power magazine march 2014

March

2014 • Vo

l. 158 • No

. 3

Vol. 158 • No. 3 • March 2014

New Roles for Old Fossil Plants

Coping with Coal Combustion Residuals

From Waste to Fertilizer

Peru’s LNG Export Experience

Polygeneration’s Promise

We see what you can’t.

CIRCLE 1 ON READER SERVICE CARD

March 2014 | POWER www.powermag.com 1

On the coverBefore the 1950s-era Huntington Beach natural gas plant undergoes a complete modern-ization and facelift befitting a Los Angeles facility, it has taken on a completely new and critical role: grid support. Courtesy: Siemens Energy and Chet Williams Photography

COVER STORY: GRID SUPPORT30 AES Uses Synchronous Condensers for Grid Balancing

Especially as grids accommodate more intermittent renewable power and operate un-der increasingly stringent emissions regimes, some power plants may find that their highest and best use is something other than generating real power, or energy.

SPECIAL REPORT: THE FUTURE OF COAL-FIRED GENERATION36 Is Polygeneration the Future for Clean Coal?

Phones are no longer used just for making voice calls. In fact, many of us use mobile phones for a range of functions that have nothing to do with talking. A similar transi-tion to multifunctionality could become part of future coal power plants.

39 The Role of Activated Carbon in a Comprehensive MATS StrategyExtensive mercury monitoring at Southern Co. units suggests that, although unit-specific situations need to be considered, an engineered, or active, mercury control technology using advanced powdered activated carbon could help you comply with the Mercury and Air Toxics Standards.

44 Converting Sulfur from Flue Gas into FertilizerTurning coal combustion byproducts into saleable materials is nothing new, but as the cost of complying with environmental regulations escalates, the business case for new and improved reuse options is likely to improve.

47 Be Prepared for Coal Ash RegulationsCould this, finally, be the year the Environmental Protection Agency finalizes rules for coal combustion residuals? The compliance schedule will be tight when a deci-sion is made, so evaluate your options now.

Established 1882 • Vol. 158 • No. 3 March 2014

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www.powermag.com POWER | March 20144

FEATURES

OPERATIONS & MAINTENANCE

51 Adaptive Brush Seals Restore Air Preheater PerformanceAir preheater seal degradation is difficult to identify and often overlooked as respon-sible for loss of fan margin, loss in boiler efficiency, problems with downstream air quality control equipment, and lost revenue. This case study demonstrates how a newer type of seal can solve those problems.

54 Modern Polymeric Materials Offer Options for Equipment RepairHydropower plant maintenance has been challenged in recent years by water avail-ability—just as the availability of hydropower is becoming increasingly important to the supply mix. The right coatings can maximize runtime and minimize maintenance headaches.

SUPPLY CHAINS

58 The Future of Utility Supply Chain ManagementIn the face of heightened concerns about recovery from natural disasters, the cy-bersecurity of equipment coming from vendors around the globe, and cost contain-ment, no generator can afford to forego supply chain improvements.

FUEL SUPPLIES

62 The LNG Export Debate: Lessons from PeruThe U.S. isn’t the first nation to consider the pros and cons of exporting large amounts of natural gas. Though every scenario is different, there are lessons to be learned from Peru’s decade of developing its liquefied natural gas (LNG) infra-structure.

INDUSTRY TRENDS

65 Facing Challenges from Natural Disasters to Customers as GeneratorsThe number of disruptive forces faced by the electric power industry seems to be growing exponentially. Here’s how some of the key speakers at April’s ELECTRIC POWER see the major developing trends.

DEPARTMENTS

SPEAKING OF POWER8 What Is a Fossil Power Plant?

GLOBAL MONITOR10 Forced Closure of Nuclear Plant Is Unlawful, German Supreme Court Rules10 The Advent of Flexible Coal12 MHI, Southern Co. Complete Demonstration Phase of CCS Test 14 THE BIG PICTURE: Coal’s Export Future17 Statkraft Shelves Osmotic Power Project18 Developing the World’s First Magma-Enhanced Geothermal System19 POWER Digest

FOCUS ON O&M22 Customized Storage Solution Improves Efficiency24 Practical Considerations for Converting Industrial Coal Boilers to Natural Gas

LEGAL & REGULATORY28 When States Try to Manipulate Wholesale Power Markets

By Thomas W. Overton, JD

COMMENTARY76 America Needs Continued Coal Use

By Mike Duncan, president and CEO, American Coalition for Clean Coal Electricity

54

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Putting Nature to Work

A utility client was looking for ways to reduce selenium

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WHERE WATER and POWER MEETCUSTOMIZED WATER SOLUTIONS THAT F IT YOUR POWER PLANT

Chris is a recognized technical leader in landfi ll design and coal

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SPEAKING OF POWER

That question isn’t as flippant as it may sound. If you look at the type of plant that’s familiar to the gen-

eration of power industry personnel who have retirement within view and compare it with the sort of facilities the incoming generation of workers will be operating, you might be surprised.

It’s not just a matter of more digitized and remotely monitored power plant sys-tems. The new definition of a fossil plant is likely to include everything from plants whose main function is something other than power generation to those whose fuel source can switch from coal to gas to biomass to hydrogen.

New Missions

Power plants produce power. That would seem self-evident, but it’s no longer universally true. As our cover story on the AES Huntington Beach plant demon-strates, a formerly conventional gas-fired plant can step into an entirely new role (with relatively little prep time)—oper-ating synchronous condensers to support less-predictable clean energy sources on the grid.

Polygeneration—the production of sale-able byproducts in addition to electricity—is another scenario for a vastly different sort of fossil-fired plant, as explained in “Is Polygeneration the Future for Clean Coal?” Even without polygeneration, generators are exploring their options for revenue-generating byproducts (see “Converting Sulfur from Flue Gas into Fertilizer”).

A major advantage of gas-fired gen-eration is its greater operating flexibility, compared with coal units. But it’s not just gas plants that are being called on to operate more flexibly these days. (This won’t be news to those of you who have already been forced to cycle coal plants in response to low capacity margins and high wind integration.) Our Global Monitor story “The Advent of Flexible Coal” looks at how, with minimal equipment modifi-cations but more significant changes in operational practices, formerly baseload generating plants can add value in an energy system that is more dynamic from points of generation to points of electric-

ity use. In fact, in Germany, where new coal-fired plants are being built along with renewable generation, baseload de-signs are out; flexibility is in.

Yes, there is a cost to this new way of operating, but there’s one sort of cost or another to every energy mix. For reliabil-ity, fuel-hedging, and other reasons, flex-ible operation may be just the ticket for life-extension of U.S. coal plants “on the bubble” for retirement.

Then there are plants that can fuel-switch or cofire multiple fuels, as you’ve seen in previous issues of POWER. Why would anyone (at least in the U.S.) con-sider modifications to enable fuel switch-ing when there’s an abundance of shale gas? Anyone who has watched natural gas prices this winter can answer that.

The Costs of Overreliance on Gas

Remember the fevered excitement over U.S. shale gas reserves and the widespread pre-dictions of low natural gas prices as far as the eye can see? Well, the markets didn’t get that memo. Natural gas futures prices hit a four-year high in January. Then, on Feb. 6 in the cash market, Henry Hub gas for next-day delivery traded as high as $9/MMBtu—higher than any time since Au-gust 2008—and closed at $7.18. Multiple rounds with the Polar Vortex can be blamed, but this isn’t the first cold winter in U.S. history, and it won’t be the last. Compa-nies building new capacity with an eye on long planning horizons and long asset life spans, as well as politicians and regulators influencing the mix of new capacity, should be able to understand that simple fact.

Though analysts worried that a surge of production would exhaust natural gas storage capacity in 2013, the U.S. Energy Information Administration (EIA) reported that weather-related record high withdraw-als from storage early in 2014 have led to

record low storage levels. As a result, the EIA said, “working gas levels in the Lower 48 states fell below the minimum storage level for the same week in the previous 5-years for the first time since EIA started reporting the statistic in 2004.”

The East has felt the cold and the supply pinch the worst. When PJM asked custom-ers in southwestern Pennsylvania to con-serve electricity during the mid-January deep freeze because it was worried about

being able to meet demand, Pittsburgh media reported that some citizens and lawmakers were wondering if PJM, which had promised reliability would not be jeopardized by shuttering two coal-fired power plants last fall, acted too hastily in that decision. I’m not about to adjudicate that decision, but we may be reaching the point where public utility commissions and federal regulators need to switch up their games to ensure that fossil plants are not unduly penalized in the market or by compliance requirements for providing flexible service.

Does Coal Have a Future?

Yes, coal-fired generation has a future, but it won’t look like its past. It will be different worldwide for a host of rea-sons, from the need to manage water resources more efficiently, to compli-ance with emissions requirements, to a new generation of workers who expect a technology assist in virtually every daily activity—from tooth brushing to bank-ing to boiler operation.

Adapting to new modes of operation won’t always be easy, but there are oppor-tunities for new businesses and for smart, flexible companies to reshape the future of fossil generation. ■

—Gail Reitenbach, PhD is editor of POWER. Follow her @GailReit and the

editorial team @POWERmagazine.

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Forced Closure of Nuclear Plant Is Unlawful, German Supreme Court RulesIn a ruling that could have reverberating implications for nuclear generators, Ger-many’s highest administrative law court upheld a lower court’s finding that de-clared unlawful the State of Hesse’s de-cision to shut down RWE’s Biblis A and B nuclear plants during the three-month nuclear moratorium in 2011.

The Federal Administrative Court in Leipzig—one of Germany’s five supreme courts—this January dismissed the State of Hesse’s appeals against two rulings by the Higher Administrative Court of Hesse. That court found that the state ministry had no legal grounds when it ordered, on decree from Angela Merkel’s administra-tion, the shutdown of two Biblis reactors on March 18, 2011—just days after the Fukushima disaster in Japan.

At that time, operations were also halt-ed at five other reactors across the country that were built before 1980—Neckarwes-theim 1, Brunsbüttel, Isar 1, Unterweser, and Philippsburg 1—as well as Vatten-fall and E.ON’s jointly owned 1994-com-missioned Krümmel nuclear power plant, which was offline at the time.

But the Fukushima nuclear disaster also prompted the central government to rethink its December 2010 decision to extend the lifespans of all German nuclear power plants

by an average of 12 years. Later, an amend-ment to the Nuclear Power Act in August 2011 mandated that eight of the country’s 17 reactors remain shuttered permanently and that the remaining nine reactors be de-commissioned by the end of 2022.

In the lower court decision in February 2013, the Higher Administrative Court of Hesse ruled that RWE had not been prop-erly heard before the shutdown orders were issued. But it also said the order was unlawful because the Environment Minis-try had exceeded its discretionary author-ity. In January, the Federal Administrative Court dismissed the State of Hesse’s appeal because it had not convinced the court on why RWE had not been heard before the shutdown orders were issued.

The decision opens an avenue for nu-clear generators to seek damages before a civil court against the states of Hesse, Lower Saxony, Bavaria, and Baden-Wuert-temberg, which forced the eight plants to shut down during the moratorium.

Only RWE, the one utility to have le-gally challenged the forced closure of the Biblis units (Figure 1), is preparing to take action against the State of Hesse. RWE estimates that decommissioning the Biblis reactors could cost more than €1.5 billion, though industry analysts estimate RWE may file for an estimated €187 mil-lion in damages as a consequence of the shutdown. The Biblis reactors, each 1.2

GW, had been licensed in December 2010 to operate until 2019 and 2021.

Germany’s Federal Constitutional Court, meanwhile, is reviewing constitutional com-plaints by E.ON, RWE, and Vattenfall con-cerning Germany’s plan to exit nuclear power entirely by 2022. That decision, which could come this year, could have larger repercus-sions for the Energiewende, or energy tran-sition, which requires the power-intensive nation to massively increase its reliance on renewable generation.

The Advent of Flexible CoalThe increasing penetration of intermit-tent renewable generation, smart grids, demand response, and other emerging technologies has underscored the need for power plants with greater flexibility and efficiency—and one surprising solution could come from new and existing coal plants, suggests a new study from the U.S. National Renewable Energy Laboratory and Intertek for 21st Century Power Partner-ship.

Coal plants, says the report, “Flexible Coal: Evolution from Baseload to Peak-ing Plant,” though widely perceived to provide only baseload generation, can be modified to cycle on and off and run at lower output (below 40% of capacity). The document details a demonstration to in-crease flexibility at a North American coal generating station—which is unnamed for “commercial reasons”—a feat that requires “limited hardware modifications but extensive modifications to operational practice,” it claims.

“Cycling does damage the plant and im-pact its life expectancy compared to base-load operations. Nevertheless, strategic modifications, proactive inspections, and training programs, among other operational changes to accommodate cycling, can min-imize the extent of damage and optimize the cost of maintenance,” it says.

According to the report, the plant was originally intended to run as a baseload unit at an 80% annual capacity factor when it came online in the 1970s, but it has “at times cycled on and off as many as four times a day to meet morning and afternoon peak demand.” The authors add that “The overarching impact of this type of cycling is thermal fatigue but also stresses on components and turbine shells resulting from changing pressures, wear

1. Unlawfully shut down. The forced closure of two reactors at RWE’s Biblis Nuclear

Power Plant in the State of Hesse during the 2011 nuclear moratorium was unlawful, a German

supreme court ruled in January. This image shows Biblis A on the right and Biblis B on the left in

2010. That year, Biblis A and B, which began commercial operation in 1974 and 1976 respectively,

were licensed to operate until 2019 and 2021. Courtesy: Peter Stehlik

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and tear on auxiliary equipment used dur-ing cycling, and corrosion caused by oxy-gen entering the system and condensation from cooling steam.” Those consequences of cycling can take several years to show up as damage or forced outages.

Several physical modifications were made to the boilers, pulverizers, turbines, rotors, and condensers at the plant, but once the physical changes were in place, “90% of future savings in costs came from adjustments to operating proce-dures,” the report reveals. For example, establishing procedures and training to control boiler ramp rates has been espe-cially effective, as have been high-energy piping inspections.

The report echoes several conclusions reached by a number of prominent ana-lytical entities, and it likewise suggests that if modified to be more flexible, older coal units can still serve a purpose in an increasingly low-carbon energy system.

Most coal power plants are “capable of some dynamic operation and are designed to be able to cycle with moderate ramp rates and potentially even handle two-shift oper-ation (where the plant is started up and shut down daily),” observes the International En-ergy Agency’s Coal Industry Advisory Board (CIAB) in a 2013 report titled “21st Century Coal: Advanced Technology and Global En-ergy Solution.” However, the increased need for flexibility “will impact costs, mainte-

nance, and reliability,” the CIAB also con-cludes.

“Most notably, higher cycling will in-crease wear and tear while the number of operating hours decreases, resulting in an increase of specific maintenance costs/MW-hr over time. Moreover, as coal power plants add more complex environmental control systems such as [carbon capture and storage] in the future, their ability to operate dynamically may be reduced,” the CIAB says.

Yet, as illustrated by some countries with a high share of intermittent renew-ables, if a portfolio of strategies involving both technical and operational improve-ments is implemented, the flexibility of current and future coal plants can be achieved, the CIAB suggests.

One prominent example is Germany, which is moving to produce 80% of its power with renewables by 2050. A tenfold increase in wind and solar photovoltaic ca-pacity in Germany since 2000 has resulted in a second “feed in” load fluctuation in addition to the traditional consumer de-mand fluctuation.

Meanwhile, in a much-cited paradox for the country that is promoting a massive shift to renewables with billions of eu-ros in subsidies, Germany’s production of coal-fired power rose in 2013 to its high-est level since 1990 as natural gas prices soared. Last November, Steag opened its

725-MW Walsum-10 unit near the west-ern city of Dortmund, and Trianel started commercial operation of a 750-MW Lünen plant (Figure 2) in North Rhine-Westphalia in December. Meanwhile, eight hard coal power plants are scheduled to begin op-eration in the next two years, including Vattenfall’s 1.5-GW Moorburg plant near Hamburg and RWE’s Hamm facility in the Dortmund area.

According to the CIAB, Germany’s ex-isting power plants are optimized “to cater to flexible operation,” even if they were built before expansion targets for wind and photovoltaic plants had been adopted. “In many plants, measures to allow greater flexibility have been im-plemented subsequently, so that power plants can meet increased requirements for market load adjustments. As a result, there are very few baseload plants that do not allow for flexible operation, it notes. At the same time, new coal-fired power plants are specifically designed for flexible operation. “Pure baseload power plants are no longer being built.”

The CIAB notes, however, that Germa-ny also suffers higher electricity prices than most developed countries. That means the impact of increased costs due to the fluctuating operation of conven-tional power plants is “somewhat less significant,” it says.

MHI, Southern Co. Complete Demonstration Phase of CCS TestMitsubishi Heavy Industries Ltd. (MHI) and Southern Co. have completed the initial demonstration phase of a carbon capture and storage (CCS) test at the Plant Barry power station in Mobile, Ala.

The companies built a 25-MW carbon capture demonstration plant, consisting of a flue gas scrubber, flue gas carbon di-oxide (CO2) capture/regeneration system, CO2 compression machinery, and electrical components, adjacent to the seven-unit James M. Barry Plant owned by South-ern subsidiary Alabama Power (Figure 3). Notably, the facility employs the KM CDR Process, which uses a proprietary KS-1 high-performance solvent for CO2 absorp-tion and desorption that was jointly devel-oped by MHI and Japanese utility Kansai Electric Power Co. and is said to use less energy than comparable systems.

Testing of the facility’s carbon capture capabilities, which the developers say is a “globally unprecedented” 500 metric tons per day (mtpd), began in June 2011. Inte-

2. Hard but flexible coal. The 750-MW Lünen hard coal–fired power plant owned by Tri-

anel Kohlkraftwerk Lünen came online in December 2013 in northwest Germany and is predicted

to run 7,000 full-load operating hours in 2014. Siemens Energy and IHI Corp., which built the turn-

key plant, say it has an efficiency of almost 46%. The plant’s Siemens SST5-6000 steam turbine

is designed to enable highly responsive ramping, which is crucial to meeting load adjustments

posed by intermittent renewable generation. Courtesy: Siemens Energy


The combination of substantial growth in total world coal trade, strong pricing for both coking and steam coals abroad, and the declining demand for coal in the U.S. power sector has sparked a surge in activity and investment to facilitate the growth of U.S. coal exports. Source: U.S. Energy Information Administration —Copy and artwork by Sonal Patel, a POWER associate editor

SHIFTING MARKETS

1-20 21-40 41-60 61-80 81-100 101-120 121-140 141-160 161-180

World Steam Coal Import Demand (million metric tons of coal equivalent) No data >180

1,146 1,171

2007 2008 2009 2010 2011 2012

1,045

-21%

1,040 933 975 932 824

1,074 1,084 1,095 1,016

(in m

illion s

hort

tons)

-11%

832

1,046

889

1,119

940

1,177

2015 2025 2040

13%13%

FALLING U.S. POWER SECTOR COAL CONSUMPTION

In 2012, the U.S. shipped a record-breaking 114 million metric tons (MMT) of coal to international markets—not just to Canada, where between 31% and 48% of U.S. coal had typically gone in the mid-2000s—making the U.S. the world's third-largest coal exporter. U.S. coal exports are fairly evenly divided between coking and steam coal. Note: * denotes steam coal exports.

U.S. coal production declined in 2012 to its lowest level in almost two decades. But U.S. coal consumption also sank in 2012 to its lowest level since 1988 as consumption from the coal industry’s largest consuming sector—U.S. coal-fired power plants—fell. U.S. coal exports are slated to increase 58% from about 107 million short tons in 2011 to 169 million short tons in 2040, buoyed by the overall increase in world coal trade. Production and consumption could increase by an average 0.6% per year through 2040 as electricity demand swells, natural gas prices rise, and the share of exports grows.

Coal consumption

by U.S. electric

power sector

U.S. Coal production

Share of U.S. coal

exports

8%14%12%

5%

2012

ASIA AMERICASEUROPE/MIDDLE

EAST/AFRICA

59%(20.3 MMT*)19%

(6.5 MMT*)

21%(7.4 MMT*)

2040

ASIA AMERICASEUROPE/MIDDLE

EAST/AFRICA

62%(57 MMT*)36%

(33.4 MMT*)2%

(2.3 MMT*)

THE BIG PICTURE: Coal’s Export Future

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grated capture and sequestration demonstration testing began in August 2012. The test confirmed “[h]igh-performance continu-ous and stable operation of the large-scale CO2 recovery plant,” MHI said in a statement to POWER.

Southern Co. and MHI are now discussing additional demon-stration phase activities using the plant. MHI also said it would “accelerate its program” that seeks to achieve commercially viable technology for recovering CO2 from the flue gas of coal-fired plants.

Richard Esposito of Southern Co.’s Advanced Energy Systems Research & Technology Management arm told the Wyoming Infra-structure Authority in January that the plant’s demonstration in-volves a 12-mile CO2 pipeline built by Denbury Resources as well as CO2 injection into a deep saline formation above the Citronelle Oil Field. So far, about 200,000 tons of CO2 has been captured (a recovery efficiency of above 90% at a purity of 99.97%) and 100,000 tons has been injected.

Southern Co. is meanwhile building a CCS-ready 582-MW in-tegrated gasification combined cycle (IGCC) plant in Kemper County, Miss., that is expected to capture 65% of its CO2 emis-sions, most of which will be transported by a completed 60-mile pipeline and used for enhanced oil recovery. That plant is slated to go into operation later this year.

January also marked milestones for a number of federally backed CCS ventures. The Department of Energy (DOE) formally committed $1 billion to its long-stalled FutureGen 2.0 project proposed for Meredosia, Ill. That project, whose total estimated cost is $1.68 billion, seeks to upgrade a unit of Ameren Energy’s Meredosia Energy Center. The repowered 168-MWe unit will in-clude oxycombustion and carbon capture technologies designed to capture at least 90% of its CO2 emissions during “steady state” operation.

The performance of CCS technology is also being tracked at the 400-MW Texas Clean Energy Project (TCEP) IGCC and 405-MW Hy-drogen Energy California (HECA) IGCC facilities—but the future of both those projects is uncertain. TCEP and HECA are two of only three active DOE Round 3 Clean Coal Power initiative projects (the third is NRG Energy’s post-combustion demonstration at the W.A. Parish plant in Texas). San Antonio, Texas–based CPS Energy

allowed a key power purchase agreement with Summit’s TCEP to expire at the end of 2013, citing delays and a changing energy landscape. California regulators are reviewing the HECA project. (For more on the TCEP and HECA projects, see “Is Polygeneration the Future for Clean Coal?” in this issue.)

Statkraft Shelves Osmotic Power ProjectNorwegian power company Statkraft has shelved its much-watched effort to harness energy from pressure-retarded osmosis (PRO). It said in a rare industry admission that the technology could not be sufficiently developed within the current market outlook to become competitive “within the foreseeable future.”

The company has been working on osmotic power for more than a decade. After years of collaborative research and devel-opment with the Norwegian University of Science and Technol-ogy, Statkraft in 2009 started up one of the world’s first osmotic power plants at Tofte on the Oslo Fjord in Norway, a facility that produced 2 kW to 4 kW (Figure 4).

The prototype operated on the PRO process, which involves pumping seawater at 60% to 85% of the osmotic pressure against one side of semipermeable membranes whose other side is ex-posed to freshwater. When freshwater, compelled by osmosis, flows across the membranes, it dilutes the saltwater and increases its volume—and consequently, the pressure within the saltwater chamber. A turbine is spun as the pressure is compensated, driv-ing a connected generator. PRO can be thought of as the reverse osmosis process (used for desalination and water treatment) run-ning backward and producing power from the flow of saltwater.

3. A test plant. Mitsubishi Heavy Industries and Southern Co.

have completed the initial demonstration phase of a carbon capture

and storage test at Plant Barry in Mobile, Ala. Courtesy: Southern Co.

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As early as last September, Statkraft was reportedly assessing a location for a possible 1-MW to 2-MW pilot osmotic power facility. In December, however, the company declared it was discontinuing its efforts and leaving the technology development to “other play-ers in the global market.”

“Our main challenge has been to make the technology efficient enough to achieve energy production costs on par with compet-ing technologies,” said Statkraft department manager Stein Erik Skilhagen. “There are other technologies which have developed enormously in recent years. These are more competitive and rel-evant investments for us in the future,” he said.

Statkraft, which is Europe’s largest generator of renewable power, noted investor interest in osmotic power has been slug-gish since the idea to exploit osmotic pressure for energy was conceived by a U.S. scientist in the 1970s. “A quarter of a century had to pass before market conditions made several independent public and private enterprises take up the idea and start develop-ing the technology further,” it said.

Yet, the company stressed that it had proven that the technol-ogy, which it had substantially improved, “works.” It also said that the technology can be used in other applications such as the production of potable water. “We are now leaving the process of maturing the technology to others, as several independent public and private enterprises around the world are looking into this already,” Skilhagen said.

