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The magazine for the international power industry
REDUCING RISK INRENEWABLE PROJECTS
A CLEAN BILL OF
HEALTH FOR HRSGSEVOLVING SEALS FORNUCLEAR PLANTS
www.PowerEngineeringInt.com
June 2014
THE SCIENCE AND
MAGIC OF PUMPS
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HRSGs for the 21stCentury
CMI ENERGY
Cockerill Maintenance & Ingnierie
www.cmigroupe.com/energyFor more information, enter 1 at pei.hotims.com
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8/10/2019 Power Engineering 2014 n06
4/522 Power Engineering InternationalJune 2014 www.PowerEngineeringInt.com
Industry Highlights
The impact of energy policy continues to
turn the screws on the European power
industry with a vengeance.
The power industry is stuck in a terrible
catch-22. It didnt blindly walk into its troubles:
it was led there by policy decisions made by
politicians who thought they could predict the
future. But the industry needs the current crop
of politicians to help get them out of the mire
by introducing policies to kick-start investment
in an industry which is financially flat-lining.
Confidence in markets, future pricesignals and asset valuations has collapsed,
said Martin Giesen, chairman of Advanced
Power, at POWER-GEN Europe in Cologne this
month (see feature on p14).
Matthias Hartung, chief executive of RWE
Generation and RWE Power, delivered one of
the events keynote speeches and warned:
What we are doing in this business is not
sustainable This will destroy the European
energy system if we continue like this.
And Jonas Rooze, lead analyst of European
Power at Bloomberg New Energy Finance,said: All this change: companies cant keep
up; governments cant keep up. If companies
cant keep up they lose money. When
governments dont keep up, lots of companies
lose money because governments do things
like retroactive policy. Too much change has
been going on. You cant keep trying to fit
everything in the system you have now.
Meanwhile, on the exhibition floor, the
manufacturers of the next generation of
power equipment have the state-of-the-art
technology to delivery what became the
buzzword of the event: flexibility.
Vesa Riihimaki, president of power plants
and executive vice-president for Wartsila
Corp, told me at the show that Europe is on a
learning journey and that the toolbox is not
there yet for renewables integration.
He and his company and many others
like them have the kit to build such a toolbox,
but he says the problem is that flexibility is a
more difficult service to sell than energy.
Helmut Moshammer of Doosan Lentjes
also demanded flexibility: You have to be
flexible on market conditions, you have to beflexible on regional demands and we have to
adapt our products.
So the major players in the industry have
the will and the know-how to deliver a power
system for the 21st century. What they dont
have is the political backing.
Fast-forward a week from Cologne and
I was in London for an energy conference
examining Britains bid to build a low carbon
energy mix, which is not going much better
than many of its European counterparts.
Why? Dieter Helm, Professor of Energy Policy
at the University of Oxford, says it all comes
down to energy policies made a decade ago.Knowing the future is a very deadly way
of constructing energy and climate policy, he
said. All of the artefacts of European energy
policy are based on assumptions made 10
years ago by the leading politicians in Europe.
He said that in response to the current
state of the European energy industry, you
would hope that there might be a rethink.
Not a bit of it. Once a policy is committed
and politicians have nailed themselves to the
mast, the incentives to reinforce that policy are
very powerful.He said both the European Commission
and every single Member State were
struggling about what to do.
In the UK, he said that every single
investment in the electricity sector going
forward is being determined by the state,
on state-backed contracts, and the state is
picking the technologies.
We have basically decided in the country
that the market will not deliver the investment
programme so weve brought the state in.
And he warned: One shouldnt kid oneself
that this is a gradual intervention, a temporary
one that will give way to a return to markets.
The temporary has a horrible tendency to
become the permanent.
Does it have to be like this? Of course not,
but governments need to get over the desire
to pick winners and instead build an energy
portfolio that, at the very least, reflects what
can be delivered economically and securely.
Prof Helm says: We may have spent 50bn-
100bn on offshore wind yet just 1bn cant
be found for a CCS project.
So we can save money by stoppingdigging the hole were in... and let the market
rip.
Manufacturers ofthe next generationof equipment candeliver what hasbecome the industrybuzzword: flexibility.Kelvin Ross
Editor
www.PowerEngineeringInt.com
Follow PEi Magazine on Twitter:@PEimagzine
Follow me: @kelvinross68
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6/524 www.PowerEngineeringInt.comPower Engineering InternationalJune 2014
Power Report: Geothermal technology
Artificially creating geothermal reservoirs gives Enhanced Geothermal Systemsgreater siting flexibility than traditional geothermal power plants. This is
opening up Europe to the possibility of geothermal energy not only makinga significant contribution to the energy mix, but also contributing to systemstability, finds David Appleyard
CRACKING EUROPEAN
GEOTHERMAL CAPACITYWITH EMERGINGTECHNOLOGY
Krafla geothermal plant in Iceland: EGS
could boost Europes geothermal power.
Source: Landsvirkjun
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7/52www.PowerEngineeringInt.com 5Power Engineering InternationalJune 2014
Geothermal technology
Although Europe is not
generally considered to
have a particularly rich
geothermal resource, an
emerging technology
commonly referred to as
EGS enhanced or engineered geothermal
systems does offer an opportunity for
geothermal power to make a major
contribution to the energy mix.
EGS may be considered as a geothermal
system with a heat reserve which is artificially
created or enhanced. Like conventional
geothermal technologies, EGS also relies on
the heat contained within the earths crust.
However, while traditional geothermal systems
require an active resource close to the surfacecapable of delivering high temperatures, EGS
makes use of lower temperature resources
that are frequently at a considerable depth
below the surface. It takes advantage of the
naturally occurring phenomenon by which,
for every 100 metres depth, the temperature of
the surrounding rocks increases by some 3C.
Similar in some respects to the fracking
technology used to extract gas and oil from
shale deposits, EGS typically uses multiple
wells to inject water deep into a borehole,
stimulating rock structures at a depth of 3-10km.
This is because the rocks at these depths
are rarely porous due to the compressive
mass of material above these strata. EGS
development thus begins by increasing the
porosity of a geological structure, commonly
known as stimulation. Stimulation can also
involve the use of acids to dissolve obstructions.
Once the structure has been fractured
and becomes sufficiently porous, water or
brine can be injected into a well placed near
the centre of the reservoir.
Injection water passes through the hot
porous zone before it is extracted from the
production wells often multiple on the
edge of the reservoir. While the water from
the production wells is still at a relatively low
temperature perhaps 80C-200C when
compared with conventional geothermal,
another breakthrough technology may be
used to apply this heat for use in electricity
production.
