June 2013

Vol. 157 No. 6 June 2013

ARCTIC Chills Turbine

Power Loss

Fast-Start HRSGs

New Build or Repower?

Troubleshooting Control Loops

Developing Skilled Craft Workers

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June 2013 | POWER www.powermag.com 1

ON THE COVERAs summer temperatures and system peak demand rise, combustion turbine power drops. The only way to recover that lost power is to cool the incoming air. Energy Concepts Co.s Absorption Refrigeration Cycle Turbine Inlet Conditioning (ARCTIC) system chills incoming air using waste heat from the turbine as the absorption chillers energy source, instead of the conventional use of electric motors driving centrifugal chillers. The first utility-scale ARCTIC system, installed on an LM6000 combustion turbine in Texas, has performed ex-ceptionally well during its first three years of operation. Courtesy: Energy Concepts Co.

COVER STORY: COMBUSTION TURBINES24 Improving Warm Weather Performance of the LM6000

Summers here, and that means combustion turbine heat rates are taking a hit ex-actly when electricity demand spikes. A new option for providing inlet air chilling uses exhaust heat to power the air-conditioning system while incurring no heat rate degradation. A case study demonstrates how the small cost premium is offset by improved performance, efficiency, and maintenance requirements.

SPECIAL REPORTS

HEAT RECOVERY STEAM GENERATORS

28 Fast-Start HRSG Life-Cycle OptimizationFoster Wheeler offers an approach for determining the effect of more frequent and faster starts at natural gas combined cycle plants on heat recovery steam genera-tors. The goal: enable fast starts while maintaining acceptable component cycle life.

PLANT DESIGN

36 Repower or Build a New Combined Cycle Unit?Thats a question many power generators are asking these days. URS shares the re-sults of an engineering study it recently conducted for a Midwestern utility facing that choice. The case study and methodology could help others in the same situation.

INSTRUMENTATION & CONTROL

42 Troubleshooting and Solving Poor Control Loop PerformanceIncorrectly tuned control loops can respond sluggishly, or they can overshoot and oscillate significantly. Controller tuning is often done by trial-and-error, but there are better ways.

24

Established 1882 Vol. 157 No. 6 June 2013

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Power in AustraliaAustralias New Energy Paradigm,

a sponsored report from Global Busi-

ness Reports, examines the tension

between environmental concerns and

energy costs in Australias power sec-

tor. (After p. 48.)

www.powermag.com POWER | June 20132

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FEATURES

POWER VIEW

52 Expect U.S. Electricity Consumption to IncreaseLawrence J. Makovich, PhD, IHS CERAs vice president and senior advisor for Global Power, discusses demand growth predictions, the competitive electricity market, and renewable power generation.

NATURAL GAS

56 New England Struggles with Gas Supply BottlenecksOld, inefficient oil and coal plants in New England have been retired and replaced with natural gasfired combined cycle plants. Consequently, emissions and electric-ity costs are lower. But now the region faces new problems.

PLANT ECONOMICS

60 What Is the Worth of 1 Btu/kWh of Heat Rate?Designing a new combined cycle plant means selecting from myriad optionsusually based on the criterion of cost of electricity produced. This screening tool allows you to quickly sort through many design options to find the cost-effective solution.

WORKFORCE DEVELOPMENT

64 Scarce Projects Raise Red Flag for Skilled LaborA sluggish economy and coal plant closures have been masking the severity of a looming shortage of craft labor needed for scheduled and unscheduled outages. Whats more, the power industry is competing for those workers with the booming oil and gas industry.

DEPARTMENTS

SPEAKING OF POWER6 Opinions la Carte

GLOBAL MONITOR8 Ontario Completes New Niagara Tunnel to Increase Output from Hydro Complex8 OTEC Gets Boost with Possibility of 10-MW Plant in China10 U.S. EGS Project Adds 1.7 MW Grid-Connected Output 12 THE BIG PICTURE: Power Accident Impacts14 Ningde 1 Is Latest Chinese Reactor to Start Commercial Operation16 POWER Digest

FOCUS ON O&M18 LADWP Harnesses LMS100 to Solve Once-Through Cooling Dilemma

LEGAL & REGULATORY22 Renewable Energy Policy Review Required

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

66 NEW PRODUCTS

COMMENTARY72 EPA to Limit Startup, Shutdown, and Malfunction Defense

By Karl A. Karg, Latham & Watkins LLP

Get More POWER on the WebOnline, associated with this issue (on our homepage, www.powermag.com, during the

month of June, or in our Archives any time), youll find the final installment of Too Dumb

to Meter: Follies, Fiascoes, Dead Ends, and Duds on the U.S. Road to Atomic Energy.

And remember to check our Whats New? segment on the homepage regularly for

just-posted news stories covering all fuels and technologies.

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SPEAKING OF POWER

Opinions la Carte

Have you ever experienced a restau-rant menu overflowing with so many tasty entres that making your se-

lection seemed an impossible decision? Your deliberation probably ended when the waiter began tapping a pen on his or-der pad and your dinner-mates gave you the evil eye. Picking a commentary topic each month is much like scanning the din-ner menu. There are usually many topics that deserve a good slice and dice, but its the deadline that forces a decision.

I decided to try something different this month. Instead serving up a one-course meal, were having smorgasbord. There are enough opinions here to either sati-ate your appetite or give you heartburn. I trust youll find the servings to your lik-ing. Bon apptit!

Unexpected Candor. In a mid-April re-port, the U.S. Environmental Protection Agency (EPA) says that tighter leakage control on natural gas wells resulted in an average annual decrease of 41.6 mil-lion metric tons of methane emissions from 1990 through 2010, or 850 million metric tons overall. That is a reduction of 20% from the agencys earlier estimates. These reductions occurred while natural gas production grew by 40% since 1990. This isnt surprising, because well produc-ers are aware that losing product to the atmosphere isnt good business. The new EPA data is kind of an earthquake in the debate over drilling, said Michael Shellen-berger, president of the Breakthrough In-stitute, an environmental advocacy group. Expect the leakage rates to continue to drop in the future, frustrating fracking foes.

Shale Gas Reserves Estimates In-creased, Again. The April 9 biennial as-sessment report from the Potential Gas Committee on future U.S. natural gas re-sources shows that the gas boom should continue for quite some time. The com-mittees future gas supply estimate rose 22.1% over its 2010 estimate to 2,688 trillion cubic feet. To put that number into perspective, the U.S. Energy Information Administration projects natural gas usage for 2013 and 2014 to average 70.2 Bcf/d

for all uses. That translates into about 100 years of supply at todays usage rate. Expect reserve estimates to continue to rise faster than usage growth. The bridge fuel is now the fuel express lane.