Developing the Word’s First Magma-Enhanced Geothermal System In 2009, when the first borehole in a series of wells was drilled as part of the Icelandic Deep Drilling Project (IDDP) in Krafla, north-east Iceland (Figure 5), it unexpectedly penetrated into magma with a temperature of between 900C and 1,000C at a depth of only 2,100 meters (m). Further investigation of the borehole,

IDDP-1, has led to the development of a unique geothermal proj-ect that supplies heat directly from magma.

“Drilling into magma is a very rare occurrence anywhere in the world, and this is only the second known instance, the first one, in 2007, being in Hawaii,” noted Wilfred Elders, a professor emeritus of geology at the University of California, Riverside who edited a special issue of the international journal Geothermics that was dedicated to the scientific and engineering findings arising from a two-year-long observation period at the unique borehole.

Bearing part of the substantial costs involved, the IDDP—com-prising HS Energy, Reykjavik Energy, Iceland’s National Power Co., and the National Energy Authority of Iceland—pumped cold water into the hole to fracture rock near the magma and create high per-meability. Next, they cemented a steel casing into the well that was perforated in the bottom section closest to the magma. Then, they allowed the hole to heat slowly. Eventually, high-pressure steam at temperatures of more than 450C, a measured output that was suf-ficient for 36 MW, was allowed to flow out of the hole for two years until July 2012, when it was closed due to a valve failure.

5. Ice and steam. The Icelandic Deep Drilling Project has success-

fully drilled down into molten rock and fed superheated steam from the

well to the 60-MW Krafla geothermal power plant. This image shows the

drill site of IDDP-1 well, which is near the volcanic explosion crater Viti.

Viti last erupted in 1724. Courtesy: Guðmundur Ó. Friðleifsson

6. Not just hot rock, magma. This image shows the flow test

of the IDDP-1 well. Courtesy: Kristján Einarsson

4. An impermeable effort. Statkraft’s project to produce pow-

er by exploiting the salinity gradient between seawater and freshwater

has been shelved because it wouldn’t likely become competitive. The

effort, which it passed on to the “global market,” means the compa-

ny won’t expand its prototype facility (shown here) in Tofte, Norway,

which produced 2 kW to 4 kW. Courtesy: Statkraft


According to Elders, the feat of being able to drill down into the magma despite difficulties—and to control it—is impressive. Perhaps more importantly, the well, which created a world record for geothermal heat, produced steam (Figure 6) that could be fed directly into National Power’s 60-MW Krafla geothermal power plant near the Krafla Volcano. The team was also able to cope with a “difficult chemical composition of steam” from the well with “simple countermeasures.”

The IDDP-1 experiment demonstrated that a high-enthalpy geothermal system can be successfully created this way, he said. “This unique engineered geothermal system is the world’s first to supply heat directly from a molten magma.”

Around the world, several large-scale field projects that use enhanced geothermal systems (EGS)—an engineered heat ex-changer designed to extract geothermal energy by fracturing hot rock at depths of 4 kilometers or more—have reached varying degrees of success. Only one project—the 2007-commissioned 3.2-MW Landau project in Germany—has sustained commercial production rates. EGS has been stalled by a variety of issues, foremost among them an exponentially higher power cost than for fossil-fueled generation, owing to expenses associated with drilling of deep geothermal wells, experts say.

The Krafla experiment was not without setbacks that “tried personnel and equipment throughout,” Elders said. Much remains to be done. The next steps entail repairing the IDDP-1 well—which is currently “unstable”—or drilling a new similar hole. The IDDP could drill the next borehole, IDDP-2, in southwest Iceland at Reykjanes between 2014 and 2015.

POWER DigestSouth Korea OKs $7B Plan for New Shin Kori Reactors. Only two weeks after South Korea announced plans to cut the share of nuclear in its total future power supply to 29% by 2035 instead of 41% by 2030, the government approved a $7 billion project to complete two 1,400-MW reactors by late 2020 at Shin Kori in the southeast portion of the country. Construction of the two APR-1400 units at Shin Kori 5 and 6 could begin this September and early next year, respectively. A documentation scandal has prompt-ed a series of nuclear reactor shutdowns since late 2012, leaving a country that imports 97% of its energy needs critically power-short.

Though it drastically cut targets for new nuclear power, the country still intends to build at least 16 new domestic reac-tors, and it is promoting sales overseas. The consortium to build the new nuclear units will be led by state-owned South Korean power company KEPCO and includes Doosan Heavy Industries & Construction Co., Samsung C&T Corp., Hyundai Engineering & Construction Co., and Westinghouse Electric Co., which is owned by Japan’s Toshiba Corp.

Senate Passes Bill to Extend 123 Agreement with South Korea. The U.S. Senate on Jan. 27 passed a bill extending a civilian nuclear cooperation agreement with South Korea by two years until Mar. 19, 2016. Talks to renew the so-called “123 Agreement,” which was set to expire in March 2014, had faltered as Seoul pushed to get Washington’s consent to enrich uranium and reprocess spent fuel. The agreement is pivotal for South Ko-rea’s plans to export 80 domestically designed nuclear reactors by 2030. (For more, see “South Korea Ramps Up Nuclear Exports”: http://bit.ly/1ev2rCo).

U.S. companies can only obtain export licenses for nuclear equipment or materials from countries with which the U.S. has

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concluded a bilateral agreement for civil nuclear trade. The U.S. has Section 123 agreements in place with 21 countries, the European Union, and the International Atomic Energy Agency, but seven of those agreements, including those with South Korea, Taiwan, and China, are set to ex-pire by 2015.

Alstom to Supply Two Ultrasuper-critical Units for Polish Plant. Alstom on Jan. 31 signed contracts worth €1.25 billion with a consortium comprising Polimex, Rafako, and Mostostal Warsa-wa, for the supply of two 900-MW ultra-supercritical (USC) coal-fired units for a power plant owned by Polish utility Pol-ska Grupa Energetyczna in Opole, south-western Poland. Alstom’s scope includes the provision of its proprietary USC tech-nology, including the supply of USC boiler islands; the steam turbine generator is-lands, including the turbine hall equip-ment; the air quality control systems; as well as some balance-of-plant systems. Al-stom previously retrofitted Units 2, 3, and 4 at Opole. The new units are expected to become commercially operational between 2018 and 2019.

Japan Approves TEPCO’s Revival Plan. Japan’s government on Jan. 15 ap-proved a plan to revive and restructure the Tokyo Electric Power Co. (TEPCO), owner of the tsunami-devastated Fukushima Dai-ichi power plant. Under the plan, TEPCO will receive another ¥4 trillion ($38.8 billion) in

state funding. It also allows for progressive privatization of the government’s 50.1% stake in the company starting in the mid-2020s. The Japanese government acquired the majority share in the company in 2012 to help it avoid bankruptcy.

In January, TEPCO said it hopes to restart all seven reactors at its Kashiwazaki-Kariwa plant by 2017. None of Japan’s 48 reactors are currently operating since Ohi 3 and 4 were taken offline in September 2013 for scheduled maintenance and inspections. The operators of at least 16 reactors have applied to Japan’s Nuclear Regulation Au-thority for a safety assessment to verify compliance with post-Fukushima safety standards and move toward restart.

Decommissioning of the Fukushima facility, meanwhile, is expected to cost around $20 billion and take 40 years to complete. TEPCO plans to build a coal-fired power plant in the prefecture as well as a number of research and devel-opment facilities.

MHI Gets First U.S. Order for J-Se-ries Gas Turbine. Marking its first U.S. order for a J-Series gas turbine, Mitsubishi Heavy Industries (MHI) on Jan. 29 was selected to supply an M501J gas turbine for the Chouteau power station, which is owned by Oklahoma state-owned util-ity Grand River Dam Authority (GRDA). The 495-MW gas turbine combined cycle plant to be built at the facility in Chou-teau east of Tulsa is scheduled to become

operational in March 2017. Along with an M501J gas turbine, plant components that MHI will supply to GRDA include an SRT-50 steam turbine and a generator. The gas turbine will be manufactured at Savannah Machinery Works in Savannah, Ga., which is MHI’s manufacturing base in the U.S.

Including the GRDA order, MHI has secured orders for 28 J-Series gas tur-bine units. Developed in 2009 by MHI, nine J-Series gas turbines are in opera-tion worldwide.

DONG Energy Divests 25% Stake in London Array. Denmark’s DONG En-ergy on Jan. 31 inked a $1 billion deal to sell half of its 50% share in the 630-MW London Array 1 offshore wind farm in the UK to Canadian institutional fund manager La Caisse de dépôt et placement du Québec. La Caisse will now hold a 25% stake along with DONG Energy (25%), E.ON (30%), and Mas-dar (20%) in the 175-turbine project, currently the world’s largest offshore wind farm.

India Clears Key Power Projects for Timely Approvals. India’s Cabi-net Committee on Investment cleared three hydropower projects in Arunachal Pradesh and Sikkim whose development had been stalled by environmental con-cerns. At the same meeting, the central government body that was established only a year ago to identify key infra-structure projects and prescribe time limits for the issuance of approvals and clearances by government minis-tries cleared Reliance Power’s 4-GW Jharkhand coal-fired Ultra Mega Power Project. The hydropower projects are Tawang (800 MW), Tato (700 MW), and Teesta (520 MW).

Vattenfall Contemplates Building New Nuclear Units in Sweden. Swedish utility Vattenfall in mid-January began a 10-year consultation process for possible new nuclear reactors at its four-unit Rin-ghals nuclear station in Sweden. A deci-sion to build the new reactors based on the consultation with government agen-cies, local residents, and other stakehold-ers is not expected until at least 2020. The company, which owns seven nuclear reactors that started commercial opera-tion between 1975 and 1985, submitted an application to the Swedish Radiation Safety Authority for permission to build and operate one or two new nuclear reac-tors in August 2012. ■

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

Regulatory Rundown

We cover power industry regulatory developments as they happen and post them at powermag.com. Did you miss any of these when they were sent out in our weekly POWERnews?

Every Megawatt Counts—Nuclear Plant Uprate いApprovedLegal Deadline Set for EPA’s Coal Ash RuleいEPA to Hand Over GHG Permitting Authority to いTexasWest Coast Floating Offshore Wind Project Gets いDOI Green Light to AdvanceOkla. Asks Supreme Court to Review EPA Regional いHaze SuitEPA Mulls Revising Nuclear Plant Radiation いStandardsObama Nominates Norman Bay to Head FERCい

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Customized Storage Solu-tion Improves Efficiency

Omaha Public Power District (OPPD) oper-ates four baseload plants in the state of Nebraska. In 1993, when the North Omaha Station added a new warehouse, OPPD sought help from Vidmar to create effec-tive storage solutions for small parts and large palletized items, as well as to pro-vide ideas for general organization within the workspace.

About three years ago, OPPD began exploring and utilizing “lean” practic-es—a customer-centric methodology used to continuously improve any pro-cess—looking for ways to reduce waste and increase efficiency.

One of the first locations to use the process was the Elkhorn Service Center. OPPD reviewed inventory handling and storage procedures in its warehouse and instituted a number of changes. Results were tremendously successful, saving about $180,000 in the first year.

The outcome led to further reviews at other service centers and power gener-ating plants, including at North Omaha Station. Lean teams looked at a variety of systems and examined many different options. After extensive evaluation, the company opted to install the STAK system manufactured by Vidmar (Figure 1). A de-ciding factor was OPPD’s previous experi-ence with the supplier.

Working with Vidmar Territory Sales Manager Chuck Eacock, OPPD upgraded the shop and benefitted from a 70% space savings. The workbenches im-proved organization and the STAK sys-tem allowed for expansion as business needs grew. The cabinets were custom-built to fit the warehouse’s exact needs and specifications. Height, width, num-ber of drawers, and drawer layouts were all custom-configured to maximize pro-ductivity.

“There are numerous operational ben-efits from the standpoint of having so many parts in a consolidated area,” said Chris L. Rush, who works in the North Omaha Stores Material Management divi-sion. “We can now organize the cabinets by application. Within each cabinet there is the opportunity for such an array of different configurations of drawers that we have not run into an issue that we can’t handle.”

The STAK adjustable racking system (Figure 2) improved workplace efficiency by providing ample storage space and the versatility to store a host of items, from the smallest computer component to the largest valve. Utilizing space saved by the Vidmar STAK system and cabinets, OPPD was also able to implement the use of pal-let racking.

“Now that we have proper storage, everything is consolidated into a small-

er footprint, so there is less walking around, with stored parts always within easy reach and full view. This means an improved bottom line for Omaha Public Power and fast, effortless retrieval for the craft guys,” said Rush.

OPPD has hosted several tours for other facilities’ management personnel seeking insight on how customized stor-age products can improve work areas and make employees more efficient. Overall, the lean process—including use of the STAK system—has helped the company reduce waste, control costs, and make better use of inventory and materials. It is all part of an overall push to be more efficient and cost-productive throughout the company, which is now more impor-tant than ever.

“Every company wants to do more with less and make better use of its resources. We are no exception. The changes we have made have helped us do that,” said Rush.

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

POWERmagazine).

1. A view of a storage area utilizing the STAK system. Courtesy: Vidmar

2. A view of the adjustable rack-ing system in use. Courtesy: Vidmar


Practical Considerations for Converting Industrial Coal Boilers to Natural GasIncreasing Environmental Protection Agency (EPA) restrictions pertaining to emissions from coal-fired power plants, the increasing cost of coal operations, and the decreasing cost of natural gas provide strong arguments for converting coal-fired boilers to natural gas–firing ones. Coal-fired boilers have emissions that are po-tentially noncompliant with the Maximum Achievable Control Technologies (MACT) rule and Mercury and Air Toxics Standards (MATS), which will require modifications to most coal-firing systems.

Where should coal boiler owners start when evaluating the various conversion options for their facilities? A compre-hensive understanding of various design alternatives and their implications is cru-cial to optimizing the initial capital cost, operating cost, safety, and reliability of the facility.

Conversion Benefits

The primary benefits of converting a coal boiler to fire natural gas are a more cost-effective, cleaner, more efficient, and reli-able source of steam. As compared with installing a new boiler, converting an operational coal-fired unit to natural gas typically requires a lower capital invest-ment, enables the most condensed sched-ule, and makes use of the existing asset.

Although the solution is not new (see “Natural Gas Conversions of Existing Coal-Fired Boilers” in the August 2011 is-sue of POWER, online at powermag.com) and has been covered recently in two Special Report articles (see “Practical Considerations for Converting Boilers to Burn Gas” and “Utility Options for Lever-aging Natural Gas” in the October 2013 issue of POWER), the topic continues to be relevant due to evolving EPA regula-tions and public perceptions of climate change initiatives.

For most industrial boiler owners, re-utilization of the existing asset is the most desirable course of action. Convert-ing an existing boiler is typically 15% to 30% of the cost of installing a new natural gas boiler. Additionally, converting coal boilers to firing natural gas provides the following major benefits.

Cleaner Operation. Natural gas burns cleaner than coal, because it does not con-tain significant amounts of sulfur, atomic nitrogen, particulate, or ash. Additionally, natural gas allows for more precombustion

controllability for lower emissions, such as NOX and CO, without the need for exten-sive flue gas treatment equipment.

Operating Cost Savings. For several years the cost of natural gas has been de-creasing while the cost of coal has been increasing. By using only natural gas in-stead of coal, facilities can eliminate op-erations, maintenance, and environmental costs associated with coal/ash storage and handling. With no ash carryover, nat-ural gas avoids ash buildup, which reduc-es heat transfer, meaning the boiler can maintain its efficiency.

Increased Boiler Flexibility. Convert-ing to natural gas improves boiler flex-ibility and turndown capability. Coal-fired boilers do not react to sudden load swings as effectively as a converted natural gas boiler. Further, coal-fired boilers have a limited turndown capability, thus limit-ing their effectiveness during low steam demand. Bringing a coal-fired boiler back online after a shutdown requires much more time than is required by a natural gas boiler.

Determining Emissions Limita-

tions Is the Key First Step

So you have a coal boiler that appears to be a perfect candidate for conversion. Where do you start? CO and NOX emissions limitations are of primary importance when converting boilers to natural gas-firing. These emission limitations dictate the requirements of the burner design, air/fuel mixing technology, and resulting flame temperature. Emission limitations affect combustion airflow requirements, refractory requirements, amount of flue gas recirculation, duct sizing, and damper control, all of which have an effect on the forced draft (FD) fan and induced draft (ID) fan requirements.

Getting too far along in the design of the project and then finding that the emissions limitations have changed could mean starting from scratch with a new design. Working with a qualified envi-ronmental consulting firm is a great way to make sure that the project is getting started on the right track.

Vertical or Horizontal Firing?

There are two typical arrangements for mounting the most important part of the conversion—the burners: horizontal, wall-mounted burner design and vertical, upward-mounted burner design. For both arrangements, the following consider-ations are important.

Heat Input Required. How many Btu

of natural gas must be burned to achieve the operational steam output at the re-quired pressure and temperature?

Boiler Furnace Geometry. Furnace dimensions significantly affect the burner design and burner placement. If the boiler has superheater tubes in the radiant area, the distance from the grate to the lowest part of the superheater tubes is also criti-cal to the design.

Backend Modifications Needed. Does a baghouse or other flue gas equip-ment need to be bypassed or removed? Does a cyclone separator need to be “gutted” to reduce the flue gas pressure drop, or is the ID fan so oversized that additional flow restrictions are needed to utilize the fan? A cost-benefit analysis of replacing the ID fan versus installing flow restrictions may be advised. Install-ing a variable frequency drive (VFD) for the ID fan may also make sense.

Impact of the Conversion on the Boiler. Depending on burner placement, a conversion from coal to gas changes the energy release slightly. Natural gas flames produce lower radiational energy, thus radiant heat transfer in the lower furnace is less, while the convective heat transfer is increased through the back-pass/economizer.

On the steam side, the changes in com-bustion temperature, quantity, and com-position affect the velocities and heat absorption within the furnace, economiz-er, and superheater sections and thus has an effect on steam flow and temperature. A boiler impact study may be needed to evaluate the gas and steam processes that may be affected by the conversion. This analysis can provide an impact eval-uation of boiler emissions, heat transfer, boiler efficiency, steam production, and steam temperature.

Natural Gas Flow and Pressure Availability. A new main gas line or a pressure regulation station with a new tap into an existing main gas line may be needed.

Electrical Distribution System Capac-ity. Does the current system have the nec-essary capacity available for the project?

Existing Boiler Condition. Is the boil-er clean and in good repair? Is retubing or similar work needed?

Code Requirements. Boiler code re-quirements differ in some areas for natu-ral gas versus coal-fired boilers. This may require boiler safety relief valve (SRV) replacement or recertification, boiler feed-water delivery pressure and flow capacity changes in relation to boiler maximum


pressure and SRV settings, as well as other relevant ASME code–dictated work.

Wall-Mount Burner Conversion

Considerations

In a wall-mount arrangement, the burner or burners are mounted within either the front wall, side wall, or rear wall (Figure 1). Each potential burner location must be evaluated for a number of concerns:

■ What is the distance to the opposing wall, thus what is the distance the flame can occupy without impinging on the opposite wall? This will help in determining the number of burners and burner design required to deliver the re-quired heat input while avoiding flame impingement.

■ Are water wall tubes currently in the way of where the burners should be mounted? If so, new bent tube panels would need to be installed to accom-modate the throats of the burners, thus requiring engineering design of the panels, shop fabrication, and field labor to cut out the existing straight tubes and weld in the new sections.

■ What is the front header clearance? If the burners are to be mounted in the front wall, then the front header height becomes an important element. Depend-ing upon the header height from the floor, the burners and windboxes may have to be located between this header and the operating floor. Low clearance may also dictate multiple smaller burn-ers, extensive relocation costs for the header, or modifications to the floor.

Most wall-mounted burner flames will initially fire horizontally, then bend up-ward based upon furnace draft. Once burner location and the quantity of burn-ers are established, an analysis of the flame geometry is required to ensure that the “angled” heat can transfer effectively within the radiant zone without flame impingement. When utilizing this type of conversion it is common to have multiple burners that fire in unison to maintain an even heat transfer.

Typically, a single FD fan is utilized to produce combustion air regardless of the number of burners used. This fan produces the required static pressure and volume

of air into a common windbox that has internal air distribution to regulate suf-ficient and constant air to the burners. In a multiple burner arrangement, the com-bination of the combustion air, fuel train, controls, and the burners’ air/fuel mixing design provides for simultaneous firing.

A successful implementation of the hor-izontal-mounted burner arrangement is op-erating at a manufacturing facility in Flint, Mich. Under a design-build contract, Lipten Co. converted three 45,000 lb/hr field-erected coal-fired boilers to front wall–fired, low–NOX natural gas firing with new FD fans, VFDs, fuel trains, controls, exten-sive tube repairs, and tube modifications.

Because of the lack of a floor level below the boilers, vertical firing was not feasible. The project was designed so that only a single burner was needed per boiler, reducing controls complexity as compared with a multiple burner boiler arrangement. Use of a single burner was possible be-cause of the liberal furnace dimensions.

Vertical Burner Mounting

Considerations

A vertical-firing arrangement places a burn-

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er and windbox at the base of the boiler, typically in the area vacated by the grates and plenum hoppers (Figure 2), thus allow-ing the flame to vertically fire upward into the furnace area, making maximum use of the furnace’s height, width, and depth. This method has been found to better emulate the replaced coal-firing system’s heat dis-tribution by allowing heat to radiate from the bottom toward the top, making use of

the liberal furnace height and minimizing the chance of flame impingement—similar to a burning bed of coal. Items to review for a vertical-firing arrangement include:

■ A building level below the boiler

(such as a basement or lower level) is critical. Review and measure the height from the lower level floor to the top of the grates. Sufficient height will be required to ensure the windbox and burner will fit below the

1. Newly installed, horizontally mounted burner. Courtesy: Lipten Co.

2. A before and after comparison of a boiler general arrangement draw-ing. The original design included a grate and hopper (left), but the conversion replaced them

with a vertical, upward-mounted burner and new forced draft fan (right). Courtesy: Lipten Co.

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boiler while allowing for maintenance access (Figure 3).

■ Is sufficient combustion air available in the building to support the conversion? A review of intake louvers and make-up air units may be necessary.

A vertical-firing burner arrangement (Figure 3) is almost always preferred, if

possible. That was the case when Lipten provided the design-build conversion of two 210,000 lb/hr steam boilers at an automotive manufacturing facility in Wentzville, Mo. The converted boilers were commissioned in late 2013. The project in-volved installation of a single 250-MMBtu/hr vertical-mounted burner on each boiler.

A vertical burner design was chosen

instead of wall-mounted burners for this application to provide optimum flame geometry for the furnace configuration, improved water circulation patterns, im-proved thermal efficiency, better overall boiler performance, avoidance of flame impingement, and simplified operation.

The existing ID fan curves were ana-lyzed, and it was determined that these fans could be reused by replacing the motors and installing VFDs. The FD fans were replaced and also fitted with VFDs. The project included new natural gas supply systems, electrical modifications, custom CombustionPac combustion con-trol systems utilizing programmable logic controllers, and additional boiler system modifications required to convert the coal boilers to fire natural gas.

To EPC or Not to EPC?

An engineering, procurement, and con-struction (EPC) company with expertise in the boiler conversion process can be in-valuable in optimizing installation costs, efficiency, safety, and reliability. Make sure that the firm providing EPC services is not favoring a particular product or de-sign and is a truly unbiased boiler conver-sion specialist that will select the proper equipment and optimum design for your application. An experienced EPC firm can work from either an end user–provided scope of work—allowing for a design-build application—or work from more de-tailed specifications, if desired.

A boiler owner could enlist the assis-tance of an engineering firm that special-izes in boiler coal-to-gas conversions to work in unison with the owner to provide site-specific drawings, design direction, component requirements, and site work details. The engineering firm’s scope may include a detailed set of plans and speci-fications or a more simplified conceptual design package to facilitate design-build bidding. Detailed engineering packages may then be used to solicit bids for in-dividual project aspects, such as skilled trade work and equipment, or conceptual design packages can be released to EPC firms that may provide all-inclusive proj-ect implementation. ■

—John Ingraham is a proposal develop-ment manager, Jim Marshall is president, and Randy Flanagan, PE is a mechanical

engineer with Lipten Co. ([email protected]), a design-build firm specializing in industrial central utility plant design and

construction with specialized expertise in converting industrial coal-fired boilers to

natural gas firing.

3. Completed conversion. A side view of a newly installed forced draft fan with stairs

and access platform (foreground) to the new fuel train and vertical, upward-mounted burner

(background). Courtesy: Lipten Co.

4. Side view of a newly installed fuel train and vertical-mounted burn-er. Courtesy: Lipten Co.


When States Try to Manipulate Wholesale Power MarketsThomas W. Overton, JD

This has not been the best of times for state regulators trying to control the future of their regional power markets.

