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February 2013

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Power Engineering International February 2013 1Power Engineering International

POWER ENGINEERING INTERNATIONAL

Contents

FEBRUARY 2013/// VOLUME 21/// ISSUE 2

4 Industry Highlights

6 News Update

46 Diary

48 Project & Technology Update

52 Ad Index

Opinion

18 International nuclear investment

An international legal advisor on nuclear power projects

argues that foreign investment in new-build plants should

be welcomed, not feared, and illustrates the international

f nancing models available.

Features

12 Russia’s power sector: An insiders’ view

As Russia’s power reforms enter a crucial phase, major

players discuss what has been done and what key

challenges remain.

22 Holistic approach to HRSG management

A top-down, intergrated managing of heat recovery steam

generators can maximise the prof tability of a combined-

cycle plant.

28 Middle East plans for fossil fuel phase-out

As the Middle East’s energy consumption rockets, the region

is embracing nuclear and renewables to conserve its own

oil and gas.

34 The SNCR option for large coal boilers

Selective non-catalytic reduction systems can be an attractive

alternative to selective catalytic reduction in coal plants.

40 Mega trial opens Europe to micro-CHP

A large-scale initiative across 12 European nations aims to

test the potential for fuel cell micro-CHP in the EU.

On the cover The core of Unit 4 at Kalnin nuclear power plant in Russia. (see p.12)

Credit: Rosatom

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Coming up in March’s issue

European electricity demand on the rollercoaster Trade body Eurelectric assesses where the European electricity sector

stands in an overall environment of recession that is putting huge

pressure on the promised low-carbon transition towards 2050.

Latin America’s shale gas boomIf media reports are to believed shale gas is ‘booming’ in the region.

What could this mean for the region’s traditional power generation

mix, especially hydro’s dominance?

The trend of operating combined-cycle plants in

varying modes places stresses on HRSGs (p.22)

Source: Alstom

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4 Power Engineering International February 2013 www.PowerEngineeringInt.com

Industry Highlights

According to off cial f gures, last year

saw several European countries rely

more heavily on their existing coal-

f red power f eet to generate electricity, at

the expense of those plants f red by natural

gas. The UK’s Department of Energy and

Climate Change (DECC) released data

that showed coal dominated the country’s

energy mix in 2012, on the back of rising

natural gas prices that makes the spark

spread less favourable.

Similarly in Germany, the BDEW (the

National Association of Energy and Water

Industries) has reported that gas-f red

power generation fell by an astounding

27 per cent last year, as many of the

countries energy providers opted to

switch to cheaper coal. According to the

latest f gures, both hard coal and lignite-

f red plants rose 1.5 per cent on 2011,

accounting for a 44 per cent share of gross

electricity demand.

As Germany continues to implement

its ambitious ‘Energiewende’ or energy

transition towards greater reliance on

renewable energies, the country’s power

producers are clearly facing signif cant

challenges, with gas-f red generation

assets bearing the brunt.

One sobering illustration is E.ON’s

announcement last month that it is

seriously considering closing its ground-

breaking Irsching 5 combined-cycle power

plant (CCPP), which only came on line in

2010 and is one of Europe’s most eff cient

power plants.

According to reports, operators of gas-

f red power assets in Germany are suffering

from high gas prices and a big drop in

wholesale power prices, plus a signif cant

reduction in plant running hours, because

renewables take precedence on

transmission grids. I have heard stories of

CCPPs running less than 1000 hours a year.

So you might think all this looks good

for a longer-term revival in coal-f red

power generation in Europe, but you’d be

wrong. Although existing coal-f red assets

are being f red-up, no-one in Europe is

seriously looking at constructing new

higher eff ciency coal plants to replace the

increasingly aged f eet – neither from an

economic nor environmental viewpoint.

And new-build coal in Europe received

a further knock back at the end of last

year, when the f rst round of the European

Commission’s (EC) NER300 funding was

announced, with relatively little fanfare I

have to say. The outcome, which some

may argue was not unexpected, was that

not one of the carbon capture and storage

(CCS) projects shortlisted was awarded

funding. Instead, 23 renewable energy

demo projects will share a €1.2 billion pot.

It was initially reported that €275 million

envisaged for CCS projects in the f rst

round remains available to fund projects

under the second phase of the NER 300

programme. However, subsequently on the

NER300 website that has been described

as ‘untenable’.

Before you start calling me a harbinger

of ‘CCS’ doom, there have been some

recent positive developments in the CCS

area. Global Data released a bullish report

at the end of last year, saying that current

government plans and other initiatives

mean that 10 GW of CCS capacity globally

could be on line by the end of this decade.

A more practical development has

been the recent establishment of a

network of international test facilities, with

the ultimate goal to help accelerate the

commercialisation of CCS technologies. The

network is being headed up by Norway’s

CO2 Technology Centre Mongstad.

Finally, the European Commission is

apparently preparing a EU CCS Policy

document that Frederic Hauge, president

of Bellona Foundation and an advocate

of CCS, describes as “the most important

document that the [EC] has produced on

CCS for the last two years”.

There is little available detail, but

allegedly the EC plans to go beyond the

ETS and introduce new mechanisms such

as Emission Performance Standards or

a CCS certif cate system. According to

Hauge, such mechanisms should provide

clear and predictable incentives for CCS

deployment in Europe’s energy sector. As is

so often the case, let us wait and see.

New-build coal in Europe received another knock back when not one of the CCS demo projects shortlisted for the NER300 funding was successfulDr Heather Johnstone

Chief Editor


1302PEI_4 4 2/15/13 9:21 AM



5Power Engineering International

Industry Highlights

Pull Quote xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxHeather Johnstone

Chief Editor

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News Update

International

Power and utilities set for robust deal making this year

The global power and utility sector is set for

robust merger and acquisition (M&A) activity

in 2013 following a decline last year, according

to new f gures.

While 2012 was a year of “transformation”

which resulted in a “tougher landscape”,

analysts at Ernst & Young believe that “the

ingredients are in place for a steady deal-

making environment in 2013”.

In its recently published Power Transactions

and Trends report, Ernst & Young reveals that

M&A deals fell in 2012 to $120.4bn, compared

to $144.7 bn in 2011.

It states that a weak macro environment

prompted buyers to focus on lower-risk

transactions and internal cost cutting

programmes. While the f rst half of the year

remained in line with 2011, the second half

depressed the average deal value, with

more deals under $100m ref ecting a greater

emphasis on smaller deals and an increase in

renewable energy transactions.

Joseph Fontana, Ernst & Young’s Global

Transactions Power & Utilities leader, said

the tougher landscape in 2012 was caused

by “decade-low natural gas prices in North

America, aggressive European environmental

regulations, continued Eurozone economic

uncertainty and over-leveraged balance

sheets at some larger European players”.

Europe contributed almost half of 2012’s

global deal volume and value. Divestment

and privatisation programmes accounted

for nearly 20 per cent of European activity as

a number of utilities sold non-core assets to

strengthen their core businesses and expand

in emerging markets.

Europe was also the focus for renewable

energy transactions, with wind the

most active segment. While subsidy cut

announcements curtailed some activity,

momentum was maintained as utilities

struggled to balance capital allocation and

portfolio management, while complying with

aggressive environmental mandates.

This strong European performance will

continue in 2013, states Ernst & Young. It

predicts “billion-dollar deals to come out of

European utility divestment programmes,

particularly on the regulated side, where there

is strong buyer interest”.

Last year, Europe was also the “favourite

destination” for Asian investors, who were

attracted by favourable regulatory policies

and availability of high-quality assets.

In the Asia-Pacif c region, major transactions

in China and Australia signif cantly increased

the region’s 2012 deal value to $30bn

compared to $11.3 bn in 2011.

In the Americas, the US became one of

the most active countries for generation deals

during 2012, thanks to depressed natural gas

prices, while in Latin America, Brazil continued

to attract foreign investors on the back of

its strong economic growth and signif cant

energy infrastructure investment needs.

Looking to deals this year, Joseph Rodriquez

of Ernst & Young’s Global Power & Utilities

Sector, said: “The ingredients are in place for

a steady deal-making environment in 2013.

Access to credit remains relatively strong,

and there is a war chest of sovereign wealth

capital ready to be put to work. The valuation

gap between buyers and sellers that held up

some deals in 2012 will narrow as sellers act

on investor pressure to redeploy capital.”

Fontana added: “As global power and

utility companies continue to operate in a f uid

market, transaction opportunities will naturally

follow. Whether the aim is to rebalance the

mix of competitive and regulated businesses,

reduce debt, focus core operations, or free up

capital to invest in emerging markets, there

will be robust activity in 2013.”

See next month’s issue for detailed analysis

of the Ernst & Young report

Global wind power hits record 282 GW

A new peak in wind power generation was

recorded in 2012, with total installed capacity

reaching 282 GW.

Of the 45 GW of new wind turbines that

were activated in 2012, China and the US led

the way with 13 GW each, while Germany,

India and the UK were next with about 2 GW

apiece, according to the Global Wind Energy

Council. The UK now ranks sixth in the world for

installed wind power, with 8.5 GW. In Europe,

only Germany (31 GW) and Spain (23 GW)

have more. China leads the world with 77 GW

installed and the US is second with 60 GW.

Europe

Energiewende was not ‘thought through’ says Siemens boss A senior boss at German power engineeing

giant Siemens has conceded that his home

country’s Energiewende – or energy transition

– from nuclear to renewables had been a

“disaster” and was “not thought through”.

But Lothar Balling, executive vice-president

of gas turbine solutions, said he remained

convinced that Germany would achieve its

target of delivering 80 per cent of its energy

from renewables by 2050.

Balling was speaking at POWER-

GEN Middle East, which recently took

place in Qatar, told the audience that

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News Update

the decision to ditch nuclear in favour of

renewables was both a “role model and

a disaster”.

“It was a very public decision and it was

not thought through,” he said. He explained

that since the decision in 2011 in the wake

of the Fukushima nuclear accident in Japan,

Germany had suffered several energy

challenges, many caused by the inability

of the grid to cope with power from wind

farms. He said in 2009 there were 285 forced

shutdowns of wind turbines – by the end of

2011 this had rocketed to more than 1000.

He said “f exible generation is the key at

the moment” and added there were also

signif cant challenges surrounding regulation

and transmission.

However he joked that the famous German

resilience to f nd solutions to problems would

result in the country getting the situation

“under control”.

His optimism was shared by Andreas Wiese,

executive director of German engineering and

consulting company Lahmeyer International,

who said he was “100 per cent” sure Germany

would hit its 2050 target.

More delays push back Olkiluoto 3 due date to 2016Progress reports from the consortium

developing the Olkiluoto 3 nuclear reactor in

Finland have shown that further delays are

expected in bringing the plant into operation.

Finnish utility Teollisuuden Voima (TVO)

said it is preparing for the possibility that the

plant may be further delayed until 2016. The

reactor was originally intended to commence

operations in 2009 but has experienced

several setbacks, with TVO stating last year

that it expected it to be delayed until 2014.

Based on progress reports from the

plant supplier, a consortium comprising

French nuclear engineering f rm Areva and

Germany’s Siemens, TVO said the production

start may be postponed until 2016.

The Finnish utility conf rmed it had asked

the supplier to update the overall schedule

after the last delay was announced, but

that it still had not received “an adequate

schedule update”.

Areva chief executive Luc Oursel has said

the reactor will ultimately cost $10.7bn.

Germany suffers drastic drop in gas generationGas-f red power generation fell by 27 per cent

in Germany last year according to the latest

f gures from the National Association of Energy

and Water (BDEW).

Many of the country’s energy providers

opted to switch to cheaper coal and rely on

renewables thanks to high gas prices in 2012.

UK faces EU f nes of £250,000 a day

The UK is facing potential f nes of up to

£250,000 ($393,000) a day, for failing to

implement European Union (EU) internal

market rules in Northern Ireland.

The rules in question are to do with

separating energy production and supply, as

well as simplifying third-party access to private

networks.

“Delays in implementation of the EU

Internal Energy Market rules have negative

effects on all players and are therefore not

acceptable,” said EU Energy Commissioner

Gunther Oettinger.

The European Commission has referred

the UK to the Court of Justice of the European

Union for failing to meet a March 2011

deadline to transpose the directives into

national law.

The directives do not yet apply in Northern

Ireland, but are in force throughout the rest of

the UK.

The UK’s Department of Energy and

Climate Change (DECC) said EU rules would

be implemented in Northern Ireland by April

of this year.

The Commission has recommended

that the UK be subject to a daily penalty of

£127,000 for each directive from the day of

the court’s judgment until each directive is

fully transposed.

The suggested penalty ref ects the

“duration and gravity” of the infringement. The

court, however, could order a different penalty.

In a statement to Power Engineering

International, DECC expressed its

disappointment with the punitive action being

taken at European level.

“The UK is very supportive of the single

energy market [in Europe}, which brings

benef ts to both consumers and business right

across the EU.

“It is regrettable that a f ne has been

proposed by the Commission at this stage

given the signif cant work completed in the

UK in relation to these directives with the

remainder due to be completed by April 2013.”The reactor pressure vessel at Olkiluoto.

Credit: Areva

1302PEI_8 8 2/15/13 9:21 AM


www.PowerEngineeringInt.com 9Power Engineering International February 2013

When looking at natural gas used in power plants, plants with

combined heat and power (CHP) and district heating plants it

reportedly fell by 14 per cent.

“This development in the use of gas-f red power plants illustrates

the critical economic situation in which operators of such power

plants f nd themselves,” said Hildegard Müller, chairman of the BDEW’s

Executive Board.

Coal-f red power plants, both hard coal and lignite-f red plants,

accounted for almost 44 per cent of the country’s gross electricity

demand, up around 1.5 per cent on 2011.

Renewable energy continued its growth in importance as an energy

source during 2012, with its combined share from wind, solar and

biomass rising to 21.9 per cent, compared to 20.3 per cent in 2011.