Indeed, it is the development of so-called
binary cycle such as Organic Rankine
Cycle (ORC) or Kalina cycle machinesthat has allowed commercial exploitation of
the engineered low temperature geological
reserves. In binary devices such as ORC
turbines the heat is exchanged via a working
fluid, for instance refrigerant R134a, which
expands through a turbine imparting rotarymotion before being condensed into a liquid
again to repeat the cycle.
As a result of these relatively recent
breakthroughs, EGS is now attracting
considerable interest.
Europes EGS dream
Although the use of geothermal energy for
power generation effectively began in Europe
- with the 1913 development of Italys Larderello
steam field - Europes only opportunity to
develop geothermal power generation at any
significant scale comes from EGS technology,
as artificially creating geothermal reservoirs
gives greater siting flexibility than traditional
geothermal power plants.
Europe already has a number of projects
operating, with around half a dozen more
currently under development. The first such
project is located in eastern France in the
Alsace region near Strasbourg, close to the
German border. It is a research facility.
The Soultz-sous-Forts project was initially
launched back in 1988 and jointly funded
by the EU, France, Germany and privatecompanies. Of the 80 million investment in
the project, some 30 million has come from
the EU, with 25 million each coming from
Germany and France.
This pilot project draws on heat sources of
up to 200C located between 4500 and 5000metres in depth.
With deep geothermal energy identified
by the multi-party roundtable Grenelle de
lEnvironnement as an important focus for the
development of renewable energy in France,
as a research project Soultz-sous-Forts has
demonstrated the feasibility of stimulating a
reservoir, and four deep boreholes have been
drilled to date, three to more than 5000 metres.
Some 200,000 m3 of water was also injected
to open and clean fractures among the rocks.
With a 1 km separation between the
injection well and the two production wells,
the fluid in the geothermal loop travels an
estimated 11 km.
Power production using Turboden and
Cryostar equipment began in the autumn of
2007.
Although the reservoir created was not
designed for commercial operations, Soultz-
sous-Forts is used to generate electricity
and has a 2.1 MWe gross power generation
capacity, of which 1.5 MW is net production
to the grid.
After contributing to scientific work onwell stimulation with a view to developing
the site, in parallel with its operation by the
Siemens offers new solution for utilization of waste heat using the Organic Rankine Cycle
Credit: Siemens
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Geothermal technology
Siemens develops SST-500 GEO steam turbine for geothermal power plantsCredit: Siemens
European Economic Interest Group (EEIG) on
Heat Mining, BRGM (Bureau de Recherches
Gologiques et Minires) the French
geological survey is now conducting work
financed by ADEME on the sustainability of
the Soultz operation. The aim is to identify
the circulation routes between the wells
(by improving tracer tests and circulation
modelling) and understand how they evolve
during operations.
The aim of the Soultz project was to
demonstrate the feasibility of the underground
heat exchanger and show that the site is able
to produce electrical power and to supply it
continuously to the grid. It has now reached a
decisive phase, explains Sylvie Gentier, project
manager and research correspondent withthe Geothermal Energy Division.
Now we need to determine the operational
lifetime of this type of installation and identify
what problems can occur during operations.
As soon as we can show that the site can
operate permanently, other operations could
be planned in other locations for power
generation on a larger scale, Gentier said.
In parallel, thanks to improvements in
the performance of heat exchangers and
thermodynamic cycles, we have found that
power can be generated at a temperatureof less than 200C. From the experience
gained, we have good reason to expect the
development of CHP systems that could also
meet local demand for heat, particularly
from industries. These more decentralized
applications could be considered within the
next 5-10 years.
Finally, understanding the subsurface
environment at Soultz, where hot fluids
circulate, allows us to work on reducing the
geological risks - which are a critical issue in
this type of operation - with a view to operating
future sites from more closely targeted
boreholes, which would also reduce the cost.
Pre-commercial EGS development
In the wake of this European EGS research
plant, work began on two commercial EGS
projects in Germany.
The Landau EGS power plant is very similar
to the earlier Soultz development but is the
worlds first commercially funded EGS plant
and is a combined heat and power (CHP)
project, rather than power only.
Rated at 3 MW, the project beganoperations in 2007 following a three-year
construction phase. The facility in Landau
exploits 155C strata at a depth of 3000
metres. Water leaves primary cycle at 72C
and is then used for district heating for around
1000 households. At the end of the CHP cycle,
50 C water is reinjected into the well.
A subsidiary of Pfalzwerke AG andEnergieSudwest AG, Geo X GmBh, owns and
operates the plant.
The operators expect the plant to begin
to pay off after about 10 years and are
apparently already planning the Landau 2
geothermal power station.
In mid-2006 US-based technology firm
Ormat Technologies received an order worth
some $4.4 million to supply a pre-assembled
ORC turbine and generator unit for the
Landau development.
The construction was undertaken by a
third party under a consortium agreement
with Ormat.
The second commercial German project
was also developed by a unit of Pfalzwerke
on the southern edge of the town of Insheim.
Launched in 2007, the project utilizes a 165C
resource located at a depth of 3800 metres. It
was connected to the grid in 2012.
The power plant supplies electricity to
approximately 8000 households, while the
residual heat is used in a district heating
network.
With a number of modest-scale EGS plantsnow operating in Europe, the scene is set for
the development of larger projects.
According to Philippe Dumas, Secretary
General of the European Geothermal Energy
Council (EGEC), there are now several
projects in the pipeline at various stages of
development.
Two EGS projects are located in the UK,two in Belgium, in France there are between
four and six potential projects underway, there
is one in Hungary (financed by the EU and
expected to be operational by 2018-2019),
and in Germany there are a further three to
five EGS projects under development.
Among the more advanced projects are
installations in Munich, Germany.
Developed on behalf of the local municipal
authority Stadtwerke Mnchen (SWM) in
mid-2010, the municipal authority signed a
contract with Italys Turboden for the supply of
a 5 MWe ORC and generator unit.
Based on a two pressure level cycle and
fed with geothermal fluid at 140C, the plant
also provides the existing district heating
network with an additional 4 MWth. It uses
forced air condensers.
General contractor Karl Lausser GmbH
was awarded the public works contract with
startup in late 2011.
Paolo Bertuzzi, General Manager of
Turboden, comments: This 5 MWe geothermal
plant is going to be an important benchmark
for both Turboden and the Europeangeothermal industry.
Turbodens other European EGS
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Geothermal technology
geothermal projects include a 1 MWe plant in
Altheim, Austria.
