powmagazine 01-2014.pdf

Febru

ary 2014 • Vo

l. 158 • No

. 2

Vol. 158 • No. 2 • February 2014

More Concerns and More Tools for Plant Control

One Way to Reduce MATS Compliance Costs

Capacity Market Coming to Texas?

Using the NIST Cybersecurity Framework

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On the coverIn most coverage of power plant instrumentation and control issues, it’s typical to empha-size the role of new technologies and capabilities, but ensuring best practices and ergo-nomics for human operators, as at Great River Energy’s Coal Creek Station (see p. 20), is an equally important consideration. Source: Winsted Corp.

COVER STORY: InSTRumEnTaTIOn & COnTROl32 Remote monitoring and Diagnostics Within a Smart Integrated Infrastructure

Faced with emissions retrofits, fuel switches, and increased cycling, maintenance staffs nearly everywhere are finding themselves pushed to deliver more with less. That’s where state-of-the-art remote monitoring and diagnostics can help.

3 6 Establishing Proper Pressure Drop for Feedwater Flow Control ValvesHere’s your tutorial on conventional industry methods for establishing control valve pressure drop plus an explanation of why they cannot be used in power plants with-out reviewing all plant operating scenarios.

40 Generation Cybersecurity: What You Should Know, and Be Doing about ItThese days, basic cybersecurity measures are as critical at generation plants of all types and sizes as proper dust control at a coal plant, and unless everyone from the CEO down to the auxiliary operator observes them, the consequences can be severe and lengthy.

FEaTuRES PlanT auTOmaTIOn46 using neural network Combustion Optimization for maTS Compliance

Neural net systems have not only demonstrated reduced boiler emissions and im-proved combustion efficiency, but they also now can reduce the administrative costs of complying with the Mercury and Air Toxics Standards (MATS).

CYBERSECuRITY49 nIST Cybersecurity Framework aims to Improve Critical Infrastructure

The new framework developed by the National Institute of Standards and Technology with industry stakeholders is designed to provide a “prioritized, flexible, repeatable, performance-based, and cost effective approach” to managing cybersecurity risk.

POWER POlICY52 Texas and the Capacity market Debate

Industry watchers both in and far beyond ERCOT are waiting to see what shape and name will be given to some sort of capacity market in Texas, which has long held firm to an energy-only market whose seams are pulling far too tightly these days.

REnEWaBlES56 Japan Ramps up Renewables

Though long a leader in developing renewable generation, Japan suffered a setback in that sector, too, following the Fukushima disaster. New legislation, subsidies, and (finally) an integrated national grid should help place the country back on course to expand the role of renewables.

Established 1882 • Vol. 158 • No. 2 February 2014

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www.powermag.com POWER | February 20142

DEPARTMENTS SPEAkiNg of PowER6 Let There Be (LED) Light!

gLoBAL MoNiToR8 Mexico Embarks on Historic Energy Reform9 white Rose Project wins Uk government CCS Backing10 THE Big PiCTURE: Power Pie Pieces12 Japan, South korea Stick to Nuclear Ambitions14 American Physical Society Pushes for Reactor Licensing Beyond 60 Years15 Using Carbon Dioxide to Produce geothermal Power18 PowER Digest

foCUS oN o&M20 Upgraded Control Room Consoles improve Ergonomic21 Reliable fire Protection for Turbine Rooms26 Corrosion Protection for fgD Vessels28 Retrofitting Mechanical Draft fans to optimize System Performance

LEgAL & REgULAToRY30 Speeding forward with integrating Plug-in Electric Vehicles

By Vidhya Prabhakaran, Davis Wright Tremaine LLP

59 NEw PRoDUCTS

CoMMENTARY64 Are You Ready to Compete with Your Customers?

By James Newcomb, Rocky Mountain Institute, and Ben Paulos, America’s Power Plan

Connect with POWERIf you like POWER magazine, follow us online for timely industry news and comments.

Become our fan at facebook.com/POWERmagazine

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Join the LinkedIn POWER magazine Group

In “The Power Plant Controls Market in China,” associated with this issue in our archives at powermag.com, you’ll find Editor Gail Reitenbach’s interview with the China business development manager for Emerson Process Management Power & Water and gain insight into the current state of control systems for Chinese power plants.

In “The Power Potential of Southern Africa,” Associate Editor Sonal Patel notes that power produced by South Africa represents 40% of Africa’s total, yet that country is tackling a crippling supply shortfall. Emergencies are offset with imports from its neighbors in southern Africa—some that are electricity poor and some that are latent supply giants.

More POWER Online

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Putting Nature to WorkA utility client was looking for ways to reduce selenium

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SPEAKING OF POWER

You’ve no doubt heard that U.S. power plant emissions have been dropping overall and that one of

the reasons has been decreased thermal generation resulting from essentially flat demand. As of Jan. 1 this year, you have former president George W. Bush to blame, or thank, for a major factor contributing to that nearly flat demand growth: more energy efficient lightbulbs.

More Heat Than LightIncandescent bulbs (or lamps, as they’re called in the industry) convert less than 10% of the energy used into light, wasting over 90% as heat. That heat can add to space-cooling needs, which adds to overall energy costs. The energy-efficiency standards Bush signed into law in 2007 require new bulbs to use about 25% less energy than com-mon incandescent models, but some are even more efficient.

As of the new year, producing and im-porting 100, 75, 60, and 40 W bulbs is banned. But that doesn’t mean the “death” of incandescents. The law has loopholes for “rough-service,” specialty (as in applianc-es and chandeliers), colored, low-wattage, three-way, and halogen bulbs—technical-ly, a more sophisticated, and expensive, type of incandescent. However, for most applications, you’ll have to choose some-thing else when your stockpile of Edison filament lamps burns out.

Cost ContainmentLighting accounts for roughly 10% to 12% of average residential electricity costs and 19% of power use nationwide. Cut that percentage by 25% to 80%, and over time, more expensive bulbs pay for themselves. However, in our immediate-gratification, throw-away culture, low first costs get all the attention. We can tell ourselves we are saving money by buying replacement incandescents at a lower price than the light-emitting diode (LED) bulbs displayed on the next shelf, but eventually, we pay the price for first-cost thinking—in higher electricity bills and more-frequent bulb purchases.

LED prices range enormously, depend-ing upon the style, rating, quality, and where you buy them, so I’ll use the ex-ample of eight recessed flood lights we recently bought at Costco to replace a hodgepodge of “traditional” and com-pact fluorescent light (CFL) models we were testing in our kitchen. (Our first LED switchover was made in the garage. No regrets there, as we have higher lu-mens, zero flicker, and no cold weather performance penalty, as with fluorescent tubes.)

Our LEDs (for replacing the equivalent of 60 W bulbs) are shaped like the original lamps, use 13 W, and deliver 750 lumens for an estimated annual cost of $1.57 per bulb, according to the manufacturer (based on 3 hours/day at 11¢/kWh). At the same electricity rate and usage level, a 60 W incandescent’s energy cost would be $7.23/year. With savings of $5.66/year/bulb, each $18.75 LED should pay for itself in 3.3 years. (It’s possible to get other styles of 60 W-equivalent LEDs for even less.)

Yes, low-income consumers may need to budget for a gradual transition to LEDs, putting them first in fixtures used most frequently (so they save the most on their electricity bills) and using CFLs as a “bridge” technology elsewhere. They will also find that many utilities offer bulb replacement incentives.

Go Directly to LEDThe Department of Energy claims that by 2027, “widespread use of LEDs could save about 348 TWh (compared to no LED use) of electricity: This is the equivalent an-nual electrical output of 44 large electric power plants (1000 megawatts each).” Does that mean more plant closures? Per-haps, though they are more likely to be fossil than nuclear plants, despite the title of Michael Kanellos’ Oct. 28 Forbes.com article, “Can LED Bulbs Make Nuclear Plants Obsolete?”

As noted, initial costs for incandes-cent alternatives may determine technol-ogy choice for some. But of the available options, LEDs are clearly the way to go.

Energy efficiency is the main reason they are being promoted, but LEDs also offer superior safety, lighting quality, and lon-gevity benefits.

Current LED bulbs are sold in a range of lumen (rather than wattage) ratings and can offer dimmable capability and wider angles of light dispersion than earlier models. You can also choose bulbs along the spectrum, from “cool” to “warm,” de-pending on their Kelvin rating. Though we all grew up under yellow-toned incan-descent light, “cool white” bulbs provide “cleaner” light, more like natural daylight, which can be useful for settings where you want to reveal true colors.

Compared to CFLs, LEDs promise lon-ger life (22.8 years at 3 hours/day for the model we bought) as well as full lu-mens when you flip the switch, instead of the warm-up period needed for fluo-rescents. And, unlike CFLs, they contain zero mercury (I’m with my predecessor in finding the Environmental Protection Agency’s instructions for cleanup of bro-ken CFLs impractical).

Longevity offers benefits beyond life-cycle cost. For our house, it means we should never again have to drag out the pole light bulb changer to replace bulbs. For power plants, which are increasingly switching to LEDs, it means both lower operating costs and decreased main-tenance—a growing concern for bud-get- and staffing-constrained plants. For example, portions of Arizona’s Palo Verde Nuclear Generating Station, the largest nuclear plant in the U.S., have been up-graded using 130 LED fixtures. The fix-tures’ manufacturer, Albeo Technologies, claims expected savings in energy con-sumption will pay for the cost and instal-lation within two years.

If you still can’t handle this year’s sticker price for LEDs, manufacturers claim prices will fall as demand for LEDs ramps up. You can thank me for being an early adopter when you buy your first LED lamps next year. ■

—Gail Reitenbach, PhD is editor of POWER. Follow her on Twitter @GailReit

and the editorial team @POWERmagazine.

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Mexico Embarks on Historic Energy Reform Mexico’s much-awaited constitutional energy reform, passed on Dec. 12 by the federal congress and a week later by the required majority of state congresses, could spark increased private participation in power projects, lower electricity prices, and transform the profile of the country’s state-dominated power sector.

The Mexican Congress must still pass supporting legislation within 120 days from the date of the official publication of the Energy Reform, and the executive branch has a year to create a supporting regulatory regime. Beyond that, authori-ties will need to design contracts to allow expanded private sector participation in the oil, gas, and power sectors.

Discussions on the reform were initi-ated earlier in 2013, and for experts like Alex Choinski, a partner at the law firm of McDermott Will & Emery, the final package seems “especially broader” than expected.

Significantly, the reform allows state-owned oil and natural gas monopoly Petróleos Mexicanos (Pemex) to partner in projects and to allow private companies and new entities formed by the govern-ment to participate in exploration and production. The Ministry of Energy will

now also be able to issue permits to pri-vate industry for refining and petrochemi-cal activities.

On the power generation front, the state has historically retained exclusive control over transmission and distribution of power through the Comisión Federal de Electricidad (Federal Electricity Commis-sion, CFE), a company created and owned by the Mexican government and which is also Mexico’s dominant generator. Mexi-co’s infrastructure includes 209 generating plants with a combined capacity of 52.5 GW. As a result of a 1992 law that partially opened electricity generation to the pri-vate sector, about 22.6% of that capacity consists of plants built with private capi-tal; these 22 plants are mostly combined cycle gas-fired turbines.

Under the reform, the private sector will be allowed, on behalf of the state, to build, operate, finance, and extend infra-structure required for the “public service” of transmission and distribution. The pri-vate sector will also be allowed to gener-ate power and possibly sell it to end-users. The Comisión Reguladora de Energía will have the authority to regulate and grant permits to private sector generators and regulate and establish transmission and distribution fees.

The CFE and Pemex, meanwhile, will be transformed into “productive state com-panies,” meaning they will retain control over their separate budgets and perfor-mance. It essentially “corporatizes” those entities, Choinski explained. “The intent is to make them more competitive and more productive, but not pull them out of the picture.”

Another significant change entails the creation of the Centro Nacional de Con-trol de Energía (National Center of Energy Control, CENACE), a federal agency that will operate the national power system and power market to ensure nondiscrimi-natory access to the national grid. This is important because under the current regime, “CFE controls the entire pro-cess, and there is no competitive market pressure—no independent system opera-tor in the middle of all this—creating a wholesale power market on the genera-tion side, which would ideally bring down power rates,” Choinski said. “The current reforms intend to create that wholesale power market with the hopes that the savings derived from competitive bidding would then be transferred to consumers and end users.”

Mexico suffers prohibitive electricity rates partly because of CFE’s monopoly and because its costs for natural gas are higher, he added. “The reforms create a more com-petitive wholesale power market that ben-efits from the concurrent liberalization of oil and gas mid-stream distribution, which promises to create a market where gas sup-ply for power generation will be cheaper.”

Finally, while an overwhelming major-ity of Mexico’s electricity generation is derived from fossil fuels, particularly gas, coal, and petroleum products, the reform calls for the establishment of a national program for sustainable use of energy within a year of becoming effective. It also calls for a law to regulate the survey, exploration, and exploitation of geother-mal resources (Figure 1).

The transition period during which Mex-ico will shape a new regulatory scheme to support the reforms is bound to be pro-tracted, Choinski projected: “The country is essentially creating the contours of a new generation market.” As he told POWER, “There are a lot of details that have to be worked out because the guidelines are gen-erally broad.” Certainties set down by the legislation include “a provision for turnover of resources from CFE to the new national

1. Earthly power. Mexico has the fourth-largest geothermal power reserves in the world, and proposed reforms call for a law to regulate exploration and exploitation of the energy source. Alstom in December signed a $40 million contract with the Comisión Federal de Electricidad to build the 25-MW Los Humeros III-Phase A geothermal plant in the state of Puebla, a plant that will operate in tandem with two plants recently installed in the same area: Los Humeros IIA and Los Humeros IIB (shown here). Courtesy: Alstom


grid operator over a certain period of time and certain provisions that allow CFE to continue transmission and distribution re-sponsibilities for a period of time.”

White Rose Project Wins UK Government CCS Backing The UK’s faltering plans to establish a carbon capture and storage (CCS) indus-try by the 2020s got a renewed boost in December as the government pledged to back the Drax Group’s White Rose project proposal. The 426-MW coal-fired project, to be built on land adjacent to the exist-ing Drax Power Station near Selby in North Yorkshire at a cost of £2 billion ($3.3 bil-lion), is expected to be fully equipped with CCS technology from the outset to capture 90% of all the CO2 produced by the plant. The trapped greenhouse gas will then be transported by pipeline for per-manent storage deep beneath the North Sea seabed.

The “multimillion pound” contract awarded by the UK government to Capture Power Ltd., a consortium of Alstom, Drax, and BOC (a unit of Linde AG) for a front end engineering and design (FEED) study, marks a major milestone in the UK CCS Commercialisation Programme. The UK in-troduced a similar $1 billion competition to help develop full-chain CCS projects in in 2007, but the $1 billion grant evapo-rated after the Department of Energy and Climate Change (DECC) failed to reach a financing deal with one remaining final-ist—Longannet. The second $1 billion competition announced in April 2012 to support “practical experience in design, construction, and operation of commer-cial-scale CCS” was opened to both gas and coal-fired power plants. Later that year, the DECC issued a shortlist of four contenders: Teesside, White Rose, Peter-head, and Captain Clean Energy. Shell and SSE’s Peterhead project in Scotland and the White Rose project were named as the two preferred bidders in March 2013.

The White Rose FEED contract also in-cludes the planned development of a CO2 transportation and storage solution—the Yorkshire Humber CCS Trunkline—to be undertaken by National Grid Carbon Ltd. Capture Power and National Grid Carbon will now work with the UK government to conclude a project contract for the con-struction and operation of the full-chain CCS project that will demonstrate oxyfuel combustion technology. Project co-devel-oper Alstom will build, operate, and main-



THE BIG PICTURE: Power Pie Pieces

KEY

WASHINGTON

The generation profiles of some states have seen a marked transformation over the last two decades. Note: All pie charts are based on generation data (in MWh). Source: Energy Information Administration —Copy and artwork by Sonal Patel, a POWER associate editor

CALIFORNIA

FLORIDA

ILLINOIS

NEW YORK

PENNSYLVANIA

TEXAS

Wood and Wood Derived Fuels

Wind

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Petroleum

Other

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Hydroelectric

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Coal

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tain the power plant, including its carbon capture facilities, while BOC will build, op-erate, and maintain the air separation unit that provides oxygen for the operation of the oxyfuel combustion capture plant. A final investment decision could come as early as 2015, which could mean construc-tion will begin by 2016 and the plant will be operational by 2020.

According to the Global CCS Institute, nearly $22 billion was committed by an assortment of governments in direct fund-ing for large-scale CCS demonstration projects between 2008 and 2012, but some funding mechanisms were canceled before they were legislated due to the global financial crisis or changing gov-ernment priorities. As of October 2013, for example, the institute estimated the highest amount of funding any single CCS project could receive from the European Union’s NER300 program is €290 million. Given the program’s rules, the interna-tional CCS watchdog group says, two CCS demonstration projects at most are likely to be funded in the second round—which represents less than 10% of the €6 billion to €9 billion proposed by the European Commission when the program was initial-ly designed. “The fall in funding value is largely due to the decreased carbon price in Europe; the NER300 program is funded by the forward sale of carbon allowances.” Notably, the White Rose CCS project is the only applicant the UK government has put forward to the European Investment Bank for NER300 funding.

CCS has been the cornerstone of the UK’s plans to bolster its energy security and mitigate climate change, and the DECC has pushed for a reform of the UK electric-ity market so CCS will be able to compete with other low-carbon sources. The UK’s FEED award to White Rose in December

was announced at the opening of the Drax coal-to-biomass conversion unit (Figure 2). Drax, which is looking to transform it-self into a predominantly wood pellet–fu-eled generator, recently converted one of its six generating units at the 4-GW Drax station to biomass and intends to convert a further two units by 2016 at a cost of £700 million.

Japan, South Korea Stick to Nuclear AmbitionsJapan and South Korea, countries that depended heavily on nuclear power before the Fukushima catastrophe in 2011 (Fig-ure 3), separately released draft long-term energy plans in December, both placing renewed emphasis on nuclear.

As it redrafted its energy plan, Japan’s Ministry of Economy, Trade and Indus-try underscored nuclear’s importance as a “base-load power source that serves as a foundation” for the stability of the resource-poor island nation’s energy sup-ply. The draft also calls for the reactiva-tion of all the country’s 50 reactors that are shut pending safety reviews by the Nuclear Regulation Authority—but it stops short of endorsing construction of new nuclear plants or replacing old ones with new ones.

The ministry stated that electricity prices have soared because the country has been forced to import fuel for ther-mal power generation to offset the loss

of nuclear power. The higher power rates have caused companies to transfer pro-duction overseas or suffer tremendous losses, it said.

No dates have been set to restart the reactors, and the country’s 10 utilities have significantly increased their use of coal and liquefied natural gas (LNG). LNG imports jumped to ¥6 trillion ($57 billion) in 2012—nearly double the ¥3.5 trillion spent on LNG imports in 2010.

The revised draft will be presented to a team tasked with revising the 2010 Basic Energy Plan, which had called to increase nuclear’s share of total capacity to 41% by 2019.

Meanwhile, South Korea’s crippling electricity shortfall, which stemmed from a documentation scandal that led to the closure of several nuclear units, was alleviated this January. Korea’s Nuclear Safety and Security Commission (NSSC) approved restart of operations at Shin Kori Units 1 and 2 and Shin Wol-song Unit 1—OPR-1000 reactors that only began commercial operation be-tween February 2011 and July 2012. A draft of the country’s next long-term en-ergy plan suggests, meanwhile, that the country will temper plans for a massive nuclear expansion.

The documentation scandal and subse-quent power crunch began in November 2012, after authorities initiated an inves-tigation into faked certificates for small components at five nuclear plants. Two

3. Cleaning up. Three years after the Fukushima Daiichi disaster, Tokyo Electric Power Co. (TEPCO) continues clean up efforts at the stricken nuclear plant. In November, TEPCO began moving nuclear fuel assemblies from Reactor Unit 4 to the Common Spent Fuel Pool (shown here). Courtesy: Greg Webb/IAEA

2. Avatar. As Drax, Alstom, and BOC pre-pare to build the 426-MW White Rose carbon capture and storage project on land adjacent to the existing 4-GW Drax Power Station shown here near Selby, in North Yorkshire, Drax plans to convert three of six units at the power station from coal to wood-pellet bio-mass. Courtesy: Drax

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NOISE

Better Signal-to-Noise Ratio Means Better Level Control Performance While transmit pulse amplitude (signal size) has helped to make guided wave radar technology the standard for accurate, reliable level measurement, the fact is signal-to-noise ratio (SNR) represents a far more critical indicator of level control performance. For superior SNR in all process conditions, no other GWR device beats the Eclipse® Model 706 transmitter from Magnetrol®.