Solar Boom Then Bust. MidAmerican Solar and SunPower began construction, in late April, of their 579-MW Antelope Valley Solar photovoltaic project, located in Kern and Los Angeles counties. The project, when completed at the end of 2015, will sell power to Southern Califor-nia Edison under long-term purchase con-tracts. At a March Solar Summit hosted by Burns & McDonnell, representatives of the three major California utilities agreed that the number of these large projects is limited because the number of future sites this large are limited, current con-tracts have lower purchase prices, one-time federal government loan guarantees have expired, the solar investment tax credit ends in 2016, and California utility solar project contract goals are oversub-scribed. Once the few large projects in Californias queue are digested, expect to see the market focus on smaller projects (

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Ontario Completes New Niagara Tunnel to Increase Output from Hydro ComplexA massive eight-year construction feat to bore a 41-foot-wide, 6.3-mile-long tunnel deep beneath hard rock under the City of Niagara Falls in Ontario, Canada, was successfully completed this March. Undertaken by Ontario Power Generation (OPG) to divert water from the Niagara River and carry it downstream to the 2,080-MW Sir Adam Beck generating complex, the C$1.5 billion project now propels additional water to the hydroelectric plant at a rate of 17,660 cubic feet per second (Figure 1).

The project has been in the planning for nearly a century. When the Sir Adam Beck Niagara Generating Station Number 1 (then known as the Queenston-Chippawa plant) was opened in 1921, it was accompanied by plans for two canals leading from the Welland River to the power station. After the first canal was

built, however, the second canal plan was abandoned. In the 1950s, after Ontarios power demand surged, work began on a second generating station (Sir Adam Beck Number 2) at the site as well as on twin water tunnels 45 feet in diameter at a depth of 330 feet. The two tunnels, completed in 1955, and the original 1921 hydro canal divert a total of 63,566 cubic feet of water per second to the two hydroelectric generating units.

When work began on the newest Niagara Tunnel, Austrian firm STRABAG Co. was forced to route the tunnel to bypass the gla-cial silt of the buried St. Davids Gorge and to maintain a safe separation from the existing tunnels (even though they run on a mostly parallel route) at a depth of 459.3 feet (Figure 2). But this depth proved cumbersome, as some workers explain on a site dedicated to the project (www.niagarafrontier.com), because it was predominantly Queenston Shale (mudstone). The reddish-purplish shale is fractured and has resulted in many roof-line rock falls slowing the boring operation, the site says. Although test boring samples were conducted in preparation for this project, none uncovered the vertical fracturing in the rock strata that the tunneling crews [experienced].

In 2009, the difficult rock conditions forced OPG and STRABAG to revise the projects schedule. According to Ontarios Ministry of Energy, the project that employed 580 people during the peak of construction was completed nine months ahead of the revised schedule and nearly C$100 million under budget.

OTEC Gets Boost with Possibility of 10-MW Plant in ChinaA 10-MW ocean thermal energy conversion (OTEC) pilot plant is being planned off the coast of southern China by global security and aerospace firm Lockheed Martin and Beijing-based cleantech firm the Reignwood Group. The companies announced an agree-ment in mid-April to develop the pilot plant to fully power a planned resort community, and if it comes to fruition, the project could pave the way for more efficient and cheaper plant designs using the technology.

OTEC plants generally generate electricity by exploiting the oceans thermal gradientstemperature differences of 36F or more between warm surface water and cold deep seawaterto drive a power-producing cycle. According to the U.S. National Renewable Energy Laboratory (NREL), 23 million square miles of tropical seas absorb an amount of solar radiation equal in heat content to about 250 billion barrels of oila tenth of which could supply 20 times the power needs of the entire U.S. on any given day.

The possibilities offered by OTEC have been considered for more than a century. The technology was first proposed as far back as 1881 by a French physicist, and several prototypes have been tested intermittently since the first experimental 22-kW low-pressure turbine was deployed in 1930. In the 1990s, the Pa-cific International Center for High Technology Research operated a 210-kW open-cycle OTEC plant at the Natural Energy Laboratory of Hawaii (Figure 3), and India unsuccessfully tested a floating 1-MW floating OTEC plant near Tamil Nadu in 2002. No commer-cial plants exist, however,

Lockheed Martins own history with OTEC began in 1970s, when it developed a floating mini-OTEC plant (50 kW) that ran for three months. In 2007, Lockheed began developing specialized com-

1. A massive undertaking. Ontario Power Generation and Austrian firm STRABAG in March completed construction of a 41-foot-

wide, 6.3-mile-long tunnel deep beneath hard rock under the City of

Niagara Falls in Ontario. The project was begun in 2005 to divert water

from the Niagara River to the 2,080-MW Sir Adam Beck generating

complex. Courtesy: Niagarafrontier.com

2. A rough road. To bypass the glacial silt of the buried St. Davids Gorge and to maintain a safe separation from an existing 1921-built hy-

drocanal and 1955-built twin tunnels, the new Niagara Tunnel, completed

this March, burrowed at a depth of 459.3 feet in rock strata predomi-

nantly consisting of Queenston Shale (mudstone). Source: OPG

Tunnel alignment longitudinal section

Intake structureNiagara

River

Normal

WL. 171.0

SAB -

Niagara

GS No. 1

Canal

Normal WL.

164.6

Outlet structure

Buried St. Davids Gorge

Existing tunnels

Whirlpool Sandstone

Queenston Shale

0 Kilometers1 2

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posite piping for obtaining cold water using a $1.2 million grant from the U.S. Department of Energy (DOE). And in 2009, fol-lowing a $8.1 million contract with the U.S. Navy, the company continued to develop a 10-MW OTEC pilot plant in Hawaii, which included creating a robust interface between the platform and cold water piping. That project was apparently cancelled after the Navy deemed the project too costly.

According to NREL, cost is the most significant reason the technology has failed to reach larger scale, despite the investi-gation of many potential thermodynamic cycles to reduce overall costs. The estimated capital cost for OTEC in 2011 ranged from $10,000/kW to $15,000/kW, and the majority of costs are linked to seawater systems, the research lab says.

However, the technologys potential benefits are lucrative, Lockheed says. Not only can OTEC serve as a baseload power source that is renewable, OTEC power can also be used to produce hydrogen (via electrolytic processing of freshwater) and ammo-nia, which can be shipped to areas not close to OTEC. The system can also include freshwater production by flash evaporating the warm seawater and condensing the subsequent water vapor using seawater.

Once a proposed plant is developed and operational in China, Lockheed and Reignwood plan to use the knowledge gained to improve the design of the additional commercial-scale plantsof up to 100 MWto be built over the next decade.

U.S. EGS Project Adds 1.7 MW Grid-Connected OutputOne of the first enhanced geothermal systems (EGS) was con-nected to the U.S. electric grid this April, marking a major milestone for the fledgling technology that seeks to tap the enormous terrestrial heat potential deep within Earths crust using directional drilling and pressurized water. Reno, Nev.based Ormat Technologies, the U.S. Department of Energy (DOE) and Schlumberger subsidiary GeothermEx said they had stimu-

lated an existing injection well to increase power output from brine by 1.7 MW at Ormats grid-connected 26-MW Desert Peak 2 geothermal plant in the Brady complex in Nevadas Churchill County (Figure 4).

EGS, a method also referred to as a hot dry rock or hot frac-tured rock system, has been around for more than three decades. Around the world, several large-scale EGS field projects have reached varying degrees of success, but only one projectthe 2007-commissioned 3.2-MW Landau project in Germanyhas sustained commercial production rates. The method has been stalled by a variety of issues, foremost among them an expo-nentially higher power cost than for fossil-fueled generation, owing to expenses associated with drilling of deep geothermal wells, experts say.