SWM is also developing a number of
additional geothermal projects as part of
its campaign to produce all of its electricity
requirements for the Munich municipality
some 7.5 TWh annually from renewables by
2025.
The 10 MWth geothermal system in Riem,
a newly built district of Munich, uses 93C
hot water from a depth of some 3000 metres
with two boreholes sunk into the Malm karst.
Development of the project began in 2002
and the project was commissioned in 2004,
supplying district heating. Most recently,
the geothermal system at Sauerlach was
officially commissioned in January 2014. Witha temperature of more than 140C from a
depth of about 4200 metres, the Sauerlach
CHP project features three boreholes two
injection and one production and the plant
generates heat and electricity for around
16,000 Sauerlach households.
In total SWM has earmarked a budget of 9
billion for the expansion of green generation
out to 2025.
EGS: a global phenomenon
While Europe is taking a strong position inEGS development, the advantages of the
technology have not been lost on other
regions. For example, the US and Australia
have both made progress over the last year or
so in developing their own EGS projects.
Following the 2008 award of a US
Department of Energy (DOE) grant to Ormat,
GeothermEx Inc and other stakeholders, in
April 2013 Ormats Brady facility near Reno,
Nevada began supplying 1.7 MW of power to
the grid.
Support for the project included $5.4
million in direct DOE funding and $2.6 million
in investment from Ormat.
Brady followed a DOE-funded EGS
demonstration and development project at
Ormats 11 MW Desert Peak site about 10 miles
(16 km) away from Brady.
Additional US EGS projects by Calpine
Corp, Ormat Technologies, and AltaRock
Energy all received federal administrative
support during 2013.
Aside from US projects, in April 2013 Australia
also began generation operations at its first
EGS plant, the 1 MW Habanero developmentnear Innamincka in South Australia.
This research installation has been
developed by Geodynamics Limited and
was supported by the Australian government
through the Australian Renewable Energy
Agencys provision of the Renewable Energy
Demonstration Program grant funding.
Habanero has achieved a well-head
temperature of 200C from its production well
of some 4200 metres depth.
Challenges and opportunities
While there is clear evidence that EGS
technology is gaining both investor support
and commercial operating experience, some
challenges remain to be overcome before it
can become a widespread and economically
attractive renewable energy resource.
Dumas points out that one of the biggestobstacles is the relative absence of accurate
geological data. One of the reasons EGS
projects take such a long period to develop
typically five to seven years is that
considerable resources must be expended
on geological exploration.
In addition, the required environmental
permitting can also be a lengthy process.
In practice, in Germany and France its 18
months to two years before you have your
permit, says Dumas.
There is inevitably some geological riskwhere a well is drilled only to find that the
anticipated resources are not realized.
Indeed the history of EGS development
presents a number of projects which have
been abandoned due to adverse geological
conditions.
However, Dumas points to the emergence
of innovative financial tools, such as risk
mitigation insurance schemes, which can
address this challenge.
Not only is geological data limited, but
exploration is also rather costly. Dumas
suggests that an initial investment of 7-10
million is required. Furthermore, given that EGS
projects tend to be relatively small, sometimes
some months are required to arrange finance
for this type of exploration, particularly as these
projects are often led by smaller developers.
Its quite capital intensive so needs a large
amounts of financing and today, in the current
economic climate, banks are hesitating in
financing projects so you need some new
players, he adds, pointing to the insurance
industry, venture capital, pension funds,
utilities and the oil and gas sector as potentialsources of new finance.
However, while oil and gas majors with
their keen insight into geological risk may
seem an obvious avenue, Dumas suggests
they are still hesitating as these projects are
typically too small to attract their interest.
The third, and perhaps most significant,
obstacle is the cost.
Dumas explains that for EGS to be
competitive it must have a total production
cost of electricity LCOE, plus system costs,
plus externalities of around 10 euro cents/
kWh.
The main opportunities for cost reduction
are increasing the size of the projects, thereby
decreasing the relative drilling costs. Drilling
costs currently account for around 70 per
cent of the total capital development costs, he
says, given the requirement to drill more wellsfor EGS development.
We expect the [forthcoming] projects to
have a capacity of at least 5 MW, but at this
stage they are anticipated to have a capacity
of not more than 10 MW. Projects above this
capacity are the next step, says Dumas.
Nonetheless, Dumas adds: We expect to
be competitive before 2030, perhaps even
2025.
He concludes: EGS is the only way to
produce a large quantity of geothermal
energy in Europe. We have really a few placeswith a high enthalpy, so its the only possibility
for geothermal power to expand.
There are plenty of research projects and
the sector is really rich in innovation and new
technologies. Currently there are new drilling
technologies, new simulation processes, new
turbines.
We are quite optimistic for two reasons.
Firstly, EGS is a new technology with a recent
breakthrough so we need to increase our
experience of this technology to show its
potential, and secondly, we think that all
technologies can be quite instrumental in the
future electricity mix in Europe.
Geothermal can be instrumental
because it can be flexible, so it can play a
role in stabilizing the grid by, for example,
switching production to heating or increasing
production of electricity.
Its flexibility is key to the future stability of
the grid.
David Appleyard is a journalist focusing on
energy matters.
Visit www.PowerEngineeringInt.comfor more informationi
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Power plants rely on plant-specific
bespoke pumps to ensure the
successful operation of the plant
and its key functions. In mostpower plants, the three key pump
duties are boiler feed, cooling
water and condensate extraction pumps. In
addition, auxiliary process pumps are utilized
for balance of plant functions which can
include boiler feed booster, closed circuit
cooling water and other auxiliary services.
While all pumps play a key role in the plant
process, from a service and maintenance
perspective, boiler feed pumps are often
considered the most costly and integral units
in the plant. They are critical to availability and
performance.
Each of these pumps is purpose designed
on a plant-specific basis. No two power
plants are alike even in duplicate plants, the
pressure, temperature, altitude and cooling
water properties will differ and this must be
factored into individual pump design.
Drivers for change
Within power generation, pumps may be
expected to operate for 40-plus years. Total
lifecycle costs are considerable, with initial
capital costs comprising as little as 5 per cent
of the total. Energy is the biggest cost over the
life of a critical pump, hence energy efficiency
improvements have the potential to offer
substantial savings for the overall plant.