In September, a federal court in Maryland shot down that state’s attempt to force the construction of a combined cycle pow-er plant outside of PJM’s capacity auctions. The Maryland Public Service Commission has spent several years trying to address what it sees as potential capacity shortfalls, and in April 2012 it finally ordered several regional utilities to execute power purchase agree-ments (PPAs) with a company that wanted to build such a plant but was unable to clear PJM auctions. The utilities sued to block the order, and on Sept. 30, the court agreed that the state com-mission impermissibly invaded the Federal Energy Regulatory Com-mission’s (FERC’s) authority over wholesale power prices.

Just two weeks later, a federal court in New Jersey threw out that state’s attempt to circumvent PJM in a similar fash-ion. Acting under New Jersey’s Long-Term Capacity Pilot Proj-ect, enacted in 2011, the New Jersey Board of Public Utilities conducted its own selection process for new generation and ordered the state’s utilities to sign PPAs with the winning com-panies. As in Maryland, the utilities sued, and the court there also agreed that the state had no authority to interfere in the wholesale power market.

In both cases, the decisions turned on a principle of constitu-tional law known as preemption. Somewhat simplified, this rule holds that where Congress intends to occupy a regulatory field within its jurisdiction, states have no authority to impose their own regulations. Federal courts have long held that the Federal Power Act leaves no room for states to regulate interstate power sales, and that that authority rests solely with FERC. With FERC having authorized PJM to manage the wholesale power market in New Jersey and Maryland, those states cannot second-guess PJM’s judgment when the market doesn’t function to their liking.

Cases in this area have historically turned on efforts to boost capacity or reduce power prices. There are signs, how-ever, that future litigation may concern methods to support renewable generation.

Renewable energy mandates have passed muster under this rule to the extent they merely require a percentage of renewable generation while leaving it to the market to de-termine the prices paid and the generators that supply the power. Attempts to go beyond that, however, have often run into trouble.

A Mighty WindThat brings us to the Cape Wind offshore wind project in Mas-sachusetts.

Cape Wind, potentially the nation’s first offshore wind farm, has been in development for more than 10 years and has spawned fierce opposition from a variety of quarters, among them the

same conservative groups that have fought renewable energy mandates elsewhere in the country. Still, it has managed to navi-gate a gauntlet of permit approvals and litigation, in no small part because of strong support from the Massachusetts govern-ment, particularly Governor Deval Patrick.

Cape Wind’s most formidable obstacle has been the cost of its power. Even with subsidies, it has been unable to offer its elec-tricity into the ISO New England market at competitive prices, even against other renewable generation. Nevertheless, it was able to secure a no-bid PPA with National Grid in 2010 for 50% of its output. The PPA came about in large part because the Massachusetts Green Communities Act favored in-state renew-able generation at the time. As I wrote in the August 2013 issue of POWER, that provision was rescinded in the face of a lawsuit from TransCanada.

Without that advantage, Cape Wind was unable to convince NSTAR, another area utility, to enter a PPA because NSTAR had re-ceived much lower-priced bids from land-based wind generators, some of them out of state. Thus things stood until NSTAR and Northeast Utilities sought approval from commonwealth regula-tors for a merger.

It’s difficult to characterize what happened next as anything but an attempt to strong-arm NSTAR into signing a PPA with Cape Wind. The Massachusetts Department of Energy Resources moved to block the merger, and it only withdrew its opposition when NSTAR and Northeast Utilities agreed, after a secret, yearlong ne-gotiation, to sign a PPA under the same well-above-market rates as the National Grid deal.

How About Another Round? Cape Wind, as I noted above, has faced years of litigation, and its opponents have failed in every attempt to block the project, most recently on Jan. 23, when the Court of Appeals for the District of Columbia Circuit upheld Federal Aviation Administra-tion approval. But on the same day that decision came down, opponents filed a new suit, arguing that the merger-PPA deal constituted state inference in wholesale power prices, given that it required the utilities to accept a specific price rather than one freely negotiated on the market.

The fact pattern here is not quite the same as in the New Jer-sey and Maryland cases, where state regulators ordered PPAs to be signed; here, Massachusetts apparently conditioned approval of the merger on the PPA. Thus, it may argue that NSTAR had a choice to forgo both.

As of this writing, the Commonwealth of Massachusetts has not filed an answer to the suit, but this case is clearly one to watch, both for the future of renewable mandates and wholesale power markets. ■

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

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GRID SUPPORT

AES Uses Synchronous Condensers for Grid Balancing

The future is looking bright for AES Hun-

tington Beach Power Generating Station.

Renderings of a proposed new look for

the power plant—located steps from the beach

on the Pacific Coast Highway—include mas-

sive surfboards and waves masking six new

120-foot structures slated to replace two 210-

foot stacks (Figure 1). The facelift is part of

a greater modernization initiative to create a

cleaner, more efficient natural gas power plant.

But the real innovation coloring the future of

the plant and its surrounding electrical grid is

happening below the surface.

A recent conversion from generators to

synchronous condensers has the plant not only

stabilizing the grid and keeping the lights on in

times of high demand, but also keeping the air

just a little bit cleaner in the process.

Keeping the Lights OnThe California Public Utilities Commis-

sion (CPUC) requires its utilities to plan for

a 15% Planning Reserve Margin of excess

generation. In peak seasons like Southern

California’s sweltering summers, addi-

tional voltage support is often required to

maintain this balance and stabilize the grid.

Historically, Southern California has had

adequate reserve margins, but in 2012 when

the San Onofre Nuclear Generating Station

(SONGS)—the largest plant in Southern

California—was shut down, this level of

comfort quickly changed.

The loss of SONGS during the summer of

2012 left Southern California with a 2,200-

MW hole in its grid. Without SONGS, gen-

eration from other nearby power plants was

insufficient to meet electricity demand, and

importing that much replacement power

into the area would put too much stress on

the region’s grid. To fill this gap, Huntington

Beach’s steam turbine Units 3 and 4 were tem-

porarily brought back from a nearly two-year

retirement. But these units could not stay on

indefinitely because of an emissions transac-

tion with Edison Mission Energy (EME) that

had been completed earlier. The terms of the

agreement required AES to retire the Unit 3

and 4 boilers and related equipment to enable

EME’s new combined cycle project to begin

commercial operations.

When it became clear in late 2012 that

an alternative means of voltage support was

necessary due to the potential retirement of

SONGS, the California Independent System

Operator (CAISO) approached the team at

AES and suggested the switch from genera-

tors to synchronous condensers. Before this

point, AES Huntington Beach was primarily

run via generators, and the team had little ex-

perience with synchronous condensers, but

the solution was undoubtedly a viable one, so

the team got to work.

Many stakeholders were involved in the

project, including Southern California Edison,

the California Energy Commission (CEC), the

CPUC, San Diego Gas & Electric, and even

the rate-paying citizens of Orange County.

With such an invested audience of stakehold-

ers, AES began procuring a wide range of

solution options that could meet the stringent

regulatory, budgetary, and deadline demands.

Faced with a critical shortfall in voltage support after the loss of the San Onofre nuclear plant, the California Independent System Operator called on AES to convert two retired units at its Huntington Beach station to synchronous condensers. The experience offers lessons for other regions looking to deal with impending plant retirements and changing grids.

Weikko Wirta and Chris Davidson

Courtesy: Siemens Energy and Chet Williams Photography

GRID SUPPORT


Assessing the TechnologyThere are a number of different ways to pro-

vide voltage support to a transmission grid.

Though generation provides support, reactive

power is needed to move the power across

the grid to serve load.

Static var compensators (SVCs) are a popu-

lar method for reactive power compensation

to improve and balance a network. An SVC

is made up of capacitive and inductive com-

ponents that inject reactive power and deliver

dynamic performance during periods of high

demand. However, SVCs may have limited ab-

sorption levels and fault current performance.

Synchronous condensers, like SVCs, are

another means of power compensation, but

unlike SVCs, synchronous condensers are

single-component rotating machines—also

known as flywheels—which positively or

negatively alter the field of the generator

to distribute or absorb reactive power. The

single component design allows for smooth

waveform and a quicker, more reliable start-

stop in a way that does not negatively affect

the system load. Synchronous condensers

also have a higher capacity to handle fault

currents, making them ideal in applications

such as this one.

Facing ChallengesUnfortunately, AES’s generators presented

three challenges for conversion to synchro-

nous condensers:

■ Multiple Original Equipment Manufac-

turers. The plant consists of two different

brands of generators, General Electric and

Westinghouse, in a cross-compound sys-

tem. Finding a conversion solution that

would work equally well for both genera-

tors was necessary. This type of situation

would normally require all new equipment

to be installed for the conversion, which

would have inflated both the timeline and

budget for the project.

■ Size. Though the generators at AES aren’t

abnormally sized compared to plants of

this capacity, they are still physically large.

A conversion solution for equipment this

size generally requires substantial electri-

cal modification to assist in controlling

the unit’s speed and a significant amount

of system analysis and adjustment.

■ Age. As an added complication, the tur-

bines at AES were nearly 50 years old, so

the issue of potential replacement or repair

of the existing equipment was a concern.

Most modern generators are converted to

motors to turn themselves on and bring

themselves up to speed, serving dual elec-

trical purpose. The generators at AES were

not designed for that type of functionality.

With each of these challenges came added

stress in identifying a solution that could be com-

pleted on time and within the allotted budget.

The team at AES partnered with Siemens

Energy to review their options. With the tight

timeline being the most critical factor, a mo-

ment of clarity brought a solution that took

repair or replacement of the AES turbines

out of the equation. After nearly a month of

comprehensive evaluation, the team was able

to retain most of AES’s existing infrastruc-

ture without requiring new equipment or sig-

nificant upgrades. The only new equipment

investments made were those pieces that

immediately supported the conversion: pony

motors, thrust bearings, variable frequency

drives (VFDs), and new distributed control

system (DCS) panels.

“Timing was a critical issue,” said Phil

Pettingill, director of regulatory strategy at

CAISO. “There was a constant stream of

questions from regulators and policymakers

regarding cost and schedule. Both AES and

Siemens were very effective at coming back to

us and telling us exactly what we needed and

how they could meet the evolving timeline.”

Maintaining a BalanceThe innovation behind the customized ap-

proach was an easy sell to the stakeholders.

AES, the CEC, the South Coast Air Qual-

ity Management District (SCAQMD), and

CAISO all quickly realized that the proposed

approach was the only one that could fulfill

all of the stringent requirements of the proj-

ect, particularly the looming summer dead-

line. The application was filed with the CEC

on Oct. 5, 2012, and the synchronous con-

densers needed to be fully functional no later

than June 28, 2013.

Work began immediately after project ap-

provals were granted in late 2012. AES em-

ployed Siemens to lead a team of contractors

in the installation. With the tight timeline

constantly in mind, the Siemens team made

the decision to adapt to the situation and ma-

terials at hand, rather than bring in a slew of

new equipment.

The Huntington Beach plant operated as

a cross-compound system. There were four

generators onsite, but only two acceleration

models were needed to bring the system to life.

Essentially, the two small pony motors were

used as prime movers, which replaced the ex-

isting boilers and steam turbines. Original plans

called for one power source to control the mo-

tors, but after careful consideration, the team

decided to install a second source to provide a

redundant source of power should any unfore-

seen circumstances affect drive functionality.

The VFDs were installed to drive the strategi-

cally located pony motors (Figure 2) and keep

the motors’ size, horsepower, and costs down

thanks to the way the units were configured

with the two tandem generators. The drives

allow the generators to be brought up slowly

and simultaneously while keeping them in an

electrical lock. Though adding the additional

power source was not part of the original plan

and required additional time to implement, the

team had been prepared by building a buffer

into the schedule for minor delays.

Along the way, the team faced additional

challenges that could have potentially affected

the timeline. At one point in the installation,

an overhead crane failed. Ultimately, the crane

was repaired and the project stayed on track.

Despite a few minor setbacks, the con-

verted system was successfully started up on

June 28, 2013—the exact date that the proj-

ect was slated for completion—and has been

a reliable resource ever since.

The generators can be automatically excit-

ed when needed and as a result do not need

1. Second life. Two retired generators at the AES Huntington Beach plant were recently

converted to synchronous condensers to provide voltage support to the Southern California

grid after the unexpected retirement of the San Onofre Nuclear Generating Station. A planned

redesign will conceal a new plant behind giant surfboards, in keeping with the city’s history as

a surfing destination. Courtesy: Siemens Energy and Chet Williams Photography

www.electricpowerexpo.com

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GRID SUPPORT


to work nearly as hard as they had in the past.

As an added bonus, synchronous condensers

require under an hour of start-up time, as op-

posed to nearly the 12 hours required to fire

a boiler, so they can be tapped on demand in

times of need.

“We needed a project that could provide

the reactive support needed to optimize power

transfers across L.A. and into the San Diego

region,” said Pettingill. “After the summer

of 2013, we can definitively say those needs

were met with the synchronous condenser

project at AES Huntington Beach.”

Clearing the AirWhen the synchronous condenser conversion

was presented, the SCAQMD appreciated

the fact that it translated into a nongenerating

resource that provides voltage support with-

out any emissions. Emissions are a growing

concern with industrial and power plants

around the world, particularly in California.

State legislation requires any investments in

generation resources (new construction and

renovation) that provide electricity to Cali-

fornia residents to meet a specific emissions

standard of 1,100 lb CO2/MWh or less. By

providing reactive power to transfer energy

across grids, the synchronous condensers

help eliminate the need for constant genera-

tor operation and reduce those emissions.

Appealing to the MassesSynchronous condensers can provide dy-

namic benefits across multiple platforms and

applications. In AES’s case, they assist in

distributing reactive power to the grid as nec-

essary in times of peak usage, but they can

also absorb reactive power when necessary.

Though AES is looking toward moderniz-

ing the plant, both inside and out, with more

efficient infrastructure and a beach-themed

wave and surfboard exterior, the trend to con-

vert to synchronous condensers has applica-

tions well beyond Southern California:

■ Renewable energy. In California as in many

other regions, higher levels of renewables

are being added to the system. As a re-

sult, introducing additional reactive power

sources such as synchronous condensers

can help deal with challenges of transform-

ing the grid in order to accommodate po-

tential differences in power sources.

■ Voltage sags. Conversely, as more coal-

fired plants are retired, more inertia is lost,

creating voltage sags across the country.

Synchronous condensers have the capa-

bility, with on-demand excitation and ac-

celeration, to provide dynamic voltage

support to make up for that loss.

■ Long distance and highly concentrated

grids. For electric suppliers whose grids

span great distances, synchronous condens-

ers come in particularly handy. The synchro-

nous condensers move reactive power and

change the voltage of the grid to balance the

distribution across greater distances or to a

greater number of consumers.

■ Large industrial loads. In high-activity

industrial settings such as paper mills,

steel mills, manufacturing facilities, and

more, system stability is constantly evolv-

ing. Loads need reactive power to assist

with initialization and stabilization. The

synchronous condensers are a low-risk

means of consuming and dissipating reac-

tive power as needed, providing an array of

benefits and avoiding outage situations al-

together. For industrial plants with a variety

of inductive loads such as motors, drives,

and transformers, synchronous condensers

provide reactive power to get things up and

running quickly and smoothly.

Drawing ConclusionsThe summer of 2013 in southern Orange and

San Diego counties went smoothly. Even

without the 2,200 MW of generation from

SONGS, residents of Southern California

stayed cool and calm with their lights and air

conditioners on.

“The effort by the whole team to restart

the units before the summer of 2012 with a

herculean effort and under a short time frame

was nothing short of amazing,” CAISO presi-

dent and CEO Steve Berberich said. “To fol-

low that up with a sprint to convert those same

units to synchronous condensers cemented

the immense respect and confidence we have

in the AES Huntington Beach team.”

As for the future of the synchronous

condensers at AES, their story doesn’t end

here. A Reliability Must-Run contract exists

between CAISO and AES. Current contract

provisions call for the retirement of one of

the synchronous condensers at the end of

2016 and the other at the end of 2017 in or-

der for AES to undertake its once-through

cooling compliance repowering plans for

the entire facility. However, CAISO will an-

nually assess whether or not the grid has a

reliability need that can still be met by this

project. The evaluation of this option will

need to consider how an extension of the

synchronous condenser’s operation beyond

2017 would affect the long-term repowering

plans for the AES Huntington Beach facil-

ity. There has also been discussion of con-

verting one or both of the retired generators

at SONGS to synchronous condensers by

the summer of 2015.

There is plenty of opportunity to replicate

the success realized by the AES conversion

project across the country. The job of a plant

manager in every industry is to evaluate and

manage risk while also maximizing the return

on the asset. Synchronous condenser conver-

sion is a very low-risk approach. Every grid

operator or transmission planning entity has

unique needs. It is important to consider how

certain technologies like synchronous con-

densers can help to optimize power flow,

minimize risk, and maximize benefits to help

meet the needs at hand. ■

—Chris Davidson is the electrical solu-tions business development director at Siemens Energy IC&E. Weikko Wirta is

the Southland operations and mainte-nance manager, site leader, and former

plant manager at AES Huntington Beach.

2. Working in tandem. The pony motor (foreground) is driven by a variable frequency

drive (out of sight underground), allowing the generators (center)—which once supplied power

to the grid—to function as synchronous condensers. Courtesy: Siemens Energy and Chet Wil-

liams Photography

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THE FUTURE OF COAL-FIRED GENERATION

Is Polygeneration the Future for Clean Coal?With the coal-fired power sector facing potentially fatal regulations, some vi-

sionaries think the future is in generating not just power but a range of products from coal gasification. Getting there will be no easy task.

Thomas W. Overton, JD

This is the story of a power plant like no

other.

The facility runs primarily on coal,

but it can utilize petcoke and biomass when

available. The front end resembles an integrat-

ed gasification combined cycle (IGCC) plant

in which the fuel is gasified to a mix of carbon

monoxide (CO) and hydrogen (H2)—syngas.

Water for the gasification process is sourced

from brackish, low-quality local supplies to

avoid stressing freshwater resources. The syn-

gas is cooled, scrubbed, and filtered before be-

ing passed through a water-shift reactor with

more steam to adjust the H2-CO ratio.

It’s at this point that things get interest-

ing. The CO2 from the gasification process

is separated from the syngas, and about two-

thirds of the syngas—by this point nearly all

hydrogen—goes to the gas turbine, where it’s

combusted to produce electricity and heat.

The other third goes to an adjacent chemi-

cal plant, where it’s combined with some of

the CO2 to produce ammonia and urea for

fertilizer. The chemical plant is also capable

of producing methanol and a variety of other

liquid fuels and products, depending on mar-

ket demand, all of it using output from the

gasifier. Waste heat from the turbine is used

to power the shift reactor and other plant pro-

cesses, increasing overall efficiency.

The unused CO2, about 80% of what’s

captured, is sent by pipeline to be used in en-

hanced oil recovery (EOR) in the area’s oil

fields, where the plant has been strategically

located to serve demand, while the fertilizer

is sold to nearby farms. When demand for the

plant’s electricity falls during the night, more

of the syngas is sent to the chemical plant

rather than ramping down the gasifier, which

runs at full capacity nearly all the time.

A New ParadigmThe plant described here does not exist—yet.

But it may be closer than you think.

It’s not exactly paranoia to suspect the

days of massive coal-burning thermal power

plants in the U.S. may be on their way out. On

Jan. 8, the Environmental Protection Agency

(EPA) published the latest version of its new

source performance standards for carbon

emissions from new power plants. The pro-

posed limit of 1,100 lb CO2/MWh serves as

an effective ban on new coal plants without

some form of carbon capture and sequestra-

tion (CCS), because meeting that limit with a

conventional coal plant is very difficult.

Yet carbon capture has not kept up with ex-

pectations, and the costs seem prohibitive: Mis-

sissippi Power’s Kemper County IGCC project,

expected to start up late this year, has seen its

total costs balloon to more than $4 billion—this

for a 582-MW plant. Duke’s 618-MW Edward-

sport IGCC plant in Indiana, built as “carbon-

capture ready” but without CCS installed, came

online in 2013 at around $3.5 billion. (The Ed-

wardsport plant was a Top Plant Award winner;

see “Edwardsport Generating Station” in the

October 2013 issue at powermag.com.)

These numbers have experts looking for

ways to improve CCS economics. Many of

them believe the way forward is a new ap-

proach: polygeneration.

What is polygeneration? Simply put, it’s

producing two or more marketable products

from the same input, whether it’s electric-

ity, hydrogen, fertilizer, synthetic natural

gas, methanol, synthetic diesel, carbon diox-

ide, or something else (Figure 1). The basic

processes are not new: Coal gasification has

been around since the 1950s, and a variety of

gasifier technologies are available.

The chemical methods used to turn syn-

gas into other products are well established

and have been in use around the world for

decades in numerous coal-to-liquids and gas-

to-liquids projects. The process works just as

well with natural gas, but there has been a

renewed focus on coal because the emissions

and efficiency benefits are potentially much

Particulate

removal

Gas

cleanupShift

reactor

Synthesis gas

conversion

Fuel and

chemicals

Carbon dioxide

sequestration

Hydrogen

Electric power

Electric power

Electric power

Generator

Generator

GasifierParticulates

Solid by-product

Air separator

Sulfur by-product

Combustor

Fuel cells

Gas turbine

Stack

Air

Compressed air

Air

Oxygen

Solid by-product

Air

Steam

Steam

Steam turbine

Heat recovery

steam generator

Coal, petroleum

coke, biomass,

waste, etc.

Gas

constituents

Hydrogenseparation

1. Waste not, want not. With polygeneration, gasified coal is used to produce a wide

variety of outputs, from electric power to hydrogen to chemicals. Source: DOE/NETL



larger. A polygeneration plant can theoreti-

cally achieve efficiencies as high as 55% to

60%, compared to a maximum of about 40%

to 45% for a state-of-the-art ultrasupercritical

coal-fired thermal plant.

Polygeneration has other benefits. One of

the biggest is the potential for much lower

emissions than from a conventional coal-

fired boiler, because the impurities and pol-

lutants, such as particulates, sulfur, mercury,

and CO2, are removed from the syngas prior

to combustion, where they are more concen-

trated and more easily captured.

Another benefit is that the chemicals and fu-

els produced from syngas are typically cleaner

than those produced from petroleum, resulting in

lower emissions further down the supply chain.

Coal gasifiers also are less sensitive to feed-

stock, and can generally use a wide variety of

coals and biomass with less optimization than

a conventional plant, allowing the owners to

leverage fluctuations in fuel prices. Likewise,

the chemical products such a plant can manu-

facture are flexible, allowing it to produce prod-

ucts with the highest current market value.

The overall synergy between the gasifier,

power plant, and chemical plant means great-

er overall efficiency and lower emissions and

production costs than for standalone facilities.

Challenges GaloreThere are significant challenges to making

all this work, however. High capital costs for

coal gasifier technology have thus far been

the largest deterrent. By comparison, AEP’s

600-MW ultrasupercritical John W. Turk, Jr.

plant in Arkansas (POWER’s 2013 Plant of

the Year, see the August issue), which came

online a few months before Edwardsport,

cost about half as much, at $1.8 billion.

Though IGCC technology has been around

for several decades, it is still not in common us-

age, especially with coal. Only two other full-

size IGCC plants are currently operating in the

U.S., Tampa Electric’s 250-MW Polk Power

Station and the 262-MW Wabash River plant

in Indiana (operated by Duke but owned by

the Wabash Valley Power Association), both of

which suffered substantial operational issues in

their first years of operation; neither incorpo-

rates CCS. Meanwhile, only a few other utility-

scale IGCC plants are in operation worldwide.

Several are planning to test or incorporate CCS,

but none involves polygeneration.

Another challenge is the multi-faceted

nature of the plant, which significantly in-

creases its operational complexity. Few if

any utilities or merchant plant owners have

the experience or expertise to operate an as-

sociated chemical plant. Early entrants are

more likely to come from the petrochemical

industry, which has the experience in that

field—though with petrochemical residu-

als rather than coal—as well as in operating

refinery-based power plants. Still, it is likely

that successful coal-based polygeneration

projects will require partnerships between

power and chemical companies.

Current ProjectsChallenges or not, the plant described in the

opening to this article is by no means a fanta-

sy. In fact, it’s the plan for two approximately

400-MW projects currently in development:

The Texas Clean Energy Project (TCEP),

near Odessa, and Hydrogen Energy Califor-

nia (HECA), planned for a site near Bakers-

field. Both locations are in the heart of their

state’s oil industry and close to substantial

commercial agriculture.

TCEP, being developed by Summit Power

Group, plans to employ two Siemens SFG-

500 gasifiers and a Siemens SGT6-PAC

5000F gas turbine. Fluor will provide the en-

gineering and construction, and Linde Group

subsidiary Selas Fluid Processing will supply

the syngas, CCS, and chemical processing

equipment. TCEP will be sized to produce at

least 400 MW gross, though normal baseload

operation will be 377 MW. Of that, about half

will be used on site: 105.7 MW to run plant

equipment, 15.7 MW for CCS, and 42.2 MW

for producing fertilizer. The remaining 214

MW will be sold to the grid.

The TCEP plant will use low-sulfur Pow-

der River Basin coal. It will capture around

90% of its CO2 emissions and produce al-

most 3 million tons of CO2 for EOR. The

Permian Basin area where TCEP will operate

has been employing EOR for more than 40

years and has a robust pipeline infrastruc-

ture for transporting CO2, but demand for

it currently exceeds supply by about 300%.

According to project documents, the largest

chunk of the project’s revenue will actually

come from fertilizer sales—about 700,000

tons per year—rather than power sales.

HECA will be located in one of California’s

oldest oil basins, the Elk Hills play (Figure 2)

in the Central Valley. Most of the oil from that

field has been extracted, however, and increas-

ingly energy-intensive methods are necessary

to get out what’s left—thus the potential for

CO2 EOR. Unlike TCEP, HECA will use a

mixture of coal and petcoke from Southern

California refineries. HECA will also be built

by Fluor, using Mitsubishi Heavy Industry

gasifier technology and gas turbines.

HECA is being developed by Massachu-

setts-based SCS Energy, which acquired it from

original developers BP and Rio Tinto. HECA

will be able to generate around 280 MW of

electricity for the grid, with the balance being

used on-site. The facility is projected to capture

about 3 million tons of CO2 and produce about

1 million tons of fertilizer each year.

Despite the attractive synergy of these

projects, both are relying heavily on public

support. TCEP has received $450 million

from the Department of Energy’s Clean Coal

Power Initiative, while HECA has received

$408 million. TCEP will also receive sub-

stantial tax exemptions for its CCS and EOR

sales from the State of Texas. In both cases,

the DOE grants are only a fraction of the

approximately $2.5 billion to $3 billion the

plants will cost.

HECA is about two-thirds of the way

through the permitting process and is still ne-

gotiating purchase agreements for its electric-

ity, fertilizer, and other products. Jim Croyle,

CEO of SCS Energy, told POWER he expects

construction to begin some time in the fourth

quarter of 2014.

2. Multitalented. The Hydrogen Energy California project will supply about 280 MW to the

California grid as well as fertilizer for Central Valley farms and CO2 for enhanced oil recovery in

the Elk Hills oil field. Courtesy: Hydrogen Energy California


The fuTure of coal-fired generaTion

Laura Miller, Summit Power’s director of projects, told POWER that TCEP had hoped to close financing in December, but its en-gineering, procurement, and construction contractors (Siemens, Linde, and Sinopec En-gineering Group) are having difficulty staffing the project because of the oil and gas boom in Texas, which has made skilled labor extremely expensive and hard to find. Its plan is to break ground as soon as possible in 2014.

TCEP suffered a setback on Jan. 6, when CPS Energy, which supplies power to the San Antonio area, allowed its power purchase agreement (PPA) with Summit to expire. It blamed repeated delays in getting TCEP built and the changing power market as a result of falling natural gas prices. Still, CPS said it would “consider the possibility of an updated PPA with the Texas Clean Energy Project in the future” and that it “remain[s] hopeful this project can proceed.”

Only one other polygeneration project is under development, but it’s one with some structural advantages not enjoyed by TCEP or HECA. India-based Reliance Industries is planning to add what may be the world’s largest gasification complex to what is al-ready the largest oil refinery in the world, Jamnagar in Gujarat. Reliance has thus far

run Jamnagar’s 1.5-GW cogeneration power plant on imported liquefied natural gas, but transitioning to syngas from the refinery’s excess petcoke (as well as coal) will allow it to reduce its fuel costs. With the refinery al-ready in place, the polygeneration plant will have a captive customer for it output. The project, to be built by Fluor using CB&I’s E-Gas technology and Linde air separation units, is planned in two phases of eight gasifi-ers each with initial start-up in mid-2015.

The Way ForwardThe companies working on polygeneration are frank about the need for better policy support if the sector is to take off. Speaking to a 2012 meeting of the Interstate Oil and Gas Compact Commission, Summit Power Vice President Jeff Brown openly conceded that the market does not currently support the extra costs of carbon capture, even with ad-ditional revenues from selling CO2, fertilizer, and other products. But the current system for carbon sequestration tax credits under Section 45Q actually makes the situation worse.

“As the tax credit is currently structured, no individual facility can predict the number of years it will be able to receive sequestra-tion tax credits,” Miller said. “As there is no

assurance that a facility will be able to receive sequestration tax credits for a set number of years, lenders are unwilling to assume the risk that the tax credits will be available.”

Summit and other groups working in CCS have been pushing for an amendment that would allow a CCS project to reserve credits once construction begins. Right now, the credit is capped at 75 million tons on a first-come ba-sis, and those credits are being used up by oil and gas companies conducting conventional EOR rather than true CCS. “We can’t put the $10/ton we ought to be getting for doing EOR with 2.5 million tons per year of captured CO2 because there is no protocol for reserving credits for individual projects, we don’t know how much has been claimed already—and, worse, the IRS won’t tell anybody how much has been claimed or who is actually eligible to make claims,” Miller said.

Jeff Phillips, manager of advanced fossil generation and CCS R&D for the Electric Power Research Institute, said the advan-tage in polygeneration is likely to go to early entrants with existing infrastructure and ex-pertise in chemical processing, such as Reli-ance. One challenge is financing projects that are unfamiliar to the investment community because they operate in both the power and chemical markets. “It’s difficult to find inves-tors who want to be involved in all of that,” he said, given how it can take many of them out of their comfort zone.

Another challenge that will need to be ad-dressed is selling polygeneration to public util-ity commissions in regulated markets, because it’s difficult to separate out the power costs from the chemical costs in calculating the rate-base. Here, the integrated nature of the plant is actually a problem because of the amount of equipment used for both power and chemical production and how operators will shift back and forth depending on market fluctuations. “You can get complicated in a hurry,” he said. “There’s a bigger regulatory hurdle” in build-ing polygeneration plants in those markets.

Croyle agreed, noting that polygeneration is a learning process for regulators as well as developers. “This is something that a myriad of local, state, and federal agencies are deal-ing with for the first time, and it’s easy to un-derstand their challenge,” he told POWER.

Phillips expects it to be the mid-2020s at the earliest before polygeneration in the U.S. progresses beyond the TCEP and HECA projects. But as with everything in the pow-er sector, things could easily change if the economics shift. “If gas prices surprise the prognosticators and go up, that might spark earlier interest,” he said. ■


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The Role of Activated Carbon in a Comprehensive MATS StrategyConventional wisdom suggests that coal-fired power plants employing selective

catalytic reduction and a wet scrubber can comply with Mercury and Air Tox-ics Standards (MATS). Long-term testing at Southern Co. demonstrates acti-vated carbon can be a key component of a reliable whole-plant solution.

Brandon Looney, Nick Irvin, Chethan Acharya, Joe Wong, and Sheila Glesmann

The U.S. Environmental Protection Agen-

cy’s Mercury and Air Toxics Standards

(MATS) set limits on the emissions of

mercury (Hg) and other pollutants for coal-

fired power plants. Many plant operators have

begun developing compliance strategies in

anticipation of the effective date of April 16,

2015 (or April 16, 2016, for facilities that

have received an extension). Conventional

wisdom suggests that mercury (Hg) compli-

ance can be achieved using existing pollution

control equipment, particularly a combination

of selective catalytic reduction (SCR), which

addresses oxides of nitrogen (NOx), and wet

scrubbers, which deal with sulfur and other

acid gases. This configuration is common in

power plants burning higher-sulfur coals.

Extensive mercury monitoring conducted

by Southern Co. challenges this myth. South-

ern Co. also evaluated various active mercury

control technologies including: activated car-

bon injection (ACI) prior to the electrostatic

precipitator (ESP), ACI with a baghouse ret-

rofit, and powdered activated carbon (PAC)

as an additive to the wet scrubber.

This article presents results and lessons

learned from such testing, plus recommended

guiding principles for developing an effective

MATS compliance strategy:

■ Mercury emissions are highly variable.

■ Complementary technologies are useful in

dealing with variability.

■ Each plant should have an engineered, or

active, mercury control technology.

■ Plant-specific testing may be necessary to

demonstrate mercury controls.

A History of Activated CarbonActivated carbon injection for coal-fired

power plants was first tested and introduced

through programs conducted collaboratively

by the U.S. Department of Energy, National

Energy Technology Laboratory, Electric Pow-

er Research Institute, and utilities in the early

1990s. Since the mid-2000s, ACI has been de-

termined to be both the best available control

technology (BACT) and maximum achiev-

able control technology (MACT) for mercury

control on a case-by-case basis for certain

coal-fired power plants, and today there are

hundreds of commercial systems operating or

contracted, designed to control mercury emis-

sions to meet state mercury limits, permit lim-

its, or MATS mercury standards.

Those early Generation 1 PACs worked

under certain conditions, but they were not

optimized for mercury capture. Rather, they

were transferred from other applications

such as water cleanup (a liquid-phase rather

than gaseous-phase use) and municipal solid

waste flue gas, which have order-of-magni-

tude higher mercury concentrations than the

dilute coal-fired flue gas stream.

Since 2011, innovative products have been in-

troduced, engineered, and designed specifically

for mercury capture for coal-fired power plants.

ADA Carbon Solutions introduced its new

trademarked next-generation FastPAC series in

2011 and has turned its focus to development

of sulfur trioxide (SO3)-tolerant PACs and other

specialty applications. Application of a more

detailed, fundamental scientific understanding

of Hg capture mechanisms, as well as more pre-

cise tuning of the PACs’ surface, pore structure,

and particle morphology, have led to significant

advancements in dealing with the complex air

pollution control system chemistries and diffu-

sional and reaction kinetics, leading to the intro-

duction of new advanced PACs with enhanced

Hg capture efficacy and efficiency.

Since then, and in conjunction with the more

accelerated recent pace of laboratory prototyp-

ing and field demonstrations, the rate of innova-

tion has picked up. One of the rapid prototyping

tools that ADA Carbon Solutions (Figure 1)

uses to quickly test and prove out new products

is its Dynamic Mercury Capture test, introduced

this February at the Energy, Utility and Environ-

ment Conference. This test is the first commer-

cially employed bench-scale test that achieves

in-flight, dynamic capture of mercury rather

than utilizing a fixed bed, which allows for rapid

product development.

As a result of these advancements, there are

several next-generation PACs today that are

designed to work more efficiently in myriad

applications, and the results are creating better

understanding and changing some assumptions

and paradigms established in the earlier work.

The Science Behind an Effective MATS Compliance StrategyThere are three essential steps to mercury

control: The elemental mercury (Hg0) must be

converted to oxidized mercury (Hg2+); it must

contact a medium that will remove it from the

flue gas stream; and it must be captured and

sequestered effectively and securely by that

medium for removal from the power plant.

All three of these mechanisms are necessary

for mercury control, and the total mercury

control cannot exceed the product of these

mechanisms as per the following:

(Conversion efficiency) x (Contact effi-

ciency) x (Capture efficiency) = Overall mer-

cury control %

For example, consider a plant with an SCR

system and wet scrubber. If native oxidation,

SCR, halogenated sorbents, and/or additives

1. Silos at ADA Carbon Solutions Red River Plant, Coushatta, La. Courtesy: ADA Carbon Solutions



can provide 95% oxidation of the flue gas

mercury (see “Optimized SCR Catalysts Max-

imize Mercury Removal Co-Benefits,” in the

December 2013 issue of POWER, available at

powermag.com), then that 95% is available to

be contacted by a removal media. In this case,

if 95% of the mercury is oxidized at the point

of entry to the wet scrubber, then the mass

transfer limitations of the wet scrubber will

dictate the limit of contact in this device.

Scrubber contact with oxidized mercury

has been observed in Southern Co.’s units to

be very efficient. So in the case of a mod-

ern wet scrubber with no bypass, if the wet

scrubber’s theoretical mass transfer limit is

98% contact, and if this directly translates

into an operational limitation for mercury,

the amount of the fuel mercury that poten-

tially is available for capture in the wet scrub-

ber is (95%) x (98%) = 93%.

Contact efficiency, of course, will be lower

in wet scrubbers with a bypass. For example,

15% bypass would limit the mercury avail-

able for scrubber contact to 85% of the fuel

mercury, or (85%) x (95% oxidized) = 81%

that can be controlled by the scrubber.

At this point, the fuel mercury in the wet scrub-

ber will be divided into many forms. It can be in

the solution as one of several oxidized mercury

species, or it can be in particulate form on sol-

ids in the scrubber. Elemental mercury will pass

through unaffected. The oxidized and particulate

mercury residing in the scrubber then need to be

captured and removed from the system.

The form and removal of this mercury

depend on scrubber chemistry and partition-

ing within the solution and solids, and can

vary significantly from plant to plant, as well

as over time. Southern Co. has observed a

wide range (from less than 10% to greater

than 90%) of the mercury to be in the aque-

ous phase. In any case, the mercury needs

to be separated from gypsum, which can be

achieved by processing through a hydrocy-

clone. Stable capture can be obtained with

activated carbon and is described below.

But when evaluating a MATS strategy, oper-

ators of each unit have to ask “Is this enough?”

In certain cases 81% to 93% average capture

may not be sufficient, or a power plant opera-

tor may want options for compliance across a

range of operating scenarios. Because MATS

compliance is continuous and averaged over a

defined period, a given unit may require addi-

tional capture only at certain times. And this is

the best-case scenario of a unit with both SCR

and a wet scrubber installed. For any unit with

different technologies, the analysis needs to be

adjusted accordingly.

Another significant consideration is that

the effective contact, conversion, and capture

must occur with minimal impact on the bal-

ance-of-plant operations. For example, PAC

may be treated with additional constituents

to promote conversion of elemental mercury

into its oxidized form for ease of capture.

However, depending on the constituent added,

downstream effects such as equipment corro-

sion could increase. Another benefit of an ac-

tive mercury control is to allow the original air

pollution control equipment to be operated to

maximize the original control purpose.

An overall strategy for MATS compliance

includes considering real-world data and inte-

grating this with the science underlying con-

trol technologies. For example, in the case of

a wet scrubber, the fate of the mercury in the

liquid or solid phase is a key to determining

whether the strategy is sustainable and ef-

fective over the long term. Each unit’s actual

data and emissions variability, the alternatives

available at relatively low additional capital

and operating costs, and the long-term reli-

ability of constantly meeting the MATS limit

are the focus of the compliance planning.

Southern Co. BaselinesMonitoring and test-program data have

shown mercury emissions vary signifi-

cantly with unit operational variability and

co-control of existing air pollution control

equipment, which are very unit-specific (see

“Determining AQCS Mercury Removal Co-

Benefits,” in the July 2010 issue). Variables

include the coal itself, as well as many op-

erational variables such as load range, SCR

bypass, particulate matter device cycles, and

scrubber operation. Preserving the primary

purpose of co-control equipment is key given

the size and complexity of these systems.

Continuous emissions monitoring (CEMS)

data from tested units have shown that the

combination of SCR and a wet scrubber on

bituminous coal may benefit from including

an active mercury control technology to com-

ply with MATS (Table 1).

The data shows that without a mercury-spe-

cific control method, each unit could be out of

MATS compliance between 5% and 33% of the

time, based on a 30-day rolling average. And it

relegates both oxidation and capture of mercury

to passive processes—the SCR and wet scrub-

ber. Because oxidation (from Hg0 to Hg+2), con-

tact with a collection media, and capture in an

engineered sorbent material or control device

for removal from the system are all required to

achieve effective mercury control, leaving these

critical steps to passive systems may not be suf-

ficient to ensure constant MATS compliance.

The table also shows the value of long-term

data. Short-term measurement periods do give

valuable insights into Hg capture performance,

but they do not necessarily reflect what will

happen over a longer time period when compli-

ance periods are mimicked, as shown in Table

1. In fact, short-term test results can appear to

comply with the standard even though longer-

term measurements reveal exceedances.

To solve the MATS compliance puzzle

for each facility, the emission control train

configuration must be taken into account, as

well as fuel type, load profile, and any future

retrofits that may be planned.

Take as an example Unit A, which, based

on historical data, could have exceeded the

30-day MATS average of 1.2 pounds per

trillion British thermal units (lb/TBtu) 25%

of the time over about a two-year period.

Achieving 1.2 lb/TBtu over the period mea-

sured on Unit A would have required approx-

imately an additional 56% mercury capture

at peak emission conditions (depending on

fuel assumptions), and to provide compli-

ance margin at 1.0 lb/TBtu would require ap-

proximately an additional 87% capture, more

than that provided by the existing SCR and

scrubber combination alone.

Plants benefit from active engineering

controls. To obtain reliable and controllable

mercury capture, ACI has been tested at sev-

eral Southern Co. plants. The approach in-

cluded conducting test programs on several

representative units and applying the data

as applicable to analyze similar units. Key

learnings from each test program helped de-

fine the overall MATS strategy.

Unit F Case StudyUnit F is an 865-MW unit built in 1976 that

would not have met the future MATS 30-day

rolling average mercury emissions in about 5%

UnitNumber of rolling

30-day periods (N)

Percentage of time N where

30-day average Hg exceeded

MATS limit of 1.2 lb/TBtu

Overall mean

Hg (lb/TBtu)

99th percentile

Hg (lb/TBtu)

A 402 25% 0.82 1.87

B 773 24% 0.83 1.59

C 926 26% 0.92 1.90

D 917 33% 0.97 1.62

E 1,003 18% 0.89 1.87

F 778 5% 0.71 1.30

G 695 14% 0.97 1.35

Table 1. Mercury CEMS data from seven Southern Co. units. Source:

Southern Co.



of the cases when evaluating historical mercury

CEMS data over a period of about two years.

Typical fuel for Unit F is a bituminous coal,

nominally 2.5% sulfur by weight. The future

configuration of Unit F is depicted in Figure 2.

With Unit F, two separate, temporary ACI

systems provided by ADA-ES Inc. and Nol-Tec

Systems Inc. were installed to accommodate

the full test range of PAC injection rates. Up-

stream of PAC injection, an alkali sorbent injec-

tion system provided by Nol-Tec was available

to inject hydrated lime. PAC and lime were then

removed along with the fly ash in the ESP.

Reliable, active MATS compliance on this

critical unit is a key component of Southern

Co.’s strategy. Compared to the baseline data,

Unit F would require a minimum of 11% ad-

ditional control to meet the MATS mercury

limit of 1.2lb/TBtu, and additional control to

maintain a margin on the compliance level.

In addition, Unit F’s configuration is similar

to other Southern Co. units that could benefit

from the test data. The Southern Co. units

analyzed would benefit from varying levels

of control to guarantee MATS compliance,

up to 60% additional mercury control over

co-control (also known as native capture).

Upon reviewing the available CEMS data for

Unit F, Southern Co. developed a test program

to determine whether MATS compliance could

be reliably addressed using PAC either through

in-duct injection (ACI) or as a scrubber additive

(in conjunction with STEAG Energy Service’s

technology and injection system).

At the time it was well understood that

Generation 1 and Generation 2 PACs had ex-

perienced interference with mercury capture in

flue gas upstream of Unit F’s scrubber in the

presence of SO3 levels up to 15 to 20 parts per

million (ppm). Empirical evidence has clearly

shown that the presence of SO3 greater than 5

ppm can inhibit mercury capture in conven-

tional Generation 1 PAC. Alkali sorbent injec-

tion such as hydrated lime, sodium bicarbonate,

trona, and the like can be used to mitigate the

SO3 prior to PAC injection, and combining this

with a higher-SO3-tolerant PAC is one solution

that Southern Co. was interested in evaluating.

Minimizing the alkali sorbent injection is ad-

vantageous from both an economical perspective

and because it minimizes the potential impact on

ESP particulate matter capture performance.

SO3-tolerant PAC such as ADA Carbon Solu-

tions’ registered FastPAC Premium-80 can help

achieve this goal, obtaining good mercury cap-

ture while minimizing both dry sorbent injection

(lime in this case) and PAC quantities.

Test results from Units F and E show there

are alternative options for mercury control

on these units, and also inform strategies for

other untested units. Depending on the de-

gree of control needed or desired upstream

of the scrubber, flue gas injection of FastPAC

Premium can be used in conjunction with

hydrated lime for control levels more than

70% (demonstrated at Unit F), or FastPAC

Premium-80 can be used without hydrated

lime injection for more than 50% capture of

mercury (demonstrated at Unit E).

Figure 3 shows the results achieved at these

two units. These control levels more than ad-

dress the incremental levels needed at Units A

through G for MATS compliance. An advan-

tage of controlling mercury at the ESP is that no

PAC is introduced to the scrubber, so gypsum

quality is unaffected. Also, the balance of the

complex, multi-phase chemistry in the scrub-

ber—critical to successful acid gas control—is

unaffected by additives and mercury loading.

Figure 4 shows the benefit of adding ACI

with either an ESP or baghouse at Unit B, as

an example. For this unit, which experienced

baseline 30-day rolling averages greater than

the MATS limit 24% of the time, it is clear

that ACI upstream of the ESP provides com-

pliance with a significant operating margin,

and that a baghouse retrofit is not necessary

for mercury capture in all circumstances.

In separate testing, Southern Co. evalu-

ated an ADA Carbon Solutions PowerPAC

in collaboration with STEAG for mercury re-

emission control into the flue gas desulfuriza-

tion (FGD) absorber tower. This testing was

performed without the injection of PAC and

alkali sorbent upstream of the scrubber. This

alternative solution was of interest to Southern

Co. for potentially providing more options for

solving the MATS compliance puzzle.

The carbon slurry was injected directly

into the forced oxidation wet limestone ab-

sorber (FGD) with an oxidation reduction

potential (ORP) of 600–700 millivolt. The

baseline testing of the flue gas at full load

revealed an FGD inlet elemental Hg of less

than 0.5 lb/TBtu with the baseline stack Hg

emission of 1.7 lb/TBtu. The baseline testing

revealed that periods of Hg re-emission (con-

version of oxidized Hg back to elemental Hg)

were taking place in the FGD.

With the addition of PowerPAC in the FGD

with a concentration range of 200–300 ppm

(average carbon injection rate: 100 pounds per

hour), the total Hg stack emission was reduced

to 0.7 lb/TBtu while the FGD inlet elemental

Hg entering the FGD remained at less than 0.5

lb/TBtu. The dissolved phase Hg in the FGD

slurry decreased from 95% during baseline

to 4% during the carbon addition test, while

the solid phase Hg increased from 5% during

baseline to 96% during the carbon addition

test. Mercury partitioning from the liquid to

the solid phase of the FGD slurry correspond-

ing to PAC addition was the primary reason

Rem

oval

of

vapo

r-ph

ase

Hg

(%)

PAC injection ratio (lb/MMacf)

◆ FastPAC Premium FastPAC Premium + hydrated

lime ▲ FastPAC Premium-80 FastPAC Premium-

80 + hydrated lime

3. In compliance. Here are results of

using FastPAC Premium and FastPAC Premi-

um-80 injection in the ESP with and without

hydrated lime at Units E and F at about 15 to

20 ppm SO3. Source: Southern Co.

Economizer

Selective catalytic

reduction

Dry sorbent

injectionActivated

carbon

injection

Air

preheater

Electrostatic precipitator

Wet scrubber

Stack gas

2. Unit F after MATS controls are installed. Source: ADA Carbon Solutions

80

70

60

50

40

30

20

10

0

0 2 4 6 8 10



for the reduction of Hg re-emission.

Testing occurred on a unit that does not

have any hydrocyclones installed after the

FGD. To determine the fate of the Hg, a pilot

hydrocyclone was used to validate the separa-

tion of the Hg in carbon from gypsum. The

Hg-laden carbon was found to be in the over-

flow of the hydrocyclone and was effectively

removed from the gypsum underflow. The

addition of the ADA carbon in the FGD was

effective in reducing Hg re-emission to South-

ern Co. compliance levels and is a good, cost-

effective option for MATS compliance.

PAC Usage ConsiderationsExtensive testing conducted by Southern Co. un-

derscores the high variability of mercury emis-

sions over time and the importance of active,

engineered control such as ACI, even in systems

with SCRs and wet scrubbers. Looking at vari-

ous alternatives provides trade-offs that can be

assessed to determine the overall lowest impact

to plant performance while reliably maintaining

compliance and cost-effectiveness.

Although PAC injection with ESP recov-

ery of the PAC enables the scrubber and the

gypsum to be unaffected, there are potential

ash consequences to take into consideration.

These can be mitigated with some of the new-

er PACs that require lower quantities and have

steeper capture responsiveness in the range

of interest and by optimizing the system over

time. Injecting PAC into the scrubber avoids

potential ash effects, but then it could result

in the scrubber chemistry being affected and

may risk gypsum quality. In tests at Southern

Co., the gypsum and chemistry quality were

maintained with scrubber PAC addition.

PAC can significantly contribute to MATS

compliance on scrubbed units with SCRs in

several ways. Depending on the configura-

tions, fuel, plant goals, and results of field

demonstrations, it may be more beneficial

to utilize the active control of PAC upstream

of the ESP, where it does provide enhanced

balance-of-plant considerations, does not in-

terfere with scrubber operations, and keeps

mercury out of the scrubber, thus avoiding

any issues with re-emissions.