EGS is essentially an engineered heat exchanger designed to extract geothermal energy under circumstances in which con-ventional geothermal production is uneconomic or inefficient. It involves enhancing the permeability of deep hot rock by hydrothermal fracturing, high-rate water injection, and/or chemical dissolution of minerals by drilling production wells to depths of 10,000 feet and beyond where temperatures reach upwards of 350F. A cold working fluidwater, typicallyis then allowed to flow through the deep openings in the rock to further crack it and to mine its heat energy. When the water is pumped back to the surface, the resulting steam is used to power a turbine to generate power. The water is cooled again into a liquid and injected back into the ground to repeat the cycle in a closed-loop system.

Ormats Desert Peak EGS project uses a production well at a previously built geothermal site in Churchill County, and its developers say that since beginning power production, it has increased power output at the site by nearly 38%. The project was of particular significance to Ormat because it helped the company demonstrate how EGS could be employed on sub-commercial wells. This could enable us to use un-productive wells to generate more power and new revenue, explained Lucien Bronicki, Ormats founder and chief tech-

3. A hot-and-cold reality. Lockheed Martin and the Beijing-based Reignwood Group have agreed to develop a 10-MW ocean

thermal energy conversion (OTEC) plant that would exploit the oceans

thermal gradients to fully power a new resort community in southern

China. Conceptualized in the 1880s, OTECs many benefits are shad-

owed by the high costs and risks associated with seawater systems.

This image shows researchers laying a cold-water pipe at Keahole

Point, Hawaii, in the early 1990s. The pipe supplied cold water for an

OTEC experiment at Hawaiis Natural Energy Laboratorya 210-kW

project that has been billed as the largest net-producing OTEC system

tested. Courtesy: A. Resnick

4. Digging deep. Ormat Technologies, the U.S. Department of En-ergy, and GeothermEx in April said they had successfully produced 1.7

additional megawatts from an enhanced geothermal system (EGS) proj-

ect inside an existing well field at Ormats Desert Peak 2 geothermal

power plant in Churchill County, Nev. This image, taken in 2008, shows

an EGS wellhead at Ormats Desert Peak project. Courtesy: NREL


THE BIG PICTURE: Power Accident ImpactsThe history of electric power has been stained by several devastating incidents triggered by natural hazards, technological fail-ures, malicious actions, and human error. Here POWER surveys some of the worlds most devastating or costly incidents. Colors: orange = nuclear event, blue = water event, black = coal event. Size of the stain indicates relative magnitude.

Copy and artwork by Sonal Patel, Senior Writer

Aug. 8, 1975Henan Province, China: Banqiao Dam and Shimantan Reservoir Dam

on the Ru River catastrophi-

cally fail following Super

Typhoon Nina, causing a wave

6.2-miles wide and up to 23

feet high that created tempo-

rary lakes as large as 4,600

square miles, inundating 18

villages. (Fatalities: 171,000)

Mar. 28 1979Pa., U.S.: Equipment failure contributes

to loss of coolant and partial

meltdown at one of two

reactors at Three Mile Island.

(Cost: $2.4B)

Aug. 17, 2009 Khakassia, Russia: Turbine 2 of the 6.4-MW Sayano-Shushenskaya hydroelectric

station breaks apart violently,

flooding the turbine hall and

engine room and damaging nine of

the plant's 10 operational turbines.

(Fatalities: 75)

Apr. 26,1986Kiev, Ukraine: A flawed reactor design operated by

inadequately trained personnel at

the Chernobyl nuclear power plant

results in a steam explosion and

fire of at least 5% of the radioac-

tive reactor core into the atmo-

sphere. (Fatalities: 30)

Dec. 1, 1923Valle di Scalve, Italy: A portion of Gleno's

Dam attached to a

3.7-MW hydroelectric

plant in northern Italy

completely fails 40

days after its reservoir

was filled, flooding

local countryside

(Fatalities: 356)

Dec. 22, 2008Tenn., U.S.: Following the breach of a 50-year-old coal ash storage

pond at the Tennessee Valley Authoritys

1,700-MW Kingston Fossil Plant, an

estimated 1.1 billion U.S. gallons of

material, mostly wet ash, is released onto

some 300 acres of surrounding land and

flows up and downstream of two Tennessee

River tributaries.

(Cost: $1.2B)

Mar. 11, 2011Fukushima Prefecture, Japan: Four of six reactors at Tokyo Electric Power Co.'s Daiichi reactors lose

cooling function after being inundated

by a 49-foot-high tsunami following a

9.0-magnitude earthquake. Cores of

Units 13 reactors melt within the first

three days, and all four reactors are later

written off. (Cost: $152B)

Aug. 8, 1975Henan Province, China: Banqiao Dam and Shimantan Reservoir Dam

on the Ru River catastrophi-

cally fail following Super

Typhoon Nina, causing a wave

6.2-miles wide and up to 23

feet high that created tempo-

rary lakes as large as 4,600

square miles, inundating 18

villages. (Fatalities: 171,000)

Mar. 28 1979Pa., U.S.: Equipment failure contributes

to loss of coolant and partial

meltdown at one of two

reactors at Three Mile Island.

(Cost: $2.4B)

Aug. 17, 2009 Khakassia, Russia: Turbine 2 of the 6.4-MW Sayano-Shushenskaya hydroelectric

station breaks apart violently,

flooding the turbine hall and

engine room and damaging nine of

the plant's 10 operational turbines.

(Fatalities: 75)

Apr. 26,1986Kiev, Ukraine: A flawed reactor design operated by

inadequately trained personnel at

the Chernobyl nuclear power plant

results in a steam explosion and

fire of at least 5% of the radioac-

tive reactor core into the atmo-

sphere. (Fatalities: 30)

Dec. 1, 1923Valle di Scalve, Italy: A portion of Gleno's

Dam attached to a

3.7-MW hydroelectric

plant in northern Italy

completely fails 40

days after its reservoir

was filled, flooding

local countryside

(Fatalities: 356)

Dec. 22, 2008Tenn., U.S.: Following the breach of a 50-year-old coal ash storage

pond at the Tennessee Valley Authoritys

1,700-MW Kingston Fossil Plant, an

estimated 1.1 billion U.S. gallons of

material, mostly wet ash, is released onto

some 300 acres of surrounding land and

flows up and downstream of two Tennessee

River tributaries.

(Cost: $1.2B)

Mar. 11, 2011Fukushima Prefecture, Japan: Four of six reactors at Tokyo Electric Power Co.'s Daiichi reactors lose

cooling function after being inundated

by a 49-foot-high tsunami following a

9.0-magnitude earthquake. Cores of

Units 13 reactors melt within the first

three days, and all four reactors are later

written off. (Cost: $152B)

2012 Baldor Electric Company

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nology officer. Conducted under a stringent induced seis-micity protocol developed by Lawrence Berkeley National Laboratory (LBNL) and the DOE, the project used Ormats air-cooled power plants, so no water was consumed in the conversion of energy into power. We achieved an increased injection rate up to 1,600 gallons per minute without con-suming or discharging water at the surface and using only existing geothermal brine returned to the original aquifer, Bronicki said.