A seminal report on pump performance
published by the Finnish Technical Research
Centre some years ago found that the
average pump operates at less than
40 per cent efficiency in the field, and
Pumps
Critical to powerplant availability andperformance, purpose-designed pumps playa key role in plantoperations, yet theaverage pump operatesat less than 40 percent efficiency in thefield. However, changeis underway and newdevelopments are afoot,finds Penny Hitchin
Pump developers are working to maintain initial efficiency levels as the pumps age
Credit: Andritz
8 Power Engineering InternationalJune 2014 www.PowerEngineeringInt.com
Pumps poised to shiftup a gear to meet
efficiency demands
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Sulzer Bringing Excellence
to Power Generation
Sulzer provides complete pumping sys-
tems solutions with leading-edge technol-
ogies backed by our long-standing exper-
tise in engineering and innovation.
our dedicated teams of experts work
closely with you to develop the right so-
lutions and services to match your spe-
always close to our customers.
Find out how we can develop the ideal
pumping solution for you.
www.sulzer.com
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12/5210 www.PowerEngineeringInt.comPower Engineering InternationalJune 2014
Pumps
10 per cent of pumps operate at less than
10 per cent efficiency. The major factors
affecting performance include efficiency of
the pump and system components, overall
system design, efficient pump control, and
appropriate maintenance cycles.
The report identified pump over-sizing
and throttled valves as the two key problem
instigators, highlighting the importance of
specifying and designing pumps that are the
appropriate size for the system they serve.
As efficiency declines with age, pump
developers are working to maintain initial
efficiency levels for longer, extending
overhaul intervals and reducing downtime.
Areas where operational and maintenance
issues in existing pumps may be addressed
by adopting newer design solutions include
hydraulic passage design, upgradedmaterials, coatings technology, improved
bearing designs, and modern sealing
technology.
The outcomes should be increased
reliability and mean time between overhauls;
optimized energy use; an increase in power
generation availability; improved corrosion
and erosion resistance; improved vibration,
pressure and pulsation; and reduction in
noise attenuation issues.
Incorporating developments in materials,
metallurgy and coating technologies
offers advances for pump manufacturers.
Metallic materials capable of operating
at ever-increasing temperatures are being
developed for power plant and aero-engine
applications.
Use of more corrosion-resistant materials
will extend the mean time between
overhauls. The resistance to erosion, corrosion,
and cavitation of silicon carbide polymers
can increase the life of some applications,
and coatings have the advantage of being
easily restorable if damage to the material
occurs.
Pump manufacturers are constantly
refining their products. Sulzer says that
innovation will enable reduced investment
and operational costs and shorten the lead
time of the new range of custom-built pumps.
The companys latest single stage mixed
flow vertical cooling water pumps with semi-
open impellers provide total pump efficiency
of over 90 per cent, which leads the market.Optional full pull-out construction reduces
lifting crane capacity and facilitates easy
maintenance.
Operators look for every technique that will
delay maintenance and minimize downtime,
and digital sensors and controls provide
operational information to support this.
Increasingly sophisticated instruments make
it possible to measure and monitor processes,
and this data can be used to control
operations and optimize maintenance input.
Condition-based monitoring can extend
service intervals and ensure that intervention
takes place only when required.
Analyst Anand Mugundhu
Gnanamoorthy, industry manager,
Industrial Automation and Process Control
at Frost & Sullivan, says that as pumps may
be used for decades buyers are increasinglymoving towards considering total lifecycle
costs.
Operators have to find the BEP (best
efficiency point). In pump operation there is
a very narrow band in which to operate at a
high efficiency. If it is run at any other speed
or any other load, there is a loss of efficiency,
Gnanamoorthy says.
Martin Unterkreutzer, senior sales
manager at Andritz, says: The main drivers
for development in pump technology are
the reduction in maintenance intervals
driven by improvement of materials, but
also by incorporating features like condition
monitoring. Efficiency will surely become
more and more important as energy prices
increase. Right now, unfortunately, many
customers do not yet think in that way since
electricity is fairly cheap.
Pumps in thermal power plant
In the past, pumps were primarily designed
for continuous operation in coal-fired plants.
Pumps are not stopped often (a few times per
year on average) and may need up to four
or five hours from cold start to reach optimum
operational conditions.
The shift to new and different fuels, such
as gas and biomass, will see plants running
on altered operating regimes often requiring
new pump designs with a variety of new
characteristics.
The start-stop cycle requirements of a
combined-cycle plant require a completely
different operating philosophy. Pumps must
have cold-start capability, which may be
required more than once per day. Thus,pumps in combined-cycle plants are
designed to withstand thermal shocks
much better than pumps designed for coal-
powered stations. The pumps work at different
speeds and require design changes in rotor
dynamics, hydraulics and impeller design.
Some of the changes may be quite small:
for example, minimal changes in design of
the impeller or the stiffness of the shaft can
make significantly increase efficiency over
the life of the pump. Pump manufacturers
have ongoing development work underway
to improve the design and efficiency of the
pumps used in such plant.
The natural gas boom in the US means
Metallic materials capable of operating at ever-increasing temperatures are being developed
Credit: Andritz
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Pumps
that gas is likely to fuel over half of the countrys new generation
capacity over the next 20 years. In Europe, combined cycle gas
turbine (CCGT) plant will play a key role in the transition to a greener
energy mix, backing up intermittent renewable energy supplies andproviding a lower-carbon alternative to coal.
The clean coal technology of ultra-supercritical (USC) steam
plants operates at very high pressures, promising higher efficiency
and a relative decrease in emissions.
The boiler feed pumps that generate very high pressure need
hydraulics, metallurgy and bearings which are able to operate
under such harsh conditions. The hydraulics must be capable of
generating pressure of 4500 psi and above. Suitable metallurgy must
be employed, especially for the barrel enclosure which is designed to
handle 12 000 psi.
The boiler feed pumps are very large, with a thick wall construction
surrounded by substantial insulation.
Renewable energy leads to new pump designs
The growth in renewable energy is bringing new pump designs to
market. Biomass generation, which generally involves a lower output
than traditional coal and gas generation, requires low- and medium-
pressure boiler feed pumps, which require pump size reduction and
potential redesign.
While concentrating solar power (CSP) plants use conventional
steam generation equipment, specialized pumps are needed to
move the high-temperature molten salt used to store the heat of
the sun. Large quantities of molten salt stored in an insulated tank
reach temperatures as high as 600C. A highly specialized pump is
needed to pump the salt to the heat exchanger, enabling electricity
generation to take place around the clock.
Fred Grondhuis of Flowserve talked to PEi about the specialized
vertical turbine pump his company designed for this application.