Middle East

Japan offers Saudi Arabia nuclear skills as kingdom targets 17 GW

Japanese Trade Minister Toshimitsu Motegi has offered his country’s

expertise in developing nuclear power in Saudi Arabia.

The kingdom is interested in building nuclear power stations in a bid

to free up more oil for exports, while Japan is seeking to secure more

oil from the Middle Eastern nation in the event of potential instability in

world supply.

A Saudi off cial told Motegi he was hopeful Japanese technology

could be used in the development of Saudi nuclear power plants, with

the kingdom planning to build up to 17 GW of nuclear power capacity

over the next two decades.

See feature: Sun sets on oil and gas dominance – p.28

Asia

EDF eyes gas deal in Cambodia France’s EDF is in negotiations with Cambodia to construct a gas-f red

power plant that would be fuelled by natural gas reserves located in

disputed waters off the country’s coast.

French Prime Minister Jean-Marc Ayrault met Cambodian Prime

Minister Hun Sen in Phnom Penh to discuss the deal and the company

is close to signing a memorandum of understanding to enter into

more detailed negotiations.

French ambassador-in-waiting, Serge Mostura, told reporters that

“the plant will enable the city of Phnom Penh to get the energy it

needs”. The Cambodian capital suffers regular blackouts during the

hottest months of the year because of a lack of supply.

The deal is complicated by the challenge of access to the natural

gas located in offshore blocks that are in a disputed territory with

neighbouring Thailand. French oil f rm Total has exploration rights in

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News Update

Solar plant to help bridge energy gap in Pakistan Korean Solar Energy Company has launched

a 1000 MW solar project in Balochistan,

Pakistan’s largest province. The plant is

expected to cover the province’s current

power shortfall of 900 MW.

“The Korean government has agreed to

invest in the power sector of Balochistan, and

has signed a memorandum of understanding

for building a 300 MW solar power plant with

the provincial government and to start work

on the remaining 700 MW of the project,” said

Additional Chief Secretary (Development)

Aslam Shakir Baloch. He added that the

province was moving ahead on the $9.1m

Solar Energy Home Project, in which about 300

villages will receive electricity.

Singapore set for $808m gas boost

Senoko Energy has inaugurated two gas-f red

power stations and says the plants will add

862 MW in capacity to Singapore’s grid.

In a move to cut down its carbon dioxide

emissions, the Singaporean power producer

has converted three 250 MW oil-f red plants

into two high-eff ciency natrual gas-f red

combined cycle plants.

The power generator is reported to have

invested S$1 bn ($808m) in repowering the

three oil-f red plants.

The company plans to use liquef ed natural

gas (LNG) from Jurong Island receiving

terminal in Singapore. This LNG facility is

expected to begin operations in the second

quarter of 2013.

Africa

GDF to build ‘Africa’s largest’ wind park

European utility giant GDF Suez has conf rmed

it is to build and operate what it has dubbed

“Africa’s largest” wind farm, to be located in

the desert in the south of Morocco.

The Tarfaya wind park will have an output

capacity of 300 MW, promising a 40 per cent

boost to Morocco’s current total installed

wind capacity.

GDF Suez will invest around $122m in the

project, which is due to enter service at the

end of next year.

Nareva Holding, a major investor in energy

projects in Morocco, will match the investment

made by GDF Suez.

In addition, the project will also be part

f nanced through €360m ($484m) of debt

provided by a group of three Moroccan banks:

Attijariwafa Bank, Banque Centrale Populaire

and Banque Marocaine du Commerce

Exterieur.

According to GDF Suez, Morocco – where

the demand for electricity is growing on

average at 6 per cent annually – wants to

produce 42 per cent of its electricity from

renewable sources by 2020.

North America

US military set to quadruple renewable energy capacityUS military spending on renewable energy

will hit $1.8bn by 2025, boosting total

installed capacity four-fold, according to new

research.

A new report predicts that the military will

increase its renewables’ capacity from the

current 80 MW to more than 3200 MW in the

next 12 years.

This has the potential to make the US

Department of Defense “one of the most

important drivers of cleantech in the

United States”, according to analyst Dexter

Gauntlett of Pike Research, which compiled

the report.

Gauntlett added that the $1.8bn

spend would “transform the production,

consumption, and transport of fuel and

energy within the military”.

The US Army, Navy, and Air Force have

each set ambitious targets of 1 GW of installed

renewable energy capacity by 2025, and Pike

calculates that because these initiatives “have

gained considerable momentum, many of

the targets will be achieved”.

The report states that because of the

US Department of Defense’s use of power

purchase agreements and enhanced use

leases, some military installations should be

able to pay the same amount – or even less

– for renewable electricity as they currently do

for retail power from the grid.

According to the report, the US

Department of Defense currently spends

in the region of $20 bn per year on

energy and uses 3.8 billion kWh of electricity.

Latin America

Alstom snatches $1.35bn Brazilian wind deal from GERenova Energia has awarded Alstom a

contract to provide more than $1.35bn of

turbines in what is believed to be South

America’s largest ever wind order.

Alstom won the contract ahead of the

Brazil-based developer’s current supplier

General Electric (GE).

The project involves the installation of

440 onshore turbines with 1200 MW of

capacity, starting in 2015.

According to Renova Energia chief

f nancial off cer Pedro Pileggi: “The deal put on

the table by Alstom was better. Price is always

important. By providing manufacturers with

long-term planning capabilities they’re able to

reduce costs.”

Demand for wind turbines in Brazil is

expected to come close to tripling in 2013 to

2024 MW from 732 MW in 2012, according to

data compiled by Bloomberg.

“Two years ago, virtually all of our onshore

wind turbine sales were in Europe,” Jerome

Pecresse, president of Alstom’s renewable

power unit told the news agency. “Now, more

than half are in Latin America.”

Visit www.PowerEngineeringInt.comfor more informationi

1302PEI_10 10 2/15/13 9:21 AM



What PEi readers are talking about online

What is the enduring appeal of coal power?

Agree? Disagree? Join the debate at

the Power Engineering International

group at www.linkedin.com

Coal is a cheap source of power, especially when you

have plenty of low-cost labour, minimal environmental

regulations or health and safety regulations, and can

use the environment as a dump for pollution at no cost.

It is only when you factor these issues into the overall

energy discussion that you see it is not really cheap at all.

However, since western nations built their economies

with cheap labour and coal, it is not fair of us to deny

developing nations the same opportunity, but it is

important that we impress upon them the problems

associated with coal and do everything we can to

promote renewable energy in these countries.

Steven Law, renewable engineer ,

Ontario Ministry of Environment

Well, gas is just not prof table across large parts of Europe

now so coal burning is quietly increasing to record levels

again. E.ON in Germany is now going to close a gas

plant that uses F-class turbines (Irsching 5), which shows

how bad things are getting. Also, there is a feeling that

complaints against coal are becoming more muted and

less fashionable, as nobody wants to be seen as spending

money unnecessarily during “times of austerity”.

Harald Thaler, industry director,

Frost & Sullivan

Coal may not be fashionable, but you don’t have to

spend billions of dollars bribing utilities to use such

technology with taxpayers money to operate them. It

is appears there is socialism for the power companies

and capitalism for the consumer. It is time there is proper

regulation to ensure that there is a proper free market

in the energy market. An unlikely prospect given current

government prospects.

Nicholas Newman,

energy journalist



1302PEI_11 11 2/15/13 9:21 AM

http://www.linkedin.com



http://www.wartsila.com/en/power-plants/power-generation/dual-fuel-power-plants



Russian electricity sector



Russia’s reform of its conventional

electricity market is widely

recognised as one of the most

ambitious reform processes ever

undertaken by any country.

The outcome of this process

will not only have a substantial impact on the

energy sector but also on Russia’s longer‐term

economic performance. According to the

International Energy Agency, “it will help to

determine the nature and pace of investment

and modernisation of the sector and will help

to shape incentives for eff cient, f exible and

innovative operation and end use”.

The reform landmarks that have been

achieved so far are impressive. They include

the unbundling and signif cant privatisation

of generation infrastructure; the introduction

of an investment mechanism; progress toward

more cost ref ective pricing; and creation and

strengthening of key market and regulatory

institutions. However, the full outcome remains

uncertain at the moment, and many believe

that the reform process is in a critical phase.

Based on interviews conducted by Focus

Reports on our behalf, we get the insider’s

view of the Russian electricity sector from four

major stakeholders – government, regulatory

and state-owned entities.

Ivan Grachev, Chairman,

State Duma – Energy Committee

The State Duma – Energy Committee plays

an important role in shaping the legislation

of the Russian power sector. From a legislative

point of view, what are some of the key laws

that still require further changes in order to

guarantee better progress in the sector?

“In my view, the reforms of the power

sector in Russia have not been carried out

properly. The foundations of these reforms

were built on the fact that modernisation

would only become possible through market

mechanisms. However, there is a strong

The reform process of the conventional electricity sector in Russia is nothing if not ambitious, and undoubtedly there have been signif cant gains. However, many believe it is entering a crucial period. We get the insider view of the industry, including the key reform issues, as well as its nuclear and hydropower expansion plans in Russia and beyond its borders.

Russia’s power sector: An inside view

The f rst reactor of the two-unit Novovoronezh II NPP is slated for start-up in 2014

Credit: Rosatom

1302PEI_12 12 2/15/13 9:21 AM



1302PEI_13 13 2/15/13 9:21 AM



http://www.hilliardcorp.com




disparity between the money needed for

modernisation and the revenues that can be

raised from the end-user side. As a result, the

power system continues to degrade and its

equipment depreciate.

“The market-based price formation

system does not bring a fair price and does

not correspond to the capacity we have in

place. We need a change in the legislation of

our sector, and thermal energy in particular.

We need federal investment programmes

specif c to our sector. Moreover, we require

better regulations around energy eff ciency.

All in all, drastic changes are required.”

The State Duma’s Energy Committee has

had many conversations with the Federal

Tariff Service and the Minister of Energy to

discuss the issues regarding electricity tariffs.

Where do these discussions currently stand

and what do you propose?

“Looking back at the resources needed

to modernise the system, there are different

estimates. Yet, even if we divide the smallest

estimates by the population and, for example,

a time frame of ten years, we need to

understand these targets are not achievable.

“We have to def ne which of these

investments, such as infrastructure or

power stations, will be handled by the

government, and which will be taken on by

private companies. Then we will be able to

understand which tariff programmes will be

suitable for the population.”

As private investors entered the market

during the reforms, they had to commit

to investing in new capacity up to 2018,

in line with the government scheme. How

satisf ed is the Russian government with the

investments that have been made on behalf

of the private sector?

“As far as I am aware, most of the private

investors did not satisfy these requirements.

This was already obvious at the beginning of

the reforms, because there was a clear gap

between the cost of these investments and

the capitalisation of these companies.

“The cost of producing a kW in Russia, for

example, lies around $3000. The capitalisation

per kW, however, lies around $300, which

explains why there cannot be that much

investment in this f eld. Although, there are

some exceptions, related to either the richer

regions in Russia or specif c energy-intensive

projects such as aluminum smelters.“

According to the World Bank, Russia has

the potential to halve its energy consumption,

indicating an immense opportunity for

better energy eff ciency. What steps have

already been taken on this front?

“Based on the fact that Russia uses twice

as much energy as it actually needs vis-à-

vis its GDP, I agree with the statement from

the World Bank. The main law on energy

eff ciency – Law 261– has been passed, but

unfortunately included two major errors.

“The f rst is an increase in bureaucracy.

Saying to a population that certain

equipment for energy eff ciency is

mandatory is one thing, but assuming they

will automatically invest remains an illusion. In

reality, if someone does not have the f nancial

resources to make these upgrades, even a

written law cannot enforce the investment.

“The second illusion that foreign experts

contend is that electricity price increases will

automatically result in energy eff ciency. It is a

fact that the price of electricity has increased

by a factor of 12 to the US dollar during the

reforms, while this had no impact whatsoever

on our level of energy eff ciency.

“Therefore, we must understand what role

the government will play in the modernisation

of the sector’s infrastructure and equipment.

From then onwards, we will have to build

effective legislative mechanisms that will

allow us to earn on energy eff ciency. “

Sergey Novikov, Head of

the Federal Tariff Service

In early 2011, the then president of the

Russian Federation Dmitry Medvedev (now

prime minister) told the BBC that if the rising

trend of electricity prices were to continue in

Russia, the country’s power could become

more expensive than in Europe or the United

States as early as 2014. How do you view this

statement today? Would you agree?

“Tariff increases are never a popular

matter to discuss and few stakeholders –

particularly consumers – support upward

price movements. Therefore, it is standard

practice for us to cooperate with regulatory

authorities in the US and Europe to collaborate

and compare both price indicators on the

market, as well as the rules of functioning.

“In the period 2010–11, we thought

that the regional regulatory authorities,

i.e. those functioning on the territories of

the constitutional entities of the Russian

Federation, which are part of the regional

administrations and formally independent

from the Federal Tariff Service, would be

much more careful in adopting investment

programmes at that time. However, rather

than their mistake, the discrepancy in

expectations was the result of the legislation

that was in force back then.

“As a result, we experienced a signif cant

increase electricity transmission tariffs,

which particularly affected the small and

medium-sized enterprises. They saw their

prices increasing abruptly, by 30–50 per

cent, and urged us to adjust the regulatory

framework. On the one hand, we clarif ed

the requirements with regards to investment

programmes and their returns, but on the

other, we also increased the public factor in

these decision-making processes.”

Russia’s ‘Energy Strategy 2030’ has set

ambitious targets with regards to investment

plans to modernise the electricity system in

the next two decades. How healthy is the

current balance between the revenues that

can be made on the market and the money

that will be needed for these investments?

“The most important aspect is to f nd

a balance between the interests of the

investors and the consumer of the electricity.

The regulatory framework in Europe, the US

and Russia has changed considerably. As a

result, the structure of the sector, as well as

the tasks of the regulatory authorities, have

become increasingly complex.

“Our tasks are linked to the different

interests in the sector. They need to support

a reliable functioning of the sector, its

development and take into account the

interests of the consumers. These interests

1302PEI_14 14 2/15/13 9:21 AM




are often very different and sometimes even

conf icting. Following the different structural

changes in the sector, consumers have now

become f rst-time participants in the process,

sometimes even as producers or investors.”

“The new task of f nding a balance

between these different interests implies that

we need to re-evaluate our regulatory tools

in the broader sense. We need to look at our

f nancial resources, which can both come

from the market and from the budget, to

develop the sector and f nd this balance.

Kirill Komarov, Deputy General

Director, Global Business

Development, Rosatom

Despite the continuing global economic

crisis and the Fukushima disaster in 2011,

Rosatom managed to nearly double the

number of overseas orders from 12 at the

start of 2011 to 21 at the end of the year. How

do you explain such strong performance in

this challenging external environment?

“The Fukushima disaster f rst of all did not

have a signif cant impact on nuclear energy

worldwide.

“At a meeting in September 2012 at the

International Atomic Energy Agency, the

consensus among all countries present was

the decrease in the construction of nuclear

power plants (NPPs) up to 2030 has only been

impacted by 10 per cent. We see that the only

countries showing intentions to stop building

NPPs were not very serious about their nuclear

plans prior to the incident in Japan. Germany,

for instance, has about 27 per cent share of

nuclear, yet it did not have plans to build new

reactors. The discussions – before and after

Fukushima– have always been about the

schedule to close down their NPPs.

“At the same time, those countries that

are the current drivers of global economic

growth, i.e. India, China, Russia and Turkey, as

well as Southeast Asia, the Middle East the

Latin America, have conf rmed plans to build

new NPPs. This is a current issue for Europe

too, where we see important projects in the

UK and Central European countries including

the Czech Republic, Slovakia and Hungary.

Also in France there is continuous interest.

“Another very important event has been

the fact that the US, for the f rst time in 20

years, has obtained a license to build a new

NPP. This implies that nuclear energy remains

relevant and is still an important part of the

global energy mix.

“There are several reasons why Rosatom

has been so successful in this period. First

of all, our NPPs are of the III+ Generation

and use the most modern technology. Even

before lthe 2011 incident in Japan, our NPPs

met all the post-Fukushima requirements.

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These, for example, include all the necessary active and passive

security elements.

“Another important factor is that we not only build NPPs abroad but

also domestically, something our competitors do not do. You cannot

go to another country and start building NPPs without showing its

reliability on your own territory..

“A third factor is that we can approach the market with truly

comprehensive proposals. Rosatom is a unique company by owning

all technology related to the nuclear sector, from uranium mining

to decommissioning. This is especially important for countries that

have only just started developing their nuclear sector because we

can help them in all the steps to build up their nuclear infrastructure.

This extends from the training of personnel and the developing of a

legal framework to answering fuel issues, structural challenges, and

so forth.

“A very important aspect in this regard is that we can provide

f nancing too. In today’s world, the biggest obstacle to building NPPs

is not Fukushima but the global crisis. These days it is very hard to f nd

money to f nance expensive long-term infrastructure projects. NPPs are

def nitely a prof table investment, although it is hard to understand this

if the return only comes after 20 years. Assuming that the life cycle of a

NPP is roughly 60 years, during its last 40 years these plants really work

as cash machines. At that point, the expense level to produce energy

becomes much lower than for gas and coal-f red stations. The issue,

however, is how to f nd the money for those f rst 20 years.

“This is why Rosatom has developed a detailed policy to allow its

clients to f nd help for f nancing solutions. We now have several tools to

address this issue, ranging from intergovernmental credit that Russia is

willing to give to countries that want to build NPPs with our designs, to

becoming investors ourselves. In this second instance, we do not only

provide the technology but also provide the actual funding to build

these NPPs. This is the so-called ‘build-own-operate’ (BOO) model,

which we have now deployed in Turkey [for the Akkuyu NPP].”

Evgeny Dod, Chairman of the Board, RusHydro

You took over the leadership of RusHydro together with a number of

top managers from INTER RAO UES at the end of 2009. Have these f rst

three years been an opportunity for RusHydro to make a new start?

“After three years, we can certainly draw a number of conclusions.

Our main task in November 2009 was to deal with the consequences

of the Sayano-Shushenskaya hydropower plant incident, a task

that has been carried out successfully. We have set a fast pace of

reconstruction and renovation of the plant and it will be accomplished

in 2014. The number of new projects is also unprecedented: 4000 MW

of new capacity is expected to be commissioned in 2012, and an

additional 10,000 MW by 2015. These are unique volumes for the hydro

sector in Russia, as well as in the [former] Soviet Union.

“We are also carrying out a programme of modernisation of our

existing plants. We are planning to invest in the region of $10 billion

with expected dates of completion within the next ten to 15 years.

“Considering that only 20 per cent of Russia’s hydro resources have

been developed to date, the potential for the future is signif cant. HPPs

can be considered as a stimulus for growth of regional industrial

clusters. For example, we are at the commissioning stage on the

Boguchanskaya HPP, which has an installed capacity of 3000 MW. [It is

scheduled to be fully operational this year].

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To investors you have announced great

potential for the Far East of Russia. Can you

elaborate on your expansion strategy there?

“RusHydro’s expansion strategy is mainly

focused on Russia. When the government

decided to provide us with the assets of

RAO UES of Far East, representing around

9000 MW of installed capacity and several

networks in that region. We are working on the

synchronisation of our investment programmes

with the construction of a comprehensive

infrastructure in Siberia and the Far East.

“While our priorities clearly focus on Russia,

we do have international projects too. Today,

we own the 561 MW cascade HPP in Armenia

and also have a cascade project lined up

in Naryn, Kyrgyzstan. Our institutes are also

working on projects in India, Vietnam and

Africa. We also believe in signif cant potential

for tidal energy in Chile and Argentina.”

Traditionally Russia is more associated

with oil and gas resources rather than

hydropower. How diff cult is it for Rushydro to

sell the idea of clean energy abroad?

“Russia is a unique country and we

are fortunate to have large reserves of

hydrocarbons. As a nation, we are certainly

focused on using oil and gas as energy

sources because these are cheaper to use

and consumers are still unwilling to pay for

more expensive energy from wind, solar and

biofuels. simply for the sake of the environment.

“As a result, the returns for companies

operating in such sectors have been less

attractive. The Russian government, however,

has now put programmes in place to

increase the share of renewables to 4 per

cent. As a company operating in the area

of renewables, we [also] try to effectively

push these initiatives. “This not only includes

hydropower, but also geothermal and solar

power. While this is not easy, Russia is also not

an island. The growing global trend [towards

renewable energy] will soon arrive in Russia.”

In partnership with Focus Reports, we

will be publishing a two-part report on

the Russian electricity sector this year. For

more informaiton on Focus Reports, visit

www.focusreports.net.

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Last year’s Energy Bill will be seen as

a f rm endorsement of new nuclear

projects by both current and potential

investors in the UK nuclear programme.

This Bill will entice the international

investment and expertise needed for future

energy security and help to kick-start Britain’s

much-needed nuclear revival.

The UK government has solid reasons

to welcome foreign investment in nuclear

power projects, in addition to the increasing

need for reliable, carbon-free energy security.

Successful nuclear projects require strong

partnerships, with commitment, mobilisation

of industries and risk mitigation on both sides.

Tangible government commitment and

support is fundamental to the enticement

of invaluable international investment,

experience and partnerships in the UK.

Last year’s £700 million ($1 billion)

purchase by Hitachi of the Horizon Project is a

positive development and a signif cant vote

of conf dence in the future of the UK nuclear

programme. The government is benef tting

from nurturing relationships with a number of

Asian countries, including Japan.

Traditionally, nuclear reactor vendors

have been reluctant to make large equity

investments in new nuclear projects and,

while this is changing for many reasons, the

action by Hitachi of purchasing Horizon is a

signif cant milestone. Given the remaining

uncertainties over the reform of the UK

electricity market, investment in its nuclear

programme still represents a ‘leap of faith’ by

any investor. The British government should

illustrate to Hitachi and other prospective

investors that they will f nd a willing and

supportive partner that is fully committed

to, and appreciates the signif cance of,

investments in the UK’s energy future.

To support the development and

construction of the new reactors, Hitachi

will most likely seek further investors and

partners. Such partners will closely examine

the actions of the British government, as well

as the general investment climate, prior to

making their f nal decision to invest.

A new nuclear programme goes beyond

the building of electricity-producing units.

With those units must come a whole new

industry, with a multi-generational, society-

wide commitment that provides long-term

benef ts in the form of energy, economic and

national security. Hitachi’s involvement not

only represents a commitment to the UK’s

nuclear programme, but also an investment

in the country’s economy and society, and an

opportunity to develop the jobs and growth

the government has been seeking. Indeed,

the partnerships Hitachi could make with the

UK nuclear supply chain may be exportable

to other European projects.

Those unconvinced by the f nancial

viability of the UK new nuclear programme

should note that while the development

of new nuclear projects can be complex,

lengthy and costly, with proper planning and

co-operation from government, industry, local

communities and f nancial institutions, the

f nancial risk during the development phase

can be greatly minimised.

Attracting foreign investment into the UK’s newly revived nuclear power sector is essential to the success of the government’s ambitious plans, believes George Borovas, head of the International Nuclear Projects team at law f rm, Pillsbury.

Foreign cash should not be feared

Opinion: Investing in nuclear

1302PEI_18 18 2/15/13 9:21 AM


Nuclear energy, by providing reliable and afordable electricity, helps

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The UK has all the fundamentals for a

robust nuclear programme. Unlike some

other countries embarking on nuclear

new build, it has an existing and successful

nuclear programme, an independent and

sophisticated regulator, a strong industry that

can be mobilised to support new projects, an

independent and fair judiciary (important

for foreign investors) and broad public and

political support. However, the UK does not

have recent construction experience.

The international nuclear industry learns

valuable lessons from each and every

new build. Recent projects around the

world demonstrate the importance of the

utilisation of experienced human resources

who can capitalise on construction and

operational lessons learned. Asian countries

have signif cant recent nuclear construction

experience. In addition, they have the benef t

of liquidity and easier access to capital.

Critics wary of foreign inf uence should

appreciate that nuclear energy is a global

business. The attraction of foreign investment

is a wise, long-term move by the British

government. Tangible commitment to new

partnerships will be vital to secure the UK’s

affordable electricity supply in the future.

From an international perspective

global interest in nuclear power is causing

governments, sponsors and lenders to look

beyond the ways in which nuclear has

traditionally been f nanced. Nuclear power

has many long-term advantages compared

to fossil fuels, including: signif cantly lower

external costs, such as damage to health

and the environment; cost competitiveness;

and stable baseload generation of electricity

over a long period of time. But getting private

investment involved in the construction of

nuclear power plants has become crucial to

the success of global nuclear development.

There are various emerging nuclear

f nancing structures and each is brief y

described below.

Pure equity investment

Reactor vendors and other nuclear industry

companies team up with plant owners to

create project companies that will ultimately

own the assets and f nance them with equity

contributions. These partnerships provide the

anchor capital that will allow other private

investors to make relatively small investments

by buying shares in these project companies.

Finnish Model

Partnership with a consumer consortium is

a model adopted for the Olkiluoto plants in

Finland (referred to as the ‘Finnish Model’).

A number of major industrial electricity

consumers invested in the plant through a

joint venture by Teollisuuden Voima Oy (TVO).

Each equity investor contributes a proportion

of the costs of building and operating the

plant in return for electricity supplies that the

shareholder can use itself or resell.

This model is suitable in countries where

there is suff cient concentration of energy

intensive industries, but is unlikely in countries

where power must be sold to the grid at a low

price, or where the grid must deliver the power

to all takers at the same cost. Participation

in such a partnership could potentially be

open to market players other than industrial

electricity consumers.

Utilities that have surplus capital and are

interested in market expansion in the nuclear

industry, either domestic or international,

will be well-received in countries where

investment is a major impediment to the

construction of new nuclear power plants.

Supply tied to equity investment

Nuclear utilities and electricity-intensive

industrial consumers form long-term industrial

and commercial partnerships on the basis of

sharing risks associated with the performance,

scheduling and development of the utilities’

nuclear capacity.

Both utilities and industrial consumers can

benef t from this type of partnership, which

contributes to furthering utilities’ investment

plans in new nuclear power plants and

provides secured sourcing of electricity for

participating industrial customers for as long

as the arrangement lasts.

Asset pooling

For equity investors other than industry energy

players, particularly f nancial sponsors, an

alternative approach could be asset pooling,

where a group of investors prepared to invest in

nuclear create a joint fund and then invest in

a range of nuclear portfolios. This could be an

option for various institutional investors such as

pension funds or insurance companies that

are typically seeking investments with long-

term, stable and predictable returns

The nuclear industry learns “valuable lessons from every project” says Borovas

Credit: WANO

Waste: A vital consideration

Credit: Sellaf eld

1302PEI_20 20 2/15/13 9:21 AM




Debt f nancing

While plant owners and project sponsors

prefer debt, commercial lenders expect

a high equity component to reduce their

own exposure. Insofar as debt f nancing is

available from commercial lenders, these

loans have been secured against the assets

of the sponsoring utilities and not against the

nuclear project itself. The availability and cost

of debt f nancing depends on the strength of

the balance sheet of the sponsoring utilities.

During the construction phase of a new

plant, banks are most likely to favour this

corporate f nancing approach backed by

the balance sheet of one or a consortium of

large, virtually integrated utilities with expertise

in nuclear construction and operation, strong

existing assets and a large consumer base.

Debt f nancing introduced at different

phases of a project could take a different form.

While balance sheet f nancing is generally

required by banks to provide f nancing for the

construction phase, non-recourse f nancing

is likely to be considered by banks for the

operational phase.

Phased f nancing

Nuclear projects comprise different and

distinct phases (development, construction,

operation and decommissioning), which may

or may not be attractive or suitable to various

types of investment groups according to the

risk prof le they carry.

While during the lowest-risk operational

phase, equity holders, funds and long-

term debt holders are potential investors,

the development, construction and

decommissioning phases present higher risks

that may only be suitable to certain investors.

With phased f nancing, the cost of capital for

each phase only ref ects the risk of that phase

and each phase may present a different capital

structure. For example, government funding

and equity investment may be introduced

to f nance the initial construction phase. As

the project proceeds and risks diminish over

the course of construction, the cost of capital

also diminishes. When the project moves

from the construction to the operation phase,

government support and equity shareholders

can be replaced with non-recourse f nancing.

In addition – for multiple units – the revenue

stream from operating units can be used to

f nance new construction.

Combining the cash f ow of multiple unit

construction can also benef t from economies

of scale by sharing plant facility resources,

saving temporary construction expenses and

optimising project management. Collectively

these serve to signif cantly reduce the overall

construction price of multiple units.

Irrespective of the f nancing model or

investment forms, private investors and

lenders will always carefully examine the

political and licensing risks, technology

choices, as well as project management,

supply chain and construction risks before

investing in a new nuclear project.

George Borovas is a partner and head

of International Nuclear Projects at law

f rm Pillsbury For more information visit

www.pillsburylaw.com/nuclear-energy.

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Driven by the demands of

today’s deregulated markets

and the inf ux of intermittent

renewable generation into

the grid, combined-cycle

power plants increasingly

have to respond to large load f uctuations in

a short time.

To meet the challenges associated with

the various modes of operation, the heat

recovery steam generator (HRSG) within a

combined-cycle plant must be capable of

frequent starts, rapid load transients and

prolonged periods of operation at low loads

for spinning reserve.

At the same time, HRSGs have become

more complex with the rapid development

of gas turbine technology. As HRSG pressures

and temperatures have increased, units have

become larger and new designs have been

introduced to accommodate the changing

steam parameters.

Although many of these HRSGs are still

relatively new, it is important to manage the

condition of this asset from the outset in order

to maintain continued safe operation and

maximise operating lifetime.

Pro-active analysis and monitoring of

assets can provide valuable insight into

weak links or constraints in the design that

can limit response rates or hamper the ability

to continuously operate according to a

particular operation prof le.

The information provided by such analysis

and monitoring can be used to establish limits

for plant operation and assess the f nancial

impact. If the impacts are severe, then options

to modify the design can be explored in a

cost-benef t analysis. This approach allows

a balance to be struck between risk to the

reliability and availability of the HRSG, and

the potential f nancial returns from having a

more f exible plant.

Asset management

Asset management was introduced to

determine the optimum and most eff cient

use of a plant’s assets. Essentially, owners and

HRSG cycling and lifecycle management

A carefully managed cycle

The growing trend of operating combined-cycle plants in varying modes places stresses on the HRSG

Heat recovery steam generators are increasingly operating in cycling mode according to market demands. This requires a holistic, top-down and integrated management of assets to maximise the overall prof tability of a combined-cycle plant, writes Alstom’s Pascal Decoussemaeker

1302PEI_22 22 2/15/13 9:21 AM


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operators have shifted their focus from simple

maintenance and cost reduction to the

optimisation of overall plant competitiveness.

Items such as operating strategy and production

losses are now all part of the equation.

For effective asset management it is

important to f nd the optimum compromise

between risk taking and risk mitigation. This is

only possible if there is suff cient knowledge of

the condition of the HSRG’s parts.

The planning of maintenance and

inspection works should also ref ect the

criticality of the equipment. It should aim to

optimise the allocation of scarce resources –

such as people, specialised equipment and

spare parts – to maintain the lifecycle value

of the asset and not compromise production

or EHS (environmental protection, health

management and safety) commitments.

Acquiring the correct knowledge of

the asset’s condition requires a good

understanding of the most critical areas and

to implement a plan to monitor the asset’s

condition so it is maintained in accordance

with the initial design goal. This is possible with

the right combination of off-line inspections

and on-line monitoring.

Asset degradation

A good understanding of a plant’s history

and future operation prof le are important

to make an analysis of the main drivers of

asset condition degradation. The thermal

and mechanical f exibility of a HRSG is heavily

dependent on the fundamental layout and

detailed design of its components.

Creep will be a degradation driver for

components that are exposed for long

periods to high temperatures, such as

superheater and reheater tubes, outlet

headers, manifolds and piping that typically

operate at temperatures above 500 ºC.

In situations where plants are increasingly

cycled, however, fatigue damage of certain

pressure parts and structural parts, such as

hot casings, can occur. Fatigue damage

usually results from thermal stresses due

to temperature differences within, or

between, parts. For example, thick-walled

components, such as drums or superheat

outlet headers, can develop signif cant

through-wall temperature gradients during

startup. Large temperature differences can

also occur at junctions between thick-

and thin-walled parts, such as tube-to-

header connections.

Through-wall temperature gradients

in thick-walled components can cause

fatigue cracking on the internal (water/

steam heated) surface, particularly around

penetrations where so-called ‘star-burst’

cracking – radial cracks emanating from

the edge of the hole – is common. Detection

of this type of damage requires, as a

minimum, internal (borescopic) inspection, in

combination with ultrasonic inspection.

Temperature differences between parts,

such as tube-to-header connections, can

result in cracking from either the internal or

external surface, depending on the nature

of the transient temperature history. External

surface cracks generally form at the toe of the

weld in the thinner wall of the components

that are joined, such as the tube of a tube-to

header connection. Internal cracks are less

common, but can occur at the root of full-

penetration tube-to-header welds.

These fatigue cracks that are the result of

cycling are generally sharp and straight. The

cracks may be oxide-f lled – held open or shut

by residual stresses – so careful inspection is

often required to detect them. Dye penetrant

or magnetic particle testing is typically used

to f nd these cracks. Advanced knowledge of

where to employ these techniques based on

an understanding of operating history and

damage mechanism greatly facilitates their

application to the appropriate locations.

Cycling-related failures

Other cycling-related failure modes can be

triggered by poor operational practices,

inappropriate control logic or defective valves.

A common case is damage to

components downstream of desuperheaters

caused by improper spray control logic. High

steam temperatures at very low steam f ows

during start up and shut down may trigger

desuperheater spray while there is insuff cient

steam f ow to entrain the spray f ow. This results

in water pooling in the bottom of pipes and

large top-to-bottom temperature differences,

which cause the pipe to bow and generate

potentially damaging local stresses in the

adjacent components. Leaking spray valves

can also cause the same problem.

Low load operation is becoming increasingly

popular as a way of avoiding constant start

up and shut downs of the gas turbine. This

usually results in higher gas turbine exhaust

temperatures and lower exhaust gas f ows,

which change the balance of heat pick-up in

the HRSG, often resulting in a bias toward higher

heat pick-up in the f nishing superheater.

This, in turn, requires higher amounts of

desuperheater spray to maintain acceptable

steam temperatures into the steam

turbine. The higher amounts of spray f ow

combined with reduced steam f ow results

in longer distances required downstream

of the desuperheater for complete spray

evaporation. This can result in spray

impingement on downstream components

generating high thermal stresses.

To mitigate these effects it is important

to f rst understand the various operating

scenarios and spraywater requirements.

There must also be a balance between local

metal temperatures – higher temperatures

might be permissible at lower operating

pressures – and spray capacity. In certain

circumstances, adjustments to heat pick-up

or desuperheater or piping design may be

needed to optimise operation over the full

range of operating scenarios.

The reduced steam f ows at low load

also mean reduced water velocities in

economisers. If velocities are suff ciently low,

buoyancy forces can cause reverse f ow in

some tubes of down-f ow economiser banks.

This generates tube-to-tube temperature

differences, resulting in thermal stress.

In many cases the issues mentioned

cannot be detected or diagnosed using the

standard plant control (DCS) instrumentation.

Invariably, additional local thermocouples, to

directly detect overspray for example, and

heat balance calculations are needed.

The examples outlined occur frequently

in practice and have been known to cause

damage affecting the functionality of

components in a relatively short period of

time. This highlights the need to continuously

review operating scenarios and practices in

relation to the original design goal and past

operation. Changes in modes of operation

should be reviewed to establish their impact

on the asset to ensure future reliability.

Based on this assessment, it is important

to develop an effective condition monitoring

system to get an early warning of potential

issues. This can be achieved by combining

on-line monitoring and off-line inspections.

On-line monitoring

Inspection and monitoring quantify the

progress of the degradation and provide

assurance that the asset integrity is maintained

1302PEI_24 24 2/15/13 9:22 AM


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in accordance with the design. There are

two different types of monitoring during

operation: monitoring the symptoms of a

certain problem and monitoring key process

parameters that trigger the degradation.

For HRSGs, monitoring the symptoms is

limited to visual and other non-destructive

inspections during the operation of the plant.

This can be used to identify failure modes that

lead to, for example, steam leaks, exhaust gas

leaks, external corrosion and internal wall loss.

Key process parameters are monitored

using a HRSG life-monitoring tool to check

elements that contribute to important failure

modes. This tool allows operators to monitor

the accumulation of creep and fatigue

damage for critical pressure parts.

Key temperature, pressure and steam f ows

from the plant instrumentation are monitored

and calculations are made to determine

temperature prof les and stresses within

pressure parts. The variation of stress with time

is monitored by the system so cycles can be

counted to determine fatigue damage, and

operating time at a certain temperature can

be used to determine creep damage.

Such a system will provide reports and

displays to allow operators to monitor

damage over time. It also provides an

indication of conditions that need immediate

attention to avoid severe damage.

For such a tool to be effective, it is

important that the calculation algorithms

have all been validated against appropriate

benchmark cases and are compliant with

prevailing codes and standards. Material

data used by the system must be based on

published values. This can be assured if the

tool has been certif ed by an independent

agency, such as for example TUV.

Off-line inspections

Periodic off-line inspections are required to

review the asset condition for degradation

modes that cannot be inspected on line, or

to further investigate areas identif ed during

on-line monitoring. For HRSGs, this needs to be

planned alongside the gas turbine inspection

to optimise overall plant availability.

Priorities for inspection should be

established based on a combination of a

review of the degradation modes, as well

as the types of operation and the potential

effects on the HRSG components. This

invariably requires a review of the HRSG

design to understand high-stress locations.

Knowledge of the operational history is also

required, particularly for transient scenarios

and off-design conditions.

For large f eets, experience can also

provide valuable feedback. Standardised

designs facilitate inspection planning as

components requiring specif c inspection

procedures will be consistent unit to unit. It

should be noted, however, that HRSGs of the

same design that operate behind different

gas turbines may experience different issues

as the turbines generate different thermal

transients in the HRSGs.

To do the up-front review and properly

identify concerns requires a thorough

consideration of numerous failure modes

and degradation phenomena. This calls

for a systematic approach to catalogue

information and perform calculations

to screen components based on their

susceptibility to relevant failure mechanisms.

Software that supports this type of

review over the lifetime of the equipment

is very useful. Such a tool should allow the

cataloguing of unit information, such as

drawings and previous inspection results,

performing relevant calculations to assess

risk to components based on operating

conditions and past history. It should also

support the management of engineering

reviews and recommendations.

Internal inspections can also provide

insight to operational issues. Damage to some

internal components may be indicative of the

need to further evaluate other areas of the

HRSG. Damage to drum separators through

f ow accelerated corrosion, for example, may

be an indication that water chemistry is not

correct and that the corrosion is occurring

elsewhere in the evaporator section.

In addition to the functional components

carrying the steam and water and the

structural components that support the

HRSG, it is important to assess items such

as baff es and insulation. Damaged gas

baff es can allow gas bypassing, which can

reduce performance. This can also result in

localised high temperatures on downstream

components that could cause more severe

fatigue because of steaming and tube-to-

tube temperature differences in economisers.

Loss of insulation in wall and roof panels has

resulted in damage to casing and, in some

cases, structural steel.

No upfront screening calculations can

identify such local effects, which highlights

the need for a co-ordinated effort based on

both engineering review and competent

inspection. This allows plant operators to

move from a reactive mode to a pro-active

one, which pays off in the long run.

Holistic approach

Effective management of HRSG assets

to maximise the overall prof tability of a

combined-cycle plant requires a holistic

approach. The operational requirements

of the plant must be considered, based

on business needs, asset condition and

the expected drivers of asset degradation,

according to component design, as well

as past, current and anticipated future

operational conditions.

Once such a review has identif ed the

areas with the highest criticality, this analysis

must then be used to determine an effective

condition monitoring programme.

Pascal Decoussemaeker is product manager,

HRSG at Alstom. For more information, visit

www.alstompower.com


A holistic approach is key to the effective

management of HRSG assets

1302PEI_26 26 2/15/13 9:22 AM

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Middle East’s energy transition Middle East’s energy transition

The Middle East is not so much at

an energy crossroads but instead

preparing to drive down an as-yet

unbuilt power superhighway.

The region’s astronomical

electricity consumption is well

known, as is the fact that if left unaddressed,

it will impact the region’s vast reserves of oil

and gas, which are currently fuelling its power

plants. The problem is not that these supplies

for domestic use will run out – it is that there will

be less of them to export, and the economics

of that are stark: “In Saudi Arabia we burn oil

for $4 and sell it for $100,” said a speaker at

POWER-GEN Middle East this month.

A year ago, the talk at POWER-GEN Middle

East was of the region’s consumption crisis: this

year, much debate focused on… the region’s

consumption crisis.

“The biggest challenge is meeting

demand,” said Amer Alswaha, chairman of

the IPP unit at Saudi Electricity Company, who

added that electricity demand “is doubling

every ten years.”

Bander Allaf, senior business development

manager at ACWA Power in Saudi, added

that the kingdom’s electricity consumption is

2.7-times the world average – “the equivalent

of burning two million barrels of oil per day”.

In Saudi Arabia, 58 per cent of its installed capacity is gas turbine-based. By 2022 that will have fallen dramatically to 2 per cent, replaced by steam turbines and solar

The Middle East knows it has a consumption

conundrum, however it also knows where the

answer to it lies: renewables and nuclear.

What the region also has – for the time

being at least – is the time to formulate an

The Middle East knows it has a consumption crisis and also knows what it is going to do about it. Following this month’s POWER-GEN Middle East in Doha, Kelvin Ross examines how the region plans to wean itself off hydrocarbons and introduce renewables and nuclear.

Sun sets on oil and gas dominance

The heat is on: As the Middle East faces a

consumption crisis, solar is an obvious solution

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Middle East’s energy transition

action plan, and then the economic clout to

deliver it.

“The big challenge for this region is to

plan ahead,” said Qatar’s minister of Energy

and Industry, Dr. Mohammed bin Saleh

Al-Sada at the off cial opening ceremony of

POWER-GEN Middle East in Doha.

That planning is taking place across the

region, with each nation forming a blueprint

to meet rising demand while phasing-out

fossil fuels and phasing-in low-carbon

alternatives.

In Saudi Arabia for example, there is

19,170 MW of capacity under construction,

with another 41,322 MW at various stages

of preparation. Some 58 per cent of the

kingdom’s installed capacity is currently gas

turbine-based: by 2022 that will have fallen

dramatically to 2 per cent, replaced by steam

turbines and solar.

Solar produced in GCC countries will offer European countries the most competitive solution for their energy – better than building fossil fuel plants” Bander Allaf, Senior business development

manager, ACWA Power

Domestic solar industry

That the Middle East will look to solar power for

part of its energy solution is a given, however

it plans to harness photovoltaic (PV) potential

on the back of a home-grown industry. For

example, Qatar is already working on a pilot

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project that is expected to produce between

5–10 MW of solar power.

Saudi plans to unlock its massive solar

potential and has set a target of 41,000 MW by

2032. “We can add value tomorrow with solar,”

said ACWA’s Bander Allaf.

The appeal of solar is two-fold: f rstly, and

obviously, there is a lot of it in the Middle East,

and secondly, renewables suit the summer–

winter consumption swing in the region.

And if the power of solar in the Middle East

can be harnessed and stored in abundance,

the region is already looking to export some

of the resulting electricity to needy European

countries via projects such as Desertec, the

renewables project already up and running in

North Africa.

The scheme’s backers believe that two-

thirds of MENA countries can be powered by

the region’s abundant desert solar energy,

with enough electricity left over to meet 15 per

cent of European consumption.

“Solar produced in GCC countries will offer

European countries the most competitive

solution for their energy – better than building

fossil fuel plants,” said Allaf.

If – or when – Gulf countries do establish

their own solar industries, it is unlikely to be with

the help of feed-in-tariffs (FiTs), a European

model that appeared to have few admirers

at POWER-GEN Middle East. “The feed-in-

tariff structure can never sustain,” said Allaf.

He believes the impact that revising FiTs has

had on solar markets in the US, Europe and

Japan was a warning sign. “Revising a FiT can

have direct consequences, with too many

companies disappearing.”

Nuclear know-how

However, it is with nuclear that the wait-and-

Demand dilemma: The Middle East’s energy use was

a hot topic of debate at POWER-GEN Middle East


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see policy of many Middle East governments will really pay off. The

Bushehr plant in Iran remains the region’s only operational nuclear

facility, while the UAE launched a nuclear energy programme in 2009,

which is proceeding apace.

Indeed, the UAE is considered “the model for expediting the nuclear

new-build market in the Middle East” according to Rudiger Tscherning,

director of the Energy and Environmental Law Center in Qatar.

He said the Middle East currently has the benef t of watching the

successes – and more pointedly – the failures, of nuclear new build

across Europe.

He singled out Olkiluoto 3 in Finland, which was due to be online

in 2009 at a cost of $4 billion, but is currently mired in setbacks and

as of this month was set to be completed in 2016 with a f nal bill of

approaching $11 billion, but he could as easily picked EDF’s Flamanville

in France which is also dogged by delays.

The Middle East would make a mistake of gargantuan magnitude if it did not look to nuclear powerMike Waite, manager, International Business Development,

Westinghouse Electric Company

He also noted that issues which have hit the UK nuclear sector in

recent weeks – including British company Centrica pulling out of the

new- build market and plans for a deep geological waste dump in

England being rejected – highlighted the importance of long-term

planning and the effect that its absence can have on investors.

Meanwhile, Mike Waite of Westinghouse Electric Company believes

that the Middle East would be making a mistake of “gargantuan

magnitude” if it did not look to nuclear power as one of the main

solutions to its energy demand challenges.

He said almost every country in the Middle East and North Africa

has expressed some level of interest in nuclear energy, ranging from

1 GW proposals to 50 GW.

Speaking in a nuclear-focused conference session at POWER-GEN

Middle East, Waite added that despite the concerns following the

Fukushima disaster in 2011, “nuclear makes as much sense today” as it

did then. “Nuclear is several times safer than renewables, 100 times safer

than gas and 1000 times safer than oil,” he claimed.

One country going in the opposite nuclear direction to the Middle

East is Germany. Almost two years on from the start of its Energiewende

– or energy transition – from nuclear to renewables, Lothar Balling,

executive vice-president of gas turbine solutions at Siemens, was in

Doha to offer an update of where Germany was in shaping its new

energy landscape.

Was the Energiewende a role model or a disaster? “A bit of both,”

according to Balling. “It was a very public decision and it was not

thought through,” he said.

With that in mind, he was asked by Emad Ragaban, business

development consultant at Saudi Aramco, if he really believed that

Germany would hits its target of renewables providing 80 per cent of its

total capacity by 2050?

The answer was a resounding yes, but there is no chance of the

Middle East looking to Germany and deciding to shun nuclear. Instead

it will bide its time, see which reactors are delivered successfully and also,

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crucially, be ready to seize the opportunities thrown up by developments

in Asia’s nuclear market, which is advancing at breakneck speed.

Tough for contractors

If there is one certainty about the Middle East power sector at the

moment, it is that it is a buyers’ market.

The considerable challenges of developing power projects in the

region were highlighted at POWER-GEN Middle East by senior players

in the sector.

Ian French, vice-president of business development in the Lower Gulf

region for Siemens, said that “life is tough for contractors in the GCC”

because of the number of f rms competing for business.

He said as well as EPC giants such as Siemens and Alstom, there

were also contractors from the US, Turkey, Spain and Greece trying to

break into the market. “More and more people are chasing less and

less business,” he said, adding that the picture was equally bleak for

developers. “The good days have gone.”

The Gulf nation offering the most opportunities is Saudi – the “shining

star of IPPs” according to Hemmat Safwat of Greek f rm Consolidated

Contractors Company – while in the wider Middle East there are strong

opportunities in Iraq, but that was a country for “the brave developer”

said French.

Cherry-picking the best

The Middle East is sitting between the established European energy

market and the fast-developing power sector in Asia, and is poised

to cherry pick the best from both regions to establish its own security

of supply.

Sarah Fairhurst, a partner at Hong Kong’s Lantau Group, told

POWER-GEN Middle East, that “the Middle East can leapfrog Asia and

sustainably grow into the future”.

Yes, the Middle East has a consumption crisis, but the region will not

be forced into knee-jerk solutions. It is taking its time to pick a suite of

technologies that, with solar, play to its geographic advantages and

can offer home-grown industries, and with nuclear give it the options of

choosing the best-in-class from around the world.


One and only: Bushehr power plant in Iran remains the

Middle East’s sole nuclear facility – a situation sure to change

Credit: WANO


1302PEI_33 33 2/15/13 9:22 AM








NOx reduction with SNCR

In the eighties and nineties when Western

Europe’s large coal-f red boilers were

retrof tted with nitrogen oxides (NOx)

control systems, selective catalytic

reduction (SCR) process was considered

the best available technology (BAT).

But subsequently, when many Central

and Eastern European countries joined

the European Union and had to accept

its emission limits, interest in SNCR grew

because it offered advantages such as lower

investment costs.

Especially in recent years, the SNCR

process has been steadily improved for

small and medium-sized boilers like waste

incineration plants, for which it is widely

considered the BAT. But power plant owners

are now also investigating whether SNCR is

feasible for their large coal-f red boilers too, on

both performance and cost considerations.

SNCR and SCR are post-combustion NOx

control technologies and both work to reduce

NOx to nitrogen and water by using reagents

based on either ammonia or urea. The main

difference between the two systems is the

‘temperature window’, i.e. without a catalyst

the reaction takes place at 900–1050 °C,

whereas with the catalyst the range drops to

160–350 °C.

In the SNCR process, reagents in aqueous

solution (ammonia water, urea) or in gaseous

form (ammonia) are injected into hot f ue

gases. For an optimum NOx-reduction with

a minimum ammonia slip (NH3 slip) it is

necessary to evenly distribute and thoroughly

mix the reagent in the f ue gases within the


Already considered the best option for small to medium-sized boilers, selective non-catalytic reduction (SNCR) systems can now been demonstrated as an attractive alternative to selective catalytic reduction in large-scale coal-f red plants, writes Bernd von der Heide of Germany’s Mehldau & Steinfath Umwelttechnik.

The SNCR option for large coal boilers

SNCR could overtake SCR as the deNOx system of choice in large coal-f red power plants

1302PEI_34 34 2/15/13 9:22 AM




s

appropriate temperature window in which NOx-reduction is possible.

The optimum temperature range to achieve high NOx-reduction

combined with a minimum consumption of reagent and a low NH3

slip is rather narrow and depends to a great extent on the f ue gas

composition. For coal-f red boilers the optimum temperature lies

between about 960 °C and 1020 °C.

Above this temperature range ammonia is oxidized to an

increasing extent, i. e. NOx are formed, while at lower temperatures the

reaction rate is slowed down, causing an NH3 slip, which may result

in the formation of ammonia salts and lead to secondary problems.

However, because temperatures over the cross-section in the

furnace are rarely uniform and considerable imbalances are often

found, special measures need to be taken to identify the right positions

for the injectors to distribute the reagent properly into the f ue gas

under all operating conditions.

To determine whether the SNCR process would suit an existing

coal-f red boiler, it is recommended to perform simple tests with a

portable test installation. Such tests can provide valuable information,

not only on what efforts need to be made with regard to the design

and the equipment of a commercial SNCR plant, but also on the

performance that can be expected and guaranteed under varying

operating conditions.

Regardless of whether ammonia water or urea is to be used in the

subsequent commercial plant, tests are generally performed with urea

solution because it is easy to handle. In addition, from a performance

point of view, both reagents are comparable in most applications.

To-date tests have been conducted on several boilers with capacities

up to 225 MWe in Germany, the Czech Republic and Poland.

In one particular example, a German utility decided to go with the

SNCR process for a 200 MWe coal-f red boiler, after successful testing

and taking into consideration relevant aspects, such as the level of NOx

reduction, the cost-benef t ratio and overall plant availability,

Effective combustion chamber diagnosis

However, temperature measurements with suction pyrometers and

the readings from permanently installed thermocouples only permit

a rough estimate regarding the temperature prof les in the individual

potential injection levels during the respective boiler loads. Furthermore,

the temperature distribution and imbalances resulting from the boiler

load, the ignition behavior and the burner conf guration, for example,

may vary strongly.

Figure 1: Temperature prof les measured by agam ensure the SNCR plant

is optimally operated


1302PEI_35 35 2/15/13 9:22 AM



http://liqui-cel.com



To ensure that the reagent is always injected

in the upper range of the temperature window

under any operating condition, i.e. in the range

where NOx reduction is highest and NH3 slip is

lowest, acoustic gas temperature measurement

systems (agam) (Figure 1) should be installed.

Agam measures the real gas temperature

and determines prof les across the entire

combustion chamber cross-section.

The system consists of transmitter

and receiver units that have an identical

mechanical and electrical design mounted to

the walls of the combustion chamber and an

external control unit. During the measurement

the solenoid valve

in the compressed

air line on the

transmitter side is

opened, generating

acoustic signals. The

signals are recorded

simultaneously on

both the transmitter

and the receiver

sides. The digitalised

signals are then

used to measure the

transmission time.

Since the

distance is known,

the velocity of

sound can be

determined, which

is then converted

into a temperature,

i.e. the path

temperature. With

several combined

transmitter/receiver

units acting on one

level, multiple path

conf gurations can

be obtained to

calculate the two-

dimensional temperature distribution in one

level immediately.

A temperature prof le is divided into sections

and can be assigned to individual lances or

groups of lances to switch them to another

level depending on the f ue gas temperature

measured. This ensures the reagent gets to the

most effective locations for the reaction, even

with rapidly varying f ue gas temperatures, and

that the SNCR plant is always operated in the

optimum temperature range.

After the German utility decided in favour

of SNCR, a preliminary agam was installed to

obtain detailed information and help inform

the design of the commercial SNCR plant, in

particular its injection levels and the number

and positions of the injectors.

The temperature measurements were

performed at the end of the combustion

chamber (at 39 metres) with different

loads and conf gurations of pulverisers.

Four symmetric zone temperatures were

determined from the temperature matrix

and the surface average value was used to

calculate deviations for the zones. It showed

the average temperature at the end of

the combustion chamber varied between

750 °C at low load (45 MWe, burner level 1)

and 1155 °C at full load (185 MWe, with all

burners in operation).