The project, which has received $5.4 million in direct DOE funding (and $2.6 million matched by Ormat), got its start in 2002, and a boost in 2008 as several entitiesincluding the U.S. Geological Survey (USGS), LBNL, and Sandia National Laboratoriesjoined the operation. It is currently one of a handful of projects in the U.S. focused on demonstrating the commercial viability of EGS. Other DOE-sponsored projects include a Calpine demonstration project at The Geysers in Middletown, Calif., and an AltaRock demonstration project at the Newberry Volcano near Bend, Ore.

Seattle-based AltaRock Energy this January announced a milestone of its own, claiming it had created multiple stimu-lated zones from a single wellbore at its projectan achieve-ment that could dramatically increase the flow and energy output per well for the completed system, it said. AltaRock this year expects to test for permeability, flow rates, and heat-capturing properties of created reservoirs before it drills production wells about 1,500 feet from the injection well.

The DOE, meanwhile, plans to widen its investment in EGS. In February, the Lawrence Livermore National Laboratory re-

leased a technology roadmap for strategic development of EGS systems in the U.S., citing a 2008 USGS projection that EGS could be exploited to meet projected capacities on the order of 100-plus GW. The potential for EGS has especially heightened, the roadmap notes, because current practices in unconventional oil and gas developmentparticularly technology advancements for drilling horizontal wells and for fracturing fluidsdemonstrate that rapid technology advancement correlates with sector growth by improving project economics and decreasing risk.

Ningde 1 Is Latest Chinese Reactor to Start Commercial OperationNingde 1, the first of four Chinese-designed CPR-1000 pressur-ized water reactors being built at a site in Fujian Province, began commercial operation this April after a 58-month construction period. The 1,080-MWe unit was grid-connected in late December 2012 and underwent a 168-hour trial operation before it began commercial operation. The $7.6 billion Ningde reactors, all which will come online by 2015 (Figure 5), are 46% owned by China Guangdong Nuclear Power Co. (CGN) and 44% by China Datang Corp., while the Fujian Provincial Energy Group holds the remain-ing shares. CGN in February successfully grid-connected Unit 1 of the Hongyanhe Nuclear Power Plant in Liaoning Province, the first nuclear plant ever in Northeast China. That six-reactor proj-ect is also slated for completion by 2015.

China now has 17 reactors in operation, 28 others under con-struction, and several more in the planning phase. Most are do-

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CAT, CATERPILLAR, their respective logos, Caterpillar Yellow, the Power Edge trade dress, as well as corporate

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2013 Caterpillar. All Rights Reserved.

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mestically designed reactors that draw from French, Canadian, and Russian technology, though Westinghouses AP1000 is ex-pected to be the main basis of Chinas transition to Generation-III technology.

China is also developing the Advanced CPR-1000 (ACPR1000) with full Chinese intellectual property rights for export, expected after 2014. This March, CGN Chair He Yu was quoted as saying, however, that China still lacks proprietary nuclear power technol-ogy and full intellectual rights that would make it a competi-tive international player. Currently, the Chinese nuclear power enterprises generally lack the experience of developing the in-ternational market as well as the awareness of marketing, com-petition, and risk control, and also are in urgent need of talents for internationalization, he said.

POWER DigestNRC Poised to Rule on SCE Proposal to Restart San Onofre Unit 2. Southern California Edison (SCE) on April 5 submitted a voluntary request to the U.S. Nuclear Regulatory Commission (NRC) for a license amendment to support restart of Unit 2 of the San Onofre Nuclear Generating Station, and the NRC later said in a preliminary finding that restart of the crippled reactor did not pose significant safety risks. SCEs proposal has called for a five-month trial period to operate Unit 2 at 70% power, and the utility asked the NRC to act on the amendment before the end of May so the unit would be available to help meet peak summer power demand in southern California by June 1. Both reactors at the San Onofre plant have been shut down since January 2012, after workers discovered significant tube-to-tube wear.

MHI Ships Turbine Rotors to AP1000 Plants in China. Mitsubishi Heavy Industries (MHI) on April 25 said it had completed the shipment of 16 turbine rotors (12 low-pressure and four high-pressure units) to Units 1 and 2 of the Sanmen Nuclear Power Plant and Units 1 and 2 of the Haiyang Nuclear Power Plant in China, which are under construction and using Westinghouses AP1000 reactor design. The Sanmen units in Sanmen, Zhejiang Province, are being built by Sanmen Nucle-ar Power Co., while the Haiyang units in Haiyang, Shandong Province, are being built by Shandong Nuclear Power Co. MHI

and Harbin Electric Co. Ltd. received the orders in 2007 and 2008. MHI designed and manufactured the nuclear plant tur-bines, which are large units integrating the latest 54-inch class rotating blade. Harbin Electric supplied turbine casings, piping, and associated equipment. MHI previously completed nuclear plant turbine generators for two reactors at the newly built Laguna Verde plant in Mexico and the fourth nuclear plant in Taiwan.

ABB to Supply Components for 8-GW Power Link. ABB in mid-April secured an order of about $150 million to supply converter transformers, direct current filter capacitors, and key components for converter valves for the 8-GW Xiluodu-Zhexi power link in China. The 800-kV ultra-high-voltage direct current (UHVDC) transmission connection that will stretch 1,670 km from Yibin in Sichuan Province in southwest China to Zhejiang prov-ince on the eastern coast has been billed as the worlds highest capacity power link. ABB pioneered HVDC technology 60 years ago, and the company says UHVDC transmission, a development of HVDC, represents the biggest capacity and efficiency leap in more than two decades.

Alstom to Supply Transformers to Brazilian Line. Alstom in early April said it supplied two high-voltage direct current (HVDC) converter transformers to the Rio Madeira power trans-mission line in Brazil, a line that measures 2,375 km (1,476 miles) and features two converter stations at Porto Velho in the central state of Rondonia and Araraquara in Sao Paulo, in the southeast. The projectone of the longest in the worldwill bring power from two mega-hydroelectric plants, the 3,150-MW Santo Antonio and 3,150-MW Jirau plants, in the Amazon region to densely populated cities in the south.

Construction of 579-MW PV Plant Begins. U.S. firms MidAmerican Solar and SunPower in late April began con-struction of the 579-MW Antelope Valley Solar project in Cal-ifornia, a project comprising two photovoltaic (PV) plants in Kern and Los Angeles counties whose electricity will be sold to Southern California Edison under two long-term contracts. Construction of the plants is expected to be completed by the end of 2015.

UK Selects Winners of CCS Commercialization Pro-gram. The UKs Department of Energy and Climate Change in late March announced that the Peterhead project in Ab-erdeenshire, Scotland, and the White Rose project in York-shire, England, are the two preferred bidders for selected funding stemming from the agencys 1 billion ($1.6 bil-lion) Carbon Capture and Storage (CCS) Commercialisation Programme Competition. Shell and Scottish and Southern Energys Peterhead project involves capturing about 90% of the carbon dioxide from part of the existing gas-fired power station at Peterhead before transporting it and storing it in a depleted gas field beneath the North Sea. A consortium consisting of Alstom, Drax Power, BOC, and National Grid will develop the White Rose project, which will capture about 90% of carbon dioxide from a new 426-MW coal-fired plant at the Drax site that will be designed to cofire biomass. The carbon dioxide will then be transported by pipeline for stor-age in a saline aquifer beneath the North Sea seabed.