Operating at 600C means using specialized high-temperature
alloy materials for construction, as normal materials would not be
suitable. The pump is submerged in the molten salt and it reaches
all the way down to bottom of the tank to capture the last amount of
energy from the tank. The molten salt also actually lubricates internal
components of the pump, he explained.
Development of the pump took a little over two years followed by
high-temperature testing at a US government lab. The first pumps were
installed five years ago in Spain, and further installations have takenplace in the US and South Africa. The pump is designed for a 30-year
operating life.
Fukushima disaster drives nuclear safety changes
In March 2011 a major earthquake off the coast of Japan caused a
tsunami to strike the Fukushima Daiichi nuclear power plant. With the
power supply disabled, the reactor coolant pumps ceased operating,
which led to a major nuclear accident. The disaster has led to a raft of
safety enhancements at nuclear sites globally.
The conventional generation side of a nuclear plant has pumps
similar to those used in a standard thermal plant. Nuclear operators
are now taking steps such as putting in an extra pump that will run
even if there is no power, to ensure that reactor cooling will continue.
Additional redundancy is being added to plant to increase safety
levels. Pumps are being subjected to submergence tests to make
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14/5212 www.PowerEngineeringInt.comPower Engineering InternationalJune 2014
Pumps
sure that they will work underwater. In most
nuclear reactors the primary coolant
pump operates at around 300C at
relatively low pressure. A mechanical seal isintegrated into the pump. Since Fukushima
a lot of attention has focused on loss-of-
coolant accident, posing the question:
if the pump stops, will the shaft seal still
work?
To prevent this, pump and seal specialist
Flowserve has upgraded its design to include
a passive shutdown abeyance seal built into
a cartridge. The interchangeable cartridge
is suitable for Flowserves and other OEMs
reactor coolant pumps, and the cartridge
design means no component assembly is
required in containment. The upgrade design
has been introduced into the market in the
last two years.
Flowserves Grondhuis says, The Flowserve
N-Seal with the abeyance seal design is
generally accepted as one of the best
methodologies to prevent against leaks. It has
been installed in the US and we are talking to
customers globally to do conversions.
Looking to the future
Pumps have come a long way since the
shadoof, the earliest known pump, was
developed 4000 years ago by the ancient
Total Pumps Market: Revenue Forecasts for Power Generation, 20102020, Global
Credit: Frost & Sullivan
This case study highlights a cooling water
pump featuring adjustable impeller blades
which can be adjusted without affecting
operations. The pump is deployed in thermal
power stations where the cooling water
quantity needs to be regulated.
Ensuring a good fit between pumps and
the system is a key in ensuring efficiency.
Power plant cooling water pumps may
be required to operate with different
combinations of delivery rate and head.
Impeller angles and speed are two of thevariables which affect pump efficiency.
Different rates of water flow and head
require a range of impellers operating at
specific speeds. The impeller design and
the initial angle of the blades are selected
to meet specific process requirements
before a vertical line shaft pump is installed.
However, additional flexibility beyond fixed-
angle impellers or manually adjusted
impellers may be needed for instance, if
there are fluctuations in the cooling water
level or differences between day and night
operations.
There are typically two ways to achieve
this: speed control with a frequency
converter, or hydraulic impeller blade
adjustment.
A frequency converter has its strength
in applications with large fluctuations in
head. While the pump can be adjusted with
infinitely variable speed control, there may be
a higher cost associated with the frequency
converter for large cooling water pumps,
including cabling and the air-conditioned
room required for installation.
The pump division of Austrian engineeringcompany Andritz has incorporated a
hydraulic device into its vertical line shaft
pumps which can adjust the impeller
blade angles to accommodate changing
conditions while the pump continues to
operate.
The hydraulic adjusting device comes
into its own where substantial changes in
delivery rate are required. The system enables
the impeller blade angle to be moved up to
15 between minimum and maximum. An
oil-filled servo-cylinder rotates the impeller
blades via sliding blocks and adjustable
cranks, an established technique that
Andritz has been using in its water turbines
for decades.
Using hydraulically adjustable-angle
impeller blades enables compensation for
changes in operating conditions while the
pump is in operation, avoiding downtime
and optimizing efficiency. Andritz says the
system has a long service life and does not
require any electronic spare parts (which
may become obsolete over the 40-year life
of a power plant system).
Examples of power stations which use thehydraulic impeller adjusting device include:
t " DPBMSFE QPXFS TUBUJPO JO UIF
Netherlands where less than half the normal
volume of cooling water is required during
thermal shock operations;
t " DPBTUBM QPXFS TUBUJPO XIFSF B
hydraulic adjusting device is used to cover
the difference in cooling water delivery head
caused by a big tidal range of 1024 metres.
The lower efficiency of frequency converting
plus the higher costs for the frequency
converter made the hydraulic impeller blade
adjusting device a far more economical
option.
Case Study: Adjustable angle impellers: added flexibility for cooling water pumping
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15/52www.PowerEngineeringInt.com 13Power Engineering InternationalJune 2014
Egyptians who used a suspended rod with a bucket on one end and
a weight on the other to draw water from wells.
Looking forward, further developments are needed. For example,
if carbon capture and storage (CCS) is to be implemented on anindustrial scale, more robust pumps will be required, often demanding
API-type specifications for seemingly non-API applications.
Working with CCS involves the need to pump either CO2gas or
liquidized CO2. Carbon dioxide requires a robust sealing system, and
as CCS is an inherently cost-negative activity it is important to reduce
the failure rate and avoid extra expenditure.
Automation and remote and condition monitoring are playing
an increased role in power generation, driving costs down by
reducing the workforce needed to operate plant. Frost & Sullivans
Gnanamoorthy believes that continued development of intelligent
pumps will lead to increased efficiency.
The pump industry has traditionally needed a lot of technicians
for maintenance, but end users are looking to move away from this
towards the intelligent pump which will report when maintenance
required, he says.
Remote monitoring and intelligent pump monitoring is evolving.
It has been pioneered in agriculture and oil and gas, and introduced
in the last five years in North America and Western Europe. We are
now starting to see it introduced in power plants.
Global pump market
Power generation is a relatively small segment of the global pump
market. In 2013, 14.3 per cent of global pump revenues came from
power generation. That year the global revenue from pump sales to
the power generation market was around $5 billion, and the rate ofgrowth was 5.9 per cent, according to Frost & Sullivan. Rates of growth
are predicted to increase steadily to around 10 per cent by the end
of the decade.
The fastest growing sectors for pump sales are oil and gas and
agriculture. In the market for pumps, emerging economies such as
the BRIC countries (Brazil, Russia, India and China) have a growing
demand for power.
