MONITORING IN THE AGE OF BIG DATA

CHALLENGES OF COAL PLANT UPGRADE

PREPARING FOR NEW EU MERCURY LIMITS

Hinkley Point CA nuclear renaissance?

www.PowerEngineeringInt.com

The magazine for the international power industry November 2015

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POWER ENGINEERING INTERNATIONAL

Contents

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On the cover

Hinkley Point C: a new nuclear renaissance. P16. Cover images: EDF Energy; DECC; EU

Industry experts offer their views on the future of nuclear. P10

Credit: WANO

Power Engineering International November 2015

Features

4 Advances in mercury control

As Europe faces new emissions standards, we investigate

what it will mean for mercury control technology

companies and Europe’s power plant operators.

10 Which way forward for nuclear?

Is nuclear an inflexible generation source being left

behind in an energy world demanding flexibility, or is it the

ideal long-term companion to renewables?

16 Hinkley Point: kickstarting a nuclear revival

Work is poised to start on Hinkley Point C. We get reaction

to the pact between EDF and China General Nuclear and

find out what the project will mean for the UK.

20 Coal conversion conveyor challenge

A complex project to convert coal conveyors was made

more challenging by the need to carry out the work while

the plant was fully operational.

2 Industry Highlights

36 Diary

36 Ad Index

NOVEMBER 2015/// VOLUME 23/// ISSUE 10

26 Monitoring in the age of big data

Condition monitoring is changing as computing

technology evolves. We discuss the future of the

technology for power plant operators.

30 Flue gas desulfurization retrofits

As new SO2 emission regulations require the retrofit of

flue gas desulfurization units, we examine cost-effective

solutions to achieve these new emission standards.

34 The Middle East’s expanding energy mix

POWER-GEN Middle East in Abu Dhabi put in the spotlight

the region’s plans to diversify its power generation

portfolio away from fossil fuels.

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2 www.PowerEngineeringInt.com

Industry Highlights

Follow PEi Magazine on Twitter: @PEimagzine

Follow me: @kelvinross68

To implement COP21 pledges, the energy sector will need to invest $13 trillion

Kelvin Ross Editor www.powerengineeringint.com

Power Engineering International November 2015

The International Energy Agency (IEA) has

released a special briefing document

that outlines the energy sector

implications of national climate pledges

submitted for the upcoming climate summit in

Paris, known as COP21.

The briefing finds that if all countries meet

the goals outlined in their submitted pledges,

growth in energy-related emissions – which

account for two-thirds of total greenhouse

gas emissions – will “slow to a relative crawl by

2030”.

And it calculates that the full

implementation of these pledges will

require the energy sector to invest

$13.5 trillion in energy efficiency and low-

carbon technologies between now and 2030,

at an annual average of $840 billion.

Around $8.3 trillion will be needed to

improve energy efficiency in the transport,

buildings and industry sectors, and the rest will

have to be spent on decarbonizing the power

sector.

The IEA projects that more than 60 per

cent of total investment in power generation

capacity will be for renewable capacity, with

one-third of this being for wind power, almost

30 per cent for solar power (mainly solar

photovoltaics) and around one-quarter for

hydropower.

The report states that “actions in the energy

sector can make or break efforts to achieve

the world’s agreed climate goal”.

More than 150 countries have submitted

pledges, accounting for around 90 per cent

of global economic activity and almost 90 per

cent of global energy-related greenhouse gas

emissions today.

By world region, all of the countries in North

America have submitted pledges, almost all

in Europe, around 90 per cent in Africa, two-

thirds in developing Asia, 60 per cent in Latin

America and one-third in the Middle East.

These countries currently account for around

90 per cent of global fossil fuel demand

and almost 80 per cent of global fossil fuel

production.

The form of the pledges varies, including

concrete emissions targets, deviation from

‘business-as-usual’ emissions trajectories,

emissions intensity targets, reductions

or limitations in per-capita emissions, or

statements regarding policies and measures

to be implemented.

IEA Executive Director Fatih Birol said that

the fact that more than 150 countries have

submitted pledges to reduce emissions is

“remarkable”.

“These pledges, together with the

increasing engagement of the energy

industry, are helping to build the necessary

political momentum around the globe to seal

a successful climate agreement in Paris.”

The briefing finds that all of the pledges

take into account energy sector emissions

and many include specific targets or actions

to address them.

If these pledges are met, then countries

currently accounting for more than half of

global economic activity will see their energy-

related greenhouse gas emissions either

plateau or be in decline by 2030.

Global energy intensity, a measure of

energy use per unit of economic output,

would improve to 2030 at a rate almost three

times faster than the rate seen since 2000. In

the power sector, 70 per cent of additional

electricity generation to 2030 would be low-

carbon.

And the power sector – the world’s largest

source of energy-related CO2 emissions –

would see emissions plateau at close to

today’s levels, “effectively breaking the link

between rising electricity demand and rising

related CO2 emissions”.

The report finds that the full implementation

of the pledges will require the energy sector

to invest $13.5 trillion in energy efficiency

and low-carbon technologies from 2015 to

2030, working out at an annual average of

$840 billion.

However, despite these efforts, the IEA

states that the pledges “still fall short of the

major course correction necessary to achieve

the globally agreed climate goal of limiting

average global temperature rise to 2oC,

relative to pre-industrial levels”.

Birol added: “The energy industry needs a

strong and clear signal from the Paris climate

summit.

“Failing to send this signal will push energy

investments in the wrong direction, locking

in unsustainable energy infrastructure for

decades.”

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Mercury control

Power Engineering International November 2015

Mercury falling

Both the development of mercury control technology and its installation in power plants

follow the evolution of emissions regulations. With a new standard in the works for Europe, Tildy Bayar investigates what it will mean for mercury control technology companies and

Europe’s power plant operators.

In a March note, Greenpeace EnergyDesk

editor Christine Ottery wrote that European

environmental regulations for power

plants, which are expected to be finalized

by 2016 and come into force by 2020 as

part of the Industrial Emissions Directive

(IED), “could change the face of Europe’s

energy system … though hardly anyone

knows they exist.”

Analysts have speculated that the

regulations, known as the large combustion

plant best available techniques reference

document (LCP BREF), could force large

numbers of coal-fired power plants across the

EU into retirement by 2025.

Along with establishing stricter limits for

SOx, NOx and particulate emissions, the

regulations, known as the large combustion

plant best available technology reference

document (LCP BREF), will likely set standards

for mercury emissions from power plants. Unlike

the US, Europe currently has no set standard

for these emissions, and thus the major market

for mercury control technologies to date

has been North American. In Europe, the

need for legislation specifically dealing with

mercury has largely been addressed by the

mercury reduction co-benefits available from

technologies used to comply with existing

legislation (the Large Combustion Plant

Directive and the current version of the IED) on

SOx and NOx removal.

The mercury emissions limits being

considered in the draft BREF for plants over

300 MW range between 0.2 µ/m3 and

10 µ/m3. Dr Lesley Sloss of the International

Energy Agency’s Clean Coal Centre said in

May that while “the actual value has yet to be

agreed and the applicability of the proposed

limits has yet to be defined,” the new BREF

“could mean … there may be a new mercury

control market opening up in Europe within

the next few years.”

And this market could expand even further.

Mandar Gadgil, Air Quality Control Systems

Engineer with Babcock & Wilcox (B&W), notes

that “in the next four to five years, Germany will

enact the BREF regulation, and Europe may

follow. China, India, South Africa, and other

coal-burning countries will implement new

regulations. It may take five years or so, but

by 2025 I think all plants will have to control

mercury all over the world.”

However, Jorgen Grubbstrom, Product

Marketing Manager for Dry FGD Environmental

Control Solutions with Alstom’s* Steam

Business, says the European market may be

slower to develop than expected. “Suppliers,

member states and different stakeholders

understand that it’s very important to have the

correct conclusions as they may drive a lot of

changes for the power industry,” he says. “[The

BREF] is taking more time than expected – it’s a

tedious process – so they are in delay.”

Bernd Volmer, Process Engineering & Design

AQCS at Mitsubishi Hitachi Power Systems

Europe (MHPSE), says his firm will be ready

when the time comes. “The US, compared

to Europe in regard to mercury reduction, is

in front of us,” he says, “so we learn from our

partners in the US about the technologies and

will implement these also on the European

market – the emission values will come into

force in 2016–17, and plants will be required to

comply in 2020–21.”

Standards development, Volmer notes, is

“an ongoing, rotating process”. While power

plant operators will be given four years to

implement the expected BREF standard, he

explains, a subsequent revision will be issued in

eight years. “So there is a time interval between

a revision of eight years and compliance

duration of four years. Every four years a utility

will comply with the regulation, then it has

another four years’ time to implement a new

revision of the standard reflecting the updated

technology.

“We have to continuously improve the

technology in response to the continuous

challenge of emission values,” he says.

How it works

The basis of the control process is the oxidation

of mercury, and then its removal within

downstream equipment before it is emitted

through the stack into the atmosphere. The

most common technology involves injection

of activated carbon into the plant’s exhaust

stream.

New EU rules on mercury control are expected

Credit: Babcock & Wilcox

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Mercury control

Power Engineering International November 2015

Mercury comes in three forms: metallic,

ionic and particulate. “The goal is to oxidize

all metallic mercury to ionic mercury so it can

be removed in the flue gas desulphurization

(FGD) system,” explains MHPSE’s Volmer.

According to B&W’s Gadgil, “the main

workhorse of the industry for mercury control

in the US is powdered activated carbon (PAC)

– both halogenated (usually bromine is the

halogen of choice) or non-halogenated

depending on how much mercury is in the

gas screen.” Another “very efficient” and widely

used technology is halogen injection into the

coal itself.

“It’s very simple,” Gadgil says. “Calcium

bromide or sodium iodide is added to the

coal. It’s an inexpensive process and results in

very high mercury oxidation. The only catch is

that for halogen addition to work on its own as

a mercury control technology, there has to be

some sort of FGD system. Oxidized mercury is

very soluble and can be taken out in the FGD.”