The UK government is expected to enter into contracts this summer for front end engineering design studies, and a final in-vestment decision could be made as early as 2015. Captain Clean Energy and Teesside Low Carbon, the remaining two bidders with whom the agency had also been in discussion for the se-lected funding, will be appointed as reserve projects.

Sonal Patel is POWERs senior writer.

5. Rendering of Ningde site. The first of four CPR-1000 reac-tors under construction by the China Guangdong Nuclear Power Co.,

China Datang Corp., and a local partner at the Ningde site in Fujian

Province, China, has begun commercial operation. The second unit is

expected to come online later this year, Unit 3 in 2014, and Unit 4

in 2015. Each of the reactors is rated at 1,080 MWe. China will add

at least 23 new reactors to its current fleet of 17 by 2015. Most will

feature Chinese CPR-1000 technology, but at least four (Sanmen Units

1 and 2 in Zhejiang Province and Haiyang Units 1 and 2 in Shandong

Province) will be AP1000s, and two (Taishan Units 1 and 2 in Guang-

dong Province) will be EPRs. Courtesy: CGN

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LADWP Harnesses LMS100 to Solve Once-Through Cooling Dilemma

Los Angeles sits alongside the worlds largest body of water, and naturally the citys Department of Water & Power (LADWP) placed its generating stations along the shoreline to take advantage of that abundant resource for cooling. The LADWP built three coastal generating stations that provide the city with 2,162 MW, about 35% of the peak annual demand.

Well, at least it seemed like a good idea at the time. Updates to Section 316(b) of the Clean Water Act are expected to man-date that new, and some existing, power plants take additional steps to minimize fish mortality by plant cooling water intake structures. Those updates are scheduled for a late June 2013 re-lease. However, in May 2010 the California State Water Resources Control Board issued a policy that all existing power plants using ocean water for once-through cooling (OTC) reduce their water usage by 93%.

To address this requirement, the LADWP has begun a $2.4 bil-lion, multi-decade project to repower the three generating sta-tions, not only reducing the water used but also creating a more efficient and flexible generating capacity.

We have a variety of efforts under way that mesh together well, says John Dennis, LADWPs director of power system engi-neering. They all work together to meet California regulations and energy efficiency goals, as well as any federal requirements. It is a pretty exciting plan.

Reliability, Rates, and Reduced Carbon FootprintEach year, the LADWP issues an updated Power Integrated Re-sources Plan (IRP), which provides the long-term planning for the utilitys power generation resources. The IRP is based on three key objectives: maintaining a high level of electric service reliability, maintaining competitive rates, and exercising envi-ronmental stewardship, including a reduced carbon footprint. These goals are often in tension.

The utility has already made significant progress toward its environmental goals. It has achieved the state mandate for 20% renewable energy, reducing its CO2 emissions by 23% compared to 1990, and is on target for reaching 33% reduction by 2020. Participants in LADWPs Green Energy program were receiving 104 GWh annually from wind, solar, geothermal, and hydro facilities in several western states. The carbon reductions have come largely from reducing the importation of electricity produced from coal, including shutting down the 1,500-MW Mohave Generating Sta-tion, of which LADWP was a co-owner, and switching to natural gas and renewable generation.

Looking ahead, the IRP envisions further increases to the use of wind and solar and early shutdown of one of LADWPs two remaining coal plants, while replacing the once-through cooling systems with dry condensers.

Although the plan does a good job of meeting the first and third of the key objectives outlined above, the second objec-tive, maintaining competitive rates, does take a hit. According to the U.S. Energy Information Administrations Electric Power Monthly for April 2013, California already had the 10th highest average cost of electricity at 13.02/kWh in Feb. 2013, 33% higher than the national average and roughly 45% higher than the average of the three states it borders: Oregon (8.39), Nevada (8.17), and Arizona (9.30). According to the IRP,

the prices may rise to 22/kWh over the next decade, adding about $50 to the average residential customers monthly bill and $600 extra per month for a commercial or industrial cus-tomer using 6,500 kWh.

Maintaining reliable service remains a difficult chore, particu-larly in the face of increasing renewable usage and the OTC man-date. The California Independent System Operator (CAISO) says that this can be achieved through increased use of fast-response, high-efficiency combustion turbines.

Gas-fired generation is our only means to do this right now until storage and demand response have matured to com-pensate for the fluctuations of wind and solar power, says CAISO spokesperson Stephanie McCorkle. We are actively edu-cating policy makers and trying to propose a solution at the regulatory level as well to ensure that there is still enough conventional gas-fired generation available to us to be able to maintain reliability as we see more and more renewables added to the grid.

LADWP manages its own grid, and sees quick-start gas genera-tion as the way to accommodate more renewables in its genera-tion mix and cut its use of ocean water.

We looked at the technologies available and decided to go with advanced CT technology, says Dennis. We saw the need to be more flexible and have faster startup times, and this would integrate well with our variable renewable energy sources.

The Haynes ProjectAs with any major, long-term generation strategy, LADWPs IRP has to take into account a variety of competing factors and find the best mix of resources to meet its needs. In addition to cut-ting water use while providing energy efficiency and flexibility, generating stations must also provide enough reactive power to support the grid and allow the importation of power from remote renewable sources. This wasnt a problem with the old boilers.

Because the units were slow in starting up, we would always have something running, says Dennis. It may not have been the most efficient, but we always had some kind of spinning reserve connected, which provided inertia.

When switching to the fast-start CTs, this would no longer be possible, and so the design had to find another way to provide voltage support.

LADWP has nine OTC units at its three generating stations. These plants were also getting on in years and needed a tech-nology refresh anyway. The first of these stations to undergo repowering is the Haynes Generating Station in Long Beach. Built in the 1960s, Haynes has six natural gas steam units generating 1,600 MW total. In 2005, Units 3 and 4 were repowered with a 575-MW 2 x 1 combined cycle power block (Units 810) that is 40% more efficient and has 94% fewer emissions than the boilers it replaced.

Our plan for Units 5 and 6 was to move on with another combined cycle block of similar size, using large frame units, says Dennis. We were close to having the environmental impact report done, but then the once-through cooling rule came out and we had to take a whole different approach.

After looking at all the options, LADWP decided that it would be better to go with six 100-MW GE LMS100 fast-start, simple cycle combustion turbines rather than a single combined cycle unit. Although at full capacity the combined cycle unit would

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be more efficient, the LMS100s were better overall based on actual usage. Each LMS100 can go from 0 to 100 MW in 10 minutes, can operate at half-load, and has a 50-MW per minute ramp rate. As a result, this gives the Haynes plant the ability to rapidly respond to system fluctuations, operating anywhere from zero to all six turbines.

If we had a 600-MW power block, we would have had a big jump of 300 MW, says Dennis. These can be run all the way up to the 600 MW and any kind of increments in between.

This didnt, however, solve the problem of having enough reac-tive power to support the grid. If there was a single large unit that was continuously operating and ramping up and down as needed, the generator would provide the necessary VARs to help pull in the power from the remote generating stations. But dur-ing periods when there is ample renewable power available, the LMS100s are offline.