This is reflected in a buoyant market for pumps in these areas.
Other regions where population growth, rising standards of living and
urbanization are fuelling growth include the Asia Pacific region, North
Africa and the Middle East.
As the general economic environment improves in North Americaand Europe, pump revenues are expected to gradually return to
moderate growth rates.
Demand for power in the mature economies of Western Europe is
starting to recover from the effects of the recession, during which a
reduction in the demand for energy inevitably stalled plans for new
capacity. Europe is seeing plans for plant upgrades and additions.
The focus is on improving efficiency by replacing inefficient pumps
and motors or, increasingly, on adding variable speed drive systems
to enable multi-speed functioning, reducing energy use.
Penny Hitchinis a journalist focusing on energy matters.
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Pumps
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ANDRITZ pumps
Cooling water applications
ANDRITZ vertical line shaft
pumps, pull-out or non pull-
out type, with radial, mixed
flow or axial impeller, fitted
with impeller blades that are
either fixed or adjustable dur-
ing operation, are used ascooling water pumps in power
plants or for water supply.
These pumps are customized
for heads up to 80 m and flow
rates up to 70,000 m/h.
ANDRITZ AG
Stattegger Strasse 18
8045 Graz, AustriaPhone: +43 (316) 6902 0
Fax: +43 (316) 6902 406
[email protected] www.andritz.com
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Three years of the Energiewende
and its consequences unintended or otherwise on
the European power sector were
starkly analyzed and debated
over three days in Cologne at
POWER-GEN Europe earlier this month.
With many of the major European
operators counting the cost of mothballing
state-of-the-art plants, you would have
expected them to be downbeat about the
state of the power market and they were.
But there was anger, too, at the situation they
found themselves in.
A blistering attack on the rise in
renewables subsidies and the phase-out
of nuclear power was delivered by Martin
Giesen, chairman of Advanced Power.
Delivering one of the speeches at the JointOpening Keynote Session, he said the
combination of the two coming on the
back of the economic crisis had been a
truly deadly mixture.
And he added that this deadly mixture
had resulted in combined losses of 200bn
for major utilities EDF, E.ON and RWE. These
are horrendously large numbers, he said,
adding the cost could also be counted by
saying that every citizen of the EU has lost
1000.
This is all bad enough, he added,
but perhaps worse is that confidence
in markets, future price signals and asset
valuations has collapsed. Government-
POWER-GEN Europe round-up
Power panel: Karel Beckman kicks off the Plenary Panel discussion
Credit: PGE
14 Power Engineering InternationalJune 2014 www.PowerEngineeringInt.com
European policyunder the microscopeThree years ofEnergiewende, three
days in Cologne: thedebates during POWER-GEN Europe this monthgave a fascinating insightinto the future of Europesenergy market, writeKelvin Rossand TildyBayar
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POWER-GEN Europe round-up
mandated subsidies for renewables whose
impact was enormously underestimated
have completely changed the industry.
And government-mandated shutdowns ofnuclear stations have taken away trust and
ownership rights and the rights to enjoy the
benefits of that ownership.
Also speaking at the Joint Opening
Keynote Session were Matthias Hartung, chief
executive of RWE Generation and RWE Power,
and Vesa Riihimaki, president of power plants
and executive vice-president for Wartsila.
Mr Hartung warned that what we are
doing in this business is not sustainable.
He said his company was already
shutting down or mothballing power plants,
and highlighted the case of a 48 per cent
efficiency CCGT plant in the Netherlands
which had been shut down.
In Germany we have a complete
transformation of a countrys energy sector,
yet he said that this in fact involved two
transitions: a small energy transformation
until 2022 when the phase-out of nuclear
will be complete, and then a large-scale
transition to 2050.
While he stressed his backing for the
Energiewende the transition is necessary:
we are supporting it and changing our
business model he added: To fulfil this
we also need support from the political
environment and the regulatory framework.
He said for a successful energy transtition,
policy reforms are necessary at both
European and national levels, and these
reforms are vital, he stressed, because this
will destroy the European energy system if we
continue like this.
Mr Riihimaki said that what Germany
and the rest of Europe needs in order to
rebalance the intermittency of renewables inthe system is a flexibility toolkit. But in order
to embrace and utilize flexible generation, he
said there is a need for a flexibility market.
Not a capacity market a flexibility
market. Flexibility means resources that we
can keep in standstill, switch on and then
switch off again. This requires a new business
model.
On day two of the show at the Joint Plenary
Panel Discussion, the flexibility message
continued, combined with a pragmatic view
that there is no going back from the energy
transition in Europe and it will fundamentally
change the way we think about the role of
electricity providers.
The genie is out of the bottle and the
genie in this case is the energy transition,
said moderator Karel Beckman, Editor-in-
Chief of Energy Post.However, he added that the good news
is that there are lots of opportunities.
Helmut Moshammer of Doosan Lentjes
said that while it was hard to give a clear
strategy for the next 10 years, the key
business areas to be focused on are flexibility,
technology and resources.
On the first he said: You have to be flexible
on market conditions, you have to be flexible
on regional demands and we have to adapt
our products, while on resources he stressed:
These are our employees. There is only one
way to go forward and survive and that is to
have good motivated employees.
Emmanouil Karakas, president of EPPSA,
a trade body of 20 thermal power plant
component manufacturers, said bluntly: We
are not the bad guys.
He said that in the new world of greater
renewables integration, thermal power has a
vital role to play in providing flexible backup,
cost-competitive supply and security of
supply.
Jim Lightfoot, chief operating officer for
Gas-CCGT at E.ON Generation, also stressed
that the turbulent changes of recent years
were only accelerating and were here to
stay.
And he added: This transition isnt cheap
so we have to make it investable. We will
need a much clearer and stable framework
to gain investor confidence.
In terms of financing, he said the power
sector is seeing entrants such as pensionfunds, who are taking a punt on the market
in the expectation that it had hit rock bottom
and the only way was up from now on.
Jonas Rooze, lead analyst for European
power at Bloomberg New Energy Finance,
said that the rate of change in the energy
sector is so fast that it is leaving people
behind.
All this change: companies cant keep
up; governments cant keep up. If companies
cant keep up they lose money. When
governments dont keep up, lots of companies
lose money because governments do things
like retroactive policy. But the reality is that
governments need to catch up. They need to
make some changes. The system cant look
the same over a 1020 year period as it does
now. Too much change has been going on.
You cant keep trying to fit everything in the
system you have now.
