORP of operating WFGD slurries is pushed above about 500 mV, manganese normally soluble as ionic Mn+2 will oxidize and precipitate out as MnO2.

When this precipitate contacts metal as part of a deposit, it serves as a galvanic cathode to exacerbate the fluoride and chloride driven un-

der-deposit corrosion mechanism. Corrosion thus accelerated by manganese precipitation can be rapid and severe.

In many applications ceramic tile and linings are considered as alternatives to alloy.

Wall-papering with UNS N10276 (Hastelloy C-276) has been performed in some installations. Some plastics and resins may also be susceptible to attack from high ORP levels.

Strong oxidizers within the slurry effluent may react with and thereby degrade some polymer bonds, because high-ORP filtrate

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samples were observed to weaken and discolor HDPE bottles in a laboratory setting.

Within substances such as fiberglass-reinforced plastic, such a reaction with resins could potentially cause some dissolution of the resin and/or lead to fiber delamination.

Plantwide Impact The WFGD ART ORP and the WWT influent process ORP both need to be controlled. Currently, studies are being performed to define techniques to maintain steady ORP and to allow for greater fuel flexibility. Such control would afford utilities the option to obtain the most cost-effective fuel, maintain a constant effluent for wastewater, and provide a better treatment scheme. Coal yard and boiler operators will need to work in conjunction with the plant’s continuous emission monitoring systems, the WFGD system, and WWT plant operators to implement improvements that integrate the entire process. Learning how a parameter change upstream affects the WFGD and WWT systems is quickly becoming crucial. With full control of the AQCS process train and dewatering systems, control of WWT influent is expected.

The effects of blending coals, staging combustion, and swinging load can create issues with AQCS equipment, especially in environments where WFGD units are employed. The WFGD system serves as the catch basin for all flue gas byproducts as well as any fine ash not captured in an electrostatic precipitator or pulse jet fabric filter. Undesired ORP levels, or undesired fluctuations therein, can cause problems ranging from mercury reemission to increased corrosion and improper treatment of WFGD effluent. Adjustments to combustion processes may affect operating parameters of the WFGD environment as well as the WWT systems. Combustion systems need tuning to allow for efficient power generation, compliance with existing regulations, and flexibility to comply with anticipated, tighter water and solid discharge regulations.

Due to the potential for aggressive or accelerated corrosion of some alloy material in high-ORP environments, care should be taken on selection of alloys or materials in the WFGD slurry and filtrate contact zones. Constituents of the WFGD slurry will include limestone, gypsum, halide ions, and metals from the burned coal as well as silica from the ash and other up-stream constituents. The ORP levels in the tank can cause the metals to undergo phase partitioning or to change their solubility due to changes in their oxidation state. ■

—S.R. Brown (srbrown@babcock.com) is AQCS engineer, R.F. DeVault (rfdevault@ babcock.com) is research chemist, and D.B. Johnson (dbjohnson@babcock.com) is field service engineer for Babcock & Wilcox Power Generation Group Inc.

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PLANT DESIGN

The Case for Utility Boiler Fuel Delivery System Upgrades A vital part of any coal-fired unit is its fuel delivery system (FDS). A newly formed subcommittee of the ASME Research Committee on Energy, Environment, and Waste has investigated potential FDS upgrades on three typical 500-MW wall-, tangential-, and cyclone-fired boilers. The subcommittee has produced a series of suggested upgrades that have a simple payback of no more than two years.

By Robert E. Sommerlad, Consultant; Donald B. Pearson, PRB Coal Users’ Group; Grant E. Grothen, Burns & McDonnell; and Steven McCaffrey, Greenbank Energy Solutions Inc.

The first step in the subcommittee’s analysis of fuel delivery systems (FDS) was to identify the family of plants of interest. A recent article (“Predicting U.S. Coal Plant Retirements,” May 2011, available in the POWER archives at powermag.com) noted that the U.S. coal-fired fleet consisted of 1,105 units with a total nameplate capacity of 342 GW at the time the article was published. A majority of those plants were between 20 and 85 years old; only 35 new plants had been added over the past 15 years.

As a group, the units 50 years and older constitute about 53 GW or 20% of the total fleet capacity and 40% of all coal-fired units—many of which may be retired due to either normal business decisions or the cost of mandated retrofits of new air quality control systems (AQCSs).

The next age group, the 30- to 45-year-old units, represent 216 GW and 63% of the current coalfired fleet. Many of these were built during the 1960s and are much more likely to invite investment in plant upgrades (Figure 1).

The boilers of the 30- to 45-year-old units are mainly of opposed wall-, cyclone-, and tangential-fired configuration with average capacity factors ranging from 61.8% to 73.3%, as shown in Figure 2. In 44

lated by averaging the rating all of the units within each age category. Data are from early 2011.

Source: POWER and Burns & McDonnell

Coal fleet average unit nameplate rating (MW)

Identify Plant Categories

1. Coal fleet average unit nameplate rating. The average unit rating was calcu-

600 500

567 521 518

494

400

371 326

326

297

300

230

210 200

173 124

100 0

76

5

10

15

20

25

30

35

40 45 50 55 Unit age (years)

60

65

57 70

40 75

0 80

6 85

2. Coal fleet average capacity factor. The average unit capacity factor was calculated by averaging the reported capacity factor of all the units within each age category. Many of the units in the five years or less category did not have data available. A 75% capacity factor was estimated. In all categories, if capacity factor data was not available, that unit was omitted from the average. Data are from early 2011. Source: POWER and Burns & McDonnell 90 80

77.3

75 est.

Coal fleet average capacity factor (%)

T

he American Society of Mechanical Engineers’ Research Committee on Energy, Environment, and Waste (RC EEW) was formed more than 40 years ago with a focus on industrial and municipal solid waste.

The Fuel Delivery System Subcommittee was recently formed to expand the RC EEW’s original charter to include all fuels, including the energy and environmental aspects of those fuels. The first project undertaken by this subcommittee, begun in September 2011, was a feasibility and economic analysis of potential upgrades to Powder River Basin (PRB) coalfired power plants. A summary of results of the subcommittee’s work to date follows.

72.7

74.6

72.1

73.3 71.9

70

67.3 61.8 61.8

60

57.2

54.9

50 40 31.8

30 23.3 19.1

20

18.0

10 0

0

5

10

15

20

25

www.powermag.com

30

35

40 45 50 55 Unit age (years)

60

65

70

75

80

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POWER July 2013

PLANT DESIGN this age group, there were about 226 opposed wall-fired, 143 tangential-fired, and about 15 cyclone-fired boilers in operation in the U.S. in 2011.

These units—the backbone of the baseload coal-fired fleet—will bear the burden of ensuring that the usual high standards of electrical grid performance, availability, and reliability are met in the future. Though most of these units have high-grade AQCSs, they will require upgrades to comply with maximum achievable control technology, but the cost is not forecast to adversely impact unit competitiveness in terms of generation cost.

However, the additional AQCS upgrades required for environmental compliance will add additional complexity to plants now straining to maintain unit availability and capacity factor.

A vital part of any coal-fired unit is its fuel delivery system, as shown in Figure 3. For the purposes of the subcommittee’s analysis, the FDS consists of the feeders, pulverizers (mills), classifiers, coal piping, and burners. These systems are vital for efficient and reliable plant operations but also require substantial maintenance due to the abrasive nature of coal.

the furnace and the convection sections of the boiler. They also impede good lowNOx burner performance. Improving fineness also reduces unburned carbon in the fly ash, thus improving combustion and boiler efficiency.

Additional Assumptions Members of the subcommittee decided that three boiler types, representative of the 35to 50-year-old fleet, would be selected: opposed wall-, tangential-, and cyclonefired boilers. The group also decided that representative boiler systems would form the basis of the upgrade analyses, although the plant itself would remain anonymous.

A common factor shared among boilers of this vintage is that they were normally designed to burn eastern or Illinois Basin coal and have been or are being considered for conversion to a subbituminous PRB

coal for emissions reduction. Most boilers have had some burner modifications over their operational life, and new modifications would be considered more for performance improvement than for emissions reduction. In focusing on the FDS, it was further assumed that air pollution retrofits would not be part of the FDS upgrades.

It was also assumed that any FDS upgrade would not increase the heat input over its original design rating and that there would be no increase in emissions, to avoid the need for a New Source Review. In addition, emissions would be less than 100 tons/year for individual pollutants, thus not triggering the Prevention of Significant Deterioration process. It was assumed that the opposed wall and cyclone boilers had selective catalytic reduction (SCR) systems installed for NOx control, but that the tangential-fired unit did not yet require in-

3. The typical coal plant fuel delivery system. Source: Babcock & Wilcox Power Generation Group Inc. Raw coal bunker

Furnace wall

Identify Possible Fuel System Upgrades In recent years, improvements in monitoring equipment have led to significant performance improvements in FDS equipment and therefore the availability and reliability of a plant. Many of these have been in flow-measuring devices for enhanced control of fuel (such as feeder coal flow and pulverized coal flow in coal pipes) and airflow (including primary and secondary air, pulverizer preheated air, coal pipe air, wind box air, and individual burner air— both secondary and tertiary).

In a properly instrumented system, the amount of coal and air sent to individual burners so vital for low-NOx and CO operation can be measured and monitored, ensuring that good combustion takes place.

Please note that cyclone boilers utilize a different FDS that consists of feeders, crushers, and cyclone burners. These differences will be addressed in the project economics section of this article.

Upgrades to the FDS to improve plant operating economics are numerous and often site- and boiler-specific (Table 1).

Each FDS component upgrade can have benefits, most of which can be quantified.

An example is the retrofit of a dynamic classifier, which improves coal fineness and virtually eliminates the coarse coal particles (>50 mesh). Coarse particles are a main cause of fouling and deposition in

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July 2013 POWER

Burner

Bin gate Damper

Coal feeder

Pulverized fuel and air piping Isolation valves

Hot air damper

Secondary air

Hot primary air

Tight shutoff damper

Air heater Tempering air

Seal air fans

Tempering air damper B&W roll wheel pulverizer

Primary air fan

Table 1. A comparison of possible fuel delivery system upgrades and their benefits. Source: The Fuel Delivery Subcommittee of the ASME Research Committee on Energy, Environment, and Waste Component

Upgrade

Benefit

Feeders

Metering

Flow control

Pulverizers

Dynamic classifier

Fineness/capacity

Coal pipes

Coal-air flow metering

Flow and air-fuel ratio

Burners Boiler control system

www.powermag.com

Metering

Improved combustion

Neural networks

Improved performance

45

PLANT DESIGN stallation of an SCR due to the inherently low NOx emission characteristics of that boiler design.

The analyses further assumed the plant capacity factor for this study is 80% (7,008 hours/year). In the current low natural gas price environment, this 80% capacity factor is likely higher than many units are currently operating at. A sensitivity analysis was performed using a range of lower capacity factors. The subcommittee believes that higher capacity factors will likely return as natural gas prices slowly but steadily rise in the future.

Determine Upgrades, Benefits, and Costs For each case study, the FDS components were identified and upgrades were proposed. Next, the potential benefits of the upgrades were discussed and evaluated.

The list of proposed upgrades was the source of spirited discussion among subcommittee members, although a consensus was always reached that reflected the collective expertise and diverse experience of the members.

For each case study, the upgrade’s scope was defined in sufficient detail so that reliable estimated costs could be prepared.

Fortunately, the various suppliers and consulting engineers on the subcommittee were able to provide estimates of the installed costs for each upgrade considered based on prior experience.

Assessing the savings produced by the upgrades was also reached by consensus over the course of several subcommittee meetings. Difficulties arose when the economic benefit of upgrading one component

4. Coal fleet boiler design. The three case studies were selected from the three largest categories of boiler design now used in the fleet. Fluid bed units were not included because those fuel systems are unique and often handle opportunity fuels. Source: POWER and Burns & McDonnell Vert-ceiling 2% Fluid bed 3%

alone was not possible because some upgrades were contingent on other upgrades.

Also, there were interactions between the upgrades that were difficult to quantify. The savings that accrue are not always merely the sum of the individual upgrades. For example, an evaluation of the economics of using neural networks within the boiler control system produces improved boiler performance, but much of the performance improvement came from the burner modifications required by the neural net system.

study. However, the FDS boundary was expanded beyond the individual cyclone feeder to beyond the coal conveyors, to the crusher-feeder island, usually located some distance from the boiler. It was felt that the crusher, more than any other device, controlled particle sizing, and the upgraded feeder provided a more uniform flow of coal to the crusher, improving overall crusher performance.

Three Case Studies

The candidate opposed wall–fired, natural circulation boiler was originally designed for eastern coal and now burns a PRB coal.

It has a retrofit SCR and the original electrostatic precipitator; plans are in place to retrofit a wet scrubber. The proposed FDS components for upgrade include replacement of original feeders, retrofit dynamic classifiers on vertical shaft pulverizers, coal pipe flow-metering devices, burner modernization, retrofit OFA, airflow metering devices, and retrofit boiler control system (BCS) with a neural network. Several of the suggested upgrades are described below and summarized in Table 2.

Fuel Feeders. The original, roughly 40-year-old volumetric feeders were replaced with new gravimetric feeders with improved metering. They also provide some increased capacity, because PRB, with its lower heating value, requires more material throughput than the original eastern bituminous coal. Six new feeders were each estimated at $75,000 x 2 (cost of installation) = $900,000. Benefits were included with those of dynamic classifiers (DCs), below.

Pulverizers. DCs are used to increase coal fineness at a given coal throughput. In so doing, DCs also reduce the coarse grind,

The subcommittee believed that each case study 500-MW boiler must be representative of the boiler design class. Selection of the case studies was based in large measure on the spectrum of boiler types that currently constitute the U.S. utility boiler fleet, as shown in Figure 4. In considering the ~500-MW units in the 35- to 45-year age range, the vertical- and front wall–fired boiler were eliminated on the basis that few, if any, would be 500-MW-size boilers.

Cyclone boilers provide an interesting opportunity for evaluation in this study. Cyclone boilers lost favor in the 1980s when they were characterized as high NOx emitters and not amenable to combustion modifications. Supposedly, they were also not amenable to burning PRB coal. Today there are approximately 60 cyclone-fired boilers still in operation, of which 10 are in the 400to 600-MW size range and four are greater than 600 MW. Many of these boilers have been successfully converted to burn PRB coal, usually with retrofitted overfire air (OFA) ports installed to aid combustion tuning for reduced NOx production.

The subcommittee decided to include a cyclone-fired unit as a separate case

Case Study 1: The Opposed Wall– Fired Boiler

Table 2. Case Study 1: Opposed wall–fired boiler FDS upgrades benefits and costs. The investment breakeven point was 15 months. Source: The Fuel Delivery Subcommittee of the ASME Research Committee on Energy, Environment, and Waste Component

Upgrade

Cost ($ x 1,000) $900

New feeders

Pulverizer

Dynamic classifiers

Coal pipes

Coal-air flow

$700

Burner modernization

LNBs & OFA

$5,400

Some NOx reduction as NH3 savings. Other benefits claimed in BCS. NH3 savings: $210.

Boiler control system

Neural network

$300

Efficiency improvements, $596; fan energy savings, $314; NH3 savings, $85.

Project management & engineering services

25%

$3,600

Unknown 6% Cyclone 7%

Other 7%

T-fired 37%

Opposed 19% Front 20%

Savings ($ x 1,000/year)

Feeder

Total

$2,725 $13,625

Combine with dynamic classifiers 5% performance recovery savings, $8,760; two days' operation, $960.

Combine with boiler control system.

NA $10,925

Notes: BCS = boiler control system, LNB = low-NOx burners, NA = not applicable, OFA = overfire air.

46

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POWER July 2013

PLANT DESIGN the 50-mesh material, which is a primary cause of slagging and fouling. A lesserknown feature of DCs is that they can also increase pulverizer capacity (depending on DC speed), fineness at higher speed, and throughput at lower speed. Typically, this is accomplished with little or no increase in pressure drop.

Because PRB is a volatile coal, there is little need for an increase in coal fineness, but there is a need for increased pulverizer throughput over the original eastern coal design conditions. DC costs were estimated as 6 x $300,000 x 2 (cost of installation) = $3,600,000, acknowledging that $300,000 is on the high side and normal installed cost is usually less than double the equipment cost.

A switch from eastern to PRB coal and its associated lower heating value means that greater quantities of PRB coal passing through the FDS and the vertical shaft mills were required to produce the same heat input. In this plant, heat input to the boiler was reduced due to coal throughput limitations. Thus, the DCs’ ability to recover lost pulverizer and boiler capacity, especially when one or more pulverizers are out of service for required maintenance work, is

vital. A conservative value of 5% loss in boiler capacity was used. The reduction of 50-mesh coal particles and improved combustion was estimated to recover two days of operation at full load. Other benefits included improved load response, improved coal drying, often less vibration, but modest NOx and unburned carbon (UBC) reduction.

The savings from the 5% capacity recovery was $8,760,000, and two days of full-load operation at $0.05/kWh was $960,000, for a total savings of $9,720,000.

Coal Pipes. The subcommittee considered coal pipe flowmeters because coal flow measurements may not be exact. The individual flow meters allow comparison of coal flow between pipes to ensure more equal and consistent coal flow to the burners that will in turn ensure good air to fuel ratios at each burner.

There was some discussion about replacing coal pipes on the basis of increased pressure drop or fan limitation. It was felt that coal pipes are seldom replaced, so this option was discarded. In sum, upgrades studied included the coal pipe flow modifications, $500,000, and primary airflow modifications, $200,000, for a total of $700,000.

It is vital to measure both coal and air as a precursor to aggressive efficiency improvement. It was also felt that the DCs would resolve a potential pressure drop issue, and the pressure drop issue was further clarified, as shown below in the BCS section.

Burner Modernization. The existing low-NOx burners (LNBs) are a third generation; a fourth-generation upgrade is planned that will include burner modernization and airflow-monitoring devices.

Overfire air is also included. NOx reduction with these new LNBs and OFA would be about 10% (~0.02 lb/106 Btu), but they serve primarily to reduce NH3 consumption by the SCR. UBC would not drop, and CO would be held to <100 ppm.

The combination of retrofit DCs and LNBs would reduce slagging and fouling, improve flue gas flow to the SCR and air heater, provide better combustion, and improve boiler performance. Typically, LNBs are upgraded every six to eight years due to new design improvements. Costs were estimated for the LNBs as $75,000 x 24 burners x 2 (cost of installation) = $3,600,000; OFA $25,000 x 8 + $50,000 x 8 (cost of installation) = $600,000; electrical $1,000,000 (cost of installation); and $200,000 for

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47

PLANT DESIGN burner management (such as new scanners and cabinets) for a total of $5,400,000. The only direct benefit was some NOx reduction that reduced annual NH3 usage by $210,000.

The other benefits for improved combustion were improved boiler performance, shown in the next section.

Boiler Control System. In a detailed analysis by a Burns & McDonnell team, all the various upgrades were examined and critiqued with a review and modification of the cost when merited. In the original consideration of upgrades to the BCS it was felt a new BCS would provide benefits as well as a neural net system. As it turned out, the Burns & McDonnell team revised the BCS upgrade to only a neural network at a cost of $300,000. This applied to pulverized coal–fired boilers (Case Studies 1 and 2) and provided unexpected benefits.

Two good rules of thumb were useful in this analysis. First, “10% excess air = 0.5% boiler efficiency” and “10% excess air = 22% fan power.” Using these rules of thumb, the difference is (22.8% – 16.1%) = 6.7% change in excess air, which results in approximately 0.34% improvement in boiler efficiency and 15% improvement (decrease) in fan power.

The savings due to boiler efficiency improvements can be estimated as 500 MW x $0.05/kWh x 7,008 hours/year x 0.0034 = approx. $600,000/year of cost savings.

Assuming 2 x 4,000 horsepower (hp) fans, 8,000 hp x 0.7457 kW/hp x $0.05/ kWh x 7,008 hours/year x 0.15 = approx. $314,000/year savings in fan power.

Improving NOx from 0.17 lb NOx/106 Btu to 0.15 lb NO x/106 Btu will decrease the amount of ammonia consumed. Assuming 10,500 Btu/kWh heat rate, $400/

ton anhydrous ammonia, SCR outlet NOx of 0.04 lb/106 Btu at 80% capacity factor, the reagent savings are approximately $85,000/year.

Project Management and Engineering Services. Engineering services,

including commissioning costs, were estimated as about 15% plus an additional 10% for project management costs, which amounted to $2,725,000.

Thus, the total installed cost is estimated as $13,625,000 and the total savings are estimated as $10,925,000—a simple payback of 15 months, as shown in Table 2. It is important to note that 83% of the cost savings were the recovery of a presumed 5% unit derate taken when the unit was converted from eastern bituminous coal to a western subbituminous PRB coal.

Case Study 2: Tangential-Fired Boiler The 500-MW tangential-fired boiler used in the analysis is a single furnace with five levels of burners and five pulverizers, 100 MW per pulverizer. Many boilers of this size and age do not have SCRs, but they often have lower NOx and UBC than other boiler designs. The subcommittee consensus was that burner modifications would be appropriate regardless of whether or not an SCR was added.

The first improvement was separating the burner levels to further reduce NOx emissions. The benefits of DCs with regard to recovery of lost capacity apply, but the need to improve slagging and fouling may not be as great. Burner modifications would involve changing buckets and adding separate overfire air (SOFA). NOx reduction may be less, but NOx emissions are likely to be

Combine with dynamic classifiers.

5% performance recovery savings, $8,760; two days' operation, $960.

Case Study 3: Cyclone-Fired Boiler

ery Subcommittee of the ASME Research Committee on Energy, Environment, and Waste Component

Upgrade New feeders

Pulverizer

Dynamic classifiers

Coal pipes

Coal-air flow

Burner modernization

New burners SOFA, pressure part mods, ducts, and dampers

Boiler control system

Neural network

Project management & engineering services

25%

Cost ($ x 1,000)

Total

$750 $3,000 $584

Savings ($ x 1,000/year)

Combine with boiler control system.

$4,800

Some NOx reduction, but no significant savings: $0.

$300

Efficiency improvements, $596; fan energy savings, $314.

$2,359 $11,793

NA $10,630

Notes: NA = not applicable, SOFA = secondary overfire air.

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Project Management and Engineering Services. A consistent 25% of the up-

grade costs was included, which amounts to $2,359,000.

Total cost of the upgrades is $11,793,000, with a total savings of $10,630,000. The breakeven point for the investment is approximately 13 months, as shown in Table 3.

As before, 82% of the savings are attributable to recapturing 5% of the unit capacity lost as part of the initial fuel switch from an eastern bituminous coal to a lower heat content subbituminous PRB coal.

Table 3. Case Study 2: Tangential-fired boiler FDS upgrades benefits and costs. The investment breakeven point was approximately 13 months. Source: The Fuel Deliv-

Feeder

low. Neural networks would provide similar improvements. Several of the suggested upgrades are described below and summarized in Table 3.

Feeders. The upgrades were much the same as in Case Study 1 but with five new feeders, costing $750,000 installed. The cost benefits were included with DCs. Pulverizers. The cost of the upgrade follows the calculations presented in Case Study 1, or $3,000,000. The calculation of benefits likewise followed the methods used in Case Study 1. Savings from the 5% capacity “recovery” were $8,760,000 and two days of full load was $960,000, for a total savings of $9,368,000.

Coal Pipes. As in Case Study 1, unit upgrades chosen were coal pipe flow and primary airflow measurement at a total of $584,000.

Burner Modernization. The modernizations comprise some bucket replacement and the addition of SOFA ports, which would require some boiler pressure part modifications. SOFA was estimated at $4,800,000. Benefits were some claimed NOx and UBC reductions, but no significant savings were estimated.

Boiler Control System. The same upgrade of a neural network with no new BCS is estimated to cost $300,000 with the similar savings forecasted in Case Study 1: boiler efficiency, $600,000, and fan reduced power costs of $314,000. There are no NH3 savings because there is no SCR. Thus, the total estimated savings are $914,000.

www.powermag.com

The cyclone boiler investigated for this case study was originally designed (in the late 1960s) to fire Illinois Basin bituminous coal, but it now burns PRB coal (since the late 1980s). It has been retrofitted with OFA (1990s), SCR, dry flue gas scrubber, fabric filter, induced draft fans (converted from pressurized to balanced draft), various boiler and turbine modifications, and new O2 analyzers (2000s). Several of the suggested upgrades are described below and summarized in Table 4.

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PLANT DESIGN Table 4. Case Study 3: Cyclone-fired boiler FDS upgrades benefits and costs. The investment breakeven point was approximately 18 months. Source: The Fuel Delivery Subcommittee of the ASME Research Committee on Energy, Environment, and Waste Component

Upgrade

Cost ($ x 1,000)

Savings ($ x 1,000/year)

Feeder/crusher island

New feeders and instrumentation

$1,200

Combine with cyclone modernization.

Cyclone modernization

Cyclone upgrades and new "split" air damper

$2,880

Seven days’ full-load operation due to elimination of downtime caused by slagging: $3,360.

Boiler control system

Update boiler control system

$400

Efficiency improvements, $298; fan energy savings, $157.

Project management & engineering services

25%

Total

$1,120

NA

$5,600

$3,815

Project Management and Engineering Services. A consistent 25% of

Table 5. Impact of capacity factor on plant retrofit economics.

Note the simple payback for each case study remains less than two years for a capacity factor down to 60%. Source: The Fuel Delivery Subcommittee of the ASME Research Committee on Energy, Environment, and Waste Case study & boiler type

Results

Capacity factor 60%

70%

80%

Savings ($ x 1,000)

$8,295

$9,096

$10,925

Payback (months)

20

18

15

2: Tangential

Savings ($ x 1,000)

$7,973

$9,301

$10,630

Payback (months)

18

15

13

3: Cyclone

Savings ($ x 1,000)

$2,861

$3

$3,815

Payback (months)

23

20

18

1: Opposed wall

Notes: NA = not applicable, SOFA = secondary overfire air.

Fuel Preparation System. The feedercrusher “island” was included in the FDS boundary, because this equipment is a vital part of coal sizing necessary for good combustion. It was generally agreed that some modification would have been made to the feeder-crusher island when switching to PRB coal, which would have included dust control and other safety-related issues.

The same would have been included in all the coal conveyors, but the coal conveyors from the feeder-crusher island to the cyclone are not part of the FDS. As part of the FDS upgrade, some upgrades will be made to the feeder-crusher island to improve coal grind at a given or increased throughput, and these costs were estimated. In discussing the cyclone modification, it was agreed that the 12 cyclones, feeders, and burners would have been previously modified, but that the upgrades to reduce UBC, which is in some cases 20% to 30%, would be required. Upgrades include a new posimetric feeder, fine grind cage crusher, and motor upgrades at $1,200,000.

Cyclone Modernization. Cyclones were upgraded with new split secondary

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July 2013 POWER

this reason the costs of new cyclones or cyclone pressure part upgrades were not addressed by this study. Also not included was the use of iron oxide additives for improved slag flow.

Boiler Control System. Only an upgrade to the BCS was required—no BCS and neural network additions. This upgrade provided savings similar to those shown for Case Study 1, except there was no significant NH3 savings. The savings again related to efficiency ($298,000) and fan operation ($157,000), for a total of $455,000.

air dampers and damper actuators. Benefits include reduced NOx and UBC by improving combustion (allowing low excess air operation); more even flue gas distribution in the furnace convection sections, SCR, and air heater; and reduced slagging.

Upgrades were estimated at $2,800,000.

The benefits were reduced operation at lower loads with individual cyclones forced out of service due to cyclone slag buildups and downtime for boiler deslagging. Longer time is usually required to cool cyclone furnaces for deslagging and maintenance work.

The savings estimates are based on an additional seven full days of operation in a year by reducing forced outages for cyclone cleaning. Modification costs were calculated at $3,360,000.

It was noted that if the cyclones themselves were nearing the end of their useful life and were to be replaced, there are numerous upgrades that should be incorporated in the replacement cyclones to further enhance PRB coal firing. However, if the cyclones were not to be replaced, these pressure part upgrades would not be made just to improve PRB coal firing. For www.powermag.com

the upgrade costs was included, which is $1,120,000.

The total upgrade cost is estimated as $5,600,000, total savings as $3,815,000, and the breakeven at 18 months, as shown in Table 4. Again, note that 88% of the cost savings are attributable to potential recovery of lost generation due to derates or forced outages caused by convective pass slagging.

The Effect of Capacity Factor The case study estimates are all based on a capacity factor of 80%, as noted earlier. While the study was under way, the increased use of natural gas reduced coal plant average capacity factor during 2012 in many regions of the U.S. Rising natural gas prices have pushed some utilities to increase coal-fired generation as the least cost option in early 2013. Table 5 illustrates the analysis results for a range of capacity factors, assuming the investment cost remains constant. Even with capacity factors in the range of 60%, the breakeven point for each project is less than two years.

The subcommittee solicits comments on the results of the analysis and suggestions for additional study. Please forward your comments and suggestions to Subcommittee Chair Robert Sommerlad. ■

—Robert E. Sommerlad (rsommerl@aol .com) is a consultant and Subcommittee Chair. Donald B. Pearson is secretary of the PRB Coal Users’ Group.

Grant E. Grothen is principal, Burns & McDonnell. Steven McCaffrey is with Greenbank Energy Solutions Inc. Other members of the Subcommittee were Robert Chase, Terrasource Global; Blaz Jurko, Gebr. Pfeiffer Inc.; David J. Stopek, Consultant, Sargent & Lundy LLC; Melanie Green, CPS Energy; Richard Himes, EPRI; Tony Licata, Licata Engineering Consulting and Chair RC EEW; and Todd Melick, Vice President, Promecon USA. 49

ASSET MANAGEMENT

EMP: The Biggest Unaddressed Threat to the Grid The electricity grid has been characterized as the world’s largest and most complicated machine. The grid, like all machines, requires periodic upgrades and maintenance to prevent outages during the normal course of business, and it can be brought down by various outside forces. Solar flares and cyber attacks have temporarily crippled the machine, but an electromagnetic pulse event would be the “ultimate cyber security catastrophe.”

By Kennedy Maize

W

hen North Korea last December successfully launched a satellite into orbit around the Earth, much of the chatter in the news media was about the ability of the rogue nation to reach a U.S. city on the West Coast with a nuclear warhead. Many experts in nuclear proliferation, including U.S. government officials, believe North Korea has a stockpile of a dozen or so nuclear weapons and the technology to produce more.

But for one set of experts, who accept the calculations about the size of the North Korean nuclear arsenal, the advances in the country’s ability to deliver a warhead over vast distances raised another, possibly more troubling, prospect. While North Korea’s nuclear and ballistic missile program probably isn’t yet sophisticated enough to put a warhead onto a specific target thousands of miles away, the country may be able to get close enough to explode a warhead some 50 miles somewhere over the U.S. That’s an easier task.

But the outcome likely would be catastrophic and widespread. As defense analyst Peter Pry has written, North Korea’s successful orbit of a satellite demonstrates its ability “to make an EMP attack against the United States—right now.” That’s a very nasty thought. Rep. Trent Franks (R-Ariz.), chairman of the House EMP Caucus, told POWER that such an attack would be “a worst case scenario . . . almost unthinkable.”

Electromagnetic pulse (EMP) is a force of nature that can wreak havoc with much of modern electronic infrastructure, as earlier articles in POWER’s publications have discussed in the context of solar storms (see “The Great Solar Storm of 2012?” in the February 2011 issue of POWER). EMP can also be a manmade force. As Pry, a former staffer on a congressional EMP commission and now executive director of the Task Force on National and Homeland Security, explains, 50

“Any nuclear weapon detonated above an altitude of 30 kilometers will generate an electromagnetic pulse that will destroy electronics and could collapse the electric power grid and other critical infrastructures—communications, transportation, banking and finance, food and water—that sustain modern civilization and the lives of 300 million Americans. All could be destroyed by a single nuclear weapon making an EMP attack” (Figure 1).

According to Pry, North Korea has been working on a super-EMP weapon for a decade or more. He says that in 2004, a delegation of Russian generals to the first Congressional EMP Commission revealed that the Kim dynasty was working on such a

weapon. Nothing since had contradicted that assessment.

Writer F. Michael Maloof, who spent 23 years at the Pentagon trying to keep critical technology out of the hands of rogue nations and groups, told POWER recently that EMP “is the classic asymmetrical weapon for warfare by a country far less powerful than the U.S. Our technology-based society has made us an economic and industrial world power.

But it has also made us vulnerable in the case of EMP.” Maloof’s new book, A Nation Forsaken, lays out the EMP threat and those who could threaten the U.S. with an EMP attack.

Those nations include not only North Korea but also Iran and Pakistan. Pakistan in particular has a large nuclear weapons stockpile,

1. Area affected by an electromagnetic pulse, by height of burst. The spread of the EMP is caused by gamma rays hitting the atmosphere at an elevation between 12 and 25 miles altitude, causing rejection of electrons that are then deflected sideways by Earth’s magnetic field. The result is that the EMP pulse is spread over an enormous area. Not shown on this diagram is the magnetic signature of Earth that accentuates the EMP effects south of the pulse and attenuates the effects north. Source: America’s Vulnerability to a Different Nuclear Threat: Electromagnetic Pulse, Heritage Foundation Backgrounder #1272, May 26, 2000 Height of burst: 300 miles Height of burst: 120 miles 1,470 miles

Height of burst: 30 miles 1,000 miles 480 miles

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ASSET MANAGEMENT and the country either encouraged or looked the other way when one of its scientists—now a revered national hero, A.Q. Kahn—diverted European centrifuge uranium enrichment technology to Iran and North Korea.

But the EMP threat extends further down the threat chain than bad state actors in nasty neighborhoods. While a nuclear weapon detonated above a modern country could spread broad havoc, much smaller devices can use pulses of radio frequencies to take out specific targets such as power plants, refineries, electric substations, and the like, arming terrorist groups, disgruntled employees, or addled individuals with asymmetrical weapons that profoundly challenge conventional arms control and police capabilities.

In his book, Maloof describes a hypothetical attack on Washington, D.C., that completely disrupts the nation’s capital and surrounding areas, including commu-

nications at the Pentagon. The attackers, he writes, use “small, rifle-sized arms that shoot not bullets but radio frequencies, weapons that can be built for about $400 with easy-to-obtain parts. Think of one of those Super Soaker water guns.” (The U.S. military is, not surprisingly, also looking at the use of electromagnetic forces for weaponry—see the sidebar.)

Maloof also describes how a terrorist cell with a primitive EMP weapon in the back of a panel truck could easily bring down a passenger airplane landing at Washington’s Reagan National Airport. “At the cost of a few thousand dollars in material and know-how, this homegrown terror cell kills more than a thousand people—several hundred passengers on the planes, the rest in the buildings that take the full impact of the crashing planes.”

The visions of Franks, Maloof, Pry, and others about the possibility of an EMP threat

have critics, although their critique is directed not directly at the physics of an EMP assault but at the doomsday nature of an attack.

Physicist Yousaf Butt, a Federation of American Scientists consultant, wrote last year in The Space Review, “If terrorists want to do something serious, they’ll use a weapon of mass destruction—not a weapon of mass disruption.” He said an EMP attack depends “on complicated secondary effects,” rendering it less fearsome and less likely.

Starfish and Other Denizens of the Deep U.S. scientists learned of the perverse effects of an EMP in an Atomic Energy Commission 1962 test explosion of a 1.4 megaton warhead over the South Pacific.

It was called “Starfish Prime,” one of several tests in the “Operation Fishbowl” series. The blast caused an electrical pulse

Electromagnetic Rail Guns Electromagnetic forces are not only a threat to U.S. infrastructure but also can be the motive force for advanced weapons. The U.S. military has been working for many years on an electrical “rail gun” that would use magnetic forces to suspend a projectile in a field and propel it forward at enormous

speeds, freed from the friction that limits conventional guns. Although the Air Force initially supported rail gun research, the program has shifted to the Navy, which sees the weapon as a way to increase its reach for ships firing at targets beyond what conventional armaments now allow (Figure 2).

2. Fast and furious. The electromagnetic railgun launcher is a long-range weapon that fires projectiles using electricity instead of chemical propellants. Magnetic fields created by high electrical currents accelerate a sliding metal conductor, or armature, between two rails to launch projectiles at 4,500 mph to 5,600 mph. Electricity generated by the ship is stored over several seconds in the pulsed power system. Next, an electric pulse is sent to the railgun, creating an electromagnetic force accelerating the projectile to Mach 7.5.

Using its extreme speed on impact, the kinetic energy warhead eliminates the hazards of high explosives in the ship and unexploded ordnance on the battlefield. Source: Office of Naval Research, U.S. Navy Above sensible atmosphere Simplifies deconfliction

Surface warfare

Missile defense Hypervelocity launch/impact (MACH 5–7) Indirect fire Long range fires

Direct fire (horizon in 6 seconds) Enhanced company operations

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July 2013 POWER

www.powermag.com

According to the Navy’s research program, the rail gun would be a “longrange weapon that fires projectiles using electricity instead of chemical propellants. Magnetic fields created by high electrical currents accelerate a sliding metal conductor, or armature, between two rails to launch projectiles at 4,500 mph to 5,600 mph.”

The key to the rail gun, according to the Navy, is a pulsed electric power system located on the ship. The electrical system would produce an instantaneous burst of electrical energy that would push a projectile down a rail path and toward a target. The rail gun would be able to reach enemy targets some 70 miles in the distance, far beyond conventional chemical ballistic, ship-fired missiles.

But development of the weapon hasn’t been easy. Popular Science reports, “Rail guns require a massive amount of electricity that current naval ships cannot spare if they can generate it at all. The Navy hopes its rail gun will debut on the next-generation of high-powered ships, like the Zumwalt class destroyer (currently slated to enter service in 2015) by early in the next decade.” The magazine notes that the Navy has spent some $240 million over seven years and “the technology is still very much restricted to the lab.” Live demonstrations could come in 2017.

51

ASSET MANAGEMENT far beyond what the scientists had calculated, driving their instruments off scale.

The explosion caused damage as far away as Hawaii, some 900 miles to the east, where it blew out streetlights, set off burglar alarms, and fried a telephone company microwave repeater.

Subsequent atmospheric tests—Bluegill Triple Prime and Kingfish—further established the unexpected EMP effects, including disrupting the Telstar communications satellite, alerting researchers to the new phenomenon. But EMP remained a largely classified topic for the next 20 years. In 1982, facing a series of challenges on how to base the next generation of strategic ballistic missiles, the MX missile, the Reagan administration began lifting the veil of secrecy around EMP effects. The president (with Executive Order 12400) appointed a panel under the direction of General Brent Scrowcroft to examine issues related to siting the missiles. Among those was the effect of EMP on missile communications.

The Scowcroft Commission concluded that the U.S. missile program was adequately hardened against EMP effects, and the issue largely disappeared from view for another few years. Over the years, the military has spent hundreds of millions of dollars hardening its own infrastructure against an EMP attack.

The problem is the civilian grid (upon which the military also depends for more than 90% of its operations). In 1989, a solar storm caused widespread disruptions in the Northeast, raising the issue graphically, both in terms of solar storms and an intentional attack. Congress got interested in the issue, and in 2001 established a commission to examine the threat of EMPs. In 2004 that commission concluded, “Our vulnerability is increasing daily as our use of and dependence on electronics continues to grow. The impact of EMP is asymmetric in relation to potential protagonists who are not as dependent on modern electronics.

“The current vulnerability of our critical infrastructures can both invite and reward attack if not corrected. Correction is feasible and well within the Nation’s means and resources to accomplish.”

As is often the case with special governmental commissions, nothing came of the 2004 report. In the meantime, an enormous blackout that struck most of the Northeast in 2003 reignited concern about the vulnerability of the U.S. grid. Congress reestablished the EMP commission (www .empcommission.org), which issued another report in 2008, calling for national action to address the threat of disruption to criti52

cal U.S. infrastructure. The chairman, William Graham, testified to Congress in April 2008, “vulnerability to EMP that gives rise to potentially large-scale, long-term consequences can be reasonably reduced below the level of a potentially catastrophic national problem by coordinated and focused effort between the private and public sectors of our country. The cost for such improved security in the next 3 to 5 years is modest by any standard—and extremely so in relation to both the war on terror and the value of the national infrastructures threatened.”

Graham’s commission estimated the cost of hardening the grid and other critical infrastructure at $10 billion to $20 billion over 20 years. Mitigation involves, among other tasks, developing backup capability for grounded transformers, which would be among the most significant components of the grid to be damaged by an EMP attack. This would also protect against the effects of a large-scale solar storm hitting the grid.

Again, to date, nothing has been done.

Think Globally, Act Locally?

Peter Pry cries out for a national response, calling for a presidential executive order, which the EMP commission has drafted, “to protect the national electric grid and other critical infrastructures from an EMP attack.”

The lack of a federal government response, despite what he believes is the clear nature of the threat, led Michael Maloof to title his book A Nation Forsaken. He told POWER, “The federal government isn’t going to do anything.” The feds, Maloof argues, are so paralyzed by partisan divisions and fights over spending cuts that a fully national response won’t work.

The federal government, he says, “never takes preventative action.” He gives Congress credit for creating the two EMP commissions but adds, they “then ignored them. The federal government has failed, and so the nation is behind the curve. The Department of Homeland Security should be taking the lead on this, but isn’t.”

So Maloof says he’s been traveling to U.S. states to encourage state and local responses.

“This is a new states’ rights issue,” he says.

“People can take action at the state level. I’m traveling around suggesting people get together with their local emergency response agencies and coordinators” to plan for an EMP contingency.

Despite legislative failures in the past, Franks and his 13-member bipartisan caucus hope to move EMP legislation in the 113th Congress. “Two years ago,” he said, “we got the Grid Act passed unanimously in the House.” But it failed to pass in the www.powermag.com

Senate, largely because of concerns about the inclusion in the House bill of provisions related to cybersecurity. Now he’s preparing legislation that will separate out cybersecurity from the EMP issue. “It’s not that we don’t take cybersecurity seriously,” he said. “An EMP event would be the ultimate in a cybersecurity catastrophe.” But as a practical matter, the cyber threat has to get dealt with on its own.

There is also an artifact of the evolution of the U.S. electric grid that may also help the country survive an EMP attack, whether a result of solar storms or an angry North Korean dictator. Because there is no national grid, but three separate, loosely interconnected systems, an EMP event likely would lead to islanding and isolating the grids.

Indeed, inside the three major grids— the Eastern and the Western interconnections and the Electric Reliability Council of Texas—the interconnections are weak enough that islanding will also occur. For many policy experts who have worked on grid issues for years, eliminating islanding is a goal, because it defeats the concept of economic power dispatch. But Ben McConnell, a retired Oak Ridge National Laboratory scientist, told a Federal Energy Regulatory Commission meeting last year, “One of the best ways to protect the grid is to go into islanding mode.”

(See “The Electric Grid: A Civilization’s Achilles Heel?” in the January 2013 issue of POWER.) Ultimately, the federal government may be helping to develop a response to EMP. Researchers at the Department of Energy’s Idaho National Laboratory (INL) are working on ways to increase the resilience of the electric grid. In a briefing paper, INL scientists Craig Rieger and Ray Grosshans describe how they are working on “resilient control system technologies that adapt and transform in real time to both failures and attacks. Truly resilient systems intelligently route around broken system components to avoid cascading failures. Resilient systems draw on reserve resources to sustain life-safety systems. And resilient systems focus human attention on the problems machines either can’t or shouldn’t solve alone.

“The development of such technologies will underpin next-generation designs for critical infrastructure, including chemical plants, refineries, nuclear facilities and defense systems, the failure of which causes even greater risk than the loss of use.” ■

—Kennedy Maize is executive editor of MANAGING POWER and a POWER contributing editor.

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ENERGY STORAGE

Beacon Power Makes a Comeback Beacon Power Corp. was founded in 1997 to develop flywheel-based energy storage technology. By 2007, the 100-kW/25-kWh Gen 4 flywheel system was commercialized and deployed in several projects. However, market conditions pushed the company into bankruptcy in late 2011. The company has since emerged, reinvigorated with new investment and a new name: Beacon Power LLC.

By Dr. Robert Peltier, PE

F

undamentally, Independent System Operators (ISOs) are responsible for the continuous balancing of electricity supply and demand on their regional grids so that the grid frequency remains as close as possible to 60 Hz at all times. In the past, an ISO would send an automatic generation control (AGC) signal to utility generators to increase or decrease output to maintain the supply-demand balance. This process made maintaining grid frequency relatively straightforward.

However, integrating large amounts of intermittent and unpredictable renewable generation on the grid, particularly wind and solar, makes maintaining the supply-demand balance more difficult, particularly when the response of traditional electricity supply resources is relatively slow compared with the rapid see-saw output from a photovoltaic system on a partly cloudy day.

Researchers at Pacific Northwest National Laboratory studied the comparative value of the relatively slow response of AGC-controlled resources with fast-response flywheel-based regulation and reported their conclusions in a report: “Assessing the Value of Regulation Resources Based on Their Time Response Characteristics.” An important conclusion was that 1 MW of fast-response energy storage–based regulation has twice the system regulation value of average conventional regulation resources.

distribution level to reduce grid losses, eliminating the need for conventional regulation plants to use a portion of needed grid capacity for regulation. In addition to grid frequency regulation, once flywheels are fully charged, they can also be used as a temporary grid backup and may be suitable for “black start” service in certain applications.

Beacon Power Corp. was founded in 1997 to commercialize flywheel technology to address the rapidly developing fast-response frequency regulation market and went public in 2000. Its first flywheel systems, the first and second generations of the technology, were deployed in North America for telecommunications backup power applications. Since 2004, the company’s focus has been development of a system that could “recycle” electricity from the grid, absorbing it when demand dropped and injecting it when demand increased.

The first grid-connected Gen 3 (15 kW/4 kWh) was introduced in 2004, followed by the familiar Gen 4 (100 kW/25 kWh) model in 2006 that now has over 3 million operating hours in commercial service (see sidebar). During 2005–2006, Beacon Power participated in 100-kW demonstration projects (using multiple Gen 3 modules) in New York and California. ISO-NE also sponsored a very successful 3-MW pilot program during 2008–2010.

The culmination of a decade of product development and testing was the grid-connected 20-MW frequency regulation plant at Stephentown, N.Y., in 2011, owned and operated by Beacon Power (as is a 0.5-MW facility in Massachusetts). That made it the world’s largest commercial grid-scale flywheel facility when it went fully commercial in June 2011, supplying the NYISO market.

1. Power on tap. The Stephentown Plant consists of 200 100-kW modules that provide up to 20 MW for 15 minutes whenever required by NYISO. The plant has been in service for over two years, with overall plant reliability approaching 100%. Courtesy: Beacon Power LLC

Why Flywheel Energy Storage?

There are other important advantages to an ISO of using flywheel-based frequency regulation.

For example, the flywheel energy storage system allows the ISO to recapture a portion of the generation capacity that otherwise would have been allocated for frequency regulation.

Also, if the flywheel-based system is located so that it can inject regulating power on the transmission system, then transmission and transformation losses may be reduced, freeing up transmission line capacity in congested regions. A flywheel system can be sited so it can inject regulating power at the

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July 2013 POWER

www.powermag.com

53

ENERGY STORAGE The Stephentown Plant consists of 10 Gen 4 100-kW modules to produce each 1-MW unit. Twenty units are combined to form the plant’s 20-MW rated capacity (Figure 1). Electronic containers are installed for each group of 10 modules, and a cooling system is installed between two 1-MW units. Each unit is equipped with a transformer that increases the voltage

output from 480 V to 13.8 kV. A switchyard transformer increases the plant output voltage from 13.8 kV to the New York grid 115 kV transmission line voltage. Plant reliability remains above 99%, and reached 100% during the last quarter of 2012, with 4,000 effective full charge/discharge cycles per year in response to remotely dispatched NYISO signals.

The Stephentown Plant is a “first responder” to frequency deviations in NYISO, where— under a new tariff—resources are dispatched in order of fastest ramp rates. NYISO requires a ramp rate of 20 MW within 6 seconds, although the plant can respond faster, with no limits on degradation due to cycle, duty, depth of discharge, charging rate, ambient temperature, and so on. The plant’s NYISO “performance index”

How the Flywheel System Works Beacon’s flywheel is a mechanical battery designed for a minimum 20-year life, with virtually no maintenance required for the mechanical portion of the flywheel system over its lifetime. Of critical importance in performing frequency regulation with energy storage–based systems is their cyclic life capability.

Beacon’s experience to date in ISO New England shows that 6,000 or more effective full charge/discharge cycles per year are required. The system is capable of more than 100,000 full charge/discharge cycles at a constant full power charge/discharge rate, with zero degradation in energy storage capacity over time. For the frequency regulation application, flywheel mechanical efficiency is over 97%, and total system round-trip charge/discharge efficiency is 85%.

At the heart of Beacon’s Gen 4 flywheel is a high-strength carbon fiber composite rim, supported by a metal hub and shaft, with a motor/generator on the shaft. Together, the rim, hub, shaft, and motor/generator assembly form the rotor.

To nearly eliminate friction, the rotor is sealed in a strong vacuum chamber and levitated magnetically. Figures 2–4 show the assembly of a flywheel unit.

The rotor spins between 8,000 and 16,000 rpm. When absorbing energy, the flywheel’s motor acts like a load and draws power from the grid to accelerate the rotor to higher speed. When discharging, the motor switches into generator mode, and the inertial energy of the rotor drives the generator, creating electricity that is injected back into the grid as the rotor slows down. At 16,000 rpm, a single Gen 4 flywheel can deliver 25 kWh of extractable energy (100 kW for 15 minutes). Multiple flywheels are connected in parallel to provide any desired rating. The Stephentown Project, rated at 20 MW/5 MWh, consists of 200 Gen 4 modules.

54

2. Flywheel cutaway. The 100-kW Gen 4 flywheel uses a magnetic lift system to suspend the rotating mass within a vacuum to reduce friction. A motor-generator is used to spin up the rotating shaft when absorbing power but is used as a generator when injecting power into the grid. Courtesy: Beacon Power LLC

3. Rim install.

A composite rim is installed inside the vacuum chamber in the company’s manufacturing facility located outside Boston. Courtesy: Beacon Power LLC

4. Finish assembly. A worker completes installation of the motor-generator and other internals in a 100-kW Gen 4 flywheel module. Courtesy: Beacon Power LLC

www.powermag.com

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POWER July 2013

ENERGY STORAGE average is greater than 95% since inception— better than any competing technologies. In fact, the plant is capable of providing 35% of NYISO’s regulation requirements with only 10% of the market regulation capacity.

To build the Stephentown facility, in 2009, Beacon Power received a U.S. Department of Energy (DOE) $43 million loan guarantee (of which the company drew about $39 million). When Beacon Power Corp. filed for bankruptcy protection on Oct. 30, 2011, as part of the bankruptcy court proceedings, the company agreed, on Nov. 18, to sell its Stephentown facility to repay the DOE loan.

On Feb. 6, 2012, private equity firm Rockland Capital bought the plant and most of the company assets. It has since rehired most of the staff, renamed the company Beacon Power LLC, and funded construction of a second 20-MW plant in Hazle Township, Pa., that will provide frequency regulation services to PJM. That plant, configured like the Stephentown Plant, will place the first 4 MW into commercial service in September 2013 and the remainder by the second quarter of 2014.

Beacon Power Rebounds In late April, POWER discussed this remarkable turnaround with Beacon Power CEO

Barry Brits to explore the underlying cause of the bankruptcy and how the company expects to earn revenue and build a business.

Brits shared that in the past, the company struggled to earn revenue when there was no market tariff in place that placed a monetary value on regulation services, particularly fast-response regulation.

Today, tariff changes are in place in several ISO regions that will pay for regulation services. Other markets are developing, such as MISO and CAISO. Brits believes that Beacon Power is well situated to compete in those markets, particularly as the company’s cost/cycle is much lower than its primary competition, batteries. Brits expects the remaining ISO markets to follow suit in time and develop attractive tariff structures. With an established tariff, Beacon can build plants and earn a return on its investment. This is what Brits described as the company’s short-term plan, over the next year or so.

In the long term, the company will pursue global opportunities where fast-responding grid regulation services have a prescribed market value, particularly in islanding applications and in regions with high power prices and a high percentage of renewables.

Not surprisingly, Brits was in Germany exploring market opportunities when we made contact by phone.

Brits noted that the Stephentown plant has provided grid regulation services (called ancillary services in other regions) for two years, earning revenue 24/7 while maintaining high reliability of service. With new tariffs for these services now available, the uncertainty that made investors reluctant to provide financing in the past has been removed. Brits suggests that there is ample money available from energy private equity or from hedge funds to construct new projects without difficulty. The company’s new connection with Rockland Capital has also opened new networks for project financing, expected to be in the range of 50% to 60% debt-to-equity.

As a taxpayer, it was very good to hear that Beacon Power has committed to the repayment of at least 70% of the DOE loan, unlike other firms that have walked away from loan repayments. Beacon’s repayment commitment is a good sign that the company has a strong product and is investing in that product with a long-term perspective. ■

—Dr. Robert Peltier, PE is editor-in-chief of POWER.

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55

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY

Gas-Electric Integration “Swamps” All Other Issues Panelists at the ELECTRIC POWER 2013 Keynote and Roundtable Discussion in Chicago in May were consumed by the need to ensure future reliability by more closely integrating the gas and electricity markets. Acknowledged less directly were distortions created by renewable energy subsidies and mandates, onerous regulations affecting coal, and “irreversible” demand destruction caused by the success of energy efficiency and demand management programs. The elephant in the room was the continued demise of electricity markets.

By Jason Makansi, Pearl Street Inc.

T

en years ago, the observation that a $1/ MMBtu swing in natural gas prices would lead to a $4/MWh swing in electricity prices (in PJM in this case) would have been hailed as market volatility for merchant generators in robust electricity markets to capitalize on. Today, it’s a measure of unwanted instability in the reliable delivery of electricity to customers. What a difference a decade makes.

The broad solution for ironing out that instability is greater integration of gas and electricity markets, the theme that emerged from the State of the Industry Keynote talks, moderated

by David Wagman, POWER’s executive editor and the event’s content director, and the Industry Leaders Roundtable, titled “Reliability at What Cost and Who Pays?” moderated by Dr. Robert Peltier, editor-in-chief of POWER. Another integration issue—intermittent renewable energy—captured the attention of the panel and audience. And if integration was the word of the session, the dis-integration of coal-fired generation wasn’t ignored, nor was the destruction of electricity load demand.

Unlike past years, no one questioned the shale gas resource estimates (Figure 1), just the ability to get it to a power plant when needed. If the writing on the wall about the impact of the domestic shale gas bonanza was visible to these industry leaders before, in this session it glowed in neon against the darkened sky of high winds, a fading spark spread, little if any dark spread to support new coal, and continuing threats to a critical zero-carbon option, nuclear power.

The “market” doesn’t value capacity, was one refrain, and certainly not baseload capacity.

Another critical observation was that a just-in time (JIT) natural gas delivery system is clashing with the JIT electricity delivery system.

Overlay onto that clash “must take” highly intermittent wind- and solar-generated elec56

1. Gas glut grows. The domestic shale gas resource is “incredible,” though it is important to realize potential resources (shown in this slide) are called “unproven” resources. Courtesy: AEP

tricity, plus demand destruction through energy efficiency, plus demand side programs.

With all that volatility, today’s electricity business should be a free marketer’s dream.

But that was oh so 1990s.

Gas Prices Rising David Wagman teed up the keynote talks by noting that natural gas prices have “disadvantaged coal,” even Powder River Basin Coal (PRB) so cheap that rail transportation cost overwhelms its price. However, the “competitive advantage has swung back to coal in recent months,” Wagman cautioned, underscoring the need for flexibility. The industry expects 50,000 MW, a mini-boom, of gasfired plant construction through 2015.

Mark McCullough, executive VP, generation, American Electric Power (AEP), then expanded on the gas theme, noting that proven www.powermag.com

gas reserves have doubled in recent years, and potential reserves “are incredible.” The nation’s annual burn is 25 tcf, while the future resource is 2,700 tcf. McCullough described a ceiling of $4–$6/MMBtu for gas prices. However, it doesn’t take much movement in the gas price to change things up (Figure 2). “A $1/MMBtu move in [gas] price really affects dispatch,” he said. Then he posed the question: “How do you contract for fuel [in this environment]?”

AEP’s analyses show that gas will be 50% of PJM’s capacity in 2020, while 5,000 MW of coal will get retired. “With less coal generation, gas has to do much more.” One of McCullough’s fundamental points was that higher dispatch of gas plants doesn’t square very well with interruptible gas supply contracts. “Less than 20% of the gas plants in PJM are on firm gas supply.” He explained that the dayahead bidding system for electricity requires

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POWER July 2013

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY that plants also submit their nominations for gas supply. “Interruptible supply could get bumped from the queue,” he cautioned.

Gas power station owner/operators also have to adapt their thinking about their role in ensuring reliability, noting, as one example, that the North American Electric Reliability Corp. requires, among other things, a quarterly checklist concerning batteries. He then amplified the capacity-value conundrum. Wind and solar may be experiencing favorable pricing trends, but neither brings capacity to the grid, only energy. Other capacity must be there to support the renewable energy. Embedding these costs in the rate base puts more and more pressure on those “favorable” renewable energy prices.

McCullough posed the question: Are we in danger of becoming a “one-fuel industry?”

It’s somewhat of an unreal scenario. Even at 50% gas capacity, there is still fuel diversity in the grid. No one talked about a one-fuel industry when coal was 50% of the generation. But it’s the trajectory McCullough was referring to.

“Baseload coal and nuclear are threatened by their respective risk profiles,” he said, “we need to promote balance in the portfolio, and we need a discussion at the national level about this.”

Swamping Other Fuels Federal Energy Regulatory Commission (FERC) Commissioner Philip Moeller amplified the onefuel note, stating that gas is “swamping” other fuel options, for five reasons: ■ ■ ■

■

■

It’s easier to build and finance a gas plant.

It’s easier to add gas capacity near load than to build transmission.

Gas plant ramping is a solution to intermittent renewable energy. (He called the ramping in California that takes place many afternoons “amazing.”)

Coal faces a regulatory tsunami, with Mercury and Air Toxics Standards (MATS) at the center of it.

Gas prices appear to be relatively stable.

The last bullet point was especially notable given that only six years ago, gas prices registered as high as $14/MMBtu at peak times.

However, Moeller noted, shale reserves “didn’t even show up seven years ago, and technology will allow finding and extracting even more.”

The resource will still be there even if “society poses additional restrictions on it.”

FERC is taking gas-electric integration seriously, especially in light of a February 2011 outage in the Southwest when thousands lost gas and electric supply because of interdependencies. An official proceeding was opened on the subject and five planned technical workshops considered regional issues.

Moeller called the situation in New England “acute.” Electricity suppliers apparently are

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July 2013 POWER

bidding in without knowing whether they’re going to get gas. Aligning the gas and electricity trading days is important, he said.

Moeller acknowledged that efforts 10 years ago to align the trading days failed. Another challenge is the legal issues surrounding the two sides talking to each other during times of stress on the system, he conceded, referring to gaming the market to unfair advantage. The fact is, though, there isn’t a “90-day supply of coal sitting outside a gas plant.” He described the gas market as not particularly liquid and as more of a JIT delivery system.

The notion of JIT gas and electric is not quite accurate. The wholesale side of the gas industry has significant amounts of storage. However, it is mostly set up for seasonal, not daily, fluctuations.

The electricity industry also has around 2% of its capacity in pumped hydroelectric storage (PHS) and one compressed air energy storage plant, plus a smattering of small-scale storage demonstration devices that don’t register in terms of

capacity. PHS has demonstrated great flexibility in helping grid operators smooth out hourly and even several-minute fluctuations between electricity supply and demand. There are those who often state that the electricity industry has plenty of storage—it’s in the gas pipeline and storage system. But Moeller’s message was that it’s the business side that has to be aligned with electricity, not necessarily the physical.

Gas Swamp Examples McCullough and Moeller were then joined by four other industry leaders who offered prepared introductory remarks (Figure 3).

David Mohre, executive director, Energy & Power Division, National Rural Electric Cooperative Association (NRECA) noted that, of the 56,000 MW of cooperative utility capacity nationwide, only 26,000 MW is coal, or 46%.

Historically, that figure has been 80%. Since 2007, 15,000 MW of new capacity has been added, 75% of it natural gas. Mohre did ex-

2. Coal makes a comeback. In the span of one quarter, AEP’s coal-to-gas ratio changed significantly in coal’s favor, although the change was more dramatic in some AEP regions than in others. Source: AEP 1Q12

1Q13

100.0% 90.0% 78.3%

80.0%

69.7% 71.8%

70.0% 60.0% 50.0%

47.7%

52.4%

47.8%

47.8%

40.0% 30.3%

30.0%

22.1% 20.0%

15.0%

10.0% 0.0%

East coal

East gas

3. Popular industry roundtable.

East combined cycle Cycle

West coal

West gas

Participants in this year’s industry roundtable ad-

dressed a full house. Source: POWER

www.powermag.com

57

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY press reservations about gas supply and price volatility but said the problem was deliverability. The resource “looks robust.”

Mohre also observed that a $1 shift in gas prices moved the PJM market by $4/MWh. What happens to price if the country, as some have forecasted, starts to export up to 5 tcf annually? Bottom line, according to Mohre: The industry is not properly valuing longterm firm capacity, which is necessary to support power plant and pipeline construction.

Joe Nipper, senior VP, government relations, American Public Power Association (APPA), made the same point as Mohre but in a different way. APPA’s members represent 9% to 10% of the country’s generating capacity. The historical 70:30 split between coal and gas is now flipped. Nipper argued that gas-electric integration doesn’t necessarily require legislative changes, noting that the Senate Energy & Natural Resources Committee was holding hearings on the issue, but it does need changes from FERC. He called the storage piece for gas “critical.”

Enter Renewables Advocates After Nipper concluded, gas issues took a back seat to renewable energy during the roundtable. While Mohre noted that his member utilities own and operate substantial renewable energy facilities, the really vocal advocates were yet to come.

Michael Polsky, president & CEO of Invenergy LLC, took a decidedly contrarian tack, stating that “renewables are stable.” They may be subsidized and high cost, but they have to be judged fairly, which is to say “the electricity comes free in the long-term.” On that basis, he argued, even discounting the production tax credit (PTC)—he omitted the investment tax credit (ITC) and the renewable portfolio standards (RPS) imposed by the majority of states—wind energy still imposes the lowest cost on the system. As an example, he said Illinois ratepayers have saved $177 million because of renewable energy. “Recognize that renewables are here to stay,” he said.

In a sense, Ron Binz of Public Policy Consulting and former chair, Colorado Public Utilities Commission (PUC), split the difference between gas and renewables. The only panelist to claim that the primary industry driver will be carbon regulation, not gas prices, he called wind energy “a fuel hedge with probably no equal.” He also proposed that building a wind farm and a gas plant is better than building a wind plant alone. Colorado has 16% renewable energy, and its dominant utility, Xcel Energy, has become expert in balancing the system.

The Value of Long-Term Planning In a moment of irony, Polsky, who referenced his time at the University of Chicago—known 58

for its unwavering and unapologetic defense of free market principles—said it flat out: “The free market does not work for long-term planning; electricity is not an open market.” If you don’t have policy decisions, you gamble every day, he said. One could argue that the free market is risk-informed gambling.

It is also true, as Mohre pointed out, that just because the government mandates something, it doesn’t mean it will stick. Mohre cited the Fuel Use Act, passed in 1979 and repealed in 1987, which barred the burning of natural gas in power plants. In that context, and to illustrate the paradox of government policy, it is also worth mentioning that the Public Utilities Regulatory Policy Act (PURPA), passed in the same year, allowed natural gas firing for cogeneration, but because the requirement for thermal output was minimal, many gas-fired power plants came to be known as PURPA machines.

Many of the questions from Dr. Peltier and the audience had to do with long-term planning. Peltier asked about the utility business model, the strategy, for the next two decades.

McCullough again repeated that renewable energy doesn’t bring capacity, and so “how do we recover the cost of the capacity?” Technical advancement in storage is one route, he said, but he noted that AEP’s “experiments in home and community storage have not gone so well.”

Mohre also alluded to the discrepancy over renewable energy costs: “We [cooperatives] know a lot about the cost and operational issues with wind.” Later, Polsky tossed out the number $25/MWh as the typical cost for wind. Mohre shot back, “We know what wind costs, and it is not $25/MWh!” Polsky continued to bait the utility leaders, saying, “utilities fight everything, but it’s a losing game; they’re in denial.” Binz called the utility of the future an “orchestra conductor,” referring to the need to balance the variations of supply and demand. Utilities have always had to “conduct,” but Binz appeared to refer to the need to do this with ever-greater variations on shorter and shorter time scales. Binz also cited the need to “think beyond the five years of low natural gas pricing” and return to long-term gas supply contracting, while Mohre stressed the need to value long-term firm resources.

Innovation is often part of a long-term business strategy. Peltier noted the collapse of the venture capital market for cleantech, which he said dropped 54% last year. “What is the prospect for long-term return?” he asked.

Polsky insisted that the cleantech venture capital sector did not understand the industry.

“High tech is not like electricity,” he said. It takes much more capital to commercialize, and it’s difficult to scale to the needs of this industry. He and Binz agreed that utilities will likely innovate on the customer side of the meter. www.powermag.com

“Utilities are looking to get into the rooftop PV business,” Binz said. Moeller mentioned storage, but that FERC is limited by jurisdiction on what it can do with new technologies.

What Value Coal?

Most of the panelists addressed coal-fired resources indirectly by lumping them into the need for a balanced resource mix. But in response to a direct question from the audience, “What is the ongoing model for coal to stay in the business?” Polsky said coal “faces extinction.” Binz referred to “cap and innovate,” implying that capping carbon dioxide emissions will force innovation in carbon capture and storage (CCS), which he said “is key” to coal’s future. McCullough, based on AEP’s direct experience with CCS demonstration, agreed with Binz but added the caveat, “at what cost?” The parasitic load for a 1,300-MW unit with CCS is 300 MW. Polsky countered that coal with CCS will not be the low-cost option.

Mohre offered the issue that everyone was happy to ignore. McCullough noted that the coal industry is exporting lots of coal, making up for lower consumption in the U.S. Mohre later asked, “How right is it to ship 100 million tons of coal and burn it in other countries?” That lower consumption is occurring because, stressed McCullough, 60 to 70 GW of coal will be retired because of MATS. Much of that coal capacity, he added, is providing ancillary services, in part to address renewable energy integration.

The Real Enemy?

It’s always easy to skewer the option that isn’t represented at the table. Rooftop photovoltaics (PV) certainly took some hits. At the top, Wagman noted that “DG [distributed generation] and microgrids are disrupting the industry,” while Peltier referenced one utility CEO who said that companies installing solar panels are going directly to the customers and another utility CEO who considers this a threat to the utility business model. Polsky advised, “utilities should deal with the real threat, which is rooftop PV.” “CHP [combined heat and power] and rooftop PV will grow significantly,” Binz echoed, adding that utilities need to be compensated and share in the rooftop PV revenues. Moeller called the $30,000 solar tax credit to install rooftop PV “poor ratepayers subsidizing affluent ratepayers.”

Polsky called the solar tax credit “unfair.”

For a CEO of a company developing wind farms with a $23/MWh PTC (along with ITCs), that was an interesting characterization, to say the least. Binz added that the wind PTC is roughly equivalent to a carbon value of $30/ton. No one ventured an estimate of the value of a state-level RPS to a wind farm developer.

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POWER July 2013

ELECTRIC POWER 2013: Flexibility and Adaptability 4. Load loss continues. Industrial load growth has declined for three quarters in a row in AEP’s service territory. Source: AEP Primary metal manufacturing Mining (except oil and gas)

Chemical manufacturing Paper manufacturing

Petroleum and coal products manufacturing

2,000 1,800 1,600 1,400

GWh

1,200 1,000 800 600 400 200 0 Mar-06

Mar-07

Mar-08

Mar-09

Rooftop PV is only one component of the real enemy of the utility business model going forward, which is weak electricity demand. McCullough showed graphs of dropping industrial load in AEP’s considerable service territories (Figure 4). On the bright side, he also acknowledged that shale gas processing and delivery needs electricity to run pumps, compressors, and other machinery. He said load is probably not going to grow substantially because of demand side technologies and behaviors. “Energy efficiency is real.”

How real was underscored by other panelists. A 1% rise in gross domestic product used to lead to a 1.6% rise in electricity demand, he said. Today, the associated demand figure is 0.3%. Light bulb replacements and appliance efficiency standards, to name two factors, have reduced cooperative utility load.

Nipper also stressed the importance of “utility-customer partnerships” in implementing energy efficiency improvements.

Lots of projections show demand going down, echoed Moeller, so customer relationships with utilities will be very different. In this context, Polsky was more conciliatory: Customers still need the utility as a backup.

Binz gave the example of a state-of-theart refrigerator that uses less electricity than a 75-watt light bulb! “Ten years ago, the same refrigerator would have consumed four to five times that wattage.” But efficient appliances are only part of the story. Binz observed that no panelist had yet used the phrase “smart grid,” adding that the smart grid is a digital mesh that will provide services in the back-

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July 2013 POWER

Mar-10

Mar-11

Mar-12

Mar-13

of load is “irreversible,” he concluded.

“Lowest cost is not necessarily the solution,” Polsky said. An option selected may not be the least cost today but will be over time.

One audience member said, “Diversity comes from long-term resource planning.”

Then he asked, “Do we need to re-introduce long-term strategic planning, central planning, for public infrastructure?” In different ways, the panelists answered yes, even if they undoubtedly had different ideas of the percentage of each resource that would constitute “diversity.”

In closing, think about this. Global petrochemical and manufacturing companies are making decisions whether to invest in multibillion-dollar facilities to take advantage of domestic shale gas. The investment horizon is similar to that of a power plant. They will have to contract for raw materials for the front end and compete on price for their products. They will have to meet as many, if not more, environmental and product quality and safety regulations. There will not be a regulated rate of return on that investment.

Nor will there be a PTC, ITC, RPS, carveout, or other subsidy. ■

ground. He noted that in the UK, the standard “rate of return” is no longer the benchmark —Jason Makansi (jmakansi@ pearlstreetfor setting electricity rates. “PUCs need to inc.com) is president of Pearl Street Inc., a abt. power 13:Layout 5/31/13 3:56 PM Pagedeployment 1 incorporate morefeb concepts of risk.”1This loss technology services firm.

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ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY

Is Gas Getting Too Hot to Handle?

With ever-increasing demands for fast ramping and flexibility, natural gas–fired plants are grabbing a bigger share of the generation pie. But uncertainty about future prices and concerns about overreliance on a single fuel are dampening enthusiasm during what may be the most exciting time for gas ever. Natural gas is hot—but will generators and the market get burned?

By Thomas Overton

I

n a series of standing-room-only sessions in Track 2: Gas Turbine/Combined Cycle Power Plants at ELECTRIC POWER 2013, an array of speakers from generating companies, manufacturers, and service providers reported on best operation and maintenance practices and new options in gas-fired power generation, particularly cycling existing plants and building distributed and combined heat and power plants (Figure 1).

1. Full house. Attendees in the gas track learned about meeting the challenges of the gas market. Source: POWER

The Challenges of Frequent Cycling With the rapidly expanding role of wind in the generation mix, the ability to ramp up and down quickly is a gas-fired plant’s biggest advantage. Rapid cycling, however, can come with hidden costs, explained Douglas Hilleman of Intertek. Too often, plant owners make assumptions about these costs without drilling down into the details, even though small changes can reap big returns in more profitable operations. Not knowing the true costs of cycling operations can leave a substantial amount of money on the table. “It’s not just fuel,” Hilleman said, “it’s the latent costs.”

Hilleman reported on Intertek’s cycling analysis for Xcel Energy’s peaking plant in Riverside, California. A full understanding of cycling costs allowed Xcel to tailor its dispatch plans to the true costs, and do it without capital investments or hardware modifications. While a comprehensive analysis of cycling operations can be costly, the returns are big enough that it can pay for itself in a few months. In the case of the Riverside plant, simply reducing the ramp rate by 33% saved thousands of dollars in maintenance costs.

When a plant owner needs to shift gears in a changing market, careful analysis is key, reported Brian Eskra of Power Engineers Collaborative. Eskra described a study performed for a client in Southern California that needed to retire its steam electric plants and replace them with combined cycle plants in order to meet the demands of the CAISO market and changing 60

regulations in the state. Recognizing that intermediate and peaking generation offered the best market niche was only the start, Eskra said. Analysis of the various options, market demands, and the returns on investment led to development of a 3 x 1 block configuration utilizing Mitsubishi Heavy Industries D/E class turbines.

Scott Polemus of LTSA Options described ways that plant owners can optimize their long-term service agreements (LTSAs). The market has changed in the past few years, and it’s worth reevaluating and renegotiating existing LTSAs for cost savings and/or increased benefits. Owners can restructure agreements to provide for more cost and risk sharing, Polemus explained. With the growing role of and demands on gas-fired plants, it’s time to determine if an LTSA is still serving a plant’s needs.

Even when a plant is optimized for its market, however, there’s no guarantee it’s going to stay that way: Wear and tear from www.powermag.com

frequent cycling and ramping, along with changes in weather and fuel properties, can reduce a plant’s operating windows. That’s why regular tuning is important, explained Donald Gauthier, senior technical lead for Power Systems Manufacturing (PSM).

These kinds of changes will increase turbine dynamics, and running with high dynamics can be very expensive, whether the costs result from lean blowouts (LBOs) or accelerated equipment wear.

While manual tuning will work, automated tuning systems are preferable because of faster response and reduced maintenance.

PSM’s AutoTune system offers one solution for 7FA units. AutoTune automatically manages combustion dynamics to reduce the risk of LBO and improve emission control, while maximizing power output.

In combined cycle plants, however, proper tuning extends beyond the turbine.

Rapid cycling also places demands on the heat recovery steam generator (HRSG), ex-

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POWER July 2013

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY plained Tony Thompson, chief technology officer for Vogt Power International—even when the HRSG is carefully designed for it. Operating profitably and efficiently under such conditions requires the ability to monitor the impact on HRSG component integrity and knowing whether replacement or repair is most cost-effective. Vogt offers an online monitoring system that records and analyzes operational data to calculate life cycles for critical components.

Small Power: When Size Matters The fall in natural gas prices has renewed interest in distributed generation (DG) and combined heat and power (CHP) resources.

Small turbines are ideal for these applications because of their flexibility, efficiency, and low maintenance requirements, Uwe Schmiemann, marketing manager for Solar Turbines, told attendees.

The need for small, decentralized power plants is likely to rise as the growth in renewable generation continues to outstrip transmission capabilities, Schmiemann said. Their rapid start and agile load-following capabilities, as well as the ability to operate with little or no on-site manpower, can efficiently manage localized grid fluc-

tuations resulting from increased amounts of behind-the-meter renewables.

DG and CHP also showed their value last year during Hurricane Sandy, when facilities with their own generation were able to keep the lights and heat on when the grid went down and surrounding areas were without power for weeks. In addition, Schmiemann noted, the shift to small gas turbines from older fuel oil systems offers substantial emissions benefits for institutions such as universities and hospitals that have long generated their own power.

CHP is also growing in usage in industry as lower gas prices offer economic benefits over grid power, as well as a reduction in emissions. As an example, Schmiemann described a facility that was able to cut its overall CO2 emissions by 60,000 tons by installing a 15-MW CHP system.

Daniel Loero of GE Aero Energy described DG and CHP applications for GE’s venerable LM series turbines. More than 2,000 are in service worldwide. Loero told attendees about a new plant at a wind farm in Kansas that uses three LM units to support 1.2 GW of wind generation. The turbines are able to even out the wind farm’s output and compensate for short-term fluctuations.

Where very rapid response with high efficiency is necessary, gas-fired engines can be ideal, said Mark Harrer, business development manager for Wärtsilä North America. The key advantage of multi-engine plants is that generation output can be adjusted by turning individual engines on and off as needed rather than ramping the plant as a whole up and down. This allows each engine to operate at peak efficiency even when the plant is generating only a portion of its total capacity, Harrer said.

Wärtsilä’s newest engines have simple cycle efficiencies greater than 46%. In addition, they can maintain stable output across wider ranges of ambient temperatures and altitudes than gas turbines. The engines can reach full power in 5 minutes, shut down, and be back at full power 10 minutes later.

This offers another benefit, Harrer explained. In competitive markets, the ability to respond rapidly to price spikes can be very lucrative. In one example he showed, the ability to respond immediately to a $3,000/MWh price spike returned $895,000 in revenue. ■

—Thomas W. Overton, JD is POWER’s gas technology editor.

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61

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY

What Does the Market Expect from Gas Plants?

With the country awash in natural gas and new construction dominated by gas-fired plants, one would think that integrating these plants into the grid would be simple. Like politics, integration problems appear to be local.

By Thomas Overton

I

n a world of conflicting priorities, uncertain demand, and uncertain fuel price trajectories, what does the electric power market need from gas-fired power?

In a word: Everything.

That was the message from a panel of industry representatives assembled to discuss the future of natural gas plants at ELECTRIC POWER 2013 in Chicago.

Dr. Paul M. Sotkiewicz, chief economist, markets, for PJM, began by telling attendees, “Our objective is to maintain reliability and operate fair and efficient nondiscriminatory markets.” Nevertheless, while PJM is fuel-neutral, he noted that the ISO is facing 20 GW of impending coal retirements by 2016—about 10% of installed capacity—most of which is likely to be replaced with gas-fired power.

Competitive markets value efficiency, he said: the more efficiently you can run, the more money you will make. That provides an incentive for building newer, more efficient combined cycle plants.

The market also places a premium on operational flexibility and reliability.

“The quicker you can move, the more accurately you can follow dispatch signals,” the more profitable you will be. “The market will reward those resources that can do this,” he said.

The newest gas-fired plants are capable of responding more quickly than older assets. “That makes gas very competitive,” he noted.

Gas-electric coordination is not the pressing issue in PJM that it is elsewhere, he said, in part because of the substantial existing gas infrastructure. It is important in winter, though, because of the increased domestic demand.

Still, Sotkiewicz argued that it’s not hard to ensure you have the gas you need with responsible planning. “It’s just a matter of being willing to pay the price for it.”

62

1. A wide range of needs. Panel members for the “What Does the Market Expect from Gas Plants?” session, left to right: Sheryl Torrey, NV Energy; Mark Harrer, Wärtsilä; David Frederick, FirstEnergy; Paul Sotkiewicz, PJM; and Clyde Loutan, CAISO. Source: POWER

Environmental Issues Are Also Important With increasing attention to emissions, the market is demanding assets that can meet regulations efficiently. Modern combined cycle plants have substantial advantages over fossil-fuel plants. “It’s a no-brainer,” he said.

Sheryl Torrey, director of trading analytics and operations for NV Energy, reviewed the laundry list of demands on the typical gas plant: optionality, flexibility, efficiency, cycling, load following, and reduced outages (Figure 1). And of course all of it, she said, needs to be delivered at low costs.

David A. Frederick, manager of fuel procurement for FirstEnergy, noted that the massive influx of shale gas from the Marcellus shale play has changed the economics of gas-fired power in the PJM region. Consequently, coal generation has fallen 33% since 2008, while gas generation has grown 173%. Both trends are ahead of national changes, substantially so for gas. www.powermag.com

The result has been to markedly flatten the supply curve in PJM. While the $50/MWh point in 2008 was at 112,000 MWh, in 2012, it had stretched out to 162,000 MWh. “We aren’t spending as much money for reliability,” he said.

And though PJM is facing a large number of coal plant retirements, the new capacity being proposed should be enough to replace it, particularly since PJM is arguably oversupplied at the moment, with baseload capacity currently at 90% of load, leaving peak units in excess. The expected retirements will leave about 5% of the load for peaking units.

Consequently, despite the influx of cheap Marcellus gas, “It’s going to be hard for merchant players to enter the market,” at least in the short term. The current economics will struggle to support new plant construction.

The situation for gas power in California, however, is quite different, reported Clyde Loutan, senior advisor for renewable energy integration for California ISO. The large amount of renewable

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POWER July 2013

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY 2. Wide swings in demand with renewables. By 2020, added renewable resources will create enormous demand for fast-ramping generation in CAISO. Source: CAISO Net load

Wind

Solar 10,000

6,300 MW in 2 hours

8,000 MW in 2 hours

13,500 MW in 2 hours

9,000 8,000 7,000 6,000 5,000 4,000 3,000

Wind & solar (MW)

Load & net load (MW)

Load 46,000 44,000 42,000 40,000 38,000 36,000 34,000 32,000 30,000 28,000 26,000 24,000 22,000 20,000

2,000 1,000 0

0:00

1:30

3:00

4:30

6:00

7:30

9:00

10:30 12:00 13:30 15:00 16:30 18:00 19:30 21:00 22:30

0:00

Net load = load–wind–solar

generation, especially solar, is creating the potential for large swings in demand throughout the day.

He showed the session a slide illustrating projections for 2020 that suggested swings

of up to 13,500 MW were possible as solar capacity comes on and off the grid during the day (Figure 2). Combined with traditional less-flexible resources, the region may be facing potential over-generation conditions. All

this means a strong demand for fast-ramping capacity and frequency response.

Asked what might be necessary to better incentivize construction of fast, flexible gas plants, the panelists had varying answers.

Sotkiewicz said, bluntly, “Nothing, other than the gas-electric coordination issue.” A system the size of PJM, he said, has enough diversity and market incentives in place. But size does matter, he noted, since larger regions have better ability to balance loads.

The lurking problem is coordinating gas supplies. Right now, Sotkiewicz said, “each interstate pipeline acts as its own ISO.” For areas of western Pennsylvania and eastern Ohio, said Frederick, “It’s more of an issue of how do we get all of that gas out of the area, because we have more than we need.”

The panelists also noted that, no matter what is generating the power, the transmission assets need to be in place to move it. There, plenty of challenges remain.

As Sotkiewicz noted, “Wouldn’t it be nice if we had something like FERC for transmission like we have with pipelines?” ■

—Thomas W. Overton, JD is POWER’s gas technology editor.

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July 2013 POWER

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63

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY

The Beguiling Promise of the HTGR It’s easy to see why technologists fall in love with high-temperature gas-cooled reactors (HTGRs). These nuclear machines are remarkable inventions, at least on paper. But few have actually seen the real world for any length of time, and their real-world experience has been mixed.

By Kennedy Maize

T

he claims of high-temperature gascooled reactor (HTGR) advocates are impressive and persuasive. They say the reactors are versatile, scalable, and largely goof-proof. Because of their high temperatures, HTGRs are ideally suited for double duty in industrial cogeneration applications, which is why chemical companies and other users of process steam pine for their development. They don’t use water as coolant, nuclear moderator, or in managing spent fuel. They are even better than conventional light-water reactors (LWRs) in displacing carbon dioxide, as they can not only generate electricity but also back out industrial use of oil and natural gas burned to raise either low- or high-pressure steam. They can easily follow load.

The nuclear buzz of late has been all about small modular reactors, which are aiming for development in the next 10 years or so—the mPower, NuScale, and Westinghouse machines. These are aimed at supplementing the big Gen III machines such as the 1,000-MW Westinghouse AP1000s now under construction in Georgia and South Carolina. But the next, next generation of nuclear plant could be the HTGR, aimed at the 2030s timeframe.

That’s the heart of the case that two representatives from the Next Generation Nuclear Plant Ltd. (NGNP) Industry Alliance—Entergy’s John Mahoney and Fred Moore, a consultant who has retired from chemical giant Dow—made in the ELECTRIC POWER 2013 nuclear track in Chicago in May. The partnership (www.ngnpalliance.org) consists of a host of companies interested in the promise of the HTGR, including, among others in addition to Entergy and Dow, Areva, Westinghouse, ConocoPhillips, and SGL Group.

The current conceptual design is for a reactor that produces 625 MWth (300 MWe) of energy, which Moore noted is about the same size as today’s gas-fired combined cycle generators. The core outlet temperature of the helium coolant to a steam generator is 750C, compared with 300C for a conventional LWR. The reactor core is Areva’s Antares prismatic block concept, which consists of TRISO (tristructural-isotropic) fuel spheres 64

1. Another nuclear option. The HTGR nuclear heat supply system (NHSS) comprises three major components: a helium-cooled nuclear reactor, a heat transport system, and a cross vessel that routes the helium between the reactor and the heat transport system. The NHSS supplies energy in the form of steam and/or high-temperature fluid that can be used for the generation of high-efficiency electricity and to support a wide range of industrial processes.

Source: NGNP Industry Alliance

packed into tubes that are then assembled into hexagonal fuel blocks (Figure 1).

The design, Mahoney and Moore emphasized, minimizes the need for developing advanced materials and is based on current fuel programs. Each tiny fuel particle is strong, fully encapsulated, and constitutes its own containment, able to withstand pressures of 1,000 atmospheres.

The safety features begin with the fact that the reactor has a strong negative void coefficient of reactivity, according to its advocates. If the reactor loses coolant, the reaction shuts down.

The core has low power density, a safety plus.

The helium is gaseous under all reactor conditions and is both chemically and radioactively inert. In a loss-of-coolant accident, there is no need for operators to shut down the machine; it shuts itself off. There is no requirement for backup power. Spent fuel doesn’t require cooling pools before it can go into above-ground, dry storage. HTGRs, according to its promoters, are beyond passive; they are essentially inert under accident conditions.

What’s needed to deploy these elegant machines? Some materials research remains, www.powermag.com

which is under way at the Department of Energy’s Idaho National Laboratory (INL). INL notes that while graphite has been used in past research and commercial HTGRs, “historical ‘nuclear’ grades no long exist. New grades must be fabricated, characterized, and irradiated to demonstrate acceptable nonirradiated and irradiated properties.”

This leads to a regulatory challenge.

HTGRs are so different from conventional nuclear reactors that they will have to undergo a ground-up review at the U.S. Nuclear Regulatory Commission. Mahoney and Moore note that one commercial HTGR operated in the U.S., the Fort St. Vrain plant in Colorado, from 1976 to 1989. The Atomic Energy Commission (and later the NRC) allowed it to operate under an exception to its licensing rules, and the plant experienced serious operational problems. Convincing the regulators to licensing a new HTGR will be smackdab on the critical path to deployment. ■

—Kennedy Maize is executive editor of MANAGING POWER and a POWER contributing editor.

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POWER July 2013

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY

Wind Resources Face Market and Policy Headwinds Natural gas prices and low wholesale electricity prices are creating headwinds for large-scale renewable projects such as wind.

By David Wagman

A

combination of relatively low natural gas prices and efforts to roll back or end renewable portfolio standards (RPS) in several states is placing pressure on renewable energy in the U.S. At the same time, however, developers remain mindful of the need to begin construction this year on large-scale wind power projects to take advantage of a production tax credit (PTC) extension approved by Congress earlier this year.

Those were key themes discussed during a session at ELECTRIC POWER 2013 on market forces impacting renewable energy finance and development. Much of the discussion focused on large-scale wind projects.

With the PTC extension in place, MidAmerican Energy Co. said in early May that it plans to add up to 1,050 MW of wind generation capacity in Iowa, representing as many as 656 wind turbines, by the end of 2015. The proposed new capacity needs state regulatory approval. MidAmerican estimated that by January 2016 it may be able to generate almost 40% of its January retail output from wind, including the proposed additions.

“Capturing the PTC is important,” said David Streicker, an attorney with Polsinelli Shugart and conference session moderator. He said it is unlikely for wind projects not under construction by the end of the year to move forward since PTC eligibility is linked to construction. He said that last year, more than 13 GW of wind capacity was brought online, representing a capital investment of $25 billion. A report in mid-May from SNL Energy said that around 8 GW of new capacity was brought online in the fourth quarter alone. By contrast, SNL said the first-quarter 2013 wind capacity addition was the wind industry’s worst since 2006. Around 384 MW of capacity was installed, down from more than 1,900 MW in the same quarter a year ago.

Boom-Bust Industry The boom-and-bust nature of the wind industry helps illustrate the important role played by the PTC and the industry’s continuing vulnerability to changes in public policy such as renewable portfolio standards, the ELECTRIC POWER audience was told.

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July 2013 POWER

Source: NREL, Warren Gretz

“The Achilles heel of RPS is that it’s a mandate,” said Mark Pruitt, principal with the Illinois Community Choice Aggregation Network and former director of the Illinois Power Agency. “It is always going to be tenuous to count on an RPS.” Bill Smith, executive director of MISO States, said regional operating rules allow negative market prices as a way to signal generators to cut production. Smith said it’s difficult, however, for a baseload nuclear power plant to cut its output in the face of negative pricing. In those instances, nuclear operators pay “because they can’t shut.” Wind generators, by contrast, can still afford to pay negative prices and remain connected to the grid as long as the payment they make is less than what they earn through PTC payments.

Pruitt said challenges to state RPS policies stem in part from the fact that lower natural gas prices and reduced electricity demand have hit wholesale electric power prices and kept them low. This in turn has widened the gap between market prices and the cost of renewable energy, rendering long-term power purchase agreements economically unattractive in some instances. At the same time, questions are arising over renewwww.powermag.com

able energy’s ability to fill gaps left by retiring fossil-fueled generating units, particularly given how flexible and relatively low cost natural gas– fired generation can be.

“What’s best, low carbon or no carbon?”

Pruitt asked, saying that renewable energy sources’ intermittency adds to that evaluation.

In its favor, wind energy can act as a price hedge against natural gas because the renewable resource has a zero fuel cost over its lifetime.

Pruitt outlined four ways that RPSs can be modified to protect them from challenge.

First, standards can promote uniform and marketwide participation with a common set of rules. Second, they can promote cost-based competition. Third, RPS standards can adopt a “big tent” approach and eliminate set-asides that benefit specific technologies. And fourth, RPS designs can be designed better. He cited the current Illinois RPS as being so complex it could bankrupt some companies and said the standard is “divorced from the reality of the market.” He said the Iowa RPS, by contrast, is more successful because it is less complicated and sets more readily achievable goals. ■

—David Wagman is POWER’s executive editor.

65

ELECTRIC POWER 2013: FLEXIBILITY AND ADAPTABILITY

Fighting Transformer Fires Transformer fires are fearsome events, perhaps the most dangerous common threats to human life—both onsite and beyond the boundaries of a power plant—that can hit an electric utility.

By Kennedy Maize

F

ire in an electric station is a destructive, demoralizing, disastrous event under most circumstances. Transformers fires—whether at large equipment in major switchgear centers or at smaller distribution centers that serve homes and businesses— are particularly fearsome. They involve fire, explosion, high-voltage electrical arcs, oil ignition and dispersion, and potential injuries or death to community firefighters who may not have a clue how to deal with a fire in electrical switchgear. Transformers fires aren’t on the scale of the Fukushima nuclear power catastrophe that struck Japan in March 2011, but they are much more likely and frequent. They are the nightmares of electrical system operators.

So when lightning strikes (peeling the high-voltage transformer open like a can of sardines) and hits your grid, or transformer insulation fails, or a kid with a high-powered rifle and a penchant for mischief shoots into a transformer, who do you call? Try Anthony Natale.

Natale, who gave a gripping presentation at ELECTRIC POWER 2013 in Chicago this May, may be the world’s expert in fighting transformer fires. He’s New York City’s doyen of transformer fires, as a key employee in Consolidated Edison’s emergency management response group and a professor at the Fire Department of New York’s (FDNY) Fire Academy, where he has changed the FDNY approach to fighting transformers fires.

Natale, a short, stocky Italian-American who talks with his hands as much as his voice, is the claxon of caution to fire departments that are summoned by fire alarms and citizens to transformer fires. He’s so energetic he could probably be hooked into the grid. And he can intimidate the brashest of firefighters into caution in the face of electrical fires (Figure 1).

Making New Rules Natale and his coworkers have established iron-clad rules that FDNY must follow when called to a fire at an electric transmission or distribution substation or even a transformer fire on a local distribution pole. These 66

1. Powerful personality. Consolidated Edison’s Anthony Natale showed several videos to describe his unique expertise: putting out transformer fires. Source: POWER

are specialized fires. The utility workers, far more than the firefighters who arrive in trucks with lights spinning and sirens squealing, understand the intricate dangers. Lives, far more than millions of dollars of on- and off-site damages, are at stake.

Some of the lessons firefighters must heed are surprisingly simple to those who understand electric generation and distribution. Wires, which may be on the ground in a substation, are not insulated, unlike the wires from a lamp or to a TV in the home. They are energized and can kill, and firefighters need to understand that threat.

Other threats are more substantial. Transformers contain copious amounts of oil, used as insulation. The oil can ignite at 300F. Transformers can not only ignite but, as Natale showed in a series of YouTube videos (frequently shot by clueless amateurs), they can explode.

Most firefighters are aggressive when it comes to fighting fires, noted Natale. They want to go toward the blaze and attack it.

But the key to fighting transformer fires is to curb this tendency, as the utility knows the hazards of electrical fires—including energized systems, the threat of arcing voltage, and the potential of explosive oil www.powermag.com

fires—far better than firefighters arriving on the scene.

ConEd and FDNY have developed a series of operating conventions to ensure that the utility takes control of the fire scene in a transformer fire. Among the most important is an unconditional “STOP” sign at the utility gate. It’s crucial, Natale said, that off-site firefighters don’t bull their way into the fire scene and get themselves and others into trouble.

A utility worker—a “white hatted” utility incident commander—will meet the fire department crew at the gate, Natale said, to talk about a plan for fighting the fire and marshaling people and equipment. Inside the gate is a lock box for the FDNY responders to use. It contains a book that includes a site map, overhead photos of the site, information about the distribution of PCBs on the site, and the location of important equipment, including water sources, pumps, and the like. This information, along with the utility incident commander, provide the guidance for fighting what are often the most difficult and dangerous fires that can strike an electric utility system. ■

—Kennedy Maize is executive editor of MANAGING POWER and a POWER contributing editor.

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POWER July 2013

NUCLEAR POWER

Too Dumb to Meter, Epilogue As the book title Too Dumb to Meter: Follies, Fiascoes, Dead Ends, and Duds on the U.S. Road to Atomic Energy implies, nuclear power has traveled a rough road. For the conclusion of POWER’s exclusive serialization of the book, we offer the “Epilogue: Some Dumb Ideas Never Die.” The first 12 installments are available in the POWER online archives.

By Kennedy Maize

T

he Manhattan Project was a marvelous engineering success, but only on a limited front. It successfully captured the power of the atom for the purpose of war and mass destruction. Its success blinded postwar policymakers in the midtwentieth century, who came to believe that big science melded to big government was the path to scientific progress.

The Manhattan Project proved to be a false god. As this book argues, the big-science approach to public science and engineering— the very model of what has come to be known as industrial policy and mimicked around the world—led to feckless, wasteful, needless dead-ends. We poured our wealth into bombers that could never fly, construction projects that could never work, mining and stockpiling fuel that we didn’t need, technologies that never delivered, and waste disposal projects that gave unintended demonstrations of the meaning of the word “waste.” Around it all, we developed an administrative and bureaucratic edifice that distorted our politics and misled our leaders and our people.

The folks who brought us these follies and failures weren’t malefactors by any sensible definition (including the popular villain Edward Teller). With good motives, exceptional educations, broad experience, and true public spirit, they were mostly brilliant. But they were often blinded by their success and pride in their accomplishments. On top of that, there was a pervasive attitude that money didn’t matter in the pursuit of atomic energy.

British Energy minister Charles Hendry, in late 2011, summarized things well. Speaking to Britain’s Royal Society, he said that in the postwar period, government energy agencies operated “like an expense account dinner: everybody ordering the most expensive items on the menu, because someone else was paying the bill.”

While we should laud the virtues and many of the fruits of the labor of the leaders of the past, we should also see clearly where they failed and, as best we can discern, why.

Economist Lawrence Summers, adviser

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July 2013 POWER

to Democrats from Carter to Obama, said recently, in the context of the Obama administration’s failed investment in a dodgy solar energy project, that the government is a “crappy venture capitalist.” That has been true for a very long time.

The spirit, concepts, and hubris flowing from the Manhattan Project have remained with us up to today. Hardly a month has passed without figures in policy and political circles proclaiming loudly, with nary a hint of doubt, that what America or the world needs is a new Manhattan Project to revitalize the economy, save the environment, or stretch our reach into outer space.

That’s just what we don’t need, but some dumb ideas never die.

Fly It In 2008, a collaboration among the UK aerospace industry, two British universities, and the British government—known as the Omega Project—floated the idea of resurrecting nuclear-powered airplanes.

The need for flying nukes, explained Ian Poll, a professor of aerospace engineering at Cranfield University, flows from the specter of man-made global warming. In a 2008 interview with the Times of London, Poll, a distinguished engineer for many years, said, “We need a design which is not kerosenepowered, and I think nuclear-powered aeroplanes are the answer beyond 2050. The idea was proved fifty years ago, but I accept it would take about thirty years to persuade the public of the need to fly on them.”

Poll’s grasp of history may have been a bit uncertain, given that the idea was never proved, but his vision of the future was firm, if familiar. In his formulation, the atomic airplane—not a bomber this time, since the Cold War ended some twenty years ago, but a passenger vessel—would fly nonstop from London to Sidney or Auckland. There would be zero pollution—under an unstated assumption of no uncontrolled radioactivity.

What about shielding the crew and passengers from the local radiation of the enwww.powermag.com

gines? Not a big deal, Poll told the Times.

“It’s done on nuclear submarines and could be achieved on aircraft by locating the reactors with the engines out on the wings. The risk of reactors cracking open in a crash could be reduced by jettisoning them before impact and bringing them down with parachutes.” Poll called for a large, government-funded program to develop the new generation of atomic-powered flight.

Poll’s A-plane would have to be large, at least twice the size of a Boeing 747 by several estimates. It would require new airports with new landing strips, and docking stations miles from existing terminals. The trip from the plane to the terminal would seem interminable to many passengers after a long flight.

Because of the local radiation, pilots could only fly for a limited time before exceeding radiation limits. Frequently fliers might also have to limit their flights on the A-planes to avoid exceeding radiation limits. Nuclear passenger planes, says Theodore Rockwell, a veteran radiation expert at the Oak Ridge National Laboratory, are “not good for anybody.”

One of the most remarkable aspects of Professor Poll’s paranormal vision is that it took place years after Arab terrorists crashed two conventional jet passenger planes into the World Trade Center in New York, demolishing them. In a 2008 article in Scientific American, David Lochbaum, a nuclear engineer at the U.S.-based Union of Concerned Scientists, scratched his head and said, “We’ve been worried since 9/11 about how to protect against bad guys hijacking an aircraft and crashing it into a nuclear power plant upwind of a heavily-populated area. Let’s now put the nuclear reactor in the plane itself, so they can target cities without a nuclear plant upwind?”

Lochbaum called Poll’s idea “a Christmas present for the terrorists of the world.”

Fortunately, Poll’s attempt to revive atomic flight has failed—at least for the time being. The aptly named Omega Project had UK government funding from 2007 to 67

NUCLEAR POWER 2009, with a mission of looking at the environmental implications of commercial aviation (Poll posed the notion of atomic flight on his own) and organized by Manchester Metropolitan University. After a series of worthy academic tomes, none of which appear to have had any discernible impact on any field of inquiry, the group quietly passed into the mists of history.

Since then, however, there have been whispers and murmurs about powering the latest, highest-tech war planes—the re-

motely piloted drones the United States is using widely in the wilds of Pakistan and Afghanistan—with small nuclear reactors.

This, of course, gives new meaning to the term “collateral” civilian casualties.

Blow It Up While the United States abandoned its “peaceful nuclear explosions” ambitions over thirty-five years ago, and the Russian remnants of the Soviet Union seem to have no interest in rearranging the physical

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www.powermag.com

landscape with hydrogen bombs, China appears to have big plans for blowing up portions of the Himalayas to reroute a major river system.

Around 2003, China began publicly discussing the idea of rerouting the Brahmaputra River and its tributaries, which begin in Tibet as the Yarlung Tsangpo River and flow into India in the state of Arunachal Pradesh, through territory that is the subject of dispute between India and China, into the Indian state of Assam, and then into Bangladesh.

The flood-prone river joins the lower Ganges and empties into the Bay of Bengal through a giant delta. It is one of Asia’s most important, and least polluted, rivers.

For some twenty years, rumors have circulated that China planned to dam the river in Tibet, diverting its flow to China’s desert regions as well as generating electric power for China’s burgeoning industries. China has already built a dozen dams on the river in Tibet, without consulting its downstream neighbors. The rumored concept is that China would divert the flow of the Brahmaputra into China’s Yellow River basin, watering the Chinese desert and impoverishing India and Bangladesh. Many Asian analysts say water will be the key natural resource in the future, defining the course of economic development in the big rivals, China and India.

Indian geopolitical analyst Brahma Chellaney at the Center for Policy Research in New Delhi wrote in 2009 that “China is now pursuing major inter-basin and interriver water transfer projects on the Tibetan plateau, which threatens to diminish international river flows into India and other co-riparian states.” Chellaney noted, “As its power grows, China seems determined to choke off Asian competitors, a tendency reflected in its hardening stance toward India…Water is becoming a key security issue in Sino-Indian relations and a potential source of enduring discord.”

Over the years, China consistently denied that it had any intention of building new dams on the Brahmaputra in Tibet. But, faced with satellite photos taken in late 2009 showing construction activities, the Chinese in October 2010 admitted they are building dams, including a 510 MW hydro project, with plans for four more. The Economic Times of India reported, “There have been reports that these projects are the beginning of a much bigger plan by China to divert the waters of the Brahmaputra to feed its parched northeast, an ambitious and technically challenging plan, called the Western Canal, that many Chinese reports say will be completed by 2050.”

While running only some three hundred kilometers, the Western Canal would pres-

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POWER July 2013

NUCLEAR POWER ent daunting technical, geological, and environmental issues. Building the canal would require blasting out tunnels and aqueducts at high altitudes and subzero temperatures. A 2006 estimate put the cost of the Western Canal at some $37.5 billion, compared to the $25 billion needed to build the Three Gorges Dam on the Yangtze River. China has officially denied plans to divert the river. In late 2009, China told the Indian government that reports of the diversion are not “consistent with facts.”

Indian foreign minister S.M. Krishna told Parliament during a questioning period in April 2010, “In November 2009, the foreign ministry of China clarified that China is a responsible country and would never do anything to undermine any other country’s interests.” This statement produced amusement among China mavens, noting that China has unilaterally seized Tibet and taken land from India over the years.

Chinese documents undercut the denials.

A 2005 book, Tibet’s Waters Will Save China, argues in favor of diverting Tibet’s rivers from India to China. New Delhi’s Chellaney observes, “Diversion of the Brahmaputra’s water to the parched Yellow River is an idea that China does not discuss in public, because the project implies environmental devastation of India’s northeastern plains and eastern Bangladesh, and would thus be akin to a declaration of water war on India and Bangladesh.”

The Chinese apparently believe that nuclear geo-engineering would help overcome the technical obstacles to the Brahmaputra project. According to Chellaney, “Chinese desire to divert the Brahmaputra by employing ‘peaceful nuclear explosions’ to build an underground tunnel through the Himalayas found expression in the international negotiations in Geneva in the mid-1990s on the Comprehensive Test Ban Treaty. China sought unsuccessfully to exempt ‘peaceful nuclear explosions’ from the CTBT, a pact still not in force.”

Under its current leadership, China has emerged as more truculent and triumphalist in its relations with other countries. George Washington University’s China scholar, David Shambaugh, has described China as “an increasingly narrow-minded, self-interested, truculent, hyper-nationalist and powerful country.”

Leading China’s ambitious plans to drain Tibet for the benefit of the ethnic Chinese regions are party chief and state president Hu Jintao and prime minister Wen Jiabao.

Hu, who is scheduled to turn power over to a new generation of Chinese communist leaders within the next year or so, is particularly identified with the project to use nuclear

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July 2013 POWER

bombs to dewater Tibet. [Editor: Hu turned over his positions as general secretary of the Communist Party and chairman of the Central Military Commission to Xi Jinping on Nov. 15, 2012.] He is a hydro engineer, long a traditional occupation among Chinese leaders, and a former governor of what China calls the Tibetan Autonomous Region, but which much of the rest of the world regards as conquered Tibet, brought under Chinese control in 1949 and strengthened in 1959, when Tibetan patriots spirited the young Dalai Lama out of the country and into India, where he has led a government in exile.

Wen is a geologist by training, and has a long association with Chinese government projects involving geology and hydro development, including the Three Gorges Dam. Will China continue with its still undisclosed plans to use “peaceful nuclear explosions” to divert the Brahmaputra River system from its not-entirely-friendly neighbors of India and Bangladesh to water arid Chinese lands? That question is open, and the emergence of Xi Jinping as the likely successor to Hu in 2012 could soften Chinese geoengineering plans. Fifty-seven-year-old Xi is a lawyer by education, a Marxist theorist, and a veteran bureaucrat. He’s often portrayed as a softer figure than either Hu or Wen, although there is little tangible evidence for this view. But the persistence of rumors of a Chinese plan to use nukes to rearrange the earth verifies the observation that dumb ideas die hard.

Breed It Breeder reactor enthusiasts have always been possessed of a sort of religious fervor. Maybe it’s an engineering thing. Engineers seem to venerate efficiency, even when it isn’t economically efficient, so the thought of leaving unused energy behind in spent nuclear fuel rubs a lot of nuclear power advocates against the grain.

The notion that conventional nuclear power might be leaving a lot of energy on the table—or buried in a desert somewhere—has motivated a significant number of nuclear advocates to hew to breeder reactors and reprocessing: no matter what. So the death of the Clinch River Breeder Reactor didn’t represent the interment of the cult of breeders and plutonium reprocessing.

Not long after the nuclear devastation in Japan following an enormous earthquake and tsunami, an official of the World Nuclear Association in London (the spawn of the uranium cartel) was arguing that the events at Fukushima made the case for closing the fuel cycle. Steve Kidd’s reasoning was that because the spent fuel pools at Fukushima were damaged, it would be a good idea to empty www.powermag.com

them into plutonium reprocessing facilities.

But, even if reprocessing were in place—as it is in Japan—those spent fuel pools would have been full of waste, waiting for reprocessing. Never mind.

Kidd even argued, rather astonishingly, that the Fukushima aftermath demonstrated that “the United States is gradually moving away, it seems, from a clear preference for the ‘once through’ nuclear fuel cycle, with the termination of the Yucca Mountain repository project.” Only a true believer could see that vision. Rather, the United States is clearly moving toward permanent, at-reactor storage in large, dry casks.

The Bush administration, late in its eightyear run in Washington, tried to revive reprocessing and breeder reactors, through an ill-designed and ill-fated Global Nuclear Energy Partnership aimed at building a multinational program to supply the world with new reactors fueled with mixed plutonium and uranium from first-world reactors. It didn’t survive the laugh test.

Salt It Away With Yucca Mountain’s waste dump program shut, those who continue to push for burying the byproducts of the U.S. nuclear endeavor were once again looking kindly on salt deposits. In particular, they are looking at a site near Carlsbad, New Mexico, where a small, test project has been storing wastes from the nuclear weapons program for over a decade.

It’s known as the Waste Isolation Pilot Project, or WIPP. When President Obama pronounced his death sentence on an already senescent Yucca Mountain nuclear waste project in 2009, he attempted to soften the blow a bit with a classic Washington ploy. He announced appointment of a committee of credentialed and experienced insiders to advise him where to look next for nuclear waste disposal. These sorts of actions— political window dressing—seldom result in concrete results, but are popular among the pols nonetheless.

Out of either naïveté or a sense of humor, Obama named—what Washington has longtermed “blue ribbon panels,” to denote their putative quality—the Blue Ribbon Commission on America’s Nuclear Future. The commission was part of a compromise between Democratic Senate majority leader Harry Reid of Nevada, the most dedicated opponent of Yucca Mountain in Congress, and the administration. Reid wanted a congressionally-appointed commission to scope out what should come next in waste disposal, but the administration wanted more control.

In March 2009, Reid and Energy secretary Steven Chu agreed to a White House–named 69

NUCLEAR POWER panel, which the administration announced in January 2010. The chairman of the panel was former Democratic congressman Lee Hamilton of Indiana. Concluding that “[a] new strategy is needed,” the commission laid out its views in July 2011, and was unable to come up with anything new. Acknowledging that Screw Nevada had failed, the commission called for new legislation and a new arrangement of the waste management deck chairs at the Department of Energy, to administer a consent-based approach, rather than the political coercion that characterized the 1987 law. The commission said the approach taken to siting the small New Mexico test for disposing of transuranics could be a model for the future.

More explicitly, some in DOE have been focusing on expansion of WIPP for disposing of used civilian reactor fuel. The trade newsletter Energy Daily reported in early 2011 that “Energy Department officials, as well as some governors and lawmakers, are warming to the idea of trying to bury some of the nation’s high-level waste at DOE’s Waste Isolation Pilot Plant in New Mexico.”

But there are serious technical obstacles to turning the much smaller WIPP salt-

based storage site into a final spent fuel repository. Two Albuquerque, New Mexico, experts—Christopher Timm and Jerry Fox—discussed some of the limits to using WIPP in a September 2011 paper for Nuclear Energy International magazine. They also noted that the original decision to build the project created a considerable political uproar, including opposition by the local congressman, several lawsuits, and a twenty-year delay in the project while it could be restructured and reduced in size to meet local political objections.

Despite the failure of the 1986 law, former journalist Luther Carter, along with DOE waste program veteran Lake Barrett and former NRC commissioner Kenneth Rogers, were pushing for resurrection of the Nevada site. In a fall 2010 edition of Issues in Science and Technology, the three lobbied the Obama commission to spit in the face of its creators and support continued development of Yucca Mountain. They argued, “Surely this is not the time to abandon the only currently viable option for very longterm geologic retrievable storage of spent fuel, and possibly final disposal.”

It should come as no surprise that the

commission deliberately refused to take this action, instead issuing a typically anodyne report advocating unspecified changes to make things right. In the meantime, the nuclear regulators have repeatedly judged that it is safe to store spent reactor fuel above the ground and at the site of the operating reactor. That will be the default position on minding the nation’s used nuclear fuel, and there appears to be no reason why it won’t continue for as long as anyone can predict.

Note to readers: If you wish to learn about the sources for this book, please connect to the web site www.toodumb.org, where you will find a bibliography and chapter source notes. The web site also includes a bonus chapter on the cons and frauds that have surrounded the quest for fusion energy, a picture gallery with images of many of the people, places, and things mentioned in the book, and the Too Dumb Film Festival, five YouTube videos related to the five sections of the book. ■

—Kennedy Maize is a POWER contributing editor and executive editor of MANAGING POWER. Too Dumb to Meter is available from the POWER Bookstore or Amazon. com and is serialized by permission.

Now Accepting Abstracts!

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POWER July 2013

NEW PRODUCTS

TO POWER YOUR BUSINESS

Energy Efficient Lighting for Hazardous Areas

Crash Cart for Mobile Remote Nuclear Facility Monitoring Rolls-Royce introduced a new line of fully customizable, heavy duty AV Crash Carts for mobile remote video, audio, and teledose monitoring at nuclear facilities.

Truly a self-contained unit, a typical cart comes equipped with storage space for every component needed for quick and easy system deployment. Housed in the cart’s lockable lid are two built-in 22-inch LCD monitors. The bottom half of the unit comprises four secure drawers as well as a lockable 19-inch rack cabinet, which together can house up to four quickmount cameras, wireless headsets and belt packs, a camera control joystick, and camera cables. Wireless helmet cameras have also been included in typical packages, providing a view of the work area straight from a field technician’s hard hat. The system itself can be configured to run on battery power. Also included are on-board recording capabilities that can free the operator from being forced to tie into a facility’s computer network or AV system for full system functionality. (www.rolls-roycenuclear.com)

Hazlux Induction Lighting Fixtures from ABB Group member Thomas & Betts now are equipped with Fulham induction electronic ballast and lamps, which deliver more than 100,000 hours of white light, an increase in service life of 66%. The fixtures are designed to retrofit into existing lighting applications in hazardous or hard-to-reach places and can save resources by eliminating the need for expensive high-intensity discharge (HID) options, such as quartz auxiliary lamps or instant re-strike. An extreme cold-weather option is also available, which will allow users to re-strike the induction fixture at –58F (–50C) and operate the fixture in temperatures as low as –85F (–65C). Hazlux Induction Lighting Fixtures are suitable for use in Class 1, Zone 2, Groups IIA, IIB, IIC, Exn R II T3 (restricted breathing), Div. 2 Groups A, B, C, D areas. They are also rated for explosion-proof areas, Class I, Div. 1, Groups C, D and Class II, Div. 1 and 2, Groups E, F, G. (www.tnb.com)

Robotic Torches for Single Arc, Tandem Applications ESAB Welding & Cutting Products launched the new Aristo RT line of robotic torches, designed for single arc or tandem applications. The Aristo RT range of robotic torches work with three different product setups: Standard (external cable), Hollow Wrist Helix (rotation +/–220o), and Hollow Wrist Infiniturn (endless rotation). Hollow Wrist Infiniturn offers the highest productivity with shorter programming time, shorter cycle time, less downtime, and cost savings as a result of the endlessly turning media coupling, optimization of the welding position, and long life of the cable. The Aristo RT42, RT-52, and RT-62 are universal torch necks that are interchangeable with each other. All three robotic necks are available in gas-cooled (RT-42G, RT-52G, RT-62G) and water-cooled (RT-42W, RT-52W, RT-62W) models in different swan neck angles with packages available for KUKA, ABB, Fanuc, and Motoman/ Yaskawa robotic systems. (www.esabna.com)

Wireless Phaser HD Electric Co.’s TAG-5000 wireless phaser is designed to perform many of the existing functions of conventional voltmeter/phaser devices while using state-of-the-art technology that eliminates the cord and lightens the weight of this important testing device. TAG-5000 can be used for all overhead and underground phasing applications and is ideal for use at higher voltages where safety and ease of use are prime considerations. (www.HDElectricCompany.com)

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

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July 2013 POWER

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71

POWER PLANT BUYERS’ MART

CAREERS IN POWER NAES Corporation is a leading provider of 3rd party O&M services to the Independent Power Industry. As we continue to grow, we have constant needs for power professionals across the nation.

For more info, log onto: www.naes.com/careers

POWER PROFESSIONALS Opportunities in Operations and Maintenance, Project Engineering and Project Management, Business and Project Development, First-line Supervision to Executive Level Positions.

Employer pays fee. Send resumes to: P.O. Box 87875 Vancouver, WA 98687-7875 email: dwood@powerindustrycareers.com (360) 260-0979 l (360) 253-5292 www.powerindustrycareers.com

READER SERVICE NUMBER 200

Turbine Controls Woodward, GE, MHC Parts and Service

TurboGen • (610) 631-3480 info@turbogen.net

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NEED CABLE? FROM STOCK Copper Power to 69KV; Bare ACSR & AAC Conductor Underground UD-P & URD, Substation Control – Shielded and Non-shielded, Interlock Armor to 35KV, Thermocouple

TUBE PLUGS Brass, S/S, Alum, Titanium, Alloy20, ChromeMoly, Monel, CuproNickel, Hastelloy.Buna-N, Fiber, Neoprene, Phenolic, Silicone

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Fax (773) 539-3500 Ph. (800) 227-4292 E-Mail: basicwire@basicwire.com WEB SITE: www.basicwire.com READER SERVICE NUMBER 203

READER SERVICE NUMBER 205 72

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READER SERVICE NUMBER 206 www.powermag.com

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POWER July 2013

PRODUCT

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CU Services LLC 725 Parkview Cir, Elk Grove Vlg, Il 60007 Phone 847-439-2303 rcronfel@cuservices.net www.cuservices.net READER SERVICE NUMBER 207

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CONDENSER OR GENERATOR AIR COOLER TUBE PLUGS THE CONKLIN SHERMAN COMPANY, INC.

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Sizes 0.530 O.D. to 2.035 O.D. Tel: (203) 881-0190 • Fax:(203)881-0178 E-mail: Conklin59@aol.com • www.conklin-sherman.com OVER ONE MILLION PLUGS SOLD

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Office (281) 359-4006 PO Box 5758 E-mail: blrclgdr@aol.com Kingwood, TX 77325-5758 Fax (281) 359-4225 READER SERVICE NUMBER 211

Layup Desiccant Dehumidification & Filtration Units for long term layup of power generation equipment. Call us.

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READER SERVICE NUMBER 212

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July 2013 POWER

READER SERVICE NUMBER 213 www.powermag.com

73

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To Advertise in POWER Classifieds CONTACT: Diane Burleson PHONE 512-250-9555

74

FAX 512-213-4855

www.powermag.com

dianeb@powermag.com

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POWER July 2013

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

Page

Reader Service Number

Abresist Kalenborn . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 . . . . . . . . 6

Reader Service Page Number MTU . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

www.abresist.com

www.mtu-online.com

A.J. Weller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 . . . . . . . . . 3

NAES Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 . . . . . . . 17

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www.naes.com

Applied Bolting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 . . . . . . . 22

NatronX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 . . . . . . . 14

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www.natronx.com

Bilfinger Piping Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 . . . . . . . . . 2

Nol-Tec Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 . . . . . . . . 9

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www.nol-tec.com

Burns & McDonnell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 . . . . . . . 15

Process Barron . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 . . . . . . . 23

www.burnsmcd.com

www.processbarron.com/power

Carboline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 . . . . . . . 20

Santee Cooper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 . . . . . . . 12

www.carboline.com

www.santeecooper.com

Carver Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 . . . . . . . 13

Siemens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 2 . . . . . . 1

www.carverpump.com

www.siemens.com/energy/solutionsets

Exxon/Mobil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 . . . . . . . 10

STF S.p.A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 . . . . . . . 21

www.exxonmobil.com

www.stf.it

Foster Wheeler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 4 . . . . . 24

TEAM Industrial Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 . . . . . . . . . 5

www.fwc.com

www.teaminc.com

Hach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 . . . . . . . . . 4

TerraSource Global . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 . . . . . . . 11

www.hach.com

www.terrasource.com

Hadek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 . . . . . . . 25 www.hadek.com

Classified Advertising

Hawk Measurements America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 . . . . . . . . 7 www.hawkmeasure.com

Martin Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 . . . . . . . 19

Pages 72-74. To place a classified ad, contact Diane Burleson, 512-250-9555, dburleson@powermag.com

www.martin-eng.com

POWER From the editors of POWER: The online magazine devoted to the coal-fired power generation industry Te c h n o l o g i e s f o r c o a l - f i r e d p o w e r p l a n t s a r e e v o l v i n g ra p i d l y , a n d COA L P O W E R h a s e v o l v e d t o o . I n i t s l a t e s t o n l i n e f o r m a t y o u g e t everything you valued in print and so much more: • A c c e s s t o COAL POWE R w h e r e v e r y o u c a n u s e a b r o w s e r.

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75

COMMENTARY

Bridging the Gap Between Company and Community

By John G. Waffenschmidt n communities all across North America, environmental justice (EJ), which calls for the fair treatment of all people, including those of color and the economically deprived, remains a serious concern. Consequently, community acceptance is an imperative when building or operating industrial facilities, such as power plants and energy-from-waste (EfW) plants. Covanta Energy’s Chester, Pa., EfW facility is a good example of the value of a formal approach to community affairs and EJ.

Troubles in Chester Since 1992, the Delaware Valley Resource Recovery Facility in Chester, Pa., has processed municipal solid waste from Delaware County, Pa., and neighboring communities, generating approximately 80 MW of renewable energy. Chester’s many industrial waste facilities have long been a concern to local residents and the U.S. Environmental Protection Agency (EPA). In 1995, the EPA found a number of risk factors present for local residents, such as high blood lead levels, cancerous and noncancerous risks from pollution sources and air emissions, and potential health risks from eating contaminated fish. Although the study never cited unacceptable emissions directly from the EfW facility, many residents considered the findings to be evidence of its impact.

The Pennsylvania Department of Environmental Protection (PaDEP) took a number of steps to empower local communities to have a voice in the permitting process going forward, such as seeking public community meetings upon receipt of a permitting application and demonstration by the applicants that they had engaged with the community.

Covanta quickly recognized the value of being a good neighbor as an important first step in creating an acceptable presence in Chester.

Efforts were made to address all topics of concern to residents. Topicspecific placards were developed and presented over a two-day session to local residents by experts knowledgeable in the issues at hand.

With the community’s concerns in mind, Covanta also conducted an environmental review, resulting in a formal agreement with the Chester residents.

In April 1997, Covanta assumed ownership of the facility with the initial permits and in 1999 received modified permits that incorporated specific elements of Covanta’s community agreement, which had been signed earlier. Covanta developed solutions to the community’s chief concerns while retaining needed operational flexibility. These solutions included instituting engineered controls to reduce odor at the facility and reducing emission exceedances by 80%. In addition, Covanta improved safety at the facility with a 70% reduction in accidents. Covanta also implemented a number of beneficial initiatives to improve the quality of residential life in Chester, such a city cleanups, landscaping projects, and a job skills development program.

Covanta’s efforts earned the community and the company the 2000 Governor’s Award for Environmental Excellence for bridging the gap between company and community.

Today, the Delaware Valley Resource Recovery facility is operating successfully and in concert with the community. The plant not only provides an effective and environmentally safe solution to the county’s solid waste disposal needs but also generates approximately 80 MW of renewable electricity for the community.

Moving Forward and Working Together Companies interested in acquiring the Chester EfW facility, or building new ones in the community, dropped or modified their proposals after a Supreme Court ruling on a suit brought by Chester residents against the PaDEP, but Covanta Energy did not. The PaDEP and Covanta were aligned in believing local residents are important stakeholders.

Prior to acquisition of the Chester facility, Covanta personnel met with residents and the PaDEP. Covanta realized that in order to improve the facility’s functionality and ensure it could operate at capacity, permit modifications pertaining to how the company received and processed waste were required. Aware of the facility’s history with the community, Covanta also knew that engaging and establishing mutually acceptable permit conditions—to the community, the company, and the PaDEP—would be imperative.

Upon acquisition of the facility and submittal of applications, the PaDEP facilitated a public meeting to provide community members with important information on the scope and nature of the application. The goal was to provide a fair opportunity for the community to be involved and to comment on the company’s proposal in a timely fashion. The PaDEP solicited input from internal experts, community residents, academia, and advocacy lawyers.

Implementing a Successful EJ Policy Covanta remains committed to engaging with and supporting the communities in which it has—or will have—facilities. To help fulfill this commitment, the company developed a Community Outreach and Environmental Justice Policy. The policy is consistent with the company’s sustainability objectives and has been beneficial in helping Covanta integrate and operate appropriately in potentially disadvantaged communities. Its main objective is to give residents early knowledge of specific company actions affecting their communities and the opportunity for meaningful involvement with the subsequent permit review process.

The dialogue with the community continues with Covanta participating as an active member of the Chester Environmental Partnership, a grassroots environmental organization led by the Reverend Dr. Horace Strand. A structured process, leadership, and the desire of all interested parties to address issues of concern openly and constructively have been key success factors in the effectiveness of this relationship. This approach can work for others as well. Regulators, companies, and communities that are able to find a way to work together stand the best chance of co-existing and succeeding. ■ — John G. Waffenschmidt is vice president, Covanta Energy Environmental Science and Community Affairs.

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September 9 - 11, 2013 Marriott Wardman Park, Washington, DC

www. RETECH2013.com

Where the Renewable Energy Industry Does Business Join us for RETECH 2013: The Renewable Energy Technology Conference & Exhibition This September, thousands of business leaders, investors, technology innovators, federal and state government officials and university educators – representing every aspect of the renewable energy industry – will unite for three days in Washington, DC. RETECH educates and informs its international attendee base with a technical program that addresses relevant and cutting-edge topics in renewable energy technologies, power generation, military and government, and business.

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3 DAYS OF IN-DEPTH WORKSHOPS AND SESSIONS As new developments in renewable energy continue to grow, it’s important for experts like you to stay on top of the ever-changing innovations in the industry. RETECH’s technical program addresses today’s most pressing issues and opportunities facing every discipline of the renewable energy industry: Wind, Solar, Hydro, Geothermal, Biomass, Biofuels, Waste, Smart Grid, Transmission, and Storage.

HEAR FROM MAJOR PLAYERS IN RENEWABLE ENERGY RETECH attracts leading industry speakers from the United States Department of Energy, Biomass Power Association, BOEM, FERC, AWEA, National Hydropower Association IBM, Siemens, GE, AT&T, SOLON Corporation, and much more!

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