To address this, LADWP had two of the LMS100s equipped with clutches from SSS Clutch Co., Inc. so they can operate as synchronous condensers. These overrunning clutches sit be-tween the turbine and the generator. When the generator ini-tially fires up, the clutch forms a connection so that it drives the generator. Then, when the unit is no longer needed for generation, the turbine can be ramped down. The clutch auto-matically disconnects the turbine from the generator, and the generator keeps spinning, synchronized to the grid and provid-ing the necessary voltage support. Later, when active power is needed, the unloaded turbine fires up and the clutch automati-cally reconnects the two.

In another example of this application, CFE retrofitted an exist-ing unit at its CTG Universidad Plant in Monterrey, Mexico, with an SSS clutch to provide additional reactive power to the down-town industrial district. This project was POWERs 2011 Marmaduke Award winner. (See CFE Extends CRG Universidad Unit 2s Life with Conversion to Synchronous Condenser in the August 2011 issue at www.powermag.com. Two additional LMS100 project reports are available online about the Groton Generating Station, September 2007, and the Panoche Energy Center, September 2010.)

During extremely slow periods, we could go all the way down to zero generation and just keep the generator synchronized and acting as voltage support to the system, says Dennis. This gives us greater overall flexibility and replaces the old technology that took so long to start up.

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Generating Solutions for


1. Six-pack plant. LADWP purchased six General Electric LMS100 simple cycle combustion turbines for its Haynes Project because of

the machines fast start and excellent part-load efficiency, and because

the units may be used as synchronous condensers. The LMS100 is

GEs first aeroderivative gas turbine rated higher than 100 MW. Source:

General Electric

Intercooler system

CF6-80C2High-pressurecompressor

CF6-80EHigh-pressureturbine

Power turbine shaft

MS600IFALow-pressure compressor

Single annular combustor

Exhaust diffuser

Power turbine

Intermediate pressure turbine


Eliminating the WaterOn Sept. 29, 2011, LADWP broke ground on the $782 mil-lion repowering project. The major equipment started arriving in mid-March 2012, and by April 2, three 190-ton turbines, 182-ton generators, and 100-ton dry cooling towers had been

delivered to the site, with the other three units arriving last summer. Testing and tuning began last November and contin-ued through April 2013, so the peakers will be ready for the 2013 summer season.

We are targeted for substantial completion in June of 2013, and everything is looking on schedule for that to hap-pen, says Dennis.

In the meantime, the utility is progressing on its second re-powering project: replacing the three units at the Scattergood Generating Station near Los Angeles International Airport. As of this writing, LADWP is finalizing contracts before beginning work to replace Unit 3, which is scheduled for completion at the end of 2015. The Scattergood project will include a mix of simple cycle units and combined cycle units with similar options for clutches as at Haynes. Either way, it will include dry cooling towers.

Next on the list are the other two units at Scattergood, then two more units at Haynes, one unit at the Harbor Gener-ating station, and then finally replacing the combined cycle units installed at Haynes by 2029. At that point, the LADWP will no longer be using any ocean water for cooling at any of its plants.

Not only can we meet our energy demands, says Dennis, but incrementally step down the use of ocean water, increase our use of renewable energy from 20% to 33% by 2020, in-crease our energy efficiency by 10% by 2020, and reduce our CO2 and NOx emissions.

Contributed by Joe Zwers, a freelance writer from Glendale, Calif., specializing in engineering and technology.

2. Water, water, everywhere, but not a drop to cool. The first two units are shown here during construction, with the gener-

ator and the LMS100 to the right of the foreground and the intercooler

in the left background. The units do not use any ocean cooling water,

unlike the units they are replacing. California requires generators to

severely reduce the amount of ocean cooling water used in future

plants. Courtesy: LADWP

the

company

torque guntm



Steven F. Greenwald Jeffrey P. Gray

Renewable Energy Policy Review Required

The Wall Street Journal (WSJ) recently reported that 14 of the 29 states that have adopted a renewable procurement man-date are currently considering legislation that would water

down or repeal the renewable set-aside. Proponents of repeal describe their motivation as simple economics: Renewable power increases costs to electric consumers.

The Political Briar PatchIn our increasingly partisan world, the debate regarding the role of government and renewable power has been relegated to political wedge status. A state senator advocating repeal of Ohios renew-able legislation equated it to Joseph Stalins five-year plan. An-other state senator seeks to eliminate Texas renewable mandate, insisting that renewables need to be developed with free-market principles, not with the heavy hand of government directing us to an inefficient process. The intensified political characteristic of the renewables debate is epitomized by Grover Norquist, head of Americans for Tax Reform, advocating the rescission of renewable mandates because they function much like a tax increase.

According to the WSJ, the defenders of the renewable mandates are similarly resorting to politics, castigating the repeal initiatives as funded by fossil-fuel interests. The WSJ also intimates that a Kansas state senator voted to preserve renewables primarily be-cause his district includes a plant that produces wind turbines.

Political Rhetoric Frustrates Energy PolicyAny meaningful government support for energy resource policy must set long-term objectives; the technological development and com-mercial deployment of new energy resources are not achievable with off-the-shelf items. The boom or bust development cycle wind generation has experienced can largely be attributed to the market uncertainties Congress has engendered by finding it politically more advantageous to offer tax incentives that expire within one year.

As a matter of economic theory, renewable mandates are in-efficient. For instance, most utility performance targets are set on an MWh basisutilities thus have the incentive to purchase higher-cost renewables even at off-peak hours when less-costly alternatives are available. For purposes of system operations, the promotion of solar and wind projectswithout considering the need for transmission facilities to move their power to load cen-ters, and ignoring the need for additional and flexible baseload power for system reliability purposesgenerates far less than optimal results. However, such inefficiency provides no basis for repeal. By definition, any government program designed to promote a market is inefficient when compared to the invisible hand of a perfectly functioning competitive market.

Attacks against renewable mandates on the basis that they repre-sent yet another government intrusion simply represent just another distracting chapter in the big versus no government debate. Elec-tricity is perhaps the most regulated, government-intrusive industry in the nation. Accordingly, challenging any governmental energy programwhether it is promoting renewable mandates, encourag-

ing oil exploration, or siting nuclear waste disposalsas being an affront to our capitalistic society ignores reality. Absent governmen-tal direction, a market dedicated to least-cost principles will select proven fossil-fuel technologies, disregarding the benefits of diver-sity in generation and forsaking technological advances.

Least-Cost Analysis Is NecessaryAbstract debates emphasizing political philosophy distract from the imperative to conduct adult discussions with the objective to es-tablish integrated, balanced, and long-term policies regarding gen-erating resources. Other than system reliability, overall cost must remain the primary driver in any assessment among competing fuels and technologies. However, selection of least cost cannot be re-solved in one-dimensional 30-second sound bites. Any enterprise can achieve least cost today by making no investment in the fu-ture. On the other hand, everyone supports utilities subordinating least cost and incurring the expenses necessary to maintain current facilities and to construct new facilities to serve load growth.

Selecting the inputs to compare the actual costs of generation resources remains challenging. The higher capital investment for renewables must be weighed against the higher historically vola-tile, and politically sensitive, price for fossil fuels. The compari-son must be dynamic and incorporate a multiplicity of forecasts and assumptions. Will encouragement of solar projects promote investment in solar technologies, driving down capital costs and increasing production? Conversely, will turning away from renew-ables in the name of least cost inexorably trigger price escala-tions of natural gas, the least cost champion du jour?