And he added: We expect to see the
impact of solar to get more extreme. By the
late 2020s to 2035, off-peak will be the new
peak and peak will be the new off-peak.
The one thing we know for sure is that
there is a huge demand for flexibility. The
system will need to change and how is the
big question. The pie is getting bigger its
how it is distributed that is changing.
Meanwhile, John Easton, vice president of
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POWER-GEN Europe round-up
international programmes at Edison Electric
Institute, said the US was seeing many of the
same issues as Europe.
We see flat demand and flat sales. We seeenvironmental policy driving energy policy.
And in answer to his own question, what is
our business going to look like in the future,
he said: The customer is going to be king.
He added that for utilities to move forward
they were going to have to become market
enablers and solutions enablers.
Renewables and climate change
While the exhibition floor played host to a
raft of product launches and business deals
being clinched, the conference rooms picked
apart the nuts and bolts of the latest power
technology and also the money driving them.
Why is our firm interested in investing in
renewable energy and energy efficiency?
asked Patrick Avato, climate business lead
at IFC, in a panel discussion called Investing
in existing and new assets: strategic options.
Because climate change is affecting our
clients.
He pointed to rising energy prices in
a number of countries, the growing cost
and increasing scarcity of water for power
projects, and the growing risk areas of
weather and policy. As a private-sector arm
of the World Bank, he said, were faced
with the expectation that 80 per cent of
our project financing should come from the
private sector. But why would the private
sector invest so much, he asked? Is this
actually an opportunity that can generate
significant returns?
To answer this question, IFC conducted
what Avato said is the first comprehensive
study on climate-smart business in
Europe, the Middle East and North Africa.The study found that the opportunity is
huge: between now and 2020 it found
$640bn in commercially viable investment
opportunities, almost half of which are in the
energy sector.
Looking at specific countries, Russia is
not that interested in renewables and
not an ideal investment climate, yet IFC
found that the size and structure of its
economy and the age of its assets make it
a big opportunity market. In its far east and
Siberia there are off-grid locations with high
power prices, and across the country there
are aging power plants and infrastructure.
Russias losses of power and heat due to an
aging grid are equal to Frances total annual
energy production, Avato said.
Large swathes of central Asia such as
Kazakhstan also feature aging infrastructurenetworks, parts of which are not recoverable,
but there are still significant opportunities
in refurbishments and upgrades of district
heating systems.
Other big-opportunity countries include
the newest EU Member States and Poland,
Romania and Turkey, the country with the
fastest-growing energy market in the region.
Opportunities for investment in renewable
energy projects are strongest in eastern
Europe, IFC found, while there are also big
opportunities in upgrading existing power
plant and transmission/distribution assets.
We only invest in projects where we
expect to make returns, Avato concluded;
We think this region at this time, with these
technologies, is a significant opportunity.
The market for large plants is over
In a bid to take the pulse of the power sector,
a new feature was introduced at this years
POWER-GEN Europe audience voting. During
a panel discussion on the final day, members
of the audience were invited to contribute
their opinions via handheld voting devices.
Nine questions were asked and here is a
roundup of the often surprising answers.
1. What regulatory structure would be
best for Europes electricity sector: fully
regulated, fully open, or a compromise
between the two?
Almost 83 per cent of the audience opted
for the compromise option, with regulated
markets coming a distant second at
10.3 per cent and a fully open single
market proving a dismal third choice at
6.9 per cent.2. Given the current economic, technical
and regulatory constraints, is Europe
right to be pressing ahead so fast with its
decarbonization agenda?
While the audience agreed that
decarbonization is a priority, attendees were
divided on how it should be pursued, with
43.3 per cent choosing Yes, as quickly as
possible and 50 per cent answering Yes, but
at a slower pace. No, we should not make
this a priority was chosen by just 6.7 per cent.
3. What is the best available way to
address intermittent generation in Europes
grid system?
Perhaps unsurprisingly, the top answer
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POWER-GEN Europe round-up
from this crowd of power producers was
Use of flexible fossil-fired generation at
30 per cent. The next most popular answer, at
23.3 per cent, was Deploy available storagetechnologies, followed by Deploy demand
response, e.g. smart meters/appliances/
grid solutions at 20 per cent. Better integrate
electricity and heat markets garnered
13.3 per cent of the vote, while Strengthen
and increase interconnections and Use
nuclear power to back up solar in the winter
tied at 6.7 per cent.
4. What would you like policymakers to
do with the European Emissions Trading
System (EU-ETS)?
Interestingly, this question produced
a three-way tie between very different
responses. Scrap it, Increase the floor price
to discourage coal and lignite generation,
and Use the mechanism but with more
restricted allowances each received
28.6 per cent of the vote. In last place at
14.3 per cent was Allow the CO2price to find
its own level.
5. What would have the greatest positive
effect on kick-starting large-scale power
project development in Europe?
An upturn in economic conditions
received a modest 6.7 per cent of the
audience vote, while Removal of subsidies
for renewables received only 3.3 per cent.
After numerous discussions on the need
for a capacity market during the three-
day conference, it was surprising that
Guaranteed value for capacity received
only 20 per cent of the vote. At 23 per cent
was A reliable long-term policy framework
from Brussels but the big winner, and again
perhaps a surprising answer, was None
the market for large power plants will never
return, at 46.7 per cent.6. What do you think is most l ikely to have
the greatest impact on Europes electricity
sector in the next five years?
Lower cost of renewable generation
proved the most popular answer to this
question, at 37.9 per cent of the vote. Next
was development of shale gas in Europe at
24.1 per cent, followed by electricity storage
at 17.2 per cent. Smart technologies drew
13.8 per cent, while deployment of CCS and
electric vehicles tied at 3.4 per cent.
7. How do you feel about recent
consolidation among equipment and
service suppliers?
Concerned that innovation and R&D
will suffer was the view expressed by
33.3 per cent of the audience, while
30 per cent believed consolidation to be
a Natural and healthy consequenceof tough market/economic conditions.
Twenty per cent were Concerned that
Europes global influence in power
engineering will suffer while 16.7 per cent
termed the consolidation a Regrettable
reduction in competition among suppliers.
8. Do you expect the growth of electric
vehicles to noticeably increase electricity
use in Europe in the coming decade?
The impact of EVs is still an open
question, if the votes are any indication. While
38.7 per cent of the audience voted Yes,
the same percentage 38.7 per cent voted
No, with 22.6 choosing the I dont know
option.
9. Who do you expect will be responsible
for the majority of power generation in
Europe in 10 years time?