There are other sorbents in use, Gadgil

adds, such as amended silicate, which is “as

good as activated carbon but has not been

as widely used due to economic reasons.”

Gadgil also confirms that “sometimes there

is re-emission of mercury – this has happened

in some plants. If there are 2µg of elemental

mercury going inside a wet scrubber and 3µg

coming out, that’s re-emission,” he explains.

“This happens because of the chemical

nature, processes and the atmosphere inside

the scrubber, and as a result some of the

oxidized mercury goes from the oxidation

phase to the elemental phase. To address

that, we have a sulphide-based additive,

sodium hydrosulphide, which has proved

very effective in controlling re-emission. Other

companies have their own re-emission control

additives.”

Alstom’s Grubbstrom notes that, “since

re-emission is a function of the chemistry of

the slurry, in particular the sulphite content

is of importance to monitor and control this

parameter.” To this end, his firm has recently

launched a sulphite analyzer which also

measures oxidation reduction potential (ORP)

and controls the flow rate of oxidization air to

the wet FGD.

MHPSE’s Volmer says the mercury reduction

process involves looking at existing plant

equipment and “how you can optimize it to

meet requirements. For a system where you

already have [mercury] mitigation through

selective catalytic reduction (SCR), the use

of SCR with special types of catalyst is a very

low-cost mitigation process, together with a

downstream wet FGD equipped for mercury

removal.”

Alstom’s Grubbstrom says his firm takes two

main approaches. First, a system based on

injecting an adsorbent such as PAC upstream

of the air preheater in a high-temperature

area and collecting it later in an area of at

least 50 degrees lower to enhance adsorption.

A milling system reduces the size of the PAC to

increase the surface area of the sorbent and

enhance mercury capture on the surface of

the carbon particles, Grubbstrom says.

Secondly, an enhanced PAC process

which includes a sorbent storage silo and

an injection system comprised of a series of

lances in the ductwork, designed to optimize

contact between flue gas and PAC. The

mercury, PAC and fly ash are removed in a

fabric filter.

Gerhard Heinz, Director of Sales & Marketing

for Alstom Thermal Services Central Europe &

CIS, notes that higher temperatures favour the

kinetics of oxidizing elemental mercury and

increase the extent of chemical absorption. In

addition, “injecting in a high-temperature area

before the air heater increases absorption

because the mercury is in contact with

the flue gas for a longer time,” he says. The

mercury is then collected in the electrostatic

precipitator (ESP), which “might need to be

upgraded a bit to fulfil lower particle emission

requirements,” he notes.

Different strokes for different plants

Daniel Chang, Air Quality Control Service

Area Leader with Black & Veatch Energy

(B&V), notes that attention to site-specific

constraints is needed to determine the best

mercury compliance solution. “We take into

consideration the performance of emissions

control technology to reduce emissions to

required limits, the ease of integrating into

an existing power plant, and then the cost to

implement the technology,” he explains.

“For example,” he says, “two different power

plants located in different regions may be

combusting different kinds of coal. This usually

means a difference in the amount of mercury

emitted, which could be in terms of quantity

as well as composition. Secondly, coal-fired

power plants can be configured very differently

in terms of the way coal is combusted. The

back end of the unit is also very different

in terms of types of equipment installed for

capturing emissions of SO2, particulate matter

and NOx.”

Power plants burning bituminous coal,

which has a higher sulphur content, are

prevalent in the eastern US, Chang notes. This

type of plant is generally equipped with a NOx

reduction system such as an SCR. Depending

on the age of the unit, some will have ESPs or,

if built later or retrofitted, a pulse jet fabric filter

(PJFF) to reduce particulate emissions from

the flue gas stream, followed by a FGD system.

Wet FGD is the most typical, Chang says.

When injected into the flue gas, PAC

captures mercury in the pores of the carbon

particles, he explains. Collection usually takes

place within the ESP or the PJFF as well as

within the wet FGD system, where water sprays

collect it in the by-product area.

“This is a commonly used approach to

mercury reduction,” says Chang. “However,

there may be other approaches within this

kind of configuration where PAC could be

avoided or its consumption reduced” through

co-benefit. “This happens when you have

an SCR which has a catalyst system that will

help oxidize mercury, and then the oxidized

mercury can be captured in the wet FGD

system,” he explains.

For the low-sulphur coal that comes from

the western US, a typical power plant could

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8 www.PowerEngineeringInt.comPower Engineering International November 2015

Mercury control

be configured with a boiler, NOx reduction

system, SCR, then a dry FGD system paired

with a PJFF to collect particulate matter as well

as by-product from the SO2 removal process.

The primary mercury removal method for

these plants is PAC. For these plants, Chang

says, “due to the composition of the coal, the

forms of mercury are usually less oxidized so

you always need to consider a halogenated

form of PAC where the halogens help promote

a reaction that converts it to oxidized mercury

to improve the capture rate.” For a lignite-

fired plant, he notes, the optimal mercury

compliance solution would be equivalent to

this US example.

B&W’s Gadgil concurs that existing

equipment installed at a plant can affect

technology choices. “For example,” he says, “if

the only air quality control equipment a plant

has is an ESP for particulate control, even if

there is a high degree of mercury oxidation,

the plant will still need PAC or some other kind

of sorbent. So you still need to install a carbon

injection system and a halogen injection

system – but instead of two systems, why not

use brominated carbon? One system is better

than two, and you can get the same effect as

a bromine system and some kind of sorbent.

“The same goes for a baghouse as well.

If you have SCR or FGD such as a circulating

dry scrubber, then you might not need to

use carbon at all. You may have enough

high oxidation of mercury either with SCR or

halogen addition to coal, so it can be removed

almost 100 per cent by FGD equipment. This

will save a lot of money on capital costs, and

to a certain extent on operating costs as well.”

Chang notes that the capital cost is less

intensive for mercury emissions reduction

than for other pollutants. “Activated carbon is

less capital-intensive than a wet FGD or SCR

system,” he says – but this is then balanced

by operating costs “because you have to buy

activated carbon from a vendor and [the cost

of] injection is considerable.” When selecting

mercury removal technology, he advises that

plant operators take into consideration both

the capital and operating cost, including

lifecycle costs, in order to “make sure they’re

not spending a lot of capital on a unit that

won’t have 20 years of remaining operation”.

Heinz concurs: “The main driver for total

cost of operation of mercury reduction

systems is the ongoing OPEX – mainly the cost

of sorbents. The CAPEX for installations is a

secondary driver,” he says.

When to implement?

Should plant operators wait until they are

within the compliance period to purchase

new mercury control equipment, or begin

before the legislation comes into force?

Alstom’s Grubbstrom says, “Those

customers that have a large fleet need to look

into the various options right now in order to

spread out the investment. We have already

had contact with customers – some larger

utilities, for example – that would like to discuss

it, even if it will be one year until the [BREF] is

published and then [they can] take four more

years [to upgrade].”

What does the upgrade involve, and

how easy is it? Alstom’s Heinz says his firm’s

technology is designed for upgrading

existing plants. “We can implement it in the

existing environment [as it is] not very space-

consuming. Especially when the customer is

currently on the way to implementing retrofit

measures to improve the plant’s performance,

then he already has to consider the necessary

steps for reduced mercury emission so as not

to be in a position two years after a retrofit to

start the next steps.”

B&V’s Chang says: “When you implement

a compliance solution you have to take

into account other anticipated future rules.

We want to make sure our clients invest in a

solution which will remain part of the overall

compliance scheme in future.”

Future developments

Current technology can remove around

90 per cent of the mercury emitted during the

coal combustion process. Can this figure be

improved – and could it ever reach 100 per

cent?

MHPSE’s Volmer says that, from a

technology perspective, “I cannot say

100 per cent – I can say 99.999 per cent

(just joking). It’s a question between the

possible technology and investment in its

implementation,” he explains. “If [power plant

operators] have to comply [with standards],

they have to invest or close down the plant.

Reaching 99.99 per cent is possible, but it also

has to be economically feasible. The operator

may not want 99.99 per cent mercury removal

technology.”

Michael Wende, Process Engineering &

Design AQCS with MHPSE, adds: “With the

technologies required to cope with the

regulations coming into force in 2016–17, a

highly sophisticated standard for mercury

removal will already be reached. In addition,

the BREF revision in an eight-year cycle will

be the driving force for additional efforts to

improve mitigation technologies.”

Volmer says his firm is working on a

different composition of their product for

different coal applications, aiming to increase

the removal efficiency of mercury in the wet

FGD system. “Our goal is not to build new

equipment for modernization,” he notes.

“We want to improve existing equipment,

which is more cost-effective for the operator.

Our improved technology can reach up to

90 per cent. But this always depends on

the incoming mercury in coal, and on

the requested emissions values. The lower

emissions values are necessary – they are the

incentive for all technology improvement.”

Wende adds that high US and European

standards represent an impetus for continuous

improvement in emissions reduction

technology and optimized emissions

mitigation in these regions. “However,” he

adds, “from a global point of view, one of the

next required steps for emission reduction

is to focus on the implementation of the

applicable flue gas cleaning technologies

in countries and regions with less stringent

standards.” For this purpose, he says “a

huge portfolio of effective technologies is

available.”

* Alstom’s Energy sectors are in the process of

being acquired by GE as PEi goes to press

Visit www.PowerEngineeringInt.com

for more information

Emissions rules drive technology R&D

Credit: Babcock & Wilcox

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10 www.PowerEngineeringInt.comPower Engineering International November 2015

Nuclear focus

Which way for nuclear?

Some suggest that nuclear is an inflexible generation source being left behind in an energy world demanding flexibility, yet Kelvin Ross finds that there are calls for it to play a part as a long-term companion to renewables.

The nuclear industry is at a

crossroads. As Ann MacLachlan,

former European Bureau Chief of

Platts Nuclear Publications, said

at the World Nuclear Symposium

in London recently, it is “flourishing

in China, finished in Germany and floundering

elsewhere”.

In Europe, the future of nuclear hangs in the

balance. Germany is taking it out of its energy

mix and the two newbuild projects that are

underway – Flamanville and Olkiluoto – are

dogged by delays and cost over-runs, and

as such are a far cry from being an industry

showcase.

And yet in October EDF agreed a deal that

will see China General Nuclear China take a

33.5 per cent stake in Hinkley Point C plant in

the UK. With a final investment decision from

EDF now almost a formality, Britain is poised

to build its first nuclear power plant in a

generation, which will give a shot in the arm to

the industry globally.

There is certainly an appetitite for nuclear

among European power trade groups. The UK-

based Energy Technologies Institute (ETI) last

month published a report called ‘The role for

nuclear within a low carbon energy system’.

In it the ETI states that new nuclear plants

“can form a major part of an affordable low

carbon transition”, and in particular highlights

the potential of small modular reactors (SMRs).

It says the emergence of multiple

developing SMR designs with an electrical

generation capacity in units of 300 MW or

less “opens up the potential to deploy a wider

range of nuclear technologies within an

integrated energy system”.

Mike Middleton, strategy manager for

nuclear at the ETI and the report’s author, says

“new nuclear power, along with conventional

power stations with carbon capture and

storage and renewables, are likely to be

the key technologies delivering low carbon

electricity in the future in the UK”.

“Our latest analysis has created new

understanding of the potentially different

contributions from large baseload reactors

and SMRs in a future UK energy system.

“These two nuclear technologies can offer

potentially complementary roles in baseload

and flexible combined heat and power

generation, and also in terms of the location

of development sites.”

However, Middleton is keen to stress that

“future nuclear technologies will only be

deployed if there is a market need, and these

technologies need to provide the most cost-

effective solution”.

He said that “the next 10 years will be critical

in developing the deployment-readiness of

key technology options for the UK’s low carbon

transition to 2050. New nuclear plants can

form a major part of an affordable transition,

with both large nuclear and SMRs potentially

playing a significant role.”

Hot on the heels of the ETI report came

a survey from the Institution of Mechanical

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12 www.PowerEngineeringInt.comPower Engineering International November 2015

Nuclear focus

Engineers, which found that 56 per cent of

the UK public support Britain’s continuing to

use nuclear power – 19 per cent did not back

nuclear and 25 per cent were unsure. Of the

people who support nuclear power, 82 per

cent said that this is because it will “help keep

the lights on”, 56 per cent because it would

provide jobs and 54 per cent because it

would boost the economy.

The main concerns for people who

opposed nuclear were that it is “too

dangerous” (77 per cent) or too damaging

for the environment (76 per cent), while just

27 per cent said that it was because it was too

expensive.

In the UK there are currently 16 civil

nuclear reactors providing 18 per cent of

Britain’s electricity needs and supporting local

communities through employment, supply

chain and economic development.

Dr Jenifer Baxter, Head of Energy and

Environment at the Institution of Mechanical

Engineers, says that the results of the survey

“show that most of the public realize the vital

role nuclear has to play in keeping the lights

on in the UK. But there is a lack of knowledge

about nuclear technology and the way

nuclear waste is managed.”

She added that there is a “critical need for

industry and government to raise awareness

about the economic and employment

benefits of nuclear power. There is also a need

to highlight the comprehensive range of

safety procedures in place to mitigate risk and

environmental damage, with both nuclear

power generation and the management of

nuclear waste.”

European electricity trade group Eurelectric

has also called for nuclear to play a key role

in the future energy mix. In a recent report,

it stated that nuclear energy “contributes

to the three major energy policy objectives

of the European Union: security of supply,

decarbonization of the electricity sector and

competitive power prices in Europe”.

However, it stresses that with new nuclear

plants currently under construction in France,

Finland and Slovakia and at the planning

stage in the UK, Hungary and Romania, the

sector faces a number of challenges.

The first of these is to improve the economic

operation of existing nuclear power plants. “In

several European countries distortive national

policy measures place economic burdens

on nuclear units which are leading to the

early shutdown of technically well-functioning

nuclear reactors,” says Eurelectric’s report

Nuclear Power Plants – Tackling the Investment

Dilemma.

Another challenge is to “enable new

market-based investment, which is not viable

under the existing energy policy and market

framework. To facilitate investment in nuclear

and other low-carbon technologies, an

improved regulatory framework is needed

and, in particular, ways must be found of

reducing investment risk.”

Eurelectric also wants to nuclear regulators

promote “greater harmonization and

standardization of components, which will

further improve cost-competitiveness”.

The trade group argues that with the

European power sector undergoing radical

change, decentralized and centralized large-

scale systems will depend on each other

and nuclear power “can play an important

role in solving the challenges of this new,

more diverse energy system, providing the

reliable baseload supply necessary to ensure

generation adequacy”.

Asia perspective

The nuclear picture in Asia could not be more

different from Europe. Despite being stalled in

Japan post-Fukushima, China is leading the

global market and Vietnam is on the way to

having its first nuclear power plant.

And a new study from research company

GlobalData predicts that India’s nuclear

capacity is expected to increase more than

six-fold, from 5.8 GW in 2014 to 35.2 GW by

2025, in a bid to reduce the country’s reliance

on coal.

GlobalData’s senior power analyst

Chiradeep Chatterjee says: “India’s nuclear

energy development strategy has been

divided into three stages due to its limited

reserves of uranium, which are already being

used in existing reactors. The potential for

generating power from uranium mined in

India has been estimated at 10 GW.

“However, the country has large reserves

of thorium, with the result that the transition to

breeder reactors that use thorium has been

proposed, through this three-stage strategy.”

The Ninh Thuan plant in Vietnam is being

built by Rosatom and I caught up with

the company’s regional vice-president for

Southeast Asia, Egor Simonov, at POWER-GEN

Asia in Bangkok.

He says that for the development of

nuclear in Southeast Asia, “it is all about

political decision-making. For Vietnam, that

decision is there – they are going to have a

nuclear power plant. For other countries in

this region it is either a power development

plan or statements of policy that say they are

considering nuclear power.”

I asked him what the effect – in Asia and

globally – would be if Japan brings its fleet

of reactors back online. After stating that he

personally believes “it is going to come back

online pretty much in its entirety”, he adds: “If

Japan’s reactors all came back online, that

would be a signal to the politicians. Industry

experts understand what has happened, why

it has happened and how severe it actually

was. It would be a sign to the politicians that

nuclear power is safe.”

He says the same effect will be had if

Callum Thomas: “The industry is dependent on men between the age of 40 and 60.”

Credit: World Nuclear Association

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14 www.PowerEngineeringInt.comPower Engineering International November 2015

Nuclear focus

Hinkley Point C goes ahead in the UK: “The

more countries that are building nuclear

power plants, then the better the public

understanding of nuclear power will be.

Having a reliable, cheap baseload that has

a zero-CO2 footprint is more beneficial than

having concerns that are not based on any

scientific or technical evidence.”

Simonov says that for the nuclear industry,

“the biggest challenge is public acceptance

and political will – and political will strongly

depends on public acceptance. Politicians

tend to follow that.”

And he adds that “what politicians should

be thinking is that when you build a nuclear

power plant you don’t just create a battery

that powers your homes – you create an

industry. You give a boost to social-economic

development. You create workplaces for the

people of a country.

“When we talk about selling a nuclear

power plant, we stress that what you are

buying is a kilowatt-hour of electricity at a very

low cost for 60 years, with very little influence

on the commodity price.”

Simonov later spoke at a conference

session at POWER-GEN Asia and told delegates:

“Such countries as Thailand, Indonesia,

Malaysia and Vietnam are among the world’s

leaders in industrial production growth, and

consequently in power consumption. Nuclear

power will allow these countries to not only

get the basic source of clean energy, but

also will allow them to reach a new level of

development in general.”

He reiterated his belief that if Japan

restarted its reactors it would be “a signal to

other Asian countries – first of all for ASEAN

countries – where, according to our estimates,

there can be built about 20 GW of nuclear

power capacity”.

“But that may happen only if these

countries will show an unambiguous political

commitment to the development of national

nuclear power programmes.”

Malcolm Grimston, senior research fellow

at Britain’s Imperial College, believes that a

new energy narrative is needed to overcome

the mixed messages from the nuclear industry

that have stymied public support.

Speaking at the recent World Nuclear

Symposium in London, he said that the

public can be left “deeply suspicious” when,

on the one hand, the industry says how safe

nuclear power is, yet on the other appears

over-cautious when dealing with radiation

protection. He added: “Although big

accidents occur, nuclear power has proved

to be one of the safest, if not the safest, large-

scale ways of generating electricity.”

He also criticized governments bent on

phasing out nuclear power, saying that “logic

and politics don’t necessarily go hand in

hand”, and added that science should be

pulled back into the debate.

“We entirely miss that most of the problems

come from a dysfunction between political,

public and scientific establishments which

had a more harmonious relationship 30 years

ago in the developed world, but might not last

in the countries where it still exists.”

To illustrate the point he referred to a recent

chemical explosion in China which left 200

people dead: “The Germans didn’t then go

out and close down their chemical industry.”

Grimston called for governments to “restore

the outcome of properly referred science to

its proper place in decision-making”, while

society should have a sensible debate about

how to manage scientific uncertainty.

“We have no concept of what power

outages are like – we are left with anodyne,

cuddly phrases such as ‘the lights go out’,

when the reality of a blackout is literally

unimaginably awful.”

Skills gap

The WNA Symposium also heard from Callum

Thomas, chief executive of Thomas Thor

Associates, a global nuclear consulting and

recruitment firm. He said that the number of

nuclear experts in Europe in 2011 was around

80,000 and added that by 2020 that figure will

have dropped to 63,000.

He said that “the industry right now is

dependent on men between the age of 40

and 60” and added that the sector now had a

“once in a generation opportunity” to address

its skills set.

Mark Rauckhorst, construction vice-

president at Southern Company, has clear

ideas about the skill sets – and mind sets – that

are needed to get a nuclear power plant built.

Rauckhorst spoke about the Vogtle 3 and

4 units, which are currently under construction.

Once operational, they will make the plant the

first four-unit nuclear power station in the US.

“You cannot attempt a nuclear power

project by committee – you must have a

single leader.” In the case of Vogtle, he said

this leader was Buzz Miller, president of nuclear

development at Southern: “He has lived it

since the project was signed and he’s there

today.”

He added that it was vital to believe in –

and love – the potential of nuclear energy: “If

you don’t have a passion for nuclear, then I

don’t know how you will weather all the storms

that you will face.”

Rauckhorst said that it was essential that

the nuclear industry kept evolving its skills set:

“The skill sets that are needed today will be

different from the skill sets of tomorrow.”

And he added that the perfect workforce

was a mix of “grey beards and young guns”.

Visit www.PowerEngineeringInt.com

for more information

Mark Rauckhorst at Vogtle nuclear plant in the US

Credit: Southern Company

1511PEI_14 14 10/26/15 3:46 PM

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16 www.PowerEngineeringInt.com

Nuclear Focus

Power Engineering International November 2015

Work is finally poised to start on Hinkley Point C, the first new nuclear plant built in the UK for a generation. Kelvin Ross gets reaction to the pact between EDF and China General Nuclear and also finds out what the project will mean for the UK

The signing of a deal between EDF

and China General Nuclear Power

Corporation on Hinkley Point C is

almost the final piece of the new

nuclear jigsaw that the UK has

been trying to put together for a

decade.

It was Tony Blair who set the ball rolling in

2005 by announcing an energy review which

would consider the possibility of a new nuclear

plant. By 2007 the plan for a new reactor at the

existing Hinkley Point plant in Somerset was on

the table and EDF said that those of us living in

the UK would be cooking our 2017 Christmas

dinner on electricity from Hinkley.

Well, those hoping for some atomic

turkey for their festive lunch next year will be

disappointed, as Hinkley is now scheduled to

be online in 2025, but nonetheless, the deal

is (pretty much) done, and having been

told for the past 18 months that the project

was “shovel-ready”, those shovels should be

digging by the end of the year.

A final investment decision from EDF to go

ahead with the plant – which is expected to

provide 7 per cent of Britain’s electricity – is

now pretty much a formality following the

China pact, which sees EDF own 66.5 per cent

of the plant and CGN 33.5 per cent.

China General Nuclear Power Corporation

(CGN) will make its investment in the UK

through a new company called General

Nuclear International (GNI). EDF, without ever

reducing its initial stake below 50 per cent, still

intends to bring other investors into the project

at a later date.

UK Energy Secretary Amber Rudd said

on the day of the Chinese deal that “the UK

is open for business and this is a good deal

for everyone – Hinkley Point C will continue

to meet our robust safety regulations and

will power nearly six million households with

low-carbon energy”. CGN chairman He Yu

said that the deal was a “triple-win for the

existing nuclear energy partnership between

China, France and the UK”, while EDF Energy

chief executive Vincent de Rivaz said Hinkley

Point C and future nuclear projects in Britain

“will guarantee the UK the reliable, secure low

carbon electricity it needs in the future”.

“Nuclear power will save customers

money compared with other energy options

and provide a huge boost to British industrial

strength, jobs and skills both in Britain and

abroad,” de Rivaz said, adding that the go-

ahead for Hinkley was “good news in the fight

against climate change”.

The operators of Hinkley Point C have

negotiated a contract for difference with the

UK government for the electricity generated

by the plant. That price is £92.50 ($142)/MWh

for 35 years, roughly double the current market

price of power – or £89.50/MWh if a final

investment decision is taken on a subsequent

new EDF reactor at Sizewell nuclear plant.

This contract was approved by the

European Commission in October 2014

following a 12-month investigation. The

Commission has also recently approved the

UK’s waste transfer contract scheme, which will

apply to Hinkley Point C. This scheme means

that the full costs of decommissioning and

waste management associated with new

nuclear power stations are set aside during

generation and are included in the price of

the electricity.

Among the companies which have

signed final partnership deals for Hinkley

Point C are Areva for the steam supply system,

instrumentation and control; Alstom France for

the turbines and Alstom UK for services during

operations; Bouygues TP/Laing O’Rourke

for the main civil works and BAM Nuttal/Kier

Infrastructure for the earthworks.

The positive views

Prospect, the largest union for nuclear industry

employees, welcomed the signing of the deal.

Deputy general-secretary Garry Graham says

it is “a key milestone in paving the way to build

our low-carbon, secure energy future”.

“The building of the new Hinkley nuclear

plant will create 25,000 jobs in construction

and provide 1000 jobs in operation. These

will be high-quality skilled jobs that will create

a positive legacy for major infrastructure

projects for the future.”

World Nuclear Association director general

Agneta Rising is relieved to see the China

pact go ahead, and she says “we need to

see more countries learning from the UK’s

example to support nuclear energy among

a mix of generation technologies that are

fit for the future. Governments must act to

ensure that markets support new investment

in technologies such as nuclear. The UK is

showing one way this can be achieved.”

Tony Ward, Head of Power & Utilities at EY,

says the deal “is a vital injection of momentum

that can unlock billions of pounds worth of

investment in the UK’s energy infrastructure.

It also brings to an end a protracted period

of negotiation and uncertainty, and puts in

place the key remaining precursor to a final

investment decision.”

He adds that “with growing concerns in the

UK around the security of our electricity supply,

and a rapid retreat from some of the more

progressive renewable energy policies of

recent years, delivering low-carbon baseload

Hailing Hinkley

1511PEI_16 16 10/26/15 3:46 PM

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18 www.PowerEngineeringInt.comPower Engineering International November 2015

Nucleear Focus

capacity at scale is a key step in securing

the UK’s energy future, as well as embedding

thousands of highly skilled UK jobs, economic

activity and industrial and export potential.”

Dr Jenifer Baxter, Head of Energy and

Environment at the Institution of Mechanical

Engineers, agrees. “Nuclear is currently one

of the least CO2-intensive ways to generate

baseload electricity. If we are to secure the UK’s

energy future, while at the same time meet a

challenging emissions target, nuclear must

play a part in the electricity mix, in addition

to gas generation and renewables.” But she

adds that “while it is important to look to secure

future energy supplies, the government also

needs to encourage significant investment in

the whole nuclear lifecycle”.

“We still need proper research and

development into methods for recycling and

maximizing the energy returns from nuclear

waste. We haven’t yet found a way of dealing

with the large stockpile of nuclear waste at

Sellafield, which is set to include an estimated

140 tonnes of plutonium by 2020. It is clear the

UK has been too slow to address this issue.

Long-term deep geological disposal offers a

potential solution; however, around 20 years of

testing is required in the UK for this approach

to be used with confidence and we are yet to

start this process.”

Environment group Greenpeace is,

unsurprisingly, not a fan of nuclear or the

Hinkley project. Its UK chief scientist Dr Doug

Parr said of the EDF-China pact: “With this

deal [UK chancellor] George Osborne is not

so much backing the wrong horse as betting

billions of consumers’ money on a nag

running backwards.

“There’s no end in sight for the nuclear

industry’s dependence on billion-pound

handouts whilst the renewable sector is on the

verge of going subsidy-free. Backing the former

and punishing the latter makes no economic

sense whatsoever. Our grandchildren will one

day wonder why their bills are propping up a

foreign-owned, outdated and costly nuclear

industry instead of supporting cutting-edge

UK firms producing cheap clean energy.”

...And the backlash

Pushing ahead with Hinkley sets the UK on a

nuclear newbuild path unlike any elsewhere

in the world. The government has identified a

further seven reactor sites it wants to develop,

including another by EDF at Sizewell, one at

Bradwell which could be built by the Chinese

using their own technology, and Moorside,

which would be the biggest nuclear plant in

Europe.

The government is debating closing all of

its 12 coal-fired power plants by 2023 at the

same time as it’s facing a squeeze on supplies.

EDF’s 1.2 GW Sizewell B plant is the only one of

the nation’s current 15 reactors scheduled to

generate beyond 2023.

The building of a fleet of new nuclear plants

was originally put on the table as a means of

addressing decarbonization, but since then

the European energy sector has changed

radically. The buzzword is flexibility and nuclear

– while highly reliable and not subject to

swings in fuel price – is pretty inflexible.

All of which would still make Hinkley Point

C a sensible plan if it and other future nuclear

plants are intended to be the long-term –

and don’t forget that with nuclear plants we

are talking very long-term – partner to an

expanding utilization of renewables. But the

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www.PowerEngineeringInt.com 19

Nuclear Focus

Power Engineering International November 2015

UK government is facing a backlash from some high-profile figures over

its recent policy decisions on renewables.

Since the General Election in May, the new Conservative government

has ended subsidies for onshore wind, because it believes there are

enough such wind farms already in Britain – Rudd has said that “we

could end up with more onshore wind projects than we can afford”.

In September the government also vetoed plans for the Navitus Bay

offshore wind farm – the first offshore project not to be granted consent.

Whitehall has also dropped support for new large-scale solar farms

and is consulting on plans to cut subsidies for smaller installations on

households, schools and community buildings.

The Solar Trade Association says around 27,000 jobs could be

at risk as the solar industry’s 3000 firms face the cuts. Trade body the

Renewable Energy Association (REA) says it has tracked 11 major policy

changes which it says is having – or will have – a negative impact on the

British renewable energy industry.

James Court, the REA’s head of policy, said the policies represent

“the UK turning away from renewables, which is surprising given the

extraordinary decline in costs and increases in technological efficiency

that have been achieved over the past five years. The government,

frustratingly, seems intent on tripping up the industry within sight of the

finishing line.”

Last month, the United Nations’ chief environment scientist slammed

the UK government for its cuts to renewables support. It is unusual for

the UN to single out a particular government for criticism, however Prof

Jacquie McGlade branded Britain’s actions as “perverse”.

She said that as more and more countries around the world were

adopting and spending money on renewable energy objectives, the

UK was going in the opposite direction. And she added that recent

reductions in wind and solar subsidies, coupled with tax breaks for

oil and gas, sent out the wrong message ahead of next month’s UN

climate summit in Paris.

In an interview with the BBC, Prof McGlade said: “What’s disappointing

is when we see countries such as the United Kingdom that have really

been in the lead in terms of getting their renewable energy up and

going – we see subsidies being withdrawn and the fossil fuel industry

being enhanced.” She said the UK was sending “a very serious signal – a

very perverse signal that we do not want to create”.

Last month John Cridland, head of the Confederation of British

Industry (CBI), also said investors would be put off Britain by its latest

policy decisions. He said that the “green economy is an emerging

market in its own right, brimming with opportunity” but added that “with

the roll-back of renewables policies and the mixed messages on energy

efficiency, the government risks sending a worrying signal to businesses”.

In September, the UK dropped out of the top ten countries for

renewable investment in an annual ranking compiled by analysts at EY.

Ben Warren, EY’s Energy Corporate Finance Leader, said that

investors are “trying to make sense of what seems to be policymaking in

a vacuum, lacking any rationale or clear intent. Worryingly, this trend of

inconsistent policy tinkering could also sour investor confidence in other

areas, such as new nuclear, carbon capture and storage and shale

gas, as well as offshore wind.”

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Since 1972, the Neurath RWE power

plant has produced electricity in

Grevenbroich-Neurath, Germany.

In 1976, the plant was expanded

to five block units – three of

300 MW and two of 600 MW.

These units are fueled by lignite from the

open pit mines at Garzweiler and Hambach.

In August 2012, after an investment of

€2.6 billion ($2.95 billion), RWE Power put

two additional power plant block units of

1100 MW each and improved systems

technology into operation.

So with its production of more than

4200 MW, the power plant covers more than

10 per cent of the installed output by RWE

Power AG-owned plants.

However, units F and G revealed a need

for improvement. The coal feeders to the

coal pulverizers did not work satisfactorily

and caused high costs for downtime

and maintenance. During an inspection

demanded by the customer, Aumund

engineers diagnosed that the pan conveyors

installed as coal feeders would fail completely

in the near future due to existing deficiencies

and foreseeable subsequent damage.

Such a breakdown would disrupt power

production in block units F and G, because

the lignite is discharged from the coal

bunkers onto the pan conveyors operating

as coal feeders. Two individual pan conveyors

transport the lignite to the coal pulverizers,

where the coal is ground to dust. There are four

pulverizers from where the ground lignite dust

is blown into each boiler. So, in total, the two

boilers of block units F and G are supplied with

fuel by eight pulverizers and 16 pan conveyors.

Construction-related wear

The coal feeders were designed as chain pan

conveyors with two chains each. Due to this

design there was an increased wear on the

chain links, causing a differential lengthening

of the two chains.

The pans of the conveyors got twisted and

rose from their assemblage. The protruding

pans acted like smoothing planes and

abraded the material being conveyed.

Besides, since the pans did not overlap, the

material was trickling in between them and

causing wedged pans.

Portions of the material trickled into the

casing and onto the feedback conveyor. The

wedged pans caused the material to bulge

over the sideboards of the coal feeder and to

trickle into the casing and onto the feedback

conveyor as well. The spillage conveyor was

actually designed to feed the spilt material

back into the material transport only. The

excessive material feeding caused heavy

wear. Occasionally the spillage or cleaning

Power Engineering International November 2015

Case study

The conveyor conversion challengeA complex project to convert coal conveyors was made more challenging by the need to carry out the work while the plant was fully operational, write Peter Müller and Erwin Last

Arched belt conveyor as coal feederCredit: Aumund

1511PEI_20 20 10/26/15 3:46 PM

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22 www.PowerEngineeringInt.comPower Engineering International November 2015

Case study

conveyor transported more material than the

main pan conveyor. In that way, continuous

heavy wear on all moving parts of the

machines evolved.

Due to the tight constructive situation and

the high costs for new machines, Aumund

Fördertechnik won the contract for conversion

of the conveyors. The company was tasked to

optimize the existing pan conveyors. The order

included design, construction and supervision

of installation as well as regular reviews and

maintenance after conversion.

First the existing conveyors had to be

retrofitted by Aumund’s conversion specialists

during a rotational plant downtime while

the furnace kept working. Thus a general

overhaul of the heavily worn conveyor during

an unscheduled boiler downtime, a medium-

term necessity under the circumstances,

could be avoided.

Conversion during operation

The most demanding phase of the project

was at its very beginning. After taking the

measurements of the installation and an

analysis of the problems, a pre-design was

drawn even before an offer was written. The

pre-design became part of the offer.

After receiving the order, the detailed

design was drawn and the project planning

set up. Already at this point, the planning of

the parts transport to the machines to be

converted and the installation sequence was

decisive for the execution of the project. Only

certain routes of transportation were usable,

since a number of routes were blocked by

Installation of new pan conveyors

Credit: Aumund

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www.PowerEngineeringInt.com 23

Case study

Power Engineering International November 2015

maintenance and repairs of other parts of the power block unit. This

especially had to be taken in consideration for delivery of the new parts

to the coal feeders just in time.

Structurally, the casings of the original machines were preserved as

fa as possible, and reinforced. On the outside sections of the machines,

transmissions, engine and bearings were re-utilized.

On the inside, however, all components including the drive shafts

were replaced by Aumund machine parts of the BPB 250 line. The

spillage conveyor was redesigned and its tensioning and drive axes

were exchanged. Thus the drive shafts of the spillage and main

conveyors were positioned on the same side of the coal feeder in

the end – an advantage for accessibility and maintenance of these

decisive components.

One of the few changes to the casing was the installation of a

maintenance opening for better access to the drive shafts. As a

consequence of the change to the drive shafts, the tensioning stations

of both conveyors had to be adapted to the new design.

The feedback conveyor was stabilized by conversion from two-strand

to three-strand design. Originally it was built from two chains with a flat

steel bar in between for pushing the feedback material along. Due to

the increased material feeding because of the leaking main conveyor,

the chains lengthened here as well, and the flat steel bars started

bending. An additional third chain strand now acts as a stabilizer in a

cross direction.

Longitudinal stabilization was achieved by increasing the preload

through installation of additional axes. Due to their own weight, the

chains were sagging between the individual axes. However, between

the axes the chain is self-tensioning, so the distance between the axes

was too great. It was decreased by installation of additional axes.

Also, one of RWE Power AG’s specifications was to build the coal

feeder pressure tight up to one bar. This specification was not met by

the original machine. Aumund stress analysts calculated the installation

anew, and based on these calculations, pressure tightness according to

specification was achieved in the course of the conversion.

For the conversion, RWE focused on pan conveyors with an average

performance of 150 tonnes/hour. During peak times, the conveyors can

transport 200 tonnes/hour. One pan conveyor transports sufficient lignite

to produce about 1 MW. While arranging the new machines within the

existing casings, some constructive tricks became necessary to achieve

the conveying performance needed: Aumund converted the machines

Optimizing the conveyor

Credit: Aumund

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24 www.PowerEngineeringInt.comPower Engineering International November 2015

Case study

with welded pan conveyors, which had to be

adapted very individually for the connection

to the hopper.

The pans of these pan conveyors overlap in

the same way as a long brick laying structure.

This prevents the material from trickling

between the pans and blocking them, or from

trickling trough between them.

While equipping the pan conveyors with

new chains, the designing engineers selected

Aumund’s AU6052 chain. With a significantly

higher chain safety than is normally chosen for

comparable uses, notably higher durabilities

can be achieved.

Limited space challenge

The Aumund conveyors with a standard width

of 200 to 300 mm had to be built into the

extremely cramped space. Simultaneously

with an adaption and a complete exchange

of the former material feed, the conveyors

were equipped with a new surface. Due to

the limited space available between material

feed, toe board and rollers on one side and

the outer edge of the casing – pressure tight

up to one bar – on the other side, a special

construction had to be realized. The conveying

speed was given.

Optimizing the conveying performance

was only possible through changes to the

cross section of the conveying elements. The

cross section results from the width of the

conveyor and the height of the toe board.

The height of the toe board was increased,

resulting in the need to lower the feedback

conveyor. In addition, a smaller sprocket

wheel was used. Literally every millimetre of

the available casing’s interior was used. In

some instances the usual minimum distance

between conveyor and casing wall was

undershot. Because of the negative pressure

loading of the coal pulverizers, special

attention was given to a better sealing of the

entire casing to avoid air leaks.

Special construction had to be realized

Credit: Aumund

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www.PowerEngineeringInt.com 25

The material loads underneath the

bunker chutes were brought under control by

installing a baffle beam. This beam deflects

the shearing forces caused by material being

fed onto the running pan conveyor into the

structural steel work. The use of new carriers

between the chain strands, the lowering of

the tensioning axis and the installation of a

new sprocket wheel made the conversion

perfect.

To complete installation and put the

equipment into operation within the planned

timeframe, Aumund developed an installation

schedule specifying in detail each step and

the manpower needed for each step. All work

was completed on time. The supervision of

the installation was undertaken by up to four

Aumund supervisors on site.

In two shifts, they supervised the expert

execution of the conversion by the client’s

installation company. At times, the installation

company worked on different parts of the

machine simultaneously. In these situations at

each site, a supervisor was present.

Besides supervising the installation, it is the

duty of the supervisor to be the contact person

for the foreman of the installation company

and for the client’s project leader. Certainly,

the special challenge of this project was the

co-ordination within the fixed time frame.

After 12 months of operation, the converted

coal feeders were inspected under Aumund’s

Preventive Maintenance Service (PREMAS)

without tracing any new unusual wear. That

proves the machines to be ready for long-term

use at present and in future.

With precise time targets and cramped

space conditions, the coal feeders were

optimized so that they met expectations

for the first time. The conversion by the

Aumund specialists proved to be much more

economical for the client than buying a new

machine.

Through professional and detailed project

planning it was possible to stay within schedule

and budget, despite the very complex task at

hand.

Peter Müller is Senior Sales Manager and

Erwin Last is Manager Field Service at Aumund

Fördertechnik GmbH, Rheinberg, Germany.

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Case study

Power Engineering International November 2015

Every millimetre of available space was used

Credit: Aumund

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26 www.PowerEngineeringInt.comPower Engineering International November 2015

Condition monitoring

Q&A

PEi: What is the difference between

condition monitoring technology in larger

power generation plants vs smaller or

on-site generation applications?

JE: The technology is very much similar from

a condition monitoring perspective. The

difference is primarily one of scale. A large

combined-cycle plant will have hundreds of

sensors and thousands of data tags: we’re

trying to do the same thing as in a small

on-site generation facility, which is to optimize

your maintenance and improve the reliability,

availability and performance of your asset.

Much of the technology employed is the

same, but there tends to be more of it in

larger plants.

The difference would be, if I have a

reciprocating engine, part of an on-site power

generation plant, and compare it to a large

combined-cycle gas turbine, some sensors will

be different on those two pieces of equipment

because the size and scale is different.

You tend to have more sensors on a larger

machine. Whereas in a large combined-cycle

power plant you may be integrating 500+

sensors, in a small facility there may be 10

sensors.

A small facility may have traditionally

employed a walkaround data collection

programme, but the larger you get, the more

automated you get. Primarily the technology

varies in scale, and in the key performance

indicators.

In a district heating plant you will have a

boiler, which is consistent with a pure power

generation plant. Downstream of the boiler,

to optimize for a district heating application,

you’ll have different sensors.

PEi: What has been the biggest technology

change in condition monitoring systems

during your career?

JE: Automation and tremendous improvement

in computing technologies. That’s what’s

providing most of the opportunities today.

Even in the last five years, the cost of

computing technology has come down

tremendously and capability has gone up

tremendously, which allows us to deploy much

more automation.

Things that used to be manual calculations

done by an engineer in a plant are now

entirely automated, and this has really allowed

much more capability to advance in this area

of condition monitoring – what might have

been primarily focused on things like anomaly

or failure detection in the past has now moved

beyond that to maintenance optimization

and optimization outcomes such as reliability

or availability.

Failure detection is the standard at this

point, with much work focused in the area

of expert software, which is how you go from

detection to insights and actions.

GE has been making significant

investments in software and analytics across

our whole portfolio. We’ve invested over

$1 billion in software development in the last

few years.

The condition monitoring space is focused

on three areas. The first layer is an asset

performance management software set that

includes failure detection plus integration into

maintenance automation, so you can link the

two, from failure to maintenance actions.

The second layer is operational optimization

software. Once you have optimized around

the asset and its maintenance, now you

can start to optimize around how the plant

operates.

How does the customer run that plant,

and its key performance indicators – reliability,

performance, steam generation – whatever is

unique to that plant.

The third layer is business optimization: how

do you optimize the profitability of a power

plant? When you get to that level it requires

heavy involvement from the customer side,

so what GE has done is develop a software

framework that allows customers to input key

variables from their side and get feedback.

One of the significant things in the industry

is the move to the cloud, which allows us to

Condition monitoring is changing as computing technology evolves. We spoke with Justin Eggart of GE Power & Water about the future of the technology for power plant operators

Monitoring in the age of big data

1511PEI_26 26 10/26/15 3:46 PM

www.PowerEngineeringInt.com 27

Q&A

Power Engineering International November 2015

provide capabilities at a much lower-cost

model, a much more analytic-capable model:

cloud-based software as a service model, built

on the industrial platform Predix.

Inhibiting growth in the past, especially

with smaller applications, was getting the

customer to get ROI around the investment

model in condition monitoring technology.

With the move to the cloud, we are much

more capable at a lower cost.

As customers don’t have to invest in data

acquisition and computers and software for

each location or site, we can leverage that

across many customers so the cost model

comes down for each. And there’s been

a change in the model, so now the user,

instead of walking up to a piece of condition

monitoring equipment and looking at it, is

logging on to a web page.

Today we offer a cloud model (software

as service model) around monitoring and

diagnostics, improving capability, adding

more features and functionality as well as

analytics.

We’re releasing two to three analytics

per week around anomaly detection and

optimization of maintenance practices. It’s

easier to add capabilities and update with

the cloud model. Diagnostics are typically

focused on detecting an issue; analytics are

focused on also, in an automated fashion,

offering insight into what’s causing that issue

and what you should do about it.

From a customer perspective, traditional

OEMs have offered some level of condition

monitoring capability with their equipment,

or through third parties. Many customers

are asking today for an integrated condition

monitoring framework across the entire power

plant or backup generation system.

They want a full view, not just an individual

view from component. This is an area that GE

is working in now: how do we provide that level

of technology across all equipment, whether

GE or non-GE, so that the customer has a

view of the maintenance requirements and

condition of the equipment across the whole

enterprise.

Our customers, the operators of power

plants, have been asking not only GE but

everybody for this capability. We’re seeing

some of other OEMs looking to offer those

kinds of multi-vendor services – also control

system vendors.

Two things distinguish GE: experience

across a wide range of power generation

equipment, not only GE equipment but

interfacing with other vendors’ equipment;

and the tremendous amount of data

collected from this equipment, which helps us

when then combined with some investment

in software, analytics and automation. Some

smaller traditional condition monitoring

companies may not have that level of

expertise and investment.

PEi: What changes do you foresee in the

condition monitoring space over the next

five to 10 years?

JE: In the next five years there will continue to

be more sensor technology embedded into

equipment. As sensors become smaller and

lower-cost, more OEMs will embed more sensor

capability, which will generate more data to

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28 www.PowerEngineeringInt.comPower Engineering International November 2015

help do condition monitoring. The challenge

will be not drowning in that data. Smaller users

without large engineering staffs on-site may

struggle to use all the data available.

The next generation of condition

monitoring will use cloud-based capability. It

will stream data into the cloud and provide

software and analysis capability to those users

at a much more comprehensive level than in

the past.

The technology is changing tremendously;

there is so much capability and investment in

the whole space of software analytics and big

data today.

It’s likely that in the next 10 years we will

have extraordinary automation available. A

piece of power generation equipment on-

site will be tweeting messages to the world

Q&A

about its operation. Reliability and availability

will continue to move up, and performance

will be able to be optimized to the particular

requirements of an individual site.

PEi: Aren’t there increased cybersecurity

risks involved as more equipment comes

onto the Internet of Things?

JE: There have to continue to be significant

investments in cybersecurity – all customers

are concerned about the risks.

The good news is that, just as technology

is advancing on the software side, it is also

advancing quickly on the security side, driven

by a consumer market which is often ahead

of the industry market from a trying-new-things

perspective.

We will also see tremendous improvements

in cybersecurity capability that will have to be

embedded in all of these devices.

We do offer on-premise capability but,

while we offer that, we encourage customers

to take advantage of the cloud.

On-site condition monitoring involves

similar capabilities but tends to be more

expensive and slower to take advantage of

updates. We do it that way for two reasons:

many users traditionally used on-site condition

monitoring technology, and so it’s a paradigm

shift to move to the cloud so they’re more

comfortable with on-site. The other reason is

the risk around cybersecurity. Many customers

are not comfortable yet in how that risk is

managed. However, there are advances in

activity solutions: for example, we deploy both

internet-based connectivity as well as cellular

technology as backup. There will continue

to be a need for some level of capability at

site, but anything critical for the site will have

backup connectivity capabilities.

Justin Eggart is General Manager, Fleet

Management, Power Generation Services at

GE Power & Water. www.ge.com

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for more information

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RENEWABLE ENERGY WORLD

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30 www.PowerEngineeringInt.comPower Engineering International November 2015

Flue gas desulfurization

Boosting SO2 removal efficiency

New SO2 emission regulations in the US and EU require some utility and power producers to retrofit new flue gas desulfurization units to existing

plants. Michael T Hoydick and Hans Jansson discuss cost-effective solutions to achieve these new emission standards

Acid gas removal efficiency

(mainly SO2) in a power

plant’s limestone-based wet

flue gas desulphurization

(WFGD) system absorber is

governed by two processes:

the absorption of SO2 via gas/liquid contact

and the rate at which the scrubbing liquor

neutralizes the liquid phase acids collected.

Improving either process generally enhances

SO2 capture.

The rate of SO2 absorption into the

absorber liquor is controlled by the mass

transfer coefficient, the surface area available

for mass transfer, and the difference between

the SO2 partial pressure in the flue gas and

the vapour pressure of SO2 at the gas/liquid

interface.

WFGD system designers can generally

influence only the contact surface area and

the dissolved alkalinity in the absorber slurry,

which, in turn, determines interface vapour

pressure. The surface area for mass transfer is

determined by the selected liquid-to-gas ratio

(L/G) in conjunction with the spray nozzle

droplet size distribution.

Improving SO2 removal performance for

existing open tower designs is generally limited

to increasing L/G ratio or creating smaller

droplet sizes via higher pressure drop nozzles,

either of which increase auxiliary pump power.

Additionally, smaller spray droplet sizes are

only marginally effective due to significant

droplet coalescence within the spray zone of

the tower.

Flue gas/slurry contact can be significantly

enhanced with the use of internal contacting

devices. In the past, packing material has been

used but has proven unreliable in limestone

WFGD systems and is not favoured by the

US utility industry. Further development has

produced the dual flow tray (DFT) technology

that has found

favour in US utility

applications for over

30 years for new and

retrofit applications.

In general, the DFT

consists of one or more levels of perforated

plates that span the entire absorber cross-

section. The DFT’s SO2 removal efficiency is

improved due to its increased and more

effective gas-to-liquid contact area compared

to a typical open tower design that relies only

on spray droplet surface area.

DFTs improve WFGD performance

by improving flue gas distribution at the

beginning of the gas-to-liquid contact zone,

which takes full advantage of the L/G provided

by the slurry sprays. Flue gas distribution in a

DFT absorber is markedly better than in open

spray tower WFGDs designed with side flue

gas entry, where momentum pushes the flue

gas to the far wall, thus delaying optimal flue

gas/absorber liquor contact. For open spray

tower designs, optimal flue gas distribution

doesn’t occur until the gas is well into the

absorption zone.

DFTs also provide very effective gas-to-liquid

contact. Flue gas flowing upward is intimately

mixed with the falling absorber slurry. The flue

gas velocity travelling through the tray holes

causes liquid resistance, thus forming a froth

layer on the tray. The froth layer, typically

150 mm-–300 mm deep, provides additional

Open Spray Tower DFT Tower

73% within 5% of average velocity 99% within 5% of average velocity

96% within 10% of average velocity 100% within 10% of average velocity

A Dual Flow Tray at its 24-month inspection

Credit: Amec Foster Wheeler

1511PEI_30 30 10/26/15 3:47 PM

www.PowerEngineeringInt.com 31Power Engineering International November 2015

Flue gas desulfurization

mass transfer surface area and contact

time in the absorption zone. Each tray level

provides an additional one to two seconds of

contact time in the absorption zone. Full scale

testing of absorber towers with and without

DFTs confirm comparable performance for

DFT absorbers at L/G ratios 15–30 per cent

below open tower designs.

Absorber slurry liquid phase chemistry

also plays a substantial role in the overall

performance of the wet FGD unit. The

absorber slurry needs sufficient liquid phase

alkalinity to quickly neutralize the absorbed

acid to maintain the driving force necessary

for SO2 capture.

In limestone-based systems, the alkalinity is

produced from dissolved calcium carbonate.

The operating pH is a general indicator of the

alkalinity of the absorber liquor. The higher the

pH, the more dissolved alkalinity is present.

As the absorber slurry falls through the

absorber tower, the pH of the solution falls as

the acid is absorbed. For an absorber with a

reaction tank pH of 5.7, the slurry pH falls to

~3.5–4.5 on the DFT. Since limestone dissolution

rate is proportional to the pH, the lower pH

on the DFT significantly increases limestone

dissolution rates and provides additional

dissolved alkalinity needed for further acid

neutralization.

Newbuilds and retrofits

A comparison between a typical open spray

tower design and an equivalent DFT design

No Dual Flow Tray, Heavy SprayDownstream of Dual Flow Tray Position

Downstream of Dual Flow Tray Position

With Dual Flow Tray, Heavy Spray

Velocity: Magnitude (ft/s) Velocity: Magnitude (ft/s)

0.00000 2.3000 4.6000 6.9000 9.2000 11.500 0.00000 2.3000 4.6000 6.9000 9.2000 11.500

A computational fluid dynamic flow model shows the improved gas flow distribution of an existing

Amec Foster Wheeler DFT installation over a comparable side entry wet FGD design. The flue gas

distribution is illustrated at 1.5 m above the inlet duct

Credit: Amec Foster Wheeler

Description Tower Design

Open Spray DFT

Absorber diameter, m 15.0 15.0

Recycle tank retention, min. 5.0 5.0

Recycle tank height, m 10.1 7.4

Number of recycle pumps (operating +spare)

3+1 2+1

Recycle pump flow, m3/hr 6,100 6,670

Number of trays 0 1

Overall tower height, m 30.3 26.1

Overall liquid recirculation rate, m3/h

18,340 13,340

Absorber auxiliary power, kW 1,800 1,310

Pressure drop, kPa 1.0 1.4

Table 1. Performance comparison between similar open tray and DFT towers in a wet FGD installed on a 500WM coal-fired unit. The fuel sulfur is 1.2% and the systems are designed for 98% SO2 removal. Source: Amec Foster Wheeler

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32 www.PowerEngineeringInt.com

Flue gas desulfurization

Power Engineering International November 2015

for a theoretical 500 MW unit illustrates the

performance and equipment size differences

between absorber types (see Table 1, p31).

Note that the DFT tower is smaller in size than a

comparable open tower because of the lower

L/G of the DFT absorber, as is the overall liquid

recirculation rate. Since limestone dissolution

and gypsum crystallization require a minimum

retention time in the recycle tank, a lower L/G

also allows for a smaller recycle tank. Because

a DFT tower requires a lower L/G, it is often

possible for a DFT tower to be designed with

one less operating spray level and recycle

pump.

In this comparison,

two operating spray

levels are required for

the DFT design while

three operating spray

levels are needed

for the open tower

design. Note that

one less spray level

reduces the overall

absorber height by

over one metre, which

may reduce absorber

shell thickness

and foundation

requirements, and

therefore overall

installation costs. The

reduced absorber

height will also

reduce piping and

electrical installation

costs. Finally, the DFT

can be used as a

maintenance platform

during construction,

and later as an

inspection platform

for the upper absorber

sections.

Performance upgrades

There are several techniques available to

improve the performance of an existing

wet FGD system. The easiest and most cost-

effective is to operate the system with a higher

pH.

The typical limestone-based system

operates at pH levels between 5.0 and 5.7.

A higher operating pH will improve SO2

removal efficiency up to a limit. Slower sulfite

to sulfate oxidation rates and high limestone

stoichiometry produce unacceptable

gypsum quality when pH levels exceed 6.0.

Poor oxidation may also produce gypsum

scaling, which is not acceptable for long-term

operation.

Physical equipment changes are

usually the upgrade path. Adding wall rings,

improving flue gas or liquid spray distribution,

smaller spray droplet spray nozzles, double

spray nozzles, more L/G, or the addition of one

or more DFTs, alone or in concert, are typical

open tower upgrade options.

Wall rings will marginally improve the

efficiency of a properly designed wet FGD

system. Higher-pressure spray or double

spray cone nozzles will produce smaller spray

droplets that should help efficiency, in theory.

However, droplet coalescence limits the

performance improvement.

The remaining option for significantly

improving the performance of an existing

open spray tower is adding L/G, in conjunction

with spray header modification. Unfortunately,

increasing L/G in an existing absorber is

normally a challenge.

Most sites do not have adequate floor

space for additional recycle pumps and not

enough tower height for additional spray

banks. Modifications to existing pumps are

possible, however, recycle pump efficiency will

likely be compromised and recycle pipe flow

velocities could exceed design limits. Recycle

tank retention times must also be considered

when adding additional L/G. These solutions,

although possible, generally require outages

of several months and have high construction

costs.

Normally the best physical upgrade option

is the addition of one or more DFTs below

the bottom spray bank. Many open towers

have adequate space between the lowest

spray bank and the inlet ductwork to allow

installation of a new DFT level. Approximately

3.0–3.5 metres of vertical height is generally

required. An added benefit of the DFT is that

The DFT can be used as a staging platform during construction

Credit: Amec Foster Wheeler

www.cd-adapco.com

info@cd-adapco.com

COMBUSTORSGAS TURBINES

GENERATORSCOMPRESSORS

DISCOVER BETTER DESIGNS.

FASTER.MULTIDISCIPLINARY SIMULATION FOR CLEAN, EFFICIENT ENERGY AND

ECONOMICAL, RELIABLE POWER

VISIT US AT POWER-GEN INTERNATIONAL AT

BOOTH 6822

For more information, enter 20 at pei.hotims.com

1511PEI_32 32 10/26/15 3:47 PM

www.PowerEngineeringInt.com 33

Flue gas desulfurization

Power Engineering International November 2015

Open Spray Chamber Absorber

Dual Flow Tray Absorber

Liquid to Gas Ratio, gpm / 1000 acfm

80

82

86

88

90

92

94

96

98

84

100

90 100 110 120 130

The Elmer Smith Station in Kentucky, US upgraded an existing open spray chamber

absorber with one DFT, thereby increases the wet FGD’s SO2 removal efficiency from

93 per cent to 98 per cent

Credit: Amec Foster Wheeler

lower pressure drop nozzles can be used

(spray nozzle droplet size is less critical for

a DFT) to artificially increase L/G without

modification to the existing recycle pump and

recycle piping systems.

Case study

Amec Foster Wheeler’s predictive models

indicate that a DFT can improve mass transfer

by as much as 50 per cent (1.5 times) from

the current design of open tray spray towers.

In many instances, the addition of one or

more DFTs can achieve desired performance

objectives without other modifications.

For even higher levels of performance, a

DFT addition in conjunction with spray nozzle

modification and pH adjustment is an option.

The liquid holdup and low pH on the DFT

will allow higher operating pH levels without

affecting limestone stoichiometry or gypsum

quality.

A DFT retrofit of an existing open spray tower

was recently completed at the Elmer Smith

Station in the US state of Kentucky, owned by

Owensboro Municipal Utilities (OMU). Amec

Foster Wheeler supplied two open spray

chamber absorbers that began operation

in 1995. In 2008, the existing absorber towers

were operating at 93 per cent SO2 removal

efficiency at an operating pH level of 5.7 when

OMU decided to upgrade its system to reach

98 per cent efficiency.

The five-point efficiency increase

represented an increase in absorber mass

transfer from 2.7 NTU to 3.9 NTU, a 42 per cent

increase. Amec Foster Wheeler’s analysis found

that adding one DFT level would increased

the overall absorber NTU by around 50 per

cent, without any additional modifications to

the existing recycle pump or spray header

system.

Kevin Frizzel, Director of Power Production,

notes: “The addition of a Dual Flow Tray level

on our two scrubbers was a very cost-effective

method for OMU to maintain our commitment

to high environmental standards.”

Operational testing of the completed DFT

upgrade in 2009 confirmed the expected

performance increase was achieved without

changes to the operating pH or limestone

stoichiometry.

Michael T Hoydick is senior technology

manager, FGD Systems, Amec Foster Wheeler,

USA. Hans Jansson is Director, Marketing and

Business Development, Amec Foster Wheeler,

Europe.

Visit www.PowerEngineeringInt.com

for more information

ACT WITH AGILITY

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1511PEI_33 33 10/26/15 3:47 PM

34 www.PowerEngineeringInt.comPower Engineering International November 2015

POWER-GEN Middle East

Reflecting on an expanding energy mix

POWER-GEN Middle East in Abu Dhabi put in the spotlight the region’s plans to diversify its power generation portfolio, writes Kelvin Ross

The Middle East has some

unique energy challenges and

opportunities.

For the Gulf countries that are

abundant in oil and gas, there

is an understanding that those

riches are not limitless, and if they want to keep

them for export then they need to diversify their

domestic energy mix away from fossil fuels.

There is also a drive among some

governments – most notably the United Arab

Emirates – to embrace clean energy and

exploit the potential of their own renewable

resources, particularly solar.

At POWER-GEN Middle East in Abu Dhabi

last month (October), the evolving energy mix

of the region was debated in the conference

rooms and on the exhibition floor.

The event opened with a speech from

the UAE Minister of Energy, H.E. Eng. Suhail

Mohamed Al Mazrouei, who highlighted his

vision for how he plans to alter his nation’s

power mix from fossil fuels to “eco-energies”.

He said that the UAE could expect a 9 per

cent increase in electricity consumption.

Stressing that the UAE needed to minimize

its use of natural gas, he said: “We need to

change the stereotypes of consumption –

we need to change our behaviour in power

consumption.”

He said that this should be done “through

using modern technologies” and added: “We

need to raise awareness among our sons and

daughters and be an example.”

The minister highlighted the effect that the

nuclear newbuild plant Barakah would have

once complete. All four units of the plant are

currently being built by a consortium led

by Korea Electric Power Co (KEPCO) and

comprising Samsung, Hyundai, Doosan and

Westinghouse, with the first unit expected

online in 2017.

The minister said that, once complete, the

plant would provide 5.4 GW of electricity and

make up 25 per cent of the UAE’s energy mix.

He said that Barakah – combined with the

growth in the UAE of solar power technologies

– would “minimize our use of natural gas”.

However, he also stressed that new

technologies “cannot rely on subsidies. They

do not encourage energy efficiency and

sustainability.”

The call for the Middle East to be at the

forefront of power innovation was also stressed

by Jamila Yousef Matar, director of energy

management for the League of Arab States.

She told the audience: “Arab countries

need to be active participants in the

development of the latest technologies, not

just recipients.”

Such development of new technologies is

a cornerstone of the work being carried out

by UAE clean energy company Masdar, and

one such innovation is the development of a

carbon capture project in association with the

Abu Dhabi National Oil Company (ADNOC).

Details of the project were given to

conference delegates by Masdar Clean

Energy’s associate director Yousif Al Ali.

He said that the project is located at a

factory of Emirate Steel and commercial

operations are expected to begin next year.

The CO2 feed stream from the Emirates

Steel plant, containing 90 per cent CO2, will

be transferred to a common compression

and dehydration facility at the project site in

Mussafah. The feed stream will be compressed

into dense phase, delivering an expected CO2

stream of over 98 per cent purity, through

50 km of the pipeline network to be injected

in an onshore field, operated by Abu Dhabi

Company for Onshore Oil Operations.

Ultimately, Masdar hopes to build a

national network that captures carbon from

power generation and industry and utilizes

carbon dioxide for enhanced oil recovery

instead of reinjecting natural gas into oil fields

to trigger oil flow.

A key aspect of the conference sessions

was a focus on project financing and the scale

of investment in power generation projects

around the world was put into numbers – and

they were massive numbers.

Shaheen Chohan of Industrial Info

Resources told delegates that global financing

for power projects stands at $6.5 trillion.

He said that out of this figure, the Middle

East and Africa accounted for $236 billion,

comprised of 1066 projects.

“This part of the world is a very big market,”

said Chohan, IIR’s vice-president of global

analytics.

And he stressed that such investment was

desperately needed, as the MENA region was

seeing “unprecedented demand”. He said

that 300 GW of new capacity was needed

across the Middle East and North Africa by

2020 and the region was expected to witness

Traditional Arabic-style buildings reflected in the cutting edge facade of a building at Masdar City.

Photo: Kelvin Ross

1511PEI_34 34 10/26/15 3:47 PM

www.PowerEngineeringInt.com 35Power Engineering International November 2015

POWER-GEN Middle East

6.7 per cent demand growth per year for the

next decade.

He broke down the MENA countries seeing

the greatest spending over the next year or

two, and top of the list by far was Saudi Arabia,

with spending of $35 billion, followed by Egypt

with $26 billion. Iran was third, the UAE fourth

and Kuwait fifth.

However, he added that Saudi, which

was “once one of the most attractive

markets in renewables”, was now seeing a

“deprioritization” of renewables and a pushing

back of their targets, in favour of a desire to

“utilize existing feedstocks, especially natural

gas”.

The UAE, he said, had the greatest diversity

in its energy mix, of which “at the forefront”

were nuclear and solar power, while Egypt

could be a “hot-spot new market. Its current

infrastructure is aged, there is much debate

about how much existing capacity can meet

demand and it is blessed with a new gas

find.”

Chohan said that a “part of the market

to start paying attention to” was that of new

projects with a capacity of between 1 MW

and 100 MW, as there is much potential in

this sector, particularly for power islands that

provide energy for industrial facilities.

On the exhibition floor, Chromalloy unveiled

a new joint venture it has initiated to provide

the Middle East with life-cycle gas turbine

engine servicing solutions.

The US company has teamed up with

Arabian Qudra – a Saudi Arabia-based service

provider of electrical equipment in power

and industrial plants – to form Chromalloy

Arabia.

The new venture will provide component

repair, new parts, field services, system

upgrades and long term service agreements,

as well as monitoring and diagnostic systems.

Chromalloy President Carlo Luzzatto said:

“Chromalloy Arabia leverages the innovations

and advancements of two leading energy

industry service providers to meet the growing

demands of the Middle East, North Africa and

Turkey.”

He said that the new company “brings

together Chromalloy’s expertise in gas turbine

engine technologies with Arabian Qudra’s

advancements and outstanding energy

service legacy”.

Arabian Qudra’s chief operations officer

Ahmed Al Bedaie said Chromalloy Arabia “is

a strategic partnership delivering innovative

energy and industrial sector solutions in Saudi

Arabia and throughout the Middle East”.

Chromalloy Arabia will be headquartered

in Jeddah, Saudi Arabia, and will also have a

sales office in Dubai.

Visit www.PowerEngineeringInt.com

for more information

UAE Minister of Energy H.E. Eng Suhail Mohamed Al Mazrouei

Credit: POWER-GEN Middle East

Visitors discuss the latest technology on the exhibition floor

Credit: POWER-GEN Middle East

1511PEI_35 35 10/26/15 3:47 PM

Diary

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POWER-GEN EUROPE 2016 C4POWER-GEN INTL 2016 C3REWNA 2016 29SEALEZE, A UNIT OF JASON, INC. 31SHAUNGLIANG ECO-ENERGY SYSTEMS CO LTD 21SIEMENS AG 13SIPOS AKTORIK GMBH 9VAISALA OYJ 18VALMET AUTOMATION 11WELLAND & TUXHORN AG 22YOKOGAWA EUROPE B.V 33

Ad Index

www.PowerEngineeringInt.com36 Power Engineering International November 2015

2016

12th International Energy Exhibition (KishENEX)11–14 January 2016Kish Island, Iran http://kishenex.ir

Myanmar Electric Power Convention13–15 January 2016Yangon, Myanmarwww.neoventurecorp.com/events/mepc

World Future Energy Summit 18–21 January 2016Abu Dhabi, UAEwww.worldfutureenergysummit.com

Nuclear Power Asia 20–21 January 2016Jakarta, Indonesiawww.nuclearpowerasia.com

Energy Storage 20163–4 February 2016Paris, Francewww.wplgroup.com

Solar Middle East1–3 March 2016Dubai, UAEwww.solarmiddleeast.ae

POWER-GEN Russia19–21 April 2016Moscow, Russian Federationwww.powergen-russia.com

POWER-GEN India & Central Asia19–21 May 2016New Delhi, Indiawww.power-genindia.com

POWER-GEN Europe21–23 June 2016Milan, Italywww.powergeneurope.com

POWER-GEN Africa19–21 July 2016Johannesburg, South Africawww.powergenafrica.com

POWER-GEN Asia20–22 September 2016Seoul, South Koreawww.asiapowerweek.com

December

Geopower & Heat Summit1–2 DecemberIstanbul, Turkeywww.greenpowerconferences.com

iPad Cameroon Energy and Infrastructure Forum1–2 DecemberYaounde, Cameroonwww.clarke-energy.com

4th District Energy Asia Summit2–3 DecemberBeijing, Chinawww.districtenergyasia.com

Power and Water Maintenance6–9 DecemberAbu Dhabi, UAEwww.powerwatermaintenance.com

POWER-GEN International8–10 DecemberLas Vegas, Nevada, USAwww.power-gen.com

Visit www.PowerEngineeringInt.com

for more information

PennWell Global Energy Group, The Water Tower, Gunpowder Mill, Powdermill Lane, Waltham Abbey, Essex EN9 1BN, United Kingdom.Phone: +44 1992 656 600 Fax: +44 1992 656 700 Web: www.PowerEngineeringInt.com

Publisher Heather Johnstone peinews@pennwell.com Chief Editor Kelvin Ross peinews@pennwell.com Associate Editor Nigel Blackaby peinews@pennwell.comProduction Editor Richard Gibson Design Samantha Heasmer Production Daniel Greene Group Publisher Rich BakerAdvertisement Sales Manager Tom Marler tomm@pennwell.com

Corporate Headquarters PennWell Corporation, 1421 S. Sheridan Road, Tulsa , OK 74112 USA. Phone: +1 918 835 3161 Fax: +1 918 831 9834

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Power Engineering International, ISSN 1069-4994, is published eleven times a year by PennWell Global Energy Group, ©Copyright 2015 by PennWell Corporation, 1421 S. Sheridan Rd., Tulsa, OK 74112, USA. All rights reserved. Subscriptions/circulation and reader enquiry office: Power Engineering International, PO BOX 3264, Northbrook, IL. 60065-3264, U.S.A. Paid annual subscription rates: Worldwide $60 Digital Version. E.U. $173, No. America $214. United Kingdom $143. All other countries $214. Single or back copies: $26 for all regions.

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COO M BINEDNED CCYCLE

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