The f nal engineering concept for the

SNCR plant for the the 200 MWe coal-f red

plant was based on the analyses of the

temperature measurements and the tests

with the SNCR demonstration plant

A simplif ed process f ow chart in Figure 2

shows the function and the scope of supply

of the commercial SNCR plant as designed,

installed and commissioned in the power

plant. Because of the signif cant temperature

differences between low load and full load, as

well as the extreme temperature imbalances,

f ve injection levels were installed from

26–51.8 metres. The injectors were arranged

so that the right and the left sides of the boiler

could be controlled independently, with

each injection lance individually activated

or deactivated.

The commercial SNCR plant entered

operation in March 2010. The guaranteed

NOx and NH3 clean gas values were attained

in most cases, with boiler loads ranging from

20–100 per cent.

The subsequent optimisation phase,

however, was time consuming because

at each of the f ve injection levels the

Figure 2: A f ow diagram of the commercial SNCR plant, featuring f ve injection levels and agam

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temperature prof le had to be measured

at various loads with suction pyrometers

to calculate the difference from the

temperatures measured with the agam at

the 39-metre level. This was necessary to

determine which lances should be operated

at various average temperatures in the zones

and at which temperatures the switching

should be effected at given loads.

SNCR demo in a 225 MWe plant

In a Polish power station with f ve 225 MW

coal-f red boilers, an SNCR demonstration was

carried out to validate that a NOx reduction

of at least 25 per cent can be achieved safely

at any boiler load between 40–100 per cent.

Temperature measurements, which

could only be performed at two openings at

47.4 metres, found imbalances of more than

120 K between the measuring points. It was

not possible to make further measurements

because there were no other openings large

enough to accommodate a pyrometer

lance. During the tests, the urea was injected

through openings at levels 37.9 metres and

47.4 metres from the front wall, as well as from

the side walls at 47.4 metres.

Despite these challenges the results were

very positive, with NOx reduction far above

the 25 per cent target at all loads and at

almost 60 per cent with 75 per cent load.

In a commercial plant, a third level

for injecting the reagent would improve

performance, especially regarding eff ciency

and NH3 slip. To minimise this, a small catalyst

could be introduced at the end of the boiler.

But with an agam like the one installed in the

German boiler the reagent could be injected

more precisely at the optimum temperatures.

As a result the slip could be maintained low

enough to keep the ammonia concentration

in the f y ash below an acceptable limit so

that an additional catalyst slice would not

be needed.

Overall plant availability is essentially

unaffected by SNCR systems. Components

critical for plant operation such as pumps

are provided with redundancy. Although, the

injection lances in contact with the f ue gas

must be regularly checked and serviced,

they can be checked during operation and

replaced relatively quickly if required.

The SNCR system in the German power

plant, for example, is equipped with an

automatic data acquisition system to facilitate

fault diagnosis and settings via remote data

connection. The higher investment costs of

such a system can be paid off within a short

period of time since the expense of costly visits

of service engineers can be avoided.

The TWiN-NOx process

Once the decision to use a SNCR system has

been made it is crucial to select the best

reagent. Urea offers advantages in availability,

logistics and cost. Yet process considerations

could make ammonia water the better option.

Coal-f red boilers essentially fall into

two design concepts. The main boiler

design features two f ue gas passes and a

contraction nose at the end of the furnace.

The alternative is the tower boiler.

In the two-pass boiler at full load the

optimum temperature is mostly in the level of or


1302PEI_37 37 2/15/13 9:22 AM



http://www.harcolabs.com




within the super heaters. The use of ammonia

water as a reagent is often limited by the

temperatures, which are mostly too high, so that

a lot of the ammonia will burn to NOx before

it can reach the area with lower temperatures

within the heat exchangers. Therefore, the

overall NOx-reduction is not optimised.

With urea solution, the situation is easier

to handle because by the time the water

droplet surrounding the urea particle has

evaporated, the NH2 of the decomposed urea

will have reached the cooler area. However,

there is serious concern that droplets

containing urea would impinge on the boiler

tubes causing corrosion and damage of the

tubes. Therefore, special attention has to be

paid to the positioning, maintenance and

operation of the injectors.

The situation with tower boilers is no

easier, although the reagent can be injected

in most applications from all four sides of

the boiler.Only the intermediate area lying

between the colder boiler walls and the

hot centre offers an optimum temperature

range for the reactions. Special measures

are needed to achieve suff cient distribution

of the reagent in the f ue gas. One alternative

is to inject the reagent in several levels

simultaneously with different penetration

depths and to use lances of different lengths.

But optimum distribution of the reagent is still

diff cult to achieve.

During the testing of the SNCR process

in the 200 MWe coal-f red boiler, in

Germany urea solution was used despite

the subsequent commercial plant utilising

ammonia water. However, the operating

results of the commercial plant did not meet

expectations, especially at full load.

Disappointingly results showed that

automatic control was no better than the

manually-controlled trial equipment. The

only signif cant difference is that ammonia

water is used in the commercial plant. It may

perform less well than urea because it reacts

too close to the boiler wall.

To investigate this, additional tests with

urea were performed in the commercial

plant. The results showed that immediately

after injection of urea, NOx reduction rose

and consumption of the reagent fell, but

concern remained over urea’s impact on the

boiler tubes.

Further tests showed that the low volatility

reagents (urea solution – NOxAMID) are

indeed released at the end of the droplet

trajectories while the high volatility reagents

(NH3) are released near the droplet source

close to the boiler walls.

Subsequent tests showed that by

changing the reagents according to

operating conditions the performance of

the SNCR could be improved considerably.

From there, it was a small step to mix the two

reagents and inject various mixtures into the

furnace to combine the best features of both.

A commercial plant has now been

built that can be operated alternately

or simultaneously with urea solution and

ammonia water (Figure 3). This process,

called TWiN-NOx, gives a more effective and

wider temperature and load range, higher

eff ciency, lower NH3 slip, less consumption of

reagent and minimum risk of corrosion.

The future for SNCR

SNCR has now been demonstrated to provide

results that are comparable with those for

catalytic NOx reduction but at a fraction of

the cost. Even in large combustion plants,

greater NOx reduction can now be achieved

through temperature-controlled adjustment

of individual lances. The temperature prof le

could be signif cantly improved and extreme

NOx peaks prevented if temperatures

measured by agam were used not only

for regulating the SCNR plant but also for

optimising the combustion process.

All feasible and commercially justif ed

technological measures such as optimising

combustion and f ue gas recirculation

should be taken. A small additional slice of

catalyst at the tail end of the boiler could

minimise the NH3 slip. The TWiN-NOx process

is expected to open up further potential for

improvement.

Over many years of continuous operation

at various combustion plants, SNCR has

proven to be reliable and economical for NOx

reduction. In the power plants highlighted

here expectations were always met and

generally exceeded.

From the process point of view, it is

almost irrelevant whether urea solution or

ammonia water is used as long as plants

are engineered, installed and operated

in an appropriate manner. In Germany,

Sweden and the Netherlands, SNCR has

been operating for several years in waste

incineration plants with designed NOx limits of

<100 mg/Nm³. These plants reliably comply with

guaranteed values in continuous operation.

Newer plants, equipped with agam and three

injection levels, achieve low NH3 slip, low NOx

clean gas values and high eff ciency.

Although SCR can offer slightly higher

NOx reduction levels, the cost-benef t ratio

is generally lower, particularly as NOx values

below 300 mg/Nm³ are now generally

obtained at large coal-f red boilers through

combustion modif cations alone.

Finally, promising test results have now

been recorded for oil-f red, as well as coal-

f red plants with capacities up to 225 MW.

In heavily coal dependent countries like

Poland and the Czech Republic, the SNCR

deNOx process for large power plants are

beginning to f nd favour.


Figure 3: A commercial plant utilising the TWiN-NOx SNCR process in now in operation

1302PEI_38 38 2/15/13 9:22 AM



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Micro-CHP in Europe

Although Elcore GmbH, a

German maker of fuel cell

micro-CHP units, only has a

few of its products in homes

in its domestic market, it

already has high hopes of

selling plenty on a fully commercial basis from

later this year before spreading its wings into

other European markets.

The Munich-based f rm’s optimism rests

largely on being among nine suppliers picked

in the €53 million ($71 million) ‘European-wide

Field Trials for Residential Fuel Cell micro-CHP’

project (Ene.f eld).

Under the initiative, European Union (EU)

utility companies, manufacturers, research

institutes and universities will collaborate on

f eld trials across 12 EU Member States of fuel

cell micro-CHP units ranging from 0.3 kWe to

5 kWe, and powered with natural gas and,

subsequently, hydrogen.

By September 2014, 960 units are due to be

installed, with each running as a demonstrator

project for three years, during which lifecycle

costs and barriers to commercialisation will

be assessed.

For fuel cell micro-CHP, the project has

come at a good time. Currently, no units are

being sold on a fully commercial basis in

Europe. Full launch targets have been pushed

back and investor conf dence is low.

“Many people that we speak to in the

industry feel that it’s now or never for the

technology,” says Scott Dwyer, micro-CHP

research manager at Delta-ee, analysts based

in Edinburgh, UK.

“But with things like Ene.f eld and other

national f eld trial projects – such as CALLUX

and NIP, both in Germany, and one in Denmark

– we think it’s justif able to expect a wave of

product launches in the next two to four years.”

A range of technologies is to be scrutinised

under Ene.f eld: high-temperature (HT) solid

oxide fuel cells (SOFC); low-temperature (LT)

SOFC; HT proton exchange membrane fuel

cells (PEMFC); and LT PEMFC.

The units will be integrated into various

European heating systems – both f oor

standing and wall hung – either in the home

or in separate installation cabinets.

The goals are to demonstrate market

potential and segmentation; gauge the

manufacturing and operating costs, and

the environmental benef ts of fuel cell micro-

CHP; develop product specif cations and

harmonised codes and standards; ready a

supply chain for commercial deployment

of fuel cell micro-CHP in the 12 participating

Member States; and provide evidence to

speed up policy support from governments

and broader adoption by new and existing

sales channels such as through utilities.

The European Commission’s Fuel Cells

and Hydrogen Joint Undertaking (FCH JU) is

committing nearly €26 million to Ene.f eld over

60 months from 1 September 2012, as one of

the Joint Technology Initiatives (JTIs) under the

EU’s outgoing 7th Framework Programme for

funding research and development.

The European Commission’s Directorate

General for Energy (DG Energy) expects

this spend to leverage at least the same

Micro-CHP in Europe

Mega trialopens Europeto micro-CHP

An ambitious initiative across 12 European nations, involving utilities, manufacturers and research institutions, aims to test the potential for fuel cell micro-CHP in the EU residential market, reports Robert Stokes

1302PEI_40 40 2/15/13 9:24 AM



Micro-CHP in Europe

commitment from participating industries,

half of whom are small and medium-sized

enterprises (SMEs), such as Elcore.

Insight into new markets

For Elcore, contributing to Ene.f eld is a no-

brainer, given the benef ts it believes it will

reap from installing about 135 trial units in

households in Germany and three other

countries yet to be decided, but possibly

including the Netherlands.

“Ene.f eld will give us exposure to

foreign markets so that we can learn what

customers there like and do not like,” says

Martin Eichelbrönner, Elcore’s sales and

marketing manager.

“It will also introduce us to different

certif cation regimes. This will be valuable to

us, though one of the ultimate challenges that

needs to be addressed is standardisation of

these throughout Europe,” he adds.

This neatly reinforces key points about

Ene.f eld. It will share the knowledge gained

from testing a range of technologies in

highly varied residential markets, climates

and types of houses throughout the EU. Take

Germany, for instance. Elcore already has

a few units operating in homes there and

plans to offer many more systems from late

2013, quite separately from its involvement in

Ene.f eld.

According to Eichelbrönner, these

commercial units will be offered at about

€9000 each, inclusive of value added tax.

Subsidies for micro-CHP units in Germany

currently only cover up to €500 per unit, but

Eichelbrönner says experience suggests that

German customers would f nd the €9000

price tag acceptable, especially set against a

claimed payback time of only seven or eight

years, as well as savings of up to 50 per cent

on their electricity bills.

Its approach is to offer units that ‘sweat’

for customers by working 24/7 to deliver

baseload electricity of 300 We and baseload

heating of 600 Wth. This value proposition has

already been validated in Germany but Ene.

f eld means that households in several other

countries will get to assess this approach for

themselves, said Eichelbrönner.

In the UK, €9000 (£7780) could look a bit

steep to consumers who tend to grumble

about having to spend even £1500 ($2300)

on a replacement hot water boiler. So

Ene.f eld aims to reveal the nuances of such

socio-economic barriers to the deployment of

fuel cell micro-CHP.

Ene.f eld f eld trials will allow the f ne tuning of fuel cell micro-CHP units

Credit: Siemens

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Micro-CHP in Europe

“In Japan for instance,” says Dwyer, “one of

the main routes to market for fuel cell micro-

CHP is through housing developers who build

a huge number of houses each year and

differentiate themselves, for example, by telling

buyers they can generate their own power by

having a fuel cell micro-CHP installed,”

But a larger proportion of people in Japan

build or buy new homes rather than buying

second-hand, which is more prevalent in

Europe. “In Germany, a lot of heating systems

tend to be sold by installers, who are generally

quite loyal to manufacturers,” says Dwyer. “In

the UK, France and the Netherlands there’s

a low market for boilers as people just tend

to buy them as a distress purchase and

begrudge the price.”

And the end customer is not really that

interested in the niceties of the technology

but in the up-front cost of the units and their

installation; the space that they take up; noise;

ease of operation; energy savings; reliability;

ongoing inspection, repair and maintenance

costs; parts availability; the service levels

provided by installers and utilities; and, if they

are sophisticated enough to take a long view,

the payback time.

“Innovative business models will be crucial

in Europe,” says Dwyer. “No-one knows which

one will be successful, but we reckon that as

soon as one takes off there’ll be quite a few

companies trying to follow that.”

Targeting lower demand

Yet Ene.f eld is a large and expensive EU

research project: €53 million is a huge sum

for the trials, as is the €26 million from the EU,

particularly when the private sector is already

conducting extensive fuel cell micro-CHP f eld

trials in Germany and Denmark.

Why invest so much? For one thing,

DG Energy hopes the substantial public

investment will catalyse the development

of ways to overcome obstacles to the

EU’s ambitious goal of cutting energy

consumption by 20 per cent.

Based on the most recent f gures available,

EU households consumed 307.3 million

tonnes of oil equivalent (Mtoe) of energy in

2010. Viewed another way, residential users

consume 27 per cent of EU energy. Reducing

this by a quarter would cut 6.75 per cent from

EU energy consumption, more than a third of

the targeted reduction.

Previous studies suggest this is achievable,

according to DG Energy. It believes that

policies adopted by the end of 2009 will

help cut consumption by about 8 per cent

by 2020. Some of the outstanding reduction

can be reached through further measures on

f nancing, more stringent implementation of

the Energy Performance of Buildings Directive

and the new Energy Eff ciency Directive, says a

spokesperson for DG Energy.

Across the EU, average energy

consumption per household was 1.5 toe in

2009 and annual residential consumption

for buildings was around 200 kWh per square

metre. But, unsurprisingly given Europe’s varied

climate and wealth, Member States showed

considerable differences.

The share of micro-CHP in general in

household heating and cooling currently

ranges from zero to a fraction of a percentage

depending on country, according to the

Commission’s FCH JU. But DG Energy sees

potential for all types of micro-CHP to yield

collective “signif cant primary energy

savings” in the residential and services sector

through replacing less eff cient heating and

cooling options.

The Commission’s estimate of micro-CHP

heaters’ market shares for space heating,

based on devices with energy class labelling

up to A+ are: 2010, 0.1 per cent; 2020, 1 per

cent; 2030, 4 per cent. There is no differentiation

between fuel cells and other types of micro-

CHP in these estimates, but the anticipated

trend is clear and fuel cell micro-CHP is of

particular interest because of the alignment

between its characteristics and residential

energy use trends.

“The electrical eff ciency of fuel cell micro-

CHP is higher than for a normal CHP,” says

Mirela Atanasiu, project manager at the FCH

JU. “And we are moving towards everything

being electrical, as it is in my own house. I do

not need a boiler, and a fuel cell micro-CHP

can provide more electricity and less heat.”

The current state of the art for fuel cell

micro-CHP is 30 per cent electrical eff ciency,

overall eff ciency of 70-85 per cent, a lifetime

of three years, a capital cost per unit of

€50,000 per kWe, and hand-made

manufacturing. This is according to COGEN

Europe, the Brussels based association for

the promotion of cogeneration, which co-

ordinates and disseminates Ene.f eld on

behalf of the FCH JU.

Credit: COGEN Europe

6

233

90

179

130

515

70

20

167

30

15

Number of fuel cell micro-CHP units planned for Ene.Field trials

1302PEI_42 42 2/15/13 9:24 AM


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Micro-CHP in Europe

The expected performance with Ene.f eld

will be 35-50 per cent electrical eff ciency, up

to 90 per cent overall eff ciency, lifetimes up to

eight years, capital costs of €13,000–€27,000

per kWe (excluding a 300 W unit involved)

and with potential to get below €10,000 per

kWe. The aim is to reach pre-serial to serial

production too.

“The manufacturers do not see fuel cell

micro-CHP as the only solution to cutting

residential energy use, but as complementary

to other solutions,” says Atanasiu.

Other features to Ene.f eld make delving

beneath the headline spend instructive,

according to Dr. Fiona Riddoch, managing

director at COGEN Europe.

“It’s a big project by any standards, but a

lot of the apparent complexity is in making the

products themselves and that is something

that the manufacturers are taking care of,”

she says.

“Although the [f nancial] sums seem huge,

much of that is because of the hardware

involved. The advantage of Ene.f eld is that

the manufacturers are taking responsibility

for identifying implementation sites and

carrying out f eld trials for their own units. So it

is a fairly decentralised project with no central

agenda and with everyone creating their own

timescales within the overall remit.”

Ene.f eld gets underway

Manufacturers Hexis AG, Switzerland, and Baxi

Innotech, Germany, will be f rst into f eld trials

under Ene.f eld, says Atanasiu. “They were

just waiting for the f rst payment from us, and

they will deploy in the f rst quarter of 2013. We

expect most of the project’s units to be in the

f eld within two years to run for three years.”

Hexis has been talking to municipalities in

Slovenia, which could be the f rst locations

involved, she adds. The Trento province of

northern Italy is another location that has

engaged strongly with the project, says

COGEN Europe’s Dr. Riddoch.

On current plans, 233 units will be installed

in the UK, 179 in Germany, 167 in Italy, 130 in

The Netherlands, 90 in Denmark, 70 in France,

30 in Austria, 20 in Spain, 15 in both Luxembourg

and Slovenia, six in Ireland and f ve in Belgium.

“HyER [Hydrogen Fuel Cells and Electro-

mobility in European Regions Association],

which promotes the use of hydrogen as

an energy source, is an important partner

in Ene.f eld in this regard,” says Antanasiu.

“They have very good contact with regions

and municipalities and have helped

manufacturers f nd places to install units and

put them in touch with utilities. So we now

have all the actors in the project and some of

the commercial interests will reach the point

where they can really take the step forward to

full commercialisation.”

COGEN Europe’s role is key, adds Antanasiu.

“Because there are a lot of competing

commercial interests involved, COGEN Europe

is really the only one that can co-ordinate it.”

Its job is to work with the EU institutions

funding Ene.f eld and to gather and

disseminate information to interest groups for

use by the industry.

Dr. Riddoch also points out the strong

interest and commitment being shown by

municipalities that are keen to be testbeds

and which could eventually help to drag

through a fuel cell micro-CHP market by

choosing these systems for municipal housing

and other public buildings.

“A market is no more than friends talking

to each other about a product or hearing

about it from some source. In that sense,

regions are ideal multipliers of awareness and

communication,” she says.

To win EU funding, the Ene.f eld partners

had to conf rm upfront that they had identif ed

installation sites. “So the core sites have

already been identif ed and the process is

understood,” says Dr. Riddoch. COGEN Europe

will be representing Ene.f eld at Hannover

Messe industrial fair in April. “Come and see

us,” she urges. The Ene.f eld plan foresees

opportunities for increasing co-operation at

Member State and regional level with a range

of participants in the supply chain to the

customer, she adds.

Big in Japan

As Ene.f eld springs into action, it has the

Ene.farm f eld trials example from Japan to

inspire it. Japan was installing 5000 fuel cell

micro-CHP units in 2009 but is expected to

bring 50,000 on line this year, according to

Delta-ee’s Dwyer.

“In Japan, we saw huge corporations such

as Panasonic and Toshiba sharing information

with the big gas utilities there and co-branding

products, which has worked really well for

them. Ene.f eld is the f rst time we’ve seen

something similarly co-ordinated in Europe

and it’s a step in the right direction.”

With this kind of lead in know-how, and

with volume production bringing down

their unit costs, could the Japanese enjoy a

headstart in Europe if a real market develops?

Is Europe just kidding itself that it can build

an indigenous fuel cell micro-CHP industry of

signif cant value?

“Japanese companies looking at Europe

have a number of hurdles to jump over,”

says Dwyer. “The gas quality’s very different in

Europe, the energy markets are very different,

the way people buy their heating systems,

mean the Japanese can’t just decide to sell a

fuel cell micro-CHP product in Europe as they

would a hi-f or a television,” he adds.

“So they will ask what part of the fuel cell

unit could they have a cost advantage for?

They could end up using the same pumps,

pipes and casings as a European company

would. So they have to make the modif cations

and establish partnerships.

“Nobody knows who’s going to have the

ultimate advantage.”

Robert Stokes is a journalist, who regulalry

writes on distributed energy/CHP matters.

Ene.f eld participants

Fuel cell mCHP suppliers to

Ene.f eld are Germany’s Elcore, Bosch

Thermotechnik, Baxi Innotech, Riesaer

Brennstoffzellentechnik (RBZ), and Vaillant;

Switzerland’s Hexis; the UK’s Ceres Power;

Denmark’s Dantherm Power; and Italy’s

SOFCpower.

The research partners are: The UK’s

Imperial College, London, and Element

Energy Ltd; Germany’s EIfER Europäisches

Institut für Energieforschung, Gaswarme-

Institut Essen EV, Gastechnologisches

Institut gGmbH; Denmark’s Danmarks

Tekniske Universitet; Italy’s Politecnico di

Torino and ENVIPARK environment park.

Utilities that are full partners in

Ene.f eld are: the UK’s British Gas; Italy’s

Dolomiti Energia; Denmark’s Dong Energy;

and France’s GDF Suez. Utilities that have

signed letters of intent to participate

include: Italy’s Edison, PVB, and ACEA;

Slovenia’s GIZ DZP; Kiwa and Eneco,

both of the Netherlands; Spain’s Gas

Natural Fenosa; Germany’s Stadtwerke

Rüsselheim; and Ireland’s Bord Gáis.

Co-ordination and dissemination

roles are covered by COGEN Europe,

HyER, Slovenia’s Development Centre for

Hydrogen Technologies, and the

UK’s Energy Saving Trust.


1302PEI_44 44 2/15/13 9:24 AM




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Diary


Diary

April

Power & Electricity World Africa6–11 April

Johannesburg, South Africa

www.terrapinn.com

China Epower 20138–10 April

Shanghai, PR China

www.chinaexhibition.com

Power and Energy Systems 10–12 April

Phuket, Thailand

http://www.iasted.org/conferences/

Wind Farm Development: European Offshore 201310–11 April

Edinburgh, UK

www.wplgroup.com/aci/conferences

Integrated Waste Management and Green Energy Engineering15–16 April

Johannesburg, South Africa

http://psrcentre.org

Power & Electricity World Asia 15–18 April

Singapore

www.terrapinn.com

Saudi Arabian Energy EPC Projects21–24 April

Al- Khobar , Saudi Arabia

www.saudiepcprojects.com

UK Nuclear New Build: Certainty, Delivery and Sustainability23 April

London, UK

www.westminsterforumprojects.co.uk

The 6th Energy Storage Forum, Europe23–25 April

Berlin, Germany

www.energystorageforum.com

Grid-Scale PV 2013 24–25 April

Lyon, France

www.wplgroup.com/aci/conferences

May

HydroVision India 6–8 May

Mumbai, India

www.hydrovisionindia.com

POWER-GEN India & Central Asia6–8 May

Mumbai, India

www.power-genindia.com

Renewable Energy World India 6–8 May

Mumbai, India

www.renewableenergyworldindia.com

Powering Innovation: Eurelectric Conference14 May

Brussels, Belgium

www.eurelectric.org

Gas in the UK electricity market30 May

London, UK

www.westminsterforumprojects.co.uk

June

Eurelectric Annual Convention3-4 June

Bologna, Italy

www.eurelectric.org

POWER-GEN Europe 4–6 June

Vienna, Austria

www.powergeneurope.com

Renewable Energy World Europe 4–6 June

Vienna, Austria

www.renewableenergyworld-europe.com

Intersolar Europe17–21 May

Munich, Germany

www.intersolar.de/en/intersolar.html

July

HydroVision InternationalDenver, CO, US

23–26 July

www.hydroevent.com

March

HydroVision Russia5–6 March

Moscow, Russian Federation

www.russia-power.org

Russia Power 5–6 March

Moscow, Russian Federation

www.hydrovision-russia.com

Unconventional Gas6-7 March

London, UK

www.smi-online.co.uk

Deeper Water Offshore Wind 6–7 March

London, UK

www.offshorewindconference.com

WTUI Conference10–13 March

San Diego, CA, US

www.wtui.com

European Nuclear Forum12–13 March

Prague, Czech Republic

http://marketforce.eu.com

The Future of Utilities19–21 March

London, UK


Iraq Energy Projects 2013 25–27 March

Dubai, United Arab Emirates

www.iraqenergyprojects.com

REA Symposium26 March

London, UK

www.r-e-a.net/events/rea-symposium-2013

Visit www.PowerEngineeringInt.comfor more informationi

1302PEI_46 46 2/15/13 9:24 AM

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http://www.hydrovision-russia.com

http://www.smi-online.co.uk

http://www.offshorewindconference.com

http://www.wtui.com



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http://www.chinaexhibition.com

http://www.iasted.org/conferences/

http://www.wplgroup.com/aci/conferences

http://psrcentre.org

http://www.terrapinn.com

http://www.saudiepcprojects.com

http://www.westminsterforumprojects.co.uk

http://www.energystorageforum.com

http://www.wplgroup.com/aci/conferences

http://www.hydrovisionindia.com

http://www.power-genindia.com

http://www.renewableenergyworldindia.com

http://www.eurelectric.org

http://www.westminsterforumprojects.co.uk

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Project/Tech Update

PROJECT UPDATE

Aggreko to test Brazilian wind farms

Aggreko has been chosen by one of the

largest independent renewable power

generation companies in Brazil to conduct

performance tests at the Morro do Ventos

wind farms in the northeast of the country.

Aggreko will supply load banks – a

recreation of the load that a power source

will generate – for commissioning tests of the

145 MW wind farms, which are operated by

Dobreve Energia. Load bank testing ensures

that the wind farm is ready for grid connection.

Diogenes Paoli Neto, managing director

of Aggreko South America, said Aggreko’s

load banks have been used for many

years “in more traditional sectors such as

manufacturing, oil and gas and shipping. Our

equipment has been built to work with any

power source, allowing us support test needs

of all technologies, traditional or new.”

Meanwhile, Aggreko has opened its

f rst service centre in Namibia. The facility

is Aggreko’s sixth in its southern and east

African network and the company’s regional

managing director James Shepherd said the

expansion into Namibia was “a major step in

our strategy to build a local presence. As the

region continues its strong growth, Aggreko

is well placed to support this growth through

the provision of the world leading temporary

power and temperature control services.”

ABB clinches US and UK contracts

ABB has won an order worth around $260 million

from US utility Bonneville Power Administration,

part of the US Department of Energy, to upgrade

the existing Celilo high-voltage direct current

converter station in Oregon.

This station is an important part of the

electricity link between the Pacif c Northwest

and southern California and was commissioned

more than 40 years ago in 1970.

The Celilo converter station is located at the

north end of the Pacif c DC Intertie, also known

as Path 65, which has a capacity of 3100 MW

and originates near the Columbia River. This

Intertie is 846 miles long and connects to the

Sylmar converter station in the south.

Key components of the station upgrade

include valves, controls, transformers as well

as switchgear and cooling equipment. As

well as modernising the converter station, the

upgrade will also make it possible to boost

capacity up to 3800 MW. ABB carried out

a similar upgrade of the Sylmar converter

station in 2004.

Brice Koch, head of ABB’s Power Systems

division, said the upgrade “will enhance the

reliability of this important HVDC link, thereby

reducing the risk of blackouts and helping to

secure power supply in the region”.

ABB has also won an order to supply a

dual channel automatic voltage regulator

(AVR) for Eggborough Power’s coal-f red

power station in Goole, England.

Eggborough Power Station provides

around 2000 MW for the UK’s National Grid.

The plant went online in 1967 and became

an independent business in 2010.

From the 1990s a number of upgrades

have been undertaken to improve

environmental performance and to replace

major components with more eff cient modern

designs, the latest of which is the upgrading of

the power station’s AVRs.

ABB is manufacturing a complete

replacement for the existing AVR equipment,

based on its UNITROL 6080 Automatic Voltage

Regulators with dual auto channels and dual

power converters replacing one of the existing

single channel AVR units, while retaining the

rotating exciters.

The UNITROL 6080 is based on the AC

800PEC high performance processor family,

which is an extension of ABB’s 800xA control

platform, developed to meet the fast control

requirements of power electronics.

MHI and Marubeni to revamp GTCC plant

Mitsubishi Heavy Industries and Marubeni

Corporation have jointly signed a contract

with NTPC to rehabilitate a 663.36 MW gas

turbine combined cycle (GTCC) power

station in Auraiya, in India’s Uttar Pradesh state.

Under the turnkey contract, the two

companies will revamp gas turbines, renew

control equipment and supply and install

equipment. The project is slated to be

Aggreko’s service centre in Namibia.Credit: Aggreko

Eggborough power station: ABB will supplyit with a dual channel AVR.

Credit: ABB

1302PEI_48 48 2/15/13 9:24 AM


September 24–26, 2013

Transamerica Expo Center

São Paulo, Brasil

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1302PEI_49 49 2/15/13 9:24 AM

http://www.power-genbrasil.com



Project/Tech Update

completed in April 2015. The Auraiya GTCC

power station has been operating since 1990.

The rehabilitation work is expected to boost its

installed capacity by 55 MW and extend its

service life by more than ten years.

Europe’s largest land wind park goes online

CEZ Group’s 600 MW Fantanele/Cogealac

wind park, Europe’s largest onshore wind

project, has entered full operation in Romania.

The project in Dobrogea, Constanta

County, features 240 GE 2.5 MW wind turbines.

Ondrej Safar, CEZ project manager, said:

“Thanks to the Fantanele/Cogealac wind

farm, CEZ is making a major contribution

to increasing Romania’s renewable energy

generation. Before this project, Romania’s

installed wind capacity was only 14 MW.”

The individual wind turbine components

for the Fantanele/Cogealac wind farm were

produced all over the world. The turbine

nacelles were supplied from GE’s facility in

Salzbergen, Germany. The rotor blades and

towers came from Germany, Brazil, the Czech

Republic, Denmark, Poland and China.

The size of the components – one

rotor blade measures nearly 50 meters in

length – and the number of units required

comprehensive planning. Twelve modes

of transport were needed to move the

components for each turbine from the port

of Constanta on the Black Sea to the project

site. At peak times, 25 cranes were in action

at once.

Metso recovery boiler f res up at pulp plant

The Metso-supplied evaporation plant and

recovery boiler for Eldorado Celulose e Papel

S.A. have been started up successfully at

Eldorado’s Três Lagoas mill in Brazil.

The mill, the largest single-line pulp mill in

the world, counts on Metso’s cutting-edge

equipment in its recovery line.

The evaporation plant, with a capacity of

1600 tonnes an hour of evaporated water, is

the largest single line evaporation plant in the

world with the purpose of concentrating black

liquor up to 80 per cent dry solids content for

eff cient and low-emission combustion in the

recovery boiler.

The recovery boiler is also among the

largest in the world in operation and has a

6800 tonnes of dry solids/day black liquor

burning capacity and steam generation of

1109 tonnes of steam/hour. The steam will be

used in the pulp manufacturing process and

in power generation to supply the entire mill

and produce a signif cant amount of power

surplus. Additionally, the recovery boiler has

high chemical recovery eff ciency making

the mill economically and environmentally

sustainable.

Sayano-Shushenskaya sees new unit online

A fourth new hydropower unit has been

commissioned at Sayano-Shushenskaya

hydropower plant, Russia’s largest

hydroelectric plant.

The plant run by RusHydro was closed in

2009 following an accident which resulted

in the deaths of 75 people, damage to all

10 turbines and the collapse of the turbine

hall roof.

Since then, new units have been

manufactured and installed by Power

Machines.

Prior to the commissioning of unit No.

9, a series of start-up tests were performed,

including testing of individual equipment and

systems of the unit, idle running of the turbine,

as well as reliability run of the unit equipment

and systems during 72 hours.

Unit No. 9 has the same functions as units

1, 7 and 8 which were commissioned in 2011

and last year.

UK f rm in bid to build longest turbine blade

A UK f rm is building what it believes will be the

longest ever wind turbine blades.

In a £15.5m ($24.8m) project, Blade

Dynamics – which is based in the Isle of

Wight off the south coast of England – will

construct blades of between 80 to 100 metres

in length, incorporating carbon f bre rather

than conventional f bre glass. Blades currently

deployed offshore are between 60 to 75

metres in length.

The blades are expected to be put into

production by late 2014, with structural trials to

be carried out at a UK test facility.

Blade Dynamics claims the blades will

weigh up to 40 per cent less than their

conventional glass-f bre counterparts, which

would enable signif cant cost savings

throughout the rest of the turbine system.

The blades are expected to be utilised on

the next generation of large offshore wind

turbines currently under development with a

capacity of 8 to10 MW.

The project is being backed by the UK’s

Energy Technologies Institute, which will

become an equity investor in Blade Dynamics.

Blade Dynamics’ senior technical manager

David Cripps said: “Financial backing from the

ETI for this project allows deployment on ultra-

large turbines far sooner than would otherwise

have been possible and as a result of this

project we will be hiring new engineers and

technologists to make this possible.”

He added that longer, low weight blades

were “a key part of the solution to making the

generation of electricity through offshore wind

both more reliable and more economical”.

The ETI’s offshore wind project manager

Paul Trinick said: “Offshore wind has the

potential to be a much larger contributor to

the UK energy system if today’s costs can be

signif cantly reduced. Investing in this project

is a key step for the whole industry in paving

the way for more eff cient turbines, which will

in turn help bring the costs of generating

electricity down.”

Thinking big: bid for largest blades.Credit: Blade Dynamics

1302PEI_50 50 2/15/13 9:24 AM



Project/Tech Update

EQUIPMENT UPDATE

Alstom installs 1 MW tidal turbine for testing

Alstom has installed a 1 MW tidal turbine at

the European Marine Energy Centre’s full-

scale test site in Orkney, Scotland.

The 1MW tidal turbine is f tted on the same

tripod support structure used to deploy a

previously tested 500kW device.

It will now be tested in different operational

conditions off Orkney over an 18 month period.

Jacques Jamart, senior vice-president of

Alstom New Energies, said: “This new milestone

installation is a step further towards the

commercialisation of this new power solution.

The aim of this project is also to demonstrate a

new, eff cient and reliable turbine design.”

The turbine has a rotor diameter of 18

metres, a 22 m-long nacelle and a weight of

150 tonnes. It has three pitchable blades and

operates, fully submerged, at a depth of 40

meters, by rotating to face the incoming tide.

Cummins unveils new mobile gensets

Cummins Power Generation has

launched four new mobile generator

sets specif cally designed for rental

applications.

Ranging from 150-300 kVA, the new

models include the Cummins QSL9

and QSB7 diesel engines. Supplied

as pre-integrated systems, Cummins

says the new models are ideal for

construction, industrial and events

applications.

Available in 150, 200, 250 and 300

kVA conf gurations, the generator sets have

been designed by Cummins’ new team

of specialist rental engineers. All four new

models benef t from Cummins made key

components supplied as a pre-integrated

system, which the company says increases

maintenance eff ciency as any potential

issues for the engine, alternator or control

system can be resolved by a single engineer.

GE targets turbine degradation with f lter

GE has introduced ClearCurrent PRO, a gas

turbine inlet f lter cartridge that has been

f eld tested and shown to positively affect gas

turbine performance while helping to reduce

the effects of turbine degradation.

The f ltration portfolio expansion supports

GE’s growing focus on the use of natural

gas for power generation. GE’s ClearCurrent

PRO cartridge f lters are compatible with GE’s

FlexEff ciency portfolio.

Over the next f ve years, GE plans to invest

nearly $11 million to improve its facilities that

produce the ClearCurrent PRO cartridges.

Keith White, general manager of GE’s Air

Filtration business, said ClearCurrent PRO’s

inlet f lter “offers enhanced output and lower

fuel costs for turbine operators”.

“Degradation-based maintenance is very

important to turbine operators,” added Paul

Sennett, product line leader for gas turbine

inlet systems at GE. “Our PRO technology

can help reduce that

degradation and make

it so that the choice of

inlet f lters has a direct

correlation to turbine

performance.”

Martin Engineering’s brush with conveyors

A new powered brush cleaner for conveyor

belt applications has been introduced by

Martin Engineering.

The rotating design removes material

accumulation and dust in diff cult

applications, even in conditions involving

sticky materials or stringy f bers such as coal

and biomass.

Martin states that the 230/460-volt, 3-phase

electric motor provides successful cleaning

with minimal power consumption. A 1 HP

motor powers the units for 18-42 inch belts,

and a 2 HP motor drives the cleaners for 48-96

inch belts. The motor can be operated in either

direction, and the unit can be installed on the

left or right side of the cleaner, depending on

the plant’s requirements.

Parker to overhaul Danfoss water pumps

Motion and control technology company

Parker Aerospace, part of Parker Hannif n

Corp, is to overhaul and recertify the Danfoss

series of high-pressure water pumps for power

generation industry applications.

Danfoss provides high-pressure

water pumps to industry leaders such

as General Electric, Rolls-Royce, and

Siemens. The initial overhaul and

recertif cation work will be performed

at Parker’s gas turbine fuel systems

division facility in Massachusetts.

High tide: Alstom’s 1MW turbine.

Credit: Alstom

Clean sweep: Martin’s brush cleaner.

Credit: Martin Engineering

GE’s ClearCurrent PRO

Credit: GE

1302PEI_51 51 2/15/13 9:24 AM



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1302PEI_52 52 2/15/13 9:25 AM










6-8 MAY 2013

BOMBAY EXHIBITION CENTRE,

GOREGAON, MUMBAI, INDIA

CONFERENCE PROGRAMME ANNOUNCED

Taking place from 6 -8 May 2013 at the Bombay Exhibition Centre in Mumbai,

POWER-GEN India & Central Asia, along with co-located events Renewable

Energy World India and HydroVision India, is the regions premier conference

and exhibition for the power industry.

Under the theme, Indian Power - Time to Deliver, this three-way event features

a world-class conference programme that covers hot topics, benchmark

industry projects, thought-provoking issues and developments by world-

leading experts from around the globe.

Highlights of Conference Topics include:

� Indian Power – Time to Deliver (Panel Discussion) � Improving Boiler Effciency

� Power Supply & Distribution � Financing Renewable Energy � PV & India’s

Solar Mission � Financing of Hydro Projects � And much more!

This three-day event also offers a leading industry exhibition showcase and

excellent business networking opportunities.

Join us at POWER-GEN India & Central Asia, Renewable Energy World

India or HydroVision India 2013 and discover new ideas, technologies and

developments and source the latest products and services showcased by

leading companies and suppliers from within India and around the world.

For further conference and exhibition details visit the websites.

INDIAN POWER

TIME TO DELIVER

www.power-gen-india.com www.renewablenenergyworldindia.com www.hydrovisionindia.com

®

�

Event Organizers: Presented by:

Supporting

Organization:

For speaker and conference enquiries, please contact: For exhibitor and sponsorship enquiries, please contact:

POWER-GEN India

& Central Asia

Samantha Malcolm

Conference Manager

T: +44 (0) 1992 656 619

F: +44 (0) 1992 656 700


Renewable Energy World India

HydroVision India

Amy Nash Conference Manager

T: +44 (0) 1992 656 621

F: +44 (0) 1992 656 700


POWER-GEN India

& Central Asia

Kelvin Marlow

Exhibit Sales Manager

T: +44 (0) 1992 656 610

F: +44 (0) 1992 656 700


Renewable Energy World India

HydroVision India

Tom Marler

Exhibit Sales Manager

T: +44 (0) 1992 656 608

F: +44 (0) 1992 656 700


REGISTER BEFORE 5 APRIL 2013 TO

GET YOUR EARLY BIRD DISCOUNT.


1302PEI_C3 C3 2/15/13 9:06 AM

http://www.power-gen-india.com

http://www.renewableenergyworldindia.com

http://www.hydrovisionindia.com






http://hydroworld.com


1302PEI_C4 C4 2/15/13 9:06 AM


http://www.smt.sandvik.com

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