Decentralized energy is on the rise,
according to the audience: 46.7 per cent
chose Small municipal/local producers. But
the status quo had its supporters: another
36.7 per cent opted for Large centralized
utilities.
Prosumers were chosen by only
6.7 per cent, while Other entities e.g. Google
or Amazon! was selected by 10 per cent.
If we take the opinions of these industry
professionals as read, Europes future power
sector will be decentralized, with big utilities
going the way of the dinosaur.
The future EU electricity market will
combine regulated and open elements.
Fossil fuel-fired power plants will continue to
back up intermittent renewable generation
as Europe moves, at a slower and steadier
pace, toward a low-carbon future; costs forrenewables will continue to fall, and energy
storage will increasingly come into play.
The ETS will be reformed in a manner
yet to be determined, or done away with
altogether. A capacity market may be
implemented, but will not rescue big utilities
from their death spiral in the end. Europes
global competitiveness may suffer due to
industry consolidation, but when economic
conditions improve this trend may reverse.
And EVs may or may not contribute to
growing electricity demand.
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Deposits and corrosion
on heat recovery steam
generator (HRSG) tubes and
other surfaces are inevitable
problems and are a common
cause of reduced steam
production, sinking steam temperatures and
degraded combustion turbine efficiency.
The effects of a fouled HRSG are also tied
to reduced electricity production and lost
revenue.
A number of factors contribute to deposit
formation on HRSG tubes, including fuel
sulfur content, tube leaks, insulation failures,
ammonia injection for NOx control, and
condensation due to low stack temperatures.
Corrosion also becomes a major problemin plants operating in locations with high
humidity, particularly when cycling plants
originally designed for baseload operation.
HRSGs equipped with oil supplemental firing
also experience a higher rate of tube fouling
than when burning only natural gas.
Over time, fouling of finned tubes can
bridge the gap between adjacent tube
fins or other heat transfer surfaces, further
disrupting heat transfer and increasing the
gas-side pressure drop. Increased HRSG gas-
side pressure drop will degrade the efficiency
of the combustion turbine (CT) and thus the
heat rate of the entire combined-cycle plant.
In cases where the HRSG performance is
severely compromised, the entire plant may
require an extended forced outage to repair
corrosion-induced tube leaks, clean tubes of
deposits, or even replace an entire module.
Mitigating deposits and corrosion
Removing HRSG gas-side deposits should be
a part of every plants annual maintenance
program. Effective maintenance planning
can be improved by closely monitoring
specific operating parameters, such as
CT backpressure, steam production and
temperature (for each pressure level) and
stack temperature, and comparing the data
against corrected plant design conditions. In
addition, plant heat rate and output should
be tracked. Carefully scrutinizing the datacan provide advance warning about the
Heat recovery steam generators
Steam production isstrongly influenced bythe cleanliness of thegas-side heat transfersurface in a heat recoverysteam generator. CO
2
pellet blasting is themost cost efficient andenvironmentally benignapproach available toowners and operators,write Christopher NortonandRandy Martin
A clean bill of
health for HRSGs
A nozzle directs the pellets directly on deposits. When the CO2 pellet
changes phase from solid to a gas, the deposit breaks free.
Credit: Environmental Alternatives, Inc.
18 Power Engineering InternationalJune 2014 www.PowerEngineeringInt.com
Figure 1: CO2blast cleaning uses small
cylindrical dry ice pellets to remove fouling,
rust and scale from tube and fin surfaces. The
process involves conversion of liquid carbon
dioxide to solid dry ice pellets.
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Toll free 1-855-ICEBLAST Phone 906-864-2421 Fax [email protected] www.precision-iceblast.com
Where others had failed before, Precision Iceblast succeeded El Dorado Energy
I recommend your services to anyone needing this type of work Millennium Power
Contractors that we have used in the past to ice-blast our HRSG have not met oursatisfaction to say the least. Your crew cleaned the tubes better than the other contrac-tors have done before Calpine
I commend them on their ability, attitude, and professional manner in which theyconduct their business Contact Energy
Your crew was very professional and knowledgeable about the cleaning process and
the reason for cleaning HRSG tubesPower South
To get the most EFFICIENCY out of your HRSG contact:
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THE WORLDS LEADER IN
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22/5220 www.PowerEngineeringInt.comPower Engineering InternationalJune 2014
Heat recovery steam generators
location, amount of fouling present, and the
rate of deposit formation within the HRSG. This
information allows the owner to determine
precisely when an outage for tube cleaningis economically justified. In general, HRSG
cleaning is required when the gas path
pressure drop across the HRSG reaches
34 inches (810 cm) WC over new and
clean condition.
Once the need for cleaning has been
established and an outage date determined,
the next step is to select the best cleaning
technology. The standard options for cleaning
an HRSG are high pressure water blasting,
grit blasting, acoustic cleaning, and carbon
dioxide (CO2
) blast cleaning. The plant owner
should carefully consider the pros and cons
associated with each cleaning option before
making a final selection.
High pressure water blasting can be
effective but may also have the undesirable
side effect of a water-deposit interaction
that creates an acidic environment and
accelerates tube corrosion. Also, it may turn
the water-deposit mixture into a concrete-
like substance when the plant is restarted.
Further, this form of cleaning is limited to line-
of-sight deposits, and the high-pressure water
may push removed deposits further back
into inaccessible regions of the HRSG. Unless
carefully performed, high pressure water
blasting can also quickly damage insulation
that is extremely difficult to access for repairs,
or may erode some tubes or damage tube
fins. Contaminated water from the blasting
is also difficult to contain and may require
expensive waste disposal, if determined to be
a hazardous waste.
Grit blasting, also limited to line-of-sight
cleaning, can quickly thin the metal tubes or
damage tube fins if not carefully performed
by experienced technicians. Unfortunately
for the plant owner, thinning of tube walls is
not obvious during cleaning but will become
apparent when the rate of tube leaks
increases in the future. Like high pressure water
blasting, large amounts of waste material are
generated, some of which may be classified
as a hazardous waste requiring special (and
expensive) handling and disposal.
Users report mixed results when using sonic
horns for dust removal from tubes, particularly
in the cold end of the HRSG. Sonic blasting
is ineffective in removing ammonia salts and
baked on deposits.
COblast cleaningThe remaining option for HRSG cleaning is
CO2pellet blasting, the only option that is non-
destructive and produces no secondary waste
products. CO2 blasting is a dry process that
avoids future heat transfer surface corrosion
and eliminates the risk of erosion of tube metal
surfaces. