power - july 2011

Vol. 155 • No. 7 • July 2011

Pairing Fossil Fuelswith Renewables

Underground Coal Gasification

Hydro: The Forgotten Renewable

Repairing Cooling Towers

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RENTECH breaks new trails in the boiler industry with its focus on custom engineering and design.

There’s no “on the shelf” inventory at RENTECH because we design and build each and every

boiler to operate at peak efficiency in its own unique conditions. As an industry leader, RENTECH

provides solutions to your most demanding specifications for safe, reliable boilers. From design and

manufacture to installation and service, we are breaking new trails.

CIRCLE 1 ON READER SERVICE CARD

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July 2011 | POWER www.powermag.com 1

On the CoverIn late 2010, Florida Power & Light (FPL) commissioned the 75-MW Martin Next Genera-tion Solar Energy Center, which it calls the world’s first utility-scale project to integrate solar thermal technology into an existing combined-cycle gas power plant. When the sun is shining, the concentrating solar power system allows the combined-cycle unit to “take its foot off the gas” and substitute steam heat from the solar array. Courtesy: FPL

COVER STORY: FUELS26 Using Fossil-Fueled Generation to Accelerate the Deployment of Renewables

In what could be the best partnering of the old and the new, the strategic pairing of fossil-fueled and renewable resources could pave the way for additional renewable generation without jeopardizing grid stability. Fast-start gas turbines, in particular, show promise for creating a hybrid, “dispatchable (quasi) renewable” plant that maximizes emissions reductions. We look at simple- and combined-cycle develop-ments that are poised to make news.

SPECIAL REPORTS CLEAN COAL TECHNOLOGY36 Underground Coal Gasification: Another Clean Coal Option

Coal resources are vast, yet concerns about meeting existing and anticipated emis-sions restrictions make its use problematic. One potential approach to using the fuel that is looking more attractive these days is underground gasification of coal. The process promises greater safety, access to otherwise unextractable resources, and cleaner power plant fuel at a competitive cost.

RENEWABLES44 Hydro: The Forgotten Renewable Rebounds

Nuclear gets all the press, but hydropower is staging its own renaissance of sorts, well below the radar. The hydro rebound appears to be slow and steady, and could be essential to meeting renewable portfolio standard goals. Here’s a look at the cur-rent U.S. licensing process and the types of hydro projects in our future.

COOLING TOWERS48 Defeating Concrete Reinforcing Steel Corrosion

Though concrete cooling towers look impermeable, deterioration often begins on the inside, as their reinforcing steel begins to corrode. This case study takes you through the entire process of before-and-after corrosion measurements, repair plan-ning and execution, and repair project evaluation.

FEATURES POWER VIEWS54 Modernizing the Grid, Modernizing Our Industry

David K. Owens, executive vice president, Business Operations Group for the Edison Electric Institute, comments on the smart grid: what it has to offer, how the grid is getting smarter, and where the money is coming from.

ASH MANAGEMENT56 The Better Environmental Option: Dry Ash Conversion Technology

Learn about a new bottom ash management technology that does not require the use of water, avoids the creation of wet ash requiring storage, and increases plant efficiency.

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RENTECH breaks new trails in the boiler industry with its focus on custom engineering and design.

There’s no “on the shelf” inventory at RENTECH because we design and build each and every

boiler to operate at peak efficiency in its own unique conditions. As an industry leader, RENTECH

provides solutions to your most demanding specifications for safe, reliable boilers. From design and

manufacture to installation and service, we are breaking new trails.

Established 1882 • Vol. 155 • No. 7 July 2011

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www.powermag.com POWER | July 20112

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Our equipment works great, but could we do more to get the winning edge?

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MATERIALS58 Titanium Tubing Still Going Strong After 40 Years

Titanium has proven an indispensable material, especially where operating condi-tions are challenging. Though it has a stellar four-decade record of immunity to cor-rosion, new applications continue to be explored.

REGULATORY ISSUES61 FERC Surrenders Jurisdiction over Station Power in California

In an unusual move, a federal agency’s decision to not exercise its authority is meet-ing with protests from industry. Get the big picture here and details of the situation’s legal history in our online supplement at www.powermag.com.

ELECTRIC POWER 2011: WHERE THE GENCOS MEET62 Consolidation, Market Distortions Underlie Remarks by Industry Executives

Want to know what keeps power industry executives awake at night? If you couldn’t make it to ELECTRIC POWER in Chicago, this is your chance to find out what the panelists were concerned about this year.

66 Nuclear Power in the Shadow of FukushimaThere was no question that recent events in Japan would color the remarks about nuclear power at this year’s ELECTRIC POWER Conference. Nevertheless, speakers argued that small, modular reactors could significantly minimize both safety and financing risks.

68 Solid Fuels: Moving Material and Managing EmissionsUnless you’ve been too busy to read this magazine for many months, you know that the big news in fossil fuels is renewables—specifically, biomass. What you may not know—even if you are a regular reader—is that we’re learning lessons from biomass that transfer to coal handling.

70 Utilities Increase Renewable Energy CapacityFour major utilities shared their approaches to increasing the renewable generation portion of their portfolios. Though some of their challenges are universal, others are tied to geography.

73 Sunny Days Ahead for U.S. Solar Energy SectorSeveral factors are leading to decreased costs for solar generation, and the North American market is responding with more, and larger, facilities.

DEPARTMENTS SPEAKING OF POWER6 Bad Gas Policy

GLOBAL MONITOR8 Pushing the 60% Efficiency Gas Turbine Barrier10 Germany to Shut Down All Nuclear Reactors10 TEPCO: Most Fuel at Daiichi 1 Melted12 Holtec, Westinghouse Roll Out Small Modular Reactor Designs14 Carbon Trust: Marine Energy Has High Potential but Faces Several Challenges15 POWER Digest

FOCUS ON O&M18 Texas Competitive Model Spreads to Pennsylvania and Illinois20 New Opportunities Abound for Retail Electric Suppliers22 Predictive Maintenance That Works

LEGAL & REGULATORY24 California’s New RPS: Opportunity Squandered

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

74 NEW PRODUCTS

COMMENTARY80 Geothermal Projects Race to Meet Incentives Deadlines

By Leslie Blodgett, editor-in-chief of Geothermal Weekly

Where Is Wind Headed?POWER was at the 2011 WINDPOWER conference this May, speaking with a host of international offshore and on-shore wind industry experts, as well as turbine and component developers, to gauge the key issues affecting this sec-tor. See what they had to say in our web exclusive, “Charting the Wind: Where the Sector Is Headed,” at www .powermag.com.

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Our equipment works great, but could we do more to get the winning edge?

Answers for energy.

SPPA-P3000 leverages our unmatched process know-how to help maximize your power plant equipment performance.

Give your equipment the edge it needs to help increase reliability and profitability. Siemens’ SPPA-P3000 solutions can help optimize your plant’s process for improved flexibility, availability and efficiency, without making costly equipment modifications. Contact us today to give your plant a performance boost.www.siemens.com/energy/controls

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We’re raising the bar on cleanliness.

If oil cleanliness is critical to your operations, turn to us; our dedicated bulk trailers can be dispatched to supply best-in-class turbine oils with a guaranteed ISO Cleanliness Code rating of 18/16/13. Our product line includes Ultra-Clean Turbine Oil and top-tier Diamond Class® Turbine Oil, which is proven to resist varnish formation for more than 35,000 hours in lab tests. This offering of two premium oils with extended oxidation stability and guaranteed cleanliness is an industry exclusive.

Long-lasting turbine protection starts here. Call 877-445-9198 or visit conocophillipslubricants.com/PowerMag to learn more.

Clean on arrival. Guaranteed.

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SPEAKING OF POWER

Bad Gas Policy

The late Dr. Carl Sagan once observed, “We live in a society exquisitely de-pendent on science and technology,

in which hardly anyone knows anything about science and technology (S&T).” I would add that those who know the least about S&T are often the ones responsible for determining policy and funding priori-ties. One good example of this problem is the piecemeal approach taken to devel-oping carbon capture and sequestration (CCS) technologies.

CCS: A Four-Step ProcessLet’s assume the end game is a fully devel-oped and reliable CCS infrastructure capa-ble of handling the gaseous CO2 emissions from existing and future fossil plants. If so, then the CCS system requires the simulta-neous development of four distinct links in the technology supply chain: CO2 must be stripped from the syngas (in the case of an integrated gasification combined-cycle plant) or exhaust gas (from conventional coal plants); CO2 must then be compressed; CO2 is then transported through pipelines to storage fields; and CO2 is injected into underground storage facilities. All four pro-cesses must work in concert if we wish to sweep CO2 under the rug, so to speak.

Both the development of commercial processes to strip CO2 from gases and geo-logic characterization work are in prog-ress. Compressing the CO2 without using a third of the plant’s output remains a technical challenge requiring intense re-search and development. Noticeably miss-ing is any substantive work on either the cost or policy formulations for interstate transportation of the gas from disparate sources to injection points.

Enormous CO2 VolumesA typical 500-MW coal-fired plant produc-es about 3 million tons per year of CO2. For comparison, the largest sequestration project in operation today injects 1 mil-lion tons of CO2 per year into a North Sea saline aquifer. Overall, the U.S. coal fleet produces about 1.5 billion tons of CO2 each year—approximately equal to one-third of the total volume of natural gas transport-

ed through 500,000 miles of pipelines in the U.S. each year. According to the Mas-sachusetts Institute of Technology (MIT) study, “The Future of Coal (2007),” if 60% of that CO2 were captured and compressed to a liquid for injection into a geologic formation, that volume would be equiva-lent to the 20 million barrels of oil the U.S. consumes each day.

The enormous volumes of collected CO2 will require a system of pipelines that will be extremely expensive to build and oper-ate. The MIT study estimated the cost to

transport and store CO2 at approximately $5 per metric ton. That puts annual op-erating costs for sequestrating CO2 in the billions of dollars each year.

A 2007 Duke Energy study estimated that it would cost $5 billion to construct a pipeline along existing rights of way from North Carolina to sequestration sites in the Gulf States and Appalachia. Extrapo-lated across the nation, the first cost of a network of pipelines would quickly climb to the hundreds of billions of dollars. In fact, the International Energy Agency in its Blue Case scenario (50% reduction of CO2 emissions by 2050) concluded that U.S. investment in CO2 pipelines by 2030 would be approximately $300 billion.

Many Policy HurdlesThose wishing to construct a CO2 pipeline also face a regulatory quagmire. For exam-ple, the Interstate Commerce Commission (ICC)—not the Federal Energy Regulatory Commission (FERC)—regulates interstate pipelines that carry commodities other than water, oil, or natural gas. Unlike FERC, the ICC has an uncertain regulatory structure with no pipeline-siting author-ity and, therefore, no eminent domain authority. That means developers are re-sponsible for obtaining the hundreds, or

perhaps thousands, of local, state, and federal permits necessary, plus easements from public and private landowners. There are also significant legal barriers to using existing gas pipeline right-of-ways. For an interstate pipeline crossing heavily popu-lated or environmentally sensitive regions, the challenges would far exceed those of siting transmission lines.

Existing laws are also a barrier to building new CO2 pipelines. For example, some state laws classify CO2 as a commodity, while others consider it a pollutant. States that

have pipelines supplying CO2 to enhanced oil recovery facilities have classified CO2 as a commodity with economic value for tax purposes. This creates an interesting policy dilemma for states that wish to construct an identical pipeline (or use the same pipe-line) to carry CO2 to a sequestration facility if they classify the gas as a pollutant with negative economic value.

Another observation is that the Depart-ment of Transportation (DOT) has primary authority to regulate CO2 pipeline safety under the Hazardous Liquid Pipeline Act of 1979. DOT lists CO2 as a hazardous materi-al, so the same pipeline safety and design rules that apply to building a gasoline pipeline apply to a CO2 pipeline.

And then there is the broader issue of who shoulders the liability for damages caused by leaks. I suspect that CO2 pipe-line operators will want the same blanket liability protection for leaks as an opera-tor of a CO2 sequestration facility.

My suspicion is that policy makers are either avoiding or have hugely misjudged the difficulty of forging the gas transpor-tation link in the CCS supply chain. On the other hand, perhaps a failed CCS policy is our best economic option. ■

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

It’s not just an adjective. It’s the new standard in power generation.FlexEffi cient Gas Generation from GE Energy provides the fl exibility and effi ciency you need to respond to the cyclic challenges of today’s grid. FlexEffi cient Gas Generation gives you faster starts, higher start reliability, quicker ramping, and lower turndown. All designed to make your plant more profi table. Flexible solutions for a fl uctuating industry. That’s FlexEffi cient. To fi nd out how you can become FlexEffi cient,go to ge-energy.com/fl exeffi cient.

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Existing laws are also a barrier to building new CO2 pipelines.

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It’s not just an adjective. It’s the new standard in power generation.FlexEffi cient Gas Generation from GE Energy provides the fl exibility and effi ciency you need to respond to the cyclic challenges of today’s grid. FlexEffi cient Gas Generation gives you faster starts, higher start reliability, quicker ramping, and lower turndown. All designed to make your plant more profi table. Flexible solutions for a fl uctuating industry. That’s FlexEffi cient. To fi nd out how you can become FlexEffi cient,go to ge-energy.com/fl exeffi cient.

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Pushing the 60% Efficiency Gas Turbine BarrierGas turbine makers GE, Siemens, and Mitsubishi Heavy Industries (MHI) in the last week of May separately profiled unprecedented results from development or testing of three innovative com-bined-cycle gas turbine (CCGT) technologies.

GE Launches Flexible, Efficient CCGTGE launched its FlexEfficiency 50 Combined Cycle Power Plant—what it called “a first-of-its-kind” power plant engineered to deliver an “unprecedented combination of flexibility and effi-ciency.” The 510-MW power plant is said to be capable of of-fering a fuel efficiency of greater than 61% while featuring a one-button start in under 30 minutes.

GE said at the launch of the turbine in Paris that the plant was designed to cost-effectively integrate renewables into pow-er grids on a large scale. According to the Financial Times, the plant’s 50-Hz gas turbine will initially be manufactured in France and be targeted at the European Union, which has set a goal that renewable power should provide 20% of all energy by 2020. GE has announced no plans for a 60-Hz U.S. model at present.

The new CCGT, which cost more than $500 million in research and development, draws from the company’s jet engine expertise “to engineer a plant that will ramp up at a rate of more than 50 megawatts per minute, twice the rate of today’s industry bench-marks,” GE said.

Development of the turbine began in 2004 after studies about how to best integrate intermittent renewable technologies into the grid showed that power systems of the future would char-acteristically see “more variability and uncertainty in the net load.” These systems could be managed with favorable “policies, power market structures, operating strategies, and investment incentives”—and advanced gas turbine technologies with flex-ible attributes would play a key role, GE said.

The company said GE engineers were able to avoid the “typi-cal tradeoffs between flexibility and efficiency by approaching the plant design from a total equipment and control systems perspective.” Essentially, the FlexEfficiency 50 integrates a next-

generation 9FB gas turbine that operates at 50 Hz (the power frequency that is most used in countries around the world); a 109D-14 steam turbine, which runs on steam produced from the waste heat from by the gas turbine; GE’s advanced W28 genera-tor; a Mark VI integrated control system that links all of the tech-nologies; and a heat-recovery steam generator (Figure 1).

The gas turbine will now be tested in GE’s full-loading $170 mil-lion testing facility in Greenville, S.C., at full capacity in a variety of real-world power plant conditions, beginning in 2014. Commer-cial operation and first achievement of 61% is expected in 2015.

GE already has a couple of buyers. In June, China’s Harbin Electric Co. signed a memorandum of understanding for the pur-chase of four 9FB gas turbines before 2013, including two that incorporate FlexEfficiency technology. And in June, the plant was selected by MetCap Energy Investments, a Turkish project devel-oper, for what GE says is the world’s first integrated renewables combined-cycle power plant. That plant, to be located in Kara-man, Turkey, will be rated at 530 MW and is scheduled to enter commercial service in 2015. (For more on integrating renewables and fossil fuels, see this issue’s cover story.)

Siemens: H-Class Turbine Exceeds ExpectationsJust days before GE’s launch of its new technology, Siemens an-nounced that it had achieved what it called a “new world record in power plant efficiency” with the SGT5-8000H gas turbine at E.ON’s Irsching 4 plant in Bavaria, Germany. The decade-long in-novation program for its new generation H-class gas turbine had surpassed 578 MW and reached a net efficiency of 60.75%. The Siemens turbine had been designed for 400 MW in simple-cycle duty and for 600 MW in combined-cycle duty (Figure 2).

Siemens Energy CEO Michael Suess said in a statement that with this achievement, Siemens had “left all current records with regard to output and efficiency far behind,” and “raised the bar for operating flexibility.” Siemens tested a number of correspond-ing load gradients and found that more than 500 MW could be

1. Model of efficiency. GE launched its FlexEfficiency 50 Com-bined Cycle Power Plant in May—a 510-MW power plant capable of offering a fuel efficiency of 61% and more. Courtesy: GE

2. More than expected. A Siemens Energy–built combined-cycle power plant—Irsching 4, near Ingolstadt, Bavaria, featuring Siemen’s H-class turbine—has achieved an efficiency of 60.75% and an output of 578 MW. This image shows the SGT5-8000H gas turbine in the foreground, the SGen5-3000W generator, and the SST5-5000 steam turbine—all of which are arranged on a single shaft. Courtesy: Siemens Energy

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put online in 30 minutes and stable load gradients of 35 MW/minute could be run—“absolutely exceptional figures,” he said.

Development of Siemens’ H-class turbine involved 250 engi-neers, scores of workers, and the construction and operation of a prototype plant in Irsching that required an investment of €500 million ($734 million). The turbine was included in mid-2009 as part of a combined-cycle facility by adding a bottoming steam cycle featuring a heat-recovery steam generator and turbine op-erating at 600C. The trial operation period is expected to be completed this summer, when E.ON will take over commercial operation of Irsching 4.

Siemens has sold six new 60-Hz versions of the plant to Florida Power and Light, which is expected to receive them in 2012. South Korean utility GS Electric Power and Services Co. has also ordered a single-shaft combined-cycle plant featuring the 60-Hz version, which is scheduled to go online in 2013.

Testing of MHI J-Series Also Makes HeadwayMeanwhile, MHI in May announced it had achieved a gross ther-mal efficiency that exceeds 60%, and “the world’s highest turbine inlet temperature” of 1,600C during test operation of its J-Series gas turbine, which began in February this year at a verification testing combined-cycle power plant at the company’s Takasago Machinery Works in Hyogo Prefecture. MHI said the accomplish-ment marks final confirmation in the testing of the new 60-Hz M501J, which MHI developed in the spring of 2009.

Theoretically, the higher a gas turbine’s inlet temperature, the greater is its thermal efficiency. The company claims that the tur-bine outperforms the 1,500C-class G-Series turbine, which held

the record for the highest inlet temperature so far. The M501J has also achieved a rated power output of about 320 MW and 460 MW in gas turbine combined-cycle power generation applications, in which heat-recovery steam generators and steam turbines are also used (Figure 3).

MHI is now developing a 50-Hz version, the M701J gas turbine, targeting first shipments in 2014. It adds that it will apply J-series

3. Massive possibilities. Test operation of Mitsubishi Heavy In-dustries’ (MHI’s) J-Series gas turbines, the 60-Hz M501J, has shown that it can achieve a gross thermal efficiency of more than 60% be-cause it is able to reach the “world’s highest turbine inlet temperature of 1,600C,” the company said in May. Courtesy: MHI

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verification results to the development of technologies to enable even higher temperature gas turbines. For now, MHI is expected to deliver six J-Series units to Kansai Electric Power Co.’s Himeji 2 power plant.

Germany to Shut Down AllNuclear Reactors Germany’s Chancellor Angela Merkel at the end of May officially endorsed a plan to shut down all 17 of the nation’s nuclear power plants by 2022. The decision, which gives the power-intensive nation just over a decade to find new sources of power for 23% of its energy needs, has had reverberations all over the world, though the future of nuclear—through growth in developing nations—continues to look sturdy.

Merkel’s historic decision—which has been likened to the de-cision to reunite East and West Germany in the 1990s—came after an overnight session at the German Chancellery following mass protests around the country against nuclear power, but it still needs parliamentary approval before being enacted. It al-lows the government to keep closed the nation’s seven oldest reactors that had been suspended in March (immediately after the catastrophic Fukushima crisis occurred), shutter six by 2021, and close the rest by 2022. Until then, perhaps one of the seven oldest reactors will be kept in reserve to guard against blackouts, Environment Minister Norbert Roettgen told reporters in May.

Otherwise, Germany will plan to cut its power usage by 10% and double the share of renewable energy to 25% by 2020. While Merkel prepares to submit bills to the Cabinet to restructure feed-in-tariffs for renewables and smart grids, Germany’s renewable energy federation, BWE, has said member companies are prepared to spend as much as €200 billion ($286 billion) by 2020 to de-velop wind and solar power.

The suspension of the seven oldest reactors has already forced Germany—a net exporter of power—to begin power imports from France, raising prices to consumers. Meanwhile, utilities that own nu-clear plants around the country, like E.ON and RWE, have threatened legal action against the government’s decision to retain a tax on spent fuel rods to cover costs of their disposal, while grid operators warned that the planned phase-out could result in winter blackouts.

E.ON said in a statement that it accepts “the will of the politi-cal majority” to phase out nuclear, but it expected financial com-pensation from the government amounting to “billions of euros” for the “damages associated with these decisions,” especially because it had prepared to extend the lives of its nuclear reac-tors. E.ON had already publicly said the nuclear fuel tax was “un-lawful,” when first announced. Because the tax withheld funds needed for investments to transform the energy framework and it put E.ON at an “unreasonable disadvantage in the European competitive market,” the company said it would sue the govern-ment over its decision regarding the fuel tax.

In Europe, Germany’s decision has been echoed only by Italy and Switzerland. France and the UK maintain political commit-ments to developing new nuclear. Lithuania in late May even began receiving bids for a new nuclear plant that could come online in 2020. Officials from that country said a new plant was necessary after the European Union ordered a shutdown of the Soviet-era Ignalina plant in 2009 and because the country im-ports 50% of its power and all of its gas from Russia.

Even the International Energy Agency (IEA) has jumped in, saying Germany’s moratorium on nuclear power could add 25 million metric tons to the country’s carbon dioxide emissions. The country would be required to generate 90 TWh of gas-fired power to replace 40 TWh from coal plants to offset the entire 25 million tons and satisfy

the European Union’s carbon constraint goals. Separately, the IEA warned in a report that the “unprecedented” challenge of decarbon-izing the world’s power supply could result in less than half of the carbon emissions reductions necessary by 2035 to limit the eventual increase in global temperatures to 2 degrees Celsius.

TEPCO: Most Fuel at Daiichi 1 MeltedTokyo Electric Power Co. (TEPCO) in May discovered—after cali-brating water gauges—that the water level in the reactor pressure vessel of Unit 1 at the quake- and tsunami-ravaged Fukushima Daiichi nuclear plant may have dropped to such low levels that the fuel was completely uncovered. This caused almost all the fuel pellets to melt and fall to the bottom of the vessel at a relatively early stage in the accident—roughly 15 hours after the March 11 earthquake that killed an estimated 28,000.

“Most . . . of the fuel is considered to be submerged in the bottom of [the] reactor pressure vessel and some part [was] ex-posed,” the company said in an official report, though it added

4. Battered down. The International Atomic Energy Agency (IAEA) said in a preliminary report that Japan’s response to the Fuku-shima Daiichi crisis was exemplary, but regulators underestimated the threat from tsunamis to coastal nuclear plants. IAEA representatives are pictured near the battered plant’s Unit 3. Courtesy: TEPCO

5. Dirty pool. The spent fuel pool at Daiichi 4 lost massive amounts of water in the aftermath of the accident, resulting in a hydrogen explo-sion and flames. This image from a video shows the damage sustained by the fuel in the pool. Courtesy: TEPCO

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that actual damage to the reactor pres-sure vessel is limited, based on tempera-tures around it. The utility is expected to release similar findings about fuel melt-down at Units 2 and 3. Meanwhile, com-puter simulations of the damaged units suggest that Unit 1 has one hole, Unit 2 may have two breaches, and Unit 3’s cooling systems may have been breached, TEPCO said.

Japan’s response to the dire crisis was exemplary under the circumstances, but the country’s regulation of its nuclear power sec-tor and safety preparedness was faulty, the International Atomic Energy Agency (IAEA) said in a preliminary report released in June (Figure 4). Specifically, the IAEA said that officials had underestimated the threat from tsunamis to coastal nuclear plants. “Nuclear regulatory systems should address extreme external events adequately, including their periodic review, and should ensure that regu-latory independence and clarity of roles are preserved in all circumstances in line with IAEA safety standards,” it says.

Japan has responded to the report by ad-mitting that poor oversight contributed to the disaster and that it would overhaul regu-lation of the country’s nuclear power sector. Japan’s Nuclear and Industrial Safety Agency (NISA) has so far already announced new safety measures. Only 19 of the country’s 54 reactors are in operation, and local govern-ments have reportedly been waiting for the new standards before approving restart of the remaining reactors.

Prime Minister Naoto Kan and NISA of-ficials have come under fire for failing to completely disclose key information about the crisis and ensuing radiation. In early June, for example, NISA officials revealed that the Fukushima accident had generat-ed 770,000 terabecquerels of radiation—more than twice the radiation previously estimated. That figure is reportedly seven times the radiation emitted by the acci-dent at Three Mile Island but just 15% that from Chernobyl.

Crews continue scrambling to control the situation at the Daiichi plant, which suffered critical power loss after a mag-nitude 9.0 earthquake and 14-meter (46-foot) wave—more than twice the height of the protective wall at Fukushima—and saw subsequent explosions at Units 1, 2, 3, and 4. TEPCO has begun preparatory work for installing a cover over the Unit 1 reactor building as an emergency measure to prevent the dispersion of radioactive substances until mid- to long-term mea-sures, including radiation shielding, are implemented. Nitrogen gas is still being injected into the Unit 1 containment ves-

sel to reduce the possibility of hydrogen combustion inside the vessel.

As of early June, closed-loop cooling had not yet been established, and fresh-water was being continually injected both via the feedwater system lines and the fire extinguisher lines into the reactor pressure vessels at Units 1, 2, and 3. TEPCO in May also began installing a supporting structure for the floor of the damaged spent fuel pool of Unit 4 (Figure 5). TEPCO believes that the damage to the Unit 4 building could have been caused by “hydrogen generated at Unit 3 that flowed into Unit 4.”

Meanwhile, TEPCO continues to deal with massive volumes of stagnant water in the basement of the turbine buildings of Units 1 and 3 that has high levels of radioactivity. It is trying to transfer the water into condens-ers, a radioactive waste treatment facility, the high-temperature incinerator building, and temporary storage tanks.

Holtec, Westinghouse Roll Out Small Modular Reactor DesignsAs the Daiichi nuclear crisis has govern-ments around the world reconsidering their nuclear-heavy energy plans and scrutiniz-ing the safety of existing reactors and third-generation designs, several develop-ers are touting the merits of small modu-lar reactors (SMRs). A growing number of SMR developers are considering applying for design certification from the U.S. Nu-clear Regulatory Commission (NRC). Among them are NuScale Power, with its 45-MW modular units, and Babcock & Wilcox, pro-posing a 125-MW mPower design. (For more on these plans, see “Nuclear Power in the Shadow of Fukushima,” p. 66) Joining that list are two new designs announced earlier this year: Holtec International’s 140-MW modular reactor and Westinghouse’s 200-MW integrated pressure water reactor.

Holtec in February said that the proof-of-principle studies of its HI-SMUR 140 were completed. The reactor’s core is located completely underground, operated by grav-ity-induced flow instead of a reactor cool-ant pump. Developers say it does not rely on offsite power for shutdown, and it can be installed as a single unit or a cluster at a site. “The waste heat from HI-SMUR’s power generation can be rejected through a water cooled or air cooled condenser or a combi-nation thereof,” Holtec said in a statement. “Eliminating the reactor coolant pump and the need for emergency or off-site power to cool the reactor core in the event of a forced shutdown, are among the distinguish-ing design features of HI-SMUR that define

its mission of utmost safety and security.” Among other features are its small footprint, a 24-month construction cycle, a miniscule site boundary dose, large inventory of cool-ant in the reactor vessel, and its modularity.

Holtec plans to fund development of the reactor itself—bypassing the fate of the Oregon State University–developed NuS-cale SMUR. NuScale Power earlier this year stopped work on contracts and has since laid off most of its 100-person workforce after its primary investor firm, the Michael Kenwood Group, was hit with a lawsuit by the Securi-ties and Exchange Commission on allegations that it was improperly diverting investors’ money. Employing a handful of executives, NuScale says it will continue to work toward submitting an application for design certi-fication next year. Holtec, which is in the process of submitting documentation for in-tellectual property protection under U.S. and international law, also plans to seek license application by the close of 2012.

Earlier in May, the Shaw Group an-nounced it would provide phase one engi-

6. A small package. Westinghouse’s un-named 200-MW integrated pressure water re-actor features core and reactor vessel internals that are derived from its AP1000, a third-gen-eration design. Horizontally mounted axial-flow canned motor pumps provide the driving head for the reactor coolant system. The design also features a compact steam generator and pres-surizer integrated into the reactor vessel head, which eliminates the need for a separate com-ponent. Courtesy: Westinghouse

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neering support for the SMR, developing the conceptual design of the balance-of-plant and support systems to advance the reactor toward eventual commercial application. Shaw also plans to pre-pare an overall design and support license activities.

Echoing other SMR developers, Westinghouse’s SMR design presents “few accident scenarios” because it has no active safety systems and the smaller design has “fewer penetrations of its re-actor and containment vessels, fewer vessels, and fewer pumps,” Michael Anness, manager for advanced reactors at the company, told attendees at a Platts-sponsored SMR conference in May.

The reactor’s primary components—drawn from the company’s third-generation AP1000 design—are located inside the reactor pressure vessel, and it is designed to be completely fabricated in the factory and shipped by rail. Westinghouse said the core, at the bottom of the module, is derived from a partial-height 17 x 17 fuel assembly used in the AP1000, and the reactor vessel internals are modified for the smaller core and to provide support for the internal control drive rod mechanisms (Figure 6).

This May, reacting to statements by NRC Chair Gregory Jaczko that the commission would not proceed with design certifica-tion for Westinghouse’s AP1000 until questions concerning the reactor design’s shield building and containment peak accident pressures were resolved, Westinghouse said the NRC’s discovery of new issues—“none of which were safety significant”—was be-ing “misinterpreted and sensationalized.”

The company’s design has been under increased scrutiny fol-lowing the Daiichi accident, and Westinghouse has been work-ing—as have many nuclear power vendors—to offer products that improve safety at nuclear plants. The company recently launched an emergency fuel pool cooling system that keeps spent nuclear fuel cool in emergency situations (or in temporary mode during refueling outages), including loss of plant power.

The system consists of a permanently installed “primary” cooling loop located inside the reactor building or spent fuel pool building and a mobile “secondary” cooling loop. The secondary cooling loop is stored offsite and then located outside the reactor building for either emergency or pre-planned use. “This approach reduces the time required for system assembly and startup, which is especially important during emergency situations, and eliminates the need to enter the reactor building,” Westinghouse said. The system includes mobile diesel generators, air compressors, switchgear and other support equipment required to operate the stand-alone system.

Carbon Trust: Marine Energy Has High Potential but Faces Several ChallengesIn a an analysis released this May, nonprofit UK group Carbon Trust admits that there is “still considerable uncertainty as to whether wave and tidal systems will play a meaningful role in meeting global energy needs,” but it suggests, based on high and low scenarios, that up to 240 GW of marine capacity could be deployed globally by 2050. Roughly 75% of this capacity will come from wave and the remainder from tidal energy.

The UK, whose coastline harbors almost half of Europe’s wave resources and over a quarter of its tidal energy resources, could hold a quarter of the global marine energy market by 2050, gen-erating nearly £76 billion (US$123.9 billion) if technology is suc-cessfully developed and deployed internationally and the UK builds on its existing lead. The industry will have to overcome several challenges, however, including technology verification, costs, and wider support in the form of public approval and grid upgrades.

Limited by cautious investment, the sector’s development has been inching ahead. Only a handful of marine energy systems are

at full demonstration stage, and most are in the early demonstra-tion or applied research phase.

Wave energy devices include oscillating wave surge converters, attenuators, overtopping devices, oscillating water columns, point absorbers, and submerged pressure differential devices. Globally, Carbon Trust estimates there are an estimated 70 to 80 wave en-ergy devices; around 80% of these are in early research stage. Only UK-based Pelamis and Aquamarine Power and U.S.-based Ocean Power Technology are currently in full-scale sea testing phase, the organization claims. “The UK is home to arguably the most ad-vanced concepts,” it says. “The U.S. is probably second.”

Tidal stream energy devices seek to harness the movement of water under the influence of the moon’s gravitational pull. Existing devices are horizontal axis two- or three-bladed concepts such as those used for wind power. Around 50 developers of tidal stream energy are active globally. Eight companies have or are building devices at full scale, but the majority of concepts are at a scale of a third or below, says the group. Leading concepts include Ma-rine Current Turbines (Figure 7), Atlantis, Hammerfest Strom, Voith Hydro, Pulse Tidal, Tidal Generation, and Open Hydro. The UK leads with around 15 devices, Carbon Trust says, Canada has around sev-en devices, and the U.S. about five (see “New York City Backs Tidal Power” in the May 2011 issue at www.powermag.com).

“For both wave and tidal[,] attritions . . . at the early stage are high, and of the numerous concepts in the initial stages of R&D a proportion will be expected to fail,” says the group.

Conditions required for marine energy to reach large deployments include ensuring that technologies are “proven.” This will be the most challenging, according to the group. Proving technical viability requires full-scale demonstration and deployment of initial arrays, but these stages are capital intensive, and the private sector will require some sort of public sector support, the analysis says.

7. Treading water. Marine energy has high potential but faces nu-merous technical and cost-related challenges, says UK nonprofit group Carbon Trust in a new analysis. Only a handful of marine energy sys-tems are at full demonstration stage. One example is Marine Current Turbines’ SeaGen, a 1.2-MW tidal energy converter that was installed in Strangford Lough in April 2008. Courtesy: Marine Current Turbines

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Marine energy will also have to reduce costs enough to com-pete with other low-carbon technologies, and this will “ultimately depend on the degree of targeted R&D that takes place and the degree to which it can drive accelerated cost reduction,” says the group. Other barriers include getting public approval for the po-tential environmental impact and sufficient development of the manufacturing supply chain. Today, the “most substantial barrier is the development of the electrical grid to accommodate the de-ployment of marine resources,” it says. Much of the deployment is expected to take place in remote locations such as the west coast of Scotland, where grid infrastructure is at present limited.

The sector can, however, expect to draw from established in-dustry sectors such as offshore wind, it adds.

POWER DigestIndonesia Sees Surge in Contracts for New Power Plants. Indonesia is Southeast Asia’s largest economy, but because it is stricken by chronic power shortages that limit economic growth, the nation’s government is pushing for massive infrastructure improvements. A consortium of Japan’s Electric Power Develop-ment (J-Power), Itochu Corp., and Adaro Energy, an Indonesian coal miner, on June 2 said they had won a tender to develop a US$3.2 billion coal-fired power plant in Java, Indonesia, for state-owned Perusahaan Listrik Negara (PLN). The 2,000-MW plant is the country’s first public-private partnership project. The power plant is expected to begin operations in 2017.

On May 31, PLN announced that South Korea’s Hyundai and Indonesia’s PP have secured a $339.4 million contract for the construction of an 88-MW hydropower plant in Sumatra’s Aceh province. That plant is expected to be grid-connected by 2016. Earlier, on May 12, China’s Gezhouba Group said it plans to construct a $1 billion hydroelectric power plant in Indonesia’s Sulawesi Selatan province and sell electricity produced by the plan to PLN. Construction of that plant will begin in 2012 and be completed in 2017. China Gezhouba has also signed a deal to build a coal-fired power plant in West Kalimantan.

The country’s hydropower expansion received another boost in late May as the World Bank approved a $640 million loan to help finance development of the Upper Cisokoan pumped storage project—the first facility of its kind in Indonesia. Construction of 1,000-MW project near Bandung, West Java, is expected to be completed at a total cost of $800 million (PLN will provide the remaining $160 million).

Chilean Government Greenlights Massive Hydropower Project. The $7 billion HidroAysén hydropower dam project pro-posed by utility Endesa Chile and Colbun on May 9 received en-vironmental approvals from the federal government commission. The 2.75-GW project involves the construction of five dams: two on the River Baker and three on the Pascua River. The first power station will begin operation in late 2019; the complex will be fully operational by 2025. Plant developers have been respond-ing to questions over the three-year environmental permit pro-cess, but the plant continues to spark dissent because opponents say it will flood untouched areas and displace communities. A planned 2,000-kilometer (km) transmission line from Patagonia to Santiago has not yet been approved.

Besides Chile, several Latin American countries—including Peru, Ecuador, Colombia, Brazil, and Argentina—are developing massive hydropower projects to sustain their growing economies. On June 1, Brazil’s environmental protection agency, IBAMA, issued a final installation license for the 11.2-GW Belo Monte hydropower proj-ect, allowing Brazil’s Norte Energia consortium to begin work on

the site on the Xingu River, in the Amazon region. Earlier in May, Brazilian iron ore producer Vale agreed to pay US$1.5 billion for a 9% stake in project, giving it the financial clout to proceed.

ABB Develops Energy Storage Solutions for UK, Swiss Renewable Projects. ABB on May 19 commissioned its first DynaPeaQ energy storage installation for utility UK Power Net-works at a site north of Hemsby in Norfolk, England. Part of ABB’s family of flexible alternating current transmission systems, DynaPeaQ is a combination of static var compensator technol-ogy with a highly scalable lithium-ion battery storage capability. Wind energy from a local village will be fed into the power net-work, and some of this energy will be kept in reserve to support power supplies in the event of a fault, or to regulate the power flow to compensate for the intermittence of wind power.

The ABB system includes eight stacks of 13 lithium-ion battery modules housed in a 25-square-meter building. The modules will be continually charged and discharged and can store up to 200 kWh of electrical energy, ABB said. The system’s effectiveness will be monitored in collaboration with the University of Durham and potentially be replicated across many coastal parts of the UK.

ABB in May also said it would partner with EKZ, a Swiss distri-bution utility, on a pilot storage facility in Dietikon, Switzerland. The facility will be integrated into the utility’s power distribution network and evaluated in key areas such as balancing peak loads, intermittent power supply, and the viability of such a solution for grid optimization. ABB will supply and install the 1-MW lithium-ion battery–based solution capable of storing 350 kWh to 500 kWh, providing additional power to the grid on demand. EKZ will evaluate the connection and behavior of grid-linked battery stor-

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E.ON Inaugurates 436-MW Gas Plant in Slovakia. E.ON on May 16 inaugurated a €400 million (US$587 million) modern combined-cycle gas turbine plant at Malženice in Slovakia. The 436-MW plant features an efficiency of more than 59%, the Ger-many firm claims, and it will be used mainly to compensate for the fluctuating production of electricity from renewable energies. The power station is E.ON’s biggest single investment in Slovakia so far.

Voith Wins Hydropower Equipment Supply Contracts in China. Voith Hydro on May 13 said it won two contracts worth a total €40 million from two Chinese utilities for equipment for new hydropower projects. One contract involves the supply of generators for two 340-MW units for the extension of Da Tang YanTan Hydro Power Co.’s existing Yan Tan plant, located at the Hongshui River in Guangxi Zhuang Autonomous Region. Voith will also supply three Francis turbines (each with an output of 400 MW) to the Huanghe Hydro Power Development Co., which is building the Yang Qu hydro power plant on the Yellow River. China sources 22% of its power from hydropower, but the govern-ment plans to increase existing capacities to 380 GW by 2020 from the current 210 GW.

MHI Starts Operation of Gas Turbine Combustor Plant in Georgia. Mitsubishi Heavy Industries’ (MHI’s) new gas turbine combustor manufacturing plant in Pooler, Ga., was completed on May 12 and has commenced full-scale operation. MHI, which ex-pects demand for gas turbine combined-cycle (GTCC) systems to

increase sharply in North America, is also building two other plants at the company’s Savannah Machinery Works site. One plant will undertake gas and steam turbine rotor servicing, and the other gas turbine assembly. The newly completed 13,000-square-meter combustor plant has advanced production lines similar to those at MHI’s Takasago Machinery Works in Hyogo Prefecture in Japan, the company’s main gas turbine production facility, and it will un-dertake fully integrated manufacturing, from welding assembly to processing and coating. MHI said in a statement that it will pro-mote increased adoption of GTCC systems around the world, and it intends to secure 30% of the world gas turbine market.

Siemens, EnBW Start Operation of First German Offshore Wind Farm. Siemens Energy and utility EnBW (Energie Baden-Württemberg AG) on May 2 put into operation Germany’s first commercial offshore wind farm. Located in the Baltic Sea, the EnBW Baltic 1 wind farm consists of 21 Siemens wind turbines, each with a capacity of 2.3 MW and a rotor diameter of 93 me-ters. The 48.3-MW wind farm covers an area of roughly 7 square km about 16 km north of the Darss/Zingst peninsula. Germany, a pioneer in onshore wind power, plans to increase its offshore wind capacity to between 20 GW and 25 GW by 2020.

Siemens is already developing a second offshore wind farm, the EnBW Baltic 2 (formerly known as Kriegers Flak), with EnBW. That project, which will have 80 wind turbines, each with a ca-pacity of 3.6 MW and a rotor diameter of 120 meters, is slated for grid connection in 2013. In addition, Siemens has orders for three other German offshore wind farms: Borkum Riffgat (108 MW), DanTysk (288 MW), and Borkum Riffgrund 1 (320 MW). ■

—Sonal Patel is POWER’s senior writer.

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Texas Competitive Model Spreads to Pennsylvania and IllinoisA record 400 attendees participated in KEMA’s 22nd annual Execu-tive Forum in San Antonio, Texas, in late April to debate and dis-cuss the “retail resurgence” of competitive electricity sweeping America. Founded in 1927, KEMA is a global provider of business and technical consulting, operational support, measurement and inspection, testing, and certification for the energy and utility industry. With world headquarters in Arnhem, the Netherlands, KEMA employs more than 1,700 professionals globally and has of-fices and representatives in more than 20 countries. KEMA’s U.S. subsidiary, KEMA Inc., is headquartered in Burlington, Mass., and serves energy clients throughout the Americas and Caribbean.

You may be asking yourself: Why should I be interested in re-tail electricity markets? You would be wrong to think that you are in the business of making electricity but not selling it. Changing trends in customer retail purchasing are now having significant impact on plant operations. Your plant may now, or soon, be selling into deregulated markets, where customer choice means increased competition. The low-cost generator will make the sale in deregulated areas, while pressure will increase in regulated regions to hold the line on retail rates.

Competition Is the KeyIt was about 10 years ago that the wheels came off the original drive to “deregulate” electric power markets in the U.S. Enron was the poster child of the movement and led the state-by-state campaign to turn loose the forces of the marketplace by promis-ing lower prices of electricity for customers, much as in the air-line and natural gas industries. California was a leading advocate

of the competitive market plan. With 37 million residents, Cali-fornia was a huge target for new sellers of electricity. But Enron’s excesses, which lead to a crash and burn in 2001, were followed by a rash of lawsuits and the bankruptcies of companies such as Pacific Gas & Electric, NRG, Mirant, and Calpine. California lost its confidence in competitive markets and went back to the old regulated model. Figure 1 illustrates the status of the U.S. retail markets today.

Texas regulators studied the tough lessons learned in California and adopted a different market structure that includes a choice of competing suppliers for all retail customers, even residential. Although there were new lessons to be learned and digested, the Texas competitive model is widely regarded by experts and, more importantly, by customers, as a huge success. Today, in each of the five major regions of the Electric Reliability Council of Texas, there are more than 30 retail electric providers (REPs) that com-pete for customers. (In other parts of the country, they may be called RES, retail electric suppliers.)

About 90% of residential customers with access to competi-tion (munis and co-ops to date have not allowed choice) have switched to a new retail provider at least once.

As Barry Smitherman, chairman of the Texas Public Utilities Commission (PUC) noted, “We have lower prices, more choices, and happier customers. We have a good market model in place and try not to interfere. Our job at the PUC is to not screw it up. To-day in metro Dallas or Houston, residents can buy electricity on a fixed-price one-year contract for about 8¢/kWh; or if you’re willing to go with a month-by-month plan linked to the price of natural gas, today’s price is about 5¢ per kWh.” (The average retail price of electricity in the U.S. in May 2011 was just under 10¢ per kWh.)

Also speaking at the KEMA conference was Mayo Shattuck, CEO of Constellation Energy. Constellation is the parent company of Baltimore Gas and Electric, and Constellation NewEnergy, a REP. Shattuck recalled Constellation’s seminal moment in 2002 when purchasing NewEnergy from AES. Part of the rationale behind the purchase was to transplant some of the entrepreneurial culture of NewEnergy into the entire Constellation organization.

He attributes Constellation’s success to focusing on the three Cs: costs, customers, and competitors. “We have to be advocates of the competitive market wherever we do business and deliver the promise.” Ironically, Constellation’s metropolitan Baltimore home turf has recently become a battleground for residential cus-tomer advocates. It took more than five years after the rate caps were lifted for residential customers en masse to figure out that electricity is something that you shop for. Shattuck notes, “We once had rate payers; now we have customers.”

Exelon announced at the end of April the purchase of Constel-lation Energy for $7.9 billion. The purchase is expected to be completed in early 2012.

The growth of competitive markets in the U.S. is being driven by the desire of customers to choose their electricity supplier based on price, terms, and service. During 2010, the total quanti-ty of electricity purchased from competitive suppliers by custom-ers who switched suppliers was up 25% for residential customers and 18% for nonresidential customers (Figure 2). The greatest increases in switching rates occurred in Ohio and Pennsylvania (Figure 3). Consumer choice in the selection of REP to reduce the cost of electricity is gathering momentum, but so are opportuni-ties for those same retail suppliers (see the next story).

Fully competitive Fully open Partially open Re-regulated Closed

1. U.S. retail markets changing. The size of the pie for each state is based on overall sales volume, and the blue wedge in each pie is the fraction of consumers eligible to switch who are now served by a nonincumbent electricity providers (as a fraction of sales). For ex-ample, in Michigan, about 10% of the market (sales volume) is eligible to switch to a nonincumbent provider (the size of the circle) and, as the filled-in blue circle indicates, nearly 100% of those eligible to change from incumbent suppliers have done so. “Open” indicates markets where consumers are eligible to switch. “Fully open” markets are those where all customers are eligible to switch retail electricity pro-vider but where the markets are not competitive. “Fully competitive” markets are those where the entire market has switched and there are technically no incumbents. Source: KEMA

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One Million Pennsylvanians SwitchThe big buzz at the conference was that in less than a year, more than 1 million Pennsylvania residential customers had switched from the default supplier, and the rate of switching was acceler-ating in the wide-open Philadelphia market.

PUC Chairman Robert Powelson, a passionate supporter of competitive markets, noted that the debate in Pennsylvania was “what do we do about the default supply?” Customers are not obligated to shop for electricity and change suppliers, but if they do not, they will be served by the default sup-plier at a price above the competitive market. Often, these non-shopping customers are the ones who can least afford an excessive electric bill.

Powelson said that continuing education is needed to remind residential customers that shopping for electricity is encouraged and that switching will not affect the reliability of service at their home. If there is a storm that causes a major power outage, restoration of service will be no faster or no slower for electricity shoppers.

Illinois Protects ConsumersIn the summer of 2007, the Illinois General Assembly created the Illinois Power Agency (IPA), an independent government agency, to develop and manage a new electric supply procurement process for customers of Ameren Illinois and ComEd. After overseeing the procurement of electric supply, the IPA directs the utilities to en-ter into wholesale electric supply contracts of various durations to purchase electric supply from different sources.

According to a plan developed by the IPA and approved by the Illinois Commerce Commission, Ameren and ComEd purchase the electric supply for customers who have not chosen to receive supply from a REP. The utilities charge customers for the costs of purchasing electric supply, without any markup or profit. Ame-ren and ComEd also pass through a transmission charge and the regulated cost of delivering the electricity. A typical residential customer in Chicago can currently reduce the commodity por-tion of the electric bill by 15% to 20% by switching to an REP for a one-year term. Promotional codes are available for further savings on some plans and at least one REP offers frequent flier miles for each $1 of electricity purchased.

Currently, about 75% of the electricity consumed by Illinois’ commercial and industrial customers is provided by a REP. In ad-dition, there are seven REP companies competing for residential customers in Ameren territory and 12 in ComEd territory. Custom-ers in MidAmerican Energy’s service territory also have the right to choose a retail electric supplier. However, no suppliers have registered with MidAmerican to serve these customers, likely be-cause the competitive market is small and has lower retail rates.

According to the Illinois Commerce Commission, residential shopping for electricity increased during the first quarter of 2011, but exact data has not been released. As of November 30, 2010, only 0.3% of residential customers in ComEd’s territory had switched to a REP. It would not surprise me to see as much as 5.0% of the residential load switched over to the competitive market by the end of 2011.

—Mark Axford is the principal of Axford Consultants LP and a POWER contributing editor.

New Opportunities Abound for Retail Electric SuppliersFollowing the conclusion of the KEMA conference (see previ-ous story), Mark Axford had the opportunity to talk with Phillip Tonge, recently appointed president of Spark Energy LP. Spark Energy is a retail energy provider (REP) of electricity and natural gas in 16 states that have opened their markets to competition for industrial, commercial, or residential customers.

Axford: Did Spark Energy see a resurgence in retail electric markets during 2010?

Tonge: Absolutely. Texas has become a mature market that is working well after 10 years of competition. For Spark, 2010 was a “hold your own” year in Texas, but we saw lots of growth and excitement in other regions. Pennsylvania is perhaps the best ex-ample of a rapidly growing market. They are getting good media coverage and public awareness of competitive choice. As a result, large numbers of customers have switched to a new electric pro-vider in a short time.

Axford: As Spark arranges its electricity supply for customers, what fraction is hedged in bilateral contracts versus spot market purchases? Would you consider your fraction to be typical for REPs?

Tonge: Our goal with managing the supply portfolio is to run a flat book, which means we endeavor to match our supply exactly to our load obligations as much as possible for any given hour.

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2. Fierce competition. Competitive electricity markets continue to grow because residential users are demanding choice of electricity supplier. During 2010, the total quantity of electricity purchased by con-sumers who switched electricity suppliers was up 25% for residential customers and 18% for nonresidential customers. Source: KEMA

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3. Change leaders. Ohio and Pennsylvania led the deregulated electricity markets with the number of residential retail customers switching electricity suppliers. This chart illustrates the total competi-tive retail electricity sales in 2009 on the left, the electricity purchased by customers who switched from the default supplier in selected states, and total electricity sales in 2010. Source: KEMA

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We do occasionally have a small amount of spot market exposure in the portfolio, but mainly in months where we see low price volatility. We typically enter a month no less than 95% to 100% hedged to expected load and will fill in the rest with either day-ahead or spot purchases. This is pretty typical practice for an REP running a well-managed supply portfolio.

Axford: Is it fair to say that Pennsylvania is looking like the next Texas for customer choice in retail electric markets?

Tonge: I think so. If you look at Pennsylvania, there are sev-eral things in common with the Texas market. First, the number of competitors—about 10 to15 providers in Harrisburg and Phila-delphia markets. Second, the pace of switching in PPL and PECO territories has been staggering. Nearly 50% of all PPL residential customers have switched since the price caps were removed about 18 months ago. In Philadelphia, about 16% of PECO’s residential customers have switched since the price cap came off on Janu-ary 1, 2011. Today, there’s market frenzy in Philadelphia because this is far and away the largest zone for households and meters in Pennsylvania.

Axford: Did Pennsylvania make a conscious effort to copy the Texas model? What are the major differences?

Tonge: Well, the [Public Utility Commission (PUC)] commis-sioners in Texas and Pennsylvania (Barry Smitherman and Robert Powelson, respectively) have exchanged compliments about how each state has handled the transition to customer choice. I think the major difference between the states is that Pennsylvania cus-tomers still have the old “utility rate to compare,” once known in Texas as the “price to beat.” Unlike Texas, the poles and wires have not been completely separated from the competing incum-bent provider in Pennsylvania.

Another important difference is that most new entrants to the Pennsylvania market must bill their customers via the incumbent provider. One challenge that all REPs face is to develop strategies to build a relationship with the customer. In Pennsylvania, we don’t yet have an anchor, the monthly bill, to better establish that relationship. In Texas, all completive electric providers bill the customer by e-mail or direct mail, and customers see their logos, websites, and promotional programs. We will continue to look at billing options in Pennsylvania as well as other markets.

Axford: Why do you think Pennsylvania has such a robust mar-ket for switching while other states in the Northeast, such as Connecticut and New York, have had a less-exuberant response to competition?

Tonge: First, I think kudos must go out to the PUC in Penn-sylvania. One thing Pennsylvania did very well was to conduct a series of consumer education seminars. There were opportunities for consumers who were sitting on the fence wondering, “What does all this mean?” to come in and hear about competition from the commission staff and the retail providers themselves. Second, I think the media in Pennsylvania latched on to the fact that this was a watershed event with a date certain for competi-tion to begin. It was newsworthy. The media got on top of it and helped explain the consequences of switching, or not switching, to the average household customer. Of course, the media did not endorse a particular competitor, but they did help create a buzz in the marketplace.

Axford: Is there a critical mass needed in a competitive power market before the switching rate takes off? It seems like New York and Connecticut have not been able to achieve the critical mass like Texas and Pennsylvania.

Tonge: Spark Energy has been happy with the market in Con-necticut, and we continue to add customers at a good clip. From my perspective, there is a little less certainty in Connecticut that

all of the political forces are 100% on board for competition with no looking back to the old regulated model. If a company like Spark Energy does not see a commitment for market longev-ity, they will be more careful about their investments in that market.

New York is a bit different. There are many incumbent utilities, and the competitive dynamics are strongest around New York City. Other regions of the state have lower electric prices and are not as attractive targets for REPs. The statewide switching rate in New York is at 20.7%, which is a 12.5% year-over-year increase from December 2009.

I am optimistic about New York as a place for Spark Energy to do business because I feel that the PUC is committed to com-petitive markets. It just hasn’t generated the buzz that we are getting in Pennsylvania.

Axford: How does Spark Energy see the newly opened market in Illinois?

Tonge: We’re in the Chicago area right now. Like in Pennsyl-vania, we have taken an innovative approach to our marketing arrangements in Chicago. We want to look, feel, and act as part of the community. We have partnered with important local in-stitutions to speed up our brand recognition. We are allowed to send our bills directly to customers in Illinois, but for now we are billing through ComEd while we grow our customer base.

Axford: Is the speed of switching in Illinois as fast as Pennsyl-vania or even more rapid?

Tonge: Illinois feels like Pennsylvania in some ways. Neither the Illinois Commerce Commission nor ComEd have published any switching statistics for the first 90 days of competition (since

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January 1, 2011). But consumers are getting the message and responding to it. The option of choice has not been covered by the media as broadly in Chicago as in Philadelphia.

Axford: If Pennsylvania is the next Texas and Illinois is the next Pennsylvania, where is the next big market for competitive retail power?

Tonge: Certainly, Florida would be of great interest to Spark Energy if it were to open up. They have a large population and larger-than-average consumption of electricity. It is interesting to note that Florida’s largest incumbent utility (NextEra) has a subsidiary (Gexa) that is aggressively seeking customers in Texas and other states open to competition. Based on some of the comments I heard at the KEMA conference, I asked our regulatory team look into both Florida and Arizona. If I was a regulator in another state looking at how to get competitive markets moving, I would look at Pennsylvania as the example.

—Mark Axford is the principal of Axford Consultants LP and a POWER contributing editor.

Predictive Maintenance That WorksIn the April “Focus on O&M,” we began a series of articles on predictive maintenance (PdM), also known as condition-based maintenance. In that article we introduce PdM as a process where maintenance is performed based on the condition of the equip-ment rather than on a predetermined interval. We also discussed how a well-oiled PdM program requires an upfront investment in equipment and in the training of technicians in order to reap lat-er benefits. The costs and benefits were also discussed in detail. Given the extremely high cost of an outage in lost energy sales,

plus the high cost of replacement power purchases, the cost of a PdM program often is justified solely based on the expected plant reliability improvement.

This installment of the series continues our review of different conditioning-monitoring techniques commonly in use at power plants using any generation technology. In the May issue we be-gan exploring specific PdM techniques with an examination of electrical surge comparison and motor-current signature analysis.

The equipment and techniques discussed are certainly not comprehensive, as new and improved methods and equipment are routinely introduced. We are discussing PdM programs that could be likened to a “basic load” of ammunition, food, and protective equipment for a soldier. You can always carry more, but the basics are sufficient for most missions.

For example, one major element of any robust PdM program is nondestructive testing (NDT) technologies. Within the category of NDT are a number of specific testing approaches used in the plant such a lube oil analysis, thermographic analysis, shock-pulse measurements, ultrasonic analysis, wear-particle analysis, and vibration analysis, to name a few. In this article we begin our discussion of the elements of NDT with a look at the most important aspects of a high-quality oil analysis program.

Routinely Analyze Your OilOil analysis identifies the condition of fluids and lubricants and determines if they are suitable for continued use or should be changed. It also indicates the condition of internal, oil-wetted components, identifying excessive wear. Generally speaking, rou-tine oil analysis will find active machine wear. Oil analysis also

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can be used to identify the presence of contamination, which can lead to premature failure. Particle contamination is usually credited with 60% to 80% of all machine lubrication-related fail-ures. Oil analysis can be used on machines that have a circulating oil system, including steam or gas turbines, generators, hydrau-lic systems, diesel or gasoline engines, gearboxes, boiler-feed pumps, and even machine tools.

For the most accurate results, samples should be taken from an active, low-pressure line, ahead of any filtration devices. For consistent results and accurate trending, samples should be tak-en from the same place in the system each time (using a per-manently installed sample valve is highly recommended). Most independent labs supply sample containers, labels, and mailing cartons. If the oil analysis is to be done by a lab, all that is required is to take the sample, fill in information (the machine number, machine type, and sample date), and send it to the lab. Results are normally available within 24 hours of receipt of the sample. If the analysis is to be done onsite, analytical equipment must be purchased, installed, and standardized. Sample contain-ers must be purchased, and a sample information form created and printed.

The most common oil analysis tests are used to determine the condition of the lubricant, excessive wearing of oil-wetted parts, and the presence and type of contamination.

Oil condition is most easily determined by measuring viscosity, acid number, and base number. Additional tests can determine the presence and/or effectiveness of oil additives such as anti-wear additives, antioxidants, corrosion inhibitors, and anti-foam agents. Component wear can be determined by measuring the amount of wear metals such as iron, copper, chromium, alumi-num, lead, tin, and nickel. Increases in specific wear metals can mean a particular part is wearing, or wear is taking place in a particular part of the machine. Contamination is determined by measuring water content, specific gravity, and the level of sili-con. Changes in specific gravity often mean that the fluid has been contaminated with another type of oil or fuel. The presence of silicon (usually from sand) indicates contamination from dirt.

Spot checking (sampling a system once a year or less) is used primarily to determine whether the fluid or lubricant should be changed, or to confirm if a suspected problem actually exists. For example, if a machine is experiencing noticeable vibration or noise, an oil sample may be taken to confirm if there is bear-ing damage or excessive wear. Sampling machinery on a periodic basis (once a month or once a quarter) can provide a more subtle indication of lubricant or machine deterioration, or the slow in-troduction of contamination. Most bearing or gear failures occur after their condition has deteriorated slowly and steadily for a period of months or even years. Contamination may be intro-duced when oil is added to the system, and periodic monitoring will indicate this. Early warning of contamination allows repairs to be planned during a scheduled shutdown.

Long-term monitoring of oil condition over six or eight sample periods can identify improper maintenance or repair practices. These can include the failure to properly flush out a system after repairs, improper fluid- or lubricant-handling procedures (which introduce water or dirt contamination), or improper filter-han-dling or -replacement techniques.

Unusually rapid oil degradation can indicate that the oil is not suitable for the equipment or application. For example, a rust- and oxidation-inhibited oil, rather than a straight mineral oil, may be required where there is the possibility of high tem-peratures or water contamination. Rapid oil degradation may also indicate that the equipment is being operated beyond its original

design capacity, creating excessive temperatures or bearing/gear surface loading.

Oil analysis is one of the simplest predictive techniques to use, and certainly one of the least expensive. Independent labs can help select machines and frequencies, suggest which tests to run, supply sample bottle and mailers, interpret the results, and archive data. The maintenance departments of most compa-nies have some experience with oil analysis, if only on a limited basis.

In spite of its low cost and simplicity, oil analysis can be an extremely effective technique, particularly when the data is trended over an extended period of time (12 to 24 months). Trended data can identify poor maintenance and operating prac-tices, which, if corrected, can result in substantial maintenance and operating cost savings.

One company found that contamination levels increased sig-nificantly each time oil was added to a gear reducer on a coal-handling system, and the contamination resulted in bearing and gear failures. Upon examination, they found that removing the cover plate to add oil allowed coal dust to fall into the sump. They installed a covered oil reservoir and piped it to all of the gear boxes. Now clean oil can be added by opening a valve, and the incidence of bearing and gear failures has been significantly reduced.

Also, make sure the samples are:

■ Taken immediately downstream of the lubricated surfaces.■ Taken during normal operating conditions, including pressures

and temperatures.■ Taken at the same location each time.■ Taken after the oil has circulated for a time after an oil

change.■ Are representative of the oil in the machine.■ Are placed into a sample collection container that is clean,

nonmetallic, and immediately sealed.

Oil analysis can be used only on equipment that contains a circulating oil system. In most cases it can indicate that a prob-lem exists—for example, that there is excessive wear. However, it may not be able to identify the specific cause—what is causing the wear—or which of similar or identical parts are wearing.

Oil analysis is only as good as the timeliness and consistency of the sample. The longer a sample sits before it is shipped and analyzed, the less significant the data; and the value of trended information diminishes quickly if samples are not taken from the same place on the machine each time.

A final thought: Oil analysis is not a standalone program but must be integrated into a comprehensive PdM program. If you only take oil samples when there is a problem, or when there are other system problem indicators (such as high vibration), then you’ll miss a large measure of the program’s benefits. Oil analysis requires constant sampling in order to develop trends that can be used to identify problems before they become chronic. Without knowing what is “normal,” it’s difficult to determine what is “ab-normal.” Sample oils frequently: critical equipment at least once a month and noncritical equipment at least once a quarter.

More ComingIn the next segment of “Predictive Maintenance That Works,” we’ll continue our discussion of specific NDT-related condition-monitoring techniques used at power plants and why each should be a part of your PdM program. ■

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

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Steven F. Greenwald Jeffrey P. GraySteven F. Greenwald

California’s New RPS: Opportunity SquanderedBy Steven F. Greenwald and Jeffrey P. Gray

In April, California Governor Jerry Brown (D) signed Senate Bill 2 (SB2) into law. When it becomes effective later this year, SB2 will be the primary legislation governing implementation

of the California Renewables Portfolio Standard (RPS) program.Governor Brown embraced SB2 for “stimulating investment

in green technologies,” “creating tens of thousands of new jobs,” and “promoting energy independence.” The governor projected that SB2 would “ensure that California maintains its long-standing leadership in renewables” and that an RPS tar-get of “40%, [and] at reasonable cost, is well within our grasp in the near future.” The resulting sound bite delivered the de-sired political message: By 2020, the percentage of renewable generation that California utilities must purchase increases from 20% to 33%—clearly making California’s RPS target the nation’s most aggressive.

SB2: Same Old, Same OldThe “green technology” hype aside, SB2 will likely not advance the development of, or any investment in, RPS power, nor create “green” or any other types of jobs, within or outside of California. SB2 will inflate demand for RPS power and concurrently restrict supply—cir-cumstances that economics teaches will trigger price increases, not decreases. The uncertainties of California regulation, combined with the idiosyncrasies of the RPS policies of other states, have deterred RPS development throughout the West. SB2 adds layers of regulatory complexity, causing inevitable delay; the California Public Utilities Commission initiated a rulemaking to implement SB2, but cautions that it needs at least two years to adopt final rules.

Significantly, SB2 authorizes the utilities to procure “Tradable Re-newable Energy Credits” (TRECs) to satisfy part of their RPS purchase requirements. In the traditional “bundled” RPS transaction, the gen-erator sells both the physical power and associated RECs in one inte-grated transaction; recognition of TRECs allows the RPS generator to sell the physical generation to one buyer and separately convey the REC associated with the generation to a second purchaser. Proponents promise authorization of TRECs will add flexibility, reduce transaction costs, increase supply, and thus reduce RPS compliance costs.

However, SB2 purposely limits a utility’s TREC purchases to no more than 10% of its total RPS MWh. It establishes a “Bucket” prior-ity for different RPS products and accords TREC purchases the low-est-priority Bucket 3 (subject to the 10% cap). In contrast, bundled transactions are awarded “Bucket 1” priority, and are thus guaranteed a minimum of 75% of the RPS market and are eligible to fill the util-ity’s entire RPS obligation (negating any TREC transactions).

SB2’s Discrimination Harms Western Energy DevelopmentSB2’s relegation of TRECs to Bucket 3 effectuates an almost identical restriction on out-of-state RPS generation. With respect to almost every possible commercially viable transaction, SB2 dictates that out-of-state RPS purchases be subject the 10% TREC limitation. The

net effect is that California utilities must satisfy their RPS obligations with only the smallest amount of non-California generation.

California’s xenophobia against out-of-state RPS resources has been criticized and faces likely judicial challenge. Former Governor Arnold Schwarzenegger (R) vetoed similar legislation adopting a 33% RPS target, finding it would restrict the “importation of cost-effective renewable energy from other states.” Opponents have asserted that the discrimination against out-of-state RPS generation violates the Commerce Clause in the U.S. Constitution.

Moreover, the policy bias against out-of-state generators is misdirect-ed. California has a legitimate interest in promoting the development of new in-state RPS generation. However, SB2’s near prohibition against out-of-state RPS generation will not add 1 MW of new RPS capacity within California. The simple realities are: California cannot satisfy its physical power or RPS requirements solely with in-state generation, and restricting purchases of out-of-state power will not streamline the per-mitting and construction of RPS projects within California.

Similarly, Governor Brown’s goal to increase green investment and employment does not necessitate SB2’s discrimination against out-of-state RPS generation. The market for commercially viable green technology developed in California is not limited by state bound-aries. California projects offer temporary employment gains during construction; however, SB2’s premise that state-of-the-art solar or wind projects equate to “tens of thousands” of permanent Califor-nia jobs is anachronistic, reminiscent of staffing for fossil-fuel or nuclear projects from the last century (and Governor Brown’s first tenure). Moreover, “green technology” employment is not dependent on geographic proximity with the generating facility. Professionals employing computer technology in Silicon Valley can optimize the performance of wind turbines in Montana to most cost-effectively generate RPS power.

SB2 is symptomatic of California’s misguided energy objectives. The promise that SB2 will promote California “energy independence” (whatever that may mean) is disingenuous. California is not, has not been, and can never be an “energy island unto itself.” Insulating in-state producers from out-of-state competitors has never benefited California consumers and will not lead to “prices dropping.”

Political gimmickry, such as SB2, is unnecessary to ensure that California retains its RPS “leadership.” The policy preferences of its citizens, combined with the enormity of its electric load, make Cali-fornia a natural leader. Importantly, RPS leadership is not only a ben-efit; it also imposes responsibility. Governor Schwarzenegger got it right! California’s RPS and other energy initiatives must be directed at and be consistent with “a regional effort that optimizes [RPS and other energy] resources throughout the West at a lower cost to” elec-tric consumers. ■

—Steven F. Greenwald ([email protected]) and Jeffrey P. Gray ([email protected]) are partners in Davis Wright Tremaine’s

Energy Practices Group. Davis Wright Tremaine represents both California and out-of-state generators who desire

to sell RPS power to California utilities.

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SymphonyTM Plus is the new generation of ABB’s total plant automation for the power and water industries. Designed to maximize plant efficiency and reliability through automation, integration and optimization of the entire plant, Symphony Plus offers a simple, scalable, seamless and secure solution. Tune to Symphony Plus and experience the power of a well-orchestrated performance. www.abb.com/powergeneration

ABB Ltd.Business Unit Power GenerationP.O. Box 81318050 Zurich, SwitzerlandTel. +41 (0) 43 317 5380

Symphony Plus Total Plant Automation. The power of a well-orchestrated performance.

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FUELS

Using Fossil-Fueled Generation to Accelerate the Deployment of RenewablesIt may seem counterintuitive, but the strategic coupling of simple- and combined- cycle technologies with renewable generation could establish the conditions neces-sary for adding more renewable megawatts to transmission grids around the world. By Dr. Justin Zachary, Bechtel Power Corp.

A lthough many nations and most U.S. states have goals for increasing the percentage of electricity generated by

renewable energy, meeting those goals means facing several challenges. In particular, the variable nature of wind and solar power cre-ates difficulties for grid stability, especially as the percentage of variable power increas-es. The large penetration of wind power in some parts of the U.S., for example, affects the existing grid in terms of system capacity, harmonics, safety, and protection.

Fortunately, two separate but related tech-nologies are already being developed and deployed to help resolve these problems: a “smart grid” and fast-start gas-fired genera-tion. The use of these technologies could fa-cilitate the deployment of more renewable generation and help states and countries meet their renewable portfolio goals.

However, questions remain. How will new generation assets influence the back-up power demand and its daily profile? How well will the design of the new conven-tional plants currently at the planning stage

in the U.S. (mostly combined-cycle plants) cope with rapid changes in demand due to the ever-increasing penetration of renew-able power? [Editor’s note: For more on this issu, see the top story in this issue’s Global Monitor.] Will anticipated CO2 capture and sequestration legislation require these facili-ties to develop higher efficiency and reduce their carbon footprint? Will smart grid initia-tives change the way gas turbine loading is done? This article attempts to answer these questions and offer solutions for integrating renewable sources with conventional fossil-fueled plants.

Currently, all of the major equipment suppliers are offering solutions for these problems based on their specific gas turbine technologies and capabilities. However, contradictory requirements for maintaining high efficiency and emissions at part load, uncertainty about CO2 capture legislation, and difficulties in financing projects that employ innovative solutions make the pro-cess complex and highly challenging—not only for original equipment manufacturers

(OEMs), but also for project developers and engineering, procurement, and construction contractors.

What the Grid Wants—and What It GetsElectric utilities and grid operators would like renewable energy sources to behave as conventional, dispatchable power plants. For example, they would like to see a constant level of voltage from wind and solar plants. But wind farms and solar power plants re-quire reactive compensation. In fact, rigor-ous reactive compensation standards are likely to become a reality for renewable energy power plants in North America, Eu-rope, and Asia. An example is the recent “Interconnection Standards Initiative Draft Straw Proposal” set forth by the California Independent System Operator in the spring of 2010.

Meanwhile, solar power plants are be-ing asked to meet power factor constraints, provide voltage control, and follow low- and high-voltage ride-through requirements. Re-

Xcel Energy’s coal-fired Cameo Station in southern Colorado ran a pilot program from July 2010 to Dec. 2010 that integrated concentrating solar generation until the Cameo plant was retired at the end of 2010. A parabolic trough solar field provided thermal energy to produce supplemental steam for power generation in order to decrease overall coal consumption, reduce emissions, improve plant efficiency, and test the commercial viability of concentrating solar integration. Courtesy: Xcel Energy

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FUELS


newable energy power plants, particularly solar plants, also must be able to provide day-to-day voltage support to maintain smooth and stable system voltages, even if the plant’s power output varies due to clouds, insuffi-cient wind speed, or other factors during the course of the day.

It is imperative that renewable sources remain connected to the grid when they are most needed, particularly during power sys-tem disturbances, to help the grid recover.

Wind Power Variability. Because wind resources shift suddenly and dramatically, wind farms do not operate all the time; there-fore, additional capacity is needed when they

are not producing power, and differences be-tween forecast and actual production have to be balanced.

Balancing and backup come at a cost, as does building new transmission infrastruc-ture. These facts apply to wind energy just as they apply to other power-producing tech-nologies that are integrated into electricity grids.

And although a wind turbine’s output is more variable and less predictable than that of conventional generation technologies, from a system operations perspective, the output of a single wind farm is just as irrelevant as the demand of a single consumer. The real chal-

lenge is matching the simultaneous collective demand of all customers with the entire avail-able production from all sources. That has been the guiding principle of grid operation since its inception and will remain so regard-less of which technologies are used.

That said, wind power is different from other power technologies, and integrating large amounts of it into the existing power system is a challenge. Here are some of the reasons:

■ According to the Electric Reliability Council of Texas, less than 10% of total wind capacity is counted as being “avail-able” during peak summer days.

■ The PJM Interconnection regional trans-mission organization credits wind with about 13% capacity factor during peak pe-riods. PJM coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia.

■ Midwest ISO operators curtail thousands of megawatts of wind daily; 1,800-MW swings over hourly periods are common.

Without energy storage or fossil-fuel back-up, integrating large quantities of wind power is difficult. Figure 1 provides one example of the discrepancies between wind power gen-eration and demand.

Solar Power Variability. Figure 2 pres-ents a dramatic illustration of the intermittent nature of solar photovoltaic (PV) power. It is important to evaluate not only the rate of change in generation, but also its magnitude. In seconds, the system can go from full out-put to 20% output and back again. At higher levels of PV penetration, such variability will significantly affect grid operation and power factor.

For direct electrical power generation re-newable technologies such as wind and solar PV, there is no way at present to match grid demand. Though some forms of energy stor-age exist for solar thermal (molten salt is one example), only conventional fossil-fueled generation systems can cover the gap for other solar and wind generation.

The remainder of this article looks at tech-nologies for bridging that gap and the design and operation considerations they raise.

The Smart Grid Part of the Solution A smart grid differs from a conventional grid in that it is able to apply digital control to electricity supply and demand. A smart grid uses the analysis of vast amounts of data plus two-way digital communication to optimize the delivery of electricity from suppliers to consumers and, in some cases, to control de-mand at consumers’ homes or businesses. The ability to remotely fine-tune power generation

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1. Mismatch. In this example from grid operator PJM, during peak load demand, wind pro-duction is close to its minimum. The economic impact is evident in the graph on the right, which shows that the premium price for power occurs when wind production is lower. Source: PJM

2. Sun and shade. This chart shows a five-day period in the summer for several locations across Texas, a span that includes clear periods and periods with intermitten sunshine. Night hours have been omitted. Hourly data is from Aug. 10 through Aug. 15, 2005 and was derived from the 1991–2005 National Solar Radiation Data Base. El Paso data has been adjusted from its local Mountain time zone to coincide temporarily with the Central time zone. Source: Texas State Energy Conservation Office

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FUELS


and delivery can save energy, reduce costs, and increase reliability and transparency.

A smart grid is made possible by sensing, measurement, and control devices equipped

with two-way communications capability that are applied to electricity production, trans-mission, distribution, and consumption parts of the power grid. Information about grid

conditions is communicated to system users, operators, and automated devices, making it possible to dynamically respond to changes in grid condition. For example, automated de-mand-side management programs can allow system operators to reduce electricity demand during periods of low renewable plant out-put that would otherwise result in an overall shortage of power on the grid. (To learn more about the smart grid, use the Smart Grid tab at the top of the POWER home page at www .powermag.com to view previous articles on the subject.)

A fully developed smart grid includes an intelligent monitoring system that keeps track of all electricity flowing in the system. It is also capable of better integrating con-ventional and renewable sources of power generation, such as solar and wind. When combined with emerging technologies that are improving the ability of renewable power generators and system operators to predict more accurately, in smaller time increments, the output of wind and solar plants, a smart grid can maximize the benefit of these re-sources.

As regional and national grids incorporate smart technologies, the grid’s new capabili-ties will affect the behavior of simple-cycle

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3. Solar backup. This scenario from a DOE study shows that as solar photovoltaic genera-tion accounts for an increasing percentage of total generation, the need for spinning reserve or storage also increases. Source: DOE

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FUELS


and combined-cycle plants. In combination with larger quantities of renewable genera-tion, the requirements for gas turbines will certainly change:

■ The tendency will be to move toward smaller and dispersed plants.

■ The type and frequency of cycling opera-tion will be significantly different than is seen today.

■ More-frequent cycling will affect compo-nent life and plant efficiency and will re-sult in much more stringent environmental emissions at part-load operation.

■ A significant reduction in peak load should occur due to better grid management and intermittent renewables, while some base-load resources will see an increase in the percentage of their utilization share.

The Gas-Plus-Renewables OptionAs wind and PV capacity increases, these renewable sources are used to meet inter-mediate and peaking loads. However, during periods when PV or wind generation output is low, additional backup power is needed to ensure that the grid demand is met. Figure 3 illustrates the need for spinning reserves or storage. In the absence of large electrical, thermal, or pumped storage options, provid-ing backup power and maintaining spinning reserve will be a major role of fast-starting and rapid-loading gas turbines.

Gas turbines are particularly well-suited to operate in conjunction with wind and PV sources (see sidebar). Their well-known fast-start and fast-ramping capabilities are better

able to meet rapid changes in grid require-ments than coal, steam, or nuclear plants. Consequently, until alternative solutions are widely available, there is a real need for man-ufacturers to adapt gas turbines specifically to compensate for renewable power variability. Grid codes and customers are continuously demanding more operational flexibility, fast-er starts, and accelerated loading response times.

As a rule of thumb, for each installed 400 MW of wind power, 100 MW of gas-fired backup power is required. Hence, the requirement that gas-fired generation sup-port renewable generation is driving modern power plant design to strongly focus on op-erational flexibility.

When compared with a continuous base-load regime, gas turbine operation over wide power ranges not only increases fuel consumption but also impacts NOx and CO emissions. The inability to achieve premix combustion operation at low power levels makes this particular requirement difficult to meet.

The good news, according to a Brattle Group study, is that a wind-plus–gas turbine plant could achieve at least 75% reduction of the maximum possible CO2 emissions. It is obvious that emissions-free power from wind generation is compensating for some of the conventional fossil-generated power.

The bad news is that the economics of gas turbine operation under these conditions are different than for a conventional standalone gas plant. All parties involved in determin-ing the price of electricity must account for

increased costs incurred by the gas turbine power generators. Forcing these facilities to operate at less than full capacity reduces their revenue stream. Cycling operation also af-fects maintenance schedules and gas turbine availability.

In response to these diverse requirements, OEMs have developed both heavy-duty and aero-derivative gas turbines with greater ca-pability to support a wide range of operational flexibility enhancements, enabling custom-ers to effectively use equipment for peak and cycling applications. The relative ease and speed of installing gas-fired generation also gives it an advantage when it comes to meet-ing emergent and urgent power demand.

Some features of OEMs’ solutions to the new demands on gas technologies are exam-ined below.

Simple-Cycle DevelopmentsAll major manufacturers have realized the importance of fast start-up and rapid loading for gas turbines in simple-cycle operation, particularly for installations designed for cycling operation. Current gas turbines can ramp at the rate of 3% per minute (though their efficient operating range is narrow), which is a much higher rate than that of pulverized coal plants. The coal-fired steam cycle exhibits substantial power losses each time a steam turbine is shut down or restart-ed. Major ramp-downs in under 15 minutes may require wasting (venting) the steam, and major ramp-ups in less than 15 minutes may be impossible.

Here is a short list of published features

Combining Gas and PhotovoltaicsSempra Generation’s El Dorado Energy plant has merged two gen-eration technologies that are flourishing together in the desert south of Las Vegas. Sempra Generation, the unregulated power plant–operating subsidiary of Sempra Energy, sells the output from the 480-MW gas-fired combined-cycle plant into the South-west power markets.

In 2009, it added ten 1-MW thin-film photovoltaic (PV) power modules arranged on 80 acres adjacent to the plant. The combined PV power is then connected with the main electrical bus of the combined-cycle plant to simplify interconnection with the grid (Figure 4).

The staff of the gas-fired plant have been cross-trained in PV plant operation and maintenance to reduce operating costs and to improve overall plant reliability. A single technician is responsible for managing the PV side of the plant. First Solar, designer and supplier of the PV modules, provides remote monitoring and main-tenance as part of the ongoing support contract.

For more information on this unique hybrid plant, see “El Dora-do Energy’s Solar Facility, Boulder City, Nevada,” December 2009, in the POWER archives at www.powermag.com.

4. Side by side. A photovoltaic installation shares a grid con-nection and real estate with the combined-cycle El Dorado Energy plant. Source: POWER


FUELS


of gas turbines in simple-cycle operation that demonstrate this technology’s attrac-tiveness for supporting variable renewable generation:

■ GE has a 100-MW gas turbine (LMS 100) capable of a 10-minute start for lower-megawatt applications and a recently an-nounced GE-7FA.05 gas turbine, also with 10-minute start-up capabilities. Similar start-up and ramping features are offered by Siemens and Mitsubishi Heavy Indus-tries (MHI).

■ Due to a unique sequential combustion design, Alstom turbines’ efficiency at part load is higher than others. The same ca-pability of shutting off one combustor at part-load operation offers an additional advantage for operating in this manner: continuous operation at close to 30% of baseload while remaining in compliance with baseload emissions levels.

■ An alternative to frame gas turbines are the aero-derivatives. One of the own-ers of large wind farms (Westar Energy) uses GE’s LM6000 gas turbines to meet demand for peak load and to cover for shortfalls in wind farm generation. The LM6000 can reach its full load output from cold start in less than 10 minutes and operate for 1 hour or less. When a number of LM6000 gas turbines are on standby, they can be dispatched immediately and are able to respond to situations when high-speed and wide-ranging wind fronts are cutting wind turbines’ production by hundreds of MW.

Combined-Cycle Developments The real challenge for the industry is to de-velop capabilities for fast start-up and rapid loading of equipment without affecting its availability and reliability. Cycling operation must be performed without increasing the number of equivalent operating hours or ac-celerating the maintenance schedule. To that end, here are some of the actions initiated by OEMs:

■ Use high-starting-reliability systems for the gas turbine and balance of plant.

■ Implement complex control systems ca-pable of providing adequate ramp rates for each specific state of the hardware.

■ Employ a high degree of start-up automa-tion for both gas and steam turbine.

■ Implement measures aimed at heat re-tention during shutdowns, such as stack dampers and the use of auxiliary steam.

■ Provide sophisticated monitoring systems for major equipment conditions, allowing operators to evaluate the impact of ac-celerated start-up or cycling operation on

component life. ■ Allow the gas turbine to rapidly ramp

without the constraints of the heat-recov-ery steam generator (HRSG) and steam turbine.

Heat-Recovery Steam Generator. It should be remembered that for CCs, the element requiring the most time to reach baseload is not necessarily the gas turbine. For HRSGs, the most appropriate solution to accelerate the start-up process is the use of the Benson-type high-pressure (HP) cir-cuit. Following are some of the well-known mechanisms affecting the performance and integrity of the HRSG components in cycling operation:

■ Low cycle fatigue ■ Creep ■ Thermal shock ■ Oxidation and exfoliation ■ Differential expansion ■ Corrosion fatigue ■ Corrosion in tubes ■ Flow-accelerated corrosion (FAC)■ Corrosion product migration ■ Deposits ■ Erosion

All components in an HRSG are subject to the operating-life-affecting mechanisms list-ed above. However, some components may be more vulnerable because of their location, construction, or exposure. Critical compo-nents in an HRSG generally include these:

■ Superheater and reheater outlets■ Tube-to-header joints in hot sections■ Drum to downcomer nozzle in HP drum■ Bent portion of the heat transfer tubes■ Attemperators■ Bypass valves

These need to be designed and monitored more closely for any kind of life-affecting con-ditions. Solutions offered by OEMs include:

■ Designing hot section outlets to minimize side-to-side variation.

■ Using full-penetration welds, generating a joint with longer fatigue life.

■ Limiting the use of dissimilar materials. ■ Designing an adequate draining system

aimed at reducing quenching effect. ■ Employing various methods to keep the

drums warm during shutdowns.■ Equipping the stack with a stack damper.■ Using special alloys to mitigate the expo-

sure of critical components to FAC. ■ Including special features such cascading

bypass to minimize thermal shock during start-up.

Steam Turbine. Design and operability improvements in steam turbines in CC op-eration have allowed overall start-up and turbine rolling to baseload in record times. As mentioned above, new and complex control features and stress measurements for steam turbines permit CCs to respond much faster than before, particularly during hot starts and load-following mode. Without appropriate flexibility for the start-up times of steam turbines, the viability of CC as a power-controlling element for renewables will be significantly reduced.

It should be noted that the most logical solution for this type of application is a 1 x 1 (one gas turbine, one HRSG, one steam turbine generator) arrangement. Other con-figurations (2 x 1 and 3 x 1) will require larger turbines with a longer start-up time. A modern G or H class gas turbine in a 3 x 1 CC configuration might require a 400-MW to 500-MW steam turbine and therefore be more suitable for baseload operation.

Considering these constraints, the pre-ferred configuration of CCs for renewable back-up power must be selected as a result of detailed feasibility studies combining the start-up curves of all CC components and their control systems.

Integrating Solar and Fossil GenerationAn additional role that a CC can play in the deployment of renewable power, specifically solar thermal, is to accept the steam produced by a solar thermal source into its steam cycle. This arrangement is called integrated solar combined cycle (ISCC). By including an ad-ditional source of heat, such as solar energy, the efficiency of the system is dramatically increased. Annual electricity production is increased because the steam turbine is al-ready in operation, avoiding lost time for start-up. During solar operation, the steam

Technology type Working fluid Maximum temperature

Tower direct steam Steam 550C (1,022F)

Tower molten salt Mixture of salts 575C (1,067F)

Trough Synthetic oil HTF 395C (743F)

Linear Fresnel Steam 270C (518F) or higher

Table 1. Summary of concentrated solar technologies. Source: Bechtel Power


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produced by the solar heat source offsets the loss of power typical for a CC when the am-bient temperature is higher.

Hybrids involving conventional coal-fired plants are also possible in regions with reasonably good solar conditions, as was the case for Xcel Energy’s Cameo Generating Station in southern Colorado, pictured at the top of this article. For these plants, where the steam pressures and temperatures are higher than for ISCC, the type of solar conversion technology used (linear Fresnel, parabolic trough, or tow-er) will dictate how solar is integrated into the plant. Table 1 summarizes the types of technology and their thermal output.

When planning to integrate steam gen-erated by solar energy into a CC, several questions must be answered. What solar technology should be used? How much so-lar energy should be integrated into the CC? Where is the best place in the steam cycle to inject the solar-generated steam? Unfortu-nately, there are no simple answers to these

questions. A detailed economic analysis must be performed to determine the levelized cost of electricity for the specific site under con-sideration. This analysis must look at differ-ent MW thermal solar inputs to the CC and different solar technologies that generate dif-fering steam conditions.

How to integrate steam generated by a solar technology obviously depends in large part on the steam conditions that can be generated by that technology. One must remember that all power generated in the steam cycle of a CC is “free” from a fuel perspective. In other words, steam cycle power is generated without burning any ad-ditional fuel (all steam cycle power is gen-erated based on the energy provided in the gas turbine exhaust gases). Thus, one must be careful to not just substitute the free en-ergy from solar power for the free energy in the gas turbine exhaust gases. When integrating solar into the steam cycle of a CC, it is important to try to maximize the use of both sources of free energy.

Next we look at how various solar technol-ogies can be integrated into CC power plants. Because technologies are evolving and im-proving, each technology has been catego-rized based on fluid temperature capability: High temperature is >500C/>932F); medium temperature is 400C/752F; low temperature is 250C–300C/482F–572F. Medium-temper-ature technology is presented first, as it is the most proven technology.

Medium-Temperature Solar Technol-ogy. The most common medium-tempera-ture solar technology is the parabolic trough. Studies have indicated that, for parabolic trough systems that can generate steam up to ~380C, it is best to generate saturated high-pressure (HP) steam to mix with the saturated steam generated in the HRSG HP drum. In-tegrating HP saturated steam into an HRSG is very common in integrated gasification combined-cycle plants.

Solar thermal input to an ISCC can also be used to reduce the plant’s fuel consump-tion. Reducing gas turbine fuel consump-tion also reduces gas turbine power and exhaust energy. For the same plant net out-put with 100 MWth of solar energy input, plant fuel consumption is reduced by ~8%.

High-Temperature Solar Technology. Solar tower systems can generate superheat-ed steam at high pressure and up to 545C. These conditions allow admission of solar-generated superheated steam directly into the HP steam line to the steam turbine. In addi-tion, steam can be reheated in the power tow-er much as it is in the HRSG. This minimizes impact on the HRSG, because superheating and reheating of solar steam take place in the solar boiler.

Low-Temperature Solar Technology. Most linear Fresnel systems fall into this category. These systems generate saturated steam at up to 270C/55 bar (518F/800 psia). (More recently, the technology has been en-hanced to reach higher temperatures.) This pressure is too low to allow integration of the steam cycle into the HP system. Basically, two options exist:

■ Generate saturated steam at ~30 bar (435 psia) and admit to the cold reheat line.

■ Generate steam at ~5 bar (73 psia) and admit to the low-pressure steam admis-sion line.

As with the other solar systems, taking the feedwater supply from the optimum location in the steam cycle is of great importance to maximizing system efficiency. At the same time, low-temperature systems allow less flexibility in selecting the feedwater takeoff point, because the takeoff temperature must be below the saturation temperature of the steam being generated.

Pairing FuelsAn increasing number of states and countries mandate that a portion of new generation must be renewable. In the absence of ade-quate storage solutions, the energy generated by wind or solar typically has to be absorbed into the grid regardless of load demand.

Predicting the output of renewable gen-eration in time to allow grid operators to adjust to sudden losses of many megawatts could be a daunting task—at least until a fully functional smart grid is in place. An-other way to compensate for shortfalls in power and maintain grid stability is to use gas turbines in simple- or combined-cycle operation.

OEMs have introduced many creative so-lutions to allow fast start-up and operation at part load without affecting equipment avail-ability and reliability. Large frame industrial turbines and, in particular, aero-derivatives—with their rapid output rate increase—are suitable options for maintaining grid sta-bility and meeting customer demands for power. ISCC also offers a solution in that the steam output of solar thermal plants could be combined with that of conventional gas-fired units, typically resulting in lower fuel consumption and lower capital costs than a standalone solar plant.

As the renewable power generation port-folio continues to grow, so too will the role of the gas turbine industry. ■

—Dr. Justin Zachary (jzachary@bechtel .com) is a POWER contributing editor,

technology manager for Bechtel Power Corp., and a Bechtel and ASME fellow.

Controls and Transient Behavior in Hybrid PlantsAs noted earlier, any contractor involved in the design of large cogeneration plants will understand how to deal with complex integration and control issues. However, cogeneration plants are not usually faced with the degree of vari-ability that comes with the integration of solar technology.

Due to the variability of the steam conditions from the solar source, any hybrid configuration needs to be evalu-ated to assess the impact of changes in steam supply on the behavior of the conventional generation facility. There-fore, the transient behavior of the entire system, including the solar steam source and power plant, should be modeled in the early plant design stage.

The complex issues associated with proper transient representation of dif-ferent types of equipment and their controls must be developed using com-puter simulation programs. The aim of such studies is to create a representative transient, integrated system capable of predicting steam temperature and pres-sure variations during steady-state and transient conditions. Finally, the com-plete system has to be optimized based on not only operational considerations, but also cost.

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CLEAN COAL TECHNOLOGY

Underground Coal Gasification: Another Clean Coal OptionUnderground coal gasification (UCG) is the gasification of coal in-situ, which

involves drilling boreholes into the coal and injecting water/air or water/oxygen mixtures. It combines an extraction process and a conversion process into one step, producing a high-quality, affordable synthetic gas, which can be used for power generation. Still in the early stage of com-mercialization, UCG is poised to become a future major contributor to the energy mix in countries around the world.

By Angela Neville, JD

Coal gasification is a well-known chemical process that converts solid carbonaceous material into synthetic

gas (syngas), which consists predomi-nantly of methane (CH4), carbon monox-ide (CO), carbon dioxide (CO2), hydrogen (H2), and water (H2O) steam. Gasification differs from combustion (or burning) be-cause burning coal takes place in excess O2 and produces only CO2 and water steam.

In the underground coal gasification (UCG) application, air and/or oxygen is in-troduced to coal while it is still in the ground by pumping it down boreholes (called injec-tion wells), which are drilled into the coal seam from the ground surface (Figure 1).

Rohan Courtney, chairman of the trust-ees of the UCG Association (UCGA, www .ucgp.com) and also chairman of Clean Coal Ltd., told POWER in May about the UCG process. He explained that once syn-gas is formed in the coal seam, the syngas then flows back to the surface under pres-sure via a second borehole (the production well), which is linked through the coal seam to the injection well (Figure 2). A linked injection well and production well is called a UCG “module,” which is the cornerstone of UCG.

“In many ways, it is the relatively re-cent perfection of drilling and methods for linking the injection and production wells that has led to the huge resurgence of in-terest in UCG that we are now witnessing across the globe,” he said. (See sidebar, “Coal Gasification Pilot Projects.”)

Two UCG Methods The two main methods used to carry out UCG are often referred to generically as the linked vertical well (LVW) method and the controlled retractable injection point (CRIP) method. Both of these meth-ods rely on a module of at least two linked

boreholes to inject the oxidant and remove the syngas.

The LVW method uses vertically drilled wells to access the coal seam and dif-ferent techniques to link the boreholes. In contrast, the CRIP method relies on a combination of conventional drilling and directional drilling to access the coal seam and physically form the link between the injection and production wells.

Evidence from previous and current tri-als suggests that the two basic methods are generally suited to exploit different coal resources. LVW methods are more suited to shallow coals seams, and CRIP methods are more suitable for deeper coal seams.

There is a fairly equal distribution of

1. Making coal cleaner. The under-ground gasification of steeply dipping coal seams was demonstrated in a pilot project near Rawlins, Wyo. In the underground coal gasification process, air and/or oxygen is introduced to the coal while it is still in the ground by pumping it down boreholes (called injection wells), which are drilled into the coal seam from the ground surface. Courtesy: Paul Ahner

2. Surfacing. After syngas is formed in the coal seam, it then flows back to the surface un-der pressure via a second borehole (the production well), which is linked through the coal seam to the injection well. Courtesy: Marc Mostarde

08_PWR_070111_SR_Gasification_pp36-43.indd 36 6/16/11 2:01:00 PM



methods employed on modern UCG proj-ects around the world.

However, Courtney pointed out that “on balance, it’s fair to say that the LVW method is currently used more.” It is used in projects in Uzbekistan, South Africa, China, and New Zealand. On the other hand, the company Carbon Energy uses the parallel CRIP method in Australia; Swan Hills in Canada is using the lin-ear CRIP method; and Linc Energy has experimented with most of the available techniques.

“As long as the techniques are deployed in properly selected sites (site selection is fundamentally important for UCG) and op-erated correctly, there are no major techni-cal challenges to these techniques used for UCG,” he said. “Much of the work nowa-days is in refining the techniques to in-crease efficiency and reduce costs, rather than in overcoming major technical chal-lenges.”

UCG plants can produce syngas by ex-ploiting coal resources located both onshore and offshore (Figures 3 and 4).

The Linked Vertical Well MethodThe LVW method uses reverse combustion (RC): The coal is ignited from one of the vertical wells and air/oxygen is introduced into the coal from the other well. The com-bustion front then moves toward the air/oxygen, forming linkages between the wells by progressively consuming small amounts of coal and forming tube-like channels as it goes. Once the linkage is established, for-ward combustion (where the combustion front moves in the same direction as the injected air/oxygen toward the production well) is used to gasify the coal.

“An advantage of the RC-LVW method is that it is relatively inexpensive, as no ex-pensive directional drilling is required to link the wells,” Courtney said.

It is also possible with RC-LVW to use greater-diameter injection and production wells than with the CRIP methods because no deviated in-seam drilling (where large borehole diameters are a disadvantage) is required. This means that greater syngas flow rates could be achieved using RC-LVW than with CRIP at shallow depths (<300 meters or 984 feet).

A disadvantage of the RC-LVW meth-od is that, because it relies on the natural permeability of coals, it is not particu-larly well suited to low-permeability coal, or deeper coal seams (>300 meters [m]), which tend to be under great pressure and consequently have reduced permeability, according to Courtney. The reliance on natural permeability may also force the

linkage to take unpredictable paths, as the linkage will likely follow preexisting frac-tures or paths of low permeability. Fur-thermore, it is more difficult to ensure that the linkage in the coal seam is maintained as close as possible to the base of the seam using this method.

“This is important because early UCG trials using the RC-LVW method showed strong evidence that maintaining the in-jection point at a low position in the coal seam is essential for obtaining good syn-gas quality and high mining/gasification efficiency,” he said.

3. Hitting pay dirt. This diagram illustrates the controlled retractable injection point (CRIP) method being used to access a coal seam onshore. The CRIP method relies on a combination of conventional drilling and directional drilling to access the coal seam and physically form the link between the injection and production wells. Source: UCG Association

4. Going to the ocean depths. UCG plants can also be constructed with injection and production wells that can access coal seams located offshore. Source: UCG Association

Air separation plant

Low air emissions Electricity generation

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Production well CO2, H2, CH4

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The Controlled Retractable Injection Point MethodThe modern CRIP techniques use a combi-nation of conventional and directional drill-ing techniques to drill and complete both the injection and production wells, Courtney pointed out. The vertical section of the CRIP module injection well is drilled to a predeter-mined depth, after which directional drilling is used to deviate the hole and drill along, and at bottom of, the coal seam.

“With the CRIP technique, the location of the injection point can be precisely controlled and retracted back along the bottom of the coal seam,” he noted. “This is of benefit be-cause it allows for fresh coal to be accessed each time the syngas quality drops as a result of cavity maturation.”

The main difference between the linear and parallel CRIP methods is in the produc-tion well design:

■ The linear CRIP concept uses a vertical production well located at least 500 m from the deviated injection well. The in-

seam section of the injection well is drilled such that it intersects the production well.

■ The parallel CRIP method uses a devi-ated in-seam production well drilled parallel to the injection well with an in-terwell spacing of around 30 m. The two wells are deviated at a predetermined in-seam length toward a third vertically drilled ignition well, which is used to initiate gasification.

Gasification efficiency drops as the UCG reactor grows because more and more of the barren roof rock is exposed, which conducts heat away from the reactor and impacts syngas quality, Courtney said. The CRIP method allows for the injection point to be retracted back within the coal seam when the efficiency drops.

“The large spacing between the injection and production wells also means that fewer boreholes are required to gasify a certain volume of coal, and so the CRIP methods have a smaller surface impact than LVW methods,” he said.

Furthermore, as the CRIP methods do not rely on natural coal permeability to create the linkage, this method can be used at great depths (1,400 m deep has been achieved at the Swan Hills project in Alberta, Canada), significantly increasing the resource base for UCG around the world.

Syngas Cost ComparisonThe cost of producing syngas on a per unit energy basis is very closely linked to a num-ber of key variables, and so it is not really possible to give one overall figure appropriate for all UCG projects, Courtney explained.

One of the most important variables is coal seam thickness. This is because the cost of producing syngas is linked closely to the cost of installing a module, and so the more coal a module can gasify, which is a function of coal seam thickness, the lower the costs to produce syngas.

“It is possible to give a rough idea of costs for specific projects, so the UCGA recently produced a price comparison with other energy-producing technologies in re-

Coal Gasification Pilot ProjectsAround the world, there are five notable underground coal gasifi-cation projects in various stages of development that are worth watching.

Linc Energy Ltd.: Chinchilla Pilot Project, Queensland, Australia Linc has had a “demonstration” UCG project at Chinchilla, Queen-sland, Australia since the late 1990s. Syngas was first produced in December 1999, and production continued thereafter for two years. Since then, Linc has developed three additional modules at Chinchilla. Module 3 was commissioned in 2007 in tandem with its gas-to-liquids (GTL) demonstration plant that has successfully produced synthetic fuels. (Peter Bond, Linc’s managing director, recently completed a 6,000-mile journey across Australia in a car fueled by synthetic diesel from Linc’s GTL plant.) Module 3 is now exhausted, but Module 4 is currently producing syngas and is ex-pected to last for another two years.

Linc now owns over 75% of the Uzbek UCG company, Yerostigaz, which has been operating the world’s oldest UCG project at Angren, Uzbekistan. This project has been continuously producing UCG syn-gas for a local electric power station for more than 40 years.

Carbon Energy Ltd.: Bloodwood Creek Project, Queensland, AustraliaIn October 2008, Carbon Energy successfully produced syngas from its unique UCG module based on the parallel controlled retractable injection point (CRIP) method. The trial, which ran for 100 days, reached coal gasification rates of around 150 tons per day and produced a high-quality syngas. Since then, Carbon Energy has installed two more modules and constructed a 5-MW electric power

plant to be fed with syngas from Module 2. Module 1 is being care-fully decommissioned.

Plans for scaling up to 25 MW of electricity generation are under way, and a second project in Queensland, known as the Blue Gum Energy Park, is also in the early stages of planning.

Swan Hills Synfuels: Alberta, CanadaSwan Hills Synfuels recently produced syngas from its pilot proj-ect in Alberta, Canada. This project is the deepest UCG pilot ever undertaken, at a depth of 1,400 meters, and is using the linear controlled retractable injection point method.

ENN Group Co. Ltd.: Inner Mongolia, China The ENN Group Co. Ltd. (a subsidiary of the Xinao company) pro-duced syngas from a pilot project in Walanchabi City, Inner Mongo-lia, China, for 26 months, gasifying more than 100,000 tons of coal. Although not much information has been made available about this project, it is known that there were initially seven injection and production wells, which were first fired in October 2007 using air. ENN is now in its fourth year of operation at the plant.

Eskom: Majuba, South AfricaThe Majuba UCG project has been producing syngas since January 2007 and began delivering UCG syngas to cofire with coal at the Majuba Power Station in late 2010. The project contributes about 3 MW to the overall output of 650 MW from the electric power sta-tion using the linked vertical well method. This project is now the longest running UCG trial in the western world. Plans are in place to expand the facilities to 1,200 MWe output, with 30% of the plant’s fuel provided by syngas.

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Westinghouse supplied the world’s � rst full-scale commercial

nuclear power plant in 1957 in Shippingport, Pennsylvania (USA).

Today, Westinghouse technology is the basis for approximately

one-half of the world’s operating nuclear plants, including 60 percent

of those in the United States. With global pressurized water reactor

(PWR) and boiling water reactor (BWR) technology and expertise,

and skilled employees at locations around the world, we provide

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sponse to a UK government-sponsored re-port entitled ‘UK Electricity Costs Update, June 2010,’” he said.

The UCGA used the same methods to calculate the costs for UCG as those used in the report to ensure a fair comparison (Figure 5). These and other cost estimates, including work by Lawrence Livermore National Laboratory, consistently show UCG to be very competitive with existing mature coal- or gas-fired electricity gen-eration technologies. It is worth pointing out that economics will only improve as UCG develops into a mature industry.

The Impact of Low Natural Gas Prices on UCG Deployment “Historically, low natural gas price is one of the main contributing factors for delaying the commercialization of UCG,” Courtney said. “Nowadays, with the advances made in directional drilling and other technologies, the production of syngas on a calorific value per unit cost basis is much more competi-tive with natural gas, even relatively cheap natural gas.”

“Since the beginning, the UCGA has had a world map detailing all the interest in UCG around the globe,” he said. “We are currently finding that we cannot update it fast enough to keep pace with the projects being under-taken in different countries.”

There are many reasons why UCG is at-tractive to coal-bearing countries:

■ Some countries, such as Poland, rely on coal to produce the vast majority of their power. As the amount of economically minable coal declines, UCG is becoming increasingly attractive.

■ Another key driver for interest in UCG in Europe is energy security concerns, par-ticularly in those countries that rely on

Russia for their natural gas supplies. ■ Other countries, such as China and India,

simply require huge amounts of energy to fuel their economic expansion. As these countries contain vast quantities of coal, much of it unminable, UCG is being de-veloped as part of the energy mix.

“In contrast, we are also seeing interest from energy-rich regions, such as Alberta in Canada. Alberta has huge oil sand reserves

and is not short of energy,” he said. “Alberta also has very large quantities of very deep unminable coal, which is suitable for UCG, so many companies are looking to exploit this valuable resource.”

Obstacles to DeploymentThere are few UCG-specific technical issues that need to be overcome because, in recent years, the technologies have matured to a stage where companies are now moving from pilot stage to a commercial stage, Courtney said. In his opinion, “what we need to see now is more projects moving into the commercial stage to give investors more confidence in the technology and fund more projects.”

“This is closely linked to another chal-lenge we are seeing: There currently is only a handful of people with direct experience

of UCG,” he said. “These people generally reached their professional peak in the last ‘phase’ of UCG development between the 1970s and late 1990s. Therefore, we now need a new generation of UCG experts to de-velop UCG in the 21st century. We are now seeing universities offer UCG modules in their undergraduate degrees as well as UCG-related PhD programs and post-doctorate research, but what we really need is more practical experience of UCG.”

Environmental Challenges The environmental challenges are well understood, as a result of the significant knowledge gained from previous UCG trials. These include groundwater contamination, subsidence, surface contamination, and gas emissions. They can be managed, however, by careful site selection, the correct opera-tion of the UCG module, and by the use of appropriate engineering materials/surface plants, according to Courtney. Safety is also often mentioned as a challenge, although ex-perience is showing that with good process control and operations, safety issues are no different than those in other process indus-tries (see sidebar “UCG Safety Issues”).

Groundwater Contamination. Con-taminants, such as benzene and other hydro-carbons, can be produced during UCG by a natural process called coal pyrolysis. Coal pyrolysis occurs during the breakdown of coal at temperatures less than those required for gasification. During UCG, this will likely happen within the coal at a distance less than 0.5 m from the coal face.

“As UCG takes place below the ground-water level, in a ‘groundwater bubble,’ there is a risk that some of the contaminants could leave the UCG reactor and impact groundwa-ter resources,” Courtney said. “It is possible, however, to stop contaminants from entering the groundwater by ensuring that water only flows into the UCG cavity, because contami-nants will not be transported against the di-rection of flow.”

Selecting the appropriate site for UCG is of fundamental importance, and a correctly sited UCG project would not be located anywhere near an aquifer used to extract

5. A cost-effective option. This cost estimate shows UCG to be competitive with exist-ing mature coal- or natural gas–fired electricity generation technologies. Note that 1.00 Euro = $1.4320 USD, May 2011. For UCG, no payment for the value of coal is included, and the cost of UCG includes the cost of 90-plus% carbon capture and storage. Source: UCG Association

The environmental challenges are well under-stood, as a result of the significant knowledge gained from previous UCG trials.

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Notes: ASC = advanced supercritical, CCGT = combined-cycle gas turbine, CCS = carbon capture and storage, IGCC = integrated gasification combined-cycle, UCG = underground coal gasification.

Renewables Nuclear Clean coal Gas UCG

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water for use. The suitability of a site with respect to assessing risks to aquifers can be determined using a number of existing and well-tested methods, so it is relatively straightforward to avoid high-risk locations in the first place.

Subsidence. Ground subsidence is the propagation of the UCG cavity toward the surface following collapse of the cavity roof rocks. The distance that subsidence can propagate is strongly dependent on cavity size, the depth to the cavity, and the me-chanical properties of the rocks overlying the cavity. Significant surface subsidence has not been observed in all UCG trials; in fact, it is very rare. Site selection is one of the most important factors in managing the risks from subsidence. Coal seam depth is critical, and seams >200 m deep minimize the risks to the surface. It is also necessary to target coal seams with strong, fully con-solidated roof rocks that can resist the ef-fects of subsidence.

The risks of surface subsidence from UCG are analogous to those from conventional mining, and so there are many standard, well-accepted techniques for assessing this risk. The fact that UCG is increasingly car-ried out at depths greater than conventional mining, however, lowers the risk of surface subsidence compared with traditional mining techniques.

Surface Contamination. Risks to the environment from UCG at the surface are es-sentially restricted to how contaminants are handled once they are condensed out with

the water in the syngas. UCG “blackwater” is no different from the wastewater produced during conventional surface coal gasifica-tion. Therefore, technologies that can treat the water are well established and readily available.

Atmospheric Emissions. The emissions from UCG are essentially no different than from any other industrial process using coal, and so existing, tried and tested technolo-gies can be employed to reduce atmospheric emissions. Emissions from a UCG plant are, however, considerably lower than from conventional coal mines, because no coal is brought to the surface, and methane emis-sions (often associated with coal mining) are minimized.

Permitting Issues for UCG Projects in the U.S.It is well within the interests of UCG opera-tors to demonstrate clearly that no impacts to groundwater resources on- or off-site will occur as a result of UCG, Courtney said. Im-pacts to aquifers from any contamination will have serious implications for a project under its environmental permitting regime. For example, a regulator could order a project to stop all UCG activities if it has breached its permitting conditions. Additionally, the UCG operator would likely have to pay the significant costs associated with aquifer re-mediation as well as expose itself to the risk of litigation from adjacent landowners.

All UCG operators are aware of these issues and, consequently, ensure that

numerous monitoring wells are distrib-uted throughout their sites. Maintain-ing groundwater levels is critical for the long-term sustainability of UCG projects. Therefore, many groundwater monitoring wells have to be on UCG sites irrespective of their use for groundwater quality moni-toring. Typically, groundwater monitoring wells are positioned at the site periphery, as well as off-site, whenever feasible. This allows UCG operators to demonstrate that they are not impacting aquifers.

Looking AheadOne of the current hindrances to widespread deployment of UCG around the world is the uncertain regulatory environment in some areas, Courtney said. Countries and regions with existing UCG regulations (or with other existing policies that can be easily adapted to deal with UCG projects) will have an advan-tage over others.

He pointed out that “it is clear that coun-tries such as the UK, China, India, Turkey, U.S. (Wyoming), Australia, and Canada are moving forward with their regulations and stimulating interest in UCG projects.” Those countries with abundant, unminable coal re-serves suitable for UCG and a strong need for affordable energy, such as China and India, will probably undertake widespread deploy-ment of UCG first. Currently, five UCG proj-ects are being carried out in Australia, China, Canada, and South Africa.

“We are at the early stage of commercial-ization of UCG. As more and more projects around the world prove that UCG produces affordable, clean, and efficient energy, the use of UCG in the U.S. will naturally grow both in the short and long term,” he said. “Other factors, such as energy security and carbon emissions, will likely have an impact on the deployment of UCG in the U.S, but probably in the longer term.”

Courtney also emphasized the impact that the successful implementation of carbon capture and sequestration (CCS) could have on UCG’s future development. “In the lon-ger time frame, it is our firm belief that CCS will become commercial, and given UCG’s inherent benefits for carbon capture (CO2 can be captured relatively cheaply from oxygen-fired UCG syngas at high pressure), this trend will see UCG being increasingly exploited in regions such as Europe,” he said.

Rohan Courtney would like to acknowl-edge the contributions of the following peo-ple: Julie Lauder, CEO, UCG Association; Marc Mostade, technical director; Shaun Lavis, senior geoscientist; and Paul Ahner, chief UCG technician, Clean Coal Ltd. ■

—Angela Neville, JD, is POWER’s senior editor.

UCG Safety Issues Underground coal gasification (UCG) is inherently safer than conventional oil and gas or coal exploitation methods. A key safety concern for oil and gas workers is the risk of a blowout during drilling, followed by ignition of the oil and/or gas, causing a fire. As was witnessed in the Gulf of Mexico in 2010, blowouts or well failures during offshore oil and gas drilling can create significant safety issues and have the potential for causing significant environmental impacts.

The risk of a blowout during drilling for UCG is significantly lower than for oil and gas drilling, as the target coal formation is not a pressurized hydrocarbon reservoir. The risks are, therefore, more comparable with coal bed methane drilling. Although it does entail the risk of hitting pockets of pressurized gas, coal methane drilling overall is intrinsically safer than oil and gas drilling.

Compared with coal mining, UCG is also significantly safer. The most obvious reason is that no people are required to work underground. Coal mining, especially in some countries, is an extremely dangerous activity because of the risks of a mine collapsing, or methane leaking into mine galleries. In UCG, all the people are located on the surface in purpose-built facilities that are designed to minimize the risk of harm.

Perhaps the most significant risk in UCG is from syngas leaking from surface pipes. Safety systems, however, such as continuous carbon monoxide monitoring or emergency proce-dures that may include diverting syngas to a flare, help to reduce these risks. As a result, there’s no reason to think that a commercial UCG plant will be less safe than any modern energy or chemical processing plant.

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• In-depth Short Courses• Solution-based Case Studies• Innovative Discussion groups• Hands-on Tutorials• Pioneering Lectures• Outstanding Exhibit Floor

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RENEWABLES

Hydro: The Forgotten Renewable ReboundsWhen President Obama unveiled his “clean energy standard” in the 2011 State

of the Union address in February, and again when he spoke of his admin-istration’s energy policy in late March, one form of electrical energy was conspicuous by its absence: hydropower. Hydro is the forgotten form, the politically incorrect renewable, the invisible generation. To borrow the complaint of comedian and Caddyshack movie star Rodney Dangerfield, hydro projects “don’t get no respect.”

By Kennedy Maize

Hydroelectric power, the oldest form of power on the planet, is a far more sig-nificant source of U.S. electricity than

trendy technologies such as wind, sun, and heat from the Earth—combined. According to Energy Information Administration 2009 figures, hydro (conventional and pumped stor-age) provides 98.5 GW of nameplate gener-ating capacity in the U.S. Wind, solar, wood, geothermal, and other biomass generation ac-count for 51.6 GW of nameplate capacity.

Hydro requires no fossil fuels, emits no air pollution at all (including carbon dioxide), is reliable and dispatchable, works well in base-load or peaking modes, and provides valuable ancillary services such as frequency support. In short, hydro has all the operational char-acteristics of fossil plants but with the values we have come to associate with renewable generation.

But hydro has other attributes not associ-ated with the au courant crowd of renewables. Hydro projects can provide flood control (Figure 1), drinking water, and recreational opportunities. It even can increase property values: Folks often pay a premium to live around hydro impoundments but often take a hit living near wind and solar energy farms.

Hydro power was also the first form of power that environmentalists learned to hate. It gobbles up large chunks of land, alters both land and water ecosystems, kills migratory fish, and presents engineers with safety chal-lenges. John Muir created the Sierra Club to fight hydro in California’s high Sierra Neva-das. Dave Brower made the club famous 50 years later—and got himself fired—opposing hydro in the Grand Canyon (and supporting a nuclear project named Diablo Canyon). In 1988, the group that Brower hatched after his ejection from the Sierra Club—Friends of the Earth—launched a decades-long project to take down existing power dams in the hydro-rich Pacific Northwest.

Hydro Is Heavily RegulatedHistorically, hydro politics and economics often have presaged the trials of nuclear pow-er. Both were largely born of the federal gov-ernment and continue to live by Uncle Sam’s largesse. Both gobble large amounts of capi-tal up front but generate power cheaply once built. Both are heavily regulated by a central, independent federal agency—the U.S. Nu-clear Regulatory Commission for the nukes and the Federal Energy Regulatory Commis-sion (FERC) for water power. Both can suffer catastrophic accidents of low probability but large impact. Both represent enticing targets for terrorist attacks. Hydro, of course, got its baptism in controversy well before nuclear energy arrived on the generating scene.

But there are significant differences be-tween the two generating technologies, pri-marily in scale. Whereas the image of hydro is the large concrete dam, such as the Bureau of Reclamation’s mammoth Hoover Dam on the Nevada/Arizona border, the reality is that small dams and projects predominate. Of the power dams that FERC regulates, more than 70% have a nameplate capacity below 5 MW.

And the scope of federal regulation of hy-dropower is far less extensive than the hold the government has on nuclear generation. FERC only regulates about half of the non-federal U.S. dams that generate power. The biggest, most visible dams tend to be those owned and operated by the federal govern-ment, including the Interior Department’s Bureau of Reclamation (Reclamation), the Army Corps of Engineers, and the Tennes-see Valley Authority (TVA). Of the others, FERC generally approves licenses for proj-ects that are on navigable waterways, are on federal land, or use surplus water from a federal dam.

According to the Oak Ridge National Lab-oratory (ORNL), licensed non-federal hydro

projects today account for 57 GW of capac-ity from 4,370 projects (see sidebar). Federal hydro totals 41.9 GW from 746 projects. The Army Corps has 432 hydropower generating stations with 21.6 GW in capacity; Reclama-tion has 198 projects with 15.1 GW in capac-ity; TVA has 116 hydro worth 5.2 GW.

Although there has been plenty of public attention on the putative nuclear renaissance in recent years—“is it is or is it ain’t”—few think much about hydro these days. Yet water over the dam and through the turbine is stag-

1. Shared services. Hoover Dam, lo-cated on the Colorado River at the border of Arizona and Nevada, is one of more than 600 dams and reservoirs operated by the Bureau of Reclamation, part of the U.S. Department of the Interior. One of the original motives for building the system of dams on the Colo-rado, which flows through seven western states and Mexico, was flood control. The 17 turbines in the Hoover Powerplant are rated at about 2,200 MW. The plant’s generation is shared among Arizona, California, and Nevada. Source: POWER

09_PWR_070111_SR_Hydro_p44-47.indd 44 6/16/11 2:05:21 PM


RENEWABLES

ing its own renaissance of sorts, well below the radar. The hydro rebound appears to be slow and steady, far slower than its champi-ons and developers would wish. But it is real nonetheless.

In 2007, FERC issued 10 hydro licenses, and nine were relicensed existing projects. In 2008, the agency issued 13 relicenses and four new licenses. By 2009, the scales had tilted toward new projects with eight re-licensing decisions and 10 new licenses. In 2010, FERC issued six relicenses and six new licenses.

Since 2008, the agency has issued nearly 400 preliminary permits for potential licens-es, most of them covering small projects.

Preliminary permits are a means of queuing for a license. FERC explains on the licensing section of its website: “A preliminary permit, issued for up to three years, does not autho-rize construction; rather, it maintains prior-ity of application for license (i.e., guaranteed first-to-file status) while the permittee studies the site and prepares to apply for a license.” Some 300 preliminary permit applications are pending at the commission.

FERC’s Jeff Wright, who heads the agency’s office of energy projects, told the Senate Energy and Natural Resources Com-mittee in March, “In recent years, the com-mission has seen a greatly increased interest in small hydropower projects, in innovative

hydrokinetic projects [Ed.: see “New York City Backs Tidal Power,” May 2011 in the POWER archives at www.powermag.com], and in pumped storage projects, particularly closed loop pumped storage, which does not involve regular water withdrawals from riv-ers or other water sources.”

More Pumped Storage NeededThe big, highly visible hydro projects these days are pumped storage projects, which use off-peak electricity to move water uphill so it can flow back down, generating power at periods of higher demand. These projects act like batteries. Though it is difficult and very expensive to store electricity, it is much

Bowersock: Poster Project for Hydro LicensingThe Bowersock Dam has been a feature in Lawrence, Kansas, since 1874, providing power—first mechanical power through leather belts and steel cable, and later electricity—to the sixth-largest city in the state (population about 87,000) and home of the state’s largest institution of higher education, the University of Kansas (“Rock Chalk, Jayhawk!”). Today, it is the poster dam for how a hydropower project with minimal environmental impacts can win quick federal approval, more than doubling its generating capacity in the process.

Bowersock Dam straddles the Kansas (aka “Kaw”) River, provid-ing flood control as well as electricity to the area. With seven turbines generating some 2.3 MW of power, it is the only hydro-power plant in the state. As noted on its website, over its 137 years “the mill has ground grain into flour, produced the first ready-make gingerbread cake mix, hosted a radio station, been a paper mill, made barbed wire, and produced power—both electri-cal and mechanical.” Today, in addition to providing power, the project’s millpond provides recreation to the city and supplies the city with water.

There had long been plans to expand the power-generating ca-pacity of the project. According to Sarah Hill-Nelson, who, with her father Stephen Hill, owns and operates Bowersock, initial plans for the expansion show up in a 1924 Army Corps of Engi-neers blueprint. In 2007, Sarah and Stephen decided to add new generation on the north side of the project, increasing the total capacity by 4.68 MW. Because the new total would exceed 5 MW, Bowersock would have to give up the licensing exemption for its existing generation and pursue a major new Federal Energy Regu-latory Commission (FERC) license under the agency’s “traditional licensing process,” a fairly scary endeavor (Figure 2).

Undaunted, the Bowersock team worked in advance of submit-ting the license with local citizens, environmental groups, city government, state environmental agencies, and the local office of the Army Corps of Engineers, winning support from all for a project that would produce more electricity with no discernible environ-mental impact. The owners also worked closely with FERC staff to be sure they had jumped through all the federal regulatory hoops. Hill-Nelson told the National Hydropower Association meeting this

spring that close community involvement was crucial to the proj-ect. “It was an open book,” she said. “We had nothing to hide.”

Bowersock applied for a FERC preliminary license in October 2009 (Docket P-13256) and submitted the formal license application on Feb. 8, 2010. FERC granted the unopposed license on Aug. 19, 2010. It was a remarkably swift process that took only six months.

License in hand, and also holding a 25-year power purchase agreement with Kansas City’s municipal utility, Bowersock was able to line up the $24 million needed to build the new project. Sarah Hill-Nelson and Stephen Hill closed a deal with the city of Lawrence for $24.215 million in industrial revenue bonds, underwritten by Stern Brothers & Co. The underwriters sold the bonds on March 10 this year, and Bowersock filed a financing plan at FERC on March 15. FERC approved the financing plan on March 18.

When the financing closed, the local newspaper commented, “Many efforts are focused on new ways to generate the power America needs, but it’s also refreshing to see a company like Bow-ersock capitalizing on one of the old standbys.”

2. Run of the river. The Bowersock Mills & Power Co. hydro plant has been in operation since 1874. The plant was recently reli-censed by FERC to a 4.68-MW expansion in a new record time of about five months. The electricity is sold to the Kansas City Board of Public Utilities under a 25-year power purchase agreement. Cour-tesy: Bowersock Mills & Power Co.



RENEWABLES

easier and cheaper to store water and convert it into electricity.

Today, according to ORNL, pumped storage provides 20 GW of U.S. capacity. Forty-one projects are licensed by FERC, six are under review, and one has been pro-posed but is not yet in the regulatory pro-cess. The largest pumped storage project in the U.S. is Virginia’s Bath County station, at 2,772 MW (Figure 3). The project went into service in 1985, at a cost of $1.6 billion, following years of controversy. Because they are large and expensive, pumped stor-age projects often draw local fire, includ-ing opposition to the high-voltage power lines that are part of the package.

The slow but steady return of hydro to the menu of politically, environmentally, and economically respectable generation was on display in April in Washington at the annual meeting of the National Hydro-power Association (NHA). The NHA is the lobbying and trade group for the water-to-watts crowd. What follows is some of the evidence for the return of hydro that emerged from that meeting.

Hydro Is Essential for RPSStates are beginning to look at ways to foster hydro developments in order to meet their re-newable portfolio standards (RPS). The mod-el is Colorado. Last summer the state signed a memorandum of understanding with FERC designed to streamline and speed up licens-ing of projects in that state that present a minimal environmental impact, such as gen-

eration from irrigation conduits, wastewater and industrial outflow, and projects under 5 MW in size.

Colorado in 2010 increased its renewable energy requirement from 20% to 30% by 2020. That goal probably can’t be met with-out new hydro. A study by the DOE’s Idaho National Laboratory found that Colorado has a potential for 1,400 MW of new hydro in projects of less than 5 MW. Under the agree-ment with FERC, the state is developing a pilot project to identify projects that qualify for streamlined federal review.

Colorado’s Francisco Flores told the NHA meeting, “The FERC process has not worked very well historically for small hydro.” Un-der the new deal with FERC, the state is working with the developers, the natural resource agencies, and investors to present a finished package to the federal regulators, short-stopping two steps out of three in the licensing process.

Congress is looking at new hydro legis-lation designed to boost conventional and unconventional waterpower technologies, including traditional terrestrial (S. 629) and new ocean-based approaches (S. 630) to making electricity. Sen. Lisa Murkowski (R-Alaska) told the NHA meeting that for her, as ranking minority member of the Senate Energy and Natural Resources Committee, and chairman Jeff Bingaman (D-N.M.), the bills are high priorities. Whether the rest of the Congress will also view hydro power as a priority is not clear. The Senate committee last year passed a comprehensive energy bill,

with provisions boosting hydro, but it died far short of even getting to the Senate floor.

Murkowski told the group that the energy committee will probably avoid comprehen-sive, kitchen sink legislation this year and in-stead focus on discrete topics, such as hydro. But the Senate committee will also be look-ing over its shoulder at what’s happening in the other arm of Congress, where new spend-ing and ramped up federal programs have far fewer friends. This year, she said, “We are often asking, ‘WWTHD’, what will the House do.”

The executive branch is putting some of its weakening financial muscle behind hydro. On the day of the NHA meeting—the timing was clearly intentional—the DOE and the In-terior Department’s Bureau of Reclamation announced a joint program to put $26.6 mil-lion into funding innovative technologies that can “produce power more efficiently, reduce costs and increase sustainable hydropower generation at sites not previously considered practical.” The funds are aimed at:

■ Small hydropower ($10.5 million award-ed over three years). These projects will research, develop, and test low-head small hydropower technologies that can be quickly and efficiently deployed in existing or constructed waterways. The DOE will fund system or component model development, as well as the test-ing of these systems.

■ Environmental mitigation technology for conventional hydropower ($2.25 million awarded over three years). These proj-ects will develop innovative convention-al hydropower technologies that feature designs to increase electricity genera-tion while mitigating fish and habitat impacts and enhancing downstream wa-ter quality. The agencies are looking for ways to demonstrate turbine efficiencies greater than 90% and fish passage sur-vival greater than 96%.

■ Pumped storage ($11.875 million awarded over four years). The DOE wants to speed up pumped storage hy-dropower projects already in the pipe-line. Projects that begin construction by 2014 and integrate wind or solar will get preference. The DOE will also support analyses that calculate the economic value of pumped storage hydropower in responding to the grid and in providing other ancillary services.

■ Advanced conventional hydropower sys-tem testing at a Bureau of Reclamation facility ($2.0 million awarded over three years). These projects will support system tests of innovative, low-head hydropower technologies at non-powered Reclama-

3. Perfect peaking power. Virginia’s Bath County Pumped Storage Plant is jointly owned by “Dominion and the operating companies of the Allegheny Power System, and managed by Dominion Generation,” according to the Dominion website. The two reservoirs, one located 1,262 feet above the other, flow water to produce electricity using the plant’s six 462-MW tur-bines during periods of high electricity demand. The plant entered commercial service in 1985. Courtesy: VEPCO/Dominion Resources



RENEWABLES

tion facilities and sites. The deliverables include testing to demonstrate energy cost reductions that could be replicated at other Reclamation sites. Both Reclamation and the DOE are sponsoring this work.

Much Hydro Remains UntappedOne reason hydro has been overlooked in re-cent years is the widespread notion that the resource is tapped out, that all the best rivers are dammed, all the opportunities used up. But that doesn’t appear to be the case. An on-going ORNL analysis—the National Hydro-power Asset Assessment Program (available at http://bit.ly/e15xeF), whose findings were unveiled at the NHA meeting in Washing-ton—shows considerable opportunities for new hydro. The study identified a potential 12.6 GW of capacity available at 54,000 ex-isting dams that don’t now have generating equipment. These potential projects are all greater than 1 MW in capacity.

The top 10 in ORNL’s potential greatest hits account for 3 GW of that total capacity. They are all Army Corps projects: four Ohio River dams, two Arkansas-Red River facili-ties, two on the Tombigbee River, and one each on the Mississippi and Alabama Rivers.

The ORNL top 100 list totals 8 GW, with 81 Army Corps projects on the list. The poten-tial hydro projects that ORNL discovered don’t represent threats to the environment. According to the report, “Most non-powered dams and potential capacity can be devel-oped outside of critical habitat, parks, and wilderness areas.”

The potential hydro sites also solve a prob-lem for states that want to enact or increase renewable energy quotas but don’t have sites that are sufficiently windy or sunny. ORNL notes, “Non-Powered Dam Potential exists in areas with less than ideal wind and solar resources.”

Separately, a Reclamation study re-leased in March also finds a large potential opportunity for new hydro development in existing non-power water projects. The bureau surveyed its properties, finding 191 sites with hydro potential. Of those, it iden-tified 43, representing potential generating capacity of 184.7 MW, with cost-benefit ratios greater than 1, meaning that a dollar investment would return benefits in excess of a dollar. Seven sites, with total capac-ity of 104.8 MW, had cost-benefit ratios higher than 2. The resource assessment

concludes that “substantial hydropower potential exists at Reclamation sites. Some site analyses are based on over 20 years of hydrologic data that indicate a high likeli-hood of generation capability.”

Under-Hyped HydroIt isn’t as high-profile as nuclear, it doesn’t get the respect it deserves (and neither did Rodney Dangerfield), but hydro looks as if it is making a comeback. And although the White House doesn’t appear to consider hy-dropower a renewable energy resource (it has not been mentioned in the list of generation technologies the administration considers “clean”) the executive branch agencies that deal with hydro view it as a realistic com-ponent in any renewable, allegedly clean, energy scheme.

It’s a good bet that any progress toward the administration’s goal of 80% of electric-ity from “clean” energy sources will include a hefty amount of water over a dam, through a pipe, down a hill, and into a turbine. ■—Kennedy Maize is a contributing edi-

tor to POWER and executive editor of MANAGING POWER (www.managing-

powermag.com).

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COOLING TOWERS

Defeating Concrete Reinforcing Steel CorrosionFour concrete cooling towers at a coal-fired electrical generation plant exhib-

ited reinforcing steel corrosion that was causing concrete deterioration. This case study follows the repairs to those towers—how the corrosion control solution was selected, how repairs were made, and how follow-up tests found the repairs to be effective three years later.

By Bruce A. Collins, Restruction Corp.

As early as the 1960s, corrosion of re-inforcing steel in structural concrete was recognized as a threat to concrete

structure durability. Steel embedded in newly cast concrete is protected by the high pH of the concrete. However, the passive film on the surface of the reinforcing steel is broken down over time by the infiltration of ionic materials, typically salts. Carbonation of the concrete, caused by diffusion of atmospheric carbon dioxide, can also break down the rein-forcing steel passivation, allowing the initia-tion of corrosion.

Many variables affect the time it takes for corrosion to begin, including the concrete cover depth, temperature, concrete moisture content, pH level of the concrete, the pres-ence of oxygen, and others. When corrosion begins, one region of reinforcing will become anodic and other regions will act as a cath-ode. The ensuing chemical reactions cause oxidation of the metal at the anode.

The oxidation product occupies a larger volume than passivated steel. As the bar oxi-dizes, an expansive tensile force is applied to the cover concrete, creating cracks and ulti-mately a concrete spall (flaking or crumbling). At this point, typically, the facility’s owner be-comes concerned about long-term durability, and repair project planning is launched.

Repair Project PlanningDuring June 2000, the engineering team of a 1,660-MW coal-fired electrical generation sta-tion located in the southwest U.S. began plan-ning a concrete repair project. The team had been observing concrete spalling and corro-sion of reinforcing steel on specific reinforced concrete assemblies integral to the plant’s four concrete mechanical draft cooling towers. Two towers served Unit 1 and two served Unit 2.

The cooling towers are constructed primar-ily of precast concrete elements, with some conventionally reinforced elements. In the plan, the cooling tower is a 12-sided shape with an approximate 212-foot diameter.

Each tower has 12 motorized fans designed to draft air from the lower level up through the tower. The moving air is heat exchanged with hot process water, ejecting steam out the top of concrete fan stack assemblies (Figure 1). The fan stack assemblies are constructed of a lower conventionally reinforced concrete ring measuring 41 feet 2 inches in diameter by 4 feet tall. The upper assembly is constructed of precast concrete panels bolted to the lower assembly. Corrosion of the reinforcing steel in the lower assembly was causing concrete spalling. The plant engineering team wanted to understand the source of deterioration and institute a repair plan for the problem.

Investigation Program and ResultsInvestigation of the corrosion source consist-ed of the following tasks:

■ Visual assessment of all 48 lower fan stack assemblies and field measurement of con-crete cover.

■ Review of original structural drawings and details for the lower fan stack assembly.

■ Chloride content analysis at depths of 1, 4, and 7 inches through the depth of the lower assembly concrete at six separate locations. A total of 18 chloride samples were tested.

■ Delamination mapping of the assemblies.■ Petrographic analysis of two cores removed

from different fan stack assemblies.

Visual assessment of the lower assemblies determined several items of concern, includ-ing the high-temperature environment, mini-mum concrete cover of ¾ inch, and water seeping down the outer face of the assembly at the joint between the upper precast and lower cast-in-place concrete. Constant contact with steam was causing elevated concrete tem-peratures and high moisture content. Each of these variables was contributing to the rebar corrosion (Figure 2).

Review of the original structural drawings detailed the location, size, and placement of cement grout in the joint between the upper precast and lower cast-in-place concrete. Reinforcing details for the lower assemblies

1. Four of a kind. The configuration of one of four cooling towers repaired as part of the project. Courtesy: Restruction Corp.

2. Much spalling found. The upper and lower fan stack assembly and the areas requiring repair on one of the four towers is shown. Courtesy: Restruction Corp.

10_PWR_070111_SR_CoolingTowers_p48-53.indd 48 6/16/11 2:08:48 PM


COOLING TOWERS

showed designed cover for reinforcing was 1 inch. Number 4 bars were spaced at 12 inch-es as stirrups over #4 hoop bars around the lower assembly circumference.

Chloride content samples were chosen to determine levels of water-soluble chlorides at

the level of reinforcing and to determine if a chloride gradient existed in the concrete. The measurements were also used to determine if chlorides were cast into the mix. Average chlo-ride content at 1 inch was 0.0581% by weight. Maximum chloride content in any sample was

0.144% by weight. ACI 318 (the American Concrete Institute’s Building Code Require-ments for Structural Concrete) allows for a 0.15% chloride content in reinforced concrete exposed to chlorides in service for new con-struction. Generally, in the U.S., 0.30% chlo-ride content is considered the threshold limit for initiation of corrosion. All chloride mea-surements fell below this limit.

Delamination mapping of the lower as-sembly concrete determined that, on average, 15% of the 600 square feet for each assembly was delaminated.

Petrographic analysis of the cores revealed poor air entrainment and locally abundant micro-cracks throughout the core body. The concrete was generally of good quality. Car-bonation depth was measured at 0.13 inches.

Based on this information, conclusions were drawn regarding the source of corro-sion. The effect of high concrete tempera-tures, high moisture content, and the wetting and drying action at the outside face of the assembly concrete were cause of the corro-sion found on the cooling towers.

Repair ProgramIt became apparent that reducing the mois-ture content level within the concrete was

3. Coating tower interior. Coatings were applied in the lower assembly interior after repairs were completed. Courtesy: Restruction Corp.

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COOLING TOWERS

the primary defense against future corrosion. Cutting off the moisture ingress would in-crease the concrete resistance, lowering the reinforcing steel corrosion rate. Reducing the concrete temperature was not a realistic expectation.

A coating system designed to lower con-crete permeability was selected. The coating system selected started with a 100% solids moisture-tolerant epoxy primer applied at the rate of 100 square feet per gallon. The body of the coating was a 100% solids polyamide based, flake-filled epoxy (Figure 3).

Access, surface preparation using 20,000-psi water lances, and coating installation would be accomplished during a 30-day plant shutdown.

Access was built using prefabricated wood joist and planks bearing on steel angle assemblies attached to existing structure. Partial removal of the grout joint between the upper and lower assembly to facilitate water-proofing was also completed during the shut-down and would minimize water penetrating through the outer concrete face. The grout was removed to a depth of approximately 2 inches. Open cell backer rod was saturated with urethane multi-grout, activated, and in-stalled in the joint. A polysulfide caulking was installed over the top to provide a fin-ished appearance.

The coating system was installed in two topcoats to minimize pin-holing. A moisture vapor test was completed prior to installation to minimize the chance of debonding. The project was completed in two phases and en-tailed applying 14,400 square feet of coating inside 24 separate assemblies in each phase.

The repair program included other rebar repassivation techniques that would be con-structed during plant operation. With the vapor drive cut off, we believed the concrete would “dry out” rather quickly. Our attention was now focused on the outside face of the assemblies.

The high concrete temperature would continue to drive corrosion at a faster than

normal rate. To counter this effect, the repair program included installation of passive ca-thodic anodes inside the concrete repair ar-eas. The density of the reinforcing steel was evaluated and anodes were specified for in-stallation at approximately 4 feet on center at the partial depth repair perimeters. Standard concrete repairs, per ICRI Guideline 310.1-2008, formerly No. 03730 (the International Concrete Repair Institute’s Guide for Sur-face Preparation for the Repair of Deterio-rated Concrete Resulting from Reinforcing Steel Corrosion), were completed. Dry mix shotcrete was measured for resistivity com-patibility with the anodes and utilized as the repair material. Dry-mix shotcrete was cho-sen for ease of application and low shrinkage characteristics.

A larger than normal amount of shrinkage cracking was anticipated, and occurred, due to the difficult curing conditions and elevated substrate temperature. A 40% solids silane sealer was applied to the outside face of the

assembly upon curing to assist in maintain-ing low concrete moisture content from the high-humidity environment outside the as-sembly. Spall repair totals were 5,900 square feet, and those repairs were completed in two phases (Figure 4).

Reducing the concrete moisture levels, installing passive anodes, and completing concrete repairs to the outside face of the as-semblies provided a complete rebar repassi-vation project.

Corrosion MeasurementsAs the first repair construction phase of the project was nearing completion in 2005, the plant engineering team raised the question of how to measure the repair program’s success. Quickly, a plan was implemented to measure corrosion. Luckily, the second phase, Unit 2 project was still in the active corrosion mode. Unit 1, consisting of 24 assemblies in the first phase, was repaired and the reinforcing steel repassivated.

4. Repairs completed. The spall repairs are completed at the base of the cooling tow-er. Courtesy: Restruction Corp.

5. Pre- and post-repair data. Data labeled “2B” are pre-repair values. Data labeled “1A” and “1B” are immediate post-repair values. No data signifies that readings weren’t taken at that location. Source: Restruction Corp.

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COOLING TOWERS

The corrosion measurement plan was to measure corrosion current, corrosion poten-tial, and concrete resistance at two fan stack locations on Unit 2. These locations would be considered pre-repair and serve as the base-line. Corrosion rates and potentials were not taken during the investigation phase. It was apparent that corrosion was occurring and the source of initiation was the high concrete temperatures and moisture levels. Further-more, no future monitoring of the corrosion was planned during the investigation phase.

Measuring corrosion rate, potential, and concrete resistance at seven locations on Unit 1 would serve as the immediate post-repair condition and provide a comparison to pre-repair condition measured at Unit 2.

A Galvapulse corrosion rate meter was used to record approximately 12 readings per assembly. The results are illustrated in Figure 5. An immediate concrete resistance

effect was measured. All seven Unit 1 as-semblies measured post-repair had higher concrete resistance than the two Unit 2 pre-repair assemblies. On average, resistance increased 135%.

Corrosion rate measured in micro-meters per year also showed immediate improve-ment. Six of seven post-repaired corrosion rates were below both pre-repaired rates. On average, corrosion rate was reduced 80%.

Corrosion potential showed immediate improvement as well. Adjusted for the sil-ver/silver chloride half-cell, copper sulfate electrode readings in the pre-repair were –315mV CSE and –360 mV CSE (CSE or a copper sulfate electrode is used as the base-line). The average post-repair potential was measured at –270 mV CSE. ASTM Standard indicates that for potentials between –200 mV and –350 mV CSE, corrosion is “uncer-tain.” Readings more positive than –200 mV

indicate with 90% confidence that no corro-sion activity is present.

Three Years LaterThe plant engineering team budgeted additional funds for repair of Unit 2 assemblies to be com-pleted in spring/summer 2008. Three years had passed since completion of Unit 1 repairs. Again, corrosion measurements were taken upon com-pletion. The same two locations on Unit 2 were measured, providing a direct comparison of pre-repair (year 2005) and post-repair readings. Five of the original seven assemblies at Unit 1 were remeasured. This provided a comparison of immediate post-repair and repair-plus-three-years’-time readings. Two new locations at both Unit 1 and Unit 2 were also recorded. Results still indicated that the reinforcing steel was pas-sive, as shown in Figure 6.

Concrete resistance increased in both Unit 2 post-repair measurements and Unit 1 mea-surements recorded in 2008 versus 2005. Av-erage concrete resistance increased over the three-year operation period. Unit 1 resistance increased from 49 kilo-ohms immediate post-repair to 115 kilo-ohms measured three years later.

A U.S. standard has not been developed for corrosion current. However, a proposed Norwegian standard indicates values of 11.5 to 58.0 micro-meters per year would be considered low corrosion. Less than 11.5 micro-meters per year indicates negligible corrosion. The Norwegian standard converts corrosion rate units of micro-amps per centi-meters squared to cross-section loss of rein-forcing steel using Faraday’s Law.

A low corrosion rate (11.5 to 58.0 micro-meters per year) was found in Unit 1 imme-diate post-repair measurement in 2005, and the 2008 measurement showed low to neg-ligible corrosion activity. The rebar in Unit 1 remains passive due to the implemented repair scheme. Unit 2 assemblies that were measured prior to repair in 2005 and then again post-repair in 2008 recorded improved corrosion currents in the low to moderate corrosion activity levels.

The corrosion current levels have dropped significantly. Corrosion potentials are also expected to continue improving as the rebar becomes more passive. These results dem-onstrate that the repairs started in 2000 and completed in 2008 were successful and the towers’ concrete will remain serviceable for many years to come. ■

—Bruce A. Collins (bruce@restruction .com) is vice president of Restruction

Corp. Portions of this article are repro-duced with the permission of the Jour-

nal of Protective Coatings & Linings, published by the Society for Protective

Coatings (www.sspc.org).

6. Follow-up test data. Corrosion data collected three years after repairs were made on each set of cooling towers found that the corrosion rates were significantly reduced from the as-found condition. Source: Restruction Corp.

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POWER VIEWS

Modernizing the Grid, Modernizing Our Industry

David K. Owens, executive vice president, Business Operations Group for the Edison Electric Institute, comments on the progress U.S. utilities are mak-ing toward a smarter electrical power grid.

Everyone talks about the importance of a stronger and smarter transmission sys-tem, but it often seems that little is be-

ing done. To get a read on the current state of grid modernization, POWER Editor-in-Chief Dr. Robert Peltier, PE talked with David K. Owens, who has a unique overview of the grid landscape thanks to his position at the Edison Electric Institute (EEI).

What is the role of the electric util-ity industry in this century? Owens: The job of every electric company re-mains the same as it has for the past 100 years—delivering a reliable, affordable electricity supply. But the world in which we are perform-ing that job continues to change dramatically.

We are moving toward a clean energy fu-ture. We are building advanced generating stations. We are expanding the use of renew-ables. And we are creating a smarter grid.

What role is EEI playing in a clean energy future?Owens: Edison Electric Institute and its mem-ber electric companies are particularly excited by the potential that modernizing the grid has to offer the industry and its customers. More than 90% of EEI’s members already are working to modernize their grid. These efforts will:

■ Empower customers to better control their electricity use.

■ Encourage the development of renewable energy sources.

■ Expand the use of distributed generation sources.

■ Support the use electricity as a fuel for cars and trucks.

■ Enhance the reliability and efficiency of the power grid.

■ Improve service restoration.■ Provide the framework and foundation for

future economic growth and global com-petitiveness.

In particular, though, modernizing the grid will help us to transform how we serve our

customers. For example, many EEI member companies are now installing advanced meter-ing infrastructure and information technologies to improve their call center functions. These technologies will enable us to push more infor-mation out to customers about their electricity service—information about outage response/restoration times, energy usage, and price alerts. And the modern grid will enable us to use mul-tiple modes of communication to do so, includ-ing phone, email, and text messaging.

What is a modernized electric grid going to cost?Owens: As part of its overall efforts to mod-ernize the grid, the electric power industry is matching $3.4 billion in grant awards that the U.S. Department of Energy (DOE) disbursed as part of the American Reinvestment and Recovery Act (ARRA) in 2009. This public-private investment will total over $8 billion in new investment in the grid.

As of early February 2011, EEI members have spent approximately $577 million, or about a third of their awarded smart grid ARRA funds. This was a $58 million in-crease over early January 2011. Con Edison of New York offers one example of how these funds are being spent.

Con Edison is using the approximately $192 million in funding it received from DOE to pur-sue a number of projects to modernize both its underground distribution system, which spans more than 90,000 miles, and its overhead wire system, which totals more than 30,000 miles. The funding will help Con Edison to reduce costs and improve operational flexibility.

The modernization projects include in-stalling state-of-the-art control and monitor-ing equipment, as well as new underground switches. Each switch has sensors that mea-sure a variety of information about the power being distributed to customers. This data will be transmitted back to their control centers, where it will be analyzed and the switches will be remotely controlled, as warranted.

As Con Edison completes the installation of a wireless mesh communication system, which

will enable data collection and control of un-derground transformers and network protector switches, the company will be better equipped to prioritize its operational workload and proac-tively address its findings.

In its continuing effort to engage customers, Con Edison also is developing ways to integrate the control of building management systems, battery storage units, distributed generation, and electric vehicle charging stations. Success-fully combining these advanced technologies will enable Con Edison to lower costs, improve reliability and customer service, and reduce its impact on the environment. (For more informa-tion, please visit www.coned.com.)

Southern Company is another industry leader that is modernizing its grid to improve perfor-mance and reliability. The company is matching a $165 million DOE investment grant to com-plete a three-year project to modernize the grid across the company’s four-state service territory.

This funding will enable the company to con-tinue its long history of investment in its trans-mission and distribution infrastructure, ensuring that its robust electric grid becomes smarter, more resilient, and more efficient through the application of intelligent electronic devices.

In particular, by applying advanced technolo-gies to reduce stress on the system, increase the control of power flow, and improve power qual-ity and environmental impact, Southern Com-pany will create new opportunities to become even more efficient and better serve its custom-ers. (For more information, please visit www .southerncompany.com.)

How do you gauge public accep-tance of a new smart grid?Owens: The customer is in favor of us mov-ing ahead with smart grid and smart meter technology. In fact, our latest research found that over two-thirds of consumers nation-wide want us to move ahead. And one in four wants us to do so quickly. But we recognize that we will run into problems if we push the smart grid technology too far too fast.

Although our research found great inter-est in moving ahead with the smart grid, it

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POWER VIEWS

also found that less than half of the public has even heard the term “smart grid.” And of those who say they have heard about it, only about one in 10 say they have a fairly com-plete understanding of the smart grid.

State regulators are another essential au-dience for our communication efforts. We are working closely with regulators to cre-ate a supportive platform for the deploy-ment of smart technology. In addition, we are addressing such issues as cost recovery of new technology investments, prudency determination, accelerated technological obsolescence, data access, privacy, and cy-ber security.

Not surprisingly, in the economic environ-ment where we find ourselves today, some regulators have been cool to the idea of adding expensive new equipment and redesigned rate systems. To get them on board with our mod-ernization plans, we are in frequent communica-tion with them about what modernizing the grid means and, most importantly, the many benefits it creates on both sides of the meter.

At the same time, we are working to keep the technology development moving. If you can keep the technology moving, it will get the consumer moving as well. Just look at how Apple has stimulated consumer interest in ad-vanced technology with its iPods, iPhones, and now iPads.

Many electric utility customers are happy with the basic service, but we know that oth-ers want more:

■ They want information about their elec-tricity use and options.

■ They want information delivered to them anytime, anywhere, not just printed on a monthly bill.

■ They want more choice and control. And, in the long term, they will want energy-related services.

For the modern grid to deliver all the val-ue it is promising, our customers will need to change their attitude about the role that electricity plays in their lives, and the rela-tionship they have with their utility. This will not be easy, as these attitudes have been built over the past 100 years. But electric utilities are ideally suited to take on this task.

Electric utilities differ from other indus-tries in that we have a strong connection with our customers. And these connections extend across all customer classes—from manufac-turers to chain stores, and from high-income to low-income residential customers. Our customers—all of them—also know that we will be there to continue to serve them in the smart grid era.

Just as we are changing and modernizing the grid, we are also changing ourselves.

Electric companies are resetting their stra-tegic focus—they are rethinking and repo-sitioning themselves for the changes ahead. Among the issues electric companies today are addressing:

■ The lines of business they are willing to de-emphasize to put more effort elsewhere.

■ The partnerships they need to succeed.■ The new technologies and new skills they

need to bring into the organization.

What other companies are in-volved in developing a smart grid?Owens: In particular, electric companies are well along in building partnerships to benefit from the changing business land-scape. Choice and diversity are the key driv-ers. Electric companies at every point along the value chain are seeking and building partnerships to give themselves and their customers the most options and the most possibilities.

Some of the leading technology compa-nies that the industry is working with now are OPower, IBM, Cisco Systems, and Silver Spring Networks, to name just a few. These partnerships are helping customers to better manage their energy use. They are enabling

utilities to deploy advanced networking products, software, and services. And they are making it possible to deploy smart grid systems rapidly and cost effectively.

Electric companies also are learning from others. To help us prepare for this transformation, EEI launched the Smart Technology Scenario Project in 2010. As a part of this project, EEI has held two workshops that brought together 60 indus-try smart technology leaders—regulators, consumer advocates, Wall Street analysts, manufacturers, and others. The discus-sions covered the business opportunities/threats that may arise and the regulatory challenges that utilities may face.

The electric power industry’s transition to a more modern grid is well under way. With outreach to customers and continued cooperation and dedication between the industry and its public and private part-ners, we are confident that this transition will empower consumers to get more value from their electricity dollar, while helping utilities to lower their operational costs and improve reliability. ■

—Dr. Robert Peltier, PE, POWER’s editor-in-chief, conducted and edited

this interview.

To subscribe, visit www.powermag.com/subscribe or call 847-763-9509.

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ASH MANAGEMENT

The Better Environmental Option: Dry Ash Conversion TechnologyAfter the 2008 incident involving the failure of a large surface impoundment con-

taining wet coal ash, the EPA began investigating all coal-fired power plants employing this wet coal ash management method. Now a new dry ash man-agement technology offers coal-fired power plants an environmentally suit-able alternative for handling coal ash that also increases energy efficiency.


Existing coal ash management regulations are undergoing close scrutiny by the U.S. Environmental Protection Agency (EPA).

This action was initiated in the wake of the 2008 incident in which a containment dike at a Ten-nessee Valley Authority coal ash disposal pond failed, spilling approximately a billion gallons of wet coal ash over about 300 acres and into a nearby river. Consequently, many coal-fired electric power producers are now investigating alternative methods of handling coal ash that do not require using water.

Bottom ash is agglomerated ash particles formed in pulverized coal furnaces that are too large to be carried in the flue gases and that impinge on the furnace walls or fall through open grates to an ash hopper at the bottom of the furnace. Physically, bottom ash is typically grey to black in color, is quite an-gular, and has a porous surface structure.

Typically, bottom ash as a byproduct at coal-fired power plants is conveyed in a hy-draulic system in which the ash is entrained in a high-flow, circulating water system and delivered to either an ash pond or dewater-ing storage bins. In the alternative, bottom ash can be conveyed by a mechanical drag system to dewatering storage bins.

Now a new bottom ash management tech-nology has been developed that does not re-quire the use of water and thereby avoids the creation of wet ash that has to be stored in surface impoundments or dewatering storage bins. DRYCON is a mechanical conveying system that handles hot bottom ash being dis-charged directly below the boiler throat. Ron Grabowski, vice president of sales at Clyde Bergemann Delta Ducon, discussed the tech-nology with POWER in May.

How the Dry Ash Conversion Technology WorksHot bottom ash falls onto the DRYCON con-veyor, where it is simultaneously conveyed and cooled, Grabowski explained. The DRY-CON technology uses the negative draft of a

pulverized coal-fired boiler to draw ambient air through the conveyor. This airflow cools the hot ash while supplying about 1% of the com-bustion air into the boiler. The dry bottom ash can then be stored in a silo and off-loaded into trucks for disposal or resale (Figure 1).

“DRYCON is the next generation of dry bottom ash systems,” he said. “One of the unique design features of DRYCON is that it does not use belt technology; rather, it conveys the bottom ash via a series of high-temperature alloy pans.”

With the new system, ash is conveyed on top of the pans as they move gently via ex-ternally mounted rollers. This design allows the new system’s conveyor to incline at a 40-degree angle from grade. This feature can reduce the footprint of the conveyor and pro-vide additional flexibility not found in other conveyors, according to Grabowski.

1. High and dry. The new dry bottom ash–handling system promotes higher efficiency by returning heat energy to the boiler. In addi-tion, with this new system in place, plants can also avoid using large amounts of water for ash cooling and conveying. Courtesy: Clyde Bergemann Delta Ducon

2. Breaking up is easy to do. “Jaw crushers” are shown above the inlet of the DRY-CON conveyor. This equipment breaks up and crushes large clinkers before they enter the new system’s conveyor. Courtesy: Clyde Bergemann Delta Ducon

12_PWR_070111_Ash_p56-57.indd 56 6/16/11 2:17:28 PM


ASH MANAGEMENT

Another innovation is the use of “jaw crushers” above the inlet of the DRYCON conveyor, he pointed out. The jaw crushers crush large clinkers before they enter the con-veyor (Figure 2).

Grabowski acknowledged that “there can be many obstacles when converting a wet bottom ash system to a dry system.” By us-ing standard components, however, a dry ash conversion system can be customized to meet the capacity, distance, particle size, and loss on ignition (LOI) requirements of a plant.

“With any wet-to-dry bottom ash conver-sion, the main challenge is finding a direct path for the conveyor to exit the bottom of the boiler without interfering with existing structural steel or surrounding equipment,” he said.

Because the wet-to-dry conversion re-quires demolition of the existing wet bot-tom ash equipment directly under the boiler, a boiler outage must occur. However, proper planning and preassembly of equipment can reduce the duration of the outage to less than 25 days.

Advantages of the Dry Conversion System Advantages of using dry bottom ash systems at coal-fired facilities instead of the tradition-al wet ash-handling systems include:

■ Economical performance: The elimina-tion of water pumps, water treatment, and related equipment reduces mainte-nance and creates an overall cost sav-ings benefit.

■ Efficiency: By removing the existing water-impounded bottom ash hopper, the plant will see a reduction of ther-mal energy losses that come from water evaporation and reductions in unburned carbon or LOI.

■ Revenue: A dry bottom ash system can increase the plant’s revenue through the benefits of boiler efficiency and the sale of dry bottom ash.

■ Environmental benefits: With a dry bot-tom ash system, the need for an ash pond, water slurry pumps, and water treatment is completely eliminated. This eliminates many environmental issues associated with these component parts (Figure 3).

As for the impact on a coal-fired plant’s wa-ter usage, “When a plant converts to a dry bot-tom ash system, it can eliminate the ash slurry pumps that use large amounts of water that can range from 2,800 gallons per minute (gpm) to 4,000 gpm during operation,” he said.

With typical water-impounded bottom ash hoppers, water evaporation plays a part in reducing boiler efficiency. When hot bot-tom ash falls into a wet bottom ash hopper, the ash is immediately quenched. In contrast, with a dry ash conversion system, the bottom ash continues to burn as it falls onto the con-veyor pans. This reduces LOI in the bottom ash and thereby increases the boiler’s overall efficiency (Figure 4).

There are no notable disadvantages of using a dry bottom ash system, according to Grabowski. He also pointed out that the life span of a dry bottom ash system meets the typical 30-plus-year requirements of the power industry.

Recently, Clyde Bergemann Power Group Americas was awarded a significant contract to convert an existing wet bottom ash removal system on two 650-MW coal-fired units for a utility plant in Florida to a dry system utilizing its DRYCON technolo-gy. “This award marks the first utilization of the DRYCON technology in North America and is a milestone for the Clyde Bergemann Power Group,” Grabowski said. “It is also the first conversion of a wet to a completely dry bottom ash system in almost 20 years in North America.”

From Ash to Cash: Turning Bottom Ash into Marketable ProductsPlant personnel can dispose of dry bot-tom ash much as they have handled dry

fly ash for many years, Grabowski ex-plained. Several grades of ash are outlined in ASTM standards. Ash with low amounts of carbon or LOI is the most desirable. It can be used in building products such as concrete and cinder blocks. “A DRYCON system has the ability to reduce unburned carbon and provide an ash quality that is marketable,” he said.

According to the EPA, bottom ash appli-cations can include:

■ Filler material for structural applications and embankments

■ Aggregate in road bases, sub-bases, and pavement

■ Feedstock in the production of cement ■ Aggregate in lightweight concrete products ■ Snow and ice traction control material

Grabowski discussed important trends that he thinks will promote the increased use of dry bottom ash systems at coal-fired power plants.

“As we all wait for regulations to be final-ized, the general opinion of the industry is that ash pond storage will be eventually be eliminated by direct or indirect regulations,” he said.

He noted another important trend that is seldom mentioned: the possible need for existing plants to consider replacement of their wet ash systems, even if they do not have ash ponds. “Because a large percent-age of wet bottom ash systems are near the end of their projected life span, plants are faced with the decision of rebuilding or re-placing them,” he said. “A dry bottom ash system may be the best economical solution to this situation.” ■


High

LowUnreliability Maintenance Loss of efficiency Operation

Wet system Drycon

3. Beating the competition. The dry ash system offers many advantages and cost sav-ings over the traditional wet ash-handling system. Courtesy: Clyde Bergemann Delta Ducon

4. Burn, baby, burn. With a dry ash-han-dling system, bottom ash continues to burn as it falls onto the conveyor pans. This reduces loss on ignition in the bottom ash and thereby increases the boiler’s overall efficiency. Cour-tesy: Clyde Bergemann Delta Ducon

12_PWR_070111_Ash_p56-57.indd 57 6/16/11 2:17:38 PM


MATERIALS

Titanium Tubing Still Going Strong After 40 Years Since 1972, titanium-tubed power plant surface condensers have been provid-

ing corrosion-free service. Recent process advances are making the mate-rial suitable for even more applications.

By Dennis J. Schumerth, Valtimet Inc.

Titanium was discovered by British scien-tist William Gregor in 1791 and named by Austrian chemist Martin Klaproth

after the Titans, the first sons of the earth in Greek mythology. This “reddish brown calx” remained largely a curiosity until William Kroll of Luxembourg, recognized as the fa-ther of the titanium industry, perfected his manufacturing process, which, even today, remains largely responsible for 80% of the world’s production of titanium.

Titanium exhibits dramatic and highly useful characteristics as a reactive metal that make it useful for many applications. Its supe-rior strength-to-weight ratio makes it valuable for use in military and commercial avionics; alloy advancements have led to its use in the field of biomedical engineering; it’s exten-sively used as “the” white-base pigment; and its high desirability index has led to extensive use in power generation, chemical and in-dustrial processing industries, and other ap-plications where both strength and corrosion resistance are desirable, if not mandatory.

Given the material’s unusual qualities, power plant owners in the early 1970s took the unprec-edented risk of installing Grade 2 (Gr. 2) tita-nium in their surface condensers. The first two utilities that retubed a condenser were located on the Northeast and California coasts. The utilities prefer to remain anonymous. These were argu-ably the first complete power plant surface con-densers ever retubed using Grade 2 titanium.

Both utilities performed several years of independent in-situ testing of titanium against competing tubing materials—including yel-low metals, stainless alloys, and titanium Gr. 2—for use in their once-through cooling sys-tems, using either brackish water, seawater, or a combination of both for condenser cool-ing. Both tests found titanium was the only material that remained completely unaffected in these hostile environments.

Since those first two projects, many plants along both U.S. east and west coasts have chosen Gr. 2 titanium as the material of choice to mitigate the problem of condenser and associated boiler tube failures. In fact, more than 600 million feet of welded tita-

nium tubing (Figure 1) have been installed without one reported corrosion event. That’s an unparalleled track record.

For reasons detailed below, titanium has proven an indispensible material, especially given today’s demanding power markets. Though the metal has proven its staying power in power plants for four decades, new applications are still being discovered. Some were not possible just a few years ago.

The OffenseThe presence of water contaminants and their omnipresent corrosion activities pose enor-mous challenges for power generators. (For example, see “Biofouling Control Options for Cooling Systems in the Sept. 2007 issue of POWER, available in the archives at www .powermag.com.) A much larger challenge for thermal power plants that use local wa-ter in a once-through cooling process pres-ents itself during the building, operation, and maintenance of those plants. The deposition, corrosion, biofouling, and mitigation that are often associated with water from lakes, rivers, and oceans affect not only these once-through cooling systems but also other cooling water systems as well as tower circuits.

The DefenseInsidious attack from any number of aggres-sive organisms raised plant owners’ awareness of the problem, but they were perplexed about what material to choose for their surface con-densers when traditionally used tube materi-als were failing at an alarming rate. In many cases, originally installed tubes made from materials such as aluminum bronze (C60800) and copper nickel alloy (90/10 CuNi/C70600 and 70/30 CuNi/C71500) failed prematurely due to high chloride and elevated levels of pol-lution in the circulating water system.

Ti Then and Now In 1972, titanium material options were lim-ited principally to the commercially pure (cp) family. Today, 38 grades of titanium tub-ing are identified just within ASTM B-338/ASME B-338 Standards.

The most common grade used for power plant surface condenser tube applications is cp Gr. 2 (Table 1). Its properties of high strength-to-weight ratio, workability, near corrosion immunity to aggressive water systems, and relatively stable pricing structure versus stain-less alloys and yellow metals make it a highly attractive long-term investment.

1. Fast gun. Typical semi-automatic tube-to-tubesheet fusion welding is under way using ASTM B-338 Gr. 2 titanium tubing and ASTM B265 solid titanium plate. Courtesy: Valtimet Inc.

13_PWR_070111_Titanium_p58-60.indd 58 6/16/11 2:19:35 PM


MATERIALS

Titanium tubing remains arguably one of the most tested of the competing ASTM condenser tube materials requiring full eddy current, ultra-sonic, and a final pneumatic proof testing. Sup-plementing this rigorous testing, improvements in the manufacturing and installation process at both the condenser fabrication facility and in the field have led to improved overall quality and increased product throughput.

It is particularly noteworthy that the latest computer-controlled technology is now be-ing applied within the process stream to dra-matically impact automatic tube end welding and mechanical expansion of the tube-to-tubesheet joint, resulting in improved and consistent joint strength and seal. Both new unit designs and modular changeouts have benefited from these innovations.

Current in-field retubing projects can now employ these sophisticated computer model-ing techniques and associated process tooling advancements, allowing highly successful mechanical tube joint expansion of thin-wall titanium tubing into softer tubesheet material such as Muntz Metal and Naval Rolled Brass.

This groove enhancement process to the in-side diameter (ID), as it is known (Figure 2), is now commonplace where thin-wall tubing (as thin as 24 BWG/0.022 in. wall thickness) can be successfully expanded, resulting in pull-out loads well within the bandwidth of best practices (Figure 3). This process was not possible even five years ago.

Following the success of these early retube projects, today’s in-field retubing projects can now use sophisticated computer modeling tech-niques and associated process tooling advance-ments that allow highly successful mechanical tube joint expansion of thin-wall titanium tub-ing into softer tubesheet material such as Muntz Metal and Naval Rolled Brass. These tooling ad-vancements, coupled with ID groove enhance-ment, are now commonplace where thin-wall tubing (such as 24 BWG/0.022 in.) can be suc-cessfully expanded, resulting in pull-out loads well within the bandwidth of ASME Code Sec-tion VIII, Division I Nonmandatory Appendices requirements and best practices acceptability.

It is also noteworthy that should titanium clad materials be used for the tubesheet, as opposed to a solid B-265 plate, seal welding of the tube-to-tubesheet joint is strongly suggested, if not man-datory. A mechanical expanded-only joint will not provide the proper sealing and will poten-tially expose the parent carbon steel to corrosion

products that would invade the annulus between the tube and drilled tubesheet (Table 2).

Generating companies in Florida, Arizona, South Carolina, and Alabama have recently se-lected titanium for their retubing projects. They selected Gr. 2 titanium tubing not only because of its acknowledged 40-year corrosion immunity but also for recent innovations in thin-wall tub-ing expansion into a softer tubesheet material.

When titanium condenser tubing is used in both new and in-field retubed units, a more gen-erous cleanliness factor (Uc) can be considered when performing the heat transfer calculations. Values such as 90% Uc are commonplace in today’s designs. A higher cleanliness factor can reduce the amount of heat transfer surface or, alternatively, increase performance as a result of reducing the overall fouling factor. Additional benefits could include reduced circulating water losses when thin-wall tubing is used and, be-cause titanium is immune to underdeposit pit-ting, a tubeside freshwater flush is not needed. Stainless alloys and other candidate materials, on the other hand, can be irreparably damaged should corrosive water be left standing in the tubes during an off-line condition.

Corrosive Activity by Any Name Is Still CorrosionDuring the early years of the titanium retub-Component Weight (%)

Carbon (max.) 0.08

Oxygen (max.) 0.25

Nitrogen (max.) 0.03

Hydrogen (max.) 0.015

Iron (max.) 0.3

Others (max. each) 0.1

Others (max. total) 0.4

Titanium remainder

Table 1. Chemical requirements of Grade 2 titanium. Source: Valtimet Inc.

2. Even more groovy. The ID groove enhancement process is now commonplace where thin-wall tubing can be successfully ex-panded. Source: Valtimet Inc.

3. Holding power. A series of tests were performed using 1-inch-diameter titanium Gr. 2 B-338 tubes with a Gr. 2 B-265 tubesheet to determine the load necessary to pull the tubes from the tubesheet after proper installation. The three pull-out tests include standard mechanical expansion, mechanical expansion with an ID groove, and mechanical expansion plus tube-to-tube sheet welding. Test data on the first two installation options demonstrate that an acceptable tube joint is possible within a shop manufacturing environment. The tests also found that mechanical expansion alone produced marginal pull-out loads for thin-wall tubes and that thin-wall tubes (30 BWG and 27 BWG) installed with only mechanical expansion were problematic. Source: Valtimet Inc.

18

16

14

12

10

8

6

4

2

0

Pull-out load (lb)

Wal

l red

uctio

n (%

)

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

Danger area

Mechanical expanded Expanded + ID groove Expanded + welded



MATERIALS

ing era, pollutants identified within the cooling water stream included high levels of chlorides, suspended solids, macro fouling, heavy metal accumulation, and a host of Environmental Protection Agency–identified toxins. Notwith-standing significant efforts on the part of plant owners to clean up this witches’ brew, emerg-ing and even more insidious contaminants have been identified both locally and nationally. Sig-nificant among these are surface pollution and nitrate runoff from agriculture, which increase the incidence of microbiologically influenced corrosion (MIC) to alarming levels.

For example, manganese, which can cause underdeposit pitting even in chlorinated envi-ronments, has been identified as plating out on equipment, and gray or impaired water

has been identified as a result of sewage run-off or inadequate facility control.

These new, non-traditional corrosion streams have forced power plants to closely review their material selection process, tak-ing into account not only existing levels of impurities but also expected future trends that may lead to using cooling water from untraditional sources.

Plenty of RedundancyFor more than 40 years, titanium condenser tube materials have demonstrated corrosion immunity from both traditional and newer pollutants found in the cooling water stream of a surface condenser. Depending on the plant location, many cooling water systems

(including once-through, tower, pond, canal, and others) can, through cycle concentration and recirculation, experience increased pol-lutant concentration. In particular, chloride level conductivity concentrations can in-crease significantly—anywhere from 1.3 to 2 times normal levels.

Testing completed by IMI plc (formerly Imperial Metal Industries) in the UK found that in seawater concentration levels of 3.5% and beyond (Figure 4), titanium’s general corrosion immunity in sea and brackish wa-ter environments at temperatures at or near 120C/248F (the typical condenser operating point) was confirmed. It’s noteworthy that this same study confirmed that Gr. 2 tita-nium remains completely immune to chlo-ride attack, even when approaching sodium chloride concentrations of 6x normal and temperatures approaching 80C/176F—well above normal concentrations and well below the operating metal temperature of a surface condenser.

Quality Is More Important Than EverEven though recent U.S. power generation totals have been down slightly, work contin-ues at the engineering and plant level to de-velop and expand continuous improvement programs that can enhance the performance of the fleet. In fact, as some coal-fired units retire in coming years, low maintenance and high reliability will become even more important for the remaining units. Conse-quently, power generators around the world will continue to select titanium tube mate-rial as a long-term solution to a common problem.

Plant owners who installed the first tita-nium tubes four decades ago continue to reap the long-term rewards of their decision—both in terms of corrosion resistance and a positive return on asset investment. Today, water quality and proper material selection are as important as they were 40 years ago. ■

—Dennis J. Schumerth (dennis [email protected]) is director of

business development for Valtimet Inc.

Test project Tube material Tube OD (inches) Tube wall (AVW, inches) T.S. material Pull-out load range (lb) ID grooves

Utility A, South Carolina Ti Gr 2 1.0 0.028 Muntz 1,750 No

Utility A, South Carolina Ti Gr 2 1.0 0.028 Muntz 2,350–2,500 Yes

Utility A, South Carolina Ti Gr 2 1.0 0.035 Muntz 2,050–2,250 No

Utility A, South Carolina Ti Gr 2 1.0 0.035 Muntz 3,900–3,950 Yes

Utility B, Georgia Ti Gr 2 0.875 0.022 Muntz 1,200–1,300 No

Utility B, Georgia Ti Gr 2 0.875 0.022 Muntz 2,700 Yes

Utility B, Georgia Ti Gr 2 0.875 0.035 Muntz 1,400–1,550 No

Utility B, Georgia Ti Gr 2 0.875 0.035 Muntz 3,400–3,700 Yes

Table 2. Holding power. Source: Valtimet

4. Strength and immunity. This chart showing the influence of temperature, sodium chloride concentration (representing brackish and ocean water), and pH on the crevice corrosion and pitting corrosion propensity of commercially pure titanium in seawater and sodium chloride brines shows the material’s immunity to corrosion at typical operating temperatures and far beyond. Source: IMI plc

240

220

200

180

160

140

120

100

80

60

40

20

0

Met

al te

mp.

(C)

Pitting and crevice corrosion probable

Crevice corrosion probable

pH9

IncreasingPh

pH3.5

Complete immunitySeaw

ater

0 5 10 15 20

Concentration % NaCL

Typical surface condenser operating point (120F/48C)



REGULATORY ISSUES

FERC Surrenders Jurisdiction over Station Power in CaliforniaIn a surprising decision, a federal agency surrendered some of its regulatory

authority—and parts of the industry don’t approve. The Federal Energy Regulatory Commission declined to defend its jurisdiction over station power in the California power market, potentially giving an economic ad-vantage to utility generators nationwide and putting merchant generators at a disadvantage.

By Mark R. Robeck and Emil J. Barth, Baker Botts LLP

In a remarkable turn of events, the Fed-eral Energy Regulatory Commission (FERC), in a set of orders affecting

the territory controlled by the California Independent System Operator (CAISO), reversed its longstanding policy permit-ting generators to net against their posi-tive electricity output their station power requirements—the electricity required by a generation station to start up its turbines, operate its machinery, and keep lighting, heating, air conditioning, and other equip-ment operating.

FERC’s Abrupt About-FaceSince 2001, FERC has regulated how station power is supplied to electric gen-erators, ensuring that all generators, both utility-owned and merchant-owned, can net their positive output against their power requirements. FERC’s netting pol-icy put utility and merchant generators on the same footing, ending the utilities’ attempts to bill merchant generators for station power at retail rates following the utilities’ divestiture of those very same fa-cilities. Last year, however, a U.S. Court of Appeals rejected FERC’s authority over interstate transmission as a valid basis for FERC’s regulation of station power in CAISO. In the proceeding following the court’s order, FERC stated, without analy-sis, that the remaining jurisdicitonal scope conferred upon it by the Federal Power Act (FPA) did not extend to the regulation of station power, but instead that station power was subject to the states’ jurisdic-tion over retail sales.

FERC’s decision threatens to impair competition in wholesale power markets. Instead of netting their station power re-quirements against their positive output, merchant generators may now have to buy station power from local utilities, expos-

ing them to high retail rates for the very product they produce. At the same time, FERC’s abandonment of its longstanding netting policy leaves unaffected the prac-tice of vertically integrated utilities sup-plying station power “in-house,” for their own generation facilities, a cost-free prac-tice that traditionally has not been treated and accounted for as a retail sale.

Needlessly Surrendering AuthorityFERC’s reasoning makes clear its belief that it has no jurisdiction to require that netting be used to determine the amount or pricing for station power. However, FERC’s conclusion was neither inevitable nor necessary, as it ignored the full scope of its authority to regulate the wholesale sales market, including station power.

FERC’s regulation of station power falls squarely within its wholesale energy market jurisdiction; it is not only a matter of incidental regulation of a practice af-fecting the wholesale markets. Allowing a generating facility to net its station power requirements against its gross electric out-put is nothing more than allowing that fa-cility to engage in a reverse or exchange wholesale energy transaction, which takes place entirely within the bounds of the wholesale energy market.

The direct and substantial relation-ship between station power and FERC’s wholesale market jurisdiction also extends beyond the character of the netting trans-action. Permitting one set of generators to self-supply station power while leaving another set open to high retail charges is both discriminatory and will lead to over-all higher electricity costs and attendant price distortions in the wholesale power market. For these reasons too, FERC has the authority to regulate station power to

rectify discriminatory or preferential prac-tices and ensure the efficiency and integ-rity of the wholesale market.

Re-Level the Playing FieldAs a result of FERC’s reluctance to con-front the question of the extent of its wholesale sales jurisdiction, the promo-tion of competition in the wholesale power markets may face a serious setback. Inde-pendent merchant generators across the country may be deprived in the future of netting their station power requirements and instead could be billed millions of dollars for electricity at retail rates. How-ever, merchant generators with an interest in preserving the longstanding practice of netting station power have solid arguments for any future proceedings in the courts or before FERC. ■

—Mark R. Robeck ([email protected]) is a partner in the

Houston office of Baker Botts LLP. Emil J. Barth ([email protected])

is an associate in the Washington, D.C., office of Baker Botts LLP. Robeck

and Barth have advised generators on FERC’s station power policies.

The views expressed in this article are those of the authors and do not

necessarily reflect the views of the firm or its clients.

Find the Legal Details OnlineFor a more detailed look at the is-sue, see the online supplement to this article, “A Level Playing Field No More,” associated with the July issue at www.powermag.com.

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ELECTRIC POWER 2011: WHERE THE GENCOS MEET

Consolidation, Market Distortions Underlie Remarks by Industry ExecutivesIf you needed additional proof that the power industry is changing, the ELEC-

TRIC POWER keynote and panel discussions over the past few years have provided it—top-of-mind issues have been significantly different each year. For the 2011 keynote speaker and panelists, the challenges of reli-ability, regulatory compliance, financing, and getting the fuel mix right took center stage. In the wake of Japan’s nuclear crisis, safety also fea-tured prominently.

Jason Makansi, Pearl Street Inc.

What a difference a year makes. At the 13th Annual ELECTRIC POWER Conference Keynote ses-

sion, smart grid and nuclear (which figured prominently last year) were the equivalent of footnotes. What the speakers converged on instead, without actually confronting it directly, is that the industry is headed for sig-nificant consolidation.

Opening remarks were given by John Shelk, president and CEO of the Electric Power Supply Association (EPSA), which has probably done more to pry open whole-sale electricity markets over the past 20 years than any other organization. His comments were followed by an industry executive pan-el, moderated by POWER Editor-in-Chief Dr. Robert Peltier (Figure 1).

Shelk began by noting a key attribute of this industry: Reliability “is an input,” a re-quirement to maintain a surplus of capacity; no other “competitive” industry operates with such a regulatory mandate. One might think that, after 30 years of “deregulation,” 20 years of competition programs at the state level, and numerous initiatives at the federal level, mandated reserve margins would be coming down. Not so, at least not in Texas.

That point was underlined in the panel discussion by Doyle Beneby, president and CEO, CPS Energy. He reported that the Elec-tric Reliability Council of Texas, which runs the Texas electricity market, increased its re-serve margin from 12% to 13.5%. And this is a market that, according to many observers, “got [competition] right.”

The Fuel Conundrum A second challenge Shelk noted was the pe-rennial cost of environmental compliance.

No one needs to be reminded that environ-mental mandates have essentially made the industry’s No. 1 power plant fuel, coal, un-competitive economically. Carbon cap and trade legislation is off the federal govern-ment’s agenda, at least for now; the Repub-lican-dominated House is trying to rein in the Environmental Protection Agency (EPA) on myriad other compliance initiatives; and, reported Shelk, Congress is requesting eco-nomic impact analyses of compliance rules from the EPA, the Federal Energy Regula-tory Commission, and the Department of Energy (DOE).

Despite this shift at the federal level, an-nouncements of coal plant retirements keep growing. Tennessee Valley Authority (TVA), one of the country’s most significant coal

burners, is “throttling back the coal fleet,” said Robert Fisher, TVA’s senior VP, fos-sil generation. “Eliminating today’s carbon footprint includes closing coal plants,” said Ruth Ann M. Gillis, executive VP and chief administrative and diversity officer, Exelon Corp. (Figure 2).

From a market perspective, it’s hard to imagine a cheaper source of electricity than a fully paid-off, amortized coal-fired plant—unless you heap enough environmental com-pliance costs on it to kill it.

Beneby noted that you can buy an idled combined-cycle plant for less than the cost of the flue gas desulfurization system that would be required on a coal unit—forget about the boiler, turbine/generator, and other major components. What’s more, the finan-

1. Keynote speaker John Shelk. Shelk is the president and CEO of the Electric Power Supply Association. Source: POWER

15_PWR_070111_EP_Keynote_p62-65.indd 62 6/16/11 2:24:02 PM



cial models show gas prices low “as far as the eye can see.”

Then there were financing concerns. Dan Foley, CEO of ACCIONA Energy North America, observed that wind plants will be “exceptionally difficult” to finance in the 2011–2012 time frame because of low gas prices and the disappearance of merchant banks, disgraced during the financial crisis, which financed half of the wind projects in recent years. They were able to protect their huge profits in other aspects of their business by taking advantage of tax-incentive financ-ing available through federal production tax credits (PTC).

Stephen Carter, vice president of regu-lated generation at Cleco Power, also not-ed that merchant generators can’t get bank financing.

The result of low gas prices and restrict-ed financing options is obvious. Fisher said TVA was growing its gas fleet, while Gillis crowned natural gas “queen,” one that will “reign for a long time.”

Despite the disaster at Japan’s Fukushima nuclear facility, the panel discussion revealed that the industry isn’t necessarily running away from nuclear, but the near-term hurdles have been raised. Exelon owns and operates the nation’s largest nuclear fleet, but it is only committed to continuing its uprate program on existing units; it’s not planning any new builds. The new units at South Texas Project, which CPS was once part of as one of sev-

eral off-takers, are now history (except for completion of the license). This is especially notable because they were some of the only U.S. units that looked like they could be de-veloped outside of rate base. TVA’s Fisher talked about completing facilities begun de-cades ago. Even though TVA isn’t “scared of the Japanese situation,” according to Fisher, the agency isn’t planning any new “big units” and instead is eyeing the smaller modular technology.

And, as Beneby suggested, nuclear be-comes cost-prohibitive without the federal government’s loan guarantees and may be further burdened by new compliance regu-lations following review of current design standards in light of the Fukushima disaster. Getting carbon legislation off of the current congressional agenda has also taken the ur-gency out of new nuclear units.

Thus, although Shelk implored that “we need it all,” every fuel and technology, it seems there’s little “competition” today on the supply side. Most generating companies will approach their banks and/or public util-ity commissions only with some type of a gas-fired plant or participation in a renewable facility. It isn’t competition, but multiple lay-ers of government intervention that is caus-ing the industry to converge.

The third challenge Shelk identified is the so-called shale gas revolution. Anyone whose eyeballs are glued to a computer, television, or digital device screen knows about the po-

litical battle over shale gas. Both sides seek to win the hearts and minds of the American public. When Shelk mentioned that the natu-ral gas industry had spent $100 million on an advertising campaign, it seemed clear indus-try had won round one. However, environ-mental groups are now focused on gas instead of coal, he stressed. Thus, when the environ-mental lobby’s troops make the full transition from the coal theatre of political operations to shale gas, it probably won’t seem as one-sided as it does now. And gas probably won’t be as cheap as it is now either.

Cleco, for one, isn’t just burning shale gas in its power plants. According to Carter, the company also plans to invest with explora-tion and production companies in “upstream integration.” This way, the utility won’t be “exposed to [pricing] volatility.” But there are potential risks with gas. Beneby, for ex-ample, believes future EPA regulations will force the price of shale gas up.

Is Solar the New Kid on the Block?Shelk mentioned that recent Electric Power Research Institute studies show solar begin-ning to be economic. Other positive senti-ments about solar were echoed by the panel. Beneby sees photovoltaic prices declining and the prices of “big solar,” sized north of 250 MW, coming in just under gas when con-sidered on a 30-year life-cycle cost basis. So-lar also potentially avoids transmission risk and costs, so Beneby thinks it is “worthwhile to look at big solar in Texas.”

Foley believes that concentrated solar plants sited adjacent to a gas-fired plant can lead to a “green peaker.” (See this issue’s cover story and cover photo.) Unlike wind, solar energy is generally available, barring cloud cover, when electricity demand peaks.

But although solar may give wind a run for the money over the next few years, Fo-ley stressed that new wind turbine technol-ogy will be more competitive. Wind facilities incorporating the latest turbine designs have exhibited 20% higher capacity factors in Oklahoma and Iowa, increasing yield and lowering prices. Foley’s “not worried about gas” because “technology changes will drive the business.”

Beneby isn’t as sure. He noted that in Tex-as, intermittent sources like wind will soon be penalized for non-delivery if Texas Senate Bill 15 becomes law.

The Buildout, Pushed OutIn recent years, topics for impassioned discussion at this forum have been new ca-pacity additions, transmission expansion, carbon legislation, and smart grid pro-grams. None of these topics got much air time at ELECTRIC POWER 2011. Cleco’s

2. 2011 Power Industry Executive Roundtable panelists. From left to right: Robert Fisher, senior VP, fossil generation, Tennessee Valley Authority, a federally owned cor-poration; Ruth Ann M. Gillis, executive VP and chief administrative and diversity officer, Exelon Corp., which in May announced a plan to acquire Constellation Energy, to become the largest electric utility in the country, and certainly one with a huge footprint in PJM; Doyle Beneby, president and CEO, CPS Energy, a municipal utility, one of the nation’s largest, with a protected service territory and charter; Stephen M. Carter, VP, regulated generation, Cleco Power, which, according to Carter, is “totally focused on the regulated utility”; Dan Foley, CEO, ACCIONA Energy North America, which is developing renewable energy projects to take advantage of renewable portfolio standard mandates imposed by at least 30 states; and Dr. Robert Peltier, PE, editor-in-chief of POWER, moderator. Source: POWER

15_PWR_070111_EP_Keynote_p62-65.indd 63 6/16/11 2:24:11 PM



Carter mentioned transmission investment as “what’s next.” He also acknowledged what others have been reading in the press about so-called smart meter programs. That is, customers don’t perceive their value. In Cleco’s case, that meant the utility was unable to rate base the DOE cost-shared program; instead, it had to fund it through operation and maintenance savings. The program also resulted in layoffs for all of the company’s meter readers.

The drop in demand over the past three years, accompanied by electricity price de-clines, has led to surplus capacity, stressed Shelk. As a follow-up to that comment, Pel-tier asked the panel about the impact of low electricity prices on their businesses. Both Gillis and Fisher noted that demand cer-tainly took a hit but that manufacturing and commercial and industrial accounts were re-bounding. The hit on earnings made nuclear unattractive, Beneby conceded.

The Value of Fuel FlexibilityCarter talked at length about Cleco’s new $1 billion circulating fluidized bed (CFB) boiler power plant completed last Febru-ary, which “burns anything,” including pe-troleum coke, biomass, and Illinois coal. (See “Cleco’s Madison Unit 3 Uses CFB Technology to Burn Petcoke and Balance the Fleet’s Fuel Portfolio,” August 2010 in POWER’s archives at www.powermag .com.) Among other things, the CFB allows the utility to burn woodchips to help meet its renewable portfolio standard (RPS) ob-ligations. Of course, if that plant started up last year, it went through permitting in the middle of the last decade, when natural gas prices were high and escalating, and carbon management was a bigger threat. Things have changed, which evidently is why Cleco also recently purchased a com-bined-cycle facility.

Other panelists saw biomass as problem-atic when an audience member asked about alternative fuels. Foley noted that biomass was “impossible to finance” because of fuel suppliers’ lack of credit-worthiness. Even Carter conceded that care had to be exercised so as not to compete with your customers, such as pulp and paper plants, and drive up wood prices. Beneby noted that the radius of supply/delivery on alter-native fuels kills you.

Safety FirstIt was heartening to know that four of the five executives, when asked by Peltier what keeps them up at night, responded with workforce safety. Fukushima obvi-ously is on the industry’s collective mind. But two of the executives also mentioned

recent fatalities. Fisher opened his remarks by reminding the audience that “weather is a significant challenge.” TVA’s system had just been devastated by more than 300 tor-nadoes in the span of a few days.

Recent pipeline, mining, and plant ac-cidents with multiple fatalities across the nation, along with a greater incidence of severe weather, have not only brought safe-ty to the forefront, but also the need for an experienced workforce. Although Peltier pointed to the experience gap—there are few workers in the 35 to 50 age bracket—these executives expressed confidence in their preemptive hiring strategies, part-time and remote worker programs, and cross-training. Fisher, for example, noted that workers from the retired coal plants at John Sevier station moved seamlessly over to the John Sevier combined-cycle plant. For the most part, the recession has at least punted the workforce problem—which was at the top of the utility executives’ agenda only three years ago—down the field.

The Hidden Cost of Shutting DownFoley made an excellent point that is prob-ably underappreciated by the industry, and certainly those outside of it. You have to be really careful about retiring capacity, he said, if for no other reason than the dif-ficulty of building replacement capacity. As just one example, he noted that his firm has been trying to permit a wind facility for 10 years—in a state, California, that is pursuing a 33% RPS!

When officials threaten to shut down nu-clear units because of Fukushima, and coal plants are retired because of compliance costs (and let’s face it, to take excess capacity out of the market), what replaces that capacity? Carter noted that “it takes five to seven years to do anything.” If, as Shelk says, reliability is an input, then it pays to not be cavalier about retirements or shutdowns.

The Big Asset ShuffleCleco isn’t alone in buying gas-fired assets. Beneby said CPS is also looking to acquire combined-cycle facilities that are “cheap” because the mandates around wind and the PTC have knocked them out of the dispatch queue in Texas. TVA seeks to “grow its gas fleet,” noted Fisher. Indeed, throughout the country, gas-fired plants once owned by mer-chant generators are being acquired by regu-lated entities.

The Exelon-Constellation merger pro-posal is only one of several. Earlier this year, Duke Energy announced that it seeks to merge with Progress Energy, First Energy consummated its merger with Allegheny Energy, and AES Corp. announced it is ac-

quiring DPL Energy. Others are clearly in the works. Divestitures to prevent “market power” will likely accompany these mergers as they move forward. In an era of low gas prices as far as the eye can see, resistance to raising rates at the retail level, and less infrastructure expansion for earning a regu-lated rate of return on capital investment, what’s a utility CEO to do? The “urge to merge,” as Peltier put it, is strong because companies can eliminate redundancies and leverage costs across larger fixed asset and customer bases (see “The Urge to Merge” in the June 2011 issue of POWER).

Consolidation isn’t just happening through utility mergers and plant acquisi-tions. Shale gas players are being consoli-dated into the major oil and gas companies. Wind industry suppliers are consolidating, now that business has contracted from the recent boom years. The federal govern-ment is even encouraging larger balanc-ing areas so that intermittent renewable resources can be integrated into the grid with less cost impact. As Fisher noted, larger service territories lead to larger con-trol areas.

Shelk mentioned “relying on market forces to do the best job for consumers.” Market forces are certainly driving con-solidation. But that generally gives greater pricing power to suppliers. The low gas prices that currently have executives’ at-tention are based on supply that hasn’t yet been extracted from the ground, an en-vironmental compliance framework that hasn’t yet gotten the full attention of the opposition lobby, and a fragmented supply industry.

Myriad government mandates have clearly limited choice in supply and, bar-ring more demand destruction, will drive electricity prices upward. It is common knowledge that few, if any, projects will get financed today outside of rate base with-out a long-term power purchase agreement with a regulated entity and fixed operat-ing costs guaranteed through a contrac-tual service agreement with the equipment vendors, at least during the debt service period. There’s little competition in that situation, at least as the industry has come to know the term.

Market forces are certainly at work, but regulatory distortions are even clearer. What’s not clear is who is watching out for ratepayers. ■

—Jason Makansi (jmakansi@ pearlstreetinc.com) is president, Pearl

Street Inc.; principal of Pearl Street Liquid-ity Advisors LLC; and executive director of the Coalition to Advance Renewable

Energy through Bulk Storage (CAREBS).

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Organized by:

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Nuclear Power in the Shadow of FukushimaRisk, risk management, and the specter of Fukushima ran through the nuclear

track at May’s ELECTRIC POWER Conference in Chicago. The reality of risk, driven home by the horrendous events in Japan, was a recurring theme in many presentations, in questions to speakers, and in the conversations among delegates during informal moments.

By Kennedy Maize

Sargent & Lundy’s William Peebles kicked off the two-day nuclear energy track with a description of what occurred in Japan

on March 11 and the current assessment of the scope of the damage. As he spoke, the toll of the earthquake and tsunami was again rising. Peebles noted that the four damaged reactors at the Fukushima site took a one-two punch, lead-ing to the dreaded condition known in the nu-clear world as “station blackout,” a loss of elec-tric power that totally disables safety systems. First, a massive earthquake hit the Japanese coast, calculated as a 9.0 event, far beyond what Japan had seen in recorded history. That took out offsite power to the site. Then, administer-ing the knockout blow, a tsunami with waves topping 10 meters—another unprecedented event—smashed into the site, killing on-site backup diesel generators and preventing rescue crews from reaching the plant.

The resulting explosions, melting fuel, spread of radiation, and enormous population evacua-tion established Fukushima as the second-worst disaster in the history of civilian nuclear power, after the Chernobyl explosion in the Ukraine al-most exactly 25 years earlier. It also provided a chilling backdrop to the discussions in Chi-cago. Throughout the meeting, those who fol-low nuclear power were discussing just what might befall the nuclear industry in Japan as a result. Some thought that Tokyo Electric Power Co. (TEPCO), the reactor operator and owner, would survive with government backing. Others were convinced that TEPCO was not “too big to fail” and would not outlast the reactor disaster.

For the developers and operators of nucle-ar power plants, risk is not just a matter of the odds that a plant could fail catastrophically, as in Japan, at Chernobyl, or at Three Mile Island in 1979. Risk arises at the very begin-ning of planning a nuclear venture. Economic and engineering risks prevail in planning and building these incredibly complex, wonder-fully useful machines for making electricity. These are risks in slow motion, but they are real and significant nonetheless.

Small-Scale DevelopmentsThe nuclear track included a popular sec-tion on the “big new thing” in nuclear: little reactors. The atomic acronym is “SMR,” for “small, modular reactor.” Reduced risk to pub-lic health and safety has long been a selling point for the SMRs. Incorporating a full range of passive features to slow down an accident scenario and make response and recovery eas-ier, the SMRs look very good on paper. (See “Are Small Reactors Better?” in the Novem-ber 2010 issue of POWER, available in our archives at www.powermag.com.)

Imagine a fission reaction in a large, steel thermos bottle (we’re not talking cold fusion here, but hot fission). That’s NuScale Power, the product of a U.S. Department of Energy research team involving Oregon State University, the Ida-ho National Laboratory, and a former Bechtel subsidiary. The 45-MWe pressurized water re-actor encloses all the conventional innards of a large reactor in a 65-foot-tall, 14-foot-diameter tube, with the air evacuated to leave a vacuum. In a commercial plant, several of these vacuum bottles would sit in a below-ground pool con-taining 4 million gallons of water—an additional safety barrier and a shock absorber in the case of an earthquake (not unknown in Oregon, where NuScale makes its home). A concrete shield covers the pool and contains any contaminants.

“The thermos bottle concept is completely novel,” NuScale Power’s Ed Wallace told the power expo (Figure 1). Wallace, senior vice president for regulatory affairs, joined NuScale a year ago, after several years working on the unsuccessful pebble bed modular reactor project at Chicago’s Exelon and South Africa’s PBMR Pty. His job at NuScale is to serve as shepherd and sherpa, guiding NuScale’s design through the risky waters of the U.S. Nuclear Regula-tory Commission’s (NRC’s) licensing process. Wallace described the concepts underlying the licensing of new, unique reactor technologies, the challenges these new technologies present, and the need to get designers, developers, and regulators speaking the same language and un-

1. Small is beautiful. NuScale Power is developing a small, modular nuclear reactor. Ed Wallace is senior vice president, regulatory affairs for the company. Source: POWER

2. Nuclear building blocks. The NuScale Power module uses pressurized water reactor technology with passive safety systems to pro-duce 45 MWe. The small, modular reactor would be refueled every 30 months using 4.95% en-riched UO2. To give a sense of scale, the reactor vessel is only 65 feet tall. Multiple units can be built and aggregated to meet any power require-ment. Courtesy: NuScale Power

16_PWR_070111_Nuclear_66-67.indd 66 6/16/11 2:25:58 PM



derstanding the technology (Figure 2).Probabilistic risk assessment (PRA), Wal-

lace said, is a key to answering the complex and intertwined licensing issues. The PRA for the NuScale project, he said, offers a way to focus analysis, make sure the right questions are asked and answered—illuminating the “unknown unknowns”—and give muscle to the familiar concept of defense-in-depth. “The real value of PRA is in the journey,” he said. The PRA, he said, “adds robustness” to the design.

Regulating Nuclear PowerWallace noted “a whole lot of emerging issues growing out of Fukushima.” Stephanie Coffin of the NRC described some of those issues that confront regulators. Her fundamental advice to those planning these new reactor technologies: “Potential applicants should engage NRC early with specific proposals”—advice she repeated throughout her presentation.

One of the issues that arose in Japan, and that the NRC wants addressed for the SMRs, is the size of emergency zones around the plants. Most large, conventional reactors are located away from population centers, but they also contain much larger inventories of radiation products in their cores. SMRs—particularly if they can be used in cogeneration and district heating ap-plications along with power generation—are likely to be located closer to populated areas, but they’re also likely to possess lower concentra-tions of poisons in the core.

Another emerging issue is control room staffing. Current NRC rules limit the number of reactors an operator can control to two. SMR in-stallations may consist of arrays of half a dozen or more units controlled by one operator. This, too, troubles some at the NRC.

The appropriate NRC licensing process for small nukes is also on the regulatory table. There are two paths toward a final operating license. NuScale plans to submit an application for NRC certification of its reactor design in 2012 under the commission’s generic program (known as Part 52 for its location in the Code of Federal Regulations), hoping for approval in 2019. This is a “one-stop” process that envisions a preap-proved reactor design. The Tennessee Valley Authority, on the other hand, is working with Babcock & Wilcox (B&W) and Bechtel to put a B&W mPower SMR on TVA’s Clinch River site in Tennessee under the NRC’s traditional, two-step “Part 50” licensing process.

The NRC is agnostic about which process should be used. In either case, Coffin assured the audience that the agency “is preparing for a high level of advanced reactor licensing activity” and that the NRC “will review ap-plications in a timely manner.”

Risk Assessment Wrap-upBooz & Co. Vice President Christopher Dann

summed up the developmental and regulatory risks to nuclear power posed by events in Ja-pan. “The oldest plants and those most believed to be exposed to natural ‘black swan’ events” such as hurricanes, floods, and other improb-able catastrophes, he said, “will face the stiff-est review; new plants should expect more local opposition if ‘greens’ and ‘fatalists’ argue for a moratorium.” Ultimately, he said, the impacts of Fukushima “will depend on the state of the plant, the nature of the technology, the national stance towards future nuclear power and the op-

tions available as alternative fuel sources.”Perhaps the greatest risk to the future of

nuclear power in the U.S., said Dann, lies en-tirely out of the control of the nuclear indus-try and its regulators. “Natural gas prices,” he said, “drive the fundamental economics” of new nuclear power. ■

—Kennedy Maize ([email protected]) is a contributing editor to POWER and

executive editor of the online magazine MANAGING POWER (www.managing-

powermag.com).


16_PWR_070111_Nuclear_66-67.indd 67 6/16/11 2:26:06 PM



Solid Fuels: Moving Material and Managing EmissionsIn today’s solid-fueled power plant, managing emissions and moving materi-

als more defines the task than the traditional work of making megawatts. That’s the message that emerged from the coal and solid fuels track at this year’s ELECTRIC POWER.

By Kennedy Maize

Whether it’s the traditional fuel, coal, or the hot new trend of cofiring coal with biomass, moving stuff

around presents major challenges.

The Hidden Costs of BiomassEzra Bar-Ziv of Ben-Gurion University described the experience of mixing raw wood-derived bio-mass with coal at two large power plants in Israel. The aim was to test the environmental benefits of combining coal with a cleaner fuel. Those ben-efits, Bar-Ziv said, were significant: limiting the growth of CO2 emissions; substantially lowering SOx, NOx, and rocks (particulates); and the ab-sence of mercury in the biomass fuel.

Biomass, Bar-Ziv noted, “can be used in coal-fired boilers without objections from en-vironmental protection authorities.” Biomass also qualifies as “sustainable,” Bar-Ziv said, as long as “the biomass growth rate equals the rate of biomass burning,” meaning no net loss of the fuel.

But the technology has little market pene-tration so far. According to Bar-Ziv’s figures, there are only 15 commercial projects in the world that feature cofiring coal and biomass. Of those, eight are in Europe and only one is in North America. (There are many more co-firing pilot and feasibility projects. See “Bio-mass Cofiring: A Promising New Generation Option” in the April 2011 issue of POWER.)

So, asks Bar-Ziv, “if cofiring biomass is good, why are there so few commercial plants?” His answer is that moving and mix-ing the fuel with coal is tricky and generates several kinds of costs:

■ Biomass is bulky, which entails expensive logistics.

■ Its high moisture means it is expensive to transport.

■ Its low heat value means it requires a lot of fuel to produce power results.

■ Biomass is hygroscopic, meaning that it takes up and retains water, burns irregu-larly, and produces undesirable tars, which must be dealt with.

■ It is difficult to pulverize.

What to do? Make biomass more like coal by torrefaction, says Bar-Ziv. Torrefaction in-volves heating the biomass to 200C to 300C in a reduced-oxygen environment. In short, it is a mild form of pyrolysis. The result of torrefaction is a fuel that has greater heat content and a decreased ratio of oxygen to carbon; it’s also a more easily handled prod-uct. “Grindability is improved dramatically, and the power required for pulverization to the suitable size range reduces by a factor of 10, reaching the power required to pulverize coal,” says Bar-Ziv. He called the product “biocoal”; others call it biochar (see “Utili-ties Increase Renewable Energy Capacity” in this issue).

Lessons from Biomass Transferred to CoalEven some ranks of coal can benefit from the same basic idea—heating to reduce moisture and make a fuel that has higher heat value and is handled more efficiently. That’s what Great River Energy, Minnesota’s second-largest utility, has done at its two-unit, 1,200-MW Coal Creek Station, the largest power plant in North Dakota. James Kennedy of the Worley Parsons consulting firm, described the Coal Creek project for the coal track.

The mine-mouth plant burns a fuel rated at 6,200 Btu/lb and 38% moisture. Unfor-tunately, noted Kennedy, the plant was de-signed to burn 6,800-Btu fuel, meaning that the two units were burning 9% more fuel than they should, which lowered efficiency and increased costs across the board. Using Department of Energy funding, Great River Energy mounted a project to use waste heat from the plant to dry the lignite and improve plant performance. After running a pilot proj-ect in 2005, the engineers installed full-scale equipment in 2009. Resulting “performance [was] right on the predicted curve,” with a 9% reduction in fuel moisture.

After a year of operation, the new equip-ment has seen over 90% availability with more than 90% of the plant’s coal processed through the new dryers. The drying process

has also produced significant air pollution reductions: 54% less SO2, around 40% less mercury, 32% less NOx, and a CO2 reduction of 4% due to more efficient operation.

Because the Coal Creek project was a first-of-a-kind venture, what lessons can be learned for those who wish to replicate the technol-ogy? Kennedy suggested two that deal with fuel handling. The first is crusher location. “Crushers,” he said, “need to be as close to the dryer inlets as possible to minimize local-ized agglomeration at hoppers along the mate-rial transport system.” The second is fuel size, he said: “Wet fines need to be minimized to prevent accumulation and bed elutriation (the separation of lighter and heavier particles),” and “Oversize chunks need to be minimized to prevent bed stagnation zones.”

Kennedy added that Great River Energy expects even greater gains in the future from its lignite-drying operations: lower NOx emis-sions as the furnace is retuned based on the new performance experience and “substantial-ly reduced routine pulverizer, boiler, and air quality control system maintenance costs.”

In summary, said Kennedy, the Coal Creek project produces “coal drying as needed”; it avoids the need for protracted fuel storage and the concomitant risks of spontaneous combus-tion. The moisture reduction means lower fuel throughput, net heat rate improvement, reduced flue gas volume, and reduced service require-ments. On top of those benefits, the project lowers air emissions for criteria pollutants and CO2 as a result of increased efficiency.

Materials-Handling ChallengesOne of the major drivers of improved air quality from coal-fired plants in the past 20 years has been the installation of wet flue gas desulfurization equipment. But wet scrubbers have created unique and daunting materials-handling issues, as described by Richard Mc-Cartney of engineering and construction firm Roberts & Schaefer Co.

“All of the wet scrubber addition projects require limestone to be delivered to the power plants and the gypsum by-products disposed

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of,” McCartney said (Figures 1 and 2). “This re-quires that two separate material-handling facil-ities be added to the power plant. The limestone facility includes delivery, unloading, stockout, storage, reclaim, and silo fill systems. The gyp-sum facility includes stockout, storage, reclaim, loading, and disposal systems.”

All this, of course, comes on top of the coal-handling requirements. So the modern solid-fueled power plant is a complex network of materials-handling gear: belts and screws and trucks and barges and chains and cranes. Here’s how McCartney describes just the options for

handling the stockout and reclaiming of the gypsum output from the wet scrubbers: “Stock-out methods can form a single conical pile, a circular pile, or a long triangular pile. Storage includes both open and enclosed. The minimum storage capacity is based on the production cy-cle and the shipping/disposal schedule.

“As with the stockout systems, there are many reclaim systems that accommodate re-claim of gypsum. Reclaim methods can vary from fully automated to manual with mo-bile equipment assistance. The arrangement of the stockout pile and the type of reclaim

equipment used dictates the percentage of the stockpile that will be automatically reclaimed without the use of mobile equipment.”

How does a plant operator dispose of all the gypsum pouring from the scrubber? McCartney explains, “The major methods for disposing of gypsum at power plants are barges, trucks, and conveyors. The disposal method is based on the location of the power plant and the opportuni-ties to sell the gypsum within that region. Power plants along major rivers like the Mississippi and Ohio ship their gypsum by barge. Coastal power plants ship the gypsum by ocean barges, while power plants in the East or West usually ship their gypsum by truck. Occasionally, conveyor trans-port is used. The typical disposal systems are:

■ Conveyor(s) directly to a wallboard plant or to a landfill area on the plant property.

■ Trucks loaded by conveyor chute or mo-bile equipment (front-end loaders).

■ River or ocean barges loaded by a loadout conveyor with a loading chute.

■ River or ocean barges loaded by a loadout shuttle conveyor with a telescopic chute.” ■

—Kennedy Maize is a POWER contributing editor and executive

editor of MANAGING POWER (www.managingpowermag.com).

2. Output. At the end of the flue gas des-ulfurization process, plants have to dispose of gypsum. At American Electric Power’s Mitchell Plant in Cresap, W.Va., barge loadout is through a transfer house and onto a barge loadout shut-tle conveyor equipped with a telescopic chute. Courtesy: Roberts & Schaefer Co.

1. Input. Progress Energy Florida’s Crystal River Station (Units 4 and 5) is located in Crys-tal River, Fla. The limestone-handling facility is designed to receive limestone from back-dump trucks at two above-grade receiving hoppers with drag chain reclaim conveyors Courtesy: Roberts & Schaefer Co.

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ELECTRIC POWER 2011: WHERE THE GENCOS MEET ELECTRIC POWER 2011: WHERE THE GENCOS MEET

Utilities Increase Renewable Energy CapacityDriven by state RPS requirements and the desire to diversify their energy

sources, U.S. utilities continue to add more renewable power to their gen-eration portfolios. As a result, they must deal with a number of important issues, including resource availability that varies geographically.


U .S. utilities are integrating a growing number of renewable energy technolo-gies into their generation portfolios in

response to state renewable energy portfolio standards (RPS) mandates and several other criteria unique to their specific geographical locations. In light of the increasing impact that renewable energy sources are having on the utility industry, this year’s ELECTRIC POWER conference offered a session titled “Utility Perspectives on Renewable Pow-er—Panel Discussion,” which featured an animated exchange between the speakers and attendees (Figure 1).

Duke Energy’s Commitment to a Sustainable Future“Duke Energy continues to invest heav-ily in renewable energy to diversify our fuel mix and reduce our carbon footprint,” said Andrew Ritch, director, Renewable Energy Strategy & Compliance for Duke Energy Corp. “Nearly 40% of the energy we gener-ated in 2010 was from carbon-free resources, enough energy to supply approximately 5.3 million homes.”

Duke Energy is the third-largest producer of carbon-free generation among U.S. investor-owned utilities. The utility has an enterprise-wide goal to triple its renewable generation capacity—from approximately 1,000 MW today to 3,000 MW by 2020, he said.

Duke Energy taps a number of renewable sources. For example, in Indiana, it is pur-chasing the energy from a 100-MW wind farm. And in North Carolina, the utility buys power from the second-largest solar farm in the Southeast, a 15.5-MW facility located on a 357-acre site. In addition, in the first-of-its-kind program to be approved and completed in its service territory, Duke Energy will own and operate 10 MW of distributed solar gen-eration located on its customers’ rooftops and properties. Also in the renewable realm, Duke Energy has entered into an agreement with FLS Energy to purchase the renewable energy credits from the largest solar water

heating installation in the U.S. The utility has even launched Duke Ener-

gy Renewables, part of Duke Energy’s com-mercial businesses, which focuses on wind and solar projects.

“We launched our renewables business in 2007 with investments in wind energy. We now have approximately 986 MW of operat-ing wind projects at nine U.S. sites,” Ritch said. “Then Duke Energy Renewables entered into the commercial solar power business in 2009. Currently, we have three photovoltaic (PV) solar farms in operation.”

Duke Energy continues to forge strategic alliances with China to help it scale up and commercialize clean energy technologies. These partnerships represent the type of global collaboration that is needed to achieve economies of scale and drive down the cost of clean-energy technologies for a carbon-constrained world, according to Ritch.

From a utility’s perspective, these are the challenges related to renewables that Ritch sees:

■ Cost. Renewables can be more expensive (due to solar tax credit normalization re-quirements and customer rate pressure).

■ Scale. Projects are often small scale.■ Intermittency. Many renewables are avail-

able only on an intermittent basis (so they are not controllable) and need backup resources such as peaker plants fired by natural gas.

■ Location. Resource availability varies geographically, and resources are often a long distance from load centers.

■ Legislative requirements. The definition of “renewable” varies by state and is a matter of legislative language.

■ Interconnection to the grid. Line congestion and system balancing can be challenges.

Southern Co.’s Diverse Renewable Landscape Southern Co., which has approximately 42,514 MW of installed capacity, is currently involved in a diverse range of renewable proj-ects that include wind, solar, and biomass.

“Offshore wind may be the best large-scale wind generation option for Southern Co.,” said Jeffrey Wilson, research engineer in Research and Environmental Affairs for the company.

Southern Co. and Georgia Tech partnered on an extensive study of offshore wind po-tential in the Southeast, identifying and detailing several key challenges that must

1. Renewable track panelists. Left to right: Cochairs Vas Choudhry, a California-based con-sulting engineer with many years of experience in the electric utility industry, and Angela Neville, JD, senior editor of POWER; Andrew Ritch, director, Renewable Energy Strategy & Compliance, Duke Energy Corp.; Ryan Fair, manager of Project Development, Florida Power & Light; Jeffrey Wilson, research engineer in Research and Environmental Affairs, Southern Co.; and Daniel P. Breig, PE, director, Project Development Division, Southern California Edison. Source: POWER

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be addressed. That offshore wind feasibility study was com-pleted in 2007. Southern Co. is also preparing applications for federal leases to construct meteorological towers off the Georgia coast to collect data for assessing the potential for offshore wind generation.

Wilson explained that a wind turbine designed by students at the University of Alabama at Birmingham has been erected atop the Alabama Power headquarters building to collect re-search data. Wind data also is being collected at Navarre Beach, Fla., and in north Georgia.

Wilson described Southern Co.’s approach to using solar en-ergy by emphasizing that “we need to characterize and deter-mine issues with this variable technology.”

Alabama Power, a Southern Co. affiliate, and the Electric Power Research Institute (EPRI) are conducting a demonstra-tion of different solar PV technologies with microinverters at the Alabama Power headquarters. The four different 1-kW PV technologies are polycrystalline Si, monocrystalline Si, HIT (heterojunction with intrinsic thin layer) hybrid, and amor-phous Si thin film.

Likewise, Georgia Power, another Southern Co. utility, is partnering with EPRI in connection with an 18-month study to evaluate how solar PV power systems may affect the util-ity’s distribution system. Georgia Power is also involved in two other solar projects; it is conducting a demonstration of seven different solar PV technologies at its headquarters building, and it has received regulatory approval to build a 1-MW portfolio of medium-scale solar demonstration projects across the state.

Further afield, Southern Co. is partnering with Turner Re-newable Energy on a 30-MW solar PV power plant in Cimar-ron, N.M.

The company is also conducting research at several plants that looks at cofiring coal with wood chips, wood pellets, saw-dust, urban wood waste, peanut hulls, switchgrass, and other biomass to determine the costs and impacts of the process.

Alabama Power has been cofiring grass fuel materials with coal for nine years as part of normal operations at its Plant Gad-sden and has been comilling wood in various forms (including chips and sawdust) for eight years. Plant Gadsden’s direct in-jection system can cofire up to 10% biomass by energy at low loads and 5% at high loads. The facility recently tested the plant Giant Miscanthus as a fuel source.

In addition, Southern Co. has a renewable energy project under way with the Center for Energy Advancement through Technological Innovation (CEATI) to investigate the torrefac-tion market. Torrefaction, also known as biochar, is a process of roasting wood chips in a large furnace, but not to the point of becoming charcoal. Work is advancing to purchase 500 tons of torrefied wood for a test burn at Plant Gadsden. Southern Co. and CEATI hope that lab- and combustor-scale testing of the material will help them better understand the handling needs and risks associated with torrefied wood.

SCE: Promoting Renewable Energy in California“Southern California Edison (SCE) is an industry leader in re-newable energy, electric transportation, smart grid, and smart metering,” Daniel P. Breig, PE, director of SCE’s Project De-velopment Division, said.

The utility serves a population of 13 million people via 4.7 million business and residential accounts in a 50,000-square-mile service area within Central, Coastal, and Southern Cali-fornia. In 2010, SCE delivered approximately 14.5 billion kWh of renewable energy to customers.

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SCE’s 2010 energy resource mix breaks down as follows: natural gas (42%), nuclear (19%), eligible renewables (18%), coal (12%), and large hydro (9%). In the eligible renew-ables category, the subcategories are: geo-thermal (9%), wind (5%), biomass and waste (2%), solar (1%), and small hydro (1%).

Brieg explained that the 18% of eligible renewable resources that SCE uses exceeds the overall percentage of renewable resources (11%) used by California utilities. He further contrasted these percentages with the U.S. total for renewables, which is only 4%.

Brieg also discussed the average retail prices of electricity per kWh. These range from a low of $0.06 in Wyoming to a high of $0.21 in Hawaii; California’s average retail price is $0.13, he said. He pointed out that “the U.S. total average price per kilowatt-hour is 9.83 cents.” (Editor’s note: The latest average retail price of electricity in different sectors of the economy by state is available from the Energy Information Administration at http://bit.ly/mcobY9.)

“Are green jobs good or bad?” Brieg asked. He then answered by pointing out the pros and cons of jobs related to renewable energy. On the downside, green jobs add to the cost of renewable energy, so currently, renewables need subsidies to compete with traditional fossil fuels.

After pointing out these challenges, he focused on some encouraging developments. He noted that equipment suppliers are using robots to reduce labor and manufacturing costs. Installers are also innovating to reduce field labor. Operations are increasingly being designed for remote automatic operation. In

addition, to decrease maintenance, many re-newable energy technologies have no or few moving parts

As for the future of renewable energy in the U.S., Brieg described what he considered to be the important issues and barriers related to promoting the widespread use of these al-ternative technologies:

■ Resource availability■ The cost to electric ratepayers and taxpayers■ Grid integration■ The intermittent, variable nature of renew-

ables■ Transmission■ Connection Standard IEEE 1547

On the positive side, he pointed out that there is now “significant use of renewables in California and a decreased reliance on coal.”

FPL: Advancing a Clean Energy Economy“We believe it is our company’s duty to address climate change head-on and provide clean en-ergy today and for future generations,” said Ryan Fair, manager of Project Development at Florida Power & Light (FPL).

He explained that NextEra Energy is a large U.S. power company composed of two busi-nesses: NextEra Energy Resources, a whole-sale generator and U.S. leader in renewable generation, and FPL, one of the largest U.S. electric utilities, with 4.5 million customer ac-counts and 23,772 MW in operation.

NextEra Energy is the largest U.S. wind energy generator; it produces 8,078 MW of electricity. In addition, FPL has opened three

commercial-scale solar power plants in the Sunshine State (Florida) since 2009.

FPL’s three utility-scale solar facilities make Florida a leading U.S. producer of so-lar energy:

■ The Martin County 75-MW solar thermal facility. The Martin Next Generation So-lar Energy Center is the first hybrid solar facility in the world to connect to an exist-ing combined-cycle power plant. It is the largest thermal solar plant outside of Cali-fornia and generates enough electricity to serve about 11,000 homes. A photograph of this facility appears on the cover of this issue.

■ The DeSoto County 25-MW solar PV fa-cility. The DeSoto Next Generation So-lar Energy Center is one of the nation’s largest solar PV facilities. It uses more than 90,000 panels to turn the sun’s rays into electricity to power more than 3,000 homes, and the project created 400 con-struction jobs (Figure 2).

■ The Space Coast/Kennedy Space Center 10-MW solar PV facility. The Space Coast Next Generation Solar Energy Center was the first U.S. private/public partnership for a solar project.

Fair described the impact of one 100-MW solar plant based on statistics compiled by FPL:

■ Oil consumption avoided: approximately 700,000 barrels.

■ Cars removed from the road each year: 17,600.

■ Natural gas consumption avoided: 40 bil-lion cubic feet.

■ Greenhouse gas emissions avoided: 3 mil-lion tons.

■ Projected tax revenues: $50 million.■ Job creation: 4,000.

“If the state were to enable utilities to pursue renewable energy projects up to 2% of revenues, FPL would immediately begin construction of more than 500 MW of new solar projects,” Fair said.

Several FPL projects are permitted and shovel-ready. If these projects move for-ward, there is the potential for the creation of approximately 10,000 to 15,000 new di-rect and indirect jobs in the first three years, he explained.

Looking down the road, Fair emphasized the increasing importance of solar energy: “With a strong commitment from the state and investments by utilities, consumers, businesses, universities, etc., we can lay the groundwork for a clean energy economy.” ■


2. Record-setting plant. The 25-MW DeSoto Next Generation Solar Energy Center was a POWER 2010 Top Plant. A detailed profile of the facility is available in the December 2010 issue of POWER and in our archives at www.powermag.com. Courtesy: FPL




Sunny Days Ahead for SolarIn the U.S., developers of thermal and photovoltaic solar plants face a num-

ber of challenges in their efforts to deploy more utility-scale solar power. Some trends, however, are helping solar proponents move this renewable energy source closer to becoming a mainstream generating option.


From new technical innovations to the latest business developments, panelists at the ELECTRIC POWER session on

“Solar Power and Photovoltaics” offered a variety of perspectives about the new direc-tions that this energy source is taking in the U.S. (Figure 1).

Trends in Utility PV PlantsIn his presentation, “PV in the Utility Gen-eration Mix,” E.L. “Mick” McDaniel, senior director of utility sales with Suntech America Inc., focused on the growth of photovoltaic (PV) solar plants.

“Approximately 1.9 GW of large-scale PV solar projects are now under construction in North America,” he said. “Twelve plants larger than 50 MW have been completed within the last 12 months.”

Utility solar development is shifting to the U.S., according to McDaniel. Em-phasizing the growing momentum of PV projects in North America, he pointed out that the largest PV plant in the world, a 92-MW facility, came online last year in On-tario. In addition, he said that construction is under way on 10 plants that each will generate more than 100 MW of electricity. Meanwhile, “the PV pipeline currently has over 22 GW of projects.”

McDaniel also pointed to statistics that show the U.S. PV market is experiencing strong growth. For example, in 2010, U.S. utilities had 242 MW of PV solar energy ca-pacity. In contrast, by 2014, American utili-ties are projected to have approximately 2,508 MW of PV capacity.

McDaniel talked about the impact of mar-ket drivers on the U.S. solar sector. He first focused on policies that are having a positive effect on the growth of the solar market:

■ State renewable portfolio standards ■ Federal tax credits/cash grants■ State tax credits and/or renewable energy

credit programs

Then he focused on the stimulative effects on the solar market from “cost progress” drivers:

■ Declining system costs■ Declining development costs■ Increased speed of execution■ Lower cost of capital

Finally, McDaniel discussed how PV solar projects are moving along at a much faster rate than concentrated solar power (CSP, also known as thermal solar) projects. He provid-ed the following current U.S. statistics:

■ 538 PV solar projects and 518 CSP proj-ects have been completed.

■ 1,008 PV solar projects and 870 CSP proj-ects are under construction.

■ 21,000 PV solar projects and 8,060 CSP projects are under development.

Water System Design for Thermal Solar PlantsDaniel Sampson, senior technical consultant with Worley Parsons, emphasized the need to rethink the traditional water balance in thermal solar power plants in his paper, “Key Concepts in Thermal Solar Plant Water Systems Design.”

The operation and design of thermal solar power plants differs substantially from that of fossil fuel plants. The sun, rather than mar-kets, determines the maximum possible plant dispatch, explained Sampson.

“Ideal plant locations seldom include abundant or readily available water,” he said. “The design of the power island is complete-ly different from that of fossil plants, yet de-signers of thermal solar plant water systems often use the same principles and approaches common in their fossil plant cousins. This renewable technology requires fresh thinking in terms of water systems design.”

Unlike fossil plants, thermal solar plant operators can predict plant starts and stops to the minute. Water requirements, especially for the steam cycle, can be predicted with much more certainty than the water require-ments of variable-dispatch fossil plants.

Predictability may improve, but unique challenges remain:

■ Solar mirrors must be cleaned, so demin-eralized water usage increases.

■ Permits often require complete or partial-zero-liquid discharge, but this complicated equipment requires a substantial commit-ment in capital and manpower.

■ Plant water supplies may be of poor qual-ity, limited availability, difficult accessi-bility, and high cost.

Water system design is always a balancing act, and that’s especially true for thermal so-lar plants. Their unique design and operating profile present both opportunities and chal-lenges. Water quality and quantity must be evaluated carefully, and treatment processes must be designed around the unique thermal solar operating constraints. Simple designs are best, Sampson advised, because operat-ing cost and operator involvement are usually lower with simple designs. That’s true of pre-treatment, demineralization, and wastewater treatment systems.

New technology can provide benefits, but only after very careful consideration and risk mitigation. New approaches, nonetheless, must be used. In many cases, the tools don’t change, but they’re used differently and for different purposes. ■


1. Red-hot solar session. Members of the session panel were (left to right): E.L. “Mick” McDaniel, senior director of utility sales with Suntech America Inc.; Daniel Samp-son, senior technical consultant with Worley Parsons; Brian Friend, technical director, Doo-san Power Systems; and Brian Robertson, chief executive officer of Amonix Inc. Cochairs were Vas Choudhry, a California-based consult-ing engineer with many years of experience in the electric utility industry, and Angela Neville, JD, senior editor of POWER. Source: POWER

19_PWR_070111_Solar_p73.indd 73 6/16/11 2:31:00 PM


NEW PRODUCTS TO POWER YOUR BUSINESS

Spectrophotometer with Radio Frequency IdentificationHach Co. unveiled its DR 3900 spectrophotometer featuring state-of-the-art radio frequency identification (RFID) technology. Hach, which describes the device as being “similar to a GPS telling you when to turn,” also says that the DR 3900 requires less training and increases confidence in the test results. This helps water and wastewater facilities prevent measurement errors. The DR 3900 further simplifies water analysis by walking users through testing procedures to ensure consistently accurate results regardless of the user’s knowledge. The device allows for hands-free calibration updates and enables tracking of samples. It connects easily with any computer or water management system through one LAN and three USB ports. (www.hach.com/spectrophotometer)

New Winding Resistance Meter The Tettex 2293 from Swiss firm Haefely Test AG is the result of extensive research and years of experience testing transformers. A simple one-time-connection system, together with the simultaneous winding magnetization method (SWM), drastically reduces measuring time. The SWM guarantees fast and reliable measurements even on large power transformers with delta windings on the low-voltage side, where stable measurements can seldom be reached using traditional winding resistance measurement instruments, the company says. In addition, the new demagnetization function eliminates the magnetic remanence in the core after the application of a DC voltage. A full graphical interface with a 7-inch touch screen guides the operator through the test procedure. The unit visualizes each test cycle and displays the results graphically or in list format. (www.haefely.com)

Self-Recuperative BurnerEclipse Inc. introduced the TJSR v5 self-recuperative burner for direct-fired furnace heating applications. The advanced burner design combines a high-velocity flame with fuel-saving recuperation. A space-saving integral eductor pulls the furnace exhaust through an internal ceramic recuperator. The recuperator preheats the incoming combustion air to very high levels, which improves furnace operating efficiency to reduce fuel usage by as much as 50% over typical ambient air burners. The TJSR v5 design eliminates the need for the hot air ductwork required by external recuperators, providing savings in hardware and installation. The internally insulated heat

exchanger section and exhaust housing hold heat in the recuperative section, adding to the heat recovery efficiency. This also keeps external temperatures very low, providing better operator comfort and reduced thermal wear on associated equipment outside the furnace shell. The integrated gas and air orifices simplify burner piping, set-up, and adjustment. The TJSR V5 can be fired on natural gas, propane, or butane and is available in three sizes, with a maximum capacity ranging from 200,000 to 600,000 Btu/hr (60 to 175 kW). (www.eclipsenet.com)

20_PWR_070111_NP_p74-75.indd 74 6/16/11 2:32:35 PM


NEW PRODUCTS

Aerogel Coating for Surface InsulationMassachusetts-based Cabot Corp. recently introduced Enova, an aerogel that is a new high-performance thermal additive designed specifically for insulation coatings. Enova aerogel is designed for application to surfaces that are not already insulated but ideally should be. Cabot researchers have found that applying a 1-millimeter coating containing Enova aerogel to a 200C metal surface meets U.S. and European testing protocols for safe touch temperature, preventing the first-degree burns one would normally expect within five seconds of skin contact. This not only protects employees but also helps keep the pipe contents at desired temperature. Coatings containing Enova aerogel can also be used to insulate cold surfaces, helping to eliminate freezer burns and reduce the power requirements needed to keep contents cold. (www.cabot-corp.com)

Smart Grid–Ready Small Wind TurbineDistributed wind generator supplier Southwest Windpower unveiled a small wind turbine for commercial and residential use, the Skystream 600, which it claims is the “most efficient power grid-connected turbine in its class, providing an average of 7,400 kWh of clean, low-cost energy per year per household in 12 mph average annual wind speeds.” The company calls it the first fully smart grid–enabled wind turbine because, with its Skyview system, users can monitor exactly how much energy the wind turbine is producing from anywhere Internet access is available. It includes a larger blade design, enhanced software, and an improved integrated inverter. (www.windenergy.com)

Microgrid System ControllerEncorp LLC announced the launch of its Microgrid System Controller, which it says is the industry’s first microgrid system controller to connect onsite synchronous generators with renewable energy assets—such as photovoltaic systems, wind, and microturbines—and then monitor and control the resulting microgrid. The controller has already been successfully installed at a major international defense contractor site. It connects separate generator sets with inverter-based renewable sources, and it can interconnect a combined generation source to the utility grid or operate in island mode. (www.encorp.com).

Emergency Lighting Management SystemThomas & Betts’ Emergi-Lite Nexus Emergency Lighting Management System provides real-time status of the entire emergency lighting and exit-sign system, runs system diagnostics, performs required monthly and annual functional tests, generates maintenance logs, and runs compliance reports from a central control unit. Additionally, the system operates independently of the emergency lighting and exit sign, so that it does not interfere with operation of the lighting system or disrupt the power supply. Available in both wired and wireless versions, it is quick and easy to install. (www.nexus-system.com)

Inclusion in New Products does not imply endorsement by POWER magazine.

20_PWR_070111_NP_p74-75.indd 75 6/16/11 2:32:44 PM

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ADVERTISERS’ INDEXEnter reader service numbers on the FREE Product Information Source card in this issue.

ABB Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 . . . . . . . . . 14 www.abb.com/powergeneration

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Beumer Group. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 . . . . . . . . . 25 www.beumer.com

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ConocoPhillips . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 . . . . . . . . . . 3 www.conocophillipslubricants.com/PowerMag

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Fenner Dunlop. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 . . . . . . . . . 11 www.fennerdunlopamericas.com

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Hitachi Power Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 3 . . . . . . . . . 26 www.hitachipowersystems.us

IHS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 . . . . . . . . . 20 www.ihs.com

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Pennsylvania Crusher . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 . . . . . . . . . 17 www.penncrusher.com

Petro-Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 . . . . . . . . . . 8 www.petrovalve.com

Process Barron. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 . . . . . . . . . . 5 www.processbarron.com/power

ProEnergy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 . . . . . . . . . 16 www.proenergyservices.com/vision

Rentech Boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 2 . . . . . . . . . . 1 www.rentechboilers.com

Roberts & Schaefer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 4 . . . . . . . . . 27 www.r-s.com

Santee Cooper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 . . . . . . . . . . 6 www.santeecooper.com

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Siemens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 . . . . . . . . . . 2 www.siemens.com/energy/solutionsets

Thielsch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 . . . . . . . . . . 9 www.thielsch.com

Valtimet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 . . . . . . . . . 23 www.valtimet.com

Westinghouse. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 . . . . . . . . . 19 www.westinghousenuclear.com

CLASSIFIED ADVERTISINGPages 76-78. To place a classified ad, contact

Dianne Hammes, 713-343-1885, [email protected]

Page

Reader Service Number Page

Reader Service Number

3. FOR POWER PRODUCERS (check all that apply)What forms of energy are used at your power plants? For non-power producers, what forms of energy is your company interested in?o Coal – Ao Oil – Bo Natural Gas – Co Nuclear – Do Hydro – Eo Waste – Fo Renewables – Go Other________________________

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COMMENTARY

Geothermal Projects Race to Meet Incentives Deadlines By Leslie Blodgett

At the close of 2009, the U.S. geothermal industry had seen seven new geothermal power plants come online in the previous 12 months. In 2010, only one new power plant

was completed.That lone 2010 entry was the 15-MW Jersey Valley, Nev., proj-

ect developed by Ormat Technologies. The company noted that project construction was completed only a short time after all permits were granted, supporting one conclusion from a February geothermal finance meeting that permitting delays have been one of the biggest inhibitors of the industry’s growth.

Why the seeming slowdown, and what does it mean for geo-thermal energy’s future? The Geothermal Energy Association (GEA) sees a wave of development in the next few years, but beyond that, the industry may be subject to battles on Capital Hill regarding the nation’s economic and security challenges.

Project and Political Mismatches Geothermal-minded investors are getting mixed signals. The lead time for geothermal projects tends to be long and is not matched by the length of legislative incentives. If this disconnect is not corrected, it could jeopardize potential investment.

Even stimulus incentives are having a delayed impact: A majority of the geothermal projects designated for the $360.8 million geothermal allotment in the American Recovery and Re-investment Act have yet to be completed. But the U.S. Bureau of Land Management is hoping to hasten its permitting process. In March, it chose 19 renewable energy projects for priority status, including five geothermal projects.

And in terms of long-term policy, many states are stepping up to help. For example, California recently adopted a renew-able portfolio standard (RPS) target of 33% renewable energy by 2020. Long-term goals like the state RPSs help, but the start-and-stop nature of federal support undermines industry growth.

A Ticking Clock: Geothermal Incentives to ExpireSome projects under development may simply have to wait for clarity from Washington. For others, there will be a rush to cash in incentives for projects that can be completed and brought online by a 2013 deadline. That would mean a potential influx to the grid of hundreds of megawatts of new power.

According to an April GEA report, 3,102 MW of geothermal power are in production in nine states. About 756 MW to 772 MW are in ad-vanced (drilling/construction) stages of development. Many of these projects may be able to meet the current tax incentive deadlines.

Under current law, geothermal projects must be completed by December 31, 2013 in order to receive either the federal produc-tion tax credit or the investment tax credit. However, congres-sional leaders on both sides of the aisle hope to extend it. There is at least some chance Congress could act on some kind of tax or energy legislation this year.

As the champions of geothermal energy continue efforts to extend the deadline, investment decisions also will have to be made by private investors. “While the government incentive pro-grams may have given the geothermal space a lift in terms of initiating new activity, it’s going to take additional support from private investment to fuel the majority of the growth in years to come,” said Saf Dhillon, investor relations contact for U.S. Geothermal Inc., in April.

Some geothermal companies that have recently indicated they will meet the 2013 deadline: Gradient Resources, with its 60-MW Nevada Patua Binary Plant; Western GeoPower, with its 26-MW plant at The Geysers, Calif.; and Nevada Geothermal Power and Ormat Nevada, with their 30-MW Crump Geyser, Ore. plant.

For geothermal, it appears that “timing is everything.” When will credits expire or be expanded, how long will permits take, and what risk tolerance will investors have? Although there are many pieces to the puzzle, what national lawmakers need to address this year is the end-date for geothermal fed-eral tax incentives. Construction takes about two years; thus, many developers soon face a critical decision point about starting construction on projects that may not come online until after the current deadline.

A President’s Request: Invest in the Future The problems facing geothermal energy development are in line with those clouding Washington politics. But the prob-lems are worth fighting, because geothermal energy can com-bat climate change, the economic downturn, and the risk of nuclear disaster. For example, the tragedy of nuclear reactor meltdowns in Japan has spawned headlines such as “Geother-mal: A More Grounded Power Source for Japan?” (Time maga-zine blog piece) and “Analysis: Can Geothermal Help Japan in Crisis?” (Reuters). Japan has the third-highest capacity for geothermal energy production in the world, with 23.47 mil-lion kW (23.47 GW), after the U.S. and Indonesia.

However, in the U.S., deficit reduction debates have threatened clean energy programs. President Obama has repeatedly asked Congress and Americans not to let this happen. “We’re going to have to cut spending and ask everyone to share in the responsibil-ity,” he said in April in a town hall speech hosted by geothermal unit provider ElectraTherm. “But we need to make sure we’re also investing in the future. We’re not going to grow the economy by gutting investments in clean energy. America has always been the leader in innovation. Instead of subsidizing yesterday’s energy sources, let’s invest in tomorrow’s energy sources.”

Investments in geothermal energy fuel the baseload energy source of the future and deserve sustained, long-term support. ■

—Leslie Blodgett ([email protected]) is editor-in-chief of Geothermal Weekly, which is published by the

Geothermal Energy Association.

23_PWR_070111_Commentary_p80.indd 80 6/16/11 2:37:04 PM

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power - july 2011

Documents

nuclear power

station power

power industry executives

renewable resources

cleaner power plant

florida power light

coal handling

new trails