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units, Yonggwang 5 and 6 (since renamed Hanbit 5 and 6), were taken offline to have the parts replaced. In April 2013, the NSSC ordered Shin Kori Units 1 and 2 (Figure 4) and Shin Wolsong Units 1 and 2 to halt operations while authorities investigated faked safety certificates for cabling. Startup of the newly built Shin Wolsong 2 continues to be delayed as the reactor has its cabling replaced. In Octo-ber 2013, authorities indicted 100 people for corruption in the scandal, including a top former state utility official, and the country has been struggling to restore public confidence in nuclear power.

The government of the resource-poor country had banked on a nuclear-heavy energy future, calling for nuclear plants to supply 59% of the country’s power by 2030—up from the current 25%—a plan that called for the addition of 24 GWe of nuclear capacity. But a draft pro-posal submitted to parliament by the energy ministry in December would raise nuclear reliance to only 29% by 2035. That was still the higher end of a range recommended by an energy task force in October, the ministry pointed out. A future with at least that much nuclear power was critical both for energy secu-rity reasons and to reduce carbon emis-sions, it said.

The proposed goal will require South Korea to add 45 reactors to its existing fleet of 23 (11 are in the pipeline) within the next two decades. The draft proposal also foresees that electricity consumption

will double by 2035, though the govern-ment has set a goal to reduce demand by at least 15%, which may be achieved by further price hikes. Starting in July, South Korea will lower consumption taxes on LNG but raise taxes on coal generation. The energy basic plan will, meanwhile, be finalized after public hearings and fur-ther discussion with related government agencies. For more on South Korea’s en-ergy troubles, see “South Korea Walks an Energy Tightrope” in POWER’s November 2013 issue.

American Physical Society Pushes for Reactor Licensing Beyond 60 YearsAllowing nuclear generators to operate some of the existing 100 U.S. nuclear re-actors longer than their 60-year licensed limit could help offset a potentially mas-sive power supply gap that could ensue as those nuclear plants begin shutting down by the year 2030, the American Physical Society (APS) suggests in a report released last December.

The report notes that there are no statu-tory prohibitions against renewing nuclear plant licenses beyond 60 years (the Nucle-ar Regulatory Commission is considering if new rules may be required for license renewal beyond that term) and that 20-year renewal periods are currently autho-rized under existing regulations. But if no licenses are renewed beyond 60 years and no new reactors are built to compensate, about 100 GW—20% of the nation’s power supply—could begin shutting down by the year 2030 and would need to be replaced by other generating sources.

As of June 2013, 73 of 100 operat-ing units had been granted renewal to 60 years, though one was subsequently closed. At least 15 units are under review, nine units are intending to renew, and seven will shut down, not intending to renew (Figure 5).

“The decision to extend nuclear plant life is both complex and urgent,” says the nation’s leading physicist organiza-tion, whose 50,000 members hail from academia, national laboratories, and in-

4. A revival. In May 2013, South Korean authorities halted operations at four recently com-pleted nuclear units after discovering that safety-related control cabling with falsified documen-tation had been installed at Shin Kori Units 1 and 2 (shown here) and Shin Wolsong Units 1 and 2. Regulators approved restart of the first three units in December 2013; Shin Wolsong Unit 2 is still awaiting approval to start commercial operation. Courtesy: KEPCO

5. An atomic age. By the end of 2013, at least 42 of the nation’s 100 commercial operat-ing reactors were between 30 and 39 years of age, 37 were between 20 and 29 years of age, and 20 reactors were more than 40 years old. This figure shows the timeframe in which current reactor licenses are set to expire. Courtesy: NRC


dustry. According to the study’s committee, which included members from the Electric Power Research Institute (EPRI) and two federal laboratories, long-term license extensions will involve interrelated technical, economic, regulatory, and policy issues. “Further, replacing these units will require long-lead planning, estimated at 10 to 15 years prior to scheduled retirement of the plant. Hence, the window of opportunity is short—utilities will begin facing a decision of whether to renew licenses starting in five years,” they say.

Several efforts are under way to examine the potential for long-term operation of the nation’s existing reactors. The De-partment of Energy (DOE) oversees, with cost sharing from in-dustry, the federal Light Water Reactor Sustainability Program, and EPRI, backed by industry, runs the Long-Term Operation Program. Current results from both programs do not “indicate any technical show-stoppers that would prevent the renewal of licenses from 60 to 80 years, assuming rigorous applica-tion of maintenance, inspection, and aging management pro-grams,” the report says.

One focus that will require particular attention, however, is component and materials aging, but both programs are “estab-lishing a pathway of research, surveillance, and response that can manage these challenges,” the APS contends. “There are uncer-tainties involved in any engineering assessment, especially over long periods of time. For example, no mathematical model can identify what bolt will corrode on which day; instead, the models predict the likelihood, with a range of uncertainty, that a portion of the bolts are likely to need replacement within an estimated period of time. The more substantial the research program is, the better the overall activity will be: uncertainty will be reduced, lead time for preventive action will be increased, predictions will be more accurate, surveillance will be better informed, and the response will be more targeted.”

Yet, the organization warns that with a mere five years left before plants should begin facing renewal decisions, U.S. en-ergy strategies must make renewal a feasible choice. This could come from policies to boost energy security and climate change mitigation—and on the basis that nuclear reactors today ac-count for more than 60% of the nation’s near-zero-carbon en-ergy production. Because a utility’s decision to renew a license hinges on an assessment of the costs of long-term operation of the plant against costs of constructing a new coal, natural gas, or nuclear plant, the APS recommends a “more substantial fundamental research effort” by the DOE that would “buy down risk” and reduce uncertainties.

The renewal of licenses is “not an end in itself,” the APS says, admitting it is not a long-term solution. However, “it does pro-vide valuable time to establish a balanced and durable energy future for the nation,” which can be used to “develop a clean energy future.”

Using Carbon Dioxide to Produce Geothermal PowerA new kind of geothermal power being developed by a team of sci-entists from the Lawrence Livermore National Laboratory (LLNL), the University of Minnesota, and the Ohio State University could sequester carbon dioxide (CO2) while boosting power generation by at least 10 times compared to existing geothermal energy ap-proaches.

The plant design resembles “a cross between a geothermal plant and the Large Hadron Collider,” featuring a network of

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subsurface concentric rings of horizontal wells inside which CO2, nitrogen, and wa-ter circulate to draw heat from deep below ground up to the surface, where it can be used to turn turbines and generate elec-tricity. “This well arrangement encircles the injected fluids with a subsurface hy-draulic dam, functioning much like a hy-droelectric dam. The intent is to recover the maximum energy benefit from fluid in-jection operations, a major improvement over conventional geothermal power sys-tems,” noted Tom Buscheck, an LLNL earth scientist, as the team debuted an expand-ed version of the design at a December American Geophysical Union meeting.

The researchers say CO2 absorbs subter-ranean heat more efficiently than water. Extraction rates are 1.7 to 2.7 times larger with CO2 than with water because CO2 mass flow rates are up to five times greater (given a fixed pressure difference between injection and production wells). Computer simulations suggest that a system of four concentric rings of horizontal wells about three miles below the ground, with the

outer ring being more than 10 miles in diameter, has the capacity to produce as much as 500 MW—much more than the average 38 MW produced by a conven-tional geothermal plant. A plant of that design might also sequester as much as 15 million tons of CO2 per year.

The approach, which stems from a design developed by Martin Saar of the University of Minnesota, adds nitrogen to the mix to enable highly efficient energy storage for an unprecedented duration. “Much of the energy required to drive the hot fluids out of the deep subsurface to surface power plants can be shifted in time to coincide with minimum power demand or when there is a surplus of re-newable power on the electricity grid,” Buscheck explained.

Meanwhile, the fledgling technology has a number of advantages over en-hanced geothermal systems (EGS), which are essentially man-made reservoirs cre-ated where there is hot rock but little natural permeability of fluid saturation. In EGS, fluid is injected into the subsur-

face under controlled conditions, which causes pre-existing fractures to open. The new plant design doesn’t require hydrofracturing of the reservoir, and it uses lower reservoir temperatures and pressures. Plus, it would likely sequester more CO2 with more emphasis on seques-tration, the researchers say.

There are a number of caveats, how-ever. One is that it would need to be con-nected, likely by pipeline, to a large CO2 source, possibly a coal-fired plant fitted with carbon capture. Buscheck added, however, that a pilot plant based on this design could initially be powered solely by nitrogen injection, in order to prove the economic viability of using CO2. The study also showed that this design can work ef-fectively with or without CO2, broadening where this approach could be deployed. The research team is currently working on more detailed computer model simula-tions and economic analyses for specific geologic settings in the U.S.

Startup company Heat Mining Co., which was spun off from the University of Minnesota, holds the worldwide patent to an earlier form of the researchers’ ap-proach, dubbed “CO2 Plume Geothermal” (CPG) and is looking to put an operational project online by 2016. The South Dako-ta–based company admits, however, that its CPG power system, which works “like a giant pressure cooker” to vent pressure and reduce the risk of CO2 leaks, requires a capped saline aquifer at least 2.5 kilome-ters deep, a minimum aquifer temperature of 50C, and a minimum of 1 million metric tons of stored CO2 (Figure 6).

POWER DigestEU’s Highest Court Says French On-shore Wind Tariff Is Illegal. The Court of Justice of the European Union (EU) ruled on Dec. 19 that a French regulatory mechanism allowing network distribu-tors—namely Électricité de France and non-nationalized distributors—to recover from final power consumers additional costs arising from an obligation to pur-chase wind-generated electricity at higher than market prices constitutes “an inter-vention through state resources.” The as-sociation Vent De Colère! (Wind of Anger) and 11 other anti-wind groups urged the French Conseil d’État (Council of State) to annul the 2008 ministerial order that al-lows full cost recovery from consumers in-stead of through a public service fund, as was previously required. The French coun-cil asked the highest court that interprets

6. Deep potential. Researchers say sequestered carbon dioxide (CO2) can be used to boost power generation by at least 10 times compared to existing geothermal approaches. As shown, the University of Minnesota–developed CO2 plume geothermal (CPG) system could be established in deep saline aquifers or components of enhanced oil recovery. Developers say the approach has a number of advantages over enhanced geothermal systems (EGS). Courtesy: Saar and Randolph


EU law to decide whether the offset mechanism is attributable to the French state and whether it constitutes an advantage granted through state resources.

“Funds financed through compulsory charges imposed by na-tional legislation, managed and apportioned in accordance with the provisions of that legislation, may be regarded as State re-sources,” the Luxembourg-based court ruled. France must now annul the ministerial decree that introduced the tariffs within three months. The implications of the decision for similar subsidy programs established by other European countries was not im-mediately clear, though observers suggest the European Commis-sion could cite the French case as additional support for action against Germany—whose management of renewable subsidies is under EU investigation—to force it to conform with notification and reporting obligations.

TEPCO Commissions Two Ultrasupercritical Coal Plants. Tokyo Electric Power Co. (TEPCO) in December began commer-cial operation of two large ultrasupercritical (USC) coal units: the 600-MW Hirono No. 6 in Fukushima Prefecture and the 1-GW Hitachinaka No. 2 in Ibaraki Prefecture. TEPCO said in a state-ment both units achieved 45.2% efficiency, “the world’s highest thermal efficiency” among coal-fired thermal stations. Byprod-ucts from the Hirono plant are expected to be used as raw mate-rial for cement. Japan plans to put online at least nine other coal units of more than 500 MW each by 2028, and it will build at least 12 new gas-fired units next year to scale back on the use of expensive crude and fuel oil plants. According to TEPCO, coal is expected to ensure stable supply because it is widely distributed by many countries such as China, the U.S., India, and Australia.

Tennet Gets Financial Boost for North Sea HVDC Offshore Wind Connectors. Tennet, a transmission system operator in the Netherlands and Germany, on Dec. 9 secured a €500 mil-lion ($680 million) corporate loan from the European Investment Bank (EIB) to co-finance the construction and operation of three offshore high voltage direct current (HVDC) lines—a total of 2.2 GW—that will connect wind farms in the North Sea to the Ger-man grid onshore: HelWin1, SylWin1, and DolWin1. The lines are integral to installing at least 6.5 GW of offshore wind by 2020, as required by Germany’s Energiewende. Tennet has already installed or is erecting a total connection capacity of 6.2 GW. The three HVDC lines are expected to be completed in 2014 and 2015.

Third Offshore UK Wind Farm Scuttled. Scottish Power, a subsidiary of Spain’s Iberdrola, on Dec. 13 canceled plans to build the 1.8-GW Argyll Array Offshore Windfarm off the coast of Tiree in the Inner Hebrides, which the company admits has “some of the best wind conditions of any offshore zone in the UK.” The company said the £5.4 billion ($8.86 billion) project was not financially viable in the short term, but noted that if cost reductions continued across the offshore wind sector, the project could become viable in the long term. Scottish Power, however, also said the project’s progress had been halted by the presence of hard rock, challenging wave conditions that could affect con-struction, and a possible environmental impact to the “signifi-cant presence” of basking sharks in the area. In November, just after the UK government announced new subsidy prices under a renewable energy support plan from 2018, RWE abandoned its £4 billion Atlantic Array offshore wind project off Devon, and Cen-trica said it was selling its stake in another major offshore wind farm, the Race Bank, off East Anglia.

Reliance Brings Second Sasan UMPP Unit Online. On Dec. 13, Reliance Power commissioned the second unit (rated

660 MW) of its 3,960-MW Sasan Ultra Mega Power Project (UMPP) in Madhya Pradesh, India. The unit started power generation in what Reliance said was the “shortest time of just about a month from boiler light up,” a feat made possible by “adopting innova-tive commissioning methods.” The Sasan UMPP is an integrated power plant and coal mining project. Four other units at the plant are under “advanced stages” of construction and should be commissioned this year.

L&T Starts Up 700-MW Supercritical Plant in India. Lar-sen & Toubro (L&T) on Dec. 9 put into operation the first of two 700-MW supercritical units at the Rajpura thermal power plant in Punjab. The second unit is expected to come online in March 2014. Coal for the Rajpura power plant, an estimated 6.75 mil-lion metric tons per year, has been secured through a fuel supply agreement with South Eastern Coalfields. Officials noted, though, that if there is a shortage, or Coal India does not provide coal, a provision allows imports of up to 10% to 12%. L&T has projects totaling about 11 GW under implementation on engineering, pro-curement, and construction basis across the country.

Ghana Commissions 400-MW Hydropower Plant. Ghana on Dec. 20 commissioned the 400-MW Bui Hydroelectric Dam in the Tain District of the Brong Ahafo Region. The $622 million project (funded by China and the Exim Bank of China) increases Ghana’s total installed power capacity by 20%, boosting plans by the West African country to become a regional powerhouse. The country, whose gross domestic product growth is estimated at 7% to 8%, seeks to increase its power capacity to 5,000 GW by 2016. ■

—Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)

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Upgraded Control Room Consoles Improve Ergonomics

Great River Energy (GRE) is a not-for-profit electric cooperative that generates and transmits power for 28 member co-operatives throughout southern, central, and northern Minnesota and northwestern Wisconsin. With a generating capacity of more than 1,100 MW, Coal Creek Station in Underwood, N.D., is the cooperative’s largest power plant.

The plant operates two boilers fueled by lignite coal, which is supplied by nearby Falkirk Mine. Lignite is a softer coal that contains higher water content than other types of coal. GRE uses a patented coal-refining process called DryFining, which utilizes waste heat from the plant to dry and refine the coal, making it burn cleaner and more efficiently.

Recently, GRE upgraded the consoles in the control room at Coal Creek Sta-tion to improve ergonomics for workers monitoring plant operations (Figure 1). The primary reason for the upgrade was to improve the operators’ sightlines to the top row of monitors in the control room. In order to see the top monitors, opera-tors were tilting their heads too far back and experiencing eyestrain from trying to focus on information on the screens.

Team EffortGRE worked with Winsted Corp. to design and install new ergonomic consoles. In or-

der to eliminate any need to drill holes in the floor or move wires or cabling, the new consoles needed to fit the existing footprint and floor penetrations.

“The control room upgrade was really a team effort between our operations, elec-trical and instrumentation, IT, safety and management staff and Winsted Custom Di-vision along with their installation team,” said Mark Baisch, control room operator at Coal Creek Station. Together, Winsted and GRE created a design that includes three custom Matrix-Evo consoles in a horse-shoe formation.

Two of the consoles sit back-to-back, with each controlling one of the two pow-er generation units (Figure 2). They are laid out identically, so regardless of which unit an operator is controlling, the pro-cess is the same. For instance, the turbine generator control is always on the left no matter which console you are facing. Each of these consoles has five monitors mounted to it, plus the operator’s local area network computer.

The third console controls the coal-refining process. It’s a bit smaller than the other consoles and has only four sta-tions, but otherwise it houses the same equipment. The reason for this is that the control system is operator-based, which means operators can run any of the con-trols from any of the three workstations, depending on how they log in.

More Than Just AestheticsTo improve sightlines and reduce physi-cal stress to operators, Winsted followed ergonomic standards for control room de-sign outlined in ISO 1106. The monitors on each of the consoles are mounted sev-eral inches below the work surface using a unique, track-style mounting system. The system uses an integrated horizontal alu-minum track, which enables easy adjust-ment of post-mounted brackets.

While the vast majority of the control system is digital and controlled via com-puter, there are a number of hard panel switches mounted to the console that

1. Coal Creek Station distributed control system console. Courtesy: Win-sted Corp.

2. Coal Creek Station control room. Courtesy: Winsted Corp.


must also be visible and accessible. “The new consoles meet the operators’ needs,” said Baisch. “They solved the neck strain issues and improved the visibility of the top monitors.”

Additional console features included metal base cabinets and Corian work sur-faces to reduce combustibles in the control room for safety and insurance reasons. Win-sted also incorporated some slat wall pan-els that allowed file management systems for paperwork, books, and a phone tray to be kept off the work surface. The new con-sole also maintained the Americans with Disabilities Act (ADA) requirements, allow-ing enough space for a wheelchair or other assistive device to roll through.

In addition to ergonomic and ADA con-siderations, it was important that the new consoles be scalable to allow for future upgrades to the control room. The track mounting system supports a wide variety of monitor arrays. This will allow GRE to eventually replace the existing 20-inch monitors (4:3 aspect ratio) with today’s more common 22-inch model (16:9 aspect ratio) without having to make any altera-tions to the console.

From design to installation, the con-sole upgrade in the control room at Coal Creek Station was a success. Winsted worked closely with GRE to complete the installations during plant outages, so disruption to plant operations was never a concern. Most importantly, the consoles provided vastly improved ergonomics for control room operators, enabling them to do their jobs more comfortably and with greater efficiency.

—Rusty Hellen, senior designer for Win-sted Custom Division ([email protected]).

Reliable Fire Protection for Turbine RoomsFire protection for power plant turbine rooms has typically been a game of tradeoffs. Enclosure integrity issues in older facilities can render CO2 and halon systems ineffective. In new and old facili-ties alike, CO2 systems are a considerable safety hazard. However, a new system available from Victaulic may help protect plants without compromising. The fol-lowing case study explains the benefits achieved by one plant that switched from a halon system.

Upgrading a Fire Suppression SystemThe Putnam Power Plant is located in East Palatka, Fla., about 60 miles south of Jacksonville. The plant is owned by Florida Power & Light (FP&L) and was built in the 1950s. Putnam was converted to a gas/oil combined cycle plant in the 1970s, and its two 550-MW units have three turbines each: two combustion and one steam.

When officials at the plant decided to replace their halon system with a Victaulic Vortex Fire Suppression System, it resolved some issues associated with traditional turbine fire protection systems and of-fered an array of additional benefits.

Putnam was originally outfitted with a halon fire suppression system. For halon to effectively suppress a fire, room integ-rity is required. Given the age of the build-ing, this was a significant challenge.

Suchat Sonchaiwanich, principal engi-neer for FP&L technical services depart-ment explains, “Every time there is a major outage, we have to take the roof off and haul the turbine out. When complete, we put the roof back. Each time we do this, we have to perform an enclosure integrity test.


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All of the steel and the roof of the building has to be tight, which makes it difficult to get a positive test back. In fact, it often fails because we have an older building and there is too much leakage.”

With older turbines in the facility that have doors and dampers that do not fully close, the plant couldn’t get a sealed enclosure (Figure 3) without a considerable retrofit expense. Should an incident arise while the doors and dampers are open, the halon system wouldn’t work effectively as designed.

With sustainability, safety, and room integrity issues top of mind, FP&L hired Space Coast Fire and Safety to provide a new fire suppression system for the plant. Officials at Putnam investigated several options, including CO2 systems and the Victaulic Vortex Fire Suppression System.

In the fire protection industry, CO2 has been around for awhile and has been used effectively over the years in unoccupied areas. The National Fire Protection Asso-ciation and U.S. Environmental Protec-tion Agency (EPA), however, have taken an aggressive stand on its use, making it increasingly difficult to install, given the risk factors associated with the gas. Ac-cording to the EPA, at the minimum de-sign concentration for its use as a total flooding fire suppressant (34%), CO2 is le-thal. As a result, it requires pre-discharge alarms and activation delays to allow for the evacuation of personnel. Similar to halon, CO2 systems also require good en-closure integrity to function properly.

A Nontoxic SystemWith room integrity—or lack thereof—among the top considerations for a new fire suppression system at the Putnam Power Plant, the contractor and plant engineers evaluated and ultimately selected the Vic-taulic Vortex Fire Suppression System as a replacement for the halon system. Victaulic Vortex is the industry’s first hybrid clean agent/water mist system; in 2009, Factory Mutual established a new category—FM

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3. Electrical enclosure zone panel. Courtesy: Victaulic


5580—to classify such systems. The system extinguishes fires without

the use of toxic chemicals or gases by deploying a high-velocity, low-pressure mixture of water and nitrogen. Water is introduced to a jet stream of nitrogen at supersonic speed within the unique emit-ter (Figure 4). The nitrogen atomizes the water, forming a dense homogeneous sus-pension that enters the protected space at 40 miles per hour. The unique swirling pattern quickly fills the hazard space and attacks the fire, overcoming aerodynamic forces that typically decelerate and dif-fuse water droplets, absorbing the heat and starving the fire of oxygen (view the system animation at bit.ly/17dYp0B).

Although water and turbines generally don’t mix—water can damage or shock the casing, resulting in expensive repairs—the size of the water droplets emitted from the Vortex system is so small that the mist does not damage equipment. At less than 10 microns in size, the wa-ter droplets are up to 100 times smaller

than water particles delivered through traditional water mist systems. This small size allows for improved heat absorption and total extinguishing. Activation of the three-dimensional total flooding system results in uniform cooling because the water and nitrogen blend is transported throughout the entire hazard area, com-pletely surrounding the equipment. As little as 1 gallon of water is released per emitter per minute. The small water drop-lets surround the equipment with minimal to no wetting, preventing water damage. Residual moisture is barely detectable fol-lowing discharge.

Unlike halon and CO2 systems, the Vic-taulic Vortex system does not require room integrity. The system extinguishes fires in open, naturally ventilated areas, meaning it would work even with doors and damp-ers open. The turbine enclosures at Putnam did not have to be retrofitted, resulting in significant cost savings for the plant.

“Besides room integrity purposes,” Son-chaiwanich said, “the other big reason for

selecting Vortex was for safety purposes. The nitrogen Vortex uses is a friendly gas. It provides adequate and sufficient time for personnel working nearby to get out.”

System activation is immediate when sensors detect smoke or heat. There is no delay in activation to evacuate personnel because the system emits only nontoxic agents. Personnel are safe during activa-tion; reduction of oxygen in the space is at levels within safe breathing tolerances.

Configuration OptionsThe new system was installed in the first unit at the Putnam plant in 2012; instal-lation and commissioning on the second unit was completed in March 2013. The contractor worked within shutdowns to replace the old system, thus reducing the impact on plant operations.

The Vortex system at Putnam is config-ured with zone control panels to isolate activation to just the unit affected by a fire (Figure 5). The two units share the nitrogen supply, which is stored in cylin-ders (Figure 6). Nitrogen cylinders sim-plify long-term maintenance relative to CO2 cylinders. Rather than yearly weight tests, as are needed for CO2 cylinders, gauges indicate adequate nitrogen levels. Maintenance best practices dictate that the cylinders be inspected for possible replacement about every 12 years. Hoses should be inspected every five years.

Not long after the Putnam project be-gan, officials at FP&L’s Lauderdale Power Plant, also a two-unit combined cycle fa-cility, selected the Victaulic Vortex system to replace that plant’s CO2 system due to personnel safety concerns.

The CO2 system at the Lauderdale plant was designed with one tank to supply both units, and activation couldn’t be isolated to just one unit. During maintenance, the whole system had to be removed from ser-vice, requiring a shutdown of the plant in accordance with site policy. As at the Put-nam plant, the Lauderdale plant installed the new system to enable activation in just the affected unit. Lauderdale, howev-er, utilizes bulk tanks instead of cylinders for the nitrogen supply; two tanks supply each turbine. This configuration ensures ample nitrogen supply to each turbine, al-lowing the plant to keep the nonaffected turbines operating after a fire.

Installation and commissioning at Unit 4 of the Lauderdale plant was completed in April 2013. Installation at Unit 5 is scheduled for completion in 2014.

—Frank Barstow is a Vortex sales repre-sentative with Victaulic.

4. Vortex emitter protection in turbine room. Courtesy: Victaulic

5. Mechanical enclosure zone panel. Courtesy: Victaulic

6. 80-L nitrogen cylinders and manifold system. Courtesy: Victaulic

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Corrosion Protection for FGD Vessels

Roughly five years ago, the power industry readily embraced the new Alloy 2205 metal as a more lightweight and cost-effective substrate for the construction of flue gas desulfurization (FGD) absorbers and vessels than traditional heavy-duty stainless steel and carbon steel substrates, including the more common Alloys 304 and 316. Assuming that the surfaces of the Alloy 2205 FGD absorbers and vessels were properly prepared and lined, early test reports indicated that the substrate would hold up well, except perhaps under conditions such as crevice corrosion or corrosion under film buildup (Figure 7).

New Substrate Gives Way to Old Corrosion ChallengesPrior to lining, Alloy 2205 requires a clean surface with a sharp profile and blast profile (depth). For most high-build linings or coatings, a 3-mil profile is needed. However, for most alloys, ad-jacent unlined surfaces also need to be protected during abra-sive blasting to ensure that the surfaces are not contaminated by iron.

Because most slag abrasives contain iron, garnet or aluminum oxide abrasives are preferred choices, provided that they are able to produce the required sharp profile. As with carbon steel, the surface must be tested for salt contamination, and cleaned if necessary, to the lining manufacturer’s requirements. One differ-ent feature with alloys is that the surface must be coated or primed soon after blasting, unless dehumidification control holds the relative humidity to less than 40%, as the surface will not show the typical discoloration, as carbon steel does, due to sur-face oxidation.

Despite acceptable surface preparation and application of lin-ings, many Alloy 2205 vessels located at more than 40 power plants across the U.S. are now showing evidence of severe pitting and corrosion under scale buildup, including “worm holing,” after just one year in service. Apparently, much of the pre-testing of Alloy 2205 did not take into consideration the effects of a high concentration of chlorides/fluorides under the scale buildup, or that it creates the same corrosive effects of crevice corrosion.

Not All Solutions Are Created Equal Increased demand for corrosion-related repairs to Alloy 2205 ves-sels has given rise to some new corrosion solutions with varying degrees of efficacy.

One repair alternative used by plant owners is to clad the in-terior of the FGD vessel with an alloy metal that is known to perform well in these service conditions and costs less than other alloys, such as Alloy C276. Nevertheless, common drawbacks to this option include material availability. Alloy metal can often be in short supply, which forces owners to wait for extended periods until the material becomes available.

The biggest drawback to this repair solution, however, is cost. Between the high price of the material and the skilled welders needed for installation, some estimates put the cost of cladding up to $75 per square foot. Furthermore, localized leaks can still seep under the cladding and attack the alloy underneath virtu-ally unnoticed. Worse, this repair process is fairly time-intensive, resulting in significant downtime, which some plants estimate at up to $1 million per day in lost revenues.

Over the past 10 years, vinyl ester linings have been the most common method of corrosion repair for both carbon steel vessels and many types of alloys. These linings can be very effective and are increasingly being utilized in Alloy 2205 corrosion re-

7. Typical flue gas desulfurization vessel that will be lined to protect the substrate. Courtesy: International Paint

8. An installer spraying Ceilcote lining onto tank walls. Courtesy: International Paint

9. An installer rolling fiberglass reinforcement into wet basecoat. Courtesy: International Paint


pairs. Nevertheless, test data reveals that there are multiple vari-ables within a lining system’s chemistry—even environmental factors—that can directly impact its long-term effectiveness—or failure—on Alloy 2205.

It’s All in the ChemistryIn order for an appropriate lining system to be properly speci-fied for new vessel construction or repair, the plant owner and contractor must give the lining manufacturer a detailed list of the vessel’s operating conditions and the owner’s goals for usage. The list may include information like temperature variables, exact chemicals used, or function of the vessel. Factors such as tem-perature can affect differences in the permeation resistance of the material, while certain chemicals used inside the vessel may require a specific polymer base, such as an epoxy, epoxy novolac, polyester, chlorendic polyester, vinyl ester, novolac vinyl ester, or hybrid novolac.

In addition to the correct polymer base, an effective lining or coating requires the optimization of many other ingredients and elements, such as wetting agents, inhibitors, promoters, flexibi-lizers, and resins (Figure 8 and 9). Together, these formulations can make a huge impact on critical performance issues, including chemical and abrasion resistance, adhesion characteristics, ap-plication properties, crack-bridging capability, impact resistance, and even regulatory compliance. Most importantly, these lining formulations must undergo extensive laboratory testing and dem-onstrate effectiveness during actual in-service evaluation.

Tying It All TogetherProvided that the manufacturer’s test data meets the performance requirements of a given project, other factors, such as the cost of the installation and projected production downtime, will also play a big part in the project equation. That’s when the lining’s ap-plication characteristics, such as high-build single-coat options and fast cure rates, can help provide the most cost-effective and fastest return to service possible.

At about half the cost of alloy metal cladding, an appropri-ate lining system can be installed in just several days. Though other outside determinants—such as ease of access to the ves-sel, equipment and scaffolding, surface preparation, and onsite scheduling of trades—can delay the installation process, owners should expect a successful lining project to be completed within about two to six weeks and offer up to 30 years of service with only minor maintenance.

—Bill Slama ([email protected]) is a senior technical advisor with International Paint/Ceilcote Products.

Retrofitting Mechanical Draft Fans to Optimize System PerformanceMechanical draft fans are used exclusively in power generation to move air and gas from one point to another. They create draft in a process system so that fluid media can be induced, forced, and boosted. Among all draft fans, centrifugal designs are the most common in the power industry. They are robust in construction and resilient in operation.

Capital investment, as well as the downtime generation loss to replace these machines with a brand new installation can be sub-stantial. An economical alternative, which can save both money and time, is to retrofit an existing fan. This article discusses pos-sible options and offers some strategies to maximize available resources for retrofitting these fans.

New Demands on Old TechnologyMost U.S. power plant fans have been in operation for some time. Many were installed in the 1960s and 1970s, and are still in use after 40 or 50 years. They were sized and selected for certain flow requirements with little margin for future modifications. As poli-cies have changed and populations have boomed, the demands placed on plants have also been altered.

Some specific reasons that might prompt a plant to retrofit its existing fan are new environmental regulations, an emissions control system upgrade (such as converting from an electrostatic precipitator to a fabric filter), a boiler fuel conversion (such as changing from bituminous coal to Powder River Basin coal), the fan is being scheduled for retirement, or changed system de-mand. Due to the high cost associated with a new installation, retrofitting the existing fan is usually preferred.

Generation output (MW) 40 45 49

Pre-installation motor amperage (amp) 257 263 274

Post-installation motor amperage (amp) 202 214 226

Table 1. Draft fan motor amperage at various gen-erating loads. Motor current was reduced using the optimization technique. Courtesy: ProcessBarron

10. Pre-installation velocity vectors. Flow separation is evi-dent in the images. Courtesy: ProcessBarron

11. Post-installation velocity vectors. Flow separation was reduced utilizing the optimization technique. Courtesy: ProcessBarron


Furthermore, addressing any one of these issues will usually result in new system requirements for fans, such as a change in air/gas temperature, gas composition, suction/supply pres-sure needs, volume requirements, or power consumption due to changing the air/gas characteristics. This means that any fan retrofit is an engineering project in its own right.

The goal of any retrofit is to minimize modifications to the existing fan while maximizing the fan’s flow and pressure ca-pability as it relates to current system demands. Ideally, this is accomplished utilizing the existing casing without modifying the foundation. Goals for the project will normally include identifying the lowest capital cost, staying within the current motor horse-power with no new electrical infrastructure, and making minor or no modifications to the existing fan, foundation footprint, ductwork tie-ins, and related fan components.

However, the ultimate solution may require modification to one or more of the following: fan wheel, fan casing, drive motor, ductwork tie-ins, and even the foundation in some cases. When retrofitting, it’s also advisable to make use of a computational fluid dynamics (CFD) study for validation purposes. This computer based computational process cuts down on modeling costs and saves precious time. Actual model tests can also be performed with a geometrically similar fan, if budget and time allow.

There are several techniques that can be used to accomplish a successful retrofit. Among them, “optimization” and “right-sizing” are the ones most commonly used. Two short case studies illustrate both of these approaches.

OptimizationA utility plant in the Midwest was unable to meet peak load dur-ing the summer months. The draft fan was being operated at or above the maximum motor amperage load. A flow performance test and subsequent CFD study confirmed that the inlet cone velocity was not properly diffused. The fluid media inside the blade passages were separating and as a result the fan was not performing efficiently. A new, high-efficiency, optimized rotor and inlet cone were installed. The existing motor was reused. The plant met load demands successfully with horsepower to spare. Table 1 and vector plots in Figures 10 and 11 demonstrate before and after results.

Right-SizingThe draft fan at another utility plant in the Midwest was experi-encing vibrations and generating a lot of noise, which concerned plant management. A comprehensive flow performance test was performed. It was determined that the fan was oversized for the application. A redesigned, “right-sized” rotor was installed using the existing shaft and drive system. A minor modification was made to the casing.

Post-installation analysis revealed no vibrations. The acoustics issues had also been resolved. The synergies of the right-sizing process also produced an added benefit in the form of energy savings (Table 2) resulting in a rapid return on investment.

Evaluating SolutionsA retrofit fan design requires a detailed and careful review of existing system performance and operational data. The most effective strategy is a total system approach: Analyze each component; isolate critical paths; and provide a practical engineering solution. When retrofitting a power plant fan, engineers should evaluate the entire draft system; perform a field inspection; establish baseline flow parameters; es-tablish baseline geometry; calculate future system require-ments; study interactions between fan characteristics and system demands; customize a retrofit fan to suit the pro-jected system requirements; predict future fan performance; perform mechanical, metallurgical, and structural (civil) studies; validate theoretical basis with a CFD study; and per-form a geometrically similar fan model test (depending on time and budget).

The most critical path through a draft system is the draft fan. The key to a successful retrofit is the pragmatic applica-tion of a sound theoretical basis. Determining a solution re-quires comprehensive study and a clear understanding of the problem it is meant to address. Understanding the dynamics of draft machines and their interactions with systems is extremely important. Experience and access to resources on the subject matter are other key ingredients for achieving success in the retrofit process. ■—Nurul “Moni” Talukder, PE ([email protected]) is chief engineer in the Air & Gas Handling Group at ProcessBarron.

Generation output (MW) 300

Pre-installation motor amperage (amp) 185

Post-installation motor amperage (amp) 136

Table 2. Before and after draft fan motor amperage. Motor current was reduced using the right-sizing technique. Courtesy: ProcessBarron

Don’t Miss Important Online-Only ContentEach monthly issue of POWER offers a mix of current issues, emerging concerns, and “long-tail content”—articles with lasting value. But if you only read the magazine, you’re missing online-only content from our eletters. You can subscribe to any of them using the link at the top right of powermag.com. Here are a few online-only stories you might have missed: Fracking May Cut Total Water Use From Increase in Gas-Fired PowerEPA Publishes Draft Carbon Pollution RulesISO-NE: Brayton Point Retirement DeniedCoal Plant Backers Support EPA Supplemental BART Rule for Navajo PlantEIA: Gas Price Hikes Pushed Up Wholesale Power Prices Across U.S. in 2013New Geothermal Plant Begins Serving California Through One Nevada Transmission Line


Vidhya Prabhakaran

Speeding Forward with Integrating Plug-in EVs

Approximately 150,000 plug-in electric vehicles (PEVs) are already on the road in the United States, according to vari-ous reports. These vehicles include relatively wallet-friend-

ly PEV options like the all-electric Nissan Leaf and the Chevro-let Volt as well as a host of plug-in hybrid-electric vehicles like the Ford Fusion Energi and Toyota Prius PHV. But also speeding around is the all-electric Tesla S, a luxury PEV that is competing with (and in certain states like California, reportedly outselling) premium brands like Volvo and Porsche.

Sales of PEVs in 2013 appear to be up significantly from 2012, and 2012 sales were up significantly from 2011. Compelling in-centives from various state governments are increasing sales. For example, California, Georgia, and Washington all provide finan-cial incentives for PEV purchases. Similarly, California, Georgia, and New York all allow use of designated High Occupancy Vehicle (HOV) lanes by PEVs regardless of the number of occupants in the vehicle. No surprise that reports indicate that the leading re-gional markets for the sale of new PEVs are Atlanta, Los Angeles, New York, San Francisco, and Seattle.

While President Obama’s stated goal of putting one million PEVs on the road by 2015 may not happen, the integration of future PEVs with the electrical grid is an increasing priority for state regulators. The actions already taken by regulators in the PEV center of the United States—California—will likely provide a window into similar regulatory activity all across the country as demand for PEVs increases.

California Gets into GearThe California Public Utilities Commission (CPUC) initiated a rulemaking in 2009 to prepare California investor-owned utility systems for customer adoption of PEVs, among other alternative-fueled vehicles. The rulemaking included three phases that will likely be replicated in regulatory proceedings in other states.

In the first phase, the CPUC determined that a charging service provider is not a regulated utility simply by virtue of its resale of electricity as a transportation fuel—a conclu-sion that the California Legislature then codified in statute in 2011.

In the second phase, the CPUC addressed a number of barriers associated with PEV deployment. Electric utilities were required to plan for where PEV charging would likely occur in their service territories. The CPUC also adopted electric rates and appropriate metering options for PEV charging that it believed would not be too burdensome. Perhaps most importantly, the CPUC determined that the costs of any upgrades necessary to accommodate basic residential PEV charging would be treated as a shared cost among all ratepayers rather than assigned to PEV owners.

In the third phase, the CPUC monitored and evaluated utility education and outreach activities with regard to PEVs.

In 2012, California Governor Jerry Brown issued an executive order setting targets to reduce the transportation sector’s green-house gas emissions to 80% below 1990 levels by 2050 and to get 1.5 million zero-emission vehicles (including PEVs) on the California roads by 2025. In an effort to help kick-start efforts to meet these goals, Brown and the CPUC announced a $120 million settlement with NRG Energy to resolve claims related to its portfolio of power plants in California. As part of that settle-ment, NRG agreed to provide $100 million to fund fast-charging stations and other PEV infrastructure at no cost to taxpayers and to encourage consumer adoption of PEVs.

The CPUC Accelerates Integration Activities More than 20 light-duty PEV options are now available in Califor-nia, and automakers are introducing new models, new financing options, and medium- and heavy-duty PEVs. Increased market penetration of PEVs means potentially both denser and more volatile energy usage across a utility’s distribution grid. More advanced charging station equipment allows vehicles to recharge batteries faster—but at higher voltage levels.

All of these advances mean that the CPUC, in its recently opened rulemaking to consider programs, tariffs, and policies for alternative-fueled vehicles and especially PEVs, has to be even more concerned with ensuring that adequate infrastructure is in place to meet increased electric demands on the grid.

At the same time, the CPUC will need to evaluate the pos-sibility that PEV charging can be used to actually serve grid needs. Specifically, the CPUC will begin to determine if it can create policies and guidelines to help harness the usage char-acteristics of and technologies within PEVs to allow them to potentially serve as a grid asset. For example, PEVs may be able to reduce:

■ Operating costs for facility and vehicle owners ■ The utilities’ distribution maintenance requirements■ Energy prices in the wholesale market

Furthermore, the CPUC will evaluate and craft policies that allow for the potential interplay of smart grid technologies and energy storage solutions with PEVs.

The rest of the country will pay close attention to the CPUC’s ability to successfully integrate PEVs onto the electric grid with-out stifling innovation. The lessons learned from the CPUC’s initial foray into these issues should help regulators across the country make the right decisions and policies that will allow for a robust and competitive PEV marketplace. ■

—Vidhya Prabhakaran ([email protected]) is a senior associate in Davis Wright Tremaine’s energy practice group in the

firm’s San Francisco, Calif. office.