On the other hand, advanced PACs can

be effective as scrubber additives, enabling

good scrubber operation and sustainable

control levels. Impacts to gypsum need to be

assessed at individual scrubbers.

In either case, when control using advanced

next-generation PACs is applied to the original

baseline CEMS data from the scrubbed units,

the results show that compliance with margin

is achieved continuously and reliably. ■

—Brandon Looney, retail generation development project manager; Nick Irvin, advanced energy systems R&D manager; and Chethan Acharya, research engineer,

are with Southern Co. Joe Wong, chief technology officer, and Sheila Glesmann

([email protected]), senior vice president of environmental, are with

ADA Carbon Solutions.


Hg

emis

sion

s, 3

0-da

y av

erag

e (lb

/TB

tu)

July 2009 Jan 2010 July 2010 Jan 2011 July 2011

■ No change (24%) ■ ACI-ESP (0%) ■ ACI-BH (0%)

4. Doing nothing is not an option. Unit B Baseline CEMS data over time, showing

calculated effect of an ESP or baghouse (BH)

retrofit. Baseline (red) data reflect actual mea-

surements. The ACI-ESP (blue) and ACI-BH data

(green) reflect projected (calculated) levels of

control based on test results. The green line at

1.2 lb/TBtu represents the future MATS mercury

standard for these units. Source: Southern Co.

2

1.8

1.6

1.4

1.2

1

0.8

0.6

0.4

0.2

0

©2014 Diamond Power International, Inc. All rights reserved.

www.a-s-h.com 1.888.ASH.PARTS

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Converting Sulfur from Flue Gas into FertilizerAs environmental regulations tighten—both in the U.S. and around the world—

coal-fired power plants continue to look for ways to operate economically. Though reuse and sale of coal combustion by-products has a long history, one new approach could benefit a somewhat unlikely partner industry.

Gail Reitenbach, PhD

The history of power plant emissions

regulations and control technologies is

largely one of preventing elements that

are bad for the environment or human health—

including sulfur dioxide, particulate matter,

and nitrogen oxides—from being dispersed to

the environment. But sometimes it’s possible

to take advantage of the by-products of the

control technologies and put them to good use

in the environment. That’s the case with a new

process that converts sulfur to fertilizer.

Charah Inc. has developed a technology

that allows sulfur captured from power plant

exhaust gases to be pelletized into a calcium

sulfate fertilizer product that returns vital

nutrients to farm fields. To understand why

Charah and coal-fired power plants would

find this worth doing, you need to understand

the role of sulfur in the environment and the

economics of the process.

Sulfur’s Ups and DownsWhen coal is burned in a boiler to generate

electricity, the naturally occurring sulfur in

the coal is released into boiler exhaust gases.

Before it was regulated, coal sulfur was dis-

charged into the atmosphere through plant

stacks. The U.S. Environmental Protection

Agency (EPA) first started regulating power

plant air emissions in 1971. According to the

EPA, these air quality controls covered SO2

because exposure to the gas can cause ad-

verse respiratory effects, it can combine with

other gases to produce harmful particulates,

and it is a primary cause of acid rain.

Declines in SO2 emissions began soon

after enactment of the 1990 Clean Air Act

Amendments, which established a national

cap-and-trade program for the gas. Because

coal-fired units accounted for a large share

of SO2 emissions, the program (which also

covered NOx) provided an economic incen-

tive for coal-fired power plants to reduce

emissions by installing pollution control

systems, burning lower-sulfur coal, or gen-

erating less electricity.

All plants built after 1978 are required to

clean the sulfur from coal combustion gases

before they go up the stack. They do so with

flue gas desulfurization (FGD) units, com-

monly called “scrubbers.” The EPA reports

that by the end of 2011, 60% of the U.S. coal

fleet had FGD scrubbers installed.

As scrubbers began to remove sulfur from

exhaust emissions, and some plants switched

to low-sulfur coal, the amount of sulfur in the

air decreased. EPA data shows that between

1980 and 2012 concentrations of atmospher-

ic SO2 in the U.S. decreased approximately

78% (Figure 1).

But sulfur need not always be a net nega-

tive for coal-fired plants. Since the 1990s,

captured sulfur from flue gas has resulted in

the production of high-quality gypsum, hy-

drated calcium sulfate: CaSO4-2H2O. That

synthetic gypsum can then be beneficially

used in a number of common applications,

from plaster and wallboard to cement and

fertilizer. Though gypsum occurs naturally

(and even lends its name to a town in Colo-

rado with a history of gypsum mining and

processing), synthetic gypsum has advan-

tages in that it doesn’t have to be mined, and

it recycles what would otherwise be a waste

product that power plants would have to pay

to dispose of in landfills. Use of synthetic

gypsum has also reduced costs for drywall

manufacturers.

Coal Country ConversionCharah Inc.—a Louisville, Ky.–based com-

pany that specializes in total ash manage-

ment, including recycling by-products from

coal-fired power plants—has developed a

technology that allows sulfur captured from

power plant exhaust gases to be pelletized

into a calcium sulfate fertilizer product, pro-

viding an improvement, it says, over previ-

ous forms of fertilizer created from power

plant emissions.

Charah’s new facility housing this process

is located at the 1,472-MW Louisville Gas

and Electric Co. (LG&E) Mill Creek Gener-

ating Station, in Jefferson County, Ky. Coal

provides the majority of power for Kentucky,

and this plant went into commercial opera-

tion in 1972 and was LG&E’s first to utilize

cooling towers to protect the Ohio River’s

aquatic life.

Plant owners are committed to keeping

1. Sulfur reduction. This graph shows SO2 air quality as a national trend from 1980 to

2012 (annual 99th percentile of daily maximum 1-hour average) based on 57 sites. There was a

78% decrease in the national average over that period. Source: EPA

Conce

ntr

ati

on (

ppb)

350

300

250

200

150

100

50

0

1980 1990 2000 2010

National standard



this plant online. Starting in spring 2012,

LG&E planned to spend approximately $1.3

billion to modernize the FGD systems and

install fabric filter baghouses for increased

particulate and mercury control on all units at

the plant. This construction project is under

way and will continue through 2015. And in

November 2012, LG&E officials announced

that, as part of the $1.3 billion, they would

be spending approximately $940 million on

clean coal technology at the station. Mike

Kirkland, general manager of Mill Creek

Station, told POWER that would include

replacing existing scrubbers with new ones,

installing new baghouses, and replacing ex-

haust stacks.

Mill Creek burns approximately 4 million

tons of high-sulfur coal annually, primarily

sourced from the Illinois Basin. Kenny Tapp,

senior by-products coordinator for LG&E

and KU Services Co., noted that over 60%

of the plant’s fly ash is used in the manufac-

turing of cement and concrete; the economic

value of the fly ash utilization in concrete is

estimated to be in excess of $5,000,000 to

the regional manufacturers of concrete- and

cement-based products. In addition, the plant

realizes significant savings on landfill capac-

ity and associated costs, though neither the

plant nor Charah would release detailed data

on these savings.

The plant has had wet scrubbers and a FGD

slurry processing plant on its property since

1978, and its processing plant can dewater up

to 1,800 tons of gypsum per day for use in the

manufacturing of cement, drywall, or other

uses. Now that gypsum has expanded utiliza-

tion opportunities as fertilizer. This additional

use can consume 200,000 plus tons per year of

the total gypsum annual production.

From Flue Gas to GypsumThe sulfur-scrubbing process at a coal-fired

power plant typically involves grinding high-

calcium limestone to powder and then mixing

it with water to form a lime slurry. The lime

slurry is then sprayed into a contact chamber,

where it combines with boiler exhaust gases

and the sulfur reacts with the lime to become

chemically bound.

Scrubbers come in two types: wet and dry.

In wet scrubbers, the ratio of lime slurry is

greater and a slurry by-product is produced.

In dry scrubbers, the ratio of slurry to hot

exhaust gases is controlled, to dry the lime

slurry and result in a dry product. Charah

has developed a process to beneficially use

the wet scrubber slurry dewatered gypsum to

manufacture a sulfur and calcium fertilizer.

Wet scrubbers capture sulfur from all

four units at Mill Creek. The lime and sul-

fur slurry is aerated to create calcium sulfate,

dewatered to produce high-quality gypsum,

and then processed to make fertilizer at the

adjacent Charah facility (Figure 2).

Mill Creek produces approximately

600,000 to 800,000 tons per year of calcium

sulfate gypsum. The gypsum products are

stockpiled onsite, and Charah manages the

gypsum on behalf of Mill Creek.

From Gypsum to FertilizerThe Mill Creek gypsum typically has higher

purity than natural gypsum because it has

less inert impurities. Mill Creek gypsum is

90+% pure calcium sulfate. Charah utilizes

this calcium sulfate gypsum to manufacture

a patent-pending fertilizer named “SUL4R-

PLUS product” that can be used to replenish

the sulfur and calcium in farm soils, turf, and

specialty crops (see sidebar). As Danny Gray,

executive vice president of Charah, explained,

this process essentially closes the cycle loop

for the sulfur that once was returned to farm

fields with rainfall, but now is removed by

the power plant emissions control equipment

before discharging the cleaned exhaust gases

into the atmosphere.

The Charah plant accepts the gypsum

when it discharges from the existing Mill

Creek dewatering facility onto a new con-

veyor that moves it directly into the Charah

plant. That gypsum serves as the feed stock

for the processing steps that include pellet-

izing to create the granular SUL4R-PLUS

product. Although synthetic gypsum has

previously been used as a soil amendment,

Charah says it is the first to pelletize the by-

product, which makes application easier for

the farmer.

That granular product is stored inside the

Charah warehouse until it is transported to

customers. Custom truck loading is done in-

side the warehouse facility. Charah also has

barge-loading capability, as well as onsite

railcar-loading capacity to meet customers’

logistics needs. Because the Kentucky plant

is located near the Ohio River, Charah can

reach distant markets by barge at economi-

cal rates.

The sulfur level of SUL4R-PLUS prod-

2. Conversion site. The Charah product

manufacturing facility sits on the Louisville

Gas and Electric Co.’s Mill Creek Generat-

ing Station property in southwest Jefferson

County, Ky. Courtesy: Charah Inc.

Sulfur’s Role in Agriculture

A key component of agriculture produc-

tion in the U.S. has been the proper de-

ployment of various types of fertilizers.

Historically, the primary fertilizers have

been nitrogen (N), phosphorus (P), and

potassium (K). High-efficiency farm-

ing requires that particular attention be

focused on secondary nutrients, which

include calcium (Ca), magnesium (Mg),

and sulfur (S). Sulfur has become more

important to high production and is of-

ten referred to as the “fourth major nu-

trient.” Each of the secondary nutrients

is essential for high-intensity farming

activities. Though required in smaller

quantities than NPK, they are essential

for plant growth.

As a nutrient, sulfur is needed in signif-

icant quantities by many crops that utilize

approximately the same amount of sulfur

as they do phosphorus. A typical crop,

such as corn or soybeans, can extract and

remove from the soil 12 to 20 pounds

of sulfur per acre (Table 1). The sulfate

ion (SO4) is the form of sulfur absorbed

by most plants. Replenishment of sulfur

is crucial to maintain high production on

each acre. Typical sources of sulfur include

organic matter, ammonium sulfate, gyp-

sum, zinc sulfate, and elemental sulfur.

Typical nutrient uptake

Crop Yield Nitrogen (lb/ac) Phosphate (lb/ac) Sulfur (lb/ac)

Corn 200 bu/ac 150 85 15

Soybeans 60 bu/ac 240 48 12

Wheat 80 bu/ac 92 44 7

Alfalfa 6 ton/ac 225 60 30

Notes: ac = acre, bu = bushels.

Table 1. Typical nutrient uptake. Source: Charah Inc.



uct is greater than 16%, its calcium level is

greater than 20%, and the product looks like

and handles like any other granular fertilizer

(Figure 3). Farmers can replenish the sulfur

depleted by crops from farm soils by applying

SUL4R-PLUS product along with their other

fertilizers. The product has a unit weight of

approximately 50 pounds per cubic foot and

spreads in common distribution equipment in

a single pass across the field.

Win-Win EconomicsIn nations where power plant emissions are

tightly regulated, adding beneficial reuse of

by-products is likely to become an increasingly

valued option for the future business case. At

full capacity, more than 50% of Mill Creek’s

gypsum will be beneficially used. By avoiding

disposal of the recycled by-products, LG&E re-

alizes lower operating costs, which help lower

electricity costs for the utility’s customers.

Additionally, Gray says Charah’s granular

fertilizer provides good economic value to the

American farmer, as typical prices of SUL4R-

PLUS product are 20% to 30% lower than al-

ternative sources of sulfur equivalents.

Charah’s investment of $12 million to $14

million in 2013 has provided a first-of-its-

kind manufacturing plant to convert high-

grade calcium sulfate into a new agriculture

product. The plant is designed to reclaim up

to 300,000 tons per year of gypsum and pro-

duce up to 250,000 tons of SUL4R-PLUS

product fertilizer. It also created up to 25 new

jobs in the recycling industry.

At power plants that generate a high-

quality gypsum product, Charah says a

manufacturing plant can be custom de-

signed and installed within 12 months.

Charah provides the capital for SUL4R-

PLUS plants and maintains owner and op-

erator status. Agreements between Charah

and the host power plant typically extend

over five to 15 years. Charah plans to de-

velop and install SUL4R-PLUS manu-

facturing plants throughout the U.S. at

strategic locations to meet the growing de-

mand for agricultural sulfur products. ■

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

3. From power plant to pelletized fertilizer. Courtesy: Charah Inc.

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Be Prepared for Coal Ash RegulationsThe ways of Washington are murky and slow, but once the Environmental Pro-

tection Agency finally finalizes its rules on coal combustion residuals, you’ll have to move fast to comply, so carefully consider your options today.

Brandon Bell, PE

A little over five years ago, on the night

of Dec. 22, 2008, the residents of

Kingston, Tenn., were devastated

when a dike holding back an 84-acre ash

pond broke loose. The ash pond servicing

Tennessee Valley Authority’s (TVA) Kings-

ton facility was holding 5.4 million cubic

yards of coal ash sludge that spread over 400

acres and damaged 42 houses. The release of

coal ash into the environment was so signifi-

cant that the consequences of the devastation

took approximately four years to clean up

(Figure 1). Even with significant cleanup ef-

forts, some reports estimate that as much as

500,000 cubic yards of coal ash remain in the

nearby Emory River.

Since that event, the promulgation of En-

vironmental Protection Agency (EPA) regu-

lations for coal combustion residuals (CCRs)

has been a concern of coal-fired power gen-

erators nationwide.

Double-Edged SwordAsh ponds were originally constructed as an

economical option to provide temporary stor-

age for CCRs generated from the combustion

of coal. Approximately 15% to 40% of ash

generated by coal combustion is in the form

of heavy ash agglomerations, commonly re-

ferred to as bottom ash. This ash is too heavy

to be carried by the combustion flue gases

and thus falls to the bottom of the boiler. This

ash is particularly hot (upwards of 2,400F)

and needs to be quenched and processed prior

to handling. For this reason, most pulverized

coal boilers are designed with hydraulic bot-

tom ash systems to cool, crush, and convey

these heavy ash agglomerations.

At the Kingston facility, the hydrau-

lic bottom ash system made use of an ash

sluicing (or slurry) system to convey the

cooled bottom ash to an ash pond. Once

the ash has settled in the pond, it can be

dredged and dried, then used for secondary

purposes or landfilled.

From an operational point of view, the

ponds were designed to accommodate a

significant volume of ash to maintain safe

and uninterrupted power plant operations.

However, the ash in the pond contains haz-

ardous substances (such as heavy metals)

that can be detrimental to the environment

in a catastrophe such as the Kingston Fossil

Plant release.

Regulatory and Legal RoundaboutThe EPA previously proposed regulating

CCRs in June 2010 under the authority of

the Solid Waste Disposal Act of 1970, the

Resource Conservation and Recovery Act of

1976 (RCRA), and the Hazardous and Solid

Waste Amendments of 1984 (the combined

regulations are often commonly referred to

as RCRA). Although proposed over three

and a half years ago, the regulation was never

finalized and remains in limbo.

CCRs are defined as fly ash (combustion

by-product consisting of fine particles that

rise with flue gases), bottom ash (agglom-

erated coal ash particles too heavy to rise

in flue gas), boiler slag (molten bottom ash

consisting of silica and aluminosilicates),

and flue gas desulfurization (FGD) materials

(predominantly CaSOx materials).

Fly ash consists of fine particles that are

carried through the boiler by combustion flue

gases. Because of the fine nature of fly ash,

systems designed to transport it are typically

pneumatic (vacuum or positive pressurize)

conveying systems. FGD systems are typical-

ly designed with gypsum dewatering systems

and wastewater treatment and are not a sig-

nificant concern for CCR regulation. Bottom

ash and boiler slag that are typically handled

via hydraulic bottom ash systems and make

use of ash ponds are of significant concern

for the regulation of CCRs.

Since the introduction of the proposed

CCR regulations in 2010, the power industry

has been anticipating the release of a finalized

rule. Year after year the industry has expected

the promulgation of these regulations, but no

direction has been afforded by the EPA. That

is due to change in 2014.

On Oct. 29, 2013, in the case of Appala-

chian Voices v. McCarthy, a federal judge

ruled that the EPA is required to submit a

plan and schedule for finalizing CCR regula-

tions within 60 days. Although this is a solid

push for the EPA to finalize CCR regulations,

it does not guarantee an expedited release of

final rules. As further incentive to finalize

CCR regulations, the ruling also requires the

EPA to review RCRA coal ash rules every

three years. The requirement for a regulatory

review of RCRA, as it relates to CCRs, could

open the door for environmental groups to

file suit against the EPA.

As this article was being written, a consent

decree was reached between the agency and

environmental groups on Jan. 29 that requires

the EPA to issue a proposed revision of its

RCRA rules no later than Dec. 18, 2014.

It is because of recent actions by the

courts that utilities still operating ash re-

moval systems that make use of ash ponds

need to consider alternative options for fu-

ture operations.

Subtitle C vs. Subtitle DAs part of the proposed regulation, the EPA

is considering two paths for the regulation of

CCRs (see table). The first path is using Sub-

title C of RCRA to create federally enforce-

able requirements for waste management and

disposal of CCRs. The second path utilizes

Subtitle D of RCRA, which sets performance

standards for waste management facilities

that will be enforced by states that adopt their

own coal ash management programs.

Under the Subtitle C proposal, wet han-

dling of CCRs, including the use of coal ash

ponds, would be phased out. The Subtitle D

path would require existing coal ash ponds

1. TVA Kingston coal ash release. This photograph was taken Dec. 23, 2008, a

day after the earthen containment walls hold-

ing more than five million cubic yards of fly

ash and bottom ash sludge failed. Source: Ten-

nessee Valley Authority



to be retrofitted with a composite liner to

prevent ash contaminants from leaching into

the groundwater. Although the addition of a

composite liner to an ash pond may appear

to be a simple remedy, the EPA is anticipat-

ing the cost of this path will create a strong

incentive to decommission these ponds and

transition to a landfill operation.

Compliance StrategiesWithout a clear understanding of which path

the EPA intends to take for regulating CCRs,

it is difficult to home in on a single technol-

ogy, wet or dry, to meet forthcoming regula-

tions. What is clear is that the EPA is intent

on shuttering coal ash pond operations, and

the February spill at Duke Energy’s Dan

River Steam Station’s ash pond is likely to

reinforce that position.

Several options exist to divert existing ash

slurry systems away from ash ponds. Utilities

may have the option of keeping an existing

ash slurry system and installing new ash-dry-

ing equipment, or they can convert their ash

slurry handling systems to a totally dry sys-

tem. Both options have their pros and cons

but are viable solutions to meet expected

CCR regulations.

Ash Slurry Options. The first option to

maintain an ash slurry system is to imple-

ment dewatering bins in lieu of an ash pond

(see “Reducing Bottom Ash Dewatering

System Maintenance” in the November 2013

issue at powermag.com). With this option,

dewatering bins are used both as a receiver

and separator for the ash slurry mixture.

Typically, a pair of dewatering bins is em-

ployed to maintain uninterrupted boiler op-

erations. The first bin will continue to receive

ash slurry until the collected solids (bottom

ash) have reached a predetermined capacity.

At that point, ash slurry flow is directed to

the second bin. With the second bin serving

as the active receiver for the ash slurry, the

first bin can begin to “dewater” its content

of bottom ash. Overflow and drainage water

from the bins are further processed (typical-

ly, with settling and surge tanks) for reuse in

closed-loop slurry systems. Trucks are then

used to remove the damp ash from the dewa-

tering bins for off-site disposal.

Dewatering bin technology is a very ma-

ture option, with several manufacturers offer-

ing equipment packages.

The primary advantages to this system are

the reuse of the existing slurry system, short

outage time, and the maturity of the dewater-

ing bin system. This type of system can be

erected independent of power plant opera-

tions and (because existing ash slurry sys-

tems are used) the only interfaces are with

existing slurry piping and recirculated water.

There are some disadvantages with dewa-

tering bins. These systems are not dry, and in

order to dewater the ash slurry, a significant

amount of auxiliary power is required. As is

typical with many wet systems, the dewater-

ing bins are prone to leaks, and screens used

for dewatering are subject to plugging. Be-

cause of the water quality used in this system,

excessive fouling and plugging of piping and

equipment is common. In some cases, plant

operations have required shutdowns due to

excessive buildup of contaminants in the sys-

tem. Boiler efficiency is unaffected, as the

original ash hoppers are retained.

A second ash slurry option diverts the slur-

ry from the ash pond to a remote submerged

scraper conveyor system. Clyde Bergemann

Power Group offers this ash slurry packaged

system known as ASHCON. In this system,

large overflow troughs are used in a similar

manner to dewatering bins, and a submerged

scraper continuously withdraws ash from the

water and conveys it to an ash pile for sec-

ondary use or landfilling.

Advantages of the ASHCON system are

similar to those of dewatering bins, but there

are some key benefits. The primary differen-

tiator between the ASHCON system and de-

watering bin option is the elevation at which

the technology operates.

Because the ASHCON system is much

lower to the ground, the existing water sup-

ply pumps and jet pumps under the boiler

should not need to be modified. Dewatering

bins operate at a much higher elevation, thus

requiring additional lift in the form of high-

er-horsepower pumps. As noted, dewatering

bins operate in a batch process (usually with

redundant bins), whereas the ASHCON sys-

tem is a continuous process that eliminates

the maintenance and operator involvement

associated with batch processing.

Little to no outage is required, as the

system can be erected without interrupting

power plant operations. The system reuses

existing ash hoppers and has a small footprint

relative to an ash pond.

For facilities that operate multiple boilers,

a single ASHCON system can be designed to

handle the flow from each slurry system, thus

reducing the need for redundant systems.

One disadvantage with this system is that

Subtitle C Subtitle D

Effective date Timing will vary from state to state,

as each state must adopt the rule

individually, which can take one to

two years or more.

Six months after final rule is

promulgated for most provisions;

certain provisions have a longer

effective date.

Enforcement State and federal enforcement Enforcement through citizen suits;

states can act as citizens.

Corrective action Monitored by authorized states

and EPA.

Self-implementing.

Financial assurance Yes. Considering subsequent rule using

CERCLA 108 (b) authority.

Permit issuance Federal requirement for permit

issuance by states.

No.

Requirements for storage, in-

cluding containers, tanks, and

containment buildings

Yes. No.

Surface impoundments built

before rule is finalized

Remove solids and meet land

disposal restrictions; retrofit with a

liner within five years of effective

date. Would effectively phase out

use of existing surface impound-

ments.

Must remove solids and retrofit

with a composite liner or cease

receiving CCRs within five years of

effective date and close the unit.

Surface impoundments built

after rule is finalized

Must meet land disposal restric-

tions and liner requirements. Would

effectively phase out use of new

surface impoundments.

Must install composite liners. No

land disposal restrictions.

Landfills built before rule is

finalized

No liner requirements, but ground-

water monitoring required.

No liner requirements, but ground-

water monitoring required.

Landfills built after rule is

finalized

Liner requirements and groundwa-

ter monitoring.

Liner requirements and groundwa-

ter monitoring.

Requirements for closure and

post-closure care

Yes; monitored by states and EPA. Yes; self-implementing.

Table 1. Comparison of Subtitle C vs. Subtitle D. Source: EPA



it still operates as a wet system; overflow wa-

ter from the troughs must be treated as pro-

cess wastewater. High power consumption

and no change in boiler efficiency are other

disadvantages.

Submerged Scraper Conveyor Option.

Similar to the remote submerged scraper con-

veyor system, the submerged scraper system

can be directly integrated into the ash hopper.

The existing ash slurry system is removed and a

water trough with a chain conveyor is installed

in its place. The water quenches the hot ash, and

the ash is dewatered as it is slowly dragged up

an incline. Ash is then fed to removable contain-

ers or a transfer conveyor for storage.

The submerged scraper system has advan-

tages similar to those of the remote submerged

scraper system. In addition to these advantag-

es, a submerged scraper system eliminates the

need for clinker grinders, hopper jets and slur-

ry pumps, and hopper gatehouse assemblies.

Auxiliary power is reduced, as the power

needed to drive high-, medium-, and low-pres-

sure pumps associated with slurry systems is

more than that required by the new conveyor

system. This technology is also mature, as the

first submerged scraper systems were installed

nearly 100 years ago.

For plants without extra real estate to im-

plement a remote submerged scraper system,

this system has an even smaller footprint.

Submerged scraper conveyor systems have

also been designed to combine economizer

ash and pyrite removal into the same system,

thus reducing overall maintenance costs.

The submerged scraper conveyor option also

minimizes water usage and is less complex

than dewatering bins.

Unfortunately, because of the significant

modifications needed to the ash hopper, a

major outage is required for installation. The

system is still not a dry system and requires

wastewater treatment for any water that

overflows the trough. The same combustion

characteristics exist, thus no change in boiler

efficiency will be observed.

Dry Conversions. The newest technol-

ogy for replacing an ash slurry system is a

complete dry ash conversion. An example of

a dry system designed to replace ash slurry

systems is Clyde Bergemann Power Group’s

DRYCON (Figure 2).

The DRYCON system replaces the exist-

ing ash slurry system with a dry conveyor

system at the bottom of the boiler. This poses

challenges, as the removal of a water-quench-

ing system requires a new method to cool hot

ash. To combat this cooling problem, these

systems introduce cool ambient air across the

conveyor system and into the furnace. This

air cools the conveyor components while

burning the remaining carbon in the ash. The

cooling air increases in temperature before

entering the boiler through the throat.

The addition of warmed ambient air for

cooling ash may appear to be problematic,

as this air volume could affect the combus-

tion characteristics of the boiler. In order

to ensure that no adverse effects on boiler

combustion occur, the amount of ambient air

used for ash cooling is limited to 0.75% of

the combustion air. This method of cooling is

quite effective, as it has been shown to reduce

the ash temperature from 750F at the outlet

2. DRYCON cooling conveyor installation in Florida. Courtesy: Clyde Berge-

mann Power Group

3. DRYCON cooling and transfer conveyor to ash storage. Courtesy: Clyde

Bergemann Power Group



of the boiler to 178F at the end of the DRY-

CON cooling conveyor (Figure 3). The con-

veyor itself does not need to be insulated, as

the outside skin temperature has been shown

to average 87F.

Removal of the water-flooded ash hop-

per will reduce thermal losses from evapo-

ration of water (evaporative cooling), and

the unburned carbon content of the ash is

reduced, thus increasing boiler efficiency.

As a result of the reduction in unburned

carbon content of the ash, boiler efficiency

can be increased by 0.02% to 0.07%. Like-

wise, the reduction in unburned carbon in

the ash itself increases its possible sale as a

beneficial by-product.

As it relates to upcoming CCR regula-

tions, the DRYCON system requires no wa-

ter, thus it will comply with either a Subtitle

C or Subtitle D final regulation. However,

installation of this type of system will require

a longer outage (the system can be installed

in a 22-day outage), as significant demolition

and construction activities to the ash hoppers

are required.

Path ForwardAlthough it may appear to be a case of “the

boy who cried wolf,” the EPA is being pres-

sured more than ever and can be expected to

promulgate CCR regulations by year’s end.

Current timetables for compliance are tight

regardless of which path for CCR regulation

the EPA takes.

In the case of a Subtitle C regulation,

each state will be required to adopt the rule

individually, thus effective dates will vary;

however, in some states effective dates will

be as soon as six months after promulga-

tion. In the case of a Subtitle D regula-

tion, most provisions will be effective six

months after promulgation.

With the tight compliance deadlines and

uncertain regulatory provisions, utilities

should be prepared with multiple compli-

ance scenarios. Many of the commercially

available technologies are mature and can

be competitively bid among suppliers. Some

technologies are “cutting edge” and may

offer additional benefits, such as reduced

auxiliary power load and increased boiler ef-

ficiency. However, each facility will need to

evaluate these technologies based upon site-

specific equipment configurations, expected

outage times, and capital/operating costs of

the systems. ■

—Brandon Bell, PE ([email protected]) is a project manager with Valdes

Engineering Co. and a POWER contribut-ing editor.

UDI WHO’S WHO AT ELECTRIC POWER PLANTS

Enhanced PDF version now available

The 2014 UDI Who’s Who Directory covers more than 4,500

U.S. and Canadian generating plants. The directory provides:

• Nearly 8,100 plant management and support contact names, titles, and primary job functions.

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Availability (%)

Heat rate

Capacity Factor (%)

• Power plant design characteristics

Choose which purchase option that best suits your needs:

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For more detailed information and a list of all available data, visit us online at UDIDATA.COM or contact the UDI Editorial team at [email protected].

2014

With the tight compliance deadlines and uncertain regulatory provisions, utilities should be prepared with multiple compli-ance scenarios.


operations & Maintenance

Adaptive Brush Seals Restore Air Preheater PerformanceAir preheater (APH) leakage has several negative consequences, including lost rev-

enue. A better design for APH seals has been shown to have several benefits over traditional metal strip seals, including a quick payback.

Pavan Ravulaparthy and Ravi Krishnan

The gas sealing systems used on rotary, regenerative air preheaters (APHs) have evolved little from the metal strip

configuration used on the first Ljungström preheaters nearly a century ago. Metallic strip seals are typically used for radial, axial, and circumferential seals that are exposed to corrosive gases at relatively high tem-peratures. Steel seal degradation begins soon after installation, and the inevitable result is increased air-to-gas leakage over time, which translates into increased fuel consumption and fan power usage. If you’ve ever expe-rienced “running out of fan,” it’s likely that APH leakage is part of the problem.

Repeated thermal expansions and contrac-tions in the large (often 20-meter in diameter or more) rotors in continuous motion usually cause large and irregular seal gaps. At operat-ing temperatures, outer edges of large APHs may droop or turn down by 3 inches or more from the cold condition. Steel strips wear (or warp or break) based on the smallest gap size, thus leaving larger gaps elsewhere. Leak rates with properly designed and installed seals should be less than 10%, although leak-age rates of 15% to 20% are typical, and rates greater than 30% are not uncommon when conventional seals fail. APH leakages typi-cally occur in air-to-gas and gas-to-air paths through the APH seals (Figure 1).

Rotary APHs are particularly critical to the efficient operation of coal-fired power plants, delivering up to 12% of the heat transfer used in the steam generation process. A useful rule of thumb is that for every 20 degree C decrease in the APH gas outlet temperature, boiler efficiency increases about 1%, which translates into about $1.5 million in fuel sav-ings every year for a typical 500-MW plant. An optimally operating APH also reduces fan power consumption and thereby net plant generation capability.

APH leakage also has a detrimental effect on downstream air pollution control equip-ment due to increased gas velocity, tempera-ture, and APH air- and gas-side pressure drop. For example, the typical flue gas velocity

through a selective catalytic reduction (SCR) module is around 5 to 6 meters per second. Increased gas velocity caused by air-to-gas leakage will decrease the residence time of the gas and thereby reduce the effectiveness of the SCR, as well as potentially cause an increase in ammonia injection rates and slip.

Additionally, lower gas residence time in the flue gas desulfurization system can ad-versely affect lime or limestone injection rates and SO2 removal efficiency. For particulate matter control systems, higher air-to-cloth face velocities in fabric filters can lead to de-creased bag life. Pulverizer capacity also can be negatively affected with lower air volumes and temperatures due to air-to-gas leakage.

Brush-up Your APH SealsBrush seals are a particularly good choice for replacing steel strips commonly used for circumferential, radial, and axial seals on

1. Many leakage paths. The air-to-gas and gas-to-air leakage paths typically found in a rotary, regenerative air preheater are through the circumferential, axial, radial, and rotor post seals, as shown by the yellow ar-rows. Courtesy: Sealeze

2. Brush seals installed. Circumferen-tial (left), radial (bottom), and axial brush seals (right) can significantly reduce air preheater leakage rates. Source: Sealeze

3. Comparison test. A worn strip seal (on the left) compared to a new brush seal (right). Flexibility of the brush seal allows it to deflect at the smaller gaps and then rebound to ensure sealing at wider gaps. The amount of wear on the steel strip seal is evident. Source: Sealeze


operations & Maintenance

Ljungström rotary regenerative APHs (Figure 2). Each brush seal consists of thousands of filaments that form a high-integrity seal and provide a high degree of abrasion resistance, flex life, and bend recovery not possible with rigid strip seals (Figure 3). Each bristle is in-dependent and flexible, allowing deflection to conform to any irregularities and gap varia-tions and recover to its original position.

The inherent elasticity of the brush design dis-sipates stress under deformation, reducing drag and wear. In addition, within the dense barrier

of thousands of filaments is an independent and flexible membrane designed for deflection that conforms to any irregularities and gap variations and recovers to its original position to ensure that a tight seal is maintained (Figure 4).

Quantifiable Benefits Air preheater leakage can account for significant increases in parasitic power draw from the boiler fans, and this translates into lost net revenue.

Consider a typical 500-MW coal-fired unit configured with two APHs originally

designed for 10% APH leakage. The unit has combined 8,595 kW installed fan power consisting of two primary, two secondary, and two induced draft fans (excluding the air quality control system). Referring to the fan curves, we find that when the APH leakage increases 10%, the fan power requirements increase 13% (1.12 MW). Table 1 suggests the simple payback for installing brush seals that return the APH leakage to design values can be a matter of days.

There are other significant benefits to us-ing brush seals that aren’t included in Table 1. For example, reducing air leakage on a sus-tained basis results in lower flue gas velocities and, therefore, reduces the pressure losses in downstream air quality control systems, and results in a corresponding reduction in fan load. For plants with electrostatic precipita-tors, increased velocities attributable to APH leakage may result in higher dust emissions at the stack. For plants with fabric filters, the higher air-to-cloth ratios due to APH leakage can affect the frequency of bag cleaning and possibly shorten bag life.

Field Performance ResultsIn June 2007, the Hardin Generating Station, owned by Bicent Power (Hardin, Mont.), con-tracted with Sealeze, a unit of Jason Inc., to supply its axial and radial stainless steel brush seals for both the hot and cold ends of the 119-MW Unit 1 Ljungström APH. The plant has an average availability of nearly 97%.

Inspection of the brush seals in 2008 showed them to be in very good condition. Some splaying of the brush was evident on the cold end due to sootblower blasts of 205C steam. To prevent direct sootblower impinge-ment, the brush seals mounted in the path of sootblower blasts have been redesigned to incorporate an angled orientation and an in-

1955 Chevy 150/210

Creating Value.Carver Pump Company2415 Park AvenueMuscatine, IA 52761563.263.3410Fax: 563.262.0510www.carverpump.com

Low NPSHa on your vacuum receiver gotyou down? Fail to resume pumping assuction levels resume? You need CarverPump 855 Series muscle!

Carver 855 Series are designed for use onvacuum receivers operating with up to 26” Hgvacuum. Flange mounted directly to the vacuumreceiver tank eliminates suction piping/NPSHproblems. Whether operating at a trickle or full flow,specially designed impellers allow pumping to resume evenafter periods of interrupted flow.

Capacities range to 600 GPM depending on discharge headand speed of operation. Available in 6 sizes ranging from 1”- 4”, standard materials of construction include All Iron,

CD4MCu and Rubber Lined. The 855Series features an overhead v-belt drivearrangement as standard, with options foreither close coupled or frame mounteddrives. Packing is standard in the stuffingbox with mechanical seals as an option,and don’t forget to ask about our Swing-Out design. Let us build the muscle you need!

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4. Membrane seal. The adaptive brush design is built around a malleable alloy foil membrane nestled within brush filaments to provide a 70% to 80% reduction in leak-age without sacrificing overall seal flexibility. Source: Sealeze



tegral protective shield.

Since that design update, the brush seals

continue to outperform the original steel strip

seals more than five years after installation

and are expected to continue to perform to

specification through at least four outage

cycles. During the past five years, the plant

has been able to postpone two planned APH

outages—another significant cost savings.

Two other brush seal installations have ex-

perienced similar results. Radial and circum-

ferential brush seals were installed in 2010

on two 8-m-diameter horizontal APHs at a

300-MW coal-fired unit located in the U.S.

(the plant wishes to remain anonymous). The

plant reports leakage rates remain well un-

der 10%. In fact, air leakage tests confirmed

leakage rates of 5% and 7% on APH-A and

APH-B, respectively.

In 2010, radial and axial brush seals were

installed on a 10-m-diameter vertical Ljung-

ström APH at a 750-MW coal-fired plant

located in the U.S. (this plant also wishes to

remain anonymous). Both the radial and axial

brush seals remain in excellent condition af-

ter more than 2.3 million impacts to the sec-

tor plates during 11,760 hours of service over

490 days (Figure 5). The brush profiles remain

essentially in the as-installed condition. Seal

integrity remains intact as the seal conforms to

gap size variations and surface irregularities.

APH seal degradation is difficult to iden-

tify and is often overlooked as responsible for

loss of fan margin, loss in boiler efficiency,

and consequential problems with downstream

air quality control equipment, particularly

the SCR. Chances are your plant is currently

troubled by poor APH performance caused by

increased seal clearances in the hot condition,

seal erosion, inappropriate seal materials, or

improper seal settings. Installing stainless steel

brush seals is one of the few low-risk, high-

reward upgrades that can be easily completed

during a typical planned maintenance outage.

Better yet, the cost of the stainless steel brush

seal retrofit will likely be repaid by improved

boiler efficiency quicker than the duration of

the outage. ■

—Pavan Ravulaparthy ([email protected]) is business development man-

ager for Sealeze. Ravi Krishnan ([email protected]) is managing director of

Krishnan & Associates.

Economic factors Savings/cost

Fuel savings $1.5 million/year

Auxiliary power savings $0.52 million/year

Total savings $2 million/year

Installed cost of brush APH

seals

$100,000

Payback ~18 days

Table 1. Payback analysis for a typical 500-MW coal-fired unit. The

savings calculations are based on an 85% ca-

pacity factor, 10,550 kJ/kWh heat rate, and

average coal heat content of 5,500 kcal/kg at

$80/ton. The incremental electricity sale price

is assumed as $30/MWh off peak (75% of the

operating hours) and $150/MWh on peak (25%

of the operating hours). Source: Sealeze

©2

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Brand Energy & Infrastructure Services is a leading provider of specialty

services to the power industry. Our unique multi-service approach

delivers significant savings to our clients on their maintenance, outages

and capital projects by reducing manpower requirements, improving

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delivering enhanced productivity.


5. Seal inspections. The radial (top)

and axial (bottom) brush seals remain in as-

installed condition after 11,760 hours of opera-

tion. Source: Sealeze



Modern Polymeric Materials Offer Options for Equipment RepairContinual development of polymer technology has enabled the creation of specialized

coatings, which can offer excellent resistance to erosion, corrosion, and cavita-tion in hydroelectric equipment and pumps at any generating plant. Polymeric materials can also increase efficiency and extend runtimes.

Kyle Flanagan

Currently accounting for over 16% of

global energy production, and with an

expected growth rate of 3% per year for

the next quarter century, hydroelectric power

generation continues to grow as the front run-

ner in renewable energy, even though growth

in the U.S. is expected to be minimal.

In recent years, maintenance of existing

hydroelectric assets has become increasingly

important to ensure a consistent supply of

power. Low water levels, due to factors such

as drought and higher local demand for water

(see “Water Issues Challenge Power Genera-

tors” in the July 2013 issue of POWER, online

at powermag.com), have resulted in decreased

production in high-profile hydroelectric sta-

tions, such as the Hoover Dam. There the

problem has become so severe that the result-

ing drop in pressure difference has caused in-

creased cavitation damage to turbine runners

and a 20% decrease in production levels.

Ensuring turbine efficiency and up-time

are at their maximum is key to achieving

optimum production. However, as with any

fluid flow equipment, the effects of erosion

and corrosion will detract from this. If left

unchecked, erosion—and specifically, cavi-

tation damage—rates increase exponentially

to cause severe metal loss. Unbalancing and

vibration of turbine runners can result, re-

quiring lengthy shutdowns for repair work to

shafts and bearings. Loss of surface smooth-

ness also results in increased turbulent flow

and lower production rates.

Traditional Repair TechniquesThe recommended procedure for determin-

ing inspection and repair frequency for hy-

droelectric runners and turbines, including

stay vanes and wicket gates, is to inspect the

equipment at set intervals following installa-

tion to ascertain the rate of damage, including

erosion, corrosion, and cavitation. Once the

rate of damage is known, procedures are put

in place to repair the damage once the depth

of metal loss reaches predetermined levels.

Once a maintenance routine is put in place,

repairs are carried out in accordance with the

recommended procedure. The procedure is of-

ten to replace the lost metal using conventional

metal replacement techniques. Large areas of

pitting are repaired by welding plates or sheets

of new metal in place as an erosion wear layer,

whereas areas of lighter damage are repaired

by weld overlay, which is then ground back

to the correct tolerance. The procedure is re-

peated at the next service interval, as dictated

by the rate of in-service deterioration.

Limitations of Traditional RepairsThe traditional repair procedure is not with-

out problems though. The most basic flaw is

the replacement of the material that is being

lost with more of the same material—a like-

for-like repair. Reintroducing the same base

material simply allows the problems to reoc-

cur and does not identify the root cause of

the issue and work to limit its effects. Con-

tinued metal loss will result in continued

shutdowns. As previously discussed, metal

loss will in some cases result in vibration due

to imbalance, and this can cause damage to

bearings and shafts.

One of the major drawbacks of using hot

work to replace lost metal is the procedure in-

volved in implementing the repair. According

to the Facilities Instructions, Standards, &

Techniques Turbine Repair manual, “Exten-

sive weld repairs can result in runner blade

distortion, acceleration of further cavitation

damage, and possible reduction of turbine

efficiency. Also, extensive repair can cause

residual stressing in the runner resulting in

structural cracking at areas of high stress.”

Coupled with this is the complexity of

carrying out hot work repairs. Extensive rig-

ging and supports are recommended in or-

der to avoid distortion of finely honed parts.

Hot work is recommended to be carried out

1. Completed replacement of leading edges damaged by cavitation. Courtesy: Belzona Polymerics Ltd.



gradually, heating up the entire part first pri-

or to application of the repair technique, and

lengthy cooldown times are required after

application of the repair to avoid excessive

heat distortion. Care is also required when

selecting the repair metal (plates or welding

rods), as different materials can introduce lo-

cal galvanic corrosion, initiating even more

repair requirements.

A Better Alternative: CoatingsModern polymeric repair systems offer an

excellent alternative to traditional repair

materials. These materials are supplied in

either paste grade filler type repair compos-

ites used to infill damaged areas and restore

profiles (Figure 1) or as coating grade prod-

ucts used to provide long-term protection

to equipment against specific damage. Ad-

vanced polymeric coatings completely halt

corrosion by isolating the metals and clos-

ing the corrosion cell.

Polymeric coatings have been used for

more than 60 years in many different appli-

cations, such as on hydroelectric generation

equipment, offshore and onshore oil and gas

systems, pumps, and sewage treatment equip-

ment, and they have a reliable track record in

these environments. By utilizing solvent-free

epoxy technology, these products are safe to

use, even in enclosed spaces.

Specialized filler materials, such as ceram-

ics and aluminium oxide, allow epoxy coat-

ings to achieve good wear resistance. Epoxy

coatings combine with the metallic substrate

to provide a composite component, which of-

fers ongoing maintenance advantages.

Application AdvantagesPrior to application, thorough surface prepa-

ration is required in the area to be repaired.

This is commonly achieved using localized

grit blasting to clean and roughen the metal,

which allows the polymer to form an intimate

bond with the base metal.

Polymeric repair and coating composites,

such as Belzona, are supplied as two-part

products. The components are mixed prior

to application using spatulas and bowls

or with paddle mixers for larger projects.

This mixing initiates the chemical reaction,

which enables the product to solidify to its

final form.

Application is commonly carried out using

trowels for paste grade rebuilding composites

and by brush for coating grade epoxies (Fig-

ures 2 and 3). Many products can also be ap-

plied by airless spray, allowing for rapid repair

times over large areas. The product is then al-

lowed to cure for a period of time before the

equipment can be returned to service.

Because modern epoxy polymer materi-

als are cold-curing, they eliminate the re-

quirement for hot work that is needed for

traditional repair techniques. This avoids

problems, such as:

■ Risk of equipment distortion.

■ Requirement for specialist rigging and jigs.

■ Lengthy repair times required to allow for

cooling of welds.

■ Grinding and finishing of weld overlay.

2. Apply. Applying Belzona 1341 (Supermetalglide) to a runner reduces surface friction, result-

ing in higher operating efficiency in fluid flow equipment, such as turbines and pumps. On the

bottom of this turbine, the paste grade material used to infill areas of erosion damage is visible

before application of the coating. Courtesy: Belzona Polymerics Ltd.

3. Ready to run. After coating application,

this runner is installed and ready to return to

service. Courtesy: Belzona Polymerics Ltd.

4. No comparison. A Leeds University

surface inspection study found that polished

stainless steel was far less smooth than Bel-

zona 1341 (Supermetalglide). Courtesy: Bel-

zona Polymerics Ltd.

Polished stainless steel (Ra 1.19 um)

Belzona polymeric efficiency coating (Ra 0.078 um)

Effi

cien

cy (%

)H

ead

(m)

Flow (m3/hr)

Coated Uncoated

5. Increased efficiency. These perfor-

mance curve results were recorded by the UK

National Engineering Laboratory. Courtesy:

Belzona Polymerics Ltd.

30

25

90

80

70

60

0 500 1000



■ Health and safety hazards associated with

hot work.

■ Need for specialist welding rods and ex-

pensive replacement metal.

■ Introduction of heat-affected zones due to

welding.

■ Lengthy shutdown times.

Use of epoxy composites as a protective

coating for the base metal also allows for much

easier wear identification in the future, as differ-

ent-colored layers of polymeric coatings allow

wear areas to be quickly identified. Repairing

existing coatings is a straightforward process;

an area can be prepared using powered hand

tools before a patch repair is applied.

Advanced application methods, such as

airless spray equipment, have allowed even

faster repair times. Turbine casings, draft

tubes, and outlets are all subject to the same

damage as the turbine runner and can be re-

paired using the same epoxy polymer prod-

ucts. The newest generation of epoxy coatings

incorporate advanced polymer fillers, which

provide improved erosion resistance while

allowing application by airless spray, which

is ideal for larger areas.

Several polymer coatings have been spe-

cially developed by Belzona for applications

in pumping and hydroelectric generation,

which specifically aim to improve efficiency

and reduce cavitation.

Efficiency EnhancementIncreasing the efficiency of existing equip-

ment allows asset owners to get the most

from their equipment. One of the most effec-

tive methods of improving asset performance

is by applying coatings that will reduce re-

sistance to flow caused by friction with the

substrate. Belzona 1341 (Supermetalglide)

is an epoxy coating with a low electronic af-

finity with water molecules (making it a hy-

drophobic material). Once applied, it forms

an extremely smooth surface, which reduces

the boundary layer of the pumped fluid and

reduces internal turbulence in the flow, thus

increasing hydraulic efficiency.

A Leeds University surface inspection

study found that Belzona 1341 (Supermetal-

glide) was 15 times smoother than polished

stainless steel (Figure 4). Incorporation of

ceramic fillers also allows the coating to

resist erosion and protect the equipment for

long service periods.

Testing conducted in the United King-

dom by the National Engineering Laboratory

showed that applying Belzona 1341 (Super-

metalglide) to a new pump increased peak

efficiency by up to 6% (Figure 5). At this

peak efficiency point, the reduction in power

consumption has been measured at 5.1 kW at

duty point. Assuming a 5,000-hour operating

cycle per year, power savings would amount

to 25,500 kWh per year.

Similar efficiency gains can be expected in

hydroelectric equipment. On existing, in-ser-

vice equipment, the increase will commonly

be even higher. Equipment that has suffered

from heavy deterioration and loss of effi-

ciency can be returned to better than original

performance. On heavily deteriorated pumps

repaired by the City of Fayetteville, Ark., an

improvement of 17% was recorded compared

to the deteriorated condition performance.

Resisting CavitationOccurring in areas of pressure change across

fluid flow equipment, cavitation is one of the

most damaging and difficult forms of ero-

sion encountered in hydroelectric equipment.

Rapid implosion of vapor bubbles close to the

metallic substrate results in powerful micro-

jets that impact and “chip” the base material,

resulting in pocketed erosion (Figure 6).

Use of hard materials and specialty alloys

is common practice in areas of cavitation, but

these measures are often very expensive and

can also fail under constant attack. In order to

resist the effects of cavitation, Belzona spe-

cially developed Belzona 2141 ACR Elasto-

mer. This is a two-part elastomeric polymer

applied using a brush as a coating specifi-

cally to areas subject to cavitation damage.

