Power egineering 2014 n09

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FOCUS ON PROJECTSDRIVING INNOVATION

CHECKLIST FOR GASPLANT PLANNING

Official Media Partner for

POWER-GEN Middle East 2014

SHOW ISSUE

September 2014The magazine for the international power industry

www.PowerEngineeringInt.com

HRSG TECHNOLOGYUNLOCKS FLEXIBILITY

PUSHING GAS TURBINEEFFICIENCY ENVELOPE

Middle East Focus:The projects driving a

new power mix
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POWER ENGINEERING INTERNATIONAL

Contents

Free Product InfoYou can request product and service information from this issue. Simply click on the link below that will provide you access to supplier companies websites,

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Features

16 Pushing the gas turbine efficiency envelope

With modern gas turbines expensive to run and maintain, weexplore how operators rise to the challenge of getting the

best out of their machines.

22 Planning tips for a gas-fired plant

Some key techno-economic aspects are often overlooked

when trying to decide on the right technology for a new gas

plant, yet they play a key role in the lifecycle analysis.

28 Offshore winds new battleground

If offshore wind is to maintain its pace of growth and competewithout subsidy, then the cost of electricity generated from

future projects must come down.

2 Industry Highlights

55 Diary

56 Ad Index

Power Engineering InternationalSeptember 2014

Middle East Power Project Focus

6 Paving the way for progress

We outline the status of several key power projects that arehelping to shape a new energy mix in the Middle East.

SEPTEMBER 2014///VOLUME 22///ISSUE 8

www.PowerEngineeringInt.com

Taking the heat: the latest advances in HRSG technology. p38

Source: NEM

32 Iraq: from crisis to ISIS

Just as it was beginning to recover its optimism afteryears of war, Iraqs energy sector has been derailed by the

advance of ISIS across the country.

38 Advances in HSRG technology

Boiler designers are coming up with a new generationof flexible steam generators that are finally setting free the

innate flexibility of the gas turbine.

44 Hydropowers environmental challenges

The hydropower sector is responding to challenges createdby concerns over climate change, water availability and

other environmental issues.

POWER-GEN Europe Best Papers50 Keeping monitoring in the pipeline

As modern thermal power plants push for ever-greaterefficiency, the need for lifetime monitoring of piping systems is

more vital than ever.

On the coverRabigh power plant. Credit Samsung
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4/602 Power Engineering InternationalSeptember 2014 www.PowerEngineeringInt.com

Industry Highlights

Another month brings yet another

report warning that policy uncertainty

risks stalling investment in a particular

power generation sector.

In August the report came from the

esteemed analysts at the International Energy

Agency and the market in question was

renewables.

Power generation from renewables grew by

240 TWh last year to hit 5070 TWh, accounting

for almost 22 per cent of global generation.

This was driven by global investment in thesector of around $250bn.

Money of this magnitude isnt invested

lightly and the IEA warned that policy tinkering

or even wholesale overhauling risks seeing

this financial backing coming to a standstill.

IEA executive director Maria van der

Hoeven said that just as renewables are

becoming a cost-competitive option in

an increasing number of cases, policy and

regulatory uncertainty is rising in some key

markets. This stems from concerns about the

costs of deploying renewables,She stressed that policy decisions must be

predictable and retroactive changes must

be avoided. Governments must distinguish

more clearly between the past, present and

future, as costs are falling over time. Many

renewables no longer need high incentive

levels. Rather, they require a market that

assures a reasonable and predictable return

for investors. This calls for a serious reflection on

market design.

So far, so obvious, yet the IEA is predicting

a drop in renewables investment of $20bn

a year to 2020. It lowered its growth forecast

for all renewables except solar PV and said

Europe and the US could expect to see a

slowdown in capacity growth.

The renewables industry is acutely aware

of this investment threat which it has little or

no control over, yet is also working on those

challenges to its future that it can influence.

One such challenge is to bring down the

cost of electricity generated from offshore

wind farms to ensure that the sector can grow

and compete with other forms of generation

without subsidy.Benj Sykes, UK wind country manager for

Dong Energy and co-chair of the Offshore

Wind Industry Council, says the industry

cannot rely on subsidies indefinitely we need

to make rapid progress towards the goal of

being competitive with other energy sources,

and outlines on p28 how he believes this can

be done.

One region showing little sign of renewables

dithering is the Middle East. It may currently

boast few green power plants, but that is on

track to change by the end of the decade.

Its flagship solar farm Shams 1 in Abu

Dhabi is set to be joined by other solarschemes in Dubai, Jordan, Oman, Saudi the

list goes on, as many Gulf states look to take

advantage of their climate and in turn save

more of their oil and gas for export rather than

their own power generation.

Which is not to say that the region is not

keeping pace with the latest technology in

other forms of power generation: far from

it. In our Special Focus on p6 we examine

several new state-of-the-art plants that are

helping to reshape the energy mix of the Gulf.

From the worlds largest internal combustionengine plant, which is poised to come online

in Jordan, to two gas-fired combined cycle

plants in Oman that are at the cutting edge

of clean and efficient power technology,

Middle East countries are pushing ahead with

energy strategies, backed up with the know-

how of European companies attracted by the

regions get-on-with-it attitude.

Meanwhile the Gulfs first nuclear plant

is making progress in the UAE supported by

enviable policy certainty. The country decided

it wanted nuclear power, drew up a policy

framework, picked a site, chose contractors

and Barakah power plant is underway, on

time and budget and winning plaudits from

the International Atomic Energy Agency. And

all in the time that plans for Hinkley Point C in

the UK are pushed across desks in Westminster

and Brussels while equipment at the so-called

shovel-ready site gather dust.

We can expect more details of how the

countries of the Middle East are pushing

ahead with their power blueprints at POWER-

GEN Middle East (12-14 October: www.

power-gen-middleeast.com), when the majorplayers in the power industry will meet in Abu

Dhabi. I hope to see you there.

Middle East countriesare pushing aheadwith energy strategies,backed by theknow-how of Europeanfirms attracted bythe regions

get-on-with-it attitude.Kelvin RossEditorwww.PowerEngineeringInt.com

Follow PEi Magazine on Twitter:

@PEimagzine

Follow me: @kelvinross68
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Outstanding OEM EPC competencefor cutting edge integrated powerplant solutions:

World Record No. 1At the heart of the plant will be the latest Siemens

turbine generation: the SGT5-8000H. Its output is

equivalent to that of 22 jumbo jet engines, and it

weighs as much as an Airbus A380 with full fuel tanks.

In combination with a downstream steam turbine

(Siemens SST5-5000), the Duesseldorf power plant

will provide an electrical output of approximately

595 megawatts (MW) in a single block.

World Record No. 2

The electrical efficiency of the power plant in combined

cycle operation will be over 61 percent exceeding

the previous world record of 60.75 percent attainedby the Siemens-built Ulrich Hartmann power plant

in the Bavarian town of Irsching, Germany.

World Record No. 3The plants waste heat energy will be used to supply

district heating for the city of Duesseldorf. The 300 MW

of thermal energy that will be extracted for this pur-

pose will set a worldwide record for the amount of

power harvested by a single gas turbine generating

unit.

District Heating

Pipelines

Transformers

Heating Condensers

Multi Purpose Building incl.

District Heating Station

SPPA-T3000

Control System


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Power Plant Fortuna (Stadtwerke Duesseldorf AG, Germany)

Three world records

in one power plant

Steam Extraction

SST5-5000Steam Turbine

Air Intake

SGen5-3000W

Generator

SGT5-8000H

Gas Turbine

Heat Recovery

Steam Generator

Architectural Highlight

(City Window to

the Center of

Duesseldorf)
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Paving the wayfor progressSix major power projects highlight the ambition of theMiddle East to provide a diverse energy mix.PEi examines the projects and presents an update oneach plant from one of the major players involved inits construction

Middle East Project Focus

Rabigh thermal power plant in Saudi Arabia

Credit: Doosan

6 Power Engineering InternationalSeptember 2014 www.PowerEngineeringInt.com

The worlds largest internal combustion engine

power plant is due for imminent completionin Jordan later this month, marking a key

milestone in the countrys unprecedented

journey towards energy self-sufficiency by

2020.

IPP3, located at Al Manakher near the

Jordanian capital Amman, will deliver 573 MW

of power through 38 Wrtsil 50DF engines.

The project is central to Jordans 2020

vision: delivering a tri-fuel plant capable of

transferring seamlessly without downtime

between natural gas, heavy fuel oil and

light fuel, while providing load-following

for renewables and matching supply and

demand exactly to drive efficiency.

IPP3 sits at the core of Jordans 2020

strategy, along with the exploration of extensive

local reserves of oil shale, nuclear investments,a new LNG terminal in the city of Aqaba and

a dual natural gas/oil pipeline running from

Iraq.

Energy self-sufficiency is an ambitious

goal for any country, but for an energy-poor

state like Jordan the target is particularly

extraordinary, given the kingdoms historical

reliance on foreign sources for up to 97 per

cent of its fuel.

In spring 2012, Amman Asia Electric Power

Company (AAEPC), a consortium owned

by the Electric Power Corporation of South

Korea, Mitsubishi Corporation and Wrtsil,

was chosen by the National Electric Power

Company of Jordan (NEPCO) to build IPP3,

with the turnkey contract awarded to Wrtsil

and South Korean Lotte Engineering &Construction.

The plant will provide baseload power

for the countrys national grid through 22

engines with a 60 per cent capacity factor.

The remaining 16 engines will serve peak load

with an expected 40 per cent capacity factor.

Notwithstanding this operating pattern,

the entire plant is capable of being operated

at any load depending on Jordans needs.

IPP3 will be an excellent catcher of load

peaks due to its high part-load performance

and its ability to dispatch with zero penalties,

enabling existing turbine plants to operate

their baseload at higher efficiency.

As a baseload plant, IPP3 benefits from

IPP3 spearheads Jordan towards self sufficiency
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METKA is a leading EPC (Engineering-Procurement-Con-

struction) contractor for large-scale power generation plants,

well-known for its ability to reliably deliver complex projects

throughout Europe, the Middle East and Africa, often on very

demanding project schedules.

The company has significant experience in gas turbine based

power generation, including combined cycle, co-generation and

simple cycle technology, providing world-class solutions and

optimal performance.

Strong project management skills, together with a complete

range of functional expertise and understanding of international

markets, give METKA the advantage in meeting customer needs.

The company excels in fast-track execution, bringing critically

needed power to growing markets.

With over 50 years of experience, METKA is a reliable partner

for utilities, independent power plant developers and local

communities around the world.

E N E R G Y

www.metka.com

Over 6.5GW of natural gas fired plant capacity

is currently under execution by METKA,

in 5 different countries

Empoweringthe future
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10/608 www.PowerEngineeringInt.comPower Engineering InternationalSeptember 2014

Middle East Project Focus

being fitted with a nitrogen oxides (NOx)

control system for abating emissions, meeting

strict environmental health and safety

guidelines set by the International Finance

Corporation.

Besides NOx regulations, IPP3 follows

international requirements for sulphur oxides

and particular matter and will have a close-

to-zero usage of water once gas is employed

as fuel, minimizing its environmental footprint.

In addition to gaining the acclaimed title

of largest internal combustion engine (ICE)power plant in the world, IPP3 is also the first

and only facility of its kind in the Middle East.

The plant represents a step change in

Jordans application of gas technology

solutions. Before IPP3, Jordans utility

professionals had never contemplated the

installation of an ICE plant, preferring to

generate baseload power through combined-

cycle gas turbine facilities, with the option to

create flexibility through part-loading when

required.

Although CCGTs continue to be heavily

marketed in Jordan, ICEs are advantageous

for three key reasons. Firstly, Jordan has no

load-following power plants capable of

starting in less than ten minutes and meeting

demand exactly as required, a particular issue

in a country that experiences huge differences

in demand between winter and summer.

Secondly, the limited flexibility possible

through part-loading has proved particularly

costly over the last five years, due to Jordans

inherent need to rely on imported gas from

Egypt, where supplies have been disruptedby political instability. The result of this is that

Jordan has often used expensive diesel to run

its plants when sufficient gas is not available.

Not only is the up-front cost of diesel more

expensive, but the fuel is also less efficient

than gas when operated at part-load, further

adding to fuel costs.

Thirdly, amid concern over imported

supplies, Jordan will require energy from up to

400 MW of renewables and a variety of local

reserves to realize its 2020 vision, meaning

flexibility to back up intermittent wind and

solar and generate baseload power from a

range of fuels will be of critical importance.

Despite these notable benefits, IPP3 only

received the green light after a thoroughmarket analysis provided by Wrtsil, as well

as a further study undertaken by NEPCO to

rigorously assess how advantageous an ICE

plant would be in comparison to a CCGT.

At the time, CCGTs were so heavily

integrated into the Jordanian energy

industry that local environmental regulations

supported its installation, and had to be

amended at ministerial level to support ICEs

a move that went against environmental

norms in the region.

The plant serves as a great example of

outstanding collaboration and compromise:

the co-operation between Wrtsil and

its affiliates has allowed for a competitive

engineering, procurement and construction

price for the plant, an efficient bidding process

and a shorter gestation period from start to

finish.

The first 16 peak load-bearing engines

were operational in as little as 16 months, while

the entire plant will be up and running in no

more than 24 months after the Limited Notice

to Proceed.

Until 2015, IPP3 will run on heavy fuel oilbefore transitioning to natural gas supplied

by a new LNG unit in Aqaba. The project will

serve as a flagship example of how prejudices

against internal combustion engines can

be broken, even amid strong support for

CCGTs, by demonstrating the advantages

the technology can bring to those striving

for energy independence or a generation

portfolio with a high penetration of renewable

energy.

Contributed by Wrtsil.

Artists impression of IPP3

Credit: Wrtsil

Doosan Heavy Industries & Construction

secured the EPC contract to build the

2800 MW Rabigh thermal power plant from

Saudi Arabias state-backed power supplier

Saudi Electricity Company (SEC) in September

2010.

Worth some $3.44 billion, the project

constitutes the largest single project for power

plant construction that a Korean company

has ever secured overseas. Doosan Heavy

emerged as the single EPC contractor, winning

the order over stiff competition from Siemens,

Alstom and Mitsubishi and thereby setting

a precedent for the recognition of Korean

expertise in plant exports to Saudi Arabia.

Rabigh is Saudi Arabias single largest

construction site. It is located some

150 km north of Jeddah on the Red Sea

coast. Construction of the plant will be

completed over six stages. When all stages are

finished, its total generation capacity will be

2800 MW, produced by four individual units,

each with a 700 MW capacity. Doosans scope

as EPC contractor includes everything from

engineering to procurement, manufacturing,

installation and operational testing and

commissioning.

By 2016, Saudi Arabias electric power

consumption is expected to reach

309,100 GWh triple 2000s rate of

consumption. Rabigh will play a vital role in

providing the expanded electricity capacity

to meet this demand. In particular, the project

Rabigh: Powering Saudi Arabias future generation


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Gas turbine performance

has traditionally been

evaluated in terms of

thermal efficiency, but

in determining overall

performance, operators

also evaluate availability, reliability, flexibility

and, above all, profitability.

The earliest commercial gas turbineengines were used to power aircraft during

the 1940s and it was another 20 years before

gas turbines became established in the

electricity generating fleet.

In the early 1960s, grid disturbances led

to electricity blackouts across the southeast

of England. With load growth predicted, the

Central Electricity Generating Board (CEGB)

decided to deploy fast start aero engines

as gas turbine generators. A demonstration

engine at Hams Hall power station in 1964 was

followed by a major installation programme.

Across the Atlantic on a November night in

1965, a cascading voltage collapse blacked

out nearly one third of the population of

the northeastern US. This led the countrys

electricity industry to call on aircraft engine

makers to provide small, rapid-start generators

that could be deployed across the grid.

There has been continuous development

in gas turbine technology since then and

their use in power generation has increased

rapidly. Gas turbines are now one of the most

widely-used power generating technologies.Turbines have become larger, with better

thermal efficiency, able to operate at higher

temperatures and pressures. New plant can

be constructed relatively quickly, but high

operating costs and lack of operational

flexibility are areas where operators seek

improvements.

Turbines used in gas-fuelled generation

are sophisticated and complex machines.

The compressor draws in air, pressurizes it,

and feeds it to the combustion chamber at

high speed. The combustion system injects

a steady stream of fuel into combustion

chambers where it mixes with the air and

burns at high temperature to produce a

hot, high pressure gas stream. As this passes

through the turbine section it expands

and spins the rotating blades which turn

a generator to produce electricity. The

combustion gas is also used to drive the

compressor.

Heat from the exhaust gas can be

recovered and used in a combined-cycle

configuration. The combined cycle ismore thermally efficient but operational

limitations include longer start-up time, purge

requirements to prevent fires or explosions,

and the need for a phased ramp-up to full

load.

Increased efficiency has been the

traditional goal in designing and operating

gas turbines. ERA Technology gas turbine

consultant Siavash Pahlavanyali reflects:

Over the last 30 to 40 years the trend has

been steady improvements in the thermal

efficiency of gas turbines. Thirty years ago,

E Class turbines operating in single shaft,

single cycle had thermal efficiency rates of

30-32 per cent, which has now increased

Gas turbines

Modern gas turbines are proving to be the fossil-fuel technology of choice, offeringlower emissions than other hydrocarbons and operational flexibility. However, they

are expensive to run and to maintain. Penny Hitchinexplores how operators rise tothe challenge of getting the best out of their machines

Measuring the radial gab of a gas turbine

Credit: Siemens


Pushing theefficiency envelope


19/60



Gas turbines

towards 37-38 per cent. In combined-cycle

operation, the rate has moved up from 50 per

cent to nearer 60 per cent.

He cautions: Pushing the efficiencyhigher may compromise the integrity and

design margin.

Continuing R&D will see the trajectory of

improved thermal efficiency continue. Alap

Shah, turbine technologies manager at Black

&Veatch, expects combined-cycle efficiency

to increase towards 65 per cent in the next

10-15 years if economic and environmental

drivers continue to push the industry.

He says: Gas turbines of the future will

have higher firing temperatures, better

sealing technology and air cooling for hot

gas path cooling, rather than steam cooling,

increasing operational flexibility. Firing

temperature limitations are based on the

material technology and metallurgy.

The trend in the last ten years is for turbine

manufacturers to offer higher temperatures

on their products. Other contributions to

efficiency will come from increased steam

temperatures and pressure of the bottoming

cycle.

Manufacturers offer customers upgrade

packages to improve output, as well as long-

term service and maintenance agreementsfor their components and systems. A typical

upgrade package for an F Class machine

might include improved blade aerodynamics,

better sealing, advanced materials and

improved cooling technologies to allow

higher operating temperatures.

Mike Salvatore, Siemens technical

marketing manager of gas turbine

modernizations for the Americas, explains:

Upgrades are driven by customers need tomaintain competitiveness in the marketplace.

We evolve products and services to provide

greater capacity and improved efficiency

and we offer products to improve operating

flexibility.

Advanced technology

Operators of turbines installed in the late 1990s

and early 2000s are looking to the OEMs for

possible upgrades. Salvatore says: When we

assess what our customers need we pull from

our newer, more advanced technology and

apply it to the more mature fleet. This means

taking advantage of our native knowledge,

improved materials, better cooling schemes,

more sophisticated gas turbine control system

technology and retrofitting them.

Upgrading is a constant refreshing of

the more mature technology that is 10-15

years old. A lot of users of older equipment

are trying to operate them like brand new

technology. They want large capacity

improvements, efficiency, fast starting ability,

fast start acceleration and oftentimes this is

prohibitive because it could require capitalchanges to the equipment.

He expands: We can help by making

improvements to the existing configuration;

we can implement the latest technology in

terms of modernizations and upgrades of the

components, thereby resulting in improved

performance levels and reliability.

Our customers are pushing for these

upgrades, as replacing their older

equipment may not be feasible

in the short term. As the

OEM with the most specificexpertise on our products,

we work closely with owner-

operators to enhance the

asset value of their existing

equipment.

Third party specialists can

advise on how to fine-tune

and get the best from systems.

Upgrading the gas turbine may

necessitate work on the balance of

plant, and involving a third party in

the upgrade can be advantageous.

Shah explains: We have been involved

in several combined cycle upgrades where

OEMs offered several gas turbine upgrade

packages to the owner and the owner hired

us to evaluate these options in conjunction

with the HRSG, steam turbine and balance of

plant equipment to find a sweet spot in termsof overall plant performance upgrade. In that

role we take the upgraded performance from

the turbine supplier and we integrate that

with the overall plant thermodynamic model.

With the help of this integrated model,

we study and evaluate the equipment such

as HRSG, steam turbine and boiler feed

pumps, and systems such as high pressure

and reheat steam, boiler feed system etc. We

perform a debottlenecking study to find the

constraint and upgrade that equipment or

system if it makes economic sense.

Upgrades are expensive and an

understanding of the current and future

operating requirements of the plant is

necessary in deciding what improvements

are appropriate. Shah says that bigger

CTG upgrades are not always better for the

combined cycle plant.

Pahlavanyali points out: I see clients who

pay to get very advanced coatings on their

blades. But if the machine runs at 80 per cent

of base load for most of the time, it means it

has not been operating efficiently. In which

case that upgrade does not make sense.

Extending maintenance intervals

All OEMs recommend specific inspection

and service intervals, but as condition-based

monitoring becomes more sophisticated,

operators may be able to extend these

intervals, giving greater availability and

profitability.

Black & Veatchs Shah explains: As

manufacturers get more information and

experience from their operating fleet, they

can reduce margins and be more aggressivein allowing turbines to operate for longer

times between maintenance intervals.

Maintenance intervals for hot gas path

inspection have typically increased from

24,000 hours to 33,000 hours, while the

interval for major inspection is up from

48,000 hours to 66,000 hours.

Shah says: The time to be considering an

upgrade is when a major overhaul is needed.

For example, a rotor inspection will come at

100,000 hours. Replacing an existing rotor

might cost up to $10 million. This is the logical

time for thinking about an upgrade.

Flexibility, the ability to start and stop

frequently and rapidly, is important where gas

MAN Diesel & Turbo has realized single digitNOx values in the load range between 50 and

100 per cent by optimizing its Advanced CanCombustors (ACC) on a MGT 6100, the single-shaft version of the new MGT gas turbine.Credit: MAN Diesel & Turbo


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22/6020 www.PowerEngineeringInt.com

Gas turbines


Pahlavanyali says: That is not always

sufficient: the manual is the same wherever

you are operating your machine, but

operating in the desert or by the coast

means there may be differences.

He believes that by paying more attention

to condition monitoring and condition

assessment of components, operators

may be able to safely extend operational

inspection intervals by condition. How can

operators determine this?

A gas turbine includes a lot of monitoringtools. Measurements of temperature, pressure,

vibration, oil quality and other factors are

recorded and can be used to improve

understanding of the machines condition.

Sharing the operational data with the

OEM or with third party experts can help

analysis. More information can be gained

from visual inspection during maintenance.

An inspection engineer carrying out visual

inspection and looking at records would

be able to determine the likely condition

of components such as blades and thenadvise whether the blades need repair or

can remain in service.

Blades can be removed and tested to

establish if the blade can remain in service, if

it needs recoating or if it should be scrapped.

Pahlavanyali explains: We have looked

at hundreds of turbine blades in the last

20 years. In many cases the nominal design

life was finished and the operator replaced

the component, but often they could extend

the life.

We carry out a lot of tests and, if the

result is that they can put the blade back

into operation for another 24,000 hours

without any problem, this almost doubles the

design life. With blades costing from 200,000

to 2 million ($336,000 to $3.4 million) this

represents a lot of money.

The same approach can be applied to

other components and processes. While the

OEM may recommend offline compressor

washing every two months, Pahlavanyal

says: In my experience compressor washing

intervals should be based on the condition

of the machine. The recommendation is to

base it on the amount of drop in pressure,

but I think the best tool is experience. Anytime there is a sign of degradation material

degradation or performance degradation

then wash the compressor (online or offline)

to take it back to normal.

Reducing emissions

One of the challenges of flexible use of gas

turbines to back up renewable sources of

power generation is that part-load operation

could significantly increase emissions.

Operating gas turbines at low loads may lead

to significantly higher levels of CO2and NOxgases.

Emissions increase during the low-load

phases of combined-cycle plants to allow

the rest of the plant to operate safely for the

desired heat level.

MAN Diesel & Turbo, which makes a

range of small gas turbines designed for

use in industry as mechanical drives for, e.g.,

compressors or for decentralized electricity

generators, has substantially reduced the

NOx emissions of its MGT gas turbines for a

wide operating range down to very low part

load operation by refining the combustion

chamber design and using premix

technology.

Dr Sven-Hendrik Wiers, vice-president gas

turbines, explains: We achieved single-digit

NOx by designing a new state-of-the-art

combustion chamber for our new turbine.The reduction in NOx emissions to single

digits (in parts per million) is aided by using an

advanced can combuster to homogeneously

premix the fuel with the combustion air before

it enters the combustion chamber. The pre-

mixing eliminates fuel-rich hot streaks, which

significantly reduces NOX gases.

Wiers says: The ambition was to have a

very efficient gas turbine. Efficiency is about

improving compression of air, improving

sealing technology, improving hot gas part

lifetime, improving cooling technology and

optimizing turbine inlet temperature levels.

We applied modern, available design

tools to improve the efficiency of compressor

and turbine, and then to achieve perfect

matching of turbine and compressor.

We adopted jet engine secondary flow

technology as the front runner in gas turbine

design methodologies in turbines.

We applied the philosophy of jet engines

to improve our sealing technology where

possible.

Long-term competitivenessModern gas turbines are proving to be

the fossil-fuel technology of choice offering

lower emissions than other hydrocarbons,

operational flexibility, and the potential for

high cycling and peaking, fast startups and

load ramps.

However, they are expensive to run and

to maintain and operators seek the best

upgrade and maintenance solutions from

OEMs and third parties.

Saa Ovcar of gas turbine specialist

Inspiro calculates that for a typical CCGTplant with plant efficiencies of over 50 per

cent, maintenance costs may represent up to

half of the total cost of electricity production.

As he says, It is therefore of highest

importance for a power plants long-term

competitiveness to consider all available

options to reducing these costs. That is the

challenge facing gas turbine operators and

manufacturers alike.

Penny Hitchin is a journalist focusing on

energy matters.

Visit www.PowerEngineeringInt.comfor more informationi

The new MGT 6100 single-shaft gas turbine before being put through its paceson the test bench in Oberhausen, Germany

Credit: MAN Diesel & Turbo
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24/60

When it comes to

building a new modern

gas-fired power plant,

it is important from the

customers standpoint

to ensure that the

project specification addresses all of their

specific needs relating to the project, and that

in doing so it will enable them to be able to

make a proper evaluation of the offers they

receive ideally on as much of a level playing

field as possible.

To ensure that this is met, at least from

the EPC side, the customers (and their

consultants) go to lengths to define and spell

out in great detail all aspects pertaining to

how the plant is to be designed, engineered,

manufactured, supplied and commissioned.

They will take great care to ensure that the

bidders ensure that all pertinent standards

and permits that the contractor(s) must

observe and comply with are adequately

drawn out in the specification, and rightly so.

As is the norm, the customers will then seek

from the EPC bidders certain commercial

guarantees against which liquidated

damages or penalties for failure to achieve

will be levied upon the contractor(s).

Gas-fired plants

Some key techno-economic aspects areoften overlooked whentrying to decide on theright technology for agas-fired power project,yet they can play asignificant part in theoverall long-term lifecycle

analysis and finaldecision making process,writes Mark Stevens

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26/6024 www.PowerEngineeringInt.com

Gas-fired plants


These main EPC commercial guarantees

are:

O Fixed & firm contract price: to be binding

upon the EPC bidder for the validity periodof its offer;

O Payment terms;

O Delivery guarantee: namely the contractual

time from NTP (notice to proceed) to COD

(commercial operation date);

O Performance guarantee: the 100 per cent

baseload power output and heat rate

for the plant (and possibly certain part-

load performances) for specific design

condition(s).

In addition, the EPC bidders will also have

to provide emission guarantee(s) as required

by the specific environment permit for the

project, covering the gaseous (e.g. ,NOx, CO)

and liquid emissions.

The EPC price, payment terms, delivery

and performance guarantees are key inputs

needed for the techno-commercial (bid)

evaluation.

However, in order for the customers and

consultants to make a complete and proper

evaluation, there is additional key information

required from the EPC bidders, namely:

O Plant maintenance costs: typically

customers will focus on the gas turbine

unit(s), being the most cost-intensive

component in such gas-fired power plants;

O Availability assurance: to allow the customer

to make some allowance/prediction for

forced and scheduled outages;

O Plant performance degradation: typically

being with respect to the plant power

output and heat rate deterioration versus

operational time due to plant wear and

fouling.

These last three items, however, are

typically covered under some sort of

separate service agreement offering from

the bidders rather than being part of the EPC

bids, as these guarantees pertain specificallyto the operational phase rather than the

construction phase.

To these key inputs we can also add the

customers own project development costs,

the projects financing costs for the EPC

phase, fuel and water costs, electricity sales

revenue, steam/water/heat production

revenues (if a cogeneration project) and

realistic operating regimes.

With all of these factors together, the

customer can now undertake a lifecycle

analysis in order to determine which offer

provides the best cost of electricity (CoE)

and/or net present value (NPV)/internal rate

of return (IRR).

This all sounds fairly straightforward until

the customers come to try and make their

comparison/evaluation and establish that

each of the EPC bidders and/or OEMs have

their own maintenance philosophies and/or

performance testing methodologies.

Indeed, the following important aspects

applicable to all gas-fired power plants

which can have significant impact on

lifecycle analyses are often not given the

due attention they deserve.

New & clean definition

From the moment of first-firing, the performance

of the gas turbine/plant starts to degrade,

with the greatest performance loss being seen

in the first few thousand operating hours.

So, if the EPC contractors performance

guarantees are based on a new & clean

definition that presumes something possibly

in the order of 500-1000 equivalent operating

hours, but then finally during the construction

phase maybe something on the order of

several thousand commissioning equivalent

operating hours is actually accumulated, theEPC contractor will adjust the guaranteed

performance downwards.

If customers instead take the lead

by actually stipulating in their project

specifications/request for quotations

(RfQs) the to be presumed number

of commissioning hours, number of

commissioning starts and number of

commissioning trips based on industry

averages/experience, then in this way the

bidders would have a common basis (to go

with the other design conditions) on which

to calculate their respective commissioning

equivalent operating hours and, in turn,

their respective new & clean performance

guarantees.

The benefits of this approach are threefold:

O All bidders would have the same

conditions for the purpose of calculating

their respective new & clean plant

performance guarantees, thereby putting

them more on a like-for-like basis for

comparison purposes;

O Customers would face fewer instances

of having to come to terms with the fact

that, due to one reason or another, the

actual commissioning EOH ends up much

higher than considered in the contract,

resulting in the performance guarantees

being corrected downwards, i.e., worse

than expected which plays out not in

customers favour;

O If the bidders are, in the end, able to

actually complete the commissioning

phase with less EOH than presumed by

customers specifications/RfQs, then this

would just mean that the performancebasis for the purpose of the guarantees

would be higher (better) - which this time

plays out in the customers favour.

Realistic plant degradation

It is also important for the purpose of carrying

out a sensible lifecycle analysis to consider

the realistic performance degradation to be

expected over the financial lifespan of the

project depending on technology choice,

site environmental/climatic conditions, fuel

choice, and probable operating regime(s)

that consider the number of start/stops,

seasonal load patterns, etc.

Here, customers should request that the

Riyadh gas fired plant

Credit: Alstom


27/60www.PowerEngineeringInt.com 25

Gas-fired plants


bidders provide, as part of their offers, plant

output and heat rate degradation plots

against EOH.

These plots should be such that thebidders would be prepared to stand behind

them from a guarantee viewpoint if required,

linked to some form of suitable long-term

service contract.

The extent of performance dropoff

(degradation) as well as the degree of

performance recovery expected at each

major inspection would vary from one

bidder/gas turbine technology to another

based on each bidders assessment

of realistic degradation for the specific

conditions pertaining to a specific project.

This degradation plot will also have a

commercial assessment on the part of

the bidders, who will be wanting to project

something that, on one hand, could be

considered sensible/realistic, but at same

time is likely to still be competitive versus other

bidders/technologies.

Customers would therefore be wise to

request that bidders submit their performance

degradation plots over a reasonable time

frame, such as the financial or technical

design life, and not just for the first or second

major inspection time frames.

The benefits of this approach are threefold:customers have something that they can

use in their evaluation/life-cycle analysis to

compare the different bidders/gas turbine

technologies; customers are considering

a plant performance forecast that is

considered to be realistic by the bidders for

their respective gas turbine technologies;

and, if required, customers have a plant

performance forecast that could be used for

the purposes of establishing guarantees, if

required, linked with some form of long-term

service contract.

True cost risks

It is during the bid phase that customers are in

the best position to determine whatever they

need to know, have tied down and agreed

with their selected contractor(s).

As mentioned at the start of this article, too

often customers do not give the right amount

of attention to the long-term operational

phase.

They may make some very simple

presumptions regarding the expected

operating regime, or presume that all of

the gas turbine technologies are effectivelythe same when it comes to considering and

comparing running costs and maintenance

regimes.

Again, if customers only look as far out

as the first or second major gas turbine

inspection interval regarding turbine/plant

running costs, the customers may not pick

up some specific maintenance requirement

that could have financial impacts over and

above those considered.

On the other hand, it is also understandable

that customers would like to limit any long-

term service contract to a reasonable time

frame that, on one side, covers the early

operational phase when a plant is expected

to have the highest operational issues, and,

on the other side, is short enough to allow

them the ability to reconsider their O&M

positions once they have accumulated some

operational experience with the selected

turbine/plant technology.

However, the bid phase is the best period

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Gas-fired plants

for customers to ask and find out. It therefore

makes sense, at least during the bid phase, to

request that the bidders provide their running

(maintenance) cost projections for their

respective turbine/plant technologies over

a long time period, say 20-25 years from the

start of commercial service, so that, again, a

proper lifecycle analysis can be undertaken

for comparison purposes.

Then they would finally decide on what

is considered from their standpoint to be

the preferred, most probably shorter (six to

ten years) time frame for any actual long-

term service agreement with the selected

contractors/OEMs.

There are three key benefits of this

approach.

Firstly, by looking to a long time period of,

say, 20-25 years, then any and all additional

major service work that might be required ona specific turbine or plant technology, which

could have additional cost and/or outage

time impacts, should be picked up on the

pre-contract phase radar (examples could

be compressor overhauls, rotor overhauls

and lifetime extensions).

Secondly, customers are able to undertake

more realistic/sensible lifecycle analysis

in order to better compare the respective

bidders and technologies before making a

final decision.

Thirdly, customers have a more

comprehensive picture of the long-term

running costs pertaining to the different

technologies under consideration for their

projects.

Even if any possible additional major

service work is projected or expected to

take place a long way out, such that on

a PV basis the financial impact may be

considered unimportant, again, it is better

on the customer side to ask the questions at

the bid phase and be informed than to find

out only later during the operational phase,

when it may be too late to argue the case.

Plant Reliability

It is standard industry practice for the

bidders to provide the plant reliability and/or

availability data for their respective turbine/

plant technologies on the basis of 8760 period

hours (8784 in a leap year).

Although this can make sense when it

comes to availability, it can pose an issue

when considering reliability.Firstly, let us recap the normal definition

or understanding of plant reliability and

availability. Reliability is generally taken as

being the difference between the period

hours considered and the actual delivered

operational hours for the covered scope

in that period, resulting from unscheduled

curtailments.

Availability, on the other hand, considers

not just forced outages and de-rates, but also

any and all scheduled (planned) outages in

the same period, namely:

A power plant can, by definition, be

100 per cent available, even if not actually

operating, simply by way of the power

company declaring it as being available.

So to consider the 8760 period hours in a

year time frame is both reasonable and

understandable. Reliability, on the other hand,is something that is more usually associated

with actual operational performance.

Although the OEMs/bidders consider the

8760 period hours for setting their reliability

values, reliability can change dramatically

for differing service factors, as shown in

Figure 3 (left).

The 8760 period hours time frame

represents an ideal case.

In reality, a power plant would not operate

constantly during this time, but would

instead be shut down when not required by

the grid and/or when it is time for scheduled

maintenance work to be undertaken.

In Figure 3, we see that for the annual

8760 hours, a 98 per cent reliability factor

equates to around 175 hours of forced

unavailability.

If this same 175 hours of forced

unavailability is witnessed on a power plant

that has, perhaps, a service factor of only

around 70 per cent (equating to around

6130 period hours) then the plants reliability

would in fact be around 97 per cent (i.e.,

1 per cent less), and for a service factor of

just around 50 per cent (equating to around

4380 period hours) this would be around

96 per cent (i.e., 2 cer cent less).

For such scenarios, customers might

wish to consider applying a weighting

factor, whereby they require high

reliability/availability factors from the plant

during high-demand periods in the year,

but are prepared to consider some

reasonable relaxation during the non-critical

periods.

By paying attention to the importanttechno-economic matters outlined in this

article at the specification/request for

quotation stage, customers can make a

much more informed and comprehensive

assessment and evaluation at the bid

phase.

Mark Stevens is director and principal

consultant at SS&A Power Consultancy in

Switzerland. [email protected].

www.sss-power.com

Visit www.PowerEngineeringInt.comfor more informationi

Relative Plant Reliability vs. Operational Hours

Operational Hours per Year

3760 4260 4760 5260 5760 6260 6760 7260 7760 8260 8760

95.20%

95.40%

95.60%

95.80%

96.00%

96.20%

96.40%

96.60%

96.80%

97.00%

97.20%

97.40%

97.60%

97.80%

98.00%

98.20%

Figure 3: Relative Plant Reliability (for 175.2 hours forced non-availability)
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R

enewable energy is playing a

crucial role as the UK remains

on course to transition to a low

carbon energy supply and meet

its carbon reduction targets.

Renewable energy now

accounts for 15 per cent of the electricity

generated in the UK double the amount

supplied in 2010. And, unsurprisingly for a

country boasting Europes longest coastline

and best offshore wind conditions, the

offshore wind sector is one of the most

fascinating threads in this great success story.

The total offshore generating capacity in

UK waters provides around 8 TWh of electricity

annually, equivalent to the electricity

consumption of around two million homes. In

the first quarter of this year, output grew by

over 50 per cent to 4.4 TWh when compared

to the first quarter of 2013.According to a report from the

Department of Energy and Climate Change

(DECC) published in July, called Delivering

UK Energy Investment, The UK is the clear

world leader in offshore wind and has more

installed capacity (3.8 GW) than any other

country, supporting 18,300 jobs. By 2020 we

could see capacity reach 10 GW, enough to

power almost seven million homes.

This is all very good news for the UK, which

is bracing itself to lose around a quarter of

its current generating capacity by the end

of this decade as existing coal-fired power

stations are retired, through age or inability

to meet tough carbon reduction targets. And

more than 50 per cent of current capacity will

be retired by 2030.

The UK government reaffirmed its support

for the future role of the technology when five

of the eight support contracts it awarded in

April this year were for offshore wind farms. The

contracts three of which were for projects

in which Dong Energy has an interest will

provide production-based financial support

for the first 15 years that these wind farms are

in operation.

With such government support available,

you might think that the offshore wind

industry is about to rest on its laurels and get

a little complacent. However, youd be wide

of the mark.

Though weve made considerable

progress so far, there is a huge job still to be

done if offshore wind is to maintain its pace of

growth and compete without subsidy againstother generation sources in the next decade.

DECC recognizes this issue in their new

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electricity generation in the next decade, so

its important to drive costs down now.

The cost of electricity is the offshore wind

industrys new battleground. At around

160/MWh, the cost of electricity generated

from future offshore wind farms has to come

down. The industry has known this and has

been on the case for some time.

The Offshore Wind Industry Council

(OWIC) also has cost reduction very much

in its sights. OWICs role, as a strategic

Renewables cost reduction

If offshore wind is to maintain its pace of growth and compete without subsidy

against other generation sources, then the cost of electricity generated from futureprojects has to come down, writes Benj Sykesof Dong Energy

Offshore windsnew battleground

Credit: London Array


Benj Sykes


31/60


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34/60

Three months before the fall of

Iraqs second largest city, Mosul, to

the Islamic State (IS), formerly the

Islamic State of Iraq and Syria (ISIS),

I was invited to present a paper on

the future of Iraqs electricity sector

at an energy conference in Dubai. Iraqs

Minister of Electricity Abdul Kareem Aftan and

many senior officials were among the invitees.

In his opening statement, the minister

conveyed the optimistic message that Iraqis

will finally benefit from 24 hours of electricitysupply by the end of 2014. He also revealed an

ambitious plan to launch investment projects

for international firms to boost Iraqs electricity

generation capacity to meet future demand.

Some additional 8000 MW were planned

to come online this year, with the expectation

that generation capacity would reach

20,000 MW by the end of 2015. But the recent

development in Mosul was a major blow to the

ministrys plan, with the fear that the country is

heading toward another sectarian war at the

bleeding heart of the ongoing conflict among

Sunni and Shiite factions.

No doubt the fall of Mosul and other

Sunni provinces will further erode the already

weak central government authority and

put the country once again on the brink of

internal conflict, with an enormous impact

on the economy. The oil export has already

been affected through the north pipeline

due to the military operations, and worsened

after KRGs Peshmerga forces stepped in

and occupied Kirkuk, the city with large oil

reserves, in an attempt to stop the insurgents

who swiftly took control of the neighbouring

cities of Tikrit and Mosul.

The conflict between the centralgovernment and KRG over Kirkuk is not new,

but seizing control of production facilities

at Bai Hassan and Kirkuk oilfields, which

produce more than 400,000 barrels per

day, has deteriorated relations between

the two sides, leading to speculation about

the declaration of an independent Kurdish

state.

Economic deadlock

During the last four decades, Iraq has gone

through three wars, periods of civil unrest and

economic sanctions which had devastating

consequences on the future and life of

its people, including lack of security, high

Regional profile: Iraq

Just as it was beginningto recover its optimismafter years of war, Iraqsenergy sector has beenderailed by the advanceof IS across the country.The nations ambitiousplans have been dealt amajor blow, writes Harry

Istepanian

IS fighters have launched attacks on the power plant in Bayji

Credit: Jim Gordan, USACE


Iraqs electricity:from crisis to ISIS


35/60

For queries relating to the

conference, please contact:

POWER-GEN Russia:

Emily Pryor

Conference Manager

T: +44 1992 656 614

E: [email protected]

HydroVision Russia:

Mathilde Sueur

Senior Conference Manager

T: +44 1992 656 634


For information on exhibiting and

sponsorship, please contact:

POWER-GEN Russia:

Gilbert Weir Jnr

Sales ManagerT: +44 (0)1992 65 6 617

F: +44 (0)1992 656 700


Svetlana Strukova

T: +7 495 249 49 15

F: +7 495 249 49 15


HydroVision Russia:

Amanda Kevan

T: +44 (0) 1992 656 645

F: +44 (0) 1992 656 700


POWER-GEN Russia (formerly Russia Power), co-located with HydroVision Russia, provides an ideal settingto explore business opportunities, meet new partners, suppliers and the industrys most influential decision-makers. The combined 2014 event combined attracted over 5,000 attendees from over 50 countries.

Featuring a busy exhibition floor with the pre-eminent organisations from the Russian and internationalenergy sector, POWER-GEN Russia and HydroVision Russia offers excellent networking opportunities.

WHY YOU SHOULD EXHIBIT IN 2015

from the industry, for the industry. For further information on exhibiting please contact your localsales representative.

INVITATION TO PARTICIPATE

REGISTER NOW TO ATTEND RUSSIAS PREMIER POWER EVENT

POWER-GEN Russia and HydroVision Russia is now open for Registration! Make sure

you register, attend, learn and network with high-level executives, professionals and

other leading decision-makers in the industry.

For information on registration pricing and how to register, please visit:

www.powergen-russia.comor www.hydrovision-russia.com.

Conference & Exhibition

3 - 5 March 2015

Expocentre, Moscow, Russian Federationwww.powergen-russia.com| www.hydrovision-russia.com

Owned and Produced by:

Presented by:

www.powergen-russia.com|www.hydrovision-russia.com

PROVIDING ENERGY SOLUTIONS & INNOVATION

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unemployment and shattered infrastructure.

According to the Foreign Policy Group, Iraq

has ranked in the top 20 failed states for

several consecutive years, trailing behind the

Central African Republic and Zimbabwe.

The electricity shortage has been one of

its economic deadlocks for years. Persistent

power cuts are still common almost everywhere

in Iraq and constitute a major restraint on the

countrys economic and social development.

Iraqis have been getting frustrated with

governments unfulfilled promises, and with

having no more than eight hours a day of

electricity despite billions of dollars spent over

the past ten years. The cost to the economy

from unserved electrical needs is estimated at

about $40 billion per year.

Iraqs socioeconomic development

has remained below expectations despite

the fact that its GDP has almost doubled

ten times since 2003. Around eight million

citizens (25 per cent of the population) are

still living below the poverty line, on less than

$2.2 per day. Iraqs economy continues to

rely predominantly on exported oil, which

generates more than 95 per cent of earnings.

Over the last eight years the government

of Prime Minister Nouri al-Maliki has failed

to evenly channel this huge oil income into

economic and social development across

the provinces, which are still suffering from the

legacy of civil war and hobbled by political

alienation and the marginalization of Sunni

minorities.Despite the fact that more than

$40 billion from the countrys oil revenue has

been poured into the sector over the past

ten years, many big projects that could have

lit up the whole of Iraq have been delayed.

Natural gas, which is one of the main sources

of fuel for power generation, has remained

unexploited due to lack of investment in the

oil and gas sector. A recent study published

in the Electricity Journal concludes that

Iraqs demand for electricity is higher than

the Ministry of Electricitys original estimate.

The study expects that Iraq will require more

than 60,000 MW of electricity by the end of

2030, driven mainly by the increase in the

population and GDP growth. It is envisaged

that the gap between demand and supply

is widening as a direct result of imprudent

policies over the last three decades, which

impeded the development of the sector

and ultimately caused massive institutional

and governance failure due to inefficient

management.

Maku Kahraba (no electricity) is a

common idiom used by Iraqis to describepower cuts which became a regular feature

of their lives, especially at peak times on

Baghdads extreme summer days with

outdoor temperatures reaching above 110F.

For years Iraqis have been relying

on expensive, noisy and polluting diesel

generators to meet the shortfall. It is estimated

that there are more than 5000 diesel

generators in the streets of Baghdad alone.

Some are provided by local councils to the

Baghdad ashwaiyyat, or informal districts

built illegally due to the influx of internallydisplaced refugees after the sectarian war

in 20062008, which often do not receive

public services from the municipalities. Fees

for running private generators are hefty

because of the high price of fuel on the black

market. Weekly service fees range between

$0.13/kWh and $0.33/kWh, on par with prices

for electricity provided by the government

at less than $0.1/kWh. It is unlikely that the

government will be able to long sustain

the subsidies to fill the gap between the

cost of electricity and the tariff, due to dire

financial burdens caused by the war on ISIS

which is exacerbating an already stretched

government budget.

0

2000

4000

6000

8000

10,000

12,000

14,000

16,000

18,000

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

1990

Maximum Generation (MW) Maximum Demand (MW)

Generation vs demand 1990 2013. Source: Iraq Ministry of Electricity

BAMASCUS

AL SAFIRA

ALLEPO ASSAD LAKE

ARRAQQ

TABQA

FALLUJA

HADITHA

RAWAHAKKAZ

MOSUL

ANAH

KIRKUK

SAMARAH

HEMREEN

BAIJI

RAMADI MANSURIYA

SADR-2

BAGHDAD

GALAHAD_DIN

ISIS CONTROLLED AREAS

ISIS PRESENCE

CITIES UNDER ISIS CONTROL

CONTESTED CITIES

POWER PLANT

POWER PLANT UNDER CONSTRUCTION

ISIS electricity map. Credit: HH Istepanian


37/60




provinces. However, it is unlikely that IS would

risk sabotaging the Mosul dam for the time

being as long as it is seizing the city of Mosul.

During the US-led invasion, the US Army

Corps of Engineers found the Mosul dam

inherently unstable. Since then, the dam

has been undergoing continuous pumping

of grout deep into its base to prevent the

structure from collapsing. Any disruption

could breach the dam and have dire

consequences within hours by flooding the

city of Mosul, surrounding Nineveh plateau

and drowning parts of Baghdad under

15 feet of water.

Out of the Syrian Desert

The Syrian Desert, the traditional home of Arab

Bedouin tribes, served as a major supply line

for the Iraqi insurgents during the 2003 war. Tenyears later it became ISs primary stronghold,

with headquarters in the city of ar Raqqa on

the Euphrates River. In February 2013, IS took

control of Tabqa (Thawrah) dam (824 MW),

the largest hydroelectric dam in Syria, built in

the 1970s with help from the Soviet Union. The

dam is now providing electricity to areas that

are in the hands of IS, including the contested

city of Aleppo. Prior to taking over Tabqa dam,

IS controlled two smaller facilities upriver,

the Baath dam (81 MW), located 14 miles

upstream from the city of ar Raqqa, and the

Tishrin dam (630 MW), 50 miles south from the

Syro-Turkish border. The battle for control of the

dams has become an effective weapon in the

Syrian civil war, offering the possibility to deny

electricity to non-allegiant towns and cities.

Turkey is also involved in a different kind

of war: that of controlling hydroelectric

resources. The Southeastern Anatolia

Development Project (GAP in Turkish)

involves the construction of 22 dams and

0

50

100

150

200

250

2002 2004 2006 2008 2010 2012 2014

GDP (current Billions US$)

GDP 2002 2014. Source: The World Bank

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39/60www.PowerEngineeringInt.com 37

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