Any meaningful comparison between construction and environmen-tal costs of the transmission lines to enable renewable generation to provide the greatest value and the greenhouse gasassociated costs of fossil fuels requires a subjective assessment of infinite proportions. If increased use of renewable technologies can decrease the nations reliance on imported fossil fuels, how do policy-makers monetize these geopolitical benefits in deciding our energy future?

An optimal-functioning market requires governing bodies to commit to an affirmative, consistent, and long-term policy for pro-moting renewable fuels and advancing the associated technologies. Private investors stand ready to commit hundreds of millions of dol-lars and enable renewables to become more cost-competitive, but only if they have assurance that they will have a true competitive opportunity to sell their product based on free-market principles.

Skeptics must recognize the economic/regulatory reality that five-year (and even 10-year) plans are necessary to afford renew-ables the opportunity to compete. Legislative critics can best serve their constituents by enabling decision-makers to decide renewable resources policy on the basis of integrated economic, environmental, reliability, and global political considerations, including calculating least cost on a transparent and multipletime horizon basis. Steven F. Greenwald ([email protected]) and Jeffrey P.

Gray ([email protected]) are partners in Davis Wright Tremaines Energy Practice Group.


COMBUSTION TURBINES

Improving Warm Weather Performance of the LM6000

The power rating and heat rate of all

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with increasing ambient temperature.

Unfortunately, in most regions, the warmest

weather (daily and yearly) is coincident with

the greatest demand for electricity and is the

exact time when CT performance plunges.

A good example of the warm weather

performance effect is the PC SPRINT model

of General Electrics LM6000. This CT pro-

duces 51.3 MW at a heat rate of 8,488 Btu/

kWh when the ambient temperature is 48F.

But when the temperature rises to 100F, the

CT output dips to 38.5 MW and heat rate de-

grades (increases) by over 6%. This degrada-

tion is the primary reason why many CTs in

warm weather service have some means of

conditioning the inlet air.

New Air Inlet Cooling OptionHistorically, there have been two primary op-

tions for inlet air chilling: evaporative cooling

(spray or wetted media) and mechanical com-

pression. At 100F ambient temperature, evap-

orative cooling increases the LM6000 output

to 44.6 MW (dependent upon humidity), with

2% degradation in heat rate (compared to the

heat rate at 48F). Mechanical compression

chilling of the inlet air to 48F increases the

output to 49 MW net, but the heat rate deg-

radation increases to 5%. For this discussion,

net output includes chilling parasitic load but

excludes other plant parasitic loads.

A third option has now proven its worth

in long-term operation. The Absorption Re-

frigeration Cycle Turbine Inlet Conditioning

(ARCTIC) systemdeveloped by Energy

Concepts Co., with team members Kiewit

Power Engineers and Nooter/Eriksenuses

an exhaust heatpowered inlet air-condition-

ing system (Figure 1). With ARCTIC, the net

output of the LM6000 on the same 100F day

increases to 51 MW, with no heat rate deg-

radation. The performance gain comes from

using exhaust heat to produce the necessary

chilling, thus avoiding the roughly 2 MW

parasitic penalty of mechanical compression

(based on a 2,000-ton centrifugal chiller).

Figure 2 illustrates the performance gains

achieved with and without using ARCTIC on

an LM6000 PC SPRINT.

An LM6000 PC SPRINT with ARCTIC

system installed at a central Texas utility has

demonstrated this capability nearly every day

for the past three summers, operating for 2 to

12 hours per day, in response to market con-

ditions. The system requires no operators and

functions fully automatically by matching

the CTs 10-minute start to full-load power

sequence. When the CT shuts down, ARC-

TIC automatically shuts down after a short

cool-down period.

There were approximately 400 starts of the

LM6000 during a three-year demonstration

period of the ARCTIC system. During this

demonstration, the ARCTIC automatic start se-

quence failed only five times, producing a start

reliability of nearly 99%. Importantly, failed

starts were all nonrecurring failures. In each

case of a failed ARCTIC start, the CT start and

operation continued without interruption. The

LM6000 merely operated without the warm

The LM6000 is the most widely used aeroderivative combustion turbine (CT) in the world, with more than 1,000 installations. As with all CTs, power output and heat rate degrade markedly during warm weather. The ARCTIC (Absorption Refrigeration Cycle Turbine Inlet Conditioning) system eliminates this deficiency.

Donald C. Erickson and Ellen E. Makar, Energy Concepts Co.

Courtesy: Energy Concepts Co.

COMBUSTION TURBINES


weather performance enhancement.

The ammonia-water absorbent of the ARCTIC

system passes through a heat exchanger inserted

in the CT exhaust gas, producing 2,000 tons of

chilling while also cooling the CT exhaust gas

from 840F to 720F. Remarkably, the lower ex-

haust temperature is also the ideal operating

temperature for the selective catalytic reduction

(SCR) catalyst for maximum catalytic activity

and catalyst life. The heat exchanger added to

the exhaust path adds roughly 0.6 inches water

column to the exhaust pressure drop. This added

pressure drop is actually less than the exhaust

pressure drop caused when adding tempering

air fans to reduce the CT exhaust temperature

105

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85

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Ambient temperature (F)

LM6000 base LM6000 ARCTIC

2. Flat-line performance. The ARCTIC-equipped LM6000 PC SPRINT with NOx water injection is shown as a percentage of ISO output across a range of ambient temperatures. The

SPRINT version of the LM6000 also uses water injection into the high-pressure and low-pres-

sure compressors to produce an additional 3.5 MW across all ambient temperatures. Source:

Kiewit Power Engineers

1. New inlet air-cooling option. An LM6000 PC SPRINT combustion turbine with

ARCTIC has completed three summers of op-

eration in central Texas. The ARCTIC system

is designed to operate in tandem with the re-

mote start of the LM6000. Courtesy: Energy

Concepts Co.

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COMBUSTION TURBINES


to match the SCR temperature needs while also

eliminating the added parasitic electric load of

the tempering air fans.

Industrial CTs (such as the General

Electric Frame 7FA) also benefit from ex-

haust-powered inlet air chilling. These CTs

typically have a lower compression ratio, and

hence have more excess air than aeroderiva-

tive turbines. As a result, they derive a some-

what lower power gain from chilling, about

4.5 kW/ton of chilling instead of the 5.0 kW/

ton enjoyed by the LM6000. However, when

the frame turbine is used in combined cycle

mode, the power gain from inlet air chilling

increases to more than 5.5 kW/ton.

The ARCTIC mode of operation is more

advantageous than duct firing because it re-

stores the warm day power to the CTs stan-

dard rating, but without the heat rate penalties

of duct firing. Duct firing can still be used

when peak power is required. Inlet chilling

of combined cycles can further increase cycle

efficiency by preheating feedwater using the

ARCTIC system reject heat, further improv-

ing the combined cycle efficiency.

Normally, the chiller rating is selected

only for chilling the inlet air. However, suf-

ficient heat energy remains in the exhaust af-

ter the SCR to produce several thousand tons

of additional chilling for other applications,

such as chilled water storage, cooling electric

generators, lube oil systems, or any other sys-

tems adversely affected by hot weather.

ARCTIC OperationThe component parts of the ARCTIC sys-

tem are illustrated in Figure 3. The evapo-

rative condenser and the turbine inlet air

chiller (TIAC) perform essentially identical

functions as their mechanical compression

counterparts. The wet surface air cooler

(WSAC) was selected for the demonstration

plant because of superior performance, but

it does required 40 gpm of makeup water at

design conditions. (For more information on

WSACs, see Wet Surface Air Coolers Mini-

mize Water Use by Maximizing Heat Trans-

fer Efficiency in the September 2008 issue

at www.powermag.com.)

The total design requirement for makeup

cooling water for the ARCTIC system plant

is 125 gpm. However, the inlet air chilling is

well below the wet bulb temperature, so there

is a steady stream of almost pure condensate

recovered, about 25 gpm at design condi-

tions. In locations where water is scarce, air-

cooling is another option. The performance

gain relative to mechanical compression is

even greater when air-cooled because air-

cooled mechanical compressors require more

parasitic power to operate. The air-cooled

variant of this system has been designed to

operate at ambient temperatures up to 125F.

The TIAC can be chilled by a circulating

coolant (water or glycol) or by direct expan-

sion of refrigerant. The latter was selected for

the demonstration plant, avoiding the 80-kW

parasitic load of the coolant pumps. Chilled

ammonia is expanded and distributed into the

TIAC coils at 34F.

The refrigerant heat exchanger (RHX) is

equivalent to the suction line heat exchanger

(SLHX) found in some mechanical compres-

sion units for efficiency improvement. The

RHX improves the coefficient of performance

(COP), the efficiency of the refrigeration unit,

by nearly 10%. The resulting ARCTIC COP is

a very attractive 0.6, where each unit of exhaust

heat input yields 0.6 units of chilling output.

The remaining ARCTIC componentsheat

recovery vapor generator (HRVG), rectifier,

cooler, absorber, and solution heat exchanger

(SHX)are responsible for compressing the

low-pressure vapor from the TIAC to produce

high-pressure vapor for the condenser. The

function is synonymous with the electric-

powered compressor of the mechanical vapor

compression system. The low-pressure am-

monia vapor is next absorbed into the aqueous

ammonia absorbent located in the absorber.

The cooler keeps the absorber at low tempera-

ture to allow absorption to proceed.

The absorbed solution is next pumped to

higher pressure and recuperatively heated in

the SHX before being desorbed by exhaust

heat in the HRVG, at the high-side pressure

of 230 psig. A solution pump pressurizes the

solution from low-side pressure (50 psig) up

to 230 psig. The 60-kW solution pump (shown

below the absorber in Figure 3) is the primary

electric demand of the cycle, with the evapo-

rative cooler fans. The equivalent mechanical

compressor system requires 2,000 kW.

Next, the desorbed vapor has approxi-

mately 10% water vapor, which is reduced to

less than 2% in the rectifier. The non-adiabatic

rectification eliminates the need for separate

reflux or reboil, thus minimizing any penalty

to cycle efficiency. Physically, the rectifier is a

5-foot-diameter column with seven non-adia-

batic distillation trays. Each tray has about 180

square feet of heat exchange surface.

The ammonia inventory in the 2,000-ton

ARCTIC is approximately 6,000 pounds. Most

cold storage warehouses and food processors

have similar or larger ammonia inventories.

However, there are notable differences. The

ARCTIC ammonia is diluted with about 8,000

pounds of water, and it contains no oil, making

the solution appreciably less hazardous than

anhydrous ammonia used in the SCR.

Winter peaks in electric demand also occur

in the region where the demonstration plant is

located. When the ambient temperature is below

40F and the air is humid, the LM6000 requires

the inlet air to be heated at least 10F to avoid

icing in the bellmouth or on the low-pressure

compressor stationary vanes. The ARCTIC

system has an anti-icing mode in which it heats

the inlet air by 20F to eliminate inlet icing. The

transition between heating mode and chilling

mode is automatic. This mode of operation was

demonstrated multiple times each winter (and

on exceptionally cold spring and fall days).

The robustness of ARCTIC was demon-

strated by its reliable operation during excep-

tionally harsh test conditions, such as during

ambient temperatures from 110F down to

11F, multiple starts and stops per day, and

3. ARCTIC flow diagram. In general, waste heat from the combustion turbine (CT) ex-haust is used in an absorption chilling system to cool the CTs inlet air. The ARCTIC system is

designed to produce sufficient chilling to maintain a constant power output, with little change in

system efficiency, across a wide temperature range. Source: Energy Concepts Co.

Evaporative condenser

Refrigerant heat exchanger

Air

Turbine inlet air chiller

Evaporative cooler

Fuel

Absorber

Solution heat exchanger

Rectifier

Exhaust

Selective catalytic reduction

Heat recovery vapor generator

COMBUSTION TURBINES


frequent, rapid power cycling from minimum

to maximum output. In one notable episode,

temperatures in central Texas dropped to a re-

cord-setting 11F. Several large power plants

were knocked offline, causing critical power

supply shortages. The ARCTIC LM6000

operated for 62 continuous hours until the

emergency passed.

The ARCTIC is delivered as a skidded

unit (Figure 4). For utility applications, the

standard skid sizes are 2,000 tons and 3,000

tons of inlet chilling. For smaller turbines

(less than 20 MW) a range of skid sizes is

available, from 100 to 1,000 tons.

The ARCTIC system has a small cost

premium relative to a mechanical chiller of

the same capacity. However, when all the

auxiliary functions are credited (anti-icing,

tempering air, less switchgear), the overall

installed cost is essentially the same. The

systems big plus is the increased cold- and

hot-weather performance, improved oper-

ating efficiency, and reduced maintenance

relative to a plant using a mechanical chill-

er for inlet cooling, all obtained at no ad-

ditional cost.

Donald C. Erickson ([email protected]) is president and Ellen E. Makar is

the projects engineer for Energy Concepts Co., the ammonia absorption refrigeration

technology supplier. The authors wish to acknowledge the other members of

the team that developed the utility-scale ARCTIC: Kiewit Power Engineers Chris

Mieckowski, responsible for project imple-mentation, and Nooter/Eriksen, supplier of

the heat recovery vapor generator.

4. ARCTIC equipment. The ARCTIC system is packaged onto a single skid to enable quick field installation and ease of interconnection with the LM6000 PC SPRINT. Courtesy:

Energy Concepts Co.



HEAT RECOVERY STEAM GENERATORS

Fast-Start HRSG Life-Cycle OptimizationModern heat recovery steam generator (HRSG) design must balance operating

response with the reduction in life of components caused by daily cycling and fast starts. Advanced modeling techniques demonstrate HRSG startup ramp rates can be accelerated without compromising equipment life.

By Horst Hack, Zhen Fan, and Andrew Seltzer, Foster Wheeler North America Corp. and Javier Alvarez, Foster Wheeler ES, Spain

Natural gasfired combined cycle

(NGCC) technology is an attractive

choice for new power plants because

of its high fuel efficiency, operating flexi-

bility (quick starts and rapid load changes),

relatively short planning and construction

Documents

June 2013