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FOCUS ON PROJECTSDRIVING INNOVATION
CHECKLIST FOR GASPLANT PLANNING
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September 2014The magazine for the international power industry
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Middle East Focus:The projects driving a
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POWER ENGINEERING INTERNATIONAL
Contents
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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
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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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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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Intelligent Power Generation Solutions
Mitsubishi Hitachi Power Systems Europe supplies up-to-date, efficient
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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
16 Power Engineering InternationalSeptember 2014 www.PowerEngineeringInt.com
Pushing theefficiency envelope
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20/6018 www.PowerEngineeringInt.comPower Engineering InternationalSeptember 2014
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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Gas turbines
Power Engineering InternationalSeptember 2014
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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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
Planningmakes perfect
Credit: Dreamstime
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Gas-fired plants
Power Engineering InternationalSeptember 2014
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
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Gas-fired plants
Power Engineering InternationalSeptember 2014
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
energy investment report: We believe offshore
wind will be key for expanding renewable
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
28 Power Engineering InternationalSeptember 2014 www.PowerEngineeringInt.com
Benj Sykes
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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
32 Power Engineering InternationalSeptember 2014 www.PowerEngineeringInt.com
Iraqs electricity:from crisis to ISIS
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For queries relating to the
conference, please contact:
POWER-GEN Russia:
Emily Pryor
Conference Manager
T: +44 1992 656 614
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
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PROVIDING ENERGY SOLUTIONS & INNOVATION
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36/6034 www.PowerEngineeringInt.comPower Engineering InternationalSeptember 2014
Regional profile: Iraq
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
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38/6036 www.PowerEngineeringInt.comPower Engineering InternationalSeptember 2014
Regional profile: Iraq
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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Power Engineering InternationalSeptember 2014
Regional profile: Iraq
19 hydroelectric power plants, with an
installed capacity