power - june 2014

Jun

e 2014 • Vo

l. 158 • No

. 6

Vol. 158 • No. 6 • June 2014

Be Prepared for 316(b)

How NERC CIP 5 Will Affect Your Plant

Long-Term Effects of Cycling Gas Units

Advanced Combustion Turbine Update

ELECTRIC POWER 2014 Roundup

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June 2014 | POWER www.powermag.com 1

ON THE COVERThe final Clean Water Act Section 316(b) rule will require characterization of organisms subject to impingement. In this photo, collected organisms are being kept alive while they are identified, counted, and measured prior to release. If the final rule calls for optimization of fish-handling systems, impinged organisms may need to be held for one to three days to monitor latent mortality. Courtesy: Mark Mohlmann of Ecological Associates Inc.

COVER STORY: WATER REGULATIONS22 Site-Specific Factors Are Critical for Compliance with Final 316(b) Existing

Facilities RuleNo, cooling towers are not the only option for complying with the long-awaited Clean Water Act regulation of cooling water intake structures at existing power gen-erating plants. However, making the best selection to achieve required rates for both impingement and entrainment mortality require evaluating the range of potential technologies based on a number of highly site-specific factors. Use the guidance provided here to assess the risks and opportunities of the candidate approaches.

SPECIAL REPORT: NERC CIP COMPLIANCE28 Introduction to NERC CIP Version 5

Do you know on which side of the “bright line” your generating facility falls for the new North American Electric Reliability Corp. Critical Infrastructure Protection (NERC CIP) standards? Even if your facility is designated as “Low” impact, you will be required to develop and implement security policies that address four specific areas of concern.

32 Identifying CIP Version 5 Assets in GenerationThe asset identification process in NERC CIP Version 5 is much more complicated than in previous versions. Learn the right ways to identify the cyber assets that are in scope for CIP Version 5.

34 When Old Systems Meet New Realities: Adding Security Controls to Generating PlantsWhether or not your plant falls under the new CIP standards, odds are you need to add or update cybersecurity controls. An engineer who has been there and done that alerts you to likely challenges and best practices.

FEATURES

GAS-FIRED GENERATION

38 Managing the Changing Profile of a Combined Cycle PlantWhen a plant that’s been run in baseload mode has to switch to flexible operation, it’s not just a matter of more frequent starts. From changes in staffing, inspections, and monitoring, to different maintenance practices and alarm management, there’s a long list of things to think about to keep the plant running smoothly.

44 Recent Innovations from Gas Turbine and HRSG OEMs The boom in gas-fired power has manufacturers rushing to fill the demand for new plants, upgrades, and repowering. Whether you’re looking for turbines, steam equip-ment, or better emissions control, it’s a buyer’s market with some exciting develop-ments being introduced.

FUELS

48 HECO Successfully Cofires Biofuel as No. 6 Oil SubstituteIsland power systems that lack indigenous fuels for baseload capacity face unique challenges, especially when they have renewable portfolio goals. Hawaii’s largest generator seems to have found one viable option for flexible, cleaner fuel use.

Established 1882 • Vol. 158 • No. 6 June 2014

22

44

In this web exclusive (associated with

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Primary systems

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www.powermag.com POWER | June 20142

WORKFORCE

54 New Technology Is Key to Recruiting New Power WorkforceOur update on workforce trends in the power sector finds that training in new plant technologies as well as training that uses technology are both essential to engage a much-needed new generation of workers.

ELECTRIC POWER 2014 ROUNDUP

64 Lessons in Resiliency and RiskELECTRIC POWER 2014 in New Orleans began with keynote presentations by Rod West, Entergy’s executive in charge of risk mitigation and disaster response, and Microsoft’s Brian Janous, who is driving energy strategy for one of the nation’s larg-est and most innovative electricity self-generators. What they shared has relevance for every reader of this magazine.

66 Veterans Bring Needed Skills to the Utility IndustryNew this year at ELECTRIC POWER: the Faraday Awards to recognize employers, programs, and partnerships that have successfully elevated the careers of American veterans in the electricity industry.

70 The Word for Gas Is “Flexibility”Yes, “flexibility” is a now-familiar marketing pitch for gas-fired generation, but pre-sentations in the gas track included discussion of some new ways of delivering flex-ibility via operation, design, and technology innovations.

72 Fuel Flexibility Is the Gift That Keeps GivingIf the word for gas is “flexibility,” the phrase for coal is “fuel flexibility.” Careful fuel blending can deliver lower costs and increased profits for coal plants competing against gas and renewables.

74 The Dynamic Challenge of Integrating Variable ResourcesBy now, it’s common to assume that gas-fired generation is the best way to firm up variable renewable resources, but overreliance on gas poses its own problems. Could a new energy imbalance market be part of the solution?

76 Just Hop on the Bus, Gus: 13 Ways to Hack a Power PlantThose who think that power plant cybersecurity isn’t their concern are the most likely to make their plant most vulnerable to attack. Don’t be the weakest link in the security chain.

DEPARTMENTS

SPEAKING OF POWER6 Who’s Talking About Climate Change?

GLOBAL MONITOR8 Europe Moves to Phase Out Renewable Subsidies8 Power Sector Link to Water Is Deep, Complex10 China Starts Construction of HTR Demonstration Plant12 THE BIG PICTURE: Power Plus14 NYISO Opens Smart Control Center14 POWER Digest

FOCUS ON O&M18 Robust Bearings Tested for Brazil’s Belo Monte Hydro Project18 New Enclosure Solution Enables Remote Monitoring of Battery Backup Systems

LEGAL & REGULATORY20 FERC Takes First Steps in Harmonizing Gas and Electricity Markets

By Thomas W. Overton, JD

COMMENTARY84 MISO Prepares for Hurricane Season

By Todd Hillman,Vice President of MISO South

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SPEAKING OF POWER

Everyone, it seems. From Bloomberg Businessweek to Rolling Stone, from ELECTRIC POWER (EP) to Platts Global

Power Markets conferences, this spring ev-eryone was talking about climate change. The topic is no longer taboo, even among executives of power companies.

More than a dozen years ago, former BP CEO John Browne may have been among the first in the energy industry to talk publicly about the threat of climate change and industry’s responsibility to participate in addressing that threat, but these days, there are few climate change deniers among industry leaders. Even when they disagree about the degree to which human activity causes climate change or express legitimate concern about the costs of reducing emissions of greenhouse gases (GHGs), those responsible for both quarterly earnings and long-term business sustainability (both economic and envi-ronmental) are learning first-hand why they need to both talk about and act in response to climate change.

Recent media and event coverage of the matter has had as much to do with responses to climate change effects as with national and international climate reports or anticipated U.S. Environmental Protection Agency (EPA) GHG rules. While regulatory entities develop GHG-reduction policies aimed at limiting climate change, countries, utilities, and enterprising com-panies are already making adaptive chang-es in response to current climate change consequences. Some may profit; others will pay.

Talking Winners and Losers“The world’s failure to take meaningful ac-tion on climate change may one day be seen as the gravest mistake of our time,” began an unsigned editorial in the Apr. 14 Bloomberg Businessweek. Three weeks later, the same magazine ran an article about how Greenland hopes to profit from easier access to minerals, thanks to its swiftly melting ice sheet. Aleqa Hammond, the country’s first female prime minister, is spearheading efforts to mine everything from gold, plati-

num, diamonds, and rubies to zinc, iron, uranium, and rare earth minerals.

Though Greenland may become a “net winner”—many of its 56,000 residents will have to move from proposed mining locations sooner, and from coastal areas a bit later—many more nations and people face myriad challenging consequences, which is why utility executives are talk-ing openly about responding to climate change (see “Lessons in Resiliency and Risk” in this issue).

Acting to Limit Climate ChangeFor the U.S. power industry, June is ex-pected to be the month when the EPA re-leases its final rule on GHGs emitted by existing fossil-fueled power plants, and Administrator Gina McCarthy has been point person for that effort. As Rolling Stone magazine described her in its May 8 article, “Obama’s Last Shot,” she “has a kind of gruff charm that suggests she’s anything but a tree-hugging elitist.”

With her blue collar Boston background, McCarthy has more in common with coal miners and coal plant workers than with the well-heeled lobbyists on both sides of climate change politics, so I take her seriously when she says (and as many in this industry have confirmed) that the EPA has listened carefully to concerns that the GHG regulations for existing plants need to be flexible—both to ensure grid reliability and to minimize economic impacts. (This issue went to press before release of the final rule, but we’ll be examining its im-plications, and legal twists and turns, over the coming months in print and online.)

Threats to GenerationClimate change isn’t just a threat to coal-fueled power plants because of recent and anticipated regulations. It’s also a threat in many less-predictable ways, from con-strained water availability to extreme weather events that may damage a plant itself or make fuel delivery impossible.

Utilities like Louisiana-based Entergy and New Jersey’s Public Service Electric & Gas (PSE&G) that have recently had to

cope with unusually severe hurricanes are learning to adopt new prevention, miti-gation, and recovery strategies. PSE&G Chairman, President, and CEO Ralph Izzo has been quoted as saying, “Climate change is the preeminent issue of our time, with the power to transform both our company and our industry.” PSE&G has a multipronged carbon-reduction strategy but also planned to spend $2.6 billion to harden its infrastructure (the Board of Public Utilities approved much less, closer to $1 billion, in early May). And in Feb-ruary, New York regulators required ConEd to factor climate risks into all its forward planning and implement state-of-the-art measures to protect its system from those risks. Over the next four years, ConEd plans to spend $1 billion on storm hard-ening and resiliency measures.

Meanwhile, the vendor community is in-troducing new tools to help address inten-sifying challenges. Just two examples are Schneider Electric and Space-Time Insight. Schneider Electric provides independent, location-specific weather forecasting services that range from load prediction to determining safe times to erect and perform maintenance on wind turbines. Among the technology products provided by Space-Time Insight is one that helps utilities predict where their grid might fail during severe weather and identify where repairs are needed after such events.

Climate change–intensified severe weather can wreak as much havoc on re-newable power generation as on fossil or nuclear generation. Stepping up to develop and deploy cost-effective and technically viable solutions to reducing GHG emissions (especially those that don’t incur a water use penalty) while also hardening infra-structure and preparing for post-event res-toration are the responsibilities of those involved in all forms of electricity genera-tion, because climate change doesn’t care what your politics or beliefs are, nor what technology provides the electrons that power your computer and refrigerator. ■

—Gail Reitenbach, PhD is POWER’s editor (@GailReit, @POWERmagazine).

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Europe Moves to Phase Out Renewable SubsidiesNew rules adopted by the European Com-mission (EC) in April will gradually phase out renewable energy subsidies that cur-rently bolster the European Union’s (EU’s) €48-billion-a-year clean energy industry.

The rules stem from an investigation into Germany’s renewable energy subsi-dies, which have sent renewables’ share of the country’s power portfolio soaring but led to market distortions. As it issued the rules, the EC called on Europe to meet am-bitious 2020 climate targets at the least possible cost for taxpayers and without undue distortions of competition in the single market.

“Many renewables sources have reached a scale and a level of maturity that allows them to compete with more commensurable sources,” EU Commissioner for Competition Joaquin Almunia told reporters on April 9. “It is time for renewables to join the mar-ket. The new guidelines provide a framework for designing more efficient public support measures that reflect market conditions, in a gradual and pragmatic way.”

The new Energy and Environmental State Aid Guidelines, which will be valid from July 1, 2014, until the end of 2020, foresee the gradual introduction of com-petitive bidding processes for allocating public support but offer the bloc’s 28 member states flexibility to take account of national circumstances. In 2015 and 2016, a pilot phase will be launched to test competitive bidding procedures in a small share of new renewable power ca-

pacity. Small installations (less than 6 MW of wind power or 1 MW of other renew-ables such as solar or biomass) will be ini-tially exempted, but tender processes will be obligatory for all new installations as of 2017.

The guidelines also call for the gradual replacement of feed-in tariffs with more market-based types of aids such as feed-in premiums. The premiums will not apply when prices on the market are negative, which means generators will have no in-centive to generate electricity under neg-ative prices. Small installations will still benefit from a special program, however, and the rules do not affect installations that are already in place (Figure 1).

Significantly, the rules also seek to al-leviate the “very high burden” of charges levied for the funding of renewables for 68 energy-intensive companies. But that measure was criticized by energy-inten-sive sectors as well as by renewable en-ergy advocates, who cautioned that it would shift the costs for the transition to cleaner energy disproportionately onto private consumers and small businesses. The European Aluminum Association said more would need to be done to restore Eu-rope’s industrial competitiveness, calling for more compensation measures for costs related to climate and energy policies.

The rules also back cross-border energy infrastructure in support of a single Euro-pean energy market, and they permit aid to secure adequate generation when there is a real risk of a reliability lapse. That means aid for so-called “capacity mecha-nisms” is possible if a state demonstrates that adequate capacity cannot be deliv-ered without state intervention.

Power Sector Link to Water Is Deep, ComplexThe interlinkages between water and en-ergy are complex and run deep, warns a United Nations (UN) World Water Develop-ment water and energy–themed report re-leased this March. As global water demand (in terms of withdrawals) is projected to increase 55% by 2050, driven by a 400% demand surge in manufacturing, 140% in thermal power generation, and 130% in domestic use, freshwater availability is expected to be badly strained.

About 90% of global power generation is water intensive. Thermal power plants, in particular, are responsible for 43% of

total freshwater withdrawals in Europe, nearly 50% in the U.S., and more than 10% of the national water cap in China, the report asserts. Meanwhile, to mitigate climate change and address energy secu-rity concerns, many nations have endorsed ambitious targets to double the share of renewables in the total power mix by 2030—many depending on hydropower and gas generation to address intermit-tency of wind and solar. All power gener-ating sources use at least some water for cooling purposes (Figure 2).

The power sector’s dependence on wa-ter introduces vulnerabilities, it finds, as periods of water scarcity and elevated temperatures can force power plants to shut down or reduce their output. And, as climate change induces more extreme weather events, the sector is exposed to higher levels of risk.

At the same time, energy is required for water provision, not only for pumping and

1. A subsidy ceiling. New renewable

projects installed in the European Union after

July 1, 2014, will be subject to new rules that

will gradually phase out renewable subsidies.

This image shows WIRSOL’s 8.1-MW crystal-

line solar plant on the 11-hectare roofs of pfen-

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rooftop solar projects. Courtesy: WIRSOL

2. Water use for electricity gener-ation by cooling technology. Cour-

tesy: World Energy Outlook 2012 © OECD/

IEA, 2012, figure 17.4, p. 510

Notes: * Includes trough, tower and Fresnel

technologies using tower, dry and hybrid cool-

ing, and Stirling technology. ** Includes binary,

flash, and enhanced geothermal system tech-

nologies using tower, dry, and hybrid cooling.

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treatment but also desalination. Use of desalination has increased significantly over the last 20 years, the report says, surging on costs that have reportedly dropped below $0.50 per cubic meter (m3). More than 16,000 desalination plants exist worldwide today with a total operating capacity of roughly 70 million m3/day—and that operating capacity could nearly double by 2020, industry observers suggest. But desalinated water involves the use of at least 75.2 TWh/year, which is about 0.4% of global power consumption, and it continues to be an expensive solution for developing countries or large water users.

Water shortages put coal generation particularly at risk, the World Resources Institute (WRI) warned in a separate March-released report. The global research organization in July 2012 estimated that 1,199 new coal-fired power plants with a total in-stalled capacity of more than 1,400 GW have been proposed in 59 countries—though more than 75% of that is slated for China and India alone. But more than 50% of the world’s largest coal-produc-ing/consuming countries face “high to extremely high levels” of water stress (Figure 3), attributable to many competing demands on water resources, it said. Ranked at the top of the high water-stress risk list for major coal producers/consumers is Kazakhstan, followed by India, South Korea, Australia, Indonesia, Japan, South Africa, China, the U.S., Germany, Poland, Russia, and Columbia.

China, whose coal-fired capacity accounts for more than 66% of its national total power capacity, has average water resources of only 1,730 m3/yr per capita—barely above the UN’s “water scarcity market.” Eight Chinese provinces have fewer than 500 m3/yr per capita of total available surface water, on par with Middle Eastern countries such as Jordan or Syria. Worsening mat-ters further is that two-thirds of China’s coal mines are located in the water-stressed north, which means at least 58% of its existing coal fleet competes heavily for water with industrial, agricultural, and domestic resources.

However, recognizing future water challenges to its energy sector, China’s Ministry of Water Resources recently announced a water allocation plan that specifies water-use efficiency and dis-charge requirements for existing coal plants—including manda-tory air cooling technology for those facing water scarcity—and requires all new coal mines to submit a water resources planning study. Meanwhile, China’s State Council has set down three na-tional goals for water: To cap annual maximum water use nation-wide at 700 billion m3, improve industrial water-use efficiency to an internationally advanced level, and protect water quality. Those are a “step in the right direction,” the organization says,

even though China “could see increased production costs in the short term as it could be more expensive to access alternative water supplies, address ongoing regulatory changes, and guard against potential disruptions,” the report says.

For India, the outlook is much more dire. More than 70% of that country’s power plants are located in water-stressed or water-scarce areas. Water risks will be borne more prevalently by unregu-lated generators—those not shielded by protective regulations enjoyed by India’s state-owned power sector. However, a national policy framework calls for a 20% improvement in water efficiency nationally through regulatory mechanisms, encouraging conserva-tion and wastewater minimization, the WRI says. While the frame-work also calls on water users, generators included, to optimize recycling and reuse practices, several other measures could help utilities in stressed regions. These include building backup supply reservoirs and desalination plants, regulator water audits, and con-crete standards for water consumption in the power sector.

China Starts Construction of HTR

Demonstration Plant

Construction of China’s first high-temperature gas-cooled reactor (HTR) demonstration plant kicked off this April after pouring of con-crete for the basemat of the Generation IV reactor was completed.

Though approved in 2005, China’s State Council suspended development of the Shidaowan-1 plant (Figure 4) in Shandong Province—a high-priority National Major Science and Technology project—following the Fukushima disaster in 2011.

According to the World Nuclear Association, the demonstration is expected to begin operating in 2017 and will feature twin HTR-PM (pebblebed module) units that will drive a single 210-MW turbine. At least 18 other HTR units are proposed for the Shidaowan site. Part of the Rongcheng Nuclear Power Industrial Park project, the site will also demonstrate CAP1400 units—which are domestically sourced advanced reactors based on Westinghouse’s AP1000 design.

The HTR-PM units, which are expected to lead to commercial versions, will use pebble bed fuel and helium coolant, each with a single steam generator.

The plant is being built by a joint venture led by China Huaneng Group (the country’s largest generator, but which has no nuclear capacity), China Nuclear Engineering & Construction Group, CNEC Corp, and Tsinghua University’s Institute of Nuclear and New Energy Technology. The engineering, procurement, and construction contract signed in 2008 involves Shanghai Electric Co. and Harbin Power Equipment Co.

3. Water woes. While about 90% of global power generation is

water intensive, several countries face varying degrees of water scar-

city, stress, or vulnerability. Courtesy: United Nations World Water De-

velopment Report 2014: Water and Energy

4. Back to life. Basemat concrete pouring for China’s first twin

high-temperature gas-cooled reactors was completed in April at the

Shidaowan site in Shandong Province. Plans call for as many as 18

generation IV reactors to be built at the site. Courtesy: China Nuclear

Engineering Corp.

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29%

Refining

18%Paper

14%

Commercial/

Institutional

13%

Food

8%

Other

manufacturing

7%

Other

industrial

6%

Metals

5%

82.4 GW

of CHP is installed at

more than 4,200 U.S.

industrial and

commercial

facilities*

*as of July 2013. Source: ICF CHP Installation Database

U.S. CHP APPLICATIONS TODAY

Sources: OECD/IEA 2013, Euroheat & Power 2013

4.4 GW

total CHP capacity

is in development

or under

construction*, 2.6

GW at <100 MW

sites

40 GW of new CHP by 2020

National target set

in Obama Executive

Order (2012)

87%

of capacity is

for industrial

applications

71%

of capacity is

natural

gas–fired

1.4 GW

added in

2011–2012 at

320 sites

CHP SHARE OF NATIONAL POWER PRODUCTION AROUND THE WORLD

0%

10%

20%

30%

40%

50%

60%

70%

Austria

Bulgaria

Croa

tia

Czech Re

p.

Denm

ark

Estonia

Finlan

d

Fran

ce

Germ

any

Icelan

d

Italy

Japa

n

Latvia

Lithua

nia

Netherland

s

Poland

Roman

ia

Slov

akia

Slov

enia

Swed

en

Switz

erland

UKU.S.

Several countries around the world are boosting investment in cogeneration—also known as combined heat and power

(CHP)—to meet broader energy and environmental goals. Specifically in the U.S., a 2012 White House executive order,

increasing interest from states, a promising natural gas supply and price outlook, and environmental rule compliance

strategies are driving CHP growth. The bulk of future additions (32%) is centered on commercial applications.

—Copy and artwork by Sonal Patel, a POWER associate editor

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NYISO Opens Smart Control CenterThe New York Independent System Operator (NYISO) this April re-placed its 44-year-old primary power control center with a state-of-the-art facility in Rensselaer County that is outfitted with digital monitoring technologies and harnesses grid control technologies installed in the operator’s June 2013–completed smart grid project.

The $75 million Department of Energy (DOE)–funded smart grid initiative, conducted in partnership with eight transmission-own-ing utilities and power authorities, deploys phasor measurement units that allow the grid operator to detect irregularities, predict problems, and take corrective action. It relays system conditions at a rate of 60 times per second (360 times faster than before) and includes capacitor banks to improve transmission system efficiency by reducing line losses. The new primary control center helps inte-grate and process this significantly higher volume of data.

The 64,000-square-foot (ft2) facility features a 2,300-ft2 video wall (Figure 5)—the largest of its kind in North America—that captures more than 3,000 live status points presenting key elec-tric system operations data and information. The former control center in Guilderland, built in 1969, will now serve as backup.

According to NYISO, the $38 million facility also enables im-proved integration of renewable power by deploying resource man-agement tools such as wind forecasts, meteorological conditions, and generation output data. The DOE said in a statement that the new control center gives NYISO and neighboring grid control areas a “far more expansive and in-depth view of the power grid.”

POWER DigestAustralia Releases Emissions Reduction Fund White Paper. Australia’s Ministry of Environment on April 24 released its Emissions Reduction Fund (ERF) White Paper, formally setting out the final design of the carbon buy-back scheme that the current administration has proposed to replace the country’s carbon tax and emissions trading scheme. Under the proposed ERF, which will extend from July 2014 to 2020, the government will use funds from a pool of capital to support “direct action” by in-dustry to reduce emissions. Through 2017, it will spend A$1.55 billion ($1.43 billion) and later, A$1 billion ($952 million) to buy back lowest-cost abatement through reverse auctions. Auctions will start in the second half of 2014 and run quarterly.

Belarus Ostrovets Nuclear Plant Gets Full Construction OK. The Belarus Department of Nuclear and Radiation Safety (of the Ministry of Emergencies) on April 29 issued state-owned nuclear plant builder Belarus AEC a full construction license for the first of two units at the Ostrovets plant. First concrete for the 1.2-GW AES-2006 model VVER reactor was poured in late 2013. The

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erator’s new 64,000-ft2 primary power control center captures more

than 3,000 live status points presenting key electric system operations

and data information to enhance grid reliability and support smart grid

efforts. Courtesy: NYISO


twin-reactor project is being built by Russia’s AtomStroyExport via a $10 billion turnkey contract. The first unit is expected to be completed in November 2018 and the second in July 2020.

CEZ Pulls Plug on Temelin Nuclear Expansion. Czech pow-er utility CEZ on April 10 canceled a tender to expand the Temelin nuclear plant after the Czech government announced it would not offer state support to the €10 billion project. Bidders to the ten-der for two new 1.2-GW reactors include Toshiba’s Westinghouse and Russia’s Rosatom. State-owned CEZ cited Europe’s turbulent electricity sector for canceling the tender. “While originally the project was fully economically feasible given the market price of electricity and other factors, today all investments into power plants, which revenues depend on sales of electricity in the free market, are threatened,” it said.

White Rose CCS Qualifies for EC’s NER300 Grant. Capture Power’s proposed 426-MW White Rose carbon capture and storage (CCS) demonstration project is the only eligible CCS venture submit-ted for consideration that qualified for the European Commission’s NER300 program as of the mid-April deadline. The $3.3 billion proj-ect could receive, as soon as this summer, a €300 million ($413 million) grant under the initiative to establish CCS demonstration projects in the European Union should developers Drax, Alstom, and BOC make a final investment decision to proceed with the project. The UK government earlier this year awarded an engineering and de-sign contracts for the White Rose project and SSE Energy’s gas-fired Peterhead project as part of a £1 billion CCS Competition.

In April, meanwhile, Drax filed suit against the UK’s Department of Energy and Climate Change after one of the generator’s two large-scale biomass units, which were in the running for substantial sub-sidies, was deemed ineligible. Instead of receiving a minimum price at which it can sell power under a new “contracts for difference” program as previously indicated by the government, the second unit will now only qualify for the old direct subsidy system.

TenneT Awards Contract for New German 900-MW Off-shore Connector. Dutch-German grid operator TenneT on Apr. 15 awarded its 12th offshore grid connection contract to a con-sortium comprising Siemens Energy, Petrofac, and Prysmian. The new €1 billion line, BorWin3, will connect remote offshore wind farms in the German North Sea to the onshore grid using direct current (DC) technology by 2019. Three other lines, the 60-MW (AC) Alpha Ventus, the 400-MW (DC) BorWin1, and 108-MW (AC) Riffgat, are now operational. This year, the 800-MW (DC) DolWin1 and 576-MW (DC) HelWin1 will become operational, and at least seven other lines, BorWin3 included, are under construc-tion or have been awarded. At least €7.5 billion have been ear-marked to install 6.5 GW of offshore wind power in Germany by 2020. When BorWin3 is completed, TenneT will have developed 7.1 GW of connection capacity by 2020. The feat also involves developing nine large offshore converter platforms and laying a total of 4,000 kilometers of submarine and land cables.

Ireland-to-UK Wind Power Export Effort Is Dead. Ireland and the UK on Apr. 13 failed to conclude an intergovernmental agreement for the Midlands Energy Export Project, which called for wind power from 2,300 proposed turbines installed in Ireland to be exported to the power-strapped UK by 2020. The two governments said they were unable to reach an agreement as envisaged.

Jordan Starts Construction of 117-MW Wind Project. Jor-dan in late April launched construction of the 117-MW Tafila wind power farm. The $285 million project being developed by the Tafila Wind Farm Co. could generate up to 400 GWh/year when commercially operational in 2015. ■

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

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Robust Bearings Tested for Brazil’s Belo Monte Hydro ProjectBrazil’s Belo Monte hydropower project includes a complex of dams, numerous dikes, and a series of canals supplying two dif-ferent power stations with water. With a rated capacity of 11,233 MW, it will be the country’s second-largest and the world’s third-largest hydropower generating station behind China’s Three Gorg-es and Brazil’s Itaipu installations.

Project owners wanted a reliable, water- and debris-resistant material that would allow extended service for the facility’s wick-et gates. The components needed to withstand the harsh 24-hour operating conditions at the dam and provide a minimum service life of 20 years.

As part of the search process, Norte Energia—the compa-ny formed to build and operate the Belo Monte hydroelectric plant—tested GGB Bearing Technology’s HPM self-lubricating, filament-wound bearings (Figure 1) to determine their suitabil-ity for the wicket gate application. The materials used in the bearings were specifically developed for hydropower applica-tions and offer resistance to impact and corrosion, high static and dynamic load capacity, and 75% less weight than equiva-lently sized metallic bearings.

Powertech Labs conducted the testing in accordance with U.S. Army Corps of Engineers specifications. The testing simu-

lated actual operating conditions at Belo Monte, including the use of water from the Xingu River, where the project is being constructed. The bearings were subjected to tests that were modified to simulate 30 years of operation rather than the stan-dard 13 years.

The bearings—consisting of a fiberglass-reinforced, ep-oxy resin support layer and a sliding layer of polyester fibers with polytetrafluoroethylene and other additives—were first subjected to a static load with rotary and oscillating motion under both dry and wet conditions. They then underwent ac-celerated wear testing with a dynamic radial load on a journal moving continuously plus or minus one degree. The static load remained constant, but the dynamic load was paused every 15 minutes to simulate a turbine wicket gate opening plus or mi-nus 15 degrees.

The bearings performed well with little evidence of operating stress. Significantly, it was demonstrated that their coefficient of friction and wear rate decreased as running time increased, which allowed the project engineers to design the turbines with smaller servomotors. Engineers now use the essential data provided from the testing when specifying self-lubricating bearings in hydro-power turbines to achieve longer service life and maintenance-free operation.

GGB HPM bearings are used in more than 25 hydropower proj-ects worldwide, including on the largest water turbine in the world at the Chinese Xiangjiaba hydropower plant. That Three Gorges Corp. project contains four Francis turbines, each with a rated capacity of 850 MW, which were fitted with bearings with an inner diameter of 520 mm and a length of 370 mm. ■

—Edited by Aaron Larson, a POWER associate editor (@AaronL_Power, @POWERmagazine).

New Enclosure Solution Enables Remote Monitoring of Battery Backup SystemsWith 4.4 million customers and nearly 46 GW of generating capac-ity, Atlanta-based Southern Co. has doubled the size of its super-

1. A 3D view of a self-lubricating, filament-wound bearing. There have been some locations using this type of bearing

since 2007 with no failures reported. The life expectancy for the mate-

rial is at least 20 years. Courtesy: GGB Bearing Technology

2. GE-MDS radio enclosure system with battery test remote monitor. The remote monitoring of battery backup sys-

tems was an essential reliability feature for Southern Co.’s supervisory

control and data acquisition system. Courtesy: Ventev


visory control and data acquisition (SCADA) system in the past three years and now has approximately 4,000 devices. Critical power backup systems must be ready if commer-cial power fails.

Bob Cheney, team leader for the Pow-er Delivery Test Lab at Southern Co., contacted Chad Briddell, product man-ager at Ventev, the manufacturing divi-sion of TESSCO Technologies, because he needed an off-the-shelf enclosure that would house essential SCADA com-munications devices. Cheney needed the enclosures to be fully integrated by the factory with all the components pre-configured. He was also hoping Ventev would design and include a very important new component.

“I had not been able to find anything already on the market that would test the backup battery and send reports back to me,” explained Cheney. “When the AC power is down, the system rests on the backup battery to keep things going. The whole system can go down because a little $30 battery dies. I needed something that would be able to tell me the battery is good or the battery is bad. You have to understand, Alabama is home to several automobile manufacturers. When the pow-er goes down, they’re not working, and we hear about it.”

The Ventev team met with Cheney to develop a customer-specific solution. They started with Ventev’s radio-specific outdoor wireless enclosure containing ample power for two radios, radio inter-face, and environmental protection. The design easily accommodates components such as networking equipment, power conversion equipment, cable grounding, and lightning protection, all of which can be installed in the Ventev factory prior to deployment. The collaboration resulted in a radio-specific outdoor wireless enclosure for Southern’s SCADA devices (Figure 2).

After that, the team worked to address the most important item on Cheney’s wish list. Ventev engineers designed and manufactured a new product—the innovative battery test remote monitor (BTRM)—to perform automatic battery load tests and send alerts via simple network management protocol, text, or email using Ethernet or DNP3 commu-nication protocols. The first-to-market technology allows remote monitoring of battery health for backup supplies relied upon to relay critical data.

“The BTRM sits on the thin rail be-tween the power supply and the battery charger,” Briddell said. “On a user-de-

fined schedule, it takes the AC power offline, forces the load of the system to be supported by the batteries, and then it monitors the voltage of the bat-teries as it degrades over time. If that rate differs from the factory settings or the factory’s normal conditions, then it raises a red flag.”

Batteries have an operational lifespan that can be reduced by environmental fac-tors. Extreme temperatures are the worst enemy of batteries. The BTRM system of-

fers a simple solution because it is a pass or fail test. It doesn’t provide a lot of data that needs to be analyzed or reviewed. The test will simply identify when a battery is in trouble and needs to be replaced.

“Ventev did what no one else had been able to do,” said Cheney. “They created an enclosure that can let me know the health of the backup battery.”■

—Edited by Aaron Larson, a POWER as-sociate editor (@AaronL_Power,

@POWERmagazine)

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FERC Takes First Steps in Harmonizing Gas and Electricity Markets Thomas W. Overton, JD

After two years of work, about a dozen conferences and meetings, and multiple rounds of comments, the Federal Energy Regulatory Commission (FERC) announced on Mar.

20 that it was ready to begin the process of changing its rules to better harmonize the natural gas and electricity sectors.

The process began in early 2012 when FERC first called for comments from the industry on various aspects of gas-electric interdependence, in light of the growing importance of natu-ral gas–fired power and several incidents that had highlighted potential problems in making sure gas-fired plants had fuel to operate when needed, without disrupting supplies for other us-ers. The response was enthusiastic enough that FERC scheduled a series of technical conferences to gather information and opin-ions on the best path forward.

One of the main issues that arose was the lack of coordination between the gas day and electric day. Both sectors use day-ahead scheduling, but some important physical and operational differ-ences exist. While FERC recognized that some of these—such as vastly different storage methods and capacities, as well as differ-ent speeds at which gas and electricity travel—are inherent in the nature of the products, others involve business practices that have created arguably unnecessary conflicts.

End of the Guessing GameFor example, in many markets, gas-fired generators, most of whom rely on interruptible pipeline service, must reserve gas transportation services before they know for sure how much elec-tricity they will be committing to produce. If they chose to wait until their commitments are known, they risk not having enough fuel to meet them. While not always a serious concern, this risk becomes acute during periods of constraint. (For some examples, see “New England Struggles with Gas Supply Bottlenecks” in the June 2013 issue and “About That Gas-Fired Power Boom…” in the April 2014 issue, available at www.powermag.com.)

Accordingly, FERC’s Mar. 20 Proposed Rule would do three things:

■ Move the start of the gas day up by 5 hours, from 9 a.m. Cen-tral Time to 4 a.m. Central Time.

■ Delay the start of the first day-ahead nomination opportunity for pipeline scheduling by 90 minutes, from 11:30 a.m. to 1:00 p.m.

■ Change the structure of the gas day to create four intraday nomination cycles from the current two.

The rationale behind these changes is to allow electric utili-ties to finalize their scheduling before gas-fired generators must submit nomination requests for gas transportation service to the pipelines, as well as to increase flexibility for shippers during the gas day. The gas day currently begins during morning ramp

or morning peak periods for generators, which creates the risk they may run out of gas from the previous day. The change would reduce this risk by moving the start of the gas day well before the morning ramp.

Likewise, delaying the first nomination cycle would allow elec-tric markets to clear when gas markets are most liquid, at the start of the day-ahead nomination process. Thus, gas generators would know what their commitments are before they must begin arranging fuel to meet them, allowing them to make reservations at the most economic time.

More FlexibilityThe additional intraday nomination cycles are intended to address a couple of concerns. First, they will give independent system operators with large fleets of gas generators, like PJM, more flex-ibility in addressing real-time fluctuations in electricity demand.

Second, generators in the Southwest, where firm transpor-tation service is more common for gas-fired plants, are handi-capped in making the best use of it. Under the current system, the last nomination cycle in which these generators can request firm service and be assured of getting it is at 8:00 a.m. Pacific Time (the second intraday deadline at 2:00 p.m. Pacific does not allow firm shippers to bump interruptible service requested in an earlier cycle). This is a problem when peak demand in their area—which can spike rapidly as large amounts of solar go off the grid—does not occur until around 5:00 p.m., which greatly reduces the value of expensive firm service.

FERC’s proposed rule would change the current intraday nomi-nation deadlines from 10:00 a.m. (bumping allowed) and 5:00 p.m. (no-bump) to 8:00 a.m. (bump), 10:30 a.m. (bump), 4:00 p.m. (bump) and 7:00 p.m. (no-bump) (all Central Time). Though some shippers already offer additional nomination cycles, this rule would standardize the practice nationwide. Further, for these shippers, the rule clarifies that bumping is permitted under such additional nomination schedules up until the no-bump deadline in the new rule.

The rule contains one additional change concerning transporta-tion contracts. FERC currently allows—but does not require—pipe-line companies to offer multiparty contracts under which multiple shippers can share in the same interstate capacity under a single service agreement. The change would make this option mandatory. The goal, again, is increasing options for gas-fired generators.

FERC is giving the gas and electric industries, through the North American Energy Standards Board, until Sept. 24, 2014, to reach a consensus on the proposed rule and any revisions. Wheth-er or not a consensus is reached, comments on the proposal, and the consensus standards, if any, will be due 60 days later. ■

—Thomas W. Overton, JD is a POWER associate editor (@thomas_overton, @POWERmagazine).

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WATER REGULATIONS

Site-Specific Factors Are Critical for Compliance with Final 316(b) Existing Facilities Rule

On May 16, 2014, the Environmental

Protection Agency (EPA) is scheduled

to release its long-delayed final 316(b)

rule for existing facilities. The rule—which

was supposed to have been issued Apr. 17

after the previous extension and which now

is expected while this issue is at the printer—

affects several hundred facilities that employ

cooling water drawn from “Waters of the

United States” at design rates of 2 million

gallons per day (mgd) and greater. Affected

facilities are facing the need to document cir-

cumstances at their facilities, and many will

need to evaluate alternatives to their cooling

system, develop a compliance approach, and

potentially install costly retrofits.

The EPA has struggled for many years to

develop a rule that is workable and survives

legal challenge; in fact, the final rule will ad-

dress a portion of the Clean Water Act (CWA)

written more than 40 years ago. Earlier at-

tempts at rulemaking have been the subject

of review by several federal courts, and the

rulemaking process has been under federal

court oversight resulting from a 1993 lawsuit.

While several factors have contributed to the

EPA’s delays, the statutory language itself

has created challenges for the rulemaking as

well as in the definition of best technology

available (BTA).

The statutory language is brief and de-

ceptively simple: “§316(b). Any standard

established pursuant to section 301 or sec-

tion 306 of this Act and applicable to a point

source shall require that the location, design,

construction, and capacity of cooling water

intake structures reflect the best technology

available for minimizing adverse environ-

mental impact.”

Although the statute does not define “ad-

verse environmental impact,” in the early

years of implementation, ecosystem-level

impacts were commonly assessed. In the past

20 years, the EPA has gravitated toward de-

fining adverse environmental impact as mor-

tality due to impingement (trapping of aquatic

organisms on the cooling water intake struc-

ture [CWIS]) and entrainment (passage of

aquatic organisms through the CWIS and the

downstream cooling system). It is common

for the EPA to consider rates of impingement

and entrainment (such as organisms/time or

organisms/volume) and to target reductions

in impingement mortality (IM) and entrain-

ment mortality (EM) rates “commensurate

with closed-cycle cooling.” Use of closed-

cycle cooling and reduced intake velocity are

essentially required for new facilities under

the Phase I rule promulgated in 2001.

Whether IM and EM rates result in ad-

verse environmental impact is less material

to the EPA’s approach than demonstrating re-

duced rates, similar to reduced effluent con-

centrations. Such a reliance on rates and their

reduction stems in part from the statute’s

reference to the parts of the CWA that call

for the development of technology-based and

water quality–based effluent limits (sections

301 and 306, respectively) as models for the

The long-awaited “cooling water” rule for existing power plants is also one of the most complicated when it comes to determining a cost-effective compliance ap-proach. Though the promised flexibility of the final rule is welcome, it also means that generating units subject to the rule have many factors to balance before mak-ing a technology choice.

Mark Gerath, Steve Cibik, and John Burnett

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WATER REGULATIONS


BTA assessment. Those sections of the CWA

deal with means of effluent treatment and

protection of water quality for chemical and

physical qualities of water.

Importantly, these qualities are subject to

chemical, physical, and biological treatment

processes that are generally transferable from

one facility to another. In contrast, the inter-

action of aquatic organisms with the CWIS

is highly site-specific, and assessment of po-

tential adverse environmental impacts as well

as alternative control measures can be poorly

transferable among facilities. In its final rule,

the EPA is expected to acknowledge the im-

portance of site-specific factors in its approach

to BTA for both IM and EM. As we describe

in this article, proper consideration of site-spe-

cific factors will be key to achieving cost-ef-

fective compliance with the final 316(b) rule.

Though it may seem premature to make

recommendations prior to a final rule, based

on the proposed rule, comments made by the

EPA publicly and privately, and the general

tone and approach taken by the EPA in this

particular rulemaking, we believe that the

issues addressed here are sure to be central

to compliance with the final rule. Given the

complexity of the compliance schedule and

process, the need for planning and potentially

assembling a multi-disciplinary team, and the

implications that chosen compliance methods

may have on overall unit operation, we be-

lieve it is important for generating companies

to understand the process and consequences

of various approaches as soon as possible.

Important Site-Specific FactorsWhen considering rates of IM and EM, po-

tential adverse environmental impact, and al-

ternatives for BTA, virtually every aspect of

the assessment can differ dramatically from

facility to facility. Some illustrations of the

variable factors are grouped here into three

broad categories:

■ The nature of impingement and entrain-

ment. Rates of impingement and entrain-

ment may vary from facility to facility by

several orders of magnitude. The value

of commercially and recreationally im-

portant species as well as threatened or

endangered species is also highly vari-

able from facility to facility. The degree to

which a given species will be a “species of

concern” often depends upon the resource

agency. For example, some agencies are

very troubled by the loss of invasive spe-

cies that now serve as forage base, while

other agencies believe that the losses of

such invasive species can be discounted.

Additionally, the potential for losses at the

CWIS to actually result in adverse envi-

ronmental impact at the ecosystem level

differs among facilities.

■ Potential effectiveness of, and constraints

on, BTA alternatives. Site-related factors

can make a single technology effective at

one site and essentially infeasible at an-

other. Such factors include weather, debris

loading, temporal variation of the source

water level, the presence of an intake canal

and the availability of additional shore-

line, spatial constraints on construction at

the facility, nearby land uses, and nature

of the generating facility itself. To provide

examples concerning the last two factors:

Operation of evaporative cooling towers

in the proximity of an airport or highway

may present safety issues related to fog

formation and runway/roadway icing, and

a facility’s existing condensers may not

withstand increased back-pressure associ-

ated with closed-cycle cooling.

■ The economics of the BTA alternatives, in-

cluding costs to the facility and attending

social costs. The factors that affect technol-

ogy effectiveness and feasibility often also

affect the technology’s costs. For example,

a longer fish return will be more costly and

is also likely to result in less survival of

the returned organisms, particularly in

extreme weather. Beyond these relatively

direct effects, the economic environment,

the price of fuel, the status of the electri-

cal grid, and the other site-specific factors

also have the potential to drive facility and

social costs of retrofits. Evaluation of BTA

at a facility should consider—and, in many

cases, quantify—these complex costs as a

part of a site-specific assessment.

As discussed below, though the final rule

is expected to approach BTA for IM and EM

in very different ways, proper accounting of

the numerous site-specific factors must be

considered in assessing the BTA options for

both. In addition, effective communication

to facility staff, company management, and

the National Pollutant Discharge Elimination

System (NPDES) permitting agency (hereaf-

ter NPDES Director) of how these factors fa-

vor or disfavor different BTA options should

be clearly stated in the reports called for by

the final rule.

BTA Approach for Impingement MortalityIn the final rule’s approach to BTA for IM, the

EPA is widely expected to offer streamlined

approaches that equate specific technology

attributes (such as closed-cycle cooling, low

through-screen velocity, existing offshore ve-

locity caps, and “fish-friendly” screens and

fish returns) to substantial reductions in IM

and designation as BTA (Figure 1). Though

this resembles a “one size fits all” approach,

the availability of different approaches as

well as a de-emphasis on monitoring to dem-

onstrate compliance should make for a work-

able approach to BTA for IM.

The EPA is also expected to delay the need to

assess and retrofit for IM BTA until after a deter-

mination of EM BTA, thus avoiding the potential

for “double jeopardy” in the form of having to

re-retrofit based on an EM assessment that fol-

1. Multiple technology options. Traveling water screens with fish protection

measures, such as this one, are widely ex-

pected to be one of several technology op-

tions for complying with the cooling water

rule’s impingement mortality requirements.

Courtesy: HDR

Schedule to Avoid Double Jeopardy?

The schedule of activities in the final rule

is a major interest to the regulated com-

munity. Although the timing of various

required studies and reports is important,

the coordination of the best technology

available (BTA) determination for impinge-

ment mortality (IM) and entrainment mor-

tality (EM) is of great concern.

Under the 2011 proposed rule, retrofits

to address BTA for IM would have been

required within eight years. The BTA as-

sessment for EM was understood to follow

the IM-related assessment. Of course, this

put the facility at risk of installing one

technology to address IM and then poten-

tially having to change that technology

to address EM.

We understand that the EPA has con-

sidered the industry’s comments and that

the final rule will postpone the retrofit to

address IM until the BTA for EM has been

determined. A second sidebar discusses

another schedule-related issue: the timing

and purpose of IM and EM monitoring.

WATER REGULATIONS


lows an IM retrofit. (See sidebar “Schedule to Avoid Double Jeopardy?”

for the implications of a possible alternative sequence.)

The final rule also will likely offer the potential to demonstrate

that some combination of existing and newly installed technologies

and operational measures reduces IM to a “level commensurate with

closed-cycle cooling.” The level anticipated is an approximately 75%

reduction in IM relative to an unmitigated CWIS. The applicant must

demonstrate this level of reduction to the satisfaction of the NPDES

Director, likely through some combination of literature-based assess-

ment and monitoring in the field.

The expected final rule also allows the NPDES Director to find that

a CWIS is BTA when it impinges a de minimis quantity of fish per

year, potentially defined as equal to or less than 1,000 fish per year.

Although this would be an attractive alternative for the small number

of facilities that qualify, the benefit should be weighed against the

cost and risk of any ongoing monitoring required.

As we consider the IM BTA options, it is useful to consider several

questions relative to the facility and its CWIS:

■ Does the CWIS already match any of the technologies that confer

BTA? Unfortunately for most of the facilities covered by the now

suspended 316(b) Phase II rule, the answer to this question is likely

to be “no.”

■ Does the existing CWIS contribute meaningfully to the reduction

of impingement mortality in ways that are not defined by the BTA

technologies? For example, does it draw water from an area with

low fish densities relative to other nearby locations? If it does, can

that reduction be reliably and cost-effectively quantified as part of

the combination approach? What additional measures might be in-

stituted to reach the percentage reduction specified in the final rule

or de minimis thresholds?

■ What are the approximate site-specific costs and constraints on the

impingement BTA technologies? Are some technologies precluded by

cost of installation and operation (such as retrofit to closed-cycle cool-

ing) or by other issues (including lack of access to shoreline property

necessary to expand the CWIS and reduce through-screen velocity)?

■ When necessary, how will optimization and/or compliance monitor-

ing affect the cost of the measure as well as the risk to compliance?

For example, the proposed 316(b) rule of 2011 called for ongoing

demonstration that post-impingement survival for Ristroph-type

screens was, on average, higher than 88% for species of concern.

Given variations in survival rates, such a standard presented unac-

ceptable risks to compliance. Though the final rule’s anticipated

reliance on optimization of post-impingement survival is less risky,

it would lead to additional costs and should be managed with the

agency so that minimum survival rates are not required.

■ Do the IM BTA approaches contribute substantially to reductions

in EM? We believe that facilities employing closed-cycle cooling

should be considered compliant with the EM BTA even in the rare

cases when actual intake flows exceed 125 mgd. Other measures that

contribute to reduced IM may also meaningfully reduce the rates of

EM. These include use of wedgewire screens (such as the one shown

in the photo at the top of this article) with reduced through-slot ve-

locity that have been shown to also reduce entrainment rates, as well

as placement of intakes in habitat that have reduced populations of

both impingeable and entrainable organisms.

■ In short, what approach or combination of approaches confers reli-

able compliance at the lowest cost and lowest risk? In many cases,

there will be a clear winner when all factors point to a single BTA

approach. In others, the best approach may require compromising

one factor, for example, cost of installation and operation, in favor

of another, such as regulatory certainty. We should expect that such

factors may be difficult to compare quantitatively (for example,

capital cost vs. certainty of compliance) and that, in some cases,

risk analysis may be warranted.

These questions must be first addressed within the internal project

team in order to define the compliance strategy and the best approach

to BTA for IM. The answers should also be soundly and convincingly

presented to the regulatory agencies using the reports and analyses

called for by the final rule and in full consideration of the conditions

present at a site.

BTA Approach for Entrainment MortalityAll indications are that the final rule’s approach to considering BTA

for EM will be appropriately dominated by site-specific factors. For

facilities explicitly captured by the EM standards in the final national

rule—expected to be those with an actual intake flow of 125 mgd or

greater—four reports will be required to help the NPDES Director

assess BTA at an affected facility:

■ The reports called for under 40 Code of Federal Regulations

(CFR)122.21(r)(9)—or report (r)(9)—will define a program for

documenting the rates of EM of fish and shellfish, including listed

species, and then implement that program to document the rates.

■ The (r)(10) report will present the technical feasibility and costs

(both facility-level and social) of technologies that could reduce

EM, including retrofit to closed-cycle cooling.

■ The Benefits Valuation Study—or (r)(11) report—evaluates the

monetized and nonmonetized benefits of EM reductions associated

with different mitigation measures.

■ The (r)(12) report—or Non-water Quality and Other Environmen-

tal Impacts Study—must present a site-specific discussion of other

effects of EM mitigation measures such as potential increased air

emissions and water consumption.

Factor(s)Report per 40

CFR 122.21(r)Costs Benefits

High rates of entrainment, presence

of listed species, commercial/recre-

ational species, potential ecosystem

level effects

9, 11 á

Decrease in thermal impacts 11, 12 á

Decrease in thermal refuge and winter

fishery11 â

Increased cost of retrofit and opera-

tion10 á

Increased ease of retrofit 10 â

Increased performance and reliability

of technology11 â á

Reduced plant efficiency, increased

emissions/MW10, 12 á â

Decrease in grid reliability 12 â

Increase in power prices 12 á â

Increase in consumptive water use 12 â

Increase in noise and other environ-

mental impacts12 â

Table 1. Site-specific factors that may affect costs and benefits of entrainment mortality reduction mea-sures. “Costs” are those that occur at the facility level, both positive

and negative, while “benefits” (again both positive and negative) occur

in the environmental and social context. Source: ECT Inc.

WATER REGULATIONS


We note that the NPDES Director will retain

the authority to regulate EM at existing facilities

with actual intake flows of less than 125 mgd

under a Best Professional Judgment standard

but that the standards are not to be explicitly de-

fined beyond the generic statutory language for

Section 316(b) provided previously.

Each of the reports (r)(9) through (12) is

expected to be subject to peer review under

a process that is managed by the applicant

but overseen by the agency. After reviewing

these reports, the NPDES Director must con-

sider the factors defined in 40 CFR 125.98(e)

in reaching a decision about what constitutes

BTA for EM at a facility.

We believe that these four reports and the

decision criteria available to the NPDES Di-

rector should be viewed as an integrated effort.

Not only do the data from one report often

contribute to the analyses of the other efforts,

but the reports could overlap in parts of their

scope, making coordination necessary to avoid

duplication and ensure consistency.

The best example of the overlap is that reports

(r) (10, 11, and 12) all deal in some way with

facility and social costs (or negative benefits) and

benefits (or negative costs). The interrelationship

is illustrated in Table 1, which summarizes the

factors in the various reports that affect costs and

benefits of a facility retrofit.

Just as the issues affecting impingement

mortality vary among facilities, the fac-

tors that affect the costs and benefits of EM

controls will also differ dramatically. For

example, the EPA has acknowledged that

some sites are so highly constrained that

installation of cooling towers is essentially

infeasible, while other sites have more space

available. Similarly, annualized rates of en-

trainment, and the potential for impacts to

listed species, can vary by orders of magni-

tude between facilities.

Although we believe that, at the great ma-

jority of facilities, costs for a cooling tower

retrofit will greatly outweigh the benefits (in

fact, we believe such trends are apparent in the

EPA’s own supporting documents for the pro-

posed rule), demonstrating this to the NPDES

Director will be relatively simple at some fa-

cilities and more difficult at others. Therefore,

in planning and executing the analysis of EM

BTA, we believe that it is constructive to con-

sider—in a conceptual, weight-of-evidence

fashion—the ratio of all potential costs rela-

tive to all potential benefits.

The variety of factors outlined in Table 1

should be assessed for the candidate technolo-

gies at a facility to identify those that are criti-

cal to driving the cost-to-benefit ratio as well

as those that may require more extensive, or

controversial, analysis. For some technolo-

gies, such as installation of fine mesh screen

panels, the costs to the facility may be rela-

tively low compared with retrofit to closed-

cycle cooling. On the other hand, the benefits

of such a retrofit at the screen, based on the

actual rate of ichthyoplankton exclusion from

the cooling system and their return alive to the

source water, may also be low.

Of course, the most significant effort is likely

to focus on putting the costs and benefits of a

potential retrofit to closed-cycle cooling in

proper perspective. The final rule’s widely an-

ticipated call to include social costs provides the

opportunity to go beyond the direct engineering,

construction, and operation costs at the facility

to consider secondary effects such as changes

in the price of power to consumers, changes in

employment associated with reduced facility

dispatch, and loss of recreational resource value

associated with reduced winter fishery.

In the end, a technically sound, integrated

summary that is well calibrated to the issues

and risks at a facility should be presented to

the NPDES Director. Though the final rule

may be construed to call for potentially com-

plicated and costly analyses, we believe that

at many facilities a more streamlined ap-

proach can be used to demonstrate the costs

and benefits of EM reduction measures. Dia-

log with the agency early in the process will

facilitate this outcome.

On the other hand, there are likely to be

facilities where, due to the level of impacts or

the stance of the agency, analysis of closed-

cycle cooling retrofits may require consider-

able effort. In these cases, it will be important

to understand the full range of potential anal-

yses, how they relate to the site, and how best

to present them to the agency.

Planning and Communicating Are Plant ResponsibilitiesBased on our experience with 316(b) and

other regulatory programs, we want to em-

phasize that it is important to plan the 316(b)

compliance process. The rule will be complex

and have several specialized definitions and a

long sequence of required steps (see sidebar

“Schedule and Scope of IM and EM Moni-

toring”). Many of the steps are expected to be

poorly defined, including in their relationship

to other parts of the process. Development of

a robust schedule of the steps required at each

facility will be important.

Fully understanding the rule, including pro-

posed changes to 40 CFR and the preamble as

well as the supporting documents, will be essen-

tial. Key definitions are expected to be incom-

plete and will require interpretation. Available

options should be carefully considered.

The final rule invests the NPDES Direc-

tor with considerable authority, particularly

relative to EM. Although the criteria avail-

able to the NPDES Director for assessing

entrainment BTA are defined at 40 CFR

125.98(e), there is considerable discretion

available. Similarly, the peer review process

for the EM assessment will bring third-party

reviewers to the process. The National Ma-

rine Fisheries Service and U.S. Fish & Wild-

life Service also may play a substantial role

in planning of the studies, interpretation of

the results, and recommending BTA. All of

these circumstances argue that careful plan-

ning and regular communication with the

agencies will be helpful both in minimizing

the potential for a “re-do” of analyses and

ensuring cost-effective compliance.

The final 316(b) rule has the ambitious

goal of regulating the interaction between

complex, dynamic biological systems and

engineered facilities. To do this, it requires

application of several disparate disciplines in

the context of facilities that vary dramatically

relative to a number of key factors. We be-

lieve that cost-effective compliance with the

rule demands careful and creative planning to

understand the risks and opportunities of the

candidate approaches. ■

—Mark Gerath ([email protected]) and Steve Cibik ([email protected])

are prinicipal scientists at ECT Inc. John

Burnett ([email protected]) is CWA §316 practice leader at HDR.

Schedule and Scope of IM and EM Monitoring

With the expectation that the final rule’s

submittals will be coordinated with the

National Pollutant Discharge Elimination

System permit renewal, the timing and

nature of impingement mortality (IM) and

entrainment mortality (EM) monitoring

may present schedule challenges.

Monitoring might be performed for

several reasons, including: understanding

potential monetized benefits, design and

optimization of newly installed technolo-

gies, estimation of the reductions in IM

and EM from some baseline condition,

and/or for compliance assessment.

The nature of programs to achieve these

goals is likely to vary, particularly in tim-

ing relative to any retrofits. For rates as-

sociated with the existing cooling water

intake structure, we believe that data col-

lected during the Phase II effort will often

be adequate. The 2011 proposed rule was

confused relative to the timing and pur-

pose of IM and EM monitoring. We hope

that the final rule is clearer and more

practical relative to the scope and timing

of any monitoring.

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NERC CIP COMPLIANCE

Introduction to NERC CIP Version 5Even if your generating facility was exempt from previous versions of NERC’s

Critical Infrastructure Protection standards, the latest version dramatically steps up the number of facilities encompassed, so the odds are high that your plant will be within its scope.

Steven Parker

The North American Electric Reliability

Corp. Critical Infrastructure Protec-

tion (NERC CIP) standards Version 5

represents the first major change in require-

ments and approach since its predecessor,

Urgent Action Standard 1200, was approved

more than a decade ago. The most notable

change is the tiered impact rating system,

which classifies bulk electric system (BES)

Cyber Systems into High, Medium, and Low

categories. This approach results in all cyber

assets that could impact BES Facilities being

in scope for the CIP standards.

Because the standards become effective

less than two years from now (Table 1) and

cover so many more facilities than previ-

ous standards (in version 5, all generating

plants that meet the BES definition will be in

scope), now is the time to become thoroughly

familiar with the latest version to ensure the

reliability of the system we all depend upon.

In previous CIP versions (Version 3 being

the most recent, as Version 4 was effectively

omitted), only those generation facilities de-

termined to be Critical Assets by their owner/

operators were required to comply with the

standards. Even then, a wide range of assets

were excluded simply by avoiding the use

of routable communication protocols. The

result was that a broad swath of generation

facilities had virtually no compliance obliga-

tions under the CIP standards.

Version 5’s tiered classification brings all

BES generating facilities into scope for at

least some requirements. A new “bright line”

approach to identifying cyber assets that

qualify for protection under the CIP stan-

dards ensures that most systems used in the

operation of any BES generation facility will

be in scope for at least some requirements.

Cyber assets meeting certain criteria will be

grouped into systems and assigned a High,

Medium, or Low impact rating based upon

the characteristics of the facility they support.

For example, BES Cyber Systems at plants

larger than 1,500 MW may receive a Me-

dium impact rating, while most black-start

units will be Low impact. All such systems,

referred to officially as BES Cyber Systems,

will be assigned at least a Low impact rating

and will be required to comply with at least a

portion of the requirements.

There is a single requirement for Low-

impact BES Cyber Systems, but that single

requirement has a broad scope. Generators

are required to develop and implement secu-

rity policies that address four specific areas

of concern: security awareness, physical se-

curity, remote access connections, and inci-

dent response. The rest of this article focuses

on these basic considerations that apply to all

BES Cyber Systems.

The importance of the implementation re-

quirement cannot be ignored. Simply creating

policies will not be sufficient for compliance.

Policies must be implemented through the

deployment of processes, procedures, and

controls that meet the objectives described in

the written policies. Significant flexibility is

provided with respect to the design of con-

trols, but the stated objectives must be met,

and generators will be audited against what

has been implemented.

Security AwarenessThe responsibility for security falls, to some

extent, on each and every individual within

an organization. Security attacks often take

advantage of individuals who ignore, or are

unaware of, basic security precautions.

For example, the most effective (and com-

monly used) initial attack vector into an orga-

nization is email. (See also “Just Hop on the

Bus, Gus: 13 Ways to Hack a Power Plant” in

this issue.) Attackers send messages designed

to convince an individual to open an attach-

ment or click a link. Upon doing so, security

vulnerabilities can be exploited, giving con-

trol of the victim’s machine to the attacker,

and with it, an entry point to an organiza-

tion’s internal computer networks, including

the generation control systems.

To strengthen security, CIP Version 5

requires that programs be implemented to

promote awareness of security risks and re-

inforce secure precautions that should be

taken. The development and implementation

of such a program is one of the four required

protections for Low-impact systems.

A security awareness program should be

broadly applicable across an organization.

Although it is not necessary to track aware-

ness messages to ensure that each individual

receives every message, the program should

be developed and executed in a manner that

makes it likely that all individuals in the orga-

nization will regularly receive such messages.

Simply creating policies will not be suffi-cient for compliance. Policies must be imple-mented . . . and generators will be audited against what has been implemented.

Milestone Date Reference

Industry approval of Version 5 11/5/12 http://bit.ly/1jX35sF

NERC Board of Trustees approval 11/26/12 http://bit.ly/1nsAQY7

NERC petition to FERC for approval 1/31/13 http://bit.ly/QJ7ruQ

FERC approval (Order 791) 11/22/13 http://1.usa.gov/1iHeh03

Published in Federal Register 12/3/13 Federal Register pages 72755 -72787

Effective date of rule 2/3/14 Federal Register pages 72755 -72787

Effective date of standards 4/1/16 http://bit.ly/1mJERr9

Table 1. NERC CIP 5 milestones. Source: EnergySec


NERC CIP COMPLIANCE

Many such general security awareness

messages are appropriate for general audi-

ences across an organization. For example,

tips on the selection and use of strong pass-

words help ensure compliance with pass-

word policies and reduce the likelihood of

passwords being guessed. Another common

topic is email security. General awareness of

the types of risks posed by email, including

how to recognize the attacks that are often

sent via email, can substantially reduce the

probability, or at least the frequency, of suc-

cessful intrusions via this method.

Physical SecurityThe second area of concern that requires poli-

cy action is physical security, a control that is

critical to the overall security of any digital sys-

tem. If an attacker can gain physical access to

a computer system or other electronic device,

full compromise of the device is nearly assured.

Likewise, physical access to network ports or

communication media can allow an attacker

to intercept, interfere with, or even inject mes-

sages onto a network. In control environments,

this can have catastrophic consequences.

Access to BES Cyber Systems and associ-

ated networks should be restricted to only those

personnel who require access for the perfor-

mance of their jobs. Physical security controls

must be implemented to enforce access restric-

tions and to allow for the detection of unauthor-

ized access. Such controls can be preventive,

or detective. Preventive controls are designed

to prevent unauthorized access from occurring.

Examples are fences, walls, doors, and locked

cabinets. Detective controls are designed to

emphasize the detection of unauthorized access

and would activate an appropriate response

procedure. Examples include alarm systems,

video surveillance, and guard patrols.

Remote Access ConnectionsThe third area of concern is remote electronic

access. The single greatest reason that cyber-

security is such a significant issue today is the

tremendous increase in connectivity of critical

systems and the global reach of the Internet.

Any system that is connected to the Internet—

even indirectly through multiple other systems

or networks, and even if a plant worker is un-

aware of those connections—has some risk of

compromise by motivated parties.

Although attacks can also be conducted

locally by individuals that gain physical ac-

cess, the near ubiquity of network connectiv-

ity has enabled attacks that many engineers

would find inconceivable. Remote connec-

tivity to systems increases the pool of poten-

tial attackers by orders of magnitude, while

simultaneously reducing the cost, difficulty,

and risk an attacker must overcome.

Remote connections come in many forms

and are used for many purposes. Internet ac-

cess, dialup, serial connections, wide area

networking, and wireless are examples. These

may exist for many legitimate business pur-

poses including employee remote access, ven-

dor support, operational control, and business

partner communications. A good CIP Version

5 process requires that such connections be

controlled and monitored to reduce the likeli-

hood of successful intrusions and to detect and

quickly respond to those that do occur.

Incident ResponseDespite the best efforts of organizations to

protect their cyber assets, successful attacks

are likely to happen, at least occasionally. Or-

ganizations must be prepared to respond ap-

propriately to such events not only because

the potential financial costs of equipment mal-

functions or worse can be enormous but also

because the longer a security breach is unad-

dressed, the greater the potential damage not

only to an individual facility but also to other

facilities and the interconnected grid.

Incident response plans should be estab-

lished to effectively handle intrusions and

other cybersecurity events. These should in-

clude the identification and training of per-

sonnel who will be responsible for the initial

response, investigation, and containment, as

well as notification and escalation proce-

dures to senior management, legal, and com-

munications staff.

Plans should include provisions for external

notification of law enforcement and other ap-

propriate agencies or organizations such as the

Department of Homeland Security’s Industrial

Control Systems Cyber Emergency Response

Team (ICS-CERT), the Electricity Sector

Information Sharing and Analysis Center

(ES-ISAC), and/or other state and local author-

ities. Plans should also allow for the involve-

ment of commercial incident response and

forensic investigation specialists, as needed.

Recent DevelopmentsAlthough there is a dramatic expansion of sys-

tems that are in scope for NERC CIP Version

5, there is still room for improvement. In its or-

der approving Version 5 of the CIP standards,

the Federal Energy Regulatory Commission

(FERC) raised concerns regarding the lack of

specific requirements for Low-impact systems.

Although the standard requires that policies

be developed and implemented in four key ar-

eas, there are no specific requirements, and

no criteria against which to measure the ef-

fectiveness of controls that are actually put in

place. The lack of specific requirements leaves

FERC with little oversight or assurance that

security risks will be adequately addressed.

To correct this situation, FERC has direct-

ed NERC to either develop new requirements

for Low-impact BES Cyber Systems or de-

velop “objective criteria” that can be used to

evaluate the effectiveness of the controls that

are deployed.

Although it is not yet known which ap-

proach will be taken or what potential spe-

cific controls may be required, the objectives

are clear, as is the need. Organizations should

develop and deploy controls that provide pru-

dent protections in the four identified areas

of concern. Although some adjustments may

need to be made based on the actual require-

ments developed by NERC, those organiza-

tions that have worked proactively to address

these areas of risk will be both more secure,

and better positioned for compliance.

The concern over cybersecurity risks to criti-

cal infrastructure, of which power generation is

a significant element, is unlikely to wane in the

foreseeable future. In fact, the issue is receiving

increasing scrutiny from the federal govern-

ment and, recently, state utility commissions

and legislatures. The expectation that critical

infrastructure operators will proactively and ef-

fectively address cyber risks is increasing.

Additionally, with respect to the NERC

CIP standards, there is an active effort to shift

the focus of audit and enforcement away from

a strict measurement against specific require-

ments toward a qualitative assessment of in-

ternal controls. This move will reinforce the

need for holistic approaches that emphasize

real security rather than mere compliance.

Compliance requirements can be an effec-

tive catalyst to kickstart cybersecurity efforts,

but if they remain the only focus, long-term

success is unlikely. Holistic efforts that view

cybersecurity as a means to compliance, rath-

er than assuming compliance is the basis for

security, are the only effective way to address

both concerns now and into the future. ■

—Steven Parker, CISA, CISSP is president and a founding director of Energy Sector

Security Consortium (EnergySec). He has been engaged in electricity sector critical

infrastructure protection for more than a decade, including eight years at PacifiCorp.

He was also part of the team that estab-lished the NERC CIP audit program at the Western Electricity Coordinating Council.

The near ubiquity of network connectivity has enabled attacks that many engineers would find inconceivable.

PCL.com

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TOGETHER WE BUILD SUCCESS.

525 MW Combined Cycle Power Plant

Mona, Utah



NERC CIP COMPLIANCE

Identifying CIP Version 5 Assets in GenerationThe latest version of Critical Infrastructure Protection standards applies to dif-

ferent facilities and assets than previous versions, so the first, critical step in compliance is to determine which facilities and assets are subject to the new standards.

Tom Alrich and Donovan Tindill

Generators of electric power face a big

effort to comply with the upcoming

North American Electric Reliabil-

ity Corp. Critical Infrastructure Protection

(NERC CIP) Version 5 (V5) cybersecurity

standards. Whether or not your facility has

had to comply with previous NERC CIP

standards, a plant’s cost of compliance will

depend directly on the number of “cyber

assets” that are in scope. This article is in-

tended to give a basic overview of how gen-

erators can identify the cyber assets in scope

for CIP V5.

Is It a Bulk Electric System Facility?The first step is to determine if a facility is

in scope for CIP V5 at all. According to the

new Bulk Electric System (BES) definition,

if a generating facility is connected to the

grid at 100 kV or higher, it is a BES facility

(with a few exceptions), and it is in scope

for CIP V5.

The next step is determining whether the

plant is “Medium” or “Low” impact under

V5. Generation facilities are not considered

“High” impact; this status is reserved for

BES control centers that meet specific crite-

ria. For the criteria for classifying facilities in

CIP V5, see Attachment 1 of CIP-002 version

5 (written as CIP-002-5) online (http://bit.ly/

ShrWQJ).

There are only two criteria in NERC CIP-

002-5 that classify generation as Medium

impact. In Attachment 1 of CIP-002-5, a

generating station is Medium if “a group of

generating units at a single plant location”

can generate 1,500 MW. Additionally, a gen-

erating station is Medium if the Planning Co-

ordinator or Transmission Planner informs

you that your plant, or specific unit(s) in the

plant, are required to operate for reliabil-

ity purposes (“reliability must run”). If your

plant does not meet one of these two criteria,

it is defined as Low impact.

If your generating station is considered

Low impact, there is no requirement to iden-

tify individual Low-impact cyber assets, and

this will remain true for the new Low-impact

requirements being developed by NERC in

response to the Federal Energy Regulatory

Commission’s directive in Order 791. As a

Low-impact asset, the rest of this article won’t

directly apply to your generating station.

However, if your whole plant or individual

unit(s) are Medium impact, the first step is to

inventory your cyber assets, defined as “pro-

grammable electronic devices.” This includes

servers, workstations, distributed control sys-

tem (DCS) controllers, programmable logic

controllers (PLC), and other devices involved

in the operation of the generating station.

However, not all cyber assets will be

in scope for CIP V5, even at a Medium-

impact facility. Those that are in scope

are called “BES Cyber Assets.” These are

grouped into “BES Cyber Systems,” to

which the CIP V5 requirements apply.

There are two basic approaches to identi-

fying BES Cyber Systems: “bottom-up” and

“top-down.” These aren’t mutually exclusive;

in fact, at least two of the NERC regions rec-

ommended that NERC entities use both ap-

proaches, because it is possible that some

BES Cyber Systems will be missed if only

one is used.

Bottoms UpIn the bottom-up approach, generators would

evaluate each cyber asset in operation in a

plant (for example, servers, operator stations,

routers, switches, PLCs, remote terminal

units, and so on) and determine if it meets

the definition of BES cyber asset, according

to the NERC Glossary: “A Cyber Asset that

if rendered unavailable, degraded, or mis-

used would, within 15 minutes of its required

Primary systems Secondary systems

Supervision and control (governor, frequency,

voltage, automatic generation control, etc.)

Water treatment

Dynamic response Fuel source (gas pipeline, coal handling, storage, etc.)

Startup, shutdown Emissions control, fly ash, flue gas desulfurization

Exciter Flame scanners, oxidizers

Protection relays ICCP communications

Power stabilizers Vibration (if required to start up unit)

Network infrastructure

Table 1. Typical generation cyber assets and systems. Source: Honeywell

The best starting point for inventorying cyber assets is the control system drawings, network drawings, and IP address lists.


NERC CIP COMPLIANCE

operation, misoperation, or non-operation,

adversely impact one or more Facilities,

systems, or equipment, which, if destroyed,

degraded, or otherwise rendered unavailable

when needed, would affect the reliable op-

eration of the Bulk Electric System.”

This isn’t an easy definition to digest, but

it essentially says that the cyber asset must

have an impact on the Bulk Electric System

within 15 minutes if it is misused, degraded,

lost, or compromised. “Impact on the BES”

typically means impact on the generating

station that hinders or prevents it from ful-

filling its purpose (that is, generating power

when required).

For example, the DCS will very likely

have an impact in under 15 minutes, so the

component cyber assets will be BES cyber

assets. In another example, characteristics

of a particular coal-handling system might

allow it to be inoperable for hours or days

before the plant has to shut down, so its

coal-handling cyber components won’t be

BES cyber assets.

The best starting point for inventorying

cyber assets is the control system drawings,

network drawings, and IP address lists. Gen-

erator control becomes the starting point, and

other systems are next (Table 1). In a typical

control system, about half the devices are IT-

type technology (computers or networking)

and the remainder are control system devices

(including DCS controllers, serial converters,

and PLCs). All these cyber assets require in-

spection and inventory, plus a determination

on whether or not each cyber asset meets the

BES cyber asset definition (it affects the BES

within 15 minutes).

Once BES cyber assets have been identi-

fied, they need to be grouped into BES Cyber

Systems. This is an exercise left to the discre-

tion of the generator. Generators can reduce

compliance paperwork by grouping many

BES Cyber Assets into a single large BES Cy-

ber System. However, if a generator defines

the BES Cyber Systems too expansively, the

generator may end up including BES cyber

assets that don’t meet the definition, unnec-

essarily increasing the compliance effort.

As a general rule, most consultants familiar

with CIP will create BES Cyber Systems by

grouping cyber assets that work together to

fulfill a function (such as control, continuous

emissions monitoring system, or protection).

Take It from the TopThe top-down approach starts with the BES

Reliability Operating Services (BROS),

which are discussed in the “Guidelines and

Technical Basis” of CIP-002-5. The BROS

are reliability services that BES facilities can

provide to the grid. Table 2 identifies those

BROS that would typically apply to genera-

tion owners (GO) and generation operators

(GOP). (If the BROS don’t make immediate

sense, refer to Table 1, which lists potential

BES Cyber Systems in a power plant.)

The systems that fulfill one or more BROS

should all be considered “potential BES Cy-

ber Systems.” But because a BES Cyber

System is composed of BES Cyber Assets,

you need to go back to the BES Cyber As-

set definition and make sure it still applies.

For instance, if a “potential BES Cyber Sys-

tem” doesn’t have a 15-minute impact on the

Bulk Electric System, then it won’t be a BES

Cyber System, even though it does fulfill a

BROS function.

Before a “potential BES Cyber System”

becomes an actual one, there is one more step

to take. The generator needs to go back to the

definition of BES cyber asset (cited above)

and make sure each “potential BES Cyber

System” meets the definition. In particular,

some “potential BES Cyber Systems” may

not pass, as they don’t have a 15-minute im-

pact on the BES.

To summarize the top-down approach:

Identify the BES Reliability Operating Ser-

vices that are performed by the generating

station and then identify the BES Cyber

Systems that execute or enable one or more

BROS. The BES Cyber System classification

as Medium or Low depends on the impact

level of the plant.

Large PlantsIf a generating facility meets Criterion 2.1

of Attachment 1, there is a further provision

in that criterion that states: “the only BES

Cyber Systems that meet this criterion are

those shared BES Cyber Systems that could,

within 15 minutes, adversely impact the re-

liable operation of any combination of units

that in aggregate equal or exceed 1500 MW

in a single Interconnection.”

This statement indicates that the generat-

ing facility could be Medium impact, but it

may have few or no Medium-impact BES

Cyber Systems, because a BES Cyber Sys-

tem has to have the capability of affecting the

entire generating station. A good example of

this condition is a DCS that controls only 800

MW of generation at a 1,600-MW facility

and has no capability to affect the full 1,600

MW at the site. In this example, the plant

would be Medium impact, but the DCS is a

Low-impact BES Cyber System.

Generators looking to reduce their CIP

compliance burden by taking advantage of

this provision need to keep in mind that sim-

ply stating that the BES Cyber Systems can-

not affect 1,500 MW will not be sufficient.

They will need to prove this position by

showing the work related to the identification

of BES Cyber Systems through the bottom-

up and top-down approaches. The generator

must also document why each BES Cyber

System doesn’t affect 1,500 MW and show

that it isn’t networked with other BES Cyber

Systems that do affect 1,500 MW.

Complex DeterminationsThe asset identification process in NERC

CIP Version 5 is much more complicated

than it was in CIP Versions 1 through 3. If a

generating station will be classified as Low

impact in V5, the process won’t be exces-

sively difficult. But owners of Medium-im-

pact generating stations will require a deep

understanding of how to identify cyber as-

sets in scope. The cost and effort required

to achieve NERC CIP V5 compliance will

depend heavily on this understanding. ■

—Tom Alrich (tom.alrich@honeywell .com) is energy sector security lead for

Honeywell International and focuses on the electric power industry and compli-

ance with NERC regulations for cyber and physical security. Donovan Tindill,

CISSP, senior security & compliance con-sultant, Honeywell Industrial IT Solutions, specializes in cybersecurity for industrial

automation and control systems for a wide variety of industries and has been

involved with NERC CIP compliance since 2005.

Entity registration RC BA TOP TO DP GOP GO

Dynamic response X X X X X X

Balancing load and generation X X X X X X X

Controlling frequency X X X

Controlling voltage X X X X

Managing constraints X X X

Monitoring and control X X

Restoration X X X

Situational awareness X X X X

Inter-entity coordination X X X X X X

Table 2. BES Reliability Operating Services. Source: CIP-002-5.1 Guidelines and

Technical Basis


NERC CIP COMPLIANCE

When Old Systems Meet New Realities: Adding Security Controls to Generating PlantsWhether or not your power plant falls under the new Critical Infrastructure

Protection standards (and many more will than in the past), you should be adding security controls. Here are some lessons learned to help you manage that process.

Michael Toecker, PE

On August 14, 2003, large parts of the

Northeast and Midwest of the U.S.

and the Canadian province of On-

tario experienced one of the largest black-

outs in history: 61,000 MW of electric

load were lost, affecting the lives and busi-

nesses of about 50 million people in the af-

fected areas. The U.S. and Canada created

a joint commission to study the blackout,

determine its causes, and develop recom-

mendations to reduce the potential for fu-

ture outages. The discovered causes of the

Northeast Blackout were condensed into

four groups (summarized from Northeast

Blackout report, pp. 18–19):

■ Failure of entities to assess and understand

the inadequacies of their power system.

■ Inadequate situational awareness leading

to lack of recognition that the system had

deteriorated.

■ Inadequate vegetation management along

transmission rights-of-way.

■ Failure of reliability organizations to

provide effective real-time diagnostic

support.

The commission made 46 recommen-

dations to reduce the possibility of future

outages, and the severity of ones that might

still occur. The most interesting part of this,

considering the causes identified, was that

15 recommendations directly addressed

physical and cybersecurity issues, while

neither physical nor cybersecurity was

identified as a major cause of the blackout.

The Security Working group ruled out a cy-

ber attack and unintentional consequences

of a currently active virus (SQL Slammer),

but it identified how technology had con-

tributed to the blackout due to degraded

situational awareness.

The implication here is clear: A third of

the Northeast Blackout recommendations

were related to improved cyber and physi-

cal security because the investigation showed

how poor the cybersecurity of the EMS/

SCADA (energy management system/super-

visory control and data acquisition) systems

used for managing the grid was.

These recommendations led directly to

development of the North American Elec-

tric Reliability Corp. (NERC) Urgent Ac-

tion 1200 standards during 2004–2005 and

the creation of the NERC Critical Infra-

structure Protection (CIP) standards, which

we have today.

Generation was never a part of the Urgent

Action 1200 standards, but attention has shifted

over the past several years due to awareness that

generators are a crucial part of a reliable grid.

NERC CIP Version 5The latest edition of the NERC CIP stan-

dards should be NERC CIP Version 5. I say

“should” because the Federal Energy Regu-

latory Commission has directed NERC to

make changes to the standards that will likely

result in a Version 6 in 2015. These changes

cover four major areas, one of which ad-

dresses a lack of objective requirements for

“Low”-impact assets. The majority of North

American generating facilities that have not

had specific technical and procedural regula-

tions so far will fall into that category. (For

more on determining facility and asset clas-

sifications, see “Identifying CIP Version 5

Assets in Generation” in this issue.)

Generation facilities will likely be classi-

fied as either Medium or Low impact, based

on a set of bright-line criteria identified in

CIP-002-5. If your facility is a Medium im-

pact one, you’ll have a set of prescriptive

requirements to follow, but a Low-impact

facility currently has a requirement for a

security policy, and not much else, until the

NERC development efforts are complete.

(Often Painful) Lessons LearnedWhen applying cybersecurity controls, you

are going to run into problems. Many of the

major control systems in power generation

plants are of an older variety and haven’t

been updated due to a combination of cost

concerns and sufficient current reliability.

Although network perimeter strategies will

generally have little effect on older systems,

the CIP-007-5 protections are another mat-

ter entirely.

Below I discuss two common challenges

I’ve encountered while involved in cyberse-

curity upgrades at generation plants, so that

engineers responsible for their own upgrades

can plan appropriately to either avoid them or

understand how to resolve them.

Lesson Learned: Old Code Can Be In-

compatible with Modern Cybersecurity

Tools. The origins of many plant control sys-

tems, especially distributed control systems

(DCSs), go back to the mid-1980s, and a lot

of the code from that era can still be found

in our systems and devices. There has sim-

ply not been a major reason to change, as the

hardware platforms for these control systems

are controlled by the same companies that

write the code. This code persists, and can

form an impediment to some cybersecurity

controls because it was simply not designed

from a maintainability and security perspec-

tive the way more modern code must be.

Old code affects systems in various ways

when adding cybersecurity. One way is that

older code isn’t developed to take advan-

tage of multi-core systems. This can lead

to performance bottlenecks that inhibit the

functionality of cybersecurity controls run-

ning alongside the DCS software and that

degrade the performance of some control

systems to an unacceptable level.

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NERC CIP COMPLIANCE

Another is that older code often uses hooks

and operating system features that were once

commonplace but are no longer acceptable,

and systems continue to use these features

in an unsupported manner. The most popular

feature that old code uses is running in kernel

mode instead of user mode.

Kernel mode is a highly privileged mode

of operation that allows full control of a sys-

tem, but it runs the risk of crashing system

processes. The modern convention is to write

user-mode programs that make use of care-

fully constructed kernel interfaces, so that

crashes are limited (and for various other

reasons). Using kernel mode was once a

necessary evil when processing and memory

resources were far more scarce, and the DCS

needed everything to maintain a high level of

functionality. The argument now is that pro-

cessing and memory are far more plentiful,

so a new design decision is needed that pri-

oritizes reliability and maintainability in an

environment of resource abundance.

Here’s an anecdotal example. I found sev-

eral years ago that a major power DCS ven-

dor was shipping modern workstations with

quad core processors, but it had disabled all

but one core to ensure that its code ran. This

was due to the old code being designed to run

as a single process; it was not capable of be-

ing swapped between the different cores due

to concurrency issues.

When the time came for generators to add a

basic cybersecurity protection—anti-virus—

the system wasn’t capable of running both

the anti-virus and the DCS at the required ef-

ficiency. This led to hangs, slowdowns, and

other problems that were quickly blamed on

the anti-virus, as it was the last thing added to

the system. Making the situation worse was

the tendency of anti-virus to scan each and

every file as it was opened. Anti-virus will in-

tercept calls to open files and will lock them

until scanning is complete. DCS systems, of-

ten because of old code, make significant use

of file operations and are capable of opening

and closing hundreds or thousands of files in

the course of a day. An assumption I made

while looking at the problem was that the old

code was written with an older design phi-

losophy that assumed exclusive access to the

file system, and it reacted badly when this as-

sumption was challenged by the anti-virus.

Many generators disregard this old code

argument and maintain that their DCS is

functional and that it performs its duties to

the level of expectation. I would argue that

the DCS may be functional, but it is rapidly

losing its functionality as the rest of the world

moves past it.

A good analogy is the use of hot sticks in

power. Hot sticks used to be made of wood;

they were functional and got the job done.

However, the excessive maintenance and up-

keep needed to keep them safe, along with

pressure from U.S. Occupational Safety and

Health Administration requirements and in-

surance companies, made wooden hot sticks

obsolete, and they have been replaced with

fiberglass. In a similar way, older code is be-

ing rendered obsolete due to the pressures of

cybersecurity and NERC CIP regulations;

consequently, newer code that can be better

maintained should be the new specification

going forward.

Lesson Learned: Controls Upgrades

Hold Surprises. Vendors to the generation

industry have stepped up in the past five

years, and most have support for NERC CIP

activities. Generally, this starts with a CIP-

007 R2 port/service specification, and slowly

increases in scope as the vendor gets more

involved in how its systems should be se-

cured. These vendor-supported activities rely

on having control system software that is at a

specific patch and revision level and having a

generator commit to maintaining that level.

This often results in a required control

system upgrade, where workstations, serv-

ers, network equipment, and potentially DCS

controllers must be replaced or modified to

ensure effective operation of those controls.

Considering the planning and testing that

must go into upgrading control systems, this

will not be a quick change-out, and it never

has been. What’s different today is that plants

that have procrastinated will have far more

systems to upgrade.

For many generators, engaging in a controls

upgrade for the sole purpose of adding cyber-

security controls will be daunting, so don’t

delay. Determine your exposure, and make

your plans far ahead of when NERC requires

compliance, especially if you already know

you will be a Medium-impact facility with

Medium bulk electric system cyber systems.

I’ve had the opportunity to talk to the

critical infrastructure group at Burns & Mc-

Donnell (disclosure: I’m a former employee-

owner), who have supervised many of these

upgrades over the past several years. They of-

ten recommend a full factory acceptance test

(FAT) to ensure the functionality of the con-

trol system and to exercise the cybersecurity

controls in a consequence-free environment.

This helps to identify problems in the control

system and to ensure corrections are made

before a system reaches the site.

Because there are often multiple control

systems that must integrate with one an-

other, and may even share a common set of

security controls, Burns & McDonnell often

recommends an “integrated FAT” to bring all

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NERC CIP COMPLIANCE

the vendors into the same space to test the

integrated components of the control sys-

tems. This is good practice, as the integration

points between control systems are often the

most prone to incompatibility problems.

Specific tasks during the FAT should include:

■ Testing functionality of the control system

and the security system.

■ Validating that ports and services meet

specifications.

■ Testing anti-virus while in operating con-

ditions.

■ Patching systems, and validating patch

management procedures on the system.

■ Creating, testing, and securing user and

machine accounts.

■ Validating that security monitoring is cap-

turing relevant logs.

Redesigning One-offs and Ancillary SystemsEvery generator has a one-off system or

two, or an ancillary system that has been

basically ignored for years because it just

worked. These systems will be surprises

when you add cybersecurity controls, as

they will likely have little vendor support in

the way of cybersecurity and an unknown

upgrade path. Most of these discoveries fol-

low the rule of “the last 20% of the project

takes 80% of the time.”

Encountering one of these systems will

likely cause a flurry of activity, because

it won’t fit into the cybersecurity model

you’ve created for the rest of your control

system. This is likely to be a system with

limited connection to a good, monitored

network. Such systems will usually be old-

er, missing patches, and sometimes have no

upgrade path.

It will be tempting to leave these systems

operating as one-offs and not do the rede-

sign to bring them into your cybersecurity

model. Resist this temptation, as manu-

ally conducting cybersecurity activities is

a human performance issue that increases

the risk of both noncompliance and com-

promise. Take the effort to identify these

systems as quickly as possible, make the

necessary network adjustments, and work

with your security and control system ven-

dors to include these systems in the cyber-

security model.

Share Lessons LearnedThe addition of cybersecurity at your facility

is going to bring with it a lot of changes, and

it’s going to introduce problems as well. At

best, you will encounter changes in systems,

in procedures, and in how you look at main-

taining your control systems in the future.

The key to successfully adding these controls

is first ensuring that you have a plan and then

executing that plan while watching for prob-

lems to develop.

This article mentions just a few of the

common problems likely to surface when

adding security to an existing system. To

gain a more comprehensive understanding

of your situation, network with your peers

and user groups to identify other potential

problems as well. A larger community-

based effort will be needed over the next

few years to increase communication be-

tween generators who have cybersecurity

and CIP responsibilities.

We are in the business of producing com-

petitive and efficient electric power, but re-

liability is everyone’s responsibility, and

security is a component of reliability.■

—Michael Toecker, PE (toecker @context-is.com) is a consulting engineer at

Context Industrial Security and has extensive experience in NERC CIP compliance, control system security, and how to implement both

in the context of power generation.

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Managing the Changing Profile of a Combined Cycle PlantWhether it’s market forces or other factors leading to a change in operating mode,

going from baseload to flexible operation places substantial new stresses on a plant and its staff. Knowing what you’re getting into is key to successfully managing the transition.

Neva Espinoza, Bill Carson, and Rick Roberts

With the growing need for opera-

tional flexibility across the power

industry, the combined-cycle gas

turbine (CCGT) fleet is increasingly being

subjected to load-following and cyclic opera-

tion. This change in operating mode is intro-

ducing new types and higher rates of damage

and can result in reduced performance and

increased operation and maintenance (O&M)

and repair costs. To meet these challenges,

today’s fleet is taking strategic and tactical

measures, and the Electric Power Research

Institute (EPRI) is compiling information on

effective approaches and best practices.

Changing LandscapeOver the past decade, the pattern of duty

modes and plant dispatch of CCGT plants

has changed. This change involves a general

shift for CCGT plants from baseload to flex-

ible operation with increased frequency and

level of cycling of these plants.

Flexible operation is broadly defined as

any mode of operation other than baseload,

and includes several specific types of duty

modes. Two-shifting is starting up and shut-

ting down a plant each day to meet load de-

mand during periods of high demand. Double

two-shifting is starting up and shutting down

a unit twice a day to match the early morning

and evening peaks in load demand. Load fol-

lowing is operating online for more than 48

hours, with varying load throughout the day

as demand changes. Many times these plants

turn down to some minimum load when de-

mand is low.

Whatever the duty mode, flexible opera-

tion typically involves more frequent start-

ups, more rapid ramping, low load operation,

and more frequent shutdowns or layup.

Factors contributing to this trend include

reduced overall demand following the eco-

nomic recession, competition, changes in

fuel prices, aging plants, demand for a more

reliable power grid, and stricter environmen-

tal controls. In some regions, one key factor

is the increasing deployment of intermit-

tent renewable generation, such as solar and

wind, which is dispatched as “must-take” and

forces fossil plants to provide load-balancing

services. In this context, relatively small dif-

ferences in costs and reliability can make a

large difference in station ranking, leading to

many older, less-efficient CCGT plants being

required to load follow.

Effects of Flexible OperationCCGT plants have less operating flexibility

than conventional steam plants, which can

be run down to 40% of rated output, while

CCGT plants have difficulty in getting below

60%. A further problem is the length of time

that it takes for the heat recovery steam gen-

erator (HRSG) plant to achieve full output.

Hence, although a CCGT plant may be able

to produce power relatively quickly, it is not

really suitable for load-following until some

time after startup.

EPRI research has identified a number of

common damage mechanisms related to cy-

cling. Cycling load is associated with stress-

es from varying temperatures and pressures,

which can trigger fatigue and fatigue-related

damage mechanisms.

Thermal Fatigue. The most common

problem resulting from cycling is thermal

fatigue damage, which manifests itself in the

form of material deformation, cracking of in-

dividual components, or mechanical failure

of structures. This mechanism is caused by

the large temperature swings associated with

flexible operation.

Thermal Mechanical Fatigue. This

mechanism, which occurs in rotating compo-

1. Wide range of challenges. This graphic details the many areas of potential cycling

damage in a combined-cycle plant. Courtesy: EPRI



nents such as turbine blades, vanes, and other

hot-section components, is caused by ther-

mal expansion and contraction, reinforced by

mechanical strains associated with centrifu-

gal and torsional loads.

Differential Thermal Expansion. This

damage occurs when components undergo

high thermal growth relative to surround-

ing components. This mechanism can affect

combustor cans, boilers, and HRSGs.

Corrosion. Two-shifting or any other op-

eration that challenges the ability of the plant

to maintain water chemistry can lead to in-

creased corrosion and accelerated component

failure. This mechanism can manifest itself

as increased problems with corrosion-fatigue

of economizer tubing and stress corrosion in

steam turbines (STs).

Impaired Performance of Environ-

mental Control Equipment. Load follow-

ing and other modes of flexible operation can

affect the performance of selective catalytic

reduction (SCR) systems.

Figure 1 shows the types of potential cy-

cling-related damage that might be expected

in different areas of a CCGT plant.

What are the consequences of this damage?

Recent investigations found that a change

from baseload operation to operating under

cycling conditions can result in increased

capital spending for component replacement,

increased routine O&M costs due to equip-

ment wear-and-tear, lower availability due

to higher failure rates and outage times, and

higher fuel consumption due to operating in

less than an optimal manner (more stops and

starts and more load changes), negatively af-

fecting unit heat rate. Also, when a unit is

subjected to cyclic operation, reliability can

suffer. These consequences can lead to a unit

becoming less reliable and more expensive to

operate, resulting in a lower dispatch order

and increased need for additional flexibility,

effectively creating a spiral of cycling opera-

tion leading to more cyclic operation.

In 2013, an EPRI study investigated the

impact of cycling on the O&M costs of

CCGTs with capacities of 110 MW to 492

MW. The results showed that the strongest

indicator of annual O&M costs was the

number of equivalent hot starts (EHS) that a

unit performs. The study assumed a hot start

equals 1 EHS, a warm start equals 3 EHS,

and a cold start equals 5 EHS.

The same study explored the equivalent

forced outage factor (EFOF) for CCGT plants

operating in both baseload and cycling modes.

EFOF is the fraction of a given operation pe-

riod in which a unit or a train is not available

due to forced outages. This particular param-

eter is very useful in measuring forced outages

in cycling power plants, because it takes into

account the derating hours.

Findings showed that the average EFOF

value for CCGT plants operating in the cy-

cling regime is about 3% higher than the

plants operating in the baseload mode in the

first six years of operation and about 1.5%

higher between six to 20 years of operation.

EFOF for cycling plants increases much

more abruptly between 20 and 30 years of

operation compared with baseload plants.

Figure 2 shows the average EFOF versus

lifetime EHS for CCGT plants operating in

cycling regimes.

The study also looked at the equivalent

planned outage factor (EPOF) for CCGT

plants operating in baseload and cycling

modes. Planned outages normally refer to

the removal of a unit from service to perform

work on specific components that is sched-

uled well in advance and has a predetermined

duration, such as annual overhaul, inspection,

and component testing.

In general, increased routine maintenance

is required due to increased levels of wear-

and-tear when a plant moves from baseload

operation to cyclic mode. Results showed

the planned outage levels for cycling CCGT

plants are within about 6% to 9% during the

first six years of operation and within about

4% to 6% for the next 14 years of operation.

The EPOF achieves its minimum level be-

tween 10 and 14 years. During the “major

component wear-out period,” which is near

the end of life (assuming major components

at or near end-of-life have not been replaced),

the EPOF value for cycling CCGT plants in-

creases to about 15% to 18%. Figure 3 shows

the average EPOF versus lifetime EHS for

CCGT plants operating in cycling regimes.

Another recent EPRI study documented

23 cases in which major HRSG components

unexpectedly reached end-of-life. Many of

these failures can be attributed to more fre-

quent cyclic operation than originally antici-

pated in the plant design. For components to

have a full design life, the factors anticipated

by the designer need to be similar to those ac-

tually experienced by the plant components

in service. These factors include the operat-

18

15

12

9

6

3

0

0 600 1,200 1,800 2,400 3,000 3,600 4,200

Eq

uiv

ale

nt

forc

ed

ou

tag

e f

ac

tor

(%)

Equivalent hot starts

2. More starts, more outages. This chart shows the average equivalent forced outage

factor v. lifetime equivalent hot starts for combined cycle gas turbine (CCGT) plants operating in

cycling regimes. Source: EPRI

Mean Upper limit Lower limit

18

15

12

9

6

3

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

Eq

uiv

ale

nt

pla

nn

ed

ou

tag

e f

ac

tor

(%)

Equivalent hot starts

Mean Upper limit Lower limit

3. Planned outages increase. This chart shows average equivalent planned outage

factor vs. lifetime equivalent hot starts for CCGT plants operating in cycling regimes. Source:

EPRI



ing temperature and pressure conditions,

temperature rates of change, external stresses

imposed by support systems, and corrosion

rates. If one or more of these variables dif-

fers from values anticipated by the designer,

a premature failure can occur.

Examples of documented cases of prema-

ture failures included weld failures in high-

pressure steam flow nozzles, catastrophic

leakage of high-pressure drum manway clo-

sures, turbine steam lead drainpipe failures,

parallel slide-gate valve failures, ST bypass

desuperheaters, lateral wye failures, freeze

damage, duct burner-related damage, and su-

perheater and reheater tube buckling.

Mitigation Measures: OperationsIn recent years, EPRI has conducted sev-

eral studies to better understand how CCGT

plants are responding to changing operating

conditions. The following is a sampling of

lessons learned from the studies.

Culture Change. An important factor

for success in transitioning from baseload to

cycling operation is the unit management’s

understanding that a culture change is neces-

sary at the site. This change has to begin with

unit management, and the changes will need

to be communicated to and understood by

unit staff. This transition will require leaders

who are willing to make tough choices, have

excellent communication skills, and have the

ability to help people in the plant understand

the reasons for the change and its impact on

the company, plant, and staff.

Four elements of plant culture, when

implemented, can properly aid in the transi-

tion from baseload to cycling operation: (1) a

change management plan, which provides a

step-by-step plan for guiding any change; (2)

a communication plan for informing staff of

changes; (3) personnel involvement, for en-

gaging personnel in the changing operations;

and (4) human performance improvement,

for providing training in new procedures and

avoiding human errors.

One priority for a cycling unit that once

was a baseload unit is to keep people focused

on having the unit ready when it is called to

operate. Staff must feel a sense of urgency

about their new operating role. The key to

success will be keeping people focused on a

day-to-day basis and ensuring a clear under-

standing of the goals of a cycling plant.

Mike Woodhouse, who managed Scottish-

Power’s Rye House Power Station, a 700-

MW CCGT plant in Hertfordshire, England,

that shifted from baseload to cycling opera-

tion due to market conditions, describes the

importance of plant culture this way: “Our

plant was fairly robust to begin with, so the

physical changes to the plant were pretty

minimal. The majority of it, the key thing,

was the people—developing optimized op-

erating procedures and training the staff in

them.”

Flexible Operations/Optimization Tri-

als. Prior to embarking on full flexible op-

erations, the plant management team should

plan a series of flexible operation/optimiza-

tion trials. Following the trials, a flexible

operations procedure should be written that

captures best practices developed during the

process.

According to Woodhouse, this is a criti-

cal part of planning. “As part of our upfront

planning, we conducted trials so that opera-

tors could get used to starting and stopping

the plant. The data from those trials was used

to help us understand what was working and

what needed to be changed.”

Operations Procedures. For plants

transitioning from baseload duty, existing

operational procedures will typically be bi-

ased toward steady-state operations and will

require a review as part of the planning phase

for flexible operations. Two shift–related op-




erational procedures should be reviewed and

updated. Following the flexible operations

trials, site operational procedures will need

to be updated to reflect the lessons learned

and best practices developed. New consid-

erations that should be incorporated into up-

dated cycling procedures include changes to

setpoints, normal operating bands, and ramp

rates.

Startup and Shutdown. For a baseload

plant, startup and load following are histori-

cally not given a great deal of management

attention, because the few starts that do oc-

cur are usually following overhaul periods

where intrusive work has been undertaken

that will introduce reliability issues, such as

interlocks not set and valve open/close limits

being out of calibration. For a plant to oper-

ate in a flexible mode, reliability issues must

be addressed in a more systematic approach,

with the emphasis on continual improvement

derived from teams responsible for various

areas of plant reliability.

Generally, if startup reliability is effective-

ly managed, shutdowns will also be reliable

because the same components (for example,

GT gas valves/boiler feed and steam valves)

are used. However, emphasis should be on

measuring trips from low load while shutting

down; these steps can often be overlooked in

the high operations workload of a shutdown.

Review of startups and shutdowns may

highlight needed changes. “In plant trials,

we learned that the control system needed to

be improved,” says Woodhouse. “When the

plant was operating in baseload, if the control

system didn’t work optimally at startup, it

was not a priority. But for flexible operation,

we had to make changes to allow smoother

and faster starts.”

Staffing Levels. Staffing levels for base-

loaded plants are typically based on steady-

state operation, where minimal operator

intervention is expected. Introduction of flex-

ible operations will change the responsibilities

and time commitments at different staff po-

sitions. Flexible operations trials can help to

identify the needed changes in staff levels.

“When the plant was a baseload plant, our

operations staff took responsibility for some

maintenance activities,” says Woodhouse.

“In that regime, once the plant was up and

running, the operating workload diminished.

But under cycling, the operations staff no

longer had time for maintenance tasks, so

we had to enlarge and strengthen our main-

tenance team.”

Staff Training. The changing skill re-

quirements of flexible plant operation will

require a review of the plant operations train-

ing process. Consideration should be given

to the following: (1) increasing the knowl-

edge in CCGT thermodynamics to support

the operators’ decision-making in startup/

shutdown scenarios; and (2) sourcing CCGT

simulator training when diagnosing sequence

faults and managing transients (for example,

high or low drum level can be undertaken).

A training program should be implemented

to develop two-shift operation skills, and a

method should be put in place to share les-

sons learned from shift to shift.

Continuous Improvement Process. An

effective approach for plants transitioning

from baseload to flexible operation is imple-

menting a continuous improvement process.

This technique involves identifying and

analyzing failures on a continuous basis and

using that information to make changes in

procedures to avoid future failures. When put

in place over time, these continual improve-

ments result in significant overall gains in the

major business metrics such as production

cost, reliability, quality, and lead time.

“Once you’re under way in flexible opera-

tions, it’s important to learn as you go,” says

Woodhouse. “Our continuous improvement

program gave us a structure to analyze every

failure to start and every drop in load, to find

a solution, and to feed that solution back into

the processes.”

Monitoring. As the plant enters an opera-

tional state not previously experienced, a re-

view should be undertaken of the operational

team’s plant inspections. For example, plant

items that will now be cycled frequently

(feedwater valves, fuel gas control valves,

and boiler casings, for example) will be more

vulnerable to performance deterioration.

“We found we had to do more frequent in-

spections,” says Woodhouse. “We were able

to reduce their rate as we got more mature.

But initially we did inspections of the gas

turbines and boilers every three months. The

biggest issue we found was thermal cycling-

induced cracks in the GT outlet ducts, which

meant we had to go in every three months

and complete inspections and weld repairs in

the ducts.”

Minimum Stable Generation (MSG).

Depending on an individual plant’s commer-

cial characteristics, achieving a low MSG

may be preferable to completely starting or

stopping the plant, when plant damage costs

and the risk of failure to start are taken into

account. Reducing a plant’s MSG can be

achieved by the same management strategy

as optimizing flexible operation; indeed, a

move to a low MSG is usually the first option

as a plant’s efficiency starts to dictate mini-

mized generation over loss-making periods,

such as overnight.

Plant Preservation (Layup). A strategy

document and operations procedures should

be developed for plant preservation during

layups of different duration. (See “Layup

Practices for Fossil Plants” in the February

2013 issue, online at www.powermag.com.)

Increased Levels of Automation. The

levels of plant automation should be reviewed

before the start of flexible operation trials to

ensure that the existing automation is func-

tioning to design and to identify any potential

improvements. During the review, consider-

ation should be given to the increased opera-

tor intervention required during the startup

and shutdown plant phases of operation to

ensure that the operators can maintain an

overview of the process at all times.

Mitigation Measures: MaintenanceFrequent cycling also impacts maintanence

practices, and changes need to be made to

adapt to the added stresses placed on the

plant.

Maintenance Team Structure. If the

team structure is unchanged from baseload

operation, that structure will not reflect the

new maintenance team challenges under the

flexible operating regime. The site mainte-

nance manager needs to produce a new team

structure capable of delivering the revised

maintenance requirements.

Time-Based Equipment Inspections.

The maintenance regime of a baseload plant

may use time-based equipment inspections

extracted from original equipment manufac-

turer (OEM) manuals. The existing routine

time-determined tasks in the maintenance

management system should be reviewed.

Where possible, the regime should be moved

to condition-based maintenance inspections,

thereby reducing the frequency of intrusive,

major inspections. In addition, the preven-

tive maintenance basis should be reviewed as

new stressors and failure mechanisms have

been introduced.

Changing Maintenance Strategies.

Each GT and heat recovery boiler design

will have differing responses to the effects

of flexible operation. The OEM should be

consulted for any design-related issues that

will form a boundary for flexible operation.

For example, an OEM will have a limit on

the number of starts or equivalent operating

hours (EOHs) between inspections. A com-

mercial decision will need to be made either

to restrict the number of plant starts to stay

within the current inspection regime or to op-

erate starts unconstrained and flex the timing

of GT inspections.

HRSG: GT Exhaust Duct Cracking.

The exhaust gas duct from the GT to the first

flexible expansion joint is at risk of stress-in-

duced cracking, particularly in welded areas.

The internal surface and external cladding of

the duct should be regularly inspected during

GT outages. Damage should be ground out

and repaired during a scheduled outage.



GT: Accelerated Degradation of Hot

Gas Path (HGP) Components. HGP com-

ponents may fail before reaching the de-

signed EOH limit. These components should

be monitored during inspections. The OEM

should be consulted to design flexible, oper-

ation-resistant components.

ST: Thick-Section Cracking. Thermal

stresses develop due to a mismatch between

the temperature of the admitted steam and the

metal in the first-stage region of the turbine.

These high stresses can initiate and propagate

cracks in the inner and outer casings and ro-

tors. Possible measures include following the

OEM’s recommended starting and loading

procedures, installing steam bypass systems,

and installing thermocouples to monitor criti-

cal temperatures and temperature differen-

tials during starting, loading, and unloading.

Instrumentation and Controls: Alarm

Systems. If the alarm system is not careful-

ly managed, operators can be deluged with

low-priority alarms and status change mes-

sages when the plant is at its most dynamic

on startups and shutdowns. Alarm manage-

ment should be reviewed to incorporate find-

ings from the flexible operation trials. A plan

should be created to eliminate unactionable

alarms, bad actors, and alarm floods to prop-

erly manage plant status changes. (See “How

to Avoid Alarm Overload with Centralized

Alarm Management” in the February 2010

issue, online at www.powermag.com.)

What are the chief lessons for plants chang-

ing their operating profiles? Woodhouse sees

two main messages. “One big learning point

is that preparation and planning are key. Do

as much as you can upfront before you com-

mercially start flexible operations. Don’t

expect to blindly go into it and see what hap-

pens. Once you get into it, you’ll have more

than enough facing you day to day. The other

learning point is that after you’re under way,

you want to have some kind of continuous

improvement process in place because you’ll

be faced with a lot of issues, and unless

you’ve got a process to capture and manage

them all, you can get overwhelmed.”

Future EPRI ResearchIn 2014, EPRI is planning several research

studies to assist combined-cycle plants in op-

erating more efficiently and avoiding damage

under conditions of operating flexibility.

One project in 2014 will help plants design

a systematic approach to reducing minimum

load for coal-fired units, with a combined-

cycle plant project to follow in 2015. The

project will use lessons from plants that have

successfully achieved minimum loads as part

of EPRI’s ongoing Operational Flexibility

Implementation Case Studies. The project

will include a web-based tool to aid in op-

erational tests necessary to achieve a lower

minimum load.

Another project will develop an integrated,

holistic procedure for plant layup (2014) and

provide a web-based tool (2015) that guides a

unit through the critical steps for plant layup.

The authors wish to acknowledge Mike

Woodhouse ([email protected]), who

served as operations, engineering, and plant

manager at Rye House Power Station in

Hertfordshire, England, for 14 years. ■

—Neva Espinoza ([email protected]) is man-ager of the Operations Management and

Technology Program, Bill Carson ([email protected]) is manager of the

HRSG Dependability Program, and Rick Roberts ([email protected]) is senior

technical specialist, all at EPRI.

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Recent Innovations from Gas

Turbine and HRSG OEMs Demand for natural gas–fired power plants is perhaps more intense than it’s ever

been. That means a big market to serve, and new opportunities for innovation. The major manufacturers are all working hard to stay ahead of the curve.

Thomas W. Overton, JD

There is no hotter market in power gen-

eration than gas.

According to the Energy Information

Administration (EIA), the U.S. is projected

to add just under 60 GW of new generating

capacity between 2013 and 2017. More than

half of that—and fully three times as much

as the next-closest technology, solar—will be

natural gas–fired.

If you suspect numbers like that have

manufacturers of combined cycle power

plant technology excited, you’d be correct.

The rapidly growing market is not grow-

ing in a vacuum, however. Though the U.S.

may be adding almost 35 GW of gas-fired

capacity by 2017, it’s also adding at least 15

GW of wind and solar. That means the gas

fleet of the future needs to be ready to back

up large amounts of intermittent generation,

and that’s a role manufacturers are moving

briskly to fill. Numerous advances in tech-

nology that will allow combined cycle plants

to start faster, ramp faster, respond more rap-

idly to grid fluctuations, and do it all more

cleanly and efficiently are in development or

have just been introduced to the market.

Reduced EmissionsOne of the challenges of backing up intermit-

tent generation with gas is that this operation-

al mode can significantly increase emissions.

This occurs for several reasons. First, op-

erating gas turbines at low loads produces

higher levels of CO and NOx. Conventional

combined cycle plants typically need to be

brought up to full power in phases to allow

the rest of the plant to heat up safely. Waiting

out these low-load hold points dramatically

increases overall emissions.

Second, rapid changes in turbine output

disrupt fuel and selective catalytic reduc-

tion (SCR) equilibrium. The additional pilot

fuel required during load changes causes in-

creased NOx production, and when turbine

load is changing, maintaining accurate am-

monia injection in the SCR is more challeng-

ing: Too little means increased NOx out the

stack; too much means ammonia slip.

The major turbine manufacturers such

as Siemens and General Electric (GE) have

recently introduced fast-starting plant tech-

nology that is designed to address the first

problem (such as the Siemens Flex-Plant

used at the Lodi Energy Center in Califor-

nia, a 2012 POWER Top Plant). Improve-

ments to heat recovery steam generator

(HRSG) design enable such plants to start

up very quick and avoid low load holds that

increase emissions.

Addressing transient SCR emissions, how-

ever, requires operational changes in addition

to design adjustments. Siemens is introduc-

ing a solution it calls Clean-Ramp, which is

designed to be integrated into the Flex-Plant

solution (Figure 1).

This technology changes how the gas tur-

bine is controlled so that the emissions con-

trol system can accurately predict changes

in turbine exhaust when a load change is re-

quested. The exhaust molar flow rate is cal-

culated based on factors such as combustion

airflow, fuel flow, historical performance,

and so on. This information is used to predict

NOx emissions, and the system then adjusts

the ammonia injection flow rate accordingly.

This allows the plant to stay at baseload emis-

sion levels even when the load is changing.

Siemens claims this allows a plant to ramp

continuously at rates above 30 MW/minute

while keeping NOx emissions under 2 ppm.

GE has developed a similar product in

its GEN II SCR control. This solution pairs

a Rapid Response plant and GE’s OpFlex

Startup Ammonia Control to reduce overall

startup emissions. GEN II measures specific

equipment and emissions parameters and, us-

ing model-based control technology, controls

the ammonia to the SCR to reduce emissions

and ammonia slip.

RetrofitsNew plants aren’t the only ones benefitting

from new technology. With a large number

of older gas-fired plants seeing increased

run time with the fall in gas prices, manu-

facturers are offering upgrades that allow

these projects to capture increases in output

and efficiency.

1. Tight targets. NRG Energy’s El Segundo Energy Center near Los Angeles, a Siemens

Flex-Plant 10, incorporates Clean-Ramp technology to meet the area’s stringent emissions con-

trols. Courtesy: NRG



GE has been offering its Advanced Gas

Path (AGP) upgrade solution for several

years to increase the output, efficiency, and

availability of its workhorse 7F line. It re-

cently expanded this offering to its 9E and

9F turbines. The AGP solution involves

improved blade aerodynamics and better

sealing, as well as advanced materials and

improved cooling technologies to allow

higher operating temperatures. The physi-

cal improvements are paired with OpFlex

model-based control software to deliver ad-

ditional performance improvements.

Alstom recently rolled out its MXL2 up-

grade package for its line of GT13 turbines.

The MXL2 upgrade consists of a completely

new blade design to boost aerodynamic ef-

ficiency in the compressor and turbine,

optimized sealing and tighter clearances, im-

provements to the combustor, and enhanced

cooling design (Figure 2).

Alstom says the upgrade will improve the

power and efficiency of legacy turbines, as

well as stretch maintenance and inspection

intervals. The upgrade offers two modes of

operation: M (for maximum output and ef-

ficiency) and XL (for extended life). Oper-

ating modes can be switched with the press

of a button, allowing generators to increase

output when market demand is high but re-

duce stress on components during periods of

reduced need. (For more on mitigating the

effects of new operating modes, see “Man-

aging the Changing Profile of a Combined

Cycle Plant” in this issue.)

New TurbinesWhether intended for new plants, retrofits, or

repowering, gas turbine techology continues

to evolve. Updated models of several work-

horse designs are debuting this year.

GE introduced its steam-cooled H-class

turbines more than 10 years ago, designs that

have become a staple in the company’s line-

up. This year, GE is rolling out two new air-

cooled H-class turbines, the 9HA and 7HA.

The 9HA.02 offers 592 MW of output at bet-

ter than 61% efficiency in 1 x 1 combined

cycle mode, and can reach full output in un-

der 30 minutes (Figure 3). In simple cycle,

it puts out 470 MW at 41% efficiency. The

9HA has a 14-stage compressor, a 16-cham-

ber dry low-NOx combustor, and a four-stage

air-cooled hot gas path.

The smaller 60-hertz 7HA offers up to 486

MW at greater than 61% efficiency in 1 x 1

combined cycle mode and can reach full out-

put in as little as 10 minutes. Both turbines are

designed to be installed considerably faster

than previous models through the use of mod-

ularized and preassembled components.

Mitsubishi Hitachi Power Systems

(MHPS) is also rolling out an air-cooled

2. Ready to roll. Alstom’s MXL2 turbine is designed to improve power and efficiency on

legacy systems. Courtesy: Alstom

3. Big air. GE’s new 9HA air-cooled turbine

offers up to 592 MW in combined cycle mode.

Courtesy: GE

4. Evolution. Mitsubishi Hitachi Power Systems is upgrading its J-series line of large-frame

gas turbines, like the one shown here, with the air-cooled M501JAC. Courtesy: MHPS



update to its turbine line with the 60-hertz

M501JAC (Figure 4). MHPS’s steam-cooled

J-series turbines, which operated at tempera-

tures of 1,600C, were introduced in 2011 and

have been deployed mostly in Asia, with sev-

eral plants coming online in 2013 and 2014.

The M501JAC adds an optimized air-

cooled combustor from the M501GAC

model and offers output of up to 450 MW in

combined cycle mode at better than 61% ef-

ficiency. The cooling holes in the turbine are

also optimized for reduced gas temperatures.

The M501JAC offers improved operational

flexibility, such as by shortening the starting

time while maintaining the same level of per-

formance as the M501J. First shipments are

expected in 2015.

New Approaches to Simple CycleNot all of the action is in combined cycle.

MHPS is developing an approach to simple

cycle turbine generation that could poten-

tially equal or exceed combined cycle gen-

eration in efficiency. The technology, which

is currently being commercialized for release

later this year, is called AHAT, or advanced

humid air turbine. AHAT takes a simple cy-

cle turbine and uses humidified compressed

air for combustion. The combustion air is

cooled by water atomization, compressed in

the compressor, and then passed through a

humidification tower. The humidified air is

then heated in a heat exchanger using the tur-

bine exhaust before entering the combustor.

The water vapor in the exhaust is then recov-

ered and returned to the humidifier.

The method is similar to steam injection

but adds far more water to the combustion

process. MHPS has been developing the tech-

nology since 2000. A pilot project using an

MHPS H-50 turbine was launched in 2010,

and the company plans to commercialize it

this year. The H-50 turbine with AHAT out-

performed the same turbine in combined cy-

cle mode, achieving 70 MW output at 50.6%

efficiency. MHPS believes efficiencies above

60% are achievable with larger turbines.

MHPS is also developing a related retrofit

product called Smart AHAT, which involves

adding significant steam injection to a com-

bined cycle arrangement, with AHAT’s water

recovery system added to the exhaust.

New HRSG TechnologyHRSG manufacturers have also been work-

ing to meet the demand for more flexible

operations. NEM USA’s DrumPlus design

is engineered to combine the advantages of

drum-type HRSGs with the responsiveness

of once-through design.

In the DrumPlus, the drum is replaced by a

knock-out vessel with external separator bot-

tles. The smaller drum has a relatively thin wall

and is thus subject to lower thermal stresses

with changes in output. The reduced volumes

of both steel and water give the DrumPlus the

dynamic capabilities of once-through steam

generation, as well as the increased lifetime.

These lower stresses eliminate the need for

hold points on the gas turbine during startup,

which allows faster startups, more cold starts,

and more rapid load changes. DrumPlus

HRSGs are able to handle 10-minute start-

ups with no reduction in life. The El Segundo

plant shown in Figure 1 employs a DrumPlus

HRSG design (Figure 5).

Alstom is also offering HRSG designs for

increased cycling. The Alstom OCC approach

employs reduced header thickness–to–tube

thickness ratio, single-row harps, and finned

tubes with no bends. These changes reduce

thermal stress by reducing areas of tempera-

ture difference and adding thermal flexibility

to areas of the HRSG that will experience rap-

id changes in temperature with faster cycling.

Nooter/Eriksen is developing several op-

tions for increased cycling and faster startup.

These include the use of stronger materials,

multi-drum designs, and thinner drum walls.

Looking AheadThis highly competitive market is sure to

continue evolving. The demands from in-

creased renewable generation are certain to

increase pressure on the gas turbine fleet to

become even more flexible and responsive,

both in upgrades to existing plants and in

new plants yet to be constructed. Whatever

your role, these are definitely “interesting

times” for natural gas. ■

—Thomas W. Overton, JD is a POWER associate editor (@thomas_overton, @

POWERmagazine).

5. Fast starts. NEM USA’s DrumPlus HRSG design, shown here at NRG’s El Segundo En-

ergy Center, allows for fast starts and rapid cycling with no reduction in life expectancy. Source:

POWER/Tom Overton


FUELS

HECO Successfully Cofires Biofuel as No. 6 Oil SubstituteThe Hawaiian Electric Co. has conducted a full-scale demonstration test of a

sustainable biofuel at its 90-MW Kahe Unit 3, located on the island of Oahu. HECO is committed to using biofuels as one means to reduce its dependence on imported low-sulfur fuel oil and to meet the requirements of the state’s renewable portfolio standard and Clean Energy Initiative.

Robert C. Carr and David McDermott

All states were not created equal, partic-

ularly when it comes to indigenous re-

serves of fossil fuels. North Dakota is

experiencing a boom in oil production, which

has increased almost 10-fold since 2005, and

natural gas production from the Marcellus

shale deposit—under New York, Pennsylva-

nia, and West Virginia—has increased about

13 times since 2007. In fact, oil and gas pro-

duction has been the fastest growing segment

of U.S. industry since 2007. Hawaii, on the

other hand, meets 90% of its energy needs

using imported oil.

In 2008, a partnership between the state of

Hawaii and the U.S. Department of Energy

(DOE) launched the Hawaii Clean Energy

Initiative (HCEI) with the goal of making

the state energy independent. As you might

expect, the “HCEI Road Map” relies heavily

on solar, wind, sea, and geothermal energy

sources, as well as biofuel and waste-to-ener-

gy projects (see “Expanded Honolulu WTE

Plant Delivers Triple Benefits for Oahu” in

the March 2013 issue or online at powermag

.com). Compared to most of the U.S., Hawaii

is endowed with an abundance of renewable

energy resources.

Hawaiian Electric Co. (HECO), the larg-

est power generator in the state, owns several

low-sulfur fuel oil (LSFO)–fired conventional

steam plants that are candidates for cofiring

liquid biofuels. Liquid biofuels are attractive

because at least a portion of the needed sup-

ply can be grown and refined locally as long

as the right market conditions exist. HECO

views liquid biofuels as potential “bridge fu-

els” until other renewable energy resources

can be brought online in the future.

Designing the Demonstration TestThe Kahe Plant, the largest generating station

in Hawaii, consists of six oil-fired generators

with a total capacity of 650 MW (Figure 1).

HECO designed a test program to fire and

cofire (with LSFO) environmentally sustain-

able crude palm oil. HECO’s 90-MW, tan-

gential-fired Kahe Unit 3 was selected for the

full-scale cofiring project conducted between

Jan. 4 and 28, 2011. Blends using between

0% and 100% biofuel were tested between

38 MW (baseload) and 88 MW (near full

load). The test program was designed to as-

sess the operating limitations when using

biofuel without:

■ Major equipment modifications

■ Violating environmental compliance re-

quirements

■ Derating generating capacity

■ Compromising the ability to operate the

unit on LSFO

Palm oil was chosen because its character-

istics are similar to those of LSFO. However,

the higher heating value of palm oil is ap-

proximately 14% less than for LSFO, which

results in increased fuel flow per burner (from

8 gpm for LSFO to 9.1 gpm for palm oil) in

order to maintain the required heat input into

the boiler and avoid boiler derating.

HECO imported 1.6 million gallons of

palm oil from Malaysia for its demonstration

project, although it plans to procure locally

produced fuels as they become available (see

sidebar). The palm oil was transported by

ship in stainless steel tanks and then stored in

a dedicated oil tank at Kahe.

A parallel fuel supply system was installed

so biofuel could be independently controlled

and fed to the boiler without LSFO cross-con-

tamination. The new palm oil fuel-handling

system included the addition of two new bio-

fuel pumps, a static blender, and a fuel heater

1. Six-unit plant. Kahe Unit 3, the test unit, is a 90-MW gross tangential-fired boiler,

originally manufactured by Combustion Engineering Corp. (now Alstom), that has design steam

conditions of 1,005F and 1,965 psig. The Kahe plant consists of six boilers fired with low-sulfur

fuel oil with a total capacity of 650 MW. Courtesy: Combustion Components Associates


FUELS

bypass valve as well as replacement of the sec-

ondary fuel oil pumps and installation of two

viscometers, various control valves, several

new flow meters, and various other valves. The

fuel supply piping arrangement also allowed

operators to quickly secure the palm oil sup-

ply and return to 100% LSFO should the need

arise. HECO required the new supply sys-

tem to be a permanent installation controlled

by the plant’s distributed control system and

designed and installed to meet National Fire

Protection Association guidelines.

Another important difference between bio-

fuel and LSFO is the biofuel’s much lower vis-

cosity (~133 SSU for palm oil versus ~1,600

SSU for LSFO at 122F). This difference re-

quired the fuel supply system to carefully

control fuel oil temperature as the blend ratio

of LSFO and biofuel changed during the test-

ing to maintain pump performance and good

oil atomization. The pour point of palm oil is

<80F. This means that fuel tanks holding palm

oil may require protective lined berms. LSFO

solidifies at ambient conditions.

The ash, sulfur, and fuel nitrogen contents

and carbon-hydrogen ratio of biofuel are

much lower than for LSFO. Consequently,

emissions of SO2, particulate matter, NOx,

and CO2 were expected to be lower than

when firing LSFO.

CCA Combustion Systems, a division

of Peerless Mfg. Co., was retained to per-

form the baseline LSFO emissions tests,

develop the computational fluid dynamic

(CFD) model used to predict palm oil im-

pacts on boiler performance, and to design

and supply a unique atomizer that would al-

low cofiring from 100% palm oil to 100%

LSFO with no loss in maximum load or

unit turndown capability (minimum load is

25 MW). CCA was also tasked with man-

aging the demonstration test, determining

boiler performance and plant heat rate, and

extrapolating the results of the demonstra-

tion test to all HECO steam plants. HECO

performed NOx emission tests following the

demonstration test.

Unique Atomizer DesignHECO contracted with CCA to design and

fabricate new mechanical, spill-return atom-

izer assemblies for the biofuel demonstration

test. The design criteria for the new fuel at-

omizers were ambitious:

■ Operate at approximately the same supply/

return pressures as the existing atomizers.

■ Have the same spray quality but not ad-

versely impact spray angle at low loads.

■ Must not inhibit full-load operations nor

impact unit turndown.

■ Operate with fuel blends from 100%

LSFO to 100% palm oil.

■ Must accommodate 14% more flow when

burning 100% palm oil due to lower heat

content.

Prior to the biofuel demonstration test the

What Is Palm Oil?

Palm oil is a vegetable oil produced

from the red fruit of oil palms, each

about the size of a strawberry. The oil

is favored by the food industry because

of its relatively low cost and because it

is one of the few with highly saturated

vegetable fats. In fact, 65% of all veg-

etable oil traded internationally is palm

oil. Indonesia and Malaysia produce

about 85% of the world’s palm oil.

Palm oil is a recent entry into the

global biofuel market. Malaysia began

refining the tropical vegetable oil—

primarily used in consumer goods like

snack foods, soaps, and cosmetics—into

a biofuel and blends about 10% palm oil

with diesel fuel for use in automobiles.

Palm oil is semi-solid at room tempera-

ture. Palm oil also has been used as a

fuel for biodiesel-fueled power plants in

various countries, including in Europe

and Asia.

Palm oil is considered by experts to

be carbon neutral because the oil is

merely returning carbon dioxide to the

atmosphere that was obtained earlier

through photosynthesis. However, some

environmental groups oppose the use

of palm oil biofuels because palm oil

plantations require deforestation, which

more than offsets the positive effects

as a carbon sink. The Roundtable on

Sustainable Palm Oil, established in

2004, publishes standards and certifies

the production of sustainable palm oil.

About 15% of the world’s palm oil pro-

duction was certified as sustainable in

2013, as was the oil burned by HECO

during the demonstration project.

Since this demonstration test was

completed, the U.S. Environmental

Protection Agency has determined that

palm oil is a nonsustainable, renewable

fuel because expanding its production

will necessitate clearing virgin forests,

and palm husks generate methane, a

greenhouse gas.

23923

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Surfaceblow’s knowledge comes from hands-on experience operating steam power plants and all manner of machinery.

Later in the series a son, Guy Newcomen Surfaceblow, was introduced. He is a university-trained engineer who also has field experience that gives him credibility when working with hard-boiled characters in the boonies. The character’s name was coined from Marmaduke, a Scottish name, and Surfaceblow, which is the action of removing impurities from a steam boiler.

Here, you will find all of Surfaceblow’s adventures consolidated into a single volume. Many of the stories were inspired by actual events.

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FUELS

oil atomizer used at Kahe Unit 3 was a me-

chanically atomized, spill/return, four-piece

assembly. The spray plate was a “conical”

design with a single orifice that produced a

uniform conical spray. The supply and re-

turn pressures at maximum load were typi-

cally 890 psig and 310 psig, respectively, and

the differential pressure between supply and

return pressures was maintained constant at

approximately 580 psid over the load range.

Turndown for the atomizers was from 90

MW to 38 MW (baseload) with all burners

in service.

To reduce flame impingement problems

experienced historically at low load on the

furnace sidewalls adjacent to the burners, an

alternate “split-flame” atomizer spray plate

was provided. The split flame produced a

flatter, nonconical spray that can be oriented

to reduce flame impingement. Two prototype

split-flame atomizer assemblies were used in

the biofuel demonstration:

■ 100% split-flame atomizer designed for op-

timum performance firing 100% biofuel.

■ 50/50 split-flame atomizer designed for

optimum performance firing a blend of

50% LSFO and 50% biofuel.

In addition to providing the proper flow

rate characteristics and narrower spray angle

at low load, the split-flame atomizers reduced

NOx emissions approximately 20% for LSFO

firing compared to the original atomizers.

Visual inspection when burning palm oil

showed the flames were very uniform and

well attached under all operating condi-

tions. It was not possible to visually dis-

tinguish a 100% LSFO flame from a 50%

biofuel/50% LSFO flame. At 70% biofuel

the flames were more transparent and less

bright. At 100% biofuel, the oil spray skirts

were transparent and a blue-colored flame

“halo” was observed at the flame stabi-

lizer. The flames were less bright than at

70% biofuel but still intense. Moreover, the

split-flame atomizers significantly reduced

but did not completely eliminate sidewall

impingement at low load. As expected,

opacity and visual emissions went from

~2.8% to below 0.5% as the ratio of biofuel

increased from 0% to 100%.

Furnace exit gas temperature (FEGT) for

the two split-flame atomizers was essentially

equal over the load range. For LSFO, the

average FEGT at 100% load for the split-

flames was approximately 140F higher than

for the conical atomizers used prior to the

biofuel tests. This is believed to be a result

of the longer flames (low NOx) produced by

the split-flame design, which reduces near-

burner fuel/air mixing rates. NOx emissions

were approximately 20% lower for the split-

2. Stack gas temperatures rise. Kahe Unit 3 furnace exit gas temperature (FEGT)

produced by different blends of palm oil and LSFO are illustrated. The test was conducted at

nominal O2, and 100% split flame atomizers. Source: Combustion Components Associates

2,700

2,650

2,600

2,550

2,500

2,450

2,400

2,350

2,300

2,250

2,200

2,150

2,100

2,050

2,000

FEG

T (F

)

0 10 20 30 40 50 60 70 80 90 100

Biofuel/LSFO blend ratio (%)

■100% ■50/50

88 MW

60 MW

38 MW

3. Attemperation water flow increase. This chart shows Kahe Unit 3 furnace exit

gas temperature (FEGT) and attemperation (superheater and reheater) water flow versus palm

oil fraction. The test was conducted at 88 MW, nominal O2, and with 100% split-flame atom-

izers. Source: Combustion Components Associates

40

35

30

25

20

15

10

5

0

Att

em

pe

rati

on

(k

lb/h

r)

■RH spray ■SH spray ■FEGT

2,800

2,700

2,600

2,500

2,400

2,300

2,200

2,100

2,000

FEG

T (F

)

0 35 50 70 85 100

Palm oil fraction (%)


FUELS

flame atomizers. Furnace residence times

were sufficient to provide good fuel burnout,

so opacity levels were not increased. FEGT

and gas emissions data measured in the up-

per furnace were reasonably well balanced

across the furnace.

Excellent Test ResultsThe palm oil/LSFO blend ratio was selected

based on total heat input into the boiler. This

approach to in-line fuel blending provided

accurate and repeatable results. The unit load

response when burning up to 100% palm oil

was comparable to burning LSFO alone. The

viscosity of the blended fuels was a constant

135 SSU up to 70% palm oil. At 100% palm

oil, the viscosity decreased to ~85 SSU; how-

ever, the performance of the fuel atomizer

was not affected.

Boiler turndown met the test plan goals.

The unit was able to cycle from full load (90

MW) down to 25 MW when burning 100%

LSFO. The fuel oil controls limit minimum

load to ~25 MW. When burning 100% palm

oil, the minimum demonstrated load was 38

MW using existing burner controls, although

with further combustion control tuning it

is expected that minimum load on palm oil

could be reduced.

Excellent flame stability was observed at

all fuel blends, unit load, and fuel tempera-

tures when using the split-flame atomizer.

Visible emissions (opacity) were also lower

when burning 100% palm oil.

The FEGT, measured below the nose of

the furnace, the superheat and reheat tem-

peratures and sprays, and boiler heat flux

were measured during the demonstration

test (Figures 2 and 3). NOx emissions with

palm oil blends were well within permitted

limits (Table 1). At 88 MW, NOx on LSFO

was 300 parts per million by volume dry

(ppmvd) but dropped to 213 ppmvd when

burning a 70% palm oil mix and to 202 pp-

mvd with 100% palm oil. Figure 4 illus-

trates NOx emissions

The impact on plant efficiency when

cofiring different percentages of palm oil

was calculated from the test data. At full

load, the negative effects on efficiency

when burning 100% palm oil included 11F

higher stack gas temperature and ~17%

higher water content in the flue gas than

when burning LSFO.

However, the excess O2 in the flue gas

was nearly 1% lower than when burning

LSFO. Unburned carbon and CO emissions

changes were negligible for both fuels.

However, 100% palm oil generally required

increased superheater and reheater attem-

peration compared to 100% LSFO, which

will decrease boiler efficiency. The existing

boiler system was adequate to provide the

increased attemperation needed. The “sweet

spot” for optimum boiler operation based on

attemperation rates was a blend of 70% bio-

fuel and 30% LSFO.

The plant’s adjusted heat rate, taking into

account superheater and reheater sprays,

excess oxygen, stack gas temperature, and

water in the flue gas (15% higher) increased

48 Btu/kWh when burning 70% palm oil,

which reflects a slight decrease in boiler ef-

ficiency. However, burning 100% palm oil

increased plant heat rate further, primarily

because of higher attemperation rates. At

biofuel blends of 70% and higher the test

data showed that a reduction in excess O2

of roughly 1 percentage point is possible

with the same or lower opacity compared to

LSFO firing.

The low ash content of the palm oil also

reduced particulate matter and unburned car-

bon emissions. Another positive side effect

was reduced frequency of sootblowing and

cleaner furnace walls.

Program Goals AchievedThe 30-day demonstration project achieved

every goal set for the testing. The in-line

blending system provided maximum opera-

tional flexibility for a biofuel that may have

fuel property variations between deliveries.

More importantly, there were no operational

or emission limitations identified that would

restrict any palm oil/LSFO blend ratio. And,

by extension, the testing did not reveal any

operational or emission limitations that

would preclude using the biofuel at any other

HECO units that now burn LSFO.■

—Robert Carr([email protected]) is project manager at CCA Combustion

Systems. David McDermott is operations and maintenance engineer for Hawaiian

Electric Co.

4. NOx emissions drop. NOx emissions dropped as the percentage of palm oil in-

creased, for three atomizer configurations. The test was conducted at 88 MW, nominal O2, and

with 100% split-flame atomizers. Source: Combustion Components Associates

▲ Conical 2009 ■ 100 SF ■ 50/50 SF

0.50

0.45

0.40

0.35

0.30

0.25

0.20

0.15

0.10

0.05

0.00

NO

x e

mis

sio

ns

(lb

/MM

Btu

)

0 20 40 60 80 100

Palm oil blend (%)

Species Low-sulfur fuel oil 70% Biofuel 100% Biofuel

O2, % dry 3.39 3.07 3.45

NOx, ppmvd (lb/MMBtu) 300 (0.38) 223 (0.28) 212 (0.27)

CO, ppmvd 1.5 0.6 0.6

SO2, ppmvd (lb/MMBtu) 192 (0.342) 64 (0.114) 11 (0.0197)

CO2, lb/lb fuel (lb/MMBtu) 3.217 (169.3) 2.942 (166.9) 2.824 (165.6)

Table 1. Controlled emissions. The average emissions recorded subsequent to the

demonstration test are shown for different fuels and blends using split-flame atomizers. Data

were collected at 88 MW and under nominal O2 conditions. SO2 and CO2 emissions are calcu-

lated from fuel properties. Source: Combustion Components Associates


WORKFORCE

New Technology Is Key to Recruiting New Power WorkforceWith so many career options to choose from, what can the power generation

industry do to draw young people into the fold? Well, if you visit a modern educational institution, you may find that technology and advanced simu-lators can make the profession seem pretty inviting.

Aaron Larson

It is an exciting time to be a part of the

energy industry. New technology is be-

ing developed in almost every sector of

the business. The coal industry is working on

carbon capture and storage solutions, nuclear

professionals are creating new Generation IV

reactors, solar developments include things

like photovoltaic windows for skyscrapers,

and energy storage solutions continue to

improve, with some experts predicting an

explosion of grid-scale deployments as soon

as this year (see “The Year Energy Storage

Hit Its Stride” in the May issue of POWER,

online at powermag.com).

There are a lot of job opportunities in the

industry as well. Because such a large number

of employees are eligible to retire in this de-

cade, the Energy Providers Coalition for Edu-

cation (EPCE) expects that 62% of employees

in the energy industry will need to be replaced

by 2020. For the most part, these jobs must

be filled locally and can’t be outsourced over-

seas, which means personnel with the right

training and education can pretty much punch

their ticket to a well-paying job with excellent

benefits. (For more on education and employ-

ment trends, see the sidebar.)

While the U.S. unemployment rate has

been on a steady decline since October 2009,

it still stood at 6.7% as of March 2014. Peo-

ple are looking for jobs; the problem is that

most of the currently unemployed just aren’t

qualified to fill the utility industry’s needs.

They don’t have the necessary training for

the positions.

Industry-Focused Education“Across the United States, utility compa-

nies—every one of them—has a relationship

with a community college or a university,”

said Matt Sadinsky, CEO of Prequalified

Ready Employees for Power International, a

talent development and recruiting company

for the energy industry. The connection bene-

fits both partners. The utility gains a valuable

future employee resource, because students

of the institution will be trained to meet the

needs of the company—assuming that the

curriculum includes courses appropriate to

utility work. The college or university place-

ment office gets a potential hiring resource

that is looking for its qualified graduates. It is

definitely a win-win situation.

Otter Tail Power Co.’s Big Stone Plant

(BSP) offers an example of one such suc-

cessful partnership. (Disclosure: I am a

former BSP employee.) BSP is a 475-MW

coal-fired power plant in eastern South Da-

kota. In 2006, Plant Manager Jeff Endrizzi

could see the writing on the wall. The plant,

then staffed with 75 personnel, had dealt

with very little employee turnover up to that

point—averaging only one retirement every

18 months—but Endrizzi projected that the

plant would see 51 employees head for the

door between 2012 and 2025 based upon the

ages of the staff at the time.

“I took a chart to Lake Area Technical In-

stitute (LATI) in Watertown, S.D., in 2006 to

explain our expected needs,” Endrizzi said.

“LATI had established programs for elec-

tronics, robotics, welding, and machining,

and we had hired several graduates in the

past. However, our upcoming retirements

were from the mechanical maintenance and

operations departments, and no program at

LATI, or any other technical institute in the

area, trained candidates for these positions.”

Endrizzi met with Deb Shephard, the vice

president of LATI at the time, to discuss possi-

ble program additions at the school. Although

BSP’s needs alone weren’t great enough to

support new programs, Endrizzi encouraged

Shepard to visit with other facilities in the area

to determine if there was a broader regional

need. Those conversations led LATI to develop

its energy technology program and, later, an

energy operations program. BSP employees

continue to serve in an advisory capacity for

each of those programs, as well as for LATI’s

welding and robotics programs.

“Our rural location can add to the chal-

lenges of attracting workers,” said Endrizzi.

To counter that, Otter Tail provides schol-

arships for technical institute students in

pertinent programs and works to maintain

relationships with the students and instruc-

tors in those programs. “Those of us that live

here understand and appreciate the benefits

of small town life, but that isn’t enough at

times,” Endrizzi added.

Online ResourcesWhile utilities work with their local institu-

tions, online learning resources have expand-

ed greatly with the Internet. (See “Going the

Distance: Online Courses for Power Industry

Professionals” in the June 2012 issue or on-

line at powermag.com.) EPCE was formed in

2000 as a nonprofit alliance of industry in-

dividuals, utilities, companies, associations,

unions, and other organizations to work to-

gether to develop the most relevant and time-

ly energy education programs.

Offered entirely online, EPCE’s educational

programs have been developed by the industry,

for the industry. EPCE does not offer courses

itself; instead, it partners with colleges and uni-

versities that are among the best in the nation

at providing education online. Classes are fully

accredited and completely transferrable.

EPCE’s educational partners include

Clemson University, Worcester Polytechnic

Institute, Bismarck State College (BSC),

Excelsior College, and VHS Collaborative.

According to EPCE, studies have shown

that students in online courses perform bet-

ter than those learning the same material

through face-to-face instruction, so this new

educational model seems to be working.

A Long Track RecordOf course, online classes are not for everyone;

some prefer the traditional approach. With its

main campus in Bismarck, N.D., BSC has

been training personnel to enter the energy

industry for quite some time. In 1970, the

school identified an industry need for elec-

trical line workers, and it began a program

to fill that niche. The program’s success led

to the development of the first power plant


WORKFORCE

More Education and Employment Trends

Power generators depend upon personnel with a wide range of

backgrounds, from those with certification in specific trades to

engineers with degrees in everything from power, mechanical,

chemical, and nuclear engineering to computer engineering. That

diverse skill and educational background mix makes it difficult to

draw a complete picture of trends that may affect specific sectors

of the industry, especially as many surveys lump power plant em-

ployment into a generic “utilities” or “energy” category. However,

a few recent studies of engineering education and energy industry

employment trends offer some valuable observations.

More EngineersA February 2014 report by the National Science Board notes that

the number of bachelor’s degrees in engineering has increased over

the past two decades, consistently accounting for about one-sixth

of all bachelor’s degrees. It used to be said that potential engi-

neering students and power industry candidates were being drawn

to computer science fields instead, but although the number of

computer science degrees rose through the dotcom glory days,

they have since declined and have leveled off more recently.

Nuclear Engineer TrainingNuclear power plants have the most rigorous employment require-

ments and, hence, merit a separate look. A report by the Oak Ridge

Institute for Science and Education (ORISE), “Nuclear Engineering

Enrollments and Degrees Survey, 2013 Data,” surveyed 32 U.S.

universities with nuclear engineering programs and found that the

number of college students graduating with majors in nuclear en-

gineering increased between September 2012 and August 2013.

According to the report, 655 students received bachelor’s degrees

with majors in nuclear engineering in 2013. That’s a 7% increase

over 2012, 25% higher than 2011, and the highest number report-

ed in 30 years—but still 20% below the peak years in the 1970s.

The 362 nuclear engineering master’s degrees awarded in 2013

(the highest number since 1980) represented an increase of 9%

over 2012 and 31% over 2011. Doctorates granted in 2013 (147

total) were 23.5% higher than in 2012, 30% higher than in 2011,

and the highest since 1972.

However, the ORISE report showed that enrollment in nuclear

engineering programs declined from the previous year. In 2013,

nuclear engineering enrollments for undergraduate and graduate

students were down 9% and 5%, respectively. While the number of

bachelor’s degrees awarded is likely to remain in the 630 to 650

range in 2014, the number of students graduating with bachelor’s

degrees in nuclear engineering in 2015 will likely decrease to less

than 600, the report’s authors concluded.

The ORISE report found that most nuclear engineering students

didn’t plan to stop with a bachelor’s degree, but for those seek-

ing employment after that degree, nuclear utilities were the most

likely employer.

Salary Level and GrowthThough engineering jobs in the power sector pay quite well when

compared with average U.S. salaries, especially when benefits

packages are considered, the field does not show the fastest salary

growth, according to a 2013 Economic Research Institute report,

“Tracking Salary Trends by Education Level and Degree.”

Those with a BS in power systems engineering, for example, ex-

perienced some of the lowest annual salary growth, an average of

1.97%, among those who held degrees in STEM (science, technol-

ogy, engineering, and mathematics) fields between 1998 and 2012,

while those with a BS in mechanical engineering saw an average

2.08% salary growth. Nevertheless, average 2012 salaries for those

two groups ($84,138 and $63,867 respectively) were higher than

for those with a BS in fields such as natural resources conservation,

environmental sciences, agricultural sciences, and chemistry.

Technology Skills GapA new Manpower survey of the energy industry released May 5,

“Strategies to Fuel the Energy Workforce,” found that the jobs

employers globally have trouble filling, across all sectors, are the

same as those the energy industry is struggling to fill now and

into the future: skilled trade workers, technicians, engineers, and

IT staff. The report points to three factors overall that are contrib-

uting to a shortage of skilled workers at both entry and senior lev-

els: aging workforce, rapid technology and innovation advances,

and “a breakdown in education at every level.”

The technology gap problem is especially wide for potential job-

changers, Manpower found: “The need for technology skills for

front-line leadership jobs also make career transfers from the con-

tracting, coal or construction industries difficult. Front-line lead-

ers now use a laptop to report back with spreadsheet programs,

and linemen often must troubleshoot electronic devices attached

to equipment up on the lines. However, many career changers have

limited computer literacy skills.”

New, more tech-savvy hires may face the opposite challenge: In

some subsectors, such as utilities, they may lack familiarity with

the “older analog infrastructure that remains in use today.”

Among the Manpower report’s recommendations for addressing

the talent shortage are giving vocational training value; marketing

to the future pipeline—including underrepresented populations

such as military veterans (see the related article in this issue),

women, and minorities; developing an intellectually agile work-

force; and getting back to STEM basics.

How Many Jobs Need to Be Filled?In the U.S., predictions of weak electricity demand growth may be

related to projections by the Department of Labor that utilities (as

a general category, not just power) will see negative job growth

between 2012 and 2022. In fact, it predicts a drop from 554,200

in 2012 to 497,800 in 2022.

However, a Manpower chart shows an average of about 50% of

U.S. and Canadian energy sector employees eligible for retirement

in the next 10 years, so that still leaves a substantial number of

positions to fill. In the utilities subsector, the Manpower study

projects 100,000 new jobs will be created by 2020, “when a sub-

stantial number of utility employees reach retirement age.” It adds

that solar and wind sectors will see slower but steady growth by

2020, with wind power jobs projected to double by 2030.—Gail Reitenbach, PhD, Editor


WORKFORCE

technology program in the country, which the

school began offering in 1976. The program

expanded to include process plant technol-

ogy in 1981.

The school has continued to expand its of-

ferings, including providing online courses

beginning in 2000, nuclear training in 2004,

and maintenance offerings in 2007, which

was also the year that the Department of En-

ergy (DOE) designated BSC as the “National

Power Plant Operations Technology and Edu-

cation Center.” In 2008, the school began of-

fering a bachelor’s degree program in energy

management, and the $21 million National

Energy Center of Excellence (NECE)—a

106,200-square-foot, state-of-the-art build-

ing that currently houses the college’s energy

programs and some administrative offices—

went into service (Figure 1).

BSC boasts that it has trained thousands

of energy employees in all U.S. states. In

fact, there was at least one student from ev-

ery state and Canada among the 1,359 credit-

seeking energy program students in 2013. A

handful of international learners were part of

the enrollment as well.

Modern FacilitiesMore than two-thirds of the money for BSC’s

NECE came by way of donations from busi-

nesses and individuals, combined with fed-

eral, state, and local funding, the largest

single portion of which was $5 million from

the DOE. In addition to funding the facility,

the money has been used on some high-tech

training equipment.

The labs at BSC include a control room

simulator (Figure 2), which was paid for by

Great River Energy (GRE) in exchange for

use of the simulator to train and qualify its

operators. The distributed control system for

the simulator utilizes software identical to that

used at GRE’s Coal Creek Station, a coal-fired

power plant with twin 600-MW units. In addi-

tion to two on-campus simulators, BSC also

has two online simulators that allow student

access from anywhere in the country.

Other state-of-the-art labs include a truck-

driving simulator that is used to prepare stu-

dents to obtain their commercial driver’s

license, which is required for line workers.

The simulator provides a realistic semi-truck

driving experience, requiring students to shift

gears, maneuver around obstacles, and use mir-

rors in the same way they would when driving

a real truck. The seat and steering wheel are

mounted on a moving, vibrating platform that

enhances the experience, while large screens

display the environment being navigated. The

school also owns a semi-truck and trailer for

actual on-road training.

An operating thermal power plant with

a natural gas–fired, water-tube boiler is an-

other hands-on training tool for students at

the college. Complete with a distributed

control system, the boiler produces steam

to operate a single-stage turbine and small

generator. The plant utilizes all of the con-

ventional equipment—deaerator, condenser,

feed pumps, and the like—typically included

in a utility-scale plant.

Physical pumps, motors, and valves with

cutaway sections for easy viewing of inter-

nal components are another useful learning

tool. In addition to these, BSC has modern

training stations for process control systems,

mechanical drive systems, electrical con-

trol modules, and hydraulic instrumentation

components (Figure 3).

They Gotta Wear ShadesThe future’s so bright for most of the power

program students that they should prob-

ably be wearing welding helmets to cut the

glare. Graduates of accredited educational

programs catering to the power industry

are finding high demand for their services.

BSC reports that its placement rate has been

in the high 90s for more than a decade and

that seems unlikely to change anytime soon,

based on the EPCE statistics.

The biggest challenge is finding candi-

dates who are interested in working in a plant

or industrial setting. Although the money is

generally agreed to be good, many young

people feel the jobs are dirty and monoto-

nous. While impressive schools with shiny

new toys may coax students in the doors,

utilities will need to utilize new techniques to

keep new employees engaged and interested.

For example, as a December 2013 report

(“Power and Utilities Changing Workforce”)

by PricewaterhouseCoopers noted: “Even

state-of-the-art utilities, however, still need to

be able to speak the language of today’s tech-

nology driven generation. And while some

organizations have been experimenting with

new digital technologies and e-learning ap-

proaches to attract and retain younger people,

most still lack appropriate training skills and

procedures. Training manuals in the form

of three-inch ring binders and a classroom-

based, instructor-led approach simply may not

be attractive to a digital generation that wants

to learn largely online and at its own pace.” ■

—Aaron Larson is a POWER associate editor (@AaronL_Power,

@POWERmagazine).

1. The National Energy Center of Excellence. This four-story building—built on a

hillside and shown here from the top of the hill—includes labs, classrooms, and administrative

offices for Bismarck State College’s energy programs. Source: POWER/Aaron Larson

2. Control room simulator. The simu-

lator is an excellent tool for training students

on plant operation. It allows instructors to en-

ter system anomalies, which require students

to identify and respond to alarms and unusual

plant conditions. Source: POWER/Aaron Larson

3. Lab training modules provide hands-on experiences. The electrical

control and hydraulic instrumentation modules

shown here are just a sample of the mockups

used at BSC. Source: POWER/Aaron Larson

tent requirements in IPP projects is a fac-

tor that will spur on the local manufacturing

industry. According to Dr. MKhulu Mathe,

manager of energy materials at CSIR: “It is

the government’s position that 50% of the

materials should be made locally. Another

reason for that is that increased competi-

tion forces a normalization of prices and

compelled developers to have a realistic

mark up.”

“Increased local content requirements will

be pushing IPPs to be creative on the for-

mulation of their tariffs when they can get

cheaper products and services from China.

Programs must be sustainable for a reason-

ably long period of time; otherwise there is

no real incentive for manufacturers to set

up manufacturing facilities in South Africa”,

said Kieran Whyte, director, national prac-

tice head for projects and infrastructure

from DLA Cliffe Dekker Hofmeyr, a leading

South African law irm.

Many entrants, especially in the solar mar-

ket, continue to import their products from

China, but are mindful of the local content

requirements and local job creation.

“As Eco Green Energy, we aim to work

with the local community, as we do not

want to threaten the local industry with

imports from China. We see it as an oppor-

tunity to develop, not only the energy that

is needed here in South Africa, but also to

create more jobs,” said Dalibor Nikolovski,

general manager of solar solutions provid-

er, Eco Green Energy.

Econet is a well-known mobile service

provider in Africa that has recently branched

out into the providing solar solutions

to remote clients. As a newcomer on the

scene, Econet is already building local ties

and manufacturing capabilities “All the

design concepts are done in South Africa

and all the installation and supervision

is local, so our products are South Afri-

can products,” said Luc Tanoh, CEO of

Econet Solar.

Coal the Present and

Gas the FutureCoal generation will continue to

predominate the energy sector until 2020

through new builds as well as the up-

grade of Eskom’s existing leet. As Ste-

phen Leatherbarrow of Robor noted: “One

needs to bear in mind that South Africa has

5Global Business Reports // POWER SOUTH AFRICAJune 2014 5

an abundance of coal resources which will

maintain and create jobs for many years

to come. If well managed, coal is still

one of the cheapest forms of energy in

South Africa.”

Yet, while coal is an important resource

for base load, the expectations are that,

post 2020, the focus will shift signiicantly.

“Endress + Hauser in South Africa under-

stands the challenges of the sustainability

of thermal projects going forward and it

remains to be seen what Eskom’s plans

are beyond Medupi and Kusile,” said Rob

MacKenzie. “There are many new opportu-

nities that are presenting themselves such

as gas which is a better alternative to coal”.

Stephen Moore, CEO of MHPSA, a merger

between Mitsubishi Heavy Industries and

Hitachi, said: “MHPSA are focused on ther-

mal power so we are keen on pushing that

www.gbreports.com

Global Business ReportsPOWER SOUTH AFRICA



Lessons in Resiliency and RiskKeynote presentations at ELECTRIC POWER 2014 focused on new threats to

power generators that range from climate change to a business environment that includes increasing numbers of large customer-generators. The take-away: Traditional utilities can survive the new challenges, but only if they are prepared and flexible.

Gail Reitenbach, PhD

Climate change is changing the odds of

extreme weather events, Entergy’s Rod

West told the audience at the opening

keynote session of ELECTRIC POWER

2014. West, who serves as Entergy’s execu-

tive vice president and chief administrative

officer, led the team responsible for the $250

million reconstruction of New Orleans’ elec-

trical infrastructure after Hurricane Katrina.

Though this year’s conference and exhibi-

tion began on Apr. 1 in New Orleans, West’s

comments were no April Fool’s joke. En-

tergy, which operates as a traditional utility

in the South and a merchant generator in the

North, owns and operates about 30 GW of

capacity, including 10 GW of nuclear power.

Though one might think its Gulf Coast as-

sets’ vulnerability to hurricanes would be the

most significant weather-related threat, West

noted that Entergy assets in all areas have

been hit by extreme weather.

Prepare, Harden, and Engage“We understand storms,” West (Figure 1) as-

serted as he delivered his keynote on risk and

resiliency for power companies.

Not only is climate change increasing the

odds of extreme weather events, but the loss-

es from those events are also increasing, he

explained. West acknowledged that, “often to

the chagrin of our colleagues,” Entergy has

been at the forefront of addressing the impli-

cations of climate change. It also has moved

away from an all-or-nothing discussion of

climate change. Instead, “it’s a conversation

about managing risk.”

To that end, in 2004 the company en-

gaged with a team of consultants and other

Gulf Coast entities to develop “a fact-based

assessment of risk” to the U.S. Gulf Coast.

One key finding: The Gulf Coast faces ex-

pected cumulative losses over $350 billion

by 2030 as a result of environmental risks.

Even events not directly “caused” by climate

change are exacerbated by it.

If you are affected by climate change

impacts, he said, it’s just loss, whether you

“believe” in climate change or not. The con-

versation Entergy has is about resilience. But

it’s not just about hardening infrastructure.

Though hurricanes are some of the most dra-

matic and destructive weather events, the largest

cumulative destruction is caused by thunder-

storms, high wind, tornados, and winter storms,

which means all regions are vulnerable.

Resilience isn’t just a concern for the Gulf

Coast, as the East Coast learned during Hur-

ricane Sandy. West suggested that after seeing

the devastation that Sandy wrought, it became

more obvious that planning, preventing, and

restoring service after extreme weather events

is a national priority that requires three ac-

tions: prepare, harden, and engage.

West spent some time detailing the im-

portance of engaging utility customers in

these steps. Because restoration of electricity

service can take weeks after a major event,

customers—industrial, commercial, and res-

idential—may need to be prepared for long

outages or have backup plans.

The costs of inaction surpass those of invest-

ment in preparation and hardening, West argued.

One of the approaches Entergy and the State of

Louisiana have taken is familiar to the nuclear

industry: defense in depth. The elements of that

strategy include, but are not limited to, building

and maintenance of levees and coastal wetlands.

Coastal wetlands are an important compo-

nent of that defense-in-depth strategy because,

as West underscored, it’s not just a “tree-hug-

ger” issue. The loss of coastal wetlands affects

energy industries all along the Gulf and has

additional economic impact. Especially given

the importance of the energy and related in-

dustries to the Gulf Coast region, the State of

Louisiana has developed a plan to reverse the

loss of coastal wetlands known as the “Gulf

Coast Adaptation Study.”

Entergy’s approach appears to be paying off.

West noted that as a result of efforts the compa-

ny has made, outage restoration after Hurricane

Isaac was faster than for the previous several

storms: Ike, Gustav, Rita, and Katrina.

When Large Customers Become Large GeneratorsBrian Janous (Figure 2), director of energy

strategy for Microsoft, made the second key-

note presentation. As is the case with many

other large technology companies, including

Google and Apple, Microsoft is committed to

providing much of its own power, including

carbon-free electricity.

To help explain why Microsoft has gone so

deeply into the business of developing gen-

eration, Janous said that the company looks 1. Rod West. Entergy’s executive vice

president and chief administrative officer de-

livered the first of two keynote addresses

at ELECTRIC POWER 2014 in New Orleans.

Courtesy: POWER

2. Brian Janous. Microsoft’s director of

energy strategy gave attendees insight into

the energy strategy of large nonutility gen-

erators that have not traditionally been self-

generators. Courtesy: POWER



at data as a form of energy. Energy is used

to produce electricity, which is distributed as

data. In one slide, Janous demonstrated all

the points at which energy is lost, from power

plant to transmission to end use at a data cen-

ter. By the time you reach the server, 99% of

the energy is lost, according to Microsoft’s

analysis. By bringing energy production to

its data centers, Janous explained, Microsoft

can reduce overall losses and optimize the

energy supply chain.

In fact, Microsoft is doing more than set-

ting up generation “outside the fence” of its

data centers. In collaboration with the Univer-

sity of California, Irvine, it’s developing an in-

rack fuel cell process that puts generation and

end-use equipment—servers—side by side on

racks. In February this year, the company ran

a successful demonstration that Microsoft said

boosted the electrical efficiency of its fuel cell

system from 39.8% to 53.3% “by cutting out

much of the electrical conditioning systems.”

It also cuts out transmission losses.

The company announcement of the test

claims that, “If this approach were scaled up

across the United States, we anticipate that

fuel cell stacks—in which the fuel cell is in-

tegrated directly into the server rack—could

double energy efficiency while cutting out

numerous points of failure that occur in tra-

ditional electrical transmission.”

Beyond onsite generation, the company is

also investing in renewable generation sited

elsewhere—its first such agreement is a 20-

year power purchase deal from a 110-MW

wind farm to be developed near Dallas—and

feeding it to the grid because the company

has a policy of being carbon neutral. In fact, it

even has a corporate-wide price on carbon that

easily justifies these capital expenditures.

Distributed and Centralized Are Not the Only OptionsThe argument made by many that traditional

centralized power generation will be supplant-

ed by distributed generation (DG)—thereby

constituting a cataclysmic “disruption” of the

power industry—wasn’t one made by Janous,

to the likely surprise of many listening. In fact,

he pointed to “Silicon Valley” as the source of

much of the hype about DG overthrowing tra-

ditional utilities (Microsoft is headquartered

more than 800 miles north of Silicon Valley, in

Redmond, Wash.).

Janous argued that the future will be neither

solely centralized nor distributed. “The future

is integrated,” he predicted. And data (an un-

surprising claim from the likes of a tech com-

pany) will be the enabling factor to integrate

distributed and centralized generation. In that

new, integrated world, Janous sees utilities de-

livering different types of services, including

networked refrigerators and energy storage.

What if utilities aren’t interested in new

business models? Whether they encourage

DG or not, Janous said, “it will happen.” That

said, Silicon Valley tech companies underes-

timate the barriers to disrupting the tradition-

al utility infrastructure, he said.

It appears that even behemoths like Micro-

soft see value in the interconnected grid. As an

example of how utilities might play in the new

world, he suggested that diesel generators cur-

rently used as backup for data centers could

represent an opportunity for utilities to be in-

volved in site-based generation—presumably

if they could dispatch it or possibly even own

and lease those distributed power plants.

Though most companies don’t look at en-

ergy beyond the next few years, Janous said

Microsoft is making a long-term commitment

to it. Of course, the company founded by the

now-richest man in the world has more op-

portunities to do this than the average enter-

prise, but that doesn’t make it an anomaly. ■

—Gail Reitenbach, PhD is POWER’s editor (@GailReit, @POWERmagazine).




Veterans Bring Needed Skills to the Utility IndustryAs reports abound about the aging workforce in U.S. power plants, ex-military per-

sonnel offer battle-tested dependability and proven leadership to an industry in need of their skills.

Aaron Larson

We all know someone who either

is, or was, in the military. In fact,

many utility industry professionals

were once in the military themselves. Person-

nel learn many valuable lessons in the armed

forces. Teamwork, discipline, reliability,

dedication, initiative, and leadership are all

important traits instilled in military members.

The ability to give and follow directions, get

along with others, work under pressure, and

conform to rules are drilled into service men

and women in all branches from the day they

sign on the dotted line.

In case you hadn’t noticed, many, if not

all, of those traits are important in the power

sector too, so when you need someone who

can be counted on to do a job in accordance

with detailed requirements, consider a cur-

rent or ex-military member. Yes, I said “cur-

rent”; many active reserve and National

Guard members are working in power plants

across the country and are doing a great job.

Although it requires a little extra effort to

schedule around weekend duty and summer

drills, many companies are successfully han-

dling that task.

During the ELECTRIC POWER Confer-

ence & Exhibition (EP) held in New Orleans

in early April, the first-ever Faraday Awards

were presented in the EP Theater. The awards

were part of the Veterans in Power (VIP) ini-

tiative and recognized employers, programs,

and partnerships that have successfully fo-

cused on elevating the careers of American

veterans in the energy industry.

The awards are named after Michael

Faraday, who published work on electro-

magnetic rotation—the principle behind the

electric motor—and discovered electromag-

netic induction—the principle behind the

electric transformer and generator—in the

early 19th century.

A Ready ResourceThe U.S. Bureau of Labor Statistics reported

in March that the unemployment rate for vet-

erans who served on active duty in the U.S.

Armed Forces at any time since September

2001—a group referred to as Gulf War-era

II veterans—was 9.0% in 2013. With a total

of 2.8 million Gulf War-era II veterans, that

leaves a pool of 252,000 well-qualified per-

sonnel waiting in the wings for an opportu-

nity to utilize their technical skills. Utilities

stand to benefit, if they can find a way to tap

this resource.

The Faraday Awards recognize outstand-

ing efforts in the electric power sector to re-

cruit, train, retain, and mentor veterans who

are entering or reentering civilian careers af-

ter serving their country in the armed forces.

Awards were presented in three categories.

American Electric Power (AEP) and In-

cremental Systems Corp. were recognized

for their investor-owned utility and small

business partnership—Power4Vets. Pow-

er4Vets is a workforce development training

program that prepares military veterans to

become North American Electric Reliabil-

ity Corp. (NERC)–certified power system

operators through simulation training and

focused studies. It also provides coaching

and mentoring for job interviews, resume

preparation, and job placement assistance.

Since its inception, 61 veterans have become

NERC certified, 57 have transitioned from

military to power industry careers, 36 have

transferred from other jobs to power industry

careers, and 68 have trained for, or upgraded

to, better jobs in the industry.

Scott Smith, senior vice president of trans-

mission strategy and business operation for

AEP, noted that AEP employees more than

20,000 people. When it began its veterans

hiring initiative, roughly 9% of the work-

force was made up of ex-military personnel.

Since that time, the percentage of veterans

has risen to 12%.

The second award was given to Siemens

Energy and Central Piedmont Community

College for their Apprenticeship Charlotte

program, which aims to build a pipeline of

qualified employees by combining class-

room and workplace learning. One unique

aspect of the program is that Siemens Ener-

gy pays apprentices while they are attending

classes and also reimburses them for tuition

and books.

The third award was presented to Do-

minion Resources and the Center for En-

ergy Workforce Development for their

Troops to Energy Jobs program. The team

was recognized as an outstanding example

of an investor-owned utility partnership

with a nonprofit organization. Troops to

Energy Jobs began as a pilot program in

September 2011 and launched nationally in

June 2013. Dominion has hired more than

270 military veterans, which equates to

about 25% of Dominion’s new hires since

the program began.

“These three have really stood out, not just

by success of the number of veterans hired,

but their view of the program and the way that

they integrate for long-term retention,” said

Matt Sadinsky, CEO of Prequalified Ready

Employees for Power International, who col-

laborated with EP to present the awards.

Making the LinkConnecting with veterans can be challeng-

ing, especially in areas of the country far

from military bases. “We had a veteran’s re-

1. American Electric Power (AEP) and Incremental Systems Corp. (IncSys) Faraday Award presenta-tion. Left to right: David Wagman, ELEC-

TRIC POWER; Matt Sadinsky, Prequalified

Ready Employees for Power International;

Scott Smith, AEP; Mike Anderson, AEP; Robin

Podmore, IncSys; and David Miranda, Pow-

er4Vets. Source: POWER/Aaron Larson

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source center that really wasn’t staffed with

veterans. It was staffed with normal college

advisors, and that didn’t work. Veterans like

to talk to veterans. That’s where we learned

our lesson,” said Bill Dillon, associate dean

for business and industry learning at Central

Piedmont Community College.

“The way that you can collaborate to get

the word out is by word of mouth,” Pow-

er4Vets Program Manager David Miranda

said. “There [are] enough military veterans

out there—in these pools that we have with

great candidates—that are going to be great

fits for any utility across the entire country.”

Roger Collins, technical training special-

ist for Siemens Energy, noted that military

personnel are used to working with the lat-

est in technology. “They come to us with a

skillset that can’t be picked up in just the

general population. They’re motivated to

learn, they’re accustomed to being trained,

they have a very good sense of duty—a good

sense of purpose—that makes it easy for

them,” Collins said. “They may not have the

exact skills that we’re looking for, but they’re

able to be trained.”

“The average age of a system operator in

America is 56, and 50% of them will retire in

the next three to five years,” Sadinsky said.

With that kind of employee turnover looming

on the horizon, utilities need to look for em-

ployment candidates who can hit the ground

running. Military veterans are one resource

that should not be overlooked.■

—Aaron Larson is a POWER associate editor (@AaronL_Power,

@POWERmagazine).

2. Siemens Energy and Central Piedmont Community College (CPCC) winners. Left to right: David Wagman, ELECTRIC POWER; Matt Sadinsky, Prequalified Ready

Employees for Power International; Dawn Braswell, Siemens Energy; Bill Dillon, CPCC; and

Roger Collins, Siemens Energy. Source: POWER/Aaron Larson

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The Word for Gas Is “Flexibility”As an ever-changing power mix and growing renewable contributions chal-

lenge grid stability, flexible gas generation looks to be more important than ever, panelists at ELECTRIC POWER 2014 reported.

Thomas W. Overton, JD

With the gas-fired power sector in

continual flux, blessed by plentiful

gas supplies but faced with uncer-

tain fuel costs and competition from intermit-

tent renewable generation, plant owners must

make flexibility and responsiveness a priori-

ty. That was the message from the natural gas

track at the ELECTRIC POWER Conference

held in New Orleans, April 1–4.

Flexible OperationsRob James, product manager for Neuco,

discussed a project optimizing heat rate and

ramp rate at Dynegy’s Independence com-

bined cycle plant in Osewgo, N.Y. The 1,042-

MW dual 2 x 1 facility began bidding into

the New York Independent System Operator

frequency regulation market about four years

ago. Dynegy later retained Neuco to help

maximize the plant’s capability for high–

ramp rate ancillary services. This meant find-

ing ways to optimize the dynamics of the

combined cycle process and enhancing day-

ahead capability prediction.

By using sophisticated modeling software

to predict demand trends, the plant is able

to deploy its duct burners ahead of time to

increase steam turbine output and preserve

high–ramp rate gas turbine capacity. The

model then turns the duct burners off as soon

as they are no longer needed in order to main-

tain plant efficiency. Timing the duct burners

is important when selling into the regulation

market because the gas turbines can reach

maximum output below total plant output

well before the heat recovery steam genera-

tor (HRSG) heats up, which can compromise

the plant’s committed ramp rate. If the duct

burners are timed properly, the plant can sell

all its power into the regulation market while

still bidding at gas turbine ramp rate.

Nikhil Kumar, director of energy and util-

ity analytics, Intertek Asset Integrity Man-

agement, reviewed a study of combined

cycle and simple cycle gas turbine operating

performance from 2002 through 2012. The

study was intended to characterize trends

and effects of cycling operation. Not surpris-

ingly, the data showed substantial increases in

average capacity factors at these plants, but

also increased number of starts and ramping

episodes. This places greater stress on a plant,

meaning steps must be taken to increase equip-

ment resiliency. Among the countermeasures

that can help deal with increased cycling are

installing additional thermocouples in the

HRSG to better monitor temperature changes

and better monitoring and control of HRSG

chemistry. More effective steps can be taken

if planning begins at the design stage.

Flexible DesignIncreased penetration from intermittent

renewable generation is challenging com-

bined cycle plant profitability as increased

cycling (see related article, “Managing the

Changing Profile of a Combined Cycle

Plant” in this issue) sends maintenance

costs up while lucrative baseload roles are

taken by wind and solar. However, renew-

able generation rarely follows forecasts

precisely, leaving plenty of gaps needing

to be filled. Properly designed plants can

ramp quickly and stay profitable by pursu-

ing opportunities in ancillary markets, as

several speakers explained.

Omar Rubio of Siemens Energy described

two major ramping episodes in Germany and

California last year, when multiple gigawatts

of renewable generation came off the grid

over a short period of time, and grid operators

had to ramp up major amounts of convention-

al generation to replace it. Such episodes will

only become more common, and that means

1. Gas projects roll on. Dennis Finn of Wärtsilä gives a report on a gas engine plant in Alaska during the ELECRIC POWER natural gas

track as panelists Udo Zirn, Chris Marks, and Joe Ferrari look on. Source: POWER/Tom Overton



a big opportunity for fast-starting combined

cycle plants that can meet the need.

Gordon Smith, chief consulting engineer

with GE Power & Water, discussed two of

the main challenges of fast starts: stresses

on the HRSG and managing NOx emissions.

Relatively minor HRSG design changes

can minimize thermal stresses and increase

steam turbine responsiveness. Meanwhile,

predictive modeling to better manage NH3

additions to the selective catalytic reduction

system can help keep emissions under con-

trol even when turbine output is erratic.

Flexible TechnologyFlexibility takes other forms than combined cy-

cle gas turbines, of course, as several presenters

reviewing the performance of reciprocating en-

gines alongside renewable generation reported.

Chris Marks, mechanical engineer with

Burns & McDonnell, described the devel-

opment and construction of Mid-Kansas

Electric Co.’s 110-MW Rubart Station gas

engine plant in western Kansas, which

is coming online this year. The area is a

major producer of wind energy, and Mid-

Kansas’s cooperative profile includes 179

MW of wind capacity out of a total of 733

MW. That’s created a need for balancing

from highly flexible but efficient genera-

tion. Mid-Kansas ultimately chose a 10-unit

plant powered by Caterpillar G20CM34 gas

engines. The plant can ramp from 0% to

100% load in only 8 minutes, with flat ef-

ficiency across a wide operating range.

Dennis Finn, business development man-

ager for Wärtsilä North America, reviewed

a similar gas engine project in Alaska, the

Matanuska Electric Association’s (MEA’s)

170-MW Eklutna Generating Station in

Palmer, northeast of Anchorage (Figure 1).

In Alaska, the highest loads are in the winter,

while summer demand can be very light. The

area is also seismically active. MEA chose a

Wärtsilä-supplied gas engine plant (powered

by 10 18V50DF dual-fuel engines) because

of their high reliability, rapid dispatch, and

low maintenance requirements. The plant

will be able to continue operating down to

–40F and remain online (by switching to fuel

oil) even in the event of an earthquake. Con-

struction began in early 2013 and the plant is

expected to come online by January 2015.

Advances in turbine technology are also in-

creasing generation options. Udo Zirn, man-

ager, turbine systems for Mitsubishi Hitachi

Power Systems Americas (MHPS), presented

a new technology that MHPS is preparing to

roll out. Called AHAT, or advanced humid

air turbine, it involves feeding humidified

compressed air into a simple cycle turbine to

increase efficiency. Combustion air is cooled

by wet evaporative cooling and is then passed

through a humidification tower and heated in

a heat exchanger using turbine exhaust be-

fore entering the combustor. The water vapor

in the exhaust is then recovered and returned

to the humidifier.

MHPS has been developing the technol-

ogy since 2000. A pilot project using an H-50

turbine was launched in 2010, and MHPS

plans to commercialize it this year. The H-50

turbine with AHAT outperformed the same

turbine in combined cycle mode, achieving

70 MW output at 50.6% efficiency. Zirn said

MHPS believes efficiencies above 60% are

achievable with larger turbines.

MHPS is also developing a related retrofit

product called Smart AHAT, which involves

adding significant steam injection to a combined

cycle arrangement, with AHAT’s water recov-

ery system added to the exhaust. (For more on

AHAT, see “Recent Innovations from Gas Tur-

bine and HRSG OEMs” in this issue.) ■

—Thomas W. Overton, JD is a POWER associate editor (@thomas_overton,

@POWERmagazine).




Fuel Flexibility Is the Gift That Keeps GivingAgainst the backdrop of low-priced natural gas and increasing renewable capacity,

finding ways to stay competitive as operating costs continue to rise at coal-fired power plants is getting increasingly difficult. Fuel flexibility can help keep coal plants in the mix.

Aaron Larson

All power plants must continually strive

to control operating expenses, but it is

particularly important for coal-fired

facilities to cut costs these days to stay com-

petitive while meeting ever-more-stringent

environmental requirements. By some es-

timates, the addition of a modern air qual-

ity control system (AQCS)—including ac-

tivated carbon injection, selective catalytic

reduction, flue gas desulfurization (FGD),

and baghouse components—can result in a

50% increase in operating expenses due to

the cost of consumables, such as activated

carbon, ammonia, and lime, as well as addi-

tional labor to operate and maintain the extra

equipment.

Worse yet, these estimates don’t take into

account catalyst or bag and cage replace-

ments; additional steam, water, and auxiliary

power usage; or by-product transport costs.

With the additional overhead expenses, find-

ing savings in other areas is imperative. De-

veloping a fuel flexibility strategy is one way

some companies have found to save a signifi-

cant amount of money.

During the ELECTRIC POWER Con-

ference & Exhibition (EP) held in New Or-

leans this April, Daniel Donochod, PE, fuel

flexibility strategy manager for Duke En-

ergy (Figure 1), gave a presentation entitled

“Keeping Coal Competitive—Fuel Flexibil-

ity.” In it, Donochod explained how Duke

Energy has diversified its fuel mix and, in the

process, positioned itself for better environ-

mental compliance.

Duke Energy is the largest electric utility

in the U.S., with about $114 billion in assets

and roughly 58 GW of generating capacity.

Like many companies, its generation port-

folio has changed dramatically since 2005.

Back then, coal accounted for about 55% of

total output, but the company estimates that in

2015 coal will fuel only 38% of its electricity

output. During the same period, natural gas–

fired generation is expected to increase from

5% to 24%, essentially picking up all of the

lost coal generation and more.

Although Donochod noted that there aren’t

1. Fuel diversification. Daniel Dono-

chod, PE of Duke spoke about fuel flexibility.

Source: POWER/Aaron Larson

PRBCUG Focuses on Safe Coal Handling

Andy Dobrzanski, Mark Collett, and Dave

Markle were among the presenters at the

Powder River Basin Coal Users’ Group (PRB-

CUG) annual conference held Mar. 31 to

Apr. 3, 2014, in conjunction with the ELEC-

TRIC POWER Conference in New Orleans.

The PRBCUG provides in-depth presen-

tations and discussions promoting the

safe, efficient, and economic use of PRB

coals by companies that currently use,

or are considering the use of PRB coals.

While several speakers mentioned house-

keeping’s important role in the safe opera-

tion of facilities, other topics were also

covered in depth.

One was fly ash–handling systems and

PRB coal ash. Dobrzanski, fuel supply

manager for DTE Energy’s Monroe Power

Station, noted that PRB coal fly ash size is

typically finer than bituminous fly ash and

normally has very low unburned carbon due

to the reactivity of the fuel. The majority

of the ash is removed as fly ash—70% to

90% of the total quantity—in a baghouse

or electrostatic precipitator.

Although Dobrzanski said that bottom

ash systems at Monroe are still wet sys-

tems, problems such as the Dan River ash

spill are putting pressure on the industry

to move toward dry ash systems. “There

are different types of systems—hydraulic,

mechanical, pneumatic, and vibratory sys-

tems—that collect bottom ash dry,” Dobr-

zanski said. “Those are some of the items

that we need to look at going forward to

meet the standards that I’m sure will be

developed very shortly.”

Mark Collett, director of mining and

minerals for River Consulting, discussed

electrical standards and area classifica-

tions. “There should be an electrical clas-

sification drawing for every substation in

the plant so you can always look on that

and see how an electrical area is classi-

fied,” said Collett. “If you don’t know

what the classification of the areas of the

plant are, there’s something wrong.”

Hot work procedures were also a “hot”

topic, but one can’t talk about hot work

without discussing fire protection. Duke

Energy’s Dave Markle noted that the only

guidance that the Occupational Safety

and Health Administration provides coal

plants is that if they have decided to have

a fire protection system, then it must be

maintained. “We are responsible for fire

protection ourselves,” he said. “There’s no

guidance for it, except if you have it, you

maintain it.” In other words, just like so

many things, “It’s up to us!”



many new coal plants being considered in the

U.S., the ones that are still in operation need

to be maintained, invested in, and stay com-

petitive. Because fuel expense is such a large

part of a power plant’s operating cost, there

are big opportunities for plants that have fuel

flexibility. (For more, see “Fuel-Flexible

CFBs Add Flexibility to Resource Plans” in

the May issue, online at powermag.com.)

The process of moving toward fuel flex-

ibility requires a team effort. It demands

station management to be on board to help

promote the strategy. Fuel procurement per-

sonnel, central engineering, outage and proj-

ect group members, environmental staff, and

perhaps most importantly, operators and pro-

duction managers must all collaborate for the

program to be successful.

Donochod suggested that having a dedi-

cated team that is focused on fuel flexibility

is important. “When you have people focus

on something, you don’t get them pulled in

a bunch of different directions. They’re fo-

cused on the mission,” he said.

Every plant is different, but some items

that need to be considered when developing

a fuel diversity strategy include: fuel-han-

dling systems, potential slagging and foul-

ing concerns, SO3 mitigation capabilities,

combustion issues, FGD operation, and

wastewater treatment. In some cases, the

coal will be drier, resulting in more dust.

Chute liners may be necessary to prevent

plugging issues. Additives may be needed,

such as magnesium hydroxide, to keep the

slag friable and improve sootblowing ef-

fectiveness. Getting the boiler combustion

tuned properly prior to making changes

is also very important. A lot of testing is

usually necessary, so starting with a good

baseline allows easier evaluation of future

adjustments.

Blending is also a critical factor for fuel

flexibility. “Coal is not coal,” Chuck Renner,

inspection and performance testing manager

for SGS Minerals Services, said during an-

other coal track breakout session. What he

meant by the statement is that there is a great

deal of variability in coal from different parts

of the country (see sidebar) and world. Even

coal from the same mine can vary consider-

ably from one seam to another.

With that in mind, the primary objective of

blending is to mix the coal to maximize uni-

formity. Producing the desired blend requires

accurate information about coal quality and

proper control of the proportions blended.

“You can’t control what you don’t measure,”

said Renner. “A competent quality assurance

plan includes verification of sampling, analy-

sis and weighing equipment, and methods.”

In order to achieve consistent results,

representative samples and precise analysis

are required. Acceptable blending can result

in increased profits. Renner noted that one

plant—burning three million tons of coal per

year—was successful in blending 10% of a

much less expensive product, which saved

the company $3 million.

Lowering fuel costs through fuel di-

versity isn’t usually free, however. Senior

management needs to be involved because

investments are often required. Donochod

said, “Try to get your funding separate from

your maintenance capital. Don’t get into a

dogfight with maintenance capital, because

you’ll never win. Strategic projects need to

have their own bucket.”

In the end though, the investment can

pay off. From January 2012 through Febru-

ary 2014, Duke Energy’s Carolina stations

saved $160 million in fuel costs. Once the

investment has been made and fuel flexibil-

ity is an option, it is the gift that keeps on

giving. ■

—Aaron Larson is a POWER associate edi-tor (@AaronL_Power, @POWERmagazine).

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The Dynamic Challenge of Integrating Variable ResourcesAll aspects of system operations are tested by unique challenges as more variable

energy resources are connected to the grid.

Sonal Patel

The share of non-hydro renewables in

total U.S. power generation shot up to

6.5% in 2013 from 2.4% in 2003, ac-

cording to the Energy Information Adminis-

tration (EIA). The past five years alone have

been specifically marked by a growth spurt

for wind and solar power—so-called “variable

energy resources” because the power they

produce is less predictable compared to power

from conventional technologies. Combined,

wind and solar power generation soared to

4.4% of the nation’s total generation in 2013,

compared to 1.49% in 2009 (Figure 1).

But, while the growth of these variable

resources is “a blessing for the planet and

for people,” it poses myriad challenges for

grid operators who must deal with inherent

swings, or ramps, in power output, said ABB

Director of Marketing Francisco Tacoa at the

ELECTRIC POWER 2014 renewables track

session on integrating renewables.

Generators, too, are being forced to tackle

a host of issues, he said. These include fac-

toring in the need for more flexible genera-

tion resources, meeting demand for real-time

energy requests, and evolving plant key per-

formance indicators to accommodate vari-

able renewables. Then they must minimize

damage to assets not designed for intermit-

tency, run power plants not designed for

highly variable generation, and coordinate an

automated and wide generation dispatch.

These issues will only gain more urgency

in the future, Tacoa noted. Backed by renew-

able portfolio standards (RPS) and federal

tax incentives, more than 50 GW of wind

capacity is projected to be installed in the

Western Interconnection while about 20 GW

are expected to be installed in the Eastern In-

terconnection by 2020.

An Energy Imbalance MarketTacoa outlined an interesting proposal in the

Western Interconnection to address the an-

ticipated increase in variable generation over

the next several years that calls for its smaller

balancing authority areas (BAAs) to pool

their variable and conventional generation

resources to improve operational efficiency

over a wider area. This sub-hourly, real-time

“Energy Imbalance Market (EIM)” would

provide centralized, automated, and region-

wide generation dispatch for imbalances. A

working group comprising several western

BAAs, the Western Governors Association,

and a number of other stakeholders is making

plans to link the entire Western Interconnec-

tion to the EIM.

The idea is gaining backers on a smaller

scale, too: In mid-April, MidAmerican En-

ergy’s newly purchased NV Energy filed

a request with the Nevada Public Utilities

Commission to voluntarily participate,

starting in October 2015, in a regional

5-minute EIM agreed to in 2012 by the

California Independent System Operator

(CAISO) and MidAmerican’s northwestern

utility PacifiCorp. NV Energy has said its

EIM participation could benefit all partici-

pating parties in the range of $9.2 million

to $29.4 million annually.

Nevertheless, the EIM concept isn’t with-

out its critics. Beyond concerns about exor-

bitant startup costs, cost shifting, and new

reliability problems, the American Public

Power Association points out that an EIM

has the potential to quickly evolve into a

regional transmission organization—which

historically “developed incrementally, with

continual additions of more complex and

costly centralized market features.” And, it

says, an EIM could suffer similar problems:

complex and costly market-pricing mecha-

nisms, price volatility, and an absence of

cost-effective measures to ensure resource

adequacy. (See “tablet” sidebar next page.)

The proposed Western Interconnection

EIM “does not require any formal coordi-

nated unit commitments, but it does not pre-

clude it down the road,” said Tacoa.

There also are other options to balance

generation and load in BAAs, he said, in-

cluding area-control error pooling, advanced

dynamic scheduling, or an intra-hour trans-

action accelerator platform.

More Flexible Generation ResourcesFor generators, the growth of variable gen-

eration has underscored the need for more

flexible generation resources, Tacoa said,

and if two key considerations were to be

identified, they are speed and efficiency. Gas

turbines are at least 20% more efficient than

steam boilers, which can take up to 12 hours

to warm up. And, while today’s gas turbines

2011

Share of total

generation:

5%(208 TWh)

2012

Share of total

generation:

5.7%(232 TWh)

2013

Share of total

generation:

6.5%(266 TWh)

2010

Share of total

generation:

4.5%(180 TWh)

2009

Share of total

generation:

4%(156 TWh)

■ Wind ■ Solar ■ Geothermal ■ Wood biomass ■ Other biomass ■ Other renewables

1. A growth spurt. Compared to 2009, the share of U.S. renewable generation that is not

conventional hydropower has increased 2.5%. From 2009 to 2013, wind generation increased

from 74 TWh to 167 TWh, while solar generation grew from 891 GWh to 9.2 TWh. Source: EIA



can get up to 150 MW in 10 minutes, next-

generation aeroderivative gas turbines prom-

ise even faster starts. Gas-fired engines win

on a number of fronts beyond the efficiency

factor, including ambient temperature opera-

tion without a derating factor, lower water

consumption, flex fuel, heat rate, and lead

time, Tacoa said.

But gas, too, has its shortfalls, as Jeff

Kopp, business consulting manager at Burns

& McDonnell explained. Kopp presented a

case study highlighting CAISO’s efforts to

address integration issues that are immi-

nent in its operation region, though he un-

derscored that California’s challenges are

unique compared to other states because

the state has an RPS of 33% by 2020. That

means forecasted high levels of variable

resources are becoming a reality: CAISO

projects that it will need to reliably meet net

load, manage about 3 GW of intrahour load-

following needs, and provide nearly 13 GW

of continuous up-ramping capability within

a 3-hour time period.

That will require more frequent dispatches

and the starting and stopping of flexible gas-

fired generators, which will potentially incur

more wear and tear and increase failure on

generation components, leading to increased

forced outages. (For more on the long-term

effects of increased cycling, see “Managing

the Changing Profile of a Combined Cycle

Plant” in this issue.) Added to that, lower

capacity factors for dispatchable generation

combined with potential reduced energy

prices could result in decreased energy mar-

ket revenues for the gas fleet.

Ultimately, CAISO’s efforts to stabilize

wind through gas generation—where gaps

were filled using market purchase or engine

dispatch, whichever was cheaper—showed

that the annual levelized cost of energy

(LCOE) from wind, gas, and the market was

less pricey ($51/MWh) than from wind and

gas only ($55/MWh), Kopp showed. These

and factors such as a high sensitivity to gas

prices determined that moving toward mar-

ketwide balancing may be a better practice,

he said.

Other OptionsYet another option to accommodate variabil-

ity is through power storage. ABB’s Tacoa

outlined several existing approaches such as

pumped storage hydropower, compressed

air energy storage, and several forms of

distributed battery-based power storage.

(For more on the state of energy storage,

see our May cover story “The Year Energy

Storage Hit Its Stride,” online at powermag

.com.) However, a number of roadblocks to

deploy storage alternatives exist, he said,

such as siting and permitting storage facili-

ties, negative environmental impacts, taxing

land demands, long lead times, and invest-

ment needs that must be ascertained without

a clear return on investment.

For Steve Fine, vice president at ICF In-

ternational, the challenges of operating a

grid with high renewable penetration span

different time scales for all system operation

entities—from less than a minute to years

(Figure 2). Different variable resources will

also require unique responses, he suggested.

Higher penetrations of photovoltaics, for

example, lead to increased ramping require-

ments that could stress system resources.

But renewable generators, too, bear risks,

Fine pointed out. Transmission congestion

and inflexible supply exacerbated by intermit-

tent generation increase risks to investments

in renewables owing to a higher likelihood

of negative energy revenues—forcing the

generator to pay to produce power—or eco-

nomic and involuntary curtailment.

So many dynamic challenges to the inte-

gration of variable resources will ultimately

require “a fresh approach to managing the

grid,” said Fine. ■

—Sonal Patel is a POWER associate edi-tor (@sonalcpatel, @POWERmagazine).

2. Minute and lengthy. The technical feasibility of a future with high renewable energy

penetration requires an adequate level of analysis on all aspects of system operations at differ-

ent time scales. Source: ICF

Local Regional Systemwide

Less than a

minute

Several

minutes

to an hour

1–24 hours

Years

Power

quality Voltage

management Regulation

System

stability

Load

following/

ramping

Distribution

efficiency

Congestion

management

Transmission

efficiency

Unit

commitment

Generation

adequacyTransmission

adequacy

Imbalanced Markets

For more on the possible implications of the proposed

energy imbalance market mentioned in this article, see

the May 9 blog post by Bracewell & Giuliani LLP attorneys

titled “Intervenors Urge Caution from FERC on CAISO-

PacifiCorp Energy Imbalance Market. You’ll find it at http://

bit.ly/1sKuvaH or by using the “Read the latest” link under

POWERblog on our homepage, powermag.com.

While you’re visiting the blog, you’ll find other FERC-

related posts, including “Terrible Twins Challenge FERC on

Enforcement Policies.”



Just Hop on the Bus, Gus: 13 Ways to Hack a Power PlantHave you done anything today to put your power plant at risk of attack? Are you

sure? Even if you think that plant security isn’t your job, it is.By Kennedy Maize

Forty years ago, musical genius Paul Si-

mon outlined “50 Ways to Leave Your

Lover.” In New Orleans in early April

at the ELECTRIC POWER Conference,

Mike Firstenberg of Waterfall Security Solu-

tions laid out 13 ways to lose your industrial

control network. Waterfall, based in Phila-

delphia, specializes in protecting industrial

control systems (ICSs), including those in

the electricity business.

13 Attack TypesHere are Firstenberg’s 13 ways that com-

puter hackers, for malicious purposes or just

for kinky kicks, can avoid the firewalls your

company thought would protect you and take

over critical ICSs. This includes the many el-

derly, very vulnerable SCADA (supervisory

control and data acquisition) systems, which

are almost always these days interconnected

with the enterprise’s overall information

technology (IT) network.

#1. Phishing. This is the easiest, most

common, way to bust into an allegedly pro-

tected network and involves getting respons-

es to spam, or fake emails, or what some refer

to as “drive-by download.” An email arrives

from someone you know, telling you to click

on the cool URL showing a picture of a kit-

ten and kids that you won’t want to miss. You

click. It’s a fake. You’ve been spear-phished,

and the phisherman now owns your network.

#2. Social engineering. Steal that pass-

word. Do you know where your passwords

are? They may be written on a label on the

backside of a keyboard or a desk drawer or

written on a post-it note on your office bul-

letin board—common and dangerous prac-

tices. Your ICS may have come from the

vendor with a default password, which your

techs have never changed. The most common

default password: 1234567890.

#3. Compromise the domain control-

ler. Create a fake account and ride it through

the front door and into the guts of the con-

trol system. Log on as a customer or vendor,

create an identity and a password, and it’s

“open sesame.”

#4. Attack exposed servers. The quick

path around the firewall is to use a “struc-

tured query language” (SQL) injection. Ac-

cording to Wikipedia, this is when malicious

SQL statements are inserted into an entry

field for execution (for example, to dump the

database contents to the attacker).

#5. Attack the ICS clients. This ap-

proach is to compromise the servers at the

heart of the interconnected ICS.

#6. Session hijacking. This is a common

trick using WiFi access points for monitor-

ing user traffic as it accesses the mother ship.

It is also known as “cookie hijacking.” This

is particularly common when users are con-

nected with open-access WiFi networks. So

don’t log on in the Starbucks or McDonald’s

and let the hackers eat your cookies.

#7. Piggybacking on the system’s vir-

tual private network (VPN). This is another

common tactic of hackers and is extraordi-

narily easy to accomplish—also a problem

with free WiFi access points. In the days after

Firstenberg’s presentation, it became public

that there is a serious bug in the OpenSSL se-

curity software widely used in VPN systems.

The analysts gave it the name “Heartbleed.”

#8. Exploit firewall vulnerabilities. Fire-

walls aren’t hardware in the cyber world. They

are software, and they have bugs, well known

to hackers (and obtainable easily over the

Internet). One well-known access to exploit

firewalls is through vendor systems that have

bugs the enterprise firewall can’t detect.

#9. Errors and omissions in the fire-

walls themselves. The smallest errors soon

get exposed for those probing ICS systems,

and they get posted on the Internet. Hackers

know far more about the vulnerabilities of

your systems than you do.

#10. Forged Internet Protocol address-

es. If an attacker can fake an Internet address

that fools the firewall, it’s easy access. This

is also known as “IP spoofing” and is a com-

mon, often successful, hacker tactic.

#11. Bypassing the network security.

There is available software that will trans-

late a web page into a foreign language and

thus bypass the site security measures. There

are also anonymizers, proxy sites, and tun-

neling software readily available to bypass

firewalls.

#12. Physical access to the firewall.

If you can touch it, you own it. So control-

ling physical access to the ICS system can

be crucial for protection. Who is that person

sitting at the terminal keying away to a fair-

thee-well?

#13. Sneaker net. If an attacker can get

to the firewall through a physical device

(Stuxnet, which gained control of Iran’s con-

trol system to corrupt operation of its nuclear

enrichment centrifuges, apparently was intro-

duced on a USB device), the attacker controls

the system. That’s game over.

Getting Real About Cyber Protection“This is a continually evolving environment,”

said Firstenberg. “Ten years ago we never

expected we would be doing this. And what

we have now learned is that what you don’t

know will hurt you.”

Firewalls, said Firstenberg, “are often the

first step any site makes when starting down

the road to cybersecurity.” But it’s only a first

And the Winners Are...

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step, and all of the 13 ways he mentioned will

defeat firewalls.

It’s not news that the bulk electric system

is vulnerable to cyber attacks. The North

American Electric Reliability Corp. (NERC),

under the direction of the Federal Energy

Regulatory Commission, has been work-

ing for years on what has become an ever-

changing landscape of rules and regulations

to protect “critical infrastructure,” known

to those who speak the jargon as “CIP” for

“critical infrastructure protection” standards.

NERC is now on the fifth iteration of its CIP

standards, aimed at protecting the bulk power

system, with version 3 in force and version

5 now leapfrogging the stillborn version 4.

(For more detail, see the set of special reports

on NERC CIP 5 in this issue.)

How to make sense out of the labyrinthine

course of the NERC cybersecurity program and

its multiple versions? Mike Radigan of ABB

and Kim Legelis of Industrial Defender, a com-

pany specializing in protecting control systems

in energy industries, including electricity, oil,

and natural gas (and recently acquired by de-

fense behemoth Lockheed Martin), presented a

paper on the cybersecurity landscape for indus-

trial control systems and CIP 5.

They noted that the Department of Home-

land Security’s Industrial Control System Cy-

ber Emergency Response Team (ICS-CERT)

recently reported 200 attacks in a six-month

period, a “drastic” increase, with most target-

ing the energy sector. Attempts ranged from

“brute force” to “sophisticated.” While most

cybersecurity programs are focused on pro-

tecting enterprise IT systems, industrial con-

trol systems present different characteristics.

Enterprise IT, they noted, seeks to protect

information, while ICSs are keyed to physi-

cal processes. Enterprise IT is looking to pre-

vent financial loss, while ICS threats are not

only financial but also threaten public health

and safety and the environment. Enterprise

IT’s focus is on central servers, while an

ICS is by its nature widely distributed. En-

terprise IT protection aims for 95% to 99%

system availability; ICS is looking for 99%

to 99.999%.

“Cyber incidents are real, and cybersecu-

rity for industrial control systems must be

taken seriously,” said Radigan. “But it is a

challenge that can be met.”

The latest CIP standards are much more

risk-based, compared to the checklist ap-

proach of previous NERC standards. The

early NERC CIP standards relied on com-

pliance rather than real security. “Version 5

represents a change in thinking by NERC

to security,” said Radigan. “It’s not compli-

ance,” but it is giving those covered a means

to manage more effectively in order to pro-

tect security. In this regard, he said, and other

speakers also noted, keeping up with cyber-

security protection has gone far beyond the

conventional utility approach of maintaining

manual computer spreadsheets for tracking

critical infrastructure protection. The paper

outlined four important aspects of keeping

up with cybersecurity:

■ Automation: “Manual efforts take too long

and are error prone.”

■ Timeline requirements: “Make sure things

get done on time—or earlier!”

■ Data analysis: “Data from across devices

and systems related and supporting vari-

ous requirements” are vulnerable.

■ Documentation and reporting: “Excel is

not your friend.”

The bottom line, Radigan and Legelis said,

is, “Prepare your organization for the coming

NERC CIP v. 5 requirements and for reason-

able protection against cyber threats.” ■

—Kennedy Maize is a POWER contributing editor.

POWER maga COAL POWER

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COMMENTARY

As hurricane season begins this year, utilities across the Gulf Coast will have a new partner as they work to keep the lights on after extreme weather events. Starting in late

2013, the Midcontinent Independent System Operator (MISO) ex-tended its service area from 11 states in the Midwest to cover Ar-kansas, Louisiana, Mississippi, and Texas. As the regional trans-mission organization that serves the Gulf Coast region, MISO is now responsible for ensuring the reliability of the electric grid for 42 million people.

As the grid operator for 15 states and the Canadian province of Manitoba, MISO has wide-ranging experience dealing with ex-treme weather events. Whether it is bitterly cold subzero tem-peratures, extreme heat, floods, or tornados, MISO ensures the reliable delivery of electricity across its service area. With the start of hurricane season, MISO will put that experience to work helping utilities in the Gulf Coast region get the lights back on following hurricanes and other extreme weather.

Utilities across the South are no strangers to preparing for and addressing the damage caused by hurricanes. (Ed.: See “Lessons in Resiliency and Risk” in this issue.) Entergy, the largest utility across the MISO South region, has won numerous awards from the Edison Electric Institute for storm restoration. Starting in 2012, MISO be-gan working with Entergy and other utilities in the South region to coordinate procedures and planning in preparation for ensuring the quickest and most efficient response in any storm’s aftermath.

What MISO provides is a comprehensive overview of the larg-est regional transmission organization region in the U.S. to help ensure reliability to as many customers as possible. MISO’s tools and data will provide an extra set of eyes to monitor the grid before, during, and following a storm to help get the lights back on as soon as possible.

MISO’s broad regional view and state-of-the-art reliability tools enable improved reliability for the region through trans-mission system availability. This provides $93 million to $140 million dollars in benefits across the entire MISO region, accord-ing to MISO’s most recent value proposition.

Grid-Monitoring ToolsA major vulnerability during hurricanes is the damage to data cen-ters that contain critical information needed for utility operations in a region. When IT facilities are damaged, utilities have diffi-culty monitoring system reliability. MISO has been working to ad-dress this issue through the Keep State Estimator Solving project, a simple name for a project that will have a large impact.

MISO’s State Estimator is a tool that provides the largest and most in-depth view of the electric grid. The system uses so-phisticated algorithms that gather data from nearly 300,000 data points from across the MISO system to predict events and conditions that could compromise reliability. The accuracy and frequency—MISO’s State Estimator solves every 60 to 90 sec-

onds—provides system operators with invaluable information on grid conditions.

As MISO expanded its service territory into the South Region, it worked closely with utilities to better understand how weather impacts their system performance. This allowed MISO to update the State Estimator to provide a better look at grid reliability during and after extreme weather events.

Additionally, MISO’s Real Time Contingency Analysis tool evalu-ates and lists the worst single contingencies that could occur, given the current state of the electrical grid, and—more impor-tantly—how the system would react for each. By running 12,000 contingencies that provide constantly updated information, sys-tem operators are in a much better position to manage those con-tingencies and head off potential problems before they occur.

Equipped with these tools providing a wide-area view of the sys-tem, MISO is able to coordinate with utilities in the region to provide the best independent picture of possible scenarios and contingencies and how the power system may be affected when damaged.

Working in Concert with UtilitiesAs a hurricane approaches the region, MISO amplifies its coordi-nation with utilities in the region. In particular, MISO will coor-dinate with utilities and regulators in the region to evaluate the impact of evacuations on load demand and unit availability.

When a storm is moving across the region, MISO, as a 24/7/365 operation, constantly monitors the bulk electric system for dis-ruptions. Additionally, MISO can utilize state-of-the-art tools to mitigate overloads of the system or prepare for the next contin-gency, loss of a facility. MISO brings more than 10 years of reli-ability and market experience that will help prepare the electric system for issues following extreme weather.

MISO also works closely with utilities as they conduct restora-tion activities. The utilities will identify the extent of the dam-age and provide that information to MISO. Priority No. 1 is the safety of those involved in restoring power and those affected by outages.

As linemen repair damage throughout the region, MISO will be overseeing and approving restoration activities on high-voltage transmission lines that connect different utilities before they are brought back into service. This coordination ensures the connec-tions are made in a reliable fashion to prevent further disruptions to customers or any cascading issues on the entire system.

MISO is trained, prepared, and equipped with best-in-class tools and experience to proactively assist utilities in the region when this season’s first hurricane rolls through. That experience and knowledge means quicker restoration and getting the lights on faster for customers in affected areas. And although MISO cannot control the forces of Mother Nature, we can be a critical part of getting things back to normal. ■

—Todd Hillman is vice president of MISO South (misoenergy.org).

MISO Prepares for Hurricane SeasonTodd Hillman

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power - june 2014

Documents

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new cip standards

o n e s o

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