Belzona 2141 ACR Elastomer followed

a lengthy development and research pro-

cess to determine the key conditions pres-

ent in cavitation areas on fluid-handling

equipment. Exceptional bond strength, re-

sistance to temperature, and the ability to

absorb the extreme impact pressures from

micro-jetting were all requirements ful-

filled by Belzona’s elastomeric polymer

material (Figures 7, 8, and 9).

Extensive independent testing, in accor-

dance with American Society for Testing

and Materials (ASTM) standards, yielded

exceptional results. A Voith–Siemens report

showed the material resisted damage after

500 hours of intensive cavitation testing.

Penn State University evaluated the product

at 130 knots of intensive cavitation testing

and reported resistance without damage after

20 hours. Samsung reported that ASTM G32

results for Belzona 2141 were significantly

higher than for 316L stainless steel.

Field applications—to turbines, wicket

gates, stay vanes, and turbine shafts—that are

still providing excellent performance after a

decade of service are testament to the mate-

rial’s longevity. ■

—Kyle Flanagan ([email protected]) is a technical services engineer for

Belzona Polymerics Ltd.

7. Original condition. This photo

shows the initial condition of a Francis turbine

runner following grit blasting. The pitting dam-

age is due to cavitation. Courtesy: Belzona

Polymerics Ltd.

8. Repaired. This turbine runner is ready for

return to service with Belzona 2141 ACR Elas-

tomer applied. Previous alternatives, such as

replacement metal and hard coatings, had failed

on this part. Courtesy: Belzona Polymerics Ltd.

9. Still holding strong. After 36

months of uninterrupted service, no damage

was found on the applied Belzona 2141 ACR

Elastomer, and the turbine was returned to

service. Courtesy: Belzona Polymerics Ltd.

6. Heavy loss. Cavitation damage has re-

sulted in severe metal loss on these impeller

vanes. Courtesy: Belzona Polymerics Ltd.

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SUPPLY CHAINS

The Future of Utility Supply Chain ManagementUtilities have sometimes lagged behind other sectors in applying advanced manage-

ment techniques, but that may be changing as the industry recognizes the impor-tance of lean, efficient supply chains.

Thomas W. Overton, JD

There may be few things about power

plant management less exciting than its

supply chains. But few things can gum

up a plant’s operations more completely than

mismanaging supplier relationships, parts

sourcing, and inventory.

Supply chain management has undergone

substantial evolution in the past few decades

along with other changes in management

philosophy that began in the 1980s. Procure-

ment, once viewed as a low-level clerical

function, is now recognized as a key special-

ty in any organization’s operations.

But the field is not standing still. Utility

supply chain experts have recognized that

there is still plenty of room for improvement,

and that while some utilities and generators

are leading the way on managing lean, effi-

cient, smooth-running supply chains, many

others still have substantial savings and ef-

ficiencies to capture.

Speakers at the 12th Platts Utility Supply

Chain Management Conference held Jan.

20–22 in San Diego generally agreed that

supply chain management starts with align-

ing internal elements of the utility for optimal

efficiency, but attention needs to be devoted

all the way across the delivery chain.

Internal RealignmentOne problem faced by procurement depart-

ments is a tactical, rather than strategic, fo-

cus from senior management. Rather than

taking a holistic view of the total costs of

owning a component, too often savings are

extracted from the budget upfront, with

the procurement department left to make

ends meet on its own. Steve Coleman,

director of transmission and distribution

(T&D) sourcing for Pacific Gas & Electric

(PG&E), stressed that procurement depart-

ments need to become strategic partners for

their internal customers. That means mak-

ing procurement a truly customer-focused,

customer-facing organization.

Unfortunately, the traditional approach

of having a dedicated supply chain for

each business unit handicaps continuous

improvement and implementation of best

practices because these chains often become

siloed and isolated from one another. These

isolated chains are capable of acting strate-

gically but are unable to fully capture sav-

ings and efficiencies available through more

centralized operations.

One approach to making this work, though

one that few utilities appear to have imple-

mented, is to better align supply chains with

their business units within a centralized sup-

ply chain organization. This is done by cre-

ating new roles within the supply chain that

work directly with business units, focusing

exclusively on understanding each unit’s

plans and strategies, enabling them to engage

with business unit initiatives very early in the

process to represent supply chain concerns

and demands.

Phil Seidler, supply chain director for

Luminant, and Joe Levesque, vice president

of product development for consulting firm

PowerAdvocate, explained the benefits of

this approach. Keeping these closely aligned

supply chains within the centralized sup-

ply chain organization enables an ongoing

focus on driving value, reducing risk, and

improving supplier relations. The organiza-

tion is able to create centers of excellence

around common core functions and realize

efficiencies and continuous improvement

by exchanging information across the indi-

vidual chains.

PG&E, for example, has added directors

for each procurement unit to its organization-

al chart as well as a chief procurement of-

ficer, moving from a single vice president of

general services overseeing two directors to a

robust center-led, customer-facing organiza-

tion. That’s allowed it to focus much more of

its attention on strategic procurement, Cole-

man explained.

Engaging business unit leaders isn’t

always straightforward, since convincing

them that supply chain issues are worth

their attention may be difficult. Seidler

and Levesque listed some ways of meet-

ing that challenge: understanding business

unit objectives, knowing their business,

and creating a pull relationship using in-

formation that demonstrates the value of

alignment. When procurement has a clear

understanding of the business unit’s needs

1. An effective category management process. A category management process

should provide an iterative approach to value creation through all phases of the supply chain

lifecycle. Courtesy: PowerAdvocate


SUPPLY CHAINS

and operations, it can better establish its

credibility and demonstrate ways to im-

prove performance.

Category ManagementThe concept of category management, in

which procurement for classes of products is

managed as an ongoing business in collabo-

ration with suppliers, has been around in re-

tail since the 1980s but is still making its way

into utility procurement.

As Seidler and Levesque explained, cat-

egory management is an evolution of stra-

tegic sourcing but is cyclical rather than

linear (Figure 1). It is an ongoing process

of continually tracking, managing, and

improving the sourcing of material rather

than an episodic, contract-focused process.

It requires both alignment with business

units and close collaboration with suppli-

ers. This allows procurement to better en-

gage business unit leaders to build lasting

expertise in the supply chain, as well as

respond proactively and swiftly to changes

in the market.

Obviously, moving toward category man-

agement is not an overnight process. Lumi-

nant, Seidler explained, began the shift with

its privatization in 2004 but only began get-

ting a robust category management system

into place in the 2010s. Getting the supply

chains aligned with business units took sev-

eral years, during which better strategies,

skills, and metrics had to be developed.

Seidler and Levesque offered some other

tips for making category management work

most effectively:

■ Start with categories that will quickly

demonstrate high impact to business units

to gain support early on.

■ Set regular cross-functional business re-

views with leadership to review process,

spend, and other performance metrics.

■ Structure roles such that responsibilities

for strategic planning and day-to-day ex-

ecution fall to different people.

■ Embed category management inside tech-

nology tools to ensure that data, and the

process, is sustained in the event of per-

sonnel turnover.

Supplier IntegrationOf course, making all this work isn’t sim-

ply an internal process—suppliers have to

be deeply involved as well. That’s why in-

tegrating suppliers into supply chain man-

agement is an increasing trend. While it’s

not yet common, with the utilities furthest

along in this process the supplier, procure-

ment, and business unit function as a seam-

less supply chain, simultaneously sharing

information up and down the chain. This

level of cooperation and communication al-

lows capturing efficiencies and cost savings

that are not visible otherwise.

Stocking and inventory decisions are

made collectively, depending on what op-

tions are most efficient and advantageous.

Materials may be stocked with the suppli-

er or the utility warehouse; management

of many materials—particularly high-turn

items needed regularly and/or rapidly—

may be entirely in the hands of the suppli-

er, who may assume direct responsibility

for fulfillment goals with the business

unit. In such a system, the supplier’s in-

ventory essentially becomes the utility’s

“virtual inventory.” If implemented effec-

tively, the result can be lower labor costs,

better resource availability, more efficient

logistics, lower transactional costs, and

better risk management.

Rodney Long and Ron Jangaon of Duke

Energy explained how the utility giant has

moved toward integrated supply with WES-

CO Distribution, which helps manage the

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SUPPLY CHAINS

program. Integrated supply programs gener-

ally comprise a number of components:

■ Procurement and fulfillment are linked.

■ Supplier has a fully transparent compensa-

tion model.

■ Supplier provides on-site labor to augment

purchasing and storeroom functions.

■ Some on-site inventory is supplier owned.

■ Service level metrics, including risk and

reward components.

■ Supplier also handles some third-party

transactions.

One benefit of such deep integration,

they explained, is better visibility of the to-

tal costs of material. The focus moves away

from the contract price and takes in all the

costs involved in sourcing, stocking, and us-

ing material.

Of course, not every supplier is capable or

willing to take on these added responsibili-

ties—it needs to be willing to partner with

the utility for the long term. That means, said

Gary D. Benz, supply chain vice president

for FirstEnergy, keeping lines of communica-

tion open and making clear to suppliers that

procurement is not a “one-off” process—the

utility needs to make suppliers understand

they’re building a relationship. But that flows

both ways, he said. If a supplier is investing

a lot of resources in that relationship, “They

deserve to understand what our business

plans are,” he said.

This approach takes on added complexity

when dealing with overseas suppliers. Fre-

quent communication is key, and organiza-

tions must be proactive in anticipating and

dealing with potential language and cultural

barriers. Having a dedicated procurement

team that regularly travels abroad to meet

with suppliers and review their operations

can be highly beneficial, especially early in

the relationship.

Michael Devoney, president and gen-

eral manager of electrical and industrial

distributor Turtle & Hughes Integrated

Supply, related an example of a client who

ran into difficulty managing supplier qual-

ity in China, where an increasing percent-

age of original equipment manufacturers

(OEMs) build their turbines and boilers.

Unfortunately, he told POWER, “there are

limited options to manage an approved

vendor list (or to conduct supplier qual-

ity audits) in China.” This creates a mar-

ket imbalance for the large OEMs, but if

this need could be addressed, “more gen-

erators could buy ‘direct’ from the actual

manufacturers,” he said.

Risk ManagementSuch a close partnership naturally brings

with it some significant risks. How to

manage supplier risk, whether in tradi-

tional concerns such as safety, quality, and

performance, or more recent issues such

as cybersecurity, becomes an increasing

concern.

Speakers at the Platts conference all men-

tioned data security as a concern. When sup-

pliers are deeply integrated into a supply

chain, simply having a good internal cyberse-

curity policy in place isn’t enough. Supplier

polices also need to be vetted and upgraded

as necessary.

Scott Landrieu of PSEG discussed how

natural disasters such as Superstorm Sandy

and the Tohoku Earthquake (which led to the

disaster at the Fukushima Daiichi nuclear

plant) have highlighted the need for having

robust recovery plans in place in the event of

severe disruptions of a supply chain. Utili-

ties need to know what to do in the event that

one or more major suppliers are knocked out

of business or significant inventory stock is

destroyed. Critical components should be

sourced from multiple suppliers, and over-

seas supply chains should source from mul-

tiple countries to reduce the risk of potential

disruptions. Here again, effective supplier

integration can prove its worth, as entities

across the chain can work together to miti-

gate risk.

Both speakers and attendees mentioned

quality control as a key supply chain risk.

Developing parallel supply chains for criti-

cal components, while potentially increasing

costs, can greatly reduce the risk of nonper-

formance. This is especially true when sourc-

ing from overseas.

Another source of risk is fuel price fluc-

tuations. The fall in natural gas prices has

increased pressure on other fuels. “Making

peak operating periods has become more

critical to overall profitability,” Chris Price

of Turtle & Hughes told POWER. Likewise,

pressure from renewable energy mandates

complicates risk management. “It’s difficult

to keep up on the technology and find the

right sourcing partners,” he said. “Also, the

focus on these initiatives changes with the

regulatory landscape.”

Close alignment between all elements in

a supply chain is important in reducing risk.

This enables better visibility and identifica-

tion of potential “choke points,” as well as

communication of impending problems.

Inventory OptimizationThough “just-in-time” sourcing has be-

come the standard in many industries, the

power sector has lagged well behind this

trend, in part because—especially in regu-

lated markets—a utility’s focus is keeping

the lights on and being able to respond

rapidly to emergencies. While a bloated

inventory full of stranded assets (spare

components that the utility no longer has

a need for) may not look good on the bal-

ance sheet, it rarely interferes with those

priorities. Even in deregulated markets,

poorly managed inventories don’t neces-

sarily prevent a plant from competing ef-

fectively. But over the long term, inventory

problems can represent significant drains

on revenue.

Utilities and generators also have chal-

lenges not faced by other sectors. Criti-

cal replacement parts, some of which can

be extremely expensive, must be kept on

hand in case of emergencies even though

they may never be needed. Utilities that

operate in more than one state may be re-

quired to maintain duplicate inventories

in order to meet requirements of separate

state oversight. The problem can be com-

pounded if the utility has merged with

or been acquired by another company.

Worse, the utility often may not have a

clear picture of how much duplication

exists or how much money is tied up in

stranded assets.

Implementing advanced supply chain

management processes can help address

these problems. Just as category manage-

ment, improved data, and better communi-

cation can streamline procurement, better

information, segmentation, and tracking of

inventory can assist a utility in identifying

and clearing unneeded stores. Some utilities

have made inventory management a sepa-

rate director-level responsibility apart from

other supply chain issues. Such a role is

responsible for maintaining visibility and

transparency into companywide inventory

to be sure the utility has a clear view at all

times into the location, quantity, and appli-

cation of all stores.

Pat Pope, president and CEO of the

Nebraska Public Power District (NPPD),

reviewed his company’s experiences in chal-

lenging these problems. NPPD was experi-

encing annual inventory growth greater than

10%, about $13 million every year—despite

previous efforts at bringing stocks under

control. New inventory was coming in faster

than procurement staff could clear out un-

needed components. Yet, the situation was

not viewed as a problem by many managers.

The solution was not another ad-hoc reduc-

tion effort but engaging senior management

in changing the way procurement operated

so that supply chain personnel had the tools

and authority to better match inventory to

business unit needs—among these, inven-

tory optimization software from Oniqua.

The result was to completely reverse the un-

necessary growth in NPPD’s inventory and


SUPPLY CHAINS

actually reduce inventory by $8.2 million with no effect on reli-

ability.

Steve Sotwick, Oniqua’s vice president of business development

for North America, explained some ways in which inventory opti-

mization can aid in supply chain management. Having a clear view

of each business unit’s needs allows procurement staff to better

identify critical inventory, forecast the needs for it, and spotlight

inventory that is no longer needed. Creating separate inventory

segments as part of category management allows category-specific

inventory to be matched to that business unit’s strategies instead of

applying across-the-board policies that are likely not appropriate

for all stock.

Utilities or generators with multiple like-kind units will often

centralize storage of critical spares that may be shared among

their own units. This works well because the carry costs of the

inventory can be spread among multiple plants. Sometimes this

“part sharing” arrangement will occur between companies, with

the arrangement often brokered through the manufacturer, though

this is fairly rare. While this can reduce costs, a challenge arises

if two plants require the same part. Careful planning and com-

munication is also necessary to make clear who takes ownership

of used parts. Because most major equipment can endure only so

many refurbish cycles, plans must be in place for how that cost

is shared.

Improved MetricsFinally, all this fine-grained management is difficult to impossible to

achieve effectively without accurate metrics to track how new strate-

gies are working and without robust processes for using metric per-

formance to drive improvements.

Most utilities have well-defined fulfillment metrics for their supply

chains in place. Less common, however, is measuring flexibility and

responsiveness, even though these metrics are critical for capturing effi-

ciencies. It is also common for unplanned or rush orders to be excluded

from metrics, even though these are the events most likely to result in

supply chain disruption and extra costs.

Several speakers noted that advanced organizations are most likely

to measure key metrics across the entire supply chain. More impor-

tantly, metrics need to be in place to measure business unit expecta-

tions, not just traditional procurement performance. Optimally, this

takes the form of a service-level agreement (SLA) between procure-

ment and the business unit. The SLA flows in both directions, spelling

out not just expectations for order fulfillment but also business unit

performance in accurate forecasts and communication of needs. The

SLA also has to be a dynamic—rather than static—tool that is con-

stantly being evaluated and updated to support continuous improve-

ment of the supply chain.

Defining metrics is not always straightforward. Some, like order

fulfillment, lend themselves easily to measurement; others, like em-

ployee skills or effective communication across the supply chain, are

harder to measure accurately. Useful metrics need to flow from strate-

gic goals while being tied into overall corporate objectives.

The Big PictureIt’s important to remember that not all supply chain management innova-

tions necessarily support one another. Increased redundancy to reduce the

risk of disruption, for example, can increase complexity of communica-

tion and performance metrics. An integrated supplier network has more

parts to monitor, increasing the risk of losing focus on the whole. Success-

ful companies will maintain a holistic approach in managing their supply

chains, making visibility, flexibility, and collaboration key priorities. ■


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The LNG Export Debate: Lessons from PeruWhat could a relatively small country in South America have to teach the U.S. about

LNG exports? Maybe a lot, as 2014 marks the 10th anniversary of its natural gas market.

Javier Matos Flores-Guerra

Recent shale gas development, resulting

in cheap natural gas in the U.S., has

opened the debate about whether or

not to export some of that energy—mainly as

liquefied natural gas (LNG). As the U.S. con-

siders the merits of LNG exports, it may be

useful to look at how that debate played out

in other countries faced with a similar situ-

ation. Understanding how previous debates

evolved, and the consequences of the deci-

sions, may prove to have lessons that the U.S.

can learn from.

There are just two LNG export terminals

in the Americas outside the U.S., in Trinidad

& Tobago and Peru. The Peruvian project, the

first of its kind in South America, was the one

that faced major controversy over whether or

not the nation should export natural gas.

The Peruvian Natural Gas RevolutionPeru is the third-largest country in South

America, with a population of 30 million and

a GDP per capita of US$6,800. It is an emerg-

ing market that grew 7% a year on average in

the past eight years. Unlike the U.S., before

2004, Peru had never been a significant con-

sumer of natural gas (see sidebar “Natural

Gas and Electricity in Peru”).

The natural gas revolution in Peru had a

name, and its name was Camisea.

Camisea hydrocarbon deposits are lo-

cated 500 kilometers east of Lima, Peru’s

capital city, in the Ucayali Basin, in the Pe-

ruvian region of Cusco, in the southcentral

jungle of the country. As early as 1981 the

Peruvian government signed an operation

agreement with a subsidiary of Royal Dutch

Shell (Shell) in order to explore the deposit.

From 1983 to 1987, Shell discovered and

confirmed the Camisea deposit was rich in

natural gas and associated liquids reserves,

with over 8 trillion cubic feet (Tcf) of re-

serves. For many reasons—including po-

litical incompetency, the emergence of the

leftist guerrillas known as the Shining Path,

and lack of capital and human resources—

Camisea had to wait until the new millen-

nium to see the light.

In August 2004, Camisea started its com-

mercial operation as an integrated project.

The project’s entire value chain included pro-

duction, transportation—a 729-km pipeline

from Malvinas to Lima and a 557-km natural

gas liquids (NGL) pipeline from Malvinas

to Pisco—and distribution, including to the

City of Lima.

The Camisea project had two main phases,

with the first involving resource exploration

and development and the second involving

the LNG export components. When Camisea I

was under procurement and construction, be-

tween 2001 and 2003, Peruvian policymakers

faced the dilemma that American policymak-

ers are facing now: There was too much gas

for the country’s domestic consumption—or

at least that seemed to be the case.

From a global perspective, 8 to 10 Tcf is

not much natural gas at all, but in the early

stage of the Peruvian natural gas industry,

when nobody used natural gas because they

did not even know about it, it was reason-

able, even indispensable, to evaluate all the

alternatives available to obtain the highest

economic benefit from the natural gas.

Because gas reserves appeared to vastly

exceed domestic needs, exportation initia-

tives started to make sense. At the same

time, questions started to arise. In an im-

mature energy market like the Peruvian

Natural Gas and Electricity in Peru

According to The World Factbook (pub-

lished online by the U.S. Central Intel-

ligence Agency), in 2010, Peru had an

estimated 8.613 GW of installed electric

power capacity. Fossil fuels accounted

for roughly 60% of all generation, with

the balance coming from hydropower.

Also for 2010, the International Energy

Agency says that 12,226 GWh were gen-

erated by natural gas, accounting for

34% of total generation.

The U.S. Energy Information Adminis-

tration reports that domestic consumption

of natural gas in Peru increased from 16

Bcf in 2002 to 202 Bcf in 2011, “driven by

government incentives, economic growth,

and the growing number of gas-fired elec-

tricity plants.” Overall, the role of natural

gas in Peru’s energy sector and economy

has increased dramatically in recent years

(Table 1).

—Gail Reitenbach, PhD, Editor

Table 1. Natural gas ramp-up. Source: U.S. Energy Information Administration

History Peru

Central &

South America World Rank

Production 255.33 5, 517 111,954 400.83

Consumption 193.88 5,106 113,321 201.65

Net export 61.45 415 — 199.18

Proved reserves (trillion

cubic feet)

12.46 270 6,845 12.70


FUEL SUPPLIES

one, how much natural gas was enough?

How would internal consumption evolve?

Would exports increase the price for lo-

cal consumers? Would exports deplete the

resources too fast? Would it be against

Peruvian energy independence? Not sur-

prisingly, we hear this group of questions

nowadays a little farther north.

Jaime Quijandría, who died in Decem-

ber 2013, was Peru’s minister of energy

and mines and minister of economics and

finance between 2001 and 2004 and is rec-

ognized as a leader and a pioneer in the Pe-

ruvian energy sector. Quijandría, a former

president of Peru’s NOC Petroperu, was

the main force behind the Peruvian energy

policymakers who were looking to make

the most of Peruvian natural gas resources

for the nation. With that objective in mind,

Quijandría and his team in the Ministry of

Energy found that the best way to accom-

plish that goal was to open and find new

markets for Peruvian natural gas through

exportation. Quijandría was very aware of


Environmental Concerns

As in the U.S., any time a major new

pipeline or resource development proj-

ect is discussed in South America, envi-

ronmental questions are raised. For the

Camisea project, which lies partly in the

Amazon rainforest, concerns included the

displacement of indigenous people, clear-

cutting of forests, and pipeline spills.

Typically, neither side in energy versus

environment debates wins everything it

wants. One example from one phase of the

Camisea project: In response to concerns

about adverse effects on the environment

and indigenous people, the multinational

development consortium led by Argentina’s

Pluspetrol agreed to not build roads but

instead adopted a model used in offshore

exploration and production that uses boats

and helicopters to move equipment, sup-

plies, and workers to and from the site.

The potential for pipeline ruptures has

been cited by North American opponents

to new pipelines and LNG export projects,

and the Peruvian project has experienced

more than one episode of pipeline breaks.

In the first year and a half after the Cami-

sea project went online in 2004, it experi-

enced a series of pipeline breaks that a San

Diego, Calf.–based environmental consult-

ing firm, E-Tech International, determined

were the result of shoddy work done by

unqualified welders who used leftover cor-

roded pipes (though Peruvian regulatory

audits could not confirm the use of left-

over pipe). Presumably, with better over-

sight and qualified workers, rupture risks

could be minimized.

Though opposition to natural gas devel-

opment on environmental grounds has not

completely subsided, some groups have

recently pointed to successful efforts to

mitigate negative environmental and cul-

tural consequences. In a March 2013 report

titled “Peru LNG: A Focus on Continuous

Improvement,” the International Finance

Corp. (which, along with other interna-

tional lending agencies, provided $2.05

billion to the project) concluded that

through “strong commitment to managing

environmental and social risks throughout

all phases of the project, PLNG successfully

managed and mitigated operational and

reputational risks related to their environ-

mental and social performance.”

—Gail Reitenbach, PhD, Editor


FUEL SUPPLIES

the dynamics of the oil and gas business and the virtuous circle

of open markets, exploration, and production and development of

new reserves.

When Peru took the decision to allow exports of natural gas, it also

looked to invigorate the exploration and production business and to

make it possible, through the right economic signals, that possible

and probable reserves become proven ones, making them commer-

cially viable.

Peru is a country that has had many traumatic experiences of

corruption in its highest levels of government throughout its his-

tory. The worst thing about corruption is not just the economic

losses that inevitably result, but rather that it seeds mistrust among

people. Peruvians mistrust their judiciary system, their parliament,

and their politicians. In that context, it’s easy for political, even

technocratic, opponents to point to different policy decisions as

motivated by corruption.

Carlos Herrera, a well-known expert in energy matters, who had

been Peru’s minister of energy and mines twice (2000–2001 and

in 2011) denounced export plans publicly and said that Peru did

not have enough natural gas reserves to justify developing an LNG

export project. He suggested that it was corruption in the adminis-

tration that modified the Peruvian oil and gas regulations in order to

make the LNG project viable. However, parliamentary investigative

commissions came and went and couldn’t find any evidence of cor-

ruption or mismanagement.

Environmental concerns have also been an ongoing matter of

debate, especially as a portion of the natural gas reserves lie in the

Amazon rainforest (see sidebar “Environmental Concerns”). Overall,

however, the resource development and export project has made re-

markably fast progress.

Export InfrastructureOn June 22, 2010, Peru LNG—a multinational consortium created

in 2003—dispatched its first shipment of LNG from its state-of-the

art liquefaction terminal located 170 km south of Lima at Pampa

Melchorita (Figure 1). The plant is a single-train facility with a ca-

pacity of 4.4 million metric tons per year.

The project’s total cost (for the LNG plant, marine terminal, pipe-

line, plus development and financing costs) was $3.8 billion, making

it, at the time, the largest foreign investment in Peru’s history.

The nearly four-year development project also included a 408-

km pipeline that crossed the Andes. The engineering, procure-

ment, and construction (EPC) contract for the liquefaction plant

facilities (Figure 2) was awarded to Chicago Bridge & Iron Co.

(CB&I). The marine terminal EPC was awarded to a consortium

led by Brazilian contractor Odebrecht, and the pipeline contractor

was Argentina’s Techint.

Early ResultsIt’s too early to conclude whether or not the exportation decision was

the best decision for Peru. However, according to the “BP Statisti-

cal World Review of 2013,” at the end of 2012, Peru’s natural gas

proved reserves were up to 12.7 Tcf (up from 8.7 Tcf in 2006), and

its reserves-to-production ratio (R/P)—the length of time that the re-

maining reserves would last if production were to continue at the cur-

rent rate—was 27.9 years, the largest in the Americas (the U.S. R/P

ratio is 12.5 years).

Since it began exports, Peru has shipped its LNG primarily to

Spain, South Korea, Japan, and Mexico. Additionally, Peru is cur-

rently considering new export projects (through LNG shipments or

pipeline) to Chile, a neighboring country with higher energy costs.

Industry sources estimate that Peru LNG will generate approxi-

mately $310 million annually of export revenues.

Not bad at all for a small South American country. ■

—Javier Matos Flores-Guerra is an associate with the Peruvian law firm Hernández & Cia. and is a specialist in the legal, regula-

tory, and project development aspects of the energy sector.

1. Stored and ready to ship. South America’s first and only natu-

ral gas liquefaction terminal is located 170 kilometers south of Lima on

the Pacific Ocean. Courtesy: Peru LNG

2. Under construction. The EPC contract for the liquefaction fa-

cility was awarded to Chicago Bridge & Iron Co. (CB&I). The LNG export

project was launched in January 2007, inaugurated on June 10, 2010, and

dispatched its first tanker on June 22, 2010. Courtesy: Peru LNG


INDUSTRY TRENDS

Facing Challenges from Natural Disasters to Customers as GeneratorsIn the process of developing both familiar and new conference tracks and sessions for

ELECTRIC POWER 2014, Event Content Director David Wagman has identified a number of current and emerging trends. Here he offers his take on the issues that will be hot topics this April in New Orleans and long after.

David Wagman

The 16th annual ELECTRIC POWER

Conference & Exhibition takes place in

New Orleans this year, and it’s a fitting

place to be discussing the many persistent

and new challenges facing the power genera-

tion industry. Entergy Corp. is the host util-

ity, and its experience is indicative of several

trends across the power sector.

As with other new U.S. baseload capacity,

gas is playing the lead role for Entergy, whose

commitment to natural gas (with fuel oil as a

backup) is evident at its 550-MW Ninemile

Point Unit 6 plant. (The plant will be open

for a tour by ELECTRIC POWER attendees

on Mar. 31.) The combined cycle gas turbine

unit is under construction a short distance

from downtown New Orleans and will add

economical and efficient gas-fired capacity

to the generating mix serving southeast Loui-

siana. The region spans an area from east of

metropolitan Baton Rouge to the Mississippi

state line and south to the Gulf of Mexico,

including New Orleans. By 2015, the region

will have more than 6,000 MW of demand.

Ninemile Unit 6 is on track to enter commer-

cial service by mid-2015 with enough capacity

to replace the loss of Ninemile Units 1 and 2.

Those units entered service in the early 1950s

and have been deactivated. Ninemile Unit

6 (Figure 1) is designed to allow it to adjust

output as a load-following plant or operate as

a baseload plant if required. The unit will use

natural gas as its main fuel, but it also will be

able to burn ultra-low-sulfur fuel oil for short

periods. Through its pollution-control systems,

the unit will be among the nation’s cleanest

gas-fired generating plants, and its emissions

will be significantly lower than the deactivated

Ninemile Point units. Additionally, locating a

large generator like Ninemile 6 close to load

enhances flexibility during system restoration

following a storm such as a hurricane.

Disaster Planning and Mitigation System restoration following a storm is a

major consideration for Entergy, whose Gulf

Coast operating units were hit hard by hurri-

canes Katrina and Rita. Rod West, Entergy’s

chief administrative officer, will reflect on

how utility investment decisions should be in-

fluenced by disruptive events such as the 2003

Northeast blackout, Hurricane Katrina, and

Superstorm Sandy in keynote remarks he will

deliver at ELECTRIC POWER on Apr. 1.

West played a unique role in the rebuilding

of Entergy New Orleans. First, in 2005, when

Hurricane Katrina struck and flooded 80% of

the city, West served as manager of the metro

New Orleans region with responsibility for

the city’s electric infrastructure. West and his

team oversaw a $250 million reconstruction

of the nearly destroyed New Orleans electrical

infrastructure (see “Preparation keyed Enter-

gy’s responses to Katrina, Rita” in POWER’s

May 2006 issue at powermag.com).

Second, in 2007, as president and CEO of

Entergy New Orleans, West led that business

unit out of Chapter 11 bankruptcy reorga-

nization and back to profitability. Addition-

ally, he oversaw one of the industry’s largest

natural gas rebuild efforts, which included

replacing around 860 miles of underground

pipe damaged after Hurricane Katrina.

The nuts and bolts of Entergy’s emergen-

cy preparedness efforts will be explored in

greater detail at ELECTRIC POWER by Greg

Grillo, storm incident commander, who will

discuss his company’s emergency prepared-

ness planning process. The Edison Electric

Institute (EEI) honored Entergy in 2013 with

its Emergency Recovery Award and Emer-

gency Assistance Award. EEI cited the utility

for its work restoring power to customers fol-

lowing Hurricane Isaac and to customers of

other utilities after Hurricane Sandy and other

severe weather events. The recognition was

nothing new for the utility: 2013 marked the

15th consecutive year that Entergy received an

EEI national storm restoration award.

In presenting the award, EEI President

Tom Kuhn said, “Entergy was faced with a

major restoration effort following Hurricane

Isaac. Getting the lights back on quickly and

safely is never easy following these natural

disasters. It takes strong commitment, ad-

vanced planning and great execution. Entergy

responded with all three, and their assistance

shows their compassion in helping others in

their time of need. They’re a great example

for the nation’s electric power industry.”

Microsoft and the Energy Supply ChainAnother trend that is picking up steam is the

growing role of diverse customers in the elec-

tricity supply chain. For examaple, in an inter-

view earlier this year, Brian Janous, director of

energy strategy for Microsoft, told me that Mi-

crosoft looks at data as a “refined form of ener-

1. Ninemile Unit 6. Entergy Corp.’s 550-MW combined cycle generating unit is slated to

enter service in 2015. Courtesy: Entergy Corp.


INDUSTRY TRENDS

gy.” He said the company thinks about energy

not only from the perspective of a consumer,

but also from the vantage point of “where we

sit in the overall energy supply chain and about

how to create more efficient energy systems,”

from the power plant to the data chip. “As a

result, our path for delivering power to sup-

ply Microsoft’s cloud infrastructure is focused

both on how we optimize for efficiency inside

our footprint, and also how we integrate and

invest in driving greater efficiencies across the

broader energy supply chain.”

Janous said Microsoft has three objec-

tives that drive this effort, which he will

elaborate on during his keynote remarks:

First, to distribute efficient power genera-

tion to the company’s datacenters that inte-

grates with the capacity and energy needs of

the local grid; second, to deliver to the grid

low-cost and efficient energy by participat-

ing in utility-scale generation projects; and,

third, to foster the development of the next

generation of energy technologies that will

make future distributed and grid-connected

projects “radically” more efficient.

“We don’t expect to achieve any of this on

our own,” Janous told me. “Instead we look

to the energy industry to partner with us on

achieving these objectives.”

Cogeneration and CHPReliability and efficiency are as important

to a regional hospital or research university

as they are to a datacenter operation such as

Microsoft’s. Every dollar spent by an institu-

tion’s utilities department to produce steam,

heat, or electricity is a dollar that cannot be

invested in the core mission, be it laboratory

research or patient care.

“Our objective is to reduce cost but retain

resiliency,” said Juan Ontiveros, executive di-

rector of utilities at the University of Texas at

Austin. Add to that the task of self-producing

100% of the power consumed by the 17 mil-

lion square feet across 150 buildings on the

Austin campus, while planning for an ad-

ditional 2 million square feet (including a 1

million–square foot hospital) by 2016.

Ontiveros will discuss the challenges of op-

erating one of the largest combined heat and

power (CHP) systems in the U.S. as part of

ELECTRIC POWER’s newest track that fo-

cuses on cogeneration and CHP applications.

The university’s generating capacity includes

two combustion turbines, each equipped with

heat recovery steam generators. One 45-MW

unit runs during the summer when air condi-

tioning load is greatest. A 32-MW unit runs

in the fall, winter, and spring seasons. Excess

heat thrown off by the turbines is used for

heating and steam throughout the campus.

Ontiveros said that recent market condi-

tions are “perfect” for institutions and their

need to avoid risk. He cited shrinking reserve

margins in some parts of the country, coal

plant retirements, and the lack of invest-

ment in new generating resources as key rea-

sons for institutions to seek greater security

through cogeneration and CHP. “We see risk

any time we are on the grid,” Ontiveros said,

adding that the Austin campus has experi-

enced three outages in 40 years. The campus

can be more resilient, more cost effective,

and greener than the grid. He added that the

emissions produced to supply 17 million

square feet are the same as in 1976, when the

campus included 10 million square feet.

Resiliency, cost effectiveness, and envi-

ronmental stewardship are three recurring

themes at ELECTRIC POWER. Networking

is a fourth, and there are plenty of opportu-

nities to meet with peers as well as solution

providers on and off the exhibit floor. ■

—David Wagman is content director for ELECTRIC POWER (www.electricpower-

expo.com), which takes place April 1-3 at the Ernest N. Morial Convention Center in

New Orleans.

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3Global Business Reports // POWER BRAZILMarch 2014 3

www.gbreports.com

Global Business Reports

from 2% to 8%, small hydro will remain

at 4%, biomass will reduce from 8% to

7%, nuclear will increase marginally but

stay at 2% and thermal will reduce from

15% to 13%. This may change a little bit

to increase thermal but these are our gen-

eral long-term projections. We anticipate an

overall increase in capacity by 60,000 MW,”

said Mauricio Tomalsquim, president of the

government-funded EPE (Energy Research

Company).

The Environmental Debacle:

Dirty Hydro for Dirtier Thermal

While Brazil’s hydropower endowment

is its greatest asset, since the 1990’s the

construction of large dam reservoirs has

become subject to increasing environmen-

tal criticism due to the damage they cause

to the environment by looding vast areas

of land.

New plants are being constructed in the

Amazon but they are fraught with contro-

versy. Belo Monte (11,233 MW), due to be-

come the third largest hydroelectric plant

in the world, is planned for completion in

2019, but has been subject to vehement

environmental opposition and numerous

suspensions since conception of plans in

1975. New hydro projects favor minimal

reservoir size or run-of-river water mills in

order to secure the elusive environmental

permits they require.

Wind

Wind complements hydropower perfectly

in Brazil: when there is heavy rainfall there

is less wind, when there is light rainfall

there is more wind. The growth of Brazil-

ian wind generation over the past decade,

and particularly the last ive years, has been

phenomenal.

The introduction of wind into Brazil’s con-

cession auctions in 2009 was when the

industry took off. The auction system func-

tions in a way that the generator who bids

with the cheapest, guaranteed price per

MWh receives a Power Purchase Agree-

ment (PPA) of 20 years indexed by inlation

and becomes eligible for 80% inancing

from BNDES (The Brazilian Development

Bank). Wind became competitive when

generators were offered a ixed revenue

so long as they did not produce less than

90% of the power they promised over a

four year period. Combined with a inancial

crisis in Europe and the USA, many foreign

companies were drawn to the Brazilian

wind market, making it one of the fastest

growing in the world.

2012 was a blip for wind and the electricity

sector as distribution companies delayed

the purchase of energy due to uncertainty

in the market caused by regulatory chang-

es and low GDP growth.

2013, however, has been a bumper year as

the market has acclimatized to the regula-

tory changes and demand for electricity

has increased. Wind contracted 1 GW in

the A-5 auction in August, dominated the

A-3 auction on 18th November with 39 pro-

jects totaling 867 MW, and won 97 of the

115 successful energy projects in the A-5

auction on 13th December.

Brazil’s wind sector continues to attract

foreign manufacturers looking for strong

growth opportunities. Vulkan do Brasil, a

German coupling and brake components

company, has been in Brazil for 35 years and

is now starting to see considerable growth

in the energy sector, particularly wind. “We

started with hydro and are currently focus-

ing more on research and development in

the wind market for wind turbine breaks.

There are other major break manufacturers

in the local wind market and we are get-

ting closer to them. Our advantage is that

we are the only local manufacturer in Bra-

zil of these components and our products

are GL certiied and BNDES-FINAME reg-

istered,” said the company’s sales director,

Tiago Bedani.

While the auction results indicate a bright

future ahead, BNDES’s stringent local con-

tent requirements are causing a bottleneck

in the supply chain. In July 2012, BNDES

changed its Finame inancing requirements

for local content to 60%, resulting in six

foreign wind turbine suppliers being dis-

qualiied from the loan program. In 2015,

100% of nacelles and towers will have to

be manufactured in the country, which al-

though important for developing Brazilian

industry, will be a tough challenge to for

manufacturers to meet.

Improvements to the system can also

be made as low prices currently come at

the cost of eficiency: “We have the ca-

pability to extract more energy from wind

through reactive power, but if we do so

the cost will be higher, which is not what

www.gbreports.com

Global Business ReportsPOWER BRAZIL

4 Global Business Reports // POWER BRAZIL March 2014

the government is looking for,” explains

market-leader Renova Energia’s president,

Mathias Becker.

Coal and Natural Gas

Brazil has recoverable reserves of around

10 billion mt of coal located in the southern

states of Rio Grande do Sul, Santa Cata-

rina and Paraná. The country’s natural gas

potential is even more substantial due to

the vast Pre-Salt reserves discovered in the

Santos and Campos Basins. The natural gas

industry has nonetheless grown sluggishly

in Brazil due to a lack of transportation in-

frastructure and low domestic prices main-

tained by Petrobras. Ten years ago, energy

planners ruled out natural gas from Brazil’s

energy matrix and so a considerable in-

vestment is now required, along with an

amendment to the auction process, to get

the sector going.

Solar

In December 2012, ANEEL inalized Nor-

mative Resolution 482, which lays out

the conditions for distributed micro and

mini-generation and creates an electric-

ity compensation system. With the leg-

islation for distributed generation now

deined, companies are progressing with

plans to capitalize on the country’s 50

million household potential and 1 MW of

residential generation has already been

installed.

Soletrol, one of the largest companies for

solar thermal water heaters in Latin Amer-

ica, has been in the market since 1981

and is now looking to expand into solar

PV. “The solar thermal industry in Brazil

has grown to the point that we know its

success to be a certainty in the future. For

photovoltaic, the ramp up could be very

rapid, or end up being much slower than

predicted: a great deal depends on the

customer,” said CEO, Luis Augusto Ferrari

Mazzon.

Ailton Ricaldoni Lobo, CEO of renewable

energy generation company, Novas Op-

ções Energéticas (NOE), is particularly

excited about a solar-powered future: “The

law of micro-generation has made distrib-

uted generation a reality in Brazil. Nowa-

days, the inal consumer will spend around

$300 per MWh of solar energy, which is

expensive but feasible due to the payback

of investment. In Minas Gerais, we al-

ready have around 20 systems connected

and generating power, and it is only

just beginning.”

The most promising indication for the

growth of solar in Brazil has been the gov-

ernment’s decision to allow PV and ther-

mal solar plants with a minimum installed

capacity of 5 MW to take part in the A-3

and A-5 energy auctions, to be delivered in

2016 and 2018 respectively.

None of the solar projects at either auc-

tion were successful, as the price cap of

$60 per MWh made competing with wind

impossible. The price ceiling for solar to be

economical is around $100 per MWh. In or-

der for the industry to take off, therefore,

it needs some help. Either inancing must

be made more accessible or price differen-

tiation between energy sources must be

allowed. There have been indications that

the EPE may create an independent

auction for solar in 2014 but nothing is con-

clusive as yet.

Transmission,

Distribution and

Smart Grid Solutions

Transmission

Brazil’s hydrology complements the coun-

try’s transmission system due to the

fact that when it is wet in the south, it is

dry in the north and vice verse. Electric-

ity is therefore constantly being trans-

mitted from one region to another. Vast

stretches of transmission lines, however,

lead to around 6% of energy losses and

so high voltage direct current (DC) lines of

600 KV and 800 KV are now being

constructed to transmit power from new

hydro projects in the Amazon via one or

two lines.

Problems have also been encountered with

the wind industry. As the sector took off,

the EPE auctioned transmission lines once

it was determined who had won the auc-

tions. The system failed, however, as the

companies who won the transmission auctions were not able to

construct the lines by the time the parks were ready. Some wind

farms are therefore ready to generate electricity but cannot con-

nect to the grid. The system has since been changed so that trans-

mission lines are auctioned in advance and wind farm investors

now have to connect to the lines themselves.

Distribution

The biggest challenge Brazil faces with regards to distribution is

non-technical losses, caused by people who do not pay their bill.

These types of losses make up an average of 16% of total losses

in the country. The problem is the most serious in the state of

Rio de Janeiro, where non-technical losses average 25% and can

reach up to 70% in some areas.

Smart Grid Solutions

Smart solutions for integrated automation, distributed automa-

tion, smart metering and telecommunications will reach the

market in 2014. However, their implementation depends on the

government’s approach as distribution companies are primarily

interested in reducing non-technical losses. “Most companies

investing in smart grid solutions are electrical companies fac-

ing issues with regards to non-technical losses. In these cases,

they are just applying technology to reduce their non-technical

losses, which is a different concept than having an architec-

tural approach; it is not about making the system more eficient,

it is about making it more secure… to develop a general smart

grid topology in the next ive years, we need to deine a roadmap

to implement a plan,” said Ricardo Van Erven, CEO, Latin America,

GE Digital Energy.

Conclusion: The Country of the Future?Brazil’s booming economy, which barely linched at the global i-

nancial crisis of 2008 and grew by 7.5% in 2010, has come back

down to earth with a thud since the euphoria of winning both the

2014 World Cup and 2016 Olympic Games. GDP growth has plum-

meted in the last two years and signs of unrest are starting to

manifest themselves through large pubic demonstrations across

the country protesting against high prices, lack of investment and

political corruption. Stefan Zweig’s hackneyed phrase that “Brazil is

the country of the future – and always will be,” seems once again

as ironic as ever.

Whilst government intervention in electricity will deter foreign

investment in the short term, changes, in many respects,

were necessary. As the market stabilizes, however, it must be

left to grow organically. Presidential elections are due to take

place on 5th October 2014 so relative tranquility can be expected

until then. In the meantime, the Brazilian power sector is open

to investment: anyone can compete for the country’s genera-

tion and transmission needs and risk is low with long PPAs and

guaranteed inancing. •

www.gbreports.com

Global Business Reports

5Global Business Reports // POWER BRAZILMarch 2014 5

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Abresist Kalenborn . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 . . . . . . . . 9 www.abresist.com

Apollo valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 . . . . . . . . 7 www.apollovalves.com

Applied Bolting technology …… . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 . . . . . . . .17 www.appliedbolting.com

Asi Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 2 . . . . . 1 www.asi-group.com

Baldor electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 . . . . . . . .11 www.baldor.com

Beumer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 . . . . . . . .10 www.beumer.com

Bilfinger Piping technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 . . . . . . . .24 www.piping.bilfinger.com

Brand energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 . . . . . . . .22 www.beis.com

Burns & Mcdonnell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 . . . . . . . . 4 www.burnsmcd.com

Calgon Carbon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 . . . . . . . .18 www.calgoncarbon.com

Carver Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 . . . . . . . .21 www.carverpump.com

diamond Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 . . . . . . . .19 www.diamondpower.com

Fluor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 . . . . . . . . 6 www.fluor.com

Fuel tech . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 . . . . . . . .16 www.ftek.com

Hadek . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 . . . . . . . . 8 www.hadek.com

Magnetrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 . . . . . . . .15 www.magnetrol.com

Md&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cover 4 . . . . .26 www.mdaturbines.com

Mitsubishi Power systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 . . . . . . . 2 www.mpshq.com

natronx . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 . . . . . . . .14 www.natronx.com

nol-tec systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 . . . . . . . .20 www.nol-tec.com

Paharpur . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 . . . . . . . .12 www.paharpur.com

siemens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 . . . . . . . . 3 www.siemens.com/energy/controls

swan Analytical instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 . . . . . . . .23 www.swan.ch

terrasource Global . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 . . . . . . . . 5 www.terrasource.com

victory energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 . . . . . . . .13 www.victoryenergy.com

Winsted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 . . . . . . . .25 www.winsted.com


COMMENTARY

Coal is currently the feedstock for nearly 40% of America’s baseload electricity supply, and in communities and states where coal has the highest utilization, utility bills are the

lowest. With more than two centuries of coal available in the United States, the government and power sector need to find ways to maximize the use of this abundant natural resource in the cleanest, most economical way possible—ensuring that all families, businesses, and communities can benefit from reliable, affordable energy.

Coal—and other fossil fuels—share a proud history, having powered three industrial revolutions (including today’s technol-ogy revolution), increased life expectancy, improved the quality of life, and brought hope to every civilization that has used these fuel sources. According to the U.S. government’s Energy Information Administration (EIA), coal will continue to be a sig-nificant feedstock for U.S. electricity and for power around the globe for decades to come.

Policy ImplicationsAlthough the EIA’s prediction is based on past trends and future anticipated use, poorly written and executed federal and state public policy could lead to constraints on domestic coal use which, in turn, would undoubtedly cause systemwide brownouts, blackouts, and price spikes.

Unfortunately, for American families and businesses, President Obama has increasingly abdicated his energy policy to leaders at the Environmental Protection Agency (EPA), who are engaging in an assault on the U.S. coal industry. The recently released draft New Source Performance Standards (NSPS) will—as written—im-pose a de facto ban on the construction of new technologically advanced coal-fueled power plants. To meet the EPA’s stipulated standards, plants will be forced to use technologies that are not yet commercially or economically viable. Considering this trou-bling precedent, we are even more concerned that a forthcoming rule on existing coal-fueled power plants could lead to the shut-tering of active units across the country.

It’s disconcerting that leaders at the EPA are ignoring the coal-based industry, its hundreds of thousands of workers, and businesses and families across the country who rely on afford-able coal-powered energy for their livelihoods. Instead, they are working behind the scenes, through secret emails and commu-nication, with environmental organizations like the Sierra Club, whose stated goal is to end coal-fueled energy in the U.S., to write regulatory energy policy.

I simply cannot believe the president has considered the deleterious consequences to our national security, our nation’s economy, or families’ budgets should coal power plants go of-fline; if he has, he is consciously putting us on a dangerous path. The nation’s power sector is already grappling with the

very ominous possibility that nearly 15% of the nation’s coal-generated electric capacity will be shut down over the next decade as 330 coal units are shuttered because of EPA’s exist-ing regulations. And, as we have seen over recent weeks, other fuel sources cannot meet demand as reliably and as affordably as coal. In short, we are on a collision course brought about by misguided policies that will cause an overreliance on less-predictable energy sources.

Coal Technology ProgressRegrettably, much of the administration’s angst with coal is misplaced. Over the past 40 years, the coal industry has invested more than $130 billion in new technologies that have reduced emissions by 90%. And we’re committed to doing more.

I’m excited to see the slate of more than 15 new clean coal technologies come online in promising projects like the Prairie State Energy Campus in Illinois and John W. Turk, Jr. Plant in Arkansas. I believe these next-generation applications will be game-changers for the coal power industry—as long as the gov-ernment allows us to succeed.

We stand ready to work with government officials and regulatory agencies to ensure a smart path forward that supports the clean use of coal in the years ahead. If the president and others in the administration refuse to work with us, however, and instead put Americans’ economic and energy security at risk, the coal-based electric industry is ready to use every resource available to fight onerous and overzealous regulations that would harm our industry, our economy, and our nation.

It’s not just one American industry that is at risk; it’s Ameri-ca’s way of life. ■

— Mike Duncan is president and CEO of the American Coalition for Clean Coal Electricity (ACCCE).

America Needs Continued

Coal Use Mike Duncan

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