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InstrumentatIon & Control

Remote Monitoring and Diagnostics Within a Smart Integrated Infrastructure

It seems as if each week brings further bad news for coal power plants. Recently, Consumer’s Energy sought relief to close

three power plants, South Carolina Electric & Gas announced it would cease operations at the Canadys Station, and the Tennessee Val-ley Authority announced the closure of eight additional coal units, removing 3,000 MW of coal-fired generation from its fleet. A Platts report released in August 2013 predicts that retirements of coal-fired plants will “surge” through 2015, when the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards go into effect. Although some por-

tion of this lost electrical generation will be replaced by natural gas combustion turbines, barring further CO2 regulation, the remain-ing fleet of coal power plants will see greater demand and thus will operate at higher capac-ity factors.

Coal accounted for 50% of U.S. generation in 2005 and by recent estimates will end 2013 at 39.3%, with natural gas–fired generation being 27.5%. According to the U.S. Energy Information Administration, coal generation will continue to slowly increase through 2029 in absolute numbers, even as its percentage of our generation mix slowly declines. The

message is clear: Most coal power plants will weather the near-term storms but will require continuous improvement in order to continue operations for the years to come.

Challenges for Future Coal Plant OperationsCompliance with the Clean Air Act Amend-ments of 1990 changed the focus at most coal-fired power plants from performance to emissions, and as a result, the net plant heat rate of the U.S. coal fleet has worsened steadi-ly. This trend extended through 2012, and giv-en the rush to meet ever-tightening emissions

Coal power plants face more and greater challenges to their continued operations than at any time since the Industrial Revolution. As a result, utilities must employ new strategies for balancing the competing pressures of emissions compliance, economic dispatch, reliability, and performance. A combination of software tools and domain knowledge—plus an informed methodology for linking and applying these tools and knowledge—is helping to meet these challenges.Una Nowling



regulations, the trend is expected to continue. These emissions mandates worsen heat

rate (see sidebar) both by requiring addition-al air quality controls and by forcing units to switch to low-sulfur coal, primarily Pow-der River Basin (PRB) coal. Furthermore, according to a recent National Renewable Energy Laboratory study, the need to accom-modate deep cycling at coal power plants will increase as our electric generating system continues to evolve (especially with the ad-dition of increased variable renewable gen-eration), which will place severe demands on unit operations and equipment.

As a result of the impacts of emissions ret-rofits, fuel switches, and increased cycling, maintenance staff are finding themselves pushed to deliver more with less budget.

A Smarter Way to Manage MonitoringAs one grizzled coal unit operator told me re-

cently, “We have thousands of thermocouples and meters and sensors and alarms, and on a good day we can pay attention to 1 in 10. We know we’re missing data that could help our performance and maintenance planning, but unless we hire 10 more operators, what can we do?”

His plant manager expressed it this way: “We spent millions adding plant instrumenta-tion and controls over the years, and it’s time it started working harder for us.” These concerns are common throughout the industry, and an excellent way to address them is through re-mote monitoring and diagnostics as part of an integrated, “smart” infrastructure.

For example, one such platform, offered by Black & Veatch, is called Smart Integrated Infrastructure (SII). It combines human knowl-edge and experience with computer monitoring and control systems to allow a utility to not only manage its generating fleet but also optimize and evolve its operations to respond to change.

A critical piece of the SII puzzle is the thousands of sensors and controls at each coal power plant, many of which not only provide real-time data but also record their data in a plant historian. These sensors pro-vide operators critical feedback for control-ling the power plant, but at the same time, they can create information overload. The result is that many subtle changes and early warning signs of performance, operations, and maintenance problems are overlooked. To solve this conundrum, some utilities have turned to remote monitoring and diagnostics (M&D) to manage their data and leverage the information provided by plant systems under an SII framework.

Implementing Remote Monitoring and DiagnosticsRemote M&D can be implemented for any-where from one to all units in a generating fleet, with economies of scale encouraging

A Decade of Worsening Heat RatesFour factors have contributed to historically increasing heat rates (Figure 1).

Emissions Controls Retrofits. Plant emissions controls contribute to efficiency losses at the power plant through direct and indirect auxiliary power consumption, as well as potential negative combustion and heat transfer impacts (Table 1). If the total life-cycle energy costs of the reagents and waste associated with emissions controls are considered as well, then the impacts on energy production efficiency are even greater.

The Move to Powder River Basin (PRB) Coal. Although low in sulfur and fuel-bound nitrogen, PRB coals have a much lower heat content and much higher moisture content, which presents challenges for most coal power plants that were designed for bituminous coal. Not only does the greater moisture content result in poorer boiler efficiency than when burning a bituminous coal, but the greater fuel burn rate of the PRB coal can result in increased auxiliary power at the power plant.

These effects can be profound; one study conducted on behalf

of the Electric Power Research Institute by Black & Veatch found that a 500-MW (net) coal power plant that switched from Northern Appalachian coal would expect to experience, on average, 4.2% poorer boiler efficiency and a 5.9% increase in auxiliary power, with an overall heat rate impact of 5.0%.

Increased Unit Load Cycling. U.S. energy demand has seen significant variation in recent years due to unusual weath-er patterns and depressed economic conditions, as well as price competition from natural gas generation. When coal power plants operate at lower loads, they tend to suffer from poorer heat rates. Increased numbers of starts and stops can not only negatively affect heat rate, but they also can significantly increase mainte-nance costs.

Shifting Maintenance Priorities. Depressed economic conditions, price competition, and pending shutdowns of coal power plants due to emissions regulations have placed combined pressures upon power plant maintenance budgets. Several power plants report that they can no longer spend money on efficiency upgrades and must devote most of their maintenance budgets to-ward activities that keep the plant running, regardless of the ef-ficiency losses.

1. Increasing heat rates. Over the last decade, the av-erage net plant heat rate (NPHR) for the 100 coal-fired power plants with the most net generation has worsened by 149 Btu/kWh. Source: U.S. Energy Information Administration

2012 NPHR 2003 NPHR Linear (2012 NPHR) Linear (2003 NPHR)

Plant ranking (1=largest)

NPH

R (B

tu/k

Wh)

Heat rate penalty

Flue gas desulfurization: limestone forced-oxidation

1.5%–1.9%

Flue gas desulfurization: lime spray dryer 1.2%–1.5%

Selective catalytic reduction 0.5%–0.6%

Selective noncatalytic reduction 0.05%–0.10%

Mercury capture via activated carbon injection 0.4%–0.5%

Table 1. Typical heat rate penalties incurred by emis-sions control equipment. Though they are necessary for regu-latory compliance, plant emissions controls increase heat rate. Source: U.S. Environmental Protection Agency and Black & Veatch



systemwide integration. The key components of a remote monitoring and diagnostics sys-tem include:

■ The plant data acquisition systems and plant data historians.

■ A reliable communications network be-tween the plant and a central data hub.

■ Analysis software at the data hub, which employs advanced pattern rec-ognition to enable early detection and diagnosis of plant equipment and per-formance anomalies.

■ Operational intelligence experts, who assess the data trends, alarms, and diag-nostic reports to determine if corrective actions are needed to respond to a dy-namic situation.

Because many utilities have cut costs dramatically by reducing their engineering staff, some have turned to third-party ex-perts to provide their M&D resources. This mode of operations provides many benefits for the utility. Perhaps the greatest is avoid-ing a large investment in engineering staff for power plants that may potentially be idled or even shut down due to economic or emis-sions concerns.

Remote M&D SuccessesFor more than 20 years Black & Veatch has worked with scores of utilities world-wide to provide M&D services, and as a result it has a wealth of success stories from these efforts. Though some of these successes may seem like “small potatoes,” the benefits provided in terms of reduced operating costs, improved heat rate, fewer unplanned outages, and lower operations risk typically far outweigh any investment in an M&D system.

Case 1: A Mill Bites Off More Than It Can Chew. Operators of one pulver-ized coal unit believed that their coal mills were performing within specifications, but they were surprised when remote M&D en-gineers noted a small but statistically sig-nificant sudden increase to one pulverizer’s motor amps, differential pressure readings, and hot air damper positions. Further anal-ysis revealed that the heat rate of the unit would experience sudden variations when-ever that coal mill was brought into service (Figure 2).

An analysis of the trends suggested that the coal feeders were delivering more coal to the mills than indicated, and fast-track troubleshooting by the plant staff avoided potential problems with both mill reli-ability and combustion issues. They first checked the gravimetric feeder’s load cell by calibrating the feeder, and then further

troubleshooting revealed a problem with the feeder’s variable-frequency drive, such that the feeder was running nearly twice as fast as indicated.

Because of the early warning from the M&D system and engineers, the mill’s per-

formance was quickly returned to normal.Case 2: Turbine Troubles Tackled. John

Twitty Energy Center (JTEC) Unit 1 is a 194-MW coal-fired unit. Due to a shortage of on-site engineering staff, JTEC chose to use remote monitoring to leverage off-site

3. One of our expansion joints is missing… The loss of this extraction line expan-sion joint not only cost $25,500 per month in lost efficiency, but the unit also lost 4.5 MW of capacity as a result. Courtesy: Black & Veatch

2. The trends are clear. It was obvious something was wrong with the 4D mill, but what? Source: Black & Veatch

NUHR by measured coal flow dropped unrealistically low, so measured coal flow must really be lower than actual flow rate.

Problem went away when Mill 4D was out of service, so probably is the 4D feeder flow rate.

Indicated total flow dropped unrealistically, at same time as Mill 4D amps and dP increased. Probably pushing too much coal for the PA flow.



engineering expertise. This remote M&D implementation was highly successful, al-lowing the operators to uncover and fix sev-eral serious problems at the unit. Two notable examples include an internal extraction line failure and unexpected turbine deposits.

In the case of the extraction line failure, a deviation in pressure ratios in the low-pressure turbine pointed to an expansion joint failure (Figure 3). Upon inspection during a weekend outage, it was found that the expansion joint had completely failed, allowing steam admission directly into the condenser.

In the case of the turbine deposits, six months following a high- and intermedi-ate-pressure turbine upgrade, unit capacity dropped approximately 17 MW, high-pres-sure turbine efficiency dropped 4.8%, and

intermediate-pressure turbine efficiency dropped 3.5%. Remote diagnostic efforts ruled out stop and governing valve issues and instead pointed to turbine deposits as the root cause. This allowed for a shorter reparative outage, during which a chemical wash re-stored the capacity.

The monthly savings in fuel costs for these reparative actions was estimated at $25,500 and $37,500, respectively.

Case 3: Oil Is the Lifeblood of Your Bearings. In some instances, operators are so busy responding to plant alarms and keeping the power flowing that they can miss subtle trends that point to potentially serious mainte-nance problems down the road. Such was the case with one unit, where the air heater guide and support bearing temperatures suddenly in-creased from their normal 140F to 160F.

Because this was well below the alarm point of 195F, no notice was taken of the temperature increase (Figure 4). However, remote monitoring engineers noticed the trend and asked the operators to investigate the issue. The problem was quickly deter-mined to be a very low oil level, which had led to a loss of oil flow to the air heater’s up-per guide bearing.

After adding 9 gallons of oil to bring it back to proper level, bearing tempera-tures returned to normal, and a potential unplanned outage and expensive repairs were avoided.

Case 4: Failure Is Not an Option. Al-coa’s Warrick Power Plant is critical for providing both power and steam for its alu-minum smelting operations in Newburgh, Ind. So when continuous monitoring efforts detected a slow increase in the feedwater heater terminal temperature difference, it was time to investigate. The increase was confirmed by redundant sensors, so after ruling out externally accessible options, an internal visual inspection revealed a parti-tion plate failure in the feedwater heater (Figure 5). The impact of this failure was significant, resulting in a loss of 40 Btu/kWh heat rate and 0.4 MW.

After repairs were made, another partition plate failure was detected in the same manner less than two years later.

Early Detection Saves MoneyWith the exception of the JTEC turbine de-posit case, most of these problems were not easily detected by an already overworked plant staff. According to Stan Piezuch, se-nior performance engineer at Black & Ve-atch, “There are many examples where statistical anomaly detection has uncovered a developing problem which is still below alarm thresholds. And of course that’s the point, since it’s beneficial to detect prob-lems as early as possible, giving the plant staff more time and flexibility to deal with the problem before damage occurs or they lose production.”

An old saying in the data analysis world posits: “uncontrolled information is noise and risk; controlled information is power and security.” Not only is this true, but in the case of coal power plant operations, controlled in-formation is profit. ■

—Una Nowling ([email protected]) is a project manager and technology lead for fuels at Black & Veatch. She

has worked on fuels-related issues and analyses at more than 550 different units

over 20 years, specializing in coal, natural gas, and biofuels. She is also an adjunct professor of mechanical engineering at

University of Missouri-Kansas City.

4. One of these trends is not like the others. In this case, the higher alarm point did not detect low oil level, but the remote monitoring engineers weren’t fooled. Source: Black & Veatch

4B AH HOT END BRG TEMPnow running +20F hotter than oil temp

5. A heat transfer short-circuit. Partition plate failures are a common source of hid-den efficiency loss in a feedwater heater. Source: Black & Veatch


INSTRUMENTATION & CONTROL

Establishing Proper Pressure Drop for Feedwater Flow Control Valves

In power plants with drum-type boilers and constant-speed main boiler feed pumps, the feedwater control valve (also referred

to as the drum level control valve) provides the means for controlling flow to the boiler. On the other hand, in power plants equipped with variable-speed turbine-driven main boiler feed pumps, the feedwater control valves are usually eliminated from the main circuit but may still be used on the startup circuit with the smaller motor-driven startup feed pump.

In either application, the feedwater con-trol valve is in critical and severe service. As such, it must be sized and designed to pro-vide adequate drum level control and cope with varying drum pressures expected over the range of plant operating conditions. In this regard, one of the important parameters to be evaluated is the control valve pressure drop at the rated condition, as well as during off-design conditions.

The control valve pressure drop needs to be established carefully, as it is a performance debit resulting from increase in horsepower associated with the pressure head of the boil-er feed pump. Use of variable-speed drives or turbine drives on the boiler feed pump can avoid this debit by eliminating the control valve altogether. Boilers designed for sliding pressure operation generally utilize variable-

speed drives or turbine drives not only to eliminate the control valve penalty but also to take advantage of minimized performance debits at part loads due to lower pump head. The part-load advantage is not available with fixed pressure operation, where boiler pres-sure remains constant and the pump pressure head must remain high, even at part loads.

This article highlights the various plant operating scenarios that must be considered while evaluating the control valve pressure drop. It also points to the fact that the con-ventional methods used in industry for estab-lishing control valve pressure drop cannot be used in power plants without reviewing all plant operating scenarios.

Note that the difference between the boiler feed pump head-flow curve and the system re-sistance curve (Figure 1) provides the basis for the pressure drop available for the drum level control valve. During startup and low-load op-eration, when drum pressures are low, the valve may experience severe service due to high pressure drop. These conditions could lead to valve cavitation and subsequent destruction of the valve trim along with pipe hammer, which could lead to piping and piping support dam-age. It is, therefore, essential that the sizing and design of the drum level control valve be such that these problems are avoided. For this

purpose, the entire range of service conditions should be provided on the valve data sheet, as this will enable the valve supplier to make the correct valve/trim selection.

Conventional Methods for Establishing Control Valve Pressure DropIn general industrial applications, control valve pressure drop has commonly been established by one of the three methods discussed below. However, note that these methods may not be adequate for feedwater control valve applications, which require ad-ditional evaluation taking into consideration the high static pressure head involved in pumping feedwater to the boiler.

Traditional Method. This method traces back to the ISA Handbook of Control Valves by J.W. Hutchison, which provides guidance for control valves in a pumped circuit. Accord-ing to this method, the pressure drop should be 33% of the dynamic loss in the system at rated flow, or 15 psi, whichever is greater. In this context, the dynamic loss in the system is expected to include the pressure drop of the 100% open control valve. Other references al-low the control valve pressure drop to be 25% to 50% of the dynamic loss in the system, ex-clusive of the control valve pressure drop.

Feedwater control valves play a critical role in boiler operation. One important parameter of their design is the pressure drop at the rated condition as well as off-design conditions. However, conventional methods used for establishing con-trol valve pressure drop cannot be used at face value without reviewing all plant operating scenarios. S. Zaheer Akhtar, PE

Courtesy: Bechtel Power Corp.



Connell Method. In this method, the minimum pressure drop assigned to the con-trol valve is based on pump discharge pres-sure, increased frictional pressure drop due to maximum flow rate, and base pressure drop to account for the fact that even in the wide open position the control valve gener-ates some pressure drop. The Connell corre-lation is expressed in the equation below:

( ) BreQQPdPn

ds +++= 11.105.0

2

where:dP is differential pressure,Ps is the pressure at the beginning of the

system (pump discharge), Qd is the design flow rate in the line, Qn is the normal flow rate in the line, e is the differential pressure (dP) across

the process equipment at normal flow, r is the dP across only the piping and

valves at normal flow, and B is the base dP for the control valve. Minimum Control Valve Pressure Drop

Method for Pumped Application. In this method, attributed to F.C. Yu, the control valve in a pumped application is assigned a minimum pressure drop at maximum design flow rate and maximum 80% control valve open position (as-suming control valve regulating range is 20% to 80% valve open position). The control valve opening is then checked at normal flow to make sure that the opening is not below the minimum 20% open limit. The minimum pressure drop is 10 to 15 psi greater than the pressure drop at valve full-open conditions.

Method Application ExamplesBelow is the computation used when apply-ing the various methods for determining the assigned control valve pressure drop for the drum level control valve. Note that the val-ues are not exactly comparative because each

method uses parameters that are not common to all three methods.

Traditional Method: ■ Dynamic losses = 75 psi at normal flow■ Control valve dP = 33% of dynamic loss-

es, including control valve dP ■ Therefore, dP / (75 + dP) = 0.33, where dP

= 38 psi

Connell Method:■ Pump discharge pressure = 3,000 psi.■ Base dP for control valve = 11 psi.■ Dynamic losses at design flow = 1.2 times

normal flow.■ Control valve dP = (0.05 x 3,000) + 1.1 x

[(1.2)2 – 1] x 75 +11 = 197 psi.

Minimum Control Valve Pressure Drop Method for Pumped Application:■ Obtain valve characteristic curve showing

the coefficient of flow (Cv) versus % valve opening and check Cv at 80% open (for example: Cv = 150 at 80% open).

■ Using maximum design flowrate (Q) of 2,300 gallons per minute (gpm) and Cv value at 80% open, calculate the control valve dP as follows: Control valve dP = (Q / Cv) 2 x specific gravity = (2,300 / 150) 2 x 0.9 = 212 psi. Ideally, this is the pressure difference, which should be available be-tween the pump’s head-flow curve and the system resistance curve (exclusive of the control valve pressure drop) at the maxi-mum design flowrate of 2,300 gpm.

■ Now, using the same valve characteristic curve, select the Cv at minimum control-lable 20% open (for example: Cv = 45 at 20% open).

■ Assume that the minimum operational flowrate (for example, 800 gpm) will be handled by the valve at minimum 20% open position, calculate the valve dP as follows: Control valve dP = (Q / Cv) 2 x specific gravity = (800 / 45) 2 x 0.9 = 284

psi. Ideally, this is the pressure difference, which should be available between the pump’s head-flow curve and the system resistance curve (exclusive of the control valve pressure drop) at the minimum op-erational flowrate of 800 gpm.

Note that due to high static head of a boiler feed pump in a power plant applica-tion, the Traditional Method for establish-ing control valve pressure drop provides a low pressure drop, which is inadequate for this application. The remaining two methods (Connell Method and Yu’s Method, or Mini-mum Control Valve Pressure Drop Method for Pumped Application) consider this high static head in the calculation and result in a more reasonable value. These methods can be used as the first iteration but should not be used without additional checks. The ad-ditional checks should be done to ensure that the selected valve sizing (Cv and dP) is able to deal with all operating scenarios with valve opening remaining within the accept-able controlling range of the valve. For this purpose, it is essential to recognize the vari-ous operating scenarios and functional con-siderations at the power plant, which impact the control valve dP.

Functional Considerations for Drum Level Control Valves The basic functional consideration for a drum level control valve serving a power boiler is that it should be capable of covering a wide range of operating parameters.

Normal Flow Versus Minimum/Maxi-mum Flow. In a power boiler fitted with a constant speed motor-driven pump, the drum level control valve should be capable of han-dling the required flow during normal plant load as well as that required at reduced load (including startup).

In addition, the drum level control valve should be capable of handling maximum flow requirements, which could arise due to a combination of feedwater flows in addition to the rated flow, such as boiler blowdown, sootblowing, or spray water usage.

If startup or low-load operation results in too severe of a range for one valve, a second startup control valve may be required to split the service conditions.

Ability to Restore Drum Level. The maximum flow requirement established should be utilized and checked against the flow requirement when trying to restore drum level from low level to normal level. In case the drum level drops to around the low-level mark and the boiler is operating under full-load conditions, it may not be possible to restore drum level without reducing load, un-less the feedwater system has been designed

1. Establishing drum level control valve pressure drop. Courtesy: Bechtel Power Corp.



for the extra flow capability.Consider a boiler drum with a 3-minute

storage between the normal level and the low-low level in a plant that is operating at full load. If the drum level dropped to the low-low level due to transient conditions, in order to restore drum level in a short period of time (for example, 15 minutes) without decreas-ing load, the feedwater pump and the associ-ated control valve will be expected to handle 20% flow above normal load operation (since 3 minutes x 100% = 15 minutes x 20%). On the same basis, if the drum level is to be re-stored over a longer period (for example, 30 minutes), then the feedwater pump and the as-sociated control valve would need to handle only 10% flow above normal load operation. This additional surge capability is built into the control valve normally operating at 80% of full travel and the pump’s design point be-ing above the 100% operating point.

Boiler Makeup During High Drum Pres-sure Condition (Pressure Safety Valve Discharging). The ASME Boiler & Pressure Vessel Code, section I, paragraph PG-61.1 re-quires that the source of feeding shall be capa-ble of supplying water to the boiler at a pressure of 3% higher than the highest setting of any safety valve. Under the conditions mentioned in the code, the increase in drum pressure re-duces the pressure drop available to the drum level control valve. This reduces the feed flow to the drum, and the control valve is required to open further to compensate, if possible.

If the control valve is already fully open and unable to compensate for the flow reduc-tion, then care should be taken that the re-duced flow rate does not decrease to a point where it falls below the pump’s minimum flow recirculation point; otherwise, all flow will be diverted to recirculation, and no flow will reach the boiler drum. Such a condi-tion is unacceptable, as it would violate the ASME code requirement.

A Graphic ExampleThese design conditions and the control valve pressure drop variation can be well represented on a graph similar to the generic one shown in Figure 1, which includes the boiler feed pump (constant speed) head-flow curve, system resistance curve, and the con-trol valve pressure drop (dPcv).

As flow increases, the available pressure drop across the control valve decreases. As a result, the control valve opening increas-es. The increase in control valve opening is, however, restricted to around 80% to 85% (due to controllability considerations), and the corresponding Cv establishes the maxi-mum flow capability of the control valve.

Figure 1 also shows that as the pressure head increases due to high drum pressure

(highest set pressure of pressure safety valve plus 3%), the system resistance line moves upward and cuts back on the available pres-sure drop across the control valve. At this point, the control valve opening increases, reducing the valve dP to compensate for the increase in pressure head.

The result is that the operating point moves to the left side of the head-flow curve. At this point, it is important that the control valve opening remains within its operating range; otherwise, the drum level may not be controllable. It is also critical that this oper-ating point falls on the right hand side of the minimum recirculation flow line; otherwise, the entire flow through the feedwater pump will go toward recirculation, and no flow will reach the drum.

Specific Design ConsiderationsSome of the specific operating cases and func-tionalities of the drum level control valve that also need to be considered are discussed below.

Combined Cycle (2 x 2 x 1) Plant Operat-ing in Single Train (1 x 1 x 1). In the case of a 2 x 2 x 1 plant—assuming one high-pressure/intermediate-pressure (HP/IP) boiler feedwa-ter pump per heat recovery steam generator (HRSG)—the HP pressure could operate at 135 bar. However, this HP pressure could decrease significantly to 85 bar during 1 x 1 x 1 operation (50% steam turbine load). Under these condi-tions, the pump continues to operate along the pump characteristic curve, but due to lower pressure in the drum, the control valve closes and has to take a high-pressure drop.

The control valve pressure drop could be as high as five to six times the normal pressure drop. At this point, the question to be addressed is whether the control valve remains within the regulating range when it closes and experiences the high dP during 1 x 1 x 1 operating condi-tions. If at this high dP the control valve is out of regulating range, then a different base dP for the control valve must be selected.

Combined Cycle Bypass Spray Op-eration. On a steam turbine trip, the HRSG steam is bypassed (usually 70% to 100%) and the bypass sprays are placed in service. The HP–cold reheat (CRH) bypass valve spray water is often taken from the IP section of the HP/IP pump. However, in some cases, the IP section spray water pressure may not be high enough, and the spray water is taken from the HP discharge section of the pump. In either case, the spray water requirements enhance the flow capacity of the HP or IP section of the pump, depending on the location of the takeoff spray water line.

Consider the case of added capacity when spray water is taken from the HP discharge section and assume that the HP section flow has to be upgraded by 20% to include the by-

pass spray water flow. This 20% additional capacity can be considered as spare during normal operation and can be utilized, if re-quired, for drum level makeup (from low level to normal level), for example, in a 15-minute time period.

Therefore, the drum level control valve should be suitable for handling the 20% ad-ditional flow with a significantly reduced pressure drop as projected by the difference between the pump curve and the system re-sistance curve. In other words, under these conditions the control valve will open wide but must remain within the regulating range of the control valve.

Combined Cycle Part-Load Operation at 75% Load. In the case of part-load op-eration with combustion turbine generators at 75%, the HP feedwater flow can decrease to around 60% of normal flow while the sys-tem head could decrease by around 75% to 80% (due to lower HP steam outlet pressure). With a constant speed feed pump, the lower feedwater flow along with the drop in sys-tem head requires the control valve to absorb the additional pressure drop and, as a result, the control valve tends to close. The extent of valve closure should be verified to ensure that the control valve remains within the con-trolling range under these conditions.

Valve Pressure Drop and Cavitation. High-pressure drop across the control valve (especially that experienced during commis-sioning and startup) can lead to cavitation, which can destroy the valve trim in a short period of time (within a few days of opera-tion). Therefore, power stations have typically used a two-valve arrangement working in split range operation. The smaller sized valve (with anti-cavitation trim) is used for startup condi-tions, while the other, larger valve (without anti-cavitation trim or minimal anti-cavitation trim) is used for higher-load operation.

Alternatively, a single valve with a char-acterized disc stack can be used to handle the wide range of operation. The bottom of the trim provides low Cv values and provides anti-cavitation features, but at higher valve openings the anti-cavitation features decrease and resemble a standard trim.

Pre-operational Procedure. Note that before commissioning the boiler there are several pre-operational procedures, such as boiler fill, chemical cleaning, passivation, steam blow, and startup. For each step, the boiler drum must be supplied with feedwater, and this procedure should be clearly estab-lished up front.

Usually, the boiler is filled using the boiler fill pump because low drum pressure and low feedwater flow is outside the range of the feedwater control valve. But some of the other pre-operational steps may require the use of



the startup feed pump (usually provided when using turbine-driven feedwater pumps) and its associated drum level control valve. If the drum level control valve is to be used under these cir-cumstances, it will be subjected to high pres-sure drop due to low drum pressures during the pre-operational process and startup.

It is important that these cases be indicated on the valve data sheet to enable the valve vendor to provide the correct valve suitable for handling high pressure drops and any ex-pected cavitation at low valve openings.

As an example, the commissioning startup on some subcritical boilers requires boiler pas-sivation to be conducted by filling the boiler with feedwater and chemicals and increasing drum pressure in steps from 0 barg to 50 barg. This pressure level exceeds the capability of the boiler fill pump; therefore, the startup feed pump may be required for this operation. Such an operation imposes a high pressure drop across the drum level control valve, which should be specified accordingly.

Supercritical Boilers. Supercritical boil-ers do not utilize the conventional boiler drum used in subcritical boilers. Instead, they have once-through flow through the tubes, except at startup, when the boiler circulation pump is in operation along with makeup flow from the startup (motor-driven) feed pump and its associated control valve.

The startup feed pump, in some cases, is sized to serve as a standby pump as well. Such a start-up/standby pump would typically be rated for 30% maximum continuous rating (MCR) flow and 100% MCR head. In such cases, the associ-ated control valve experiences a large pressure drop during pre-start/startup conditions.

The pre-start process for supercritical boil-ers involves a boiler flushing operation for achieving proper water chemistry, followed by the first burner light-off (cold start). A typical flushing operation is carried out at around 20% MCR flow with no pressure in the boiler. On first burner light-off, the boiler feed is at 3% forward flow (to prevent economizer steam-ing) and the boiler circulating pump provides head due to 32% MCR flow around the fur-nace. Under these conditions, the control valve is exposed to severe operating conditions due to low flow and high pressure drop.

The pressure drop decreases during the startup sequence as the boiler pressure in-creases. In any case, in order to avoid valve damage, the operating conditions specified for the control valve should cover the entire range of pre-startup and startup conditions to which the valve will be subjected.

Steam Blow Operation for Boiler Ex-ternal Piping. During steam blow operation, the boiler drum pressure is increased to a cer-tain value (approximately 700 to 1,100 psig, depending on the blow path) and then the

blow valve is opened until the drum pressure is bled down to a low value (about 150 to 450 psig). The drum is then re-filled with feedwa-ter at the low drum pressure, which imposes a high pressure drop across the drum level control valve. If the control valve trim is not designed for this operation, the trim could be damaged during this process.

One Size Does Not Fit AllThe Connell Method and Yu’s Method may be used as a first approximation in establish-

ing the pressure drop for the feedwater con-trol valve. However, the value obtained from the first iteration needs to be further checked and modified as necessary. This is to ensure proper functioning of the feedwater control valve under all operating scenarios (includ-ing startup). These operating scenarios and corresponding operating parameters should be clearly identified on the valve data sheet submitted to the valve supplier. ■

—S. Zaheer Akhtar, PE is a principal engi-neer for Bechtel Power Corp., Frederick, Md.

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Generation Cybersecurity: What You Should Know, and Be Doing About It

Cybersecurity has become a topic of in-terest over the past year in generation, owing to new developments in North

American Electric Reliability Corp. Criti-cal Infrastructure Protection (NERC CIP) regulations, awareness of the vulnerability of generation control systems, and several inci-dents that have caused downtime and produc-tion issues for generation owners.

The intent of this article is to help gen-eration owners and operators understand what cybersecurity vulnerability is and to outline some basic first steps in reducing the risk to production from cybersecurity vulnerabilities.

Vulnerabilities and ExploitsCybersecurity issues are not like issues nor-mally seen in a control system. Excepting human performance issues, control system events are natural—they evolve from the

A professional engineer specializing in the cybersecurity of industrial control systems explains cybersecurity controls that should be present at every generation plant and why they are needed for basic risk reduction from everyday cybersecurity threats. Michael Toecker, PE

Courtesy: Michael Toecker

How the Rules Have ChangedThe best real-world example of how the rules can change from a cybersecurity event is Stuxnet. Stuxnet has been ex-tensively studied from a control systems perspective by Ralph Langner, who first identified that the virus was targeting Siemens controllers.

In Langner’s final paper on Stuxnet (“To Kill a Centrifuge”), he states that the en-tire Natanz control system down to the controller level was altered to wreck the centrifuges used for the Iranian nuclear enrichment program. The malicious code “decoupled” the legitimate code during the preprogrammed attack on the cen-

trifuges. The malicious code replayed 21 seconds of history and masked the actual values from the legitimate logic. Lang-ner even suggests that certain pressure probes that would have monitored over-pressure, and tripped the system as pro-tection, were de-calibrated by the attack code to mask the need for pressure vent-ing as long as possible.

In an environment where the con-trol system has the final say on what is wrong within a process, the creators of Stuxnet used the system against the very engineers who were entrusted to fix it.



physical characteristics of the system under control. Engineers have studied these prob-lems and created mechanisms that respond before the conditions affect production. But these problems involve physical laws and forces that are deterministic and (to an ex-tent) predictable.

Cybersecurity issues are different; they involve a human intelligence. Though the forces of nature are impressive, they are not clever, nor resourceful, nor cunning. Exploits and vulnerabilities are created to defy and change the rules of systems they target (see sidebar “How the Rules Have Changed”).

The Lack of Security in Control Systems Most commercial software now is built to en-force good security principles. For instance, when navigating to a banking website to make a transaction, there are multiple lay-ers of security so that the bank has a reason-able belief that a user is authorized to make a transaction.

Industrial control systems don’t possess these mechanisms. An entity that can com-municate with a control system can make changes that should be reserved for opera-tors and engineers. The only limiting factor is how difficult the learning curve is when learning to speak to the control system. Lack of security was built in during original devel-opment, and it hasn’t changed for most con-trol products.

For example, Project Basecamp was a Digital Bond project in 2011–2012 to evalu-ate and catalog the security vulnerabili-ties present in several programmable logic control (PLC)–based controller platforms. What was found was expected: The systems under test had numerous issues that an at-tacker with communications could exploit to alter a process.

Digital Bond researchers found that configurations could be changed or their firmware altered. Many systems had un-documented features and accounts that gave new privileges when accessed, and several systems could be easily crashed with a sin-gle command.

The conclusion was clear: Control system development has not kept pace with modern cybersecurity issues.

Compounding the lack of security in con-trol systems is the tendency for those sys-tems to fail when exposed to network traffic and data that is common on corporate net-works and the Internet but that exceeds the original design.

Experience points to a single conclusion: Malicious programs or people who can com-municate with a control system are able to make changes, operate, or crash a system entirely.

Establish a PerimeterBecause of the vulnerability of control sys-tem software and hardware as it stands today, a strong network perimeter is vital (Figure 1). There are three goals when establishing a perimeter:

■ Prevent external entities from accessing the control system networks and devices (see sidebar “Example of Excessive Auto-mation Capability and Risk Reduction”).

■ Prevent control system networks and de-vices from accessing external entities.

■ Limit access, in cases where access to or from control systems networks and de-

vices is required to meet a valid business need, to the minimum capability neces-sary to get the job done.

Though there is a tendency to focus on IT connections, don’t ignore automation con-nections. Automation connections are often a direct route to the internal workings of your system, and they are often configured for a lot more capability than is required for func-tionality. External automation connections are often done with protocols that are well-known to engineers and security profession-als. Additionally, the methods used for these automation connections have changed over

1. Typical automation network setup. This diagram shows external networks and the distributed control system (DCS) network as well as a buffer zone called a “demilitarized zone.” This demilitarized zone is used for systems that communicate with specific systems in the DCS network and with limited systems on external networks. Source: Michael Toecker

External networksIncluding Internet

External firewall

Internal firewall

Distributed control system network

Operatorworkstation

DCScontroller

Demilitarizedzone

Remoteaccess

host

File transferserver Performance

monitoring

Engineerworkstation

Historian

Notes:Tier 1 systems may communicate to external networksTier 2 systems may communicate with Tier 1 systemsTier 3 systems may only communicate with Tier 2 systems

Example of Excessive Automation Capability and Risk ReductionAn engineer at a coal mine-mouth plant has identified that her distributed con-trol system (DCS) has a Modbus connec-tion to a coal-handling facility, run by a separate mining subsidiary. This is an external connection, as the responsibil-ity and accountability for the mining subsidiary is not directed toward the reli-able production of power. The connection feeds necessary operational data into the DCS regarding coal volume, and it can’t be removed.

When evaluating the Modbus connec-tion, the engineer discovers that while

the handling facility only uses a small subset of points, the connection allows access to a chunk of points the handling facility staff have no need to access and that could cause operational issues.

Recognizing that the mining facil-ity has very little responsibility and ac-countability for power plant operations, she recognizes that the extra points are a risk to her operation. She takes steps to limit the points available via Modbus to only those necessary through the engi-neering application, and removes control points entirely.

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the years, with pure IP, Ethernet to serial converters, and serial servers becoming good options for reliable communication but coming with an additional risk as well.

Prioritize Patching for Exposed SystemsIn my experience, generation engineers are concerned about the risk of patching systems. The reasoning is that patches can often introduce un-known elements to what is a functioning system. This view is supported by anecdotes of patches that have negatively affected operations. Ad-ditionally, patching comes with additional manpower and testing costs, ones that should be evaluated before undertaking a patch.

Not patching runs a similar risk as not fixing a piece of equipment when there is a known problem. For instance, if a pump has a ten-dency to overheat, the decision might be to limit usage and to watch closely for problems.

However, a “watch and see” approach in cybersecurity is based on a faulty assumption that tools and personnel are available who can recognize a cybersecurity compromise at the same level as they can diagnose and troubleshoot an overheating pump. Even many security professionals can have difficulty recognizing malicious code in the wild without considerable experience and investment. This level of capability simply does not exist at most generation plants, and it is not a core function of making electric power.

Unpatched systems are vulnerable to simple exploits, many of which have point-and-click usage. Without periodic patching, systems would remain vulnerable forever, awaiting a motive to compromise. Patching every time a vulnerability is discovered is a worthy goal but is not appropriate for a generation environment. What is needed is a more intelligent process that patches based on risk and that limits risk to the control system.

Prioritized patching is an approach that ensures that systems with the most exposure to the outside world are patched first, and other systems follow on a set schedule. No matter what, control system engineers should set the patch schedule for their control systems and never patch a system when it can affect operations. Digital Bond has used three tiers:

■ Tier 1: Patch systems with external connections as soon as possible after testing.

■ Tier 2: Patch systems that can communicate with Tier 1 systems during biannual outages.

■ Tier 3: Patch everything else at least annually.

Ideally, Tier 1 systems are those systems that would not have an impact on operation. Specifically, these would be things like external-facing historians, performance-monitoring systems, remote access, and human-machine interfaces (HMIs) not used by operators. Tier 2 systems would be interface systems, those responsible for passing data to and from Tier 1 systems. They would ideally not have a major control function, and should be patched on a scheduled basis. Tier 3 consists of critical devices and systems that, if compromised, could affect the production of electric power.

The risk of not patching everything in an IT environment would be that viruses could spread throughout the environment quickly. How-ever, control systems are already so vulnerable that simply being on the same network as a control system would allow an attacker much more capability than using an exploit.

Say No to Indiscriminate Use of Technician LaptopsLaptops are the newest tools at a generation site. Turbine tuning is routinely done with a laptop and a set of sensors, and protection relays are configured as well. Most major control system vendors have stan-

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dard software, and this software is installed on laptops from an ease-of-use perspective.

There is nothing inherently wrong with using a laptop to complete vital work, but laptops are not wrenches and screwdrivers. They are multipurpose, and they have the capability to affect operations that exceed the scope of work. Laptops in industrial en-

vironments tend to migrate between control system tasks and web browsing, email, and basic file storage. Switching between the outside world and the control system in-creases the risk of an outside influence on the process—and does so without any intent from the user.

Restricting laptops becomes an even more important policy when the technician laptop is owned by an outside contractor. That laptop has likely been to several other industrial sites. It may even have been con-nected to various Wi-Fi access points for Internet usage, and it probably isn’t get-ting the patches and anti-virus updates it should. Logically, allowing a previously Internet-connected laptop to plug in to a control system network is not a good risk-prevention strategy.

Laptops for control system use should be segregated from normal IT laptops and never used for IT functions like email and general web browsing. They should receive updates to anti-virus and patching. These laptops should be checked out for usage and have appropri-ate maintenance and training procedures, just like a tool that can have a detrimental effect on operations if used incorrectly. Laptops not owned and managed by the plant should nev-er be allowed to connect without inspection, just like other specialized tools a contractor would bring on site.

Restrict Other Removable MediaCDs and DVDs have been the usual way that control system software is distributed to users, but use of USB drives for simple file transfers has exploded over the past sev-eral years in automation. All of these means of moving files from system to system are grouped under the heading of “removable media.” Backups of control systems are con-ducted using large removable media, vendors often bring a set of tools and scripts on USB removable media, and the configurations for many automation devices can be loaded di-rectly from removable media.

The use case of removable media makes it very attractive for reliably infecting sys-tems. Removable media is almost exclu-sively used to swiftly transfer a program or file that is immediately needed. Once on the system, it is run by user action. If that file/program is a virus or other malicious code, it is now resident on your control system, re-gardless of the individual’s intent. To mod-ify a familiar safety quotation: That which must be done fast is never done securely (see sidebar “Incidents Involving Remov-able Media at Generation Sites”).

Removable media should never be di-rectly connected to control systems without a rigorous inspection process. The inspec-

tion process should make use of anti-virus and should include a means to verify that vendor software is unaltered. Vendor soft-ware on removable media should come directly from the manufacturer, with no potential for added files. Removable media used for control systems should be reserved for control system use and never used on noncontrol systems.

Use Anti-VirusIn generation, we make extensive use of pro-tective relaying systems to detect known fault conditions and respond to those fault condi-tions by taking prescribed action before dam-age to equipment occurs. Protective relays are used everywhere because of regulations, and because the calculus of risk is simple: A single event has the potential to harm a sig-nificant capital investment and lose revenue, and the cost of the prevention via protective relay is far less than the consequence of not preventing it. Protective relaying isn’t per-fect, but it is significantly better to operate with it than without it.

Anti-virus is the protective relay concept applied to computer systems and processes. Anti-virus continuously monitors for known cybersecurity conditions and halts the activity before it can damage the system. Anti-virus will not protect you from new or unknown conditions, but it does provide good protec-tion against what has already been found and classified. Not all control systems can use anti-virus, due to age of the operating sys-tem, but all should investigate its usage as a good control.

There has been discussion about anti-vi-rus between generation professionals over the past decade. Many see it as a drain on computing resources, as the protection re-quires a certain level of processing power and memory to be effective. Additionally, there is a risk of a false positive, where the anti-virus flags a valid process as a threat and shuts it down. As a false positive could be a vital control system process, this is a risk that must be considered during the testing of new signatures and during up-dates of programs.

However—to reuse the protective relay example—relays may also experience false positives, and the consequences of a relay misoperating can be equally nasty. Funda-mentally, the risk of misoperation was deter-mined to be less than the risk of operating without protection, and procedures were put in place to test settings. The same type of procedure is necessary to minimize the nega-tive aspects of using anti-virus.

Major DCS and control system vendors in electric power have endorsed the use of anti-virus (though they generally require you use

Incidents Involving Removable Media at Generation SitesFrom a historical perspective, USB drives have the public award for the most im-pact on generation operations. In Octo-ber 2012, ICS-CERT Monitor (published by the U.S. Department of Homeland Se-curity’s Industrial Control Systems Cyber Emergency Response Team—ICS-CERT, http://ics-cert.us-cert.gov) called out two specific instances of virus infec-tion at generation plants involving USB drives. In the first case, a third-party technician infected a turbine control system with the Mariposa virus via a USB drive. The Monitor states that the Mariposa infection and cleanup delayed the restart of the plant by three weeks.

The Mariposa virus is a botnet virus discovered in December 2008, which allows victim systems to be rented for use in conventional hacker attacks on the Internet. The primary tactic is con-ducting denial of service attacks, where significant network traffic is directed at a target from multiple infected systems, crashing the target. Effective detection and prevention (via anti-virus) has been available for Mariposa since early 2009. If the Monitor article is accurate about the three-week delay being a result of the virus, this is three weeks of lost revenue due to a fully detectable and preventable issue.

The second incident involved an em-ployee who was backing up two engi-neering workstations and inadvertently used an infected USB drive. ICS-CERT does not call out the malware found, but once again, updated anti-virus found it upon a scan via the company’s IT department. Here too, regardless of individual intent, the control system was compromised by an easily detect-able and preventable virus.



the anti-virus product they have tested with their software). Consult with your vendor on anti-virus that can be used on your system, what the common activities are, and make sure you cover your corner cases (such as OPC servers or other software that is not part of the vendor testing requirements).

Get a Third-Party Cybersecurity Risk AssessmentOnce the basics above have been covered, it’s time for a more in-depth assessment of your cybersecurity risk. A third party should be consulted to see what other measures may be appropriate to your environment and the level of risk they would remove. Ideally, the best time to conduct an assessment like this is during an outage, coordinated with all the other work that will be conducted on site.

There will be findings in this third-party assessment, but the key is to identify that your initial controls have been configured appropriately and to look for other risks that should be addressed. And, as noted above, access to the control system network should not be given to the third party without a plan to ensure that systems and scripts will not cause production issues. The same tools and

techniques used by security assessors can crash a system just as easily as a malicious attacker can.

Numerous suppliers exist to provide cy-bersecurity services, but there are fewer that specialize in control systems and generation in particular. Control system vendors also of-fer this service, but many also sell products to “solve” the same cybersecurity problem. Try to get a team that has some experience in industrial environments, as they are most aware of risks, and discuss the risks and re-wards carefully.

The report should include a list of specific cybersecurity findings from the assessment, an appropriate rating of the risk each poses to op-eration, and general steps to fix the problem.

Security Work Is Never DoneMost cybersecurity incidents aren’t Stux-net; they are mundane in nature. There is consistent research on threats being done by numerous companies around the world. Hav-ing a good cybersecurity program that limits normal risk allows for the opportunity to find more malicious and targeted viruses that may target generation systems.

For this article, I was asked to provide

good practices for cybersecurity in genera-tion, irrespective of NERC CIP compliance concerns. If you are a NERC CIP plant, these practices will likely aid your compliance pro-gram, but they will not make you compliant on their own. The intent of these recommen-dations is to provide efficient risk reduction from cybersecurity events, answering the question “Where should I put my next dol-lar in order to get the biggest cybersecurity improvement?”

There will undoubtedly be discussions of controls that I’ve “missed,” or other prudent controls that should take precedence before the ones discussed in this article. These dis-cussions are valuable, because they provide different perspectives on the problem of secur-ing generation control systems. The practices in this article are not meant to be the final say, but they should provide a place for concerned operators of generation facilities to start. ■

—Michael Toecker, PE ([email protected]) is a cybersecurity consultant,

engineer, and White Hat Hacker for Digital Bond Inc. (www.digitalbond.com) special-

izing in the cybersecurity of industrial control systems, predominantly those

used in power generation.

For more information, call Wright’s Media at 877.652.5295

or visit our website at www.wrightsmedia.com

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PLANT AUTOMATION

Using Neural Network Combustion Optimization for MATS ComplianceThe U.S. Environmental Protection Agency adjusted the language of the final Mercury

and Air Toxics Standards (MATS) regulation to recognize the value of neural network combustion optimization systems by extending the required “boiler tune-up” frequency from 36 months to 48 months. Neural net systems have not only demonstrated reduced boiler emissions and improved combustion efficiency, but they also now can reduce the administrative costs of complying with MATS.

Peter Spinney

The Mercury and Air Toxics Standards (MATS), promulgated by the Environ-mental Protection Agency (EPA) on

Dec. 21, 2011, set maximum achievable con-trol technology (MACT) emission standards for specific classes of hazardous air pollutants (HAPs) found in the flue gases of coal- and oil-fired utility boilers. The emission limits vary based on the type of coal burned and whether the units are new or already in opera-tion at time of publication of the final rule.

Specifically, MATS sets removal standards for mercury (Hg), acid gases (such as hydro-chloric acid [HCl] and hydrofluoric acid), toxic non-mercury metals (such as arsenic, chromium, and nickel) and organic HAPs. MATS also limits HCl emissions (a surrogate for acid gases) and filterable particulate mat-ter (PM, a surrogate for non-mercury HAP metals). Total non-mercury HAP metals and individual non-mercury HAP metals can be used as an alternative to the filterable PM limits. Coal-fired electric utility steam gen-erating units (EGUs) equipped with flue gas desulfurization (FGD) systems may use SO2 limits as an alternative to HCl limits. Com-plying with these complicated and interre-lated standards will require boiler operators to develop new operating and maintenance practices. MATS identifies neural network optimization software as a best combustion practice for NOx and CO reduction.

MATS Drives Work Practice Standards MATS also requires new work practice stan-dards to increase combustion efficiency, thus decreasing CO, NOx, and HAPs such as dioxin and furan that cannot be measured by continu-ous emissions monitoring systems. NOx and CO reduction tuning includes burners, overfire air (OFA) controls, concentric firing system improvements, control system calibrations, and adjustment of combustion zone temperature profiles. Selective catalytic reduction (SCR) and

selective noncatalytic reduction (SNCR) are in-cluded in the NOx tuning requirement.

Work practices include burner and com-bustion control inspection and maintenance, tuning combustion controls, maintaining re-cords of CO and NOx emissions before and after burner adjustments, and submitting reports after each tune-up. The data must be taken while operating at full load or the unit’s predominant operating mode.

The tune-up requires inspection of all burn-er and combustion controls, and cleaning or re-placement of any components of the burner or combustion controls as necessary upon initia-tion of the work practice program and at least once every required inspection period. The inspections include operation such as damper operation, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill per-formance parameters. Also, air-fuel ratios must be calibrated and functioning properly, includ-ing calibration of excess O2 sensors, adjusting OFA systems, changing optimization software parameters, and calibrating associated actua-tors and dampers to ensure that the systems are optimally operated. Burner or combustion control component parts needing replacement that affect the ability to optimize NOx and CO must be installed within three calendar months after the burner inspection.

The work practice and tune-up testing reports must be submitted to the EPA every three years—except for those units that em-ploy neural network optimization software. For those units, the reports may be submit-ted every four years, following MATS imple-mentation in 2015. Depending on the unit specifics, this additional year may produce significant costs savings.

The effect of the work rules on unit op-erations is difficult to quantify at this time. However, the cost of plant testing and outag-es for repairs prior and subsequent to the test-ing will likely be substantial. For example, a one-day outage of a 500-MW coal-fired plant

will result in lost revenue of about $250,000, assuming replacement generation is $20/MWh more expensive.

Optimizing CombustionReal-time combustion optimization systems have demonstrated substantial value for reduc-ing NOx emissions, controlling CO, and im-proving heat rate for over a decade. In addition to improved emissions performance, optimized combustion can also reduce opacity, accelerate unit load ramping and load following, reduce tube leakage incidents by alleviating the reduc-ing conditions typically found inside the pri-mary furnace, and reduce slag agglomeration through better management of the fuel gas exit temperature. These problems are often cited as the cause of most forced outages or reduced unit availability and/or capacity.

Modern neural network-based combus-tion optimization technologies have evolved significantly since their introduction in the mid-1990s. Early optimization systems were manpower intensive to sustain targeted im-provements, causing some unit operators to bypass the neural network. Today’s more so-phisticated systems combine neural network–based optimization and model predictive control (MPC) to extract knowledge about the combustion process, determine the opti-mal balance of fuel and airflow in a furnace, and quickly respond to changing conditions.

Neural networks are based on nonlinear, multivariable steady-state models derived from historical unit operating data that iden-tify the best combination of independent op-erating variables that will produce the best possible combustion efficiency and the lowest possible emissions. MPC employs dynamic models used to predict changes that will oc-cur during the next few minutes of operation and anticipate the effects of disturbances. Specifically, these optimization processes directly adjust the unit’s distributed control system (DCS) or other control system to


PLANT AUTOMATION

more consistently position dampers, burner tilts, OFA, and other controllable parameters to continuously minimize NOx and CO. The process of determining the optimal biases and adjusting them accordingly is continuous and occurs in closed loop, without the need for operator action.

Strong Return on Investment There are several important ways in which combustion optimization provides economic and operational value, even if the system is focused on just the optimization of NOx and CO required by the pending MATS work practices. There are inherent boiler efficiency improvements that will be achieved when op-timizing NOx and CO as required by the rule. Figure 1 shows an example of the boiler NOx reduction achieved with neural net combus-tion optimization on a 600-MW coal-fired unit. Note that the average NOx is approxi-mately 19% lower during the 30-day test and there were fewer excursions when the neural net system was engaged.

Units with post-combustion NOx control (SCR and SNCR) experience additional cost savings from neural net combustion optimiza-tion in two significant ways. First, combustion optimization enables boiler controls to more closely match boiler temperatures and NOx profiles to catalyst effectiveness and reagent distribution as each changes over time. Second, combustion optimization will reduce reagent usage by 10% to 20%. Other beneficial side benefits include reduced ammonia slip and minimizing sulfur trioxide conversion (Figure 2). Combined with the typical fuel savings achieved with combustion optimization, the in-vestment in combustion optimization produces a very attractive financial return. Table 1 shows fuel savings and reagent cost savings for two il-lustrative coal-fired units, one a large 600-MW unit with an SCR, and the second a medium-sized 350-MW unit with an SNCR.

Integrated Optimization Boiler optimization, once synonymous with furnace fuel and air mixing, now refers to the integrated optimization of the combustion and sootblowing processes, including the furnace and backpass regions of the boiler. An example of the holistic nature of boiler optimization is seen in the sootblower system. The typical soot-blowing system determines the specific boiler zones to be cleaned and activates the needed blowers and lances through the DCS system. However, boiler cleanliness significantly im-pacts combustion efficiency, and furnace tem-peratures affect ash build up, fouling, and slag formation. The complexity of these interrelated processes must also be considered when the best possible operating economics is the goal.

Resolving these complex relationships is the strength of neural net combustion optimi-zation systems. Heuristic models, representing knowledge in the form of situation-action rules, are the cornerstone of the neural net combus-tion system. Instead of attempting to fully ex-press every possible operating alternative in a physical control system (an impossible task), heuristic models use expert knowledge gleaned from the plant data historian and plant opera-tor experience to represent situations in which

plant operating experts know how best to react. These rules can be systematically applied by an inference engine, which automatically ranks a set of possible actions described in the form of situation-action rules and selects the optimal action. In the sootblower example, the rule set would determine when and where to perform the next sootblowing operation so the overall unit operation is cost-optimized. Expert rules can also be used to address challenging discrete changes in plant operations, such as determin-

1. Demonstrated advantage. The figure illustrates measured NOx produced (horizontal scale) under the same operating conditions when the neural network is engaged (right) and when removed from service (left). The data shown was taken at equivalent load, coal quality, and ambient conditions. The vertical scale is percentage of time the boiler operates at the pre-scribed concentration of NOx. Courtesy: NeuCo Inc.

2. Reduced operating costs. Ammonia flow required to meet a 90% NOx removal set-point (vertical axis) over one year is illustrated with the neural net combustion optimizer enabled (right) and secured (left). The horizontal axis is unit load. Source: NeuCo Inc.


PLANT AUTOMATION

ing the most economic combination of pulver-izers to put into service at a particular load.

The expert rules have become much more sophisticated in recent years and today there are processes that “extract” knowledge from experi-enced operators with intimate knowledge of the operation of a particular unit. These rules can now be reflected in software so the knowledge is permanently stored yet easily retrievable. The expert rules approach can then be seamlessly combined with neural networks, MPC, first-principles equations, and other methods in the best possible combination to solve a particular problem, such as an integrated boiler combus-tion optimization system.

Optimize Back-End Systems TooIntegrated unit optimization must go beyond boiler optimization. Other plant operations must be considered in order to substantially increase the efficiency, availability, and emis-sions benefits obtained though combustion optimization. For example, boiler optimiza-tion will impact flue gas temperatures, stoi-chiometry, and unburned carbon in the flue gas that will in turn impact FGD sorbent and reagent use, and therefore the effectiveness of the FGD used for control of HAPS under MATS. The same may be said of reagents,

such as activated carbon, injected directly into the boiler or flue gas for mercury removal.

The variable costs for these reagents can be quite high, particularly those injected directly into the flue gas. The emissions removal ef-ficiency can be improved considerably by op-timizing the injection rates of these chemicals in response to not only load, but also the very same operating parameters addressed with boiler optimization. The best unit combustion optimization system must consider tradeoffs between boiler efficiency, NOx levels, reagent use, and sorbent costs in order to minimize total operating costs while adhering to emis-sions and operational constraints.

MATS adds another layer of complexity for operators of coal-fired plants beginning in 2015, so now is the time to begin developing a compliance plan. A neural net combustion op-timization system is the only holistic tool avail-able that will help ensure MATS compliance while at the same time paying for itself through improved plant operating efficiency. An intan-gible yet valuable side benefit is reducing the testing and administrative reporting expense that comes with MATS compliance. ■

–Peter Spinney ([email protected]) is di-rector of market and technology assessment

for NeuCo Inc. His background includes more than 25 years of combined electric

power generation, economics consulting, and government agency experience.

Operating and economic data Typical 600-MW plant Typical 350-MW plant

Net capacity (MW) 555 333

Capacity factor 75% 60%

Annual output (MWh) 3,646,350 1,747,620

Boiler type Tangential Opposed

Design heat rate (Btu/kWh) 9,850 10,000

Annual heat input (mmBtu) 38,828,700 18,396,000

Fuel cost ($/mmBtu) 2.00 2.00

Annual CO2 output (tons) 5,379,686 1,575,776

Annual fuel cost $77,657,400 $36,792,000

Heat rate improvement -0.375% -0.375%

Annual fuel savings $291,215 $137,970

Baseline average boiler NOx (lb/mmBtu) 0.19 0.2

Baseline annual NOx (tons/year) 3,592 1,840

Nominal SCR/SNCR NOx reduction 90% 90%

Reagent cost ($/ton NOx) 3,009 500

Annual NH3 cost reduction $110,874 $82,782

Total combustion optimization savings $402,090 $220,752

Table 1. Operating cost savings. This table shows fuel and reagent cost savings for a 600-MW unit with selective catalytic reduction and a 350-MW unit with selective noncatalytic reduction with neural net combustion optimization, both burning Powder River Basin or other subbituminous coal. The simple payback for the 600-MW unit is less than one year, based solely on fuel and reagent cost savings. The cost savings that result from avoided MATS tune-ups and avoided slagging and waterwall tube corrosion are unit-specific but will further reduce the pay-back period, as will the cost of NOx allowances, if required. Source: NeuCo Inc.

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CyberseCurity

NIST Cybersecurity Framework Aims to Improve Critical InfrastructureYet another standard? No. What you’ll see this month is a tool designed to bring to-

gether all the relevant cybersecurity standards and put them in an appropriate context—a framework—so you can manage cybersecurity risk more effectively. (And yes, managing that risk is everyone’s business, regardless of job title.)

Steve Mustard

A year ago, on Feb. 12, 2013, Presi-dent Obama issued Executive Order 13636, titled “Improving Critical

Infrastructure Cybersecurity.” The Execu-tive Order instructed the National Institute of Standards and Technology (NIST) to de-velop a voluntary Cybersecurity Framework that would provide a “prioritized, flexible, repeatable, performance-based, and cost ef-fective approach for assisting organizations responsible for critical infrastructure services to manage cybersecurity risk.”

The definition of “critical infrastructure” in the Executive Order is: “Systems and as-sets, whether physical or virtual, so vital to the United States that the incapacity or destruction of such systems and assets would have a debil-itating impact on security, national economic security, national public health or safety, or any combination of those matters.”

As everyone working in the power industry understands, power generation and transmission assets are part of that critical infrastructure.

The State of CybersecurityGiven the availability of a variety of stan-dards for cybersecurity management, ques-tions have been raised as to why an official Cybersecurity Framework is required. Fur-thermore, many of these standards have been in existence for many years, and a popular belief is that the requirements of these stan-dards are being followed, so additional, simi-lar standards will not help.

Unfortunately, the data show that even if current standards are being followed, they aren’t providing sufficient protection. There are many publically available reports on cy-bersecurity attacks, and there has been a com-mon theme throughout them for the past few years, exemplified by these statistics from Verizon’s breach reports of 2012 and 2013:

■ 97% avoidable with basic or intermediate security controls (2012)

■ 92% discovered by a third party (2012)■ 20% of network intrusions involved man-

ufacturing, transportation, and utilities (2013)

■ 76% of network intrusions exploited weak or stolen credentials (2013)

The Verizon report (you can down-load it here: www.verizonenterprise.com/DBIR/2013/) used data from 19 global organi-zations, including law enforcement agencies, national incident-reporting agencies, research institutions, and private security firms.

The Repository of Industrial Security Inci-dents (RISI) produces an annual report that fo-cuses specifically on industrial control systems (ICS), and these reports provide conclusions similar to those from Verizon. The 2013 RISI annual report stated that 33% of all ICS inci-dents were perpetrated using remote access.

The Verizon report from 2012 provides stag-gering temporal statistics relating to cybersecu-rity attacks. In 2012, 75% of attacks took just minutes to result in an organization being com-promised; however, 54% of these compromises took months to be discovered (and, as noted, 92% of these discoveries were not by the orga-nization itself). Even after this lengthy delay, in 17% of cases, it took months before restoration was achieved after the breach discovery, and in 38% of cases it took weeks.

The statistics from Verizon cover all sec-tors and industry types. Within industrial au-tomation–oriented sectors the situation varies considerably. Many such organizations have mandatory cybersecurity standards—such as North American Electric Reliability Corp. Critical Infrastructure Protection (NERC CIP) in the power industry—and their cybersecuri-ty management programs are good. However, many organizations that have a potentially high impact on the critical infrastructure (for instance, water and wastewater organizations) have a much lower degree of cybersecurity management adoption (Figure 1).

There are many reasons for this situation, and they include:

■ Lack of awareness in organizations, in

particular at the top of the organization.■ Misunderstanding the level of risk an

organization has (for example, thinking “that only happens to other companies” or “this has never happened before”).

■ Inability to quantify the risk in likelihood or impact terms, resulting in inappropriate level of investment.

■ Lack of adequate training in cybersecurity good practice, especially in regards to basic controls such as good password manage-ment, backups, and malware protection.

The purpose of the NIST Cybersecurity Framework is to help tackle some of these issues. The Cybersecurity Framework is not another standard. Instead, it is a high-level concept that brings together relevant standards and sets them in an appropriate context.

The Cybersecurity Framework ProcessFollowing the Executive Order announce-ment in February 2013, NIST issued a request for information. More than 245 re-sponses were received from asset owners, product vendors, and consultants from all

1. Cybersecurity standards adop-tion. The adoption of cybersecurity stan-dards in the power industry may be higher than in some other sectors, but the impact of a compromised system is the highest. Source: Steve Mustard


CyberseCurity

industry sectors. NIST then arranged a series of five workshops from May through No-vember last year at various locations around the country. At these workshops, typically 350 to 400 attendees representing asset own-ers, product vendors, and consultants debated various aspects of the Framework; between the workshops, NIST reworked the gathered information into new drafts.

The initial meetings focused heavily on information technology (IT) systems and the protection of data and information. Many attendees were unaware of the specif-ic issues associated with ICS or operational technology (OT) systems where protection is required:

■ Loss of system availability■ Process upsets leading to compromised

process functionality, inferior product qual-ity, lost production capacity, compromised process safety, or environmental releases

■ Equipment damage■ Personal injury■ Violation of legal and regulatory re-

quirements■ Risk to public health and confidence

The Automation Federation, along with a number of asset owners with OT depen-dencies, worked throughout the workshop process, raising awareness of these issues to ensure the Framework properly addresses them.

A draft of the Cybersecurity Framework was issued at the end of October 2013 for public comment. After a 45-day comment period, NIST will take the comments and produce a final version for issue in February 2014 (after this issue goes to press).

Once issued, the Cybersecurity Frame-work enters an ongoing maintenance and up-keep cycle to reflect changing circumstances and feedback from users.

How the Framework Can Help Your OrganizationThe Cybersecurity Framework consists of three key parts:

■ The Framework Core■ The Framework Profile■ The Framework Implementation Tiers

The Framework Core (Figure 2) helps pro-vide an overview of the set of cybersecurity management activities that an organization is performing (or should be performing). Start-ing with five functions—identify, protect, detect, respond, and recover—the Core is divided into categories (such as asset man-agement, risk management, awareness, and training) and subcategories (such as investi-

gate anomalies and perform forensics). Ref-erences (to sector, national, or international standard requirements or clauses) are then listed with these subcategories.

The Framework Profile (Figure 3) helps organizations quantify their desired outcomes when implementing the Framework Core. A “Target Profile” will show what the organi-zation aims to achieve in terms of industry standards and common industry practices.

The organization can then compare its “Cur-rent Profile” (what it is currently implement-ing and following) against the Target Profile to produce a gap analysis.

The Framework Implementation Tiers (Figure 4) help define how cybersecurity is managed within an organization. There are currently four tiers—partial, risk-informed, risk-informed and repeatable, and adaptive—which require increasing levels of rigor and

Framework Core

Categories Subcategories Information references

IdentIFy

ProteCt

deteCt

resPond

reCover

Asset management, risk management, awareness and training, etc.

IeC62443/IsA99, Iso027001, nIstsP 800-53, etc.

Investigate anomalies, perform forensics, etc.

2. The Cybersecurity Framework Core. Source: NIST

Current Profile

Category/Subcategory



.

.

.


target Profile




.

.

.


Gap Identification




.

.

.


3. Gap analysis. Using the Framework Profile helps to identify gaps in an organization’s cybersecurity implementation plan. Source: NIST


CyberseCurity

sophistication to achieve. In general, the aim is for organizations to move from informal processes, which are not widely deployed in their business, to a culture of good cyberse-curity practices supported by formalized and adaptable processes.

The Cybersecurity Framework will not automatically make an organization secure from cybersecurity threats. However, adopt-ing the Cybersecurity Framework will help organizations be better prepared to deal with these threats, by providing:

■ A high-level structure for an organiza-tion’s cybersecurity management process.

■ A focus on the appropriate application of standards.

■ A view of an organization’s cybersecurity management maturity.

■ A common cybersecurity vocabulary.■ A clear statement to help senior manage-

ment understand what their organizations need to be doing.

■ Possible government incentives for adoption.

The intention of the Cybersecurity Frame-work in its current form is to help raise the overall level of cybersecurity preparedness across all sectors and businesses. This is especially important for those organiza-tions that have so far done very little in this area. Even organizations that already have well-established cybersecurity management programs can benefit from adopting the Framework.

Electricity Sector ExampleFor a draft illustrative framework example for electricity sector industrial control systems, see http://1.usa.gov/1c3d3mx. The example acknowledges that this industry needs to ac-

commodate a variety of legacy equipment that “requires special consideration when implementing cybersecurity practices.”

The example also notes that, “Within the electricity subsector there are many stakeholders, including users, owners, and operators of the national power grid, as well as vendors, regulators and other interested parties. As such, there are many existing programs, guidelines, and standards, to leverage when creating a Framework Profile. Moreover, some orga-nizations need to adhere to mandatory cy-ber security standards, such as the NERC CIPs. This Profile is written to be flexible and adaptable to different sizes and types of organizations within the electricity subsector, regardless of compliance obli-gations or existing programs.”

What Should Organizations Be Doing?Regardless of how well-established an or-ganization’s cybersecurity management program is, those with management respon-sibility should:

■ Map out existing cybersecurity processes in the organization to produce a current profile.

■ Review recommended industry, national, and international standards and identify a target profile that the organization should be following.

■ Perform a gap analysis of the current pro-file against the target profile to identify ac-tions to be undertaken to achieve the target profile.

■ Review the actions and the target profile and either confirm or revise the target pro-file and required actions to achieve this revised profile.

■ Raise awareness of cybersecurity manage-ment processes and procedures throughout the organization.

■ Identify cybersecurity information-shar-ing channels within the sector and begin the process of establishing cybersecurity information-sharing processes.

In addition, organizations should con-sider engaging (if they have not already) in the Framework development process to help ensure that the Cybersecurity Framework re-mains relevant and valuable.

Next StepsThe Automation Federation has been ac-tively involved in the development of the Cybersecurity Framework, helping to ensure that a focus is maintained on OT systems and ensuring that appropriate stan-dards, such as ISA/IEC62443 (Industrial Automation and Control Systems Secu-rity), are applied.

On completion of the workshop phase of development, the Automation Federation and its member organizations are working with the White House and NIST on a series of tabletop exercises and seminars across the country to brief industry about the importance of adopting the Cybersecurity Framework. In addition, the Automation Federation’s cyber-security subject matter experts will continue to be engaged in the Cybersecurity Frame-work development process. ■

—Steve Mustard ([email protected]) is an industrial control

system and cybersecurity consultant. He is a Certified Automation Professional,

member of the ISA, Fellow of the Institu-tion of Engineering and Technology, and

a member of the Automation Federation’s Government Relations Committee.

PartialNot formulated/ad-hoc

Limited awareness of cybersecurity risk

Limited ability to collaborate with other organizations for cybersecurity risk management

Risk-informedRisk managementpractice not organization-wide

Awareness of cybersecurity risk withinformal sharing ofcybersecurity informationwithin organization

No formal interactionwith other external organization forcybersecurity riskmanagement

Risk-informed and repeatableFormal risk managementprocess

Organization-widemanagement of cybersecurity risk

Receives informationfrom external organization and usesthis in risk managementdecisions

AdaptivePractices adapt based onlessons learned andpredictions

Cybersecurity risk management is part ofthe culture

Two way sharing of information with externalorganizations

Increasing rigor and sophistication

4. Move your organization forward. The Framework Implementation Tiers require increasing levels of rigor and sophistication. Source: Steve Mustard


Power Policy

Texas and the Capacity Market DebateThe odds that the Texas electricity market will undergo change this year are high.

Despite the promise of low costs in an energy-only market, that market alone is providing insufficient incentives for the reserve capacity needed by the state’s growing population and economy.

Kennedy Maize

On Feb. 2, 2011, a winter storm gripped the Lone Star State, bringing freez-ing temperatures and heavy ice loads

onto the state’s electric infrastructure. Texas experienced a series of unexpected rolling blackouts. That circumstance changed the dynamics of energy policy in the state, along with the shape of energy politics. The out-ages raised the issue of whether Texas should implement a capacity market along with its long-functioning energy market, to ensure adequate electricity to consumers.

In the 2011 outage, more than a million Texas customers lost service, some for ex-tended periods. More than 200 power plants shut down under ice loads and complica-tions of cold temperatures, including frozen coal piles at generating stations. The Elec-tric Reliability Council of Texas (ERCOT), the state’s wholesale electric market, scram-bled to find adequate supplies of electricity (Texas has sparse interconnections to the rest of the U.S. grid), and short-term elec-tricity prices soared.

As the crisis passed, Texan electricity bof-fins scratched their heads (after removing their Stetsons, of course) and began think-ing about an aspect of the state’s wholesale market that is different from several of the other large electricity markets that have come to dominate over half of the U.S., in-cluding PJM Interconnection (PJM) in the Middle Atlantic states, the Independent Sys-tem Operator-New England (ISO-NE), and the New York Independent System Operator (NYISO). What those big markets have im-plemented, and what Texas so far lacks, is a market for electric capacity, or potential elec-tricity supply, to exist alongside the conven-tional market for energy supplied each and every day (see sidebar “Capacity and Energy in Electricity Markets”).

Restructured Markets and the Disappearing ReserveA little explanation is in order for those not

deep into the weeds of electricity market eco-nomics. For those who already get it, please bear with us.

In traditional regulated monopoly mar-kets, which dominated the U.S. until around the turn of the 21st century and which still prevail in much of the Southeast and West, state regulators require utilities to carry a re-serve margin—generation in excess of what’s needed to meet day-to-day needs. This means backup electric generating plants, paid for by customers, which are ready to kick in when it looks like the utility is going to be stressed by weather or other events to meet its cus-tomers’ needs for electricity. This amounts to generating inventory.

Inventory is expensive. That’s a fact for most businesses (and one of the motivators of online commerce). But too little inventory is also expensive, in terms of lost sales and lost customers. In electricity markets, blackouts are devastating in terms of economic costs and political impacts. Though most electricity cus-tomers pay no notice when the lights go on as expected, they often raise a ruckus when the lights go off unexpectedly. No utility distribu-tion company wants to go before its regulators to try to justify hundreds of thousands of cus-tomers sitting in the dark for hours, days, or weeks. And those customers have no choice about seeking other suppliers. It’s often a toxic political environment for the suppliers.

Capacity and Energy in Electricity MarketsWhat’s the difference between “capacity” and “energy” when it comes to electricity markets, and does it make a difference? That question is a key to understanding the debate about how to structure the organized wholesale competitive markets that now provide electricity to more than half of U.S. customers.

Capacity is the amount of electricity a plant can deliver when it is operating at full power. For example, a nuclear power plant typically has a capacity of 1,000 MW. A wind plant may have a capacity of something on the order of 100 MW. But those numbers can be misleading, as the nuclear plant’s capacity is available around the clock, while the wind plant’s capacity varies based on whether the wind is blowing and how fast.

The U.S. Energy Information Adminis-tration defines capacity as “the maximum electric output a generator can produce under specific conditions. Nameplate ca-

pacity is determined by the generator’s manufacturer and indicates the maximum output a generator can produce without exceeding design thermal limits.”

On the other hand, energy is the amount of electricity generators actually provide to the grid and is available to be used at any moment. Organized wholesale electricity markets buy and supply electricity instanta-neously. That’s energy. They buy capacity as backup, or inventory, in case of shortages.

The PJM Interconnection, which has the most mature and robust energy and capacity markets for electricity, dating back some 75 years, offers this definition of capacity versus energy markets: “En-ergy markets are used to coordinate the continuous buying, selling, and delivery of electricity. Capacity markets provide incentives that are designed to stimulate investment both in maintaining existing generation and in encouraging the devel-opment of new sources of capacity.”


Power Policy

In the pre-restructured world of electricity, the cost of inventory—excess generating ca-pacity—was simply folded into overall rates; customers never really saw those expenses of backup power. Supporters of competitive markets assert that the result of the old sys-tem was too much excess capacity, or power inventory, also known as “gold plating.” The utilities were able to reap a return on the in-vestments in inventory, which encouraged them to stockpile generation. The more they spent, the more they earned.

Then competitive electricity markets came along, beginning with Federal Energy Regulatory Commission (FERC) Order 888. One of the questions arising from the com-petitive world of electricity procurement was how to handle reserves. When restructuring and competitive markets kicked in, driven by FERC policies, the new markets had to decide how to deal with the issue of backup power, or capacity. One choice, which Texas took, was to rely on daily energy markets to supply the needed power. Markets would de-termine how much inventory to carry. Texas had always enjoyed an excess of electric sup-ply, and there was no obvious reason in 1995 to expect that would change. Its restructured market, among the most aggressive in the country, elected to face shortages rather than paying for excess generation.

In the East, where a massive blackout in 2003 hit some 50 million electric customers from Canada to New Jersey, the new regional transmission organizations (often created out of long-standing existing power pool sharing agreements such as PJM) decided to structure competitive markets for both energy and ca-pacity (see sidebar “PJM’s Capacity Market”). PJM, ISO-NE, and NYISO now conduct auc-tions for generators to bid to supply backup power supplies to the energy market. The ba-sic concept is that market prices from capacity auctions will be high enough to encourage in-vestment in new electric generating plants and to encourage large consumers of electricity—or companies that can aggregate small users into large consumers—to reduce their use. This latter concept is “demand response” in electricity industry argot. In the capacity mar-kets, large consumers and aggregators of load can bid demand response into the markets on the same basis as generation. FERC blessed this concept in its Order 745 in 2011.

Texas decided to keep the prices that con-sumers must pay for electricity lower by avoiding capacity costs. The choice between an energy-only market and a capacity market is clearly a matter of money.

A FERC technical conference last fall explored the cost implications—expressed as the “missing money”—of introducing capacity costs into the wholesale cost of en-

ergy. The “missing money”—as economist David Patton, market monitor for both ISO-NE and NYISO, explained—is the differ-ence between the levels of excess capacity that an energy-only market would provide (probably in the range of 7% to 10%) and the higher planning levels that most electric system operators want to see (in the range of 17%).

The substantial costs of buying capacity in advance, as opposed to buying energy today, have proven controversial. In the PJM region, both Maryland and New Jersey state regula-tors and their governors objected to the higher costs of PJM’s inventorying capacity at mar-ket rates. The public service commissions in both states hatched schemes to use taxpayer funds to subsidize new gas-fired generating plants that would bid into the PJM capacity market. The states perceived that the prices awarded in the market’s auction were too high and the state-subsidized plants would win in the auction and lower costs of future generation. But PJM and FERC objected, arguing that the state subsidies would drive down bids in the capacity market auctions because the subsidized plants would drive out nonsubsidized competitors.

Federal courts in both states last year nixed the Maryland and New Jersey plans, saying that the federal government was in control of these interstate markets and FERC had blessed the capacity purchases. The legal

presumption that federal agencies have rights that trump state regulatory commissions blocked both Maryland and New Jersey. As is often the case when it comes to the opera-tion of sophisticated wholesale competitive markets where state-regulated monopolies once prevailed, considerable contention re-mains about the need for capacity markets. In overturning the New Jersey and Maryland

attacks on FERC, the courts didn’t address the economics in play in the debate over ca-pacity markets.

Because buying reserve energy (inven-tory) is expensive, consumer interests often oppose the idea. That’s what motivated the state governments in New Jersey (with a sup-portive Republican governor) and Maryland (with a supportive Democratic governor) to offer their now-illegal options. A paper for the libertarian Cato Institute concludes, “The theoretical case for capacity markets is weak at best. Many of its arguments depend on oversimplified assumptions that are at vari-ance with reality, particularly those that are necessary to produce the missing money phe-nomenon.” But the capacity markets in play in the Northeast and Middle Atlantic states are working, a powerful argument for their wider use.

Texas Bucks Capacity MarketsThe issue of capacity markets has now landed squarely in Texas, where the three-member

PJM’s Capacity MarketThe PJM Interconnection, which covers a wide swath of the U.S. from New Jersey to Ohio, has the most robust and developed capacity market among the organized wholesale electricity markets. Known in-ternally as the “reliability pricing model,” the PJM capacity market rests on an auc-tion each year to reserve capacity three years ahead. As PJM describes it, “PJM’s capacity market provides forward pricing signals to encourage retention of exist-ing resources and development of new resources in the PJM region. Adequate capacity resources are required to sup-port the reliability and stability of the

electric grid for consumers’ demand.”The most recent PJM capacity auc-

tion last May produced good results for the wholesale market, drawing a record amount of new generation at lower prices than previous sales. “The results of this year’s capacity auction reaffirm that well-designed, mature markets are a power-ful tool for procuring new resources at competitive prices,” said PJM CEO Terry Boston. “Again this year, we see record amounts of new conventional generation and strong showings from renewables and energy efficiency.”

The choice between an energy-only market and a capacity market is clearly a matter of money.


POWER POLICY

Public Utility Commission of Texas (PUCT) is pondering scrapping its energy-only approach in order to include a mandatory reliability margin and an auction mechanism to achieve that margin.

Texas has what can best be described as an “aspirational” reserve margin. The PUCT has established what it wants as a goal for excess generation (somewhere around 14%), but there is no way to require any participants in the ERCOT market to meet that target.

The North American Electric Reliability Corp. (NERC), the na-tional judge of whether the nation has enough electricity capacity to meet its customer demands, has long targeted Texas as a problem. In its December 2013 report, “Long-Term Reliability Challenges and Emerging Issues,” the Atlanta-based group said, “Since 2011, NERC has highlighted resource adequacy challenges in ERCOT.”

The February 2011 blackouts (which came on the heels of a 2006 summer set of politically fraught rolling blackouts), sparked Donna Nelson, PUCT chairman, to push for a Texas ca-pacity market. Nelson, a lawyer, was Gov. Rick Perry’s advisor on energy and telecommunications issues when he named her to the powerful PUCT in 2008 and chairman in July 2011, after the February energy crisis. She quickly concluded that Texas should implement a capacity market to provide needed backup power to prevent future blackouts.

She also quickly ran into opposition from fellow PUCT Commis-sioner Kenneth Anderson, also a Perry appointee and a lawyer. He has argued forcefully against a capacity market for Texas. In testi-mony to a state Senate committee recently, Anderson said, “A manda-tory capacity reserve margin will result in billions of unnecessary, unavoidable and largely un-hedgeable costs to customers, without guaranteeing rolling blackouts will not occur.”

He’s had support from Texas business interests and the Dallas Morn-ing News. The newspaper has said that arguments by power generators

that they need a market for their services are bogus. “That’s nonsense, and a scare tactic designed to get a payday from consumers,” said the editorial. “PUC Commissioner Ken Anderson recently suggested as much, challenging industry claims that Texas would lose $14 billion over the next decade and a half because of power outages.”

Nelson and Anderson butted heads for two years on the issue of a capacity market for Texas. A vacancy on the three-member PUCT pre-vented action. But last August, Perry filled the vacancy on the regula-tory commission with Brandy Marty, who had been his chief of staff. She is also an attorney and was a budget and planning guru for the Perry administration before becoming his chief of staff. Although she has not made her views known on the capacity market, many analysts expect she will be the deciding vote to break the Nelson-Anderson deadlock in Nelson’s favor.

The policy debate in Texas is coming to a head in early 2014, after much political maneuvering at the end of last year, according to many observers.

Opponents of a capacity market have argued, as does PUCT Com-missioner Anderson, that the costs of reserve capacity in a formal market are too high. That’s won support from the Texas Association of Manufacturers, which consists of large electricity users. Their chief, Tony Bennett, argued in the Dallas Morning News that “a ca-pacity market assumes worst-case, hypothetical scenarios, and all existing power generators receive the same subsidy payment, regard-less of whether their power is ever needed or used.” His group has proposed an alternative, which he calls a “Supplemental Reserve Service.” Under this plan, ERCOT “would determine the amount of additional power that needs to be purchased, say during the summer, and would provide payments only to those generators who provide the additional power.”

Bennett’s proposal, as outlined in the press, appears to duck the issue of how much ERCOT might pay for the reserve power and the terms and conditions under his alternative. As a practical matter, it appears Bennett’s plan could amount to a capacity market by another name.

Capacity Market or Bust?Generators have promoted the idea of a classic capacity market, as implemented in PJM, NYISO, and ISO-NE. Exelon’s John Orr told the Dallas Business Journal, “I need to be sent a signal and have a reasonable expectation of what I’m going to get or I won’t drop a dol-lar here. You have to think what you’re competing against. It’s a world market for money and it’s certainly a national market for money. And every other place is willing to pay you, but not here. You’re gambling here if you’re an investor.”

Today, as the issue moves toward a resolution in Texas, the betting is that Nelson and Marty will approve some sort of plan for a Texas capacity market that resembles what exists in the Northeast. UBS utilities analyst Julien Dumoulin-Smith, one of the savviest savants of electricity markets, recently told his clients, in a private analysis obtained by POWER, “We see ERCOT as repositioning itself strate-gically to make any new capacity market palatable; while clearly on board with the idea in our view, the price ‘must be right.’”

A major indicator will be the release of a report by the con-sulting firm The Brattle Group, which is imminent as this article is being written. Dumoulin-Smith says the report’s recommen-dation of a reserve margin for ERCOT could be crucial for the debate on implementing a capacity market for the state; the rec-ommended margin will determine the overall cost of a market. The lower the suggested margin, the less capacity ERCOT will have to buy and the less impact on overall consumer prices. In any case, he says, Texas is moving toward some form of a capac-ity market for ERCOT. ■

—Kennedy Maize is a POWER contributing editor.

Grading Bob’s 2013 PredictionsDon’t miss former Editor-in-Chief Robert Peltier, PE’s self-grading of his predictions for 2013. They can be found in his blog posts dated 1/6/2014 and 1/7/2014. From the POWERblog area of powermag.com, click “Read the latest” to find the posts.We’ve started a discussion about his predictions and grades on the LinkedIn POWER magazine group. Comment there if you agree or disagree with his grades!Bob’s predictions ranged from issues concerning likely U.S. federal regulations to natural gas prices. His overall grade? “My grade average works out to 3.53, which is barely equivalent to an A- this year, my highest score to date. Making the Honor Roll for 2013 was an excellent way to end the year.”

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renewables

Japan Ramps Up RenewablesAlready planning a major expansion of its renewable capacity, Japan has been

forced to redouble its efforts with the loss of its nuclear fleet after the Fu-kushima Daiichi disaster. Though an array of obstacles stand in its way, the nation hopes to triple its renewable output by 2030.

Thomas Overton

In 2010, intent on continuing its commit-ment to energy efficiency and preventing climate change, Japan enacted its second

Basic Energy Plan. The new policy docu-ment, revising the first, from 2003, called for dramatic increases in both nuclear genera-tion and renewable energy, all with an eye to-ward reducing the nation’s carbon emissions 25% below 1990 levels by 2020. Renewable generation was to increase from 9% (almost entirely hydroelectric) to 20% by 2030. Non-hydro renewables would be supported by expanding the existing feed-in tariff (FIT) system, established in 2009 to support small-scale solar photovoltaic (PV), to include wind, geothermal, and biomass. An array of other subsidies, credits, and tax exemptions were planned to support the development of new renewable technologies.

Japan has long been one of the leaders in renewable energy, both in innovation and in installed capacity. Its domestic solar PV in-dustry, led by electronics giant Sharp—then the world’s largest manufacturer of solar panels—expected to supply growing demand worldwide for many years.

Much of this changed on March 11, 2011.Though Japan’s nuclear industry sus-

tained the lion’s share of the upheaval fol-lowing the Tohoku Earthquake and tsunami,

and the subsequent disaster at the Fuku-shima Daiichi nuclear plant, those changes have also forced Japan to reassess its plans for renewable generation.

Much, however, has not changed. Japan re-mains a nation with limited resources that must import more than 90% of its energy needs. Its economy, still the third-largest in the world, is stagnant, mired in a two-decade period of flat-to-negative growth in GDP. But its manufac-turing sector remains one of the world’s most advanced, and strong government and social support for energy efficiency means the na-tion’s electricity consumption has been level for the past decade, with total generation for 2012 virtually the same as 2002 levels, accord-ing to the Federation of Electric Power Compa-nies, the association of the country’s 10 utilities (though this also reflects the fact that Japan’s entire nuclear fleet remains offline).

Current Policies and ProblemsThe 2010 Basic Energy Plan, which was scheduled to begin taking effect last year, has undergone repeated revisions. The pre-vious government, led by the Democratic Party of Japan, had planned for a complete phase-out of nuclear by the 2030s combined with an aggressive focus on renewables. The new Liberal Democratic government, led by

Prime Minister Shinzo Abe, has backed away from a nuclear retreat, saying in December that nuclear would remain an important part of the nation’s energy mix and that Japan will only seek to reduce dependence on nuclear “as much as possible.”

The most recent draft policy envisions the nation reaching 25% to 35% renewable gen-eration by 2030. The revised FIT system went into effect in 2012 and sets fixed prices that utilities must pay for renewable generation. The initial tariff for solar—¥42/kWh ($0.40/kWh) over a 10-year period for small sys-tems and over 20 years for those larger than 10 kW—was originally about twice that for wind (¥23.10/kWh), though it was reduced in April 2013 (to ¥37.8/kWh).

These generous subsidies, which are sub-stantially higher than those offered elsewhere, such as in renewable-friendly Germany and Sweden, have led to a boom in solar con-struction (Figure 1), resulting in an estimated 5 GW of new capacity added in 2013. As of July, the government had approved 23 GW of new solar projects, nearly all of it since the new FIT came into effect.

Still, there are substantial barriers in the way of reaching the ambitious 2030 targets.

Perhaps the biggest challenge is where to site all this space-intensive generation in a mountainous country that is one of the most densely populated industrialized nations in the world. The lack of space elsewhere has meant many new large projects are being sited in the less-populated north, particu-larly on the island of Hokkaido. The recent crush of applications for power sales—amounting to 25% of all projects approved nationwide—has overwhelmed Hokkaido Electric Power Co. (HEPCO), leading to de-lays in processing.

The need to site so much generation so far from population centers in the south has also led to concerns about transmission ca-pacity. HEPCO complained last April that it had received applications for four times as much new capacity as its grid is capable of handling. The problem is so acute that the country’s Ministry of Economy, Trade and Industry (METI) has allocated nearly $300

1. Sunny skies. The 10-MW Komekurayama Solar Power Plant in Kofu, built by Tokyo Elec-tric Power Co., came online in 2012. Courtesy: Sakaori


Renewables

million to build what will be the world’s larg-est storage battery for HEPCO. The 60-MW battery, due to come into service in 2015, will boost HEPCO’s ability to accommodate in-dependent generation by an additional 10%.

Elsewhere, many applicants are being de-nied access to local grids because of similar overcapacity. A survey conducted by the Japan Renewable Energy Foundation found that 20% of the respondents were denied access and 37% were approved, but with limited output.

While this is an issue with renewable gener-ation nearly everywhere, it is a special concern in Japan, which operates two separate national grids—one at 60 Hz in the west and the other at 50 Hz in the east—with only limited ability to move power between them. Worse, the 10 regional utilities typically operate as separate systems, only rarely sharing power.

In hopes of addressing these issues, the gov-ernment passed legislation in December that would establish a single national grid company by 2015. The aim is to better align standards and practices across the regional utilities and two grids. METI is also advising developers to seek solar sites outside of Hokkaido.

Cost is another issue. One reason for the high FIT is that prices for installed solar PV in Japan are around twice those in Germany. Land is more expensive, labor costs are high, and limited space for installation often means more sophisticated technology is necessary.

This is a problem despite the fall in solar panel prices, which has wreaked havoc in the nation’s renewables manufacturing sector. Once supplying nearly 90% of Japan’s solar PV demand, domestic manufacturers saw imports—mostly from China—claim a 56% market share last year. The competition has forced Sharp to close three of its four solar PV factories, while Panasonic recently can-celled plans for a new domestic plant, decid-ing instead to site it in Malaysia.

Wind generation has its own set of issues. Though the nation has many areas of good

wind potential, bureaucratic hurdles have slowed development, and the nation currently has only 2.3 GW of installed capacity. New wind projects are required to complete lengthy and complex environmental assessments, which have stalled several large projects, in-cluding a 120-MW facility in Tokyo. Turbines over 100 feet tall are required to incorporate expensive seismic safeguards (though this is the reason most of its existing turbines sur-vived the earthquake unscathed). Even so, the government is hoping that at least 10 GW of wind generation can be added by 2030.

Another problem has been the lack of a con-sistent energy policy. The national government has seen six different prime ministers since 2008, and the frequent shifts in direction, es-pecially since 2011, have created uncertainty about future support for renewables. Industry officials and policy analysts have stressed the need for consistent, long-term policy goals if further progress is to be made. Streamlining approval processes and reducing bureaucratic impediments will also be important.

Current ProjectsJapan’s renewable output is dominated by hydropower, but most of the current develop-ment is focused on solar, with wind running a distant second—though the latter has the most interesting potential.

Solar. More than 90% of Japan’s installed capacity of non-hydro renewables is solar. In 2013, Japan became the fifth country with at least 10 GW of solar capacity. In November, electronics company Kyocera inaugurated what is so far the nation’s largest solar PV plant, the 70-MW Kagoshima Nanatsujima Mega Solar Power Plant in Kagoshima City, at the southern tip of the country (Figure 2). The $275.5 million project, which comprises 290,000 solar panels manufactured by Kyo-cera, is a joint venture between Kyocera and six other companies. The consortium was formed in July 2012, shortly after the FIT

program took effect, and construction was completed in a little over a year.

Larger projects are in the works. Telecom-munications and internet company Softbank, which already operates seven solar energy facilities across the country (though most are fairly small), had plans for three large solar plants in Hokkaido totaling 180 MW. The uncertain situation on Hokkaido forced Soft-bank to scale back the project to 110 MW. Construction was due to start in October, with completion scheduled for 2015.

Meanwhile, last January industrial giant Mit-subishi announced plans to partner with another firm to build an 80-MW solar plant in Tahara City, in Aichi Prefecture southeast of Nagoya. The $221 million project will be built by Toshiba and is scheduled for operation in early 2015.

Wind. Japan’s wind industry has lagged well behind solar. The largest currently op-erating wind farm in the country is the 148-MW Mutsu facility near Kyoto, but only a handful of other projects larger than 50 MW exist. Nevertheless, ambitions are large.

In 2012, Fukushima Forward, a project backed by METI and a coalition of private companies led by Marubeni Corp., began what may one day become a 1-GW floating wind farm off the coast of Fukushima Prefec-ture. The first phase of the project comprised a 2-MW Hitachi turbine mounted on a spar buoy, which began supplying power in November (Figure 3). A floating 66-kV substation, the first of its kind in the world, has also been con-structed. The next phase of the project, slated for March, will comprise two 7-MW Mitsubi-shi Heavy Industry turbines. METI has com-mitted $220 million for the five-year project. If all goes well, the project may ultimately be expanded to 143 floating turbines with a total capacity of 1 GW by 2020.

Despite the technological challenges, ex-perts think floating wind power may have substantial potential for Japan. Though it has many areas of prime offshore wind resourc-es, the continental shelf around Japan is too deep to construct the sort of fixed offshore wind farms common in Europe—more than 80% of its wind potential is in deep water. The seas at the Fukushima Forward site, for example, are around 100 meters deep. ME-TI’s long-term plan is to make Japan a world leader in floating offshore wind power.

Another floating test project has been un-derway off Nagasaki since May 2012. After launching a 100-kW test bed, the project was upgraded with a 2-MW turbine this past fall.

Geothermal. Japan has been producing geothermal energy since 1966 and currently has 17 geothermal plants in operation with a total capacity of 535 MW. Most of them, however, were constructed before 1974, when the national government banned further

2. Biggest for now. The 70-MW Kagoshima Nanatsujima Mega Solar Power Plant is cur-rently the largest solar plant in Japan. Courtesy: Kyocera


RENEWABLES

development out of environmental concerns. Though Japan, with numerous active volca-noes, is thought to have enormous geother-mal potential—as much as 20 GW, according to government research—most of it is found in areas that have been set aside as national

parkland. Japan’s long cultural affinity for enjoying its natural hot springs has made geothermal development highly sensitive.

Even so, pressure from the nuclear shut-down has caused some rethinking. Last March, the government lifted the ban to al-low five new projects to proceed, though oversight is strict.

The FIT for geothermal is currently ¥27.3/kWh for projects over 15 kW. Around 20 oth-er projects are under consideration, though some are quite small.

Hydropower. Hydro has traditionally supplied the bulk of Japan’s renewable out-put, around 70% in 2011. With an installed capacity of 27 GW and 82.5 TWh of total generation in 2011, Japan ranked eighth in the world for hydroelectric production. Almost no new capacity has been added in decades, however, and nearly all of the na-tion’s major hydroelectric potential has al-ready been harnessed. Small-scale projects continue to be developed, but these are not expected to make a meaningful impact on the generation mix.

The future is likely to be in pumped stor-age. Japan has a number of large dams with pumped storage capacity, and three major pumped storage projects are due to come into

service in the next decade. The Kannagawa Hydropower Plant in Nagano is currently about one-third of the way through construc-tion of its six-unit generating plant that will ultimately reach 2,820 MW capacity, with final completion expected in 2020. The 600-MW Kyogoku Pumped Hydro Power Station in Hokkaido is expected to be completed in 2022, and the Kazunogawa Dam in Yama-nashi is adding 800 MW to its pumped stor-age capacity, also by 2022.

OutlookAs this article went to press, METI was still revising the latest Basic Energy Plan, and was expected to present a new draft to a gov-ernment panel in late December. Much of the current debate centers on the role of nuclear, but further efforts to open up the 10 regional power companies to more competition are also under discussion. Meanwhile, the nation burned record amounts of imported coal and liquefied natural gas in November, a situation all parties agree is unsustainable. Whatever direction Japan ultimately takes, a greatly ex-panded role for renewables seems certain. ■

—Thomas W. Overton, JD (@thomas_overton) is POWER’s gas technology

editor.

3. Setting sail. This 2-MW wind turbine off the coast of Fukushima may be the first el-ement of a planned 1-GW floating wind farm. Courtesy: Marubeni Corp.

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The RCTrms-3ph operates from a 12–24 V power supply. The transducer provides a galvanically isolated measurement and uses nonmagnetic materials, which ensures excellent linearity and prevents damage from overcurrents. Typical accuracy is better than 1% of reading from 10% to 100% full scale. (www.pemuk.com)

Urethane-Lined Knife Gate ValveDeZURIK offers a urethane-lined knife gate valve, model KUL, designed for on/off and throttling applications of abrasive slurry and dry abrasive materials. KUL valves feature a one-piece, cast-in-place liner that provides bidirectional, drip-tight shutoff to either 150 or 250 psi. All wetted surfaces of the ductile iron body are lined with urethane. The valves are available in sizes 2 to 48 inches with temperature ratings from –40F to 180F. (www.dezurik.com)

Portable Industrial Emissions AnalyzerThe E5500 combustion analyzer is a complete portable tool for emissions monitoring for regulatory and maintenance use in boiler, burner, engine, turbine, furnace, and other combustion applications. The analyzer includes electrochemical gas sensors for O2, CO, NO, NO2, and SO2, and can have a maximum of five total gas sensors. The standard “EGAS” software package includes the ability to save and graph data in real time in the field with a laptop or in a laboratory with a personal computer.

Temperature measurements for the flue gas and air as well as the differential temperature are standard features. The differential temperature is used as part of the efficiency calculation. An internal pressure sensor allows the analyzer to measure pressure and stack draft. With two pressure inputs, a differential pressure can also be measured. Gas velocity can be measured using the differential pressure and an optional pitot tube. The analyzer comes standard with a complete factory calibration. (www.E-Inst.com)

Opportunities in Operations and Maintenance,Project Engineering and Project Management,

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Employer pays fee. Send resumes to:

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Commentary

James Newcomb Ben Paulos

Are You Ready to Compete with Your Customers?

New technologies and consumer demand for cleaner energy are rapidly transforming the power sector. This transforma-tion is most evident in the advent of distributed energy

resources (DER)—a marriage of information technologies with the power grid. Some call it the internet of electricity.

DER is a package of customer-side technologies including en-ergy efficiency, demand response (DR), distributed generation, storage (both thermal and electric), and smart electric vehicle charging. Thanks to digital controls and wireless communica-tions, these demand-side resources are becoming controllable enough to look to the grid just like a power plant. Supply and demand are becoming interchangeable to grid operators.

As part of America’s Power Plan (americaspowerplan.com), Rocky Mountain Institute looked at the potential for DER and the barriers standing in their way.

Losing ControlThe growth of DER is a wildcard in the power sector. With central-station power plants and transmission lines, regulators have a high degree of control over how much gets developed and where. Even in competitive markets, independent power plant develop-ers are keenly aware of market trends and do not risk billion dol-lar investments lightly.

But demand-side technologies are driven by consumers, who make decisions to meet their own needs, not those of the whole system. As long as efficiency, distributed generation, and smarter controls deliver value to consumers, their use will continue to grow.

How big a contribution can they make? Some examples sug-gest we are in the early stages of a revolution.

A New Type of CapacityThe PJM Interconnection, serving 60 million customers from the Mid-Atlantic to Chicago, has enthusiastically embraced demand re-sponse. With DR, customers respond to calls for conservation and the market price of electricity in real time. Automated controls change the temperature of thermostats, dim lights, briefly turn off water heaters and refrigerators, and otherwise give the grid a break.

DR is an evolution of what utilities have for years called direct load control. But information technology has refined it to be faster, more reliable and transparent, and more attractive to consumers.

Now that DR has become reliable enough to count as a utility system asset, its value has been quantified and an industry of DR aggregators has grown up, led by companies like Enernoc and Comverge. These companies recruit customers, bundle the DR to make it look to the utility system like a power plant, and then sell “negawatts” to the market.

Each year PJM holds auctions to buy capacity three years ahead of time. Starting in 2009, PJM allowed efficiency and DR to compete in the auctions with new power plants. Last May, PJM signed up 169,000 MW of capacity for 2016. Most of this was existing power plants, but for new resources DR was the biggest winner, with 12,400 MW accepted. This was over two times as much as new power plants.

“We can reduce our peak loads in this country by 20 percent using demand response,” according to Jon Wellinghoff, recently retired chair of the Federal Energy Regulatory Commission. “It’s happening and it’s coming very quickly.”

Big customers, like factories and campuses, have been the first to adopt DER technologies. Companies like Amazon, AT&T, and Home Depot are beginning to test products for residential cus-tomers. Meanwhile, Ford has launched MyEnergi Lifestyle with Whirlpool, SunPower, and others to integrate its Cmax Energi electric car with smart appliances and solar, delivering a 60% reduction in energy costs for a typical home.

Paving the Way for InnovationThese innovations no doubt are just the beginning. But they are confronting regulations that are not equipped to incorporate them gracefully.

A paper for the Edison Electric Institute, “Disruptive Chal-lenges,” drew on parallels with the telecom industry to evoke a “vicious cycle” triggered by DER that would undermine util-ity profits. “The threat to the centralized utility service model is likely to come from new technologies or customer behavioral changes that reduce load,” it argued.

In many places the rules penalize utilities with lost profits for every kilowatt-hour not used and for every generator put on the customer side of the meter. Our century-old legal, economic, and regulatory structures are thwarting innovation.

To address the mismatch between evolving electricity system needs and the rules and regulations constraining that system, we recommend the following set of policy changes:

■ Better analysis. Policymakers need to better measure DER costs and benefits to provide a foundation for designing effective incentives, pricing structures, and markets, as well as to compare centralized and distributed options in resource planning processes.

■ Create a level playing field. As long as DER play a different game than centralized options, there will be unintended results that could undermine the quality of service, financial viability, and innovation. We need to put them on the same field, competing fully and fairly, to provide energy and ancillary services.

■ New technologies and service models. Distributed technologies are like square pegs in the round holes of current regulations. Regulators must remove this barrier to innovation by setting up appropriate metering and cost accounting, and allowing in-novative ownership and billing structures. Permitting, financ-ing, and interconnection procedures can all be streamlined to avoid wasted money and effort.

These changes will allow for a graceful transition to the clean-er, more efficient, more resilient, and more affordable future cus-tomers are seeking with distributed energy resources. ■

—James Newcomb is a program director for Rocky Mountain Institute and lead author of “Policy Implications of Decentraliza-

tion.” Ben Paulos is the director of America’s Power Plan.

Register now to reserve your seat at www.energyocean.com

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Dedicated to the Advancement of the Offshore Renewable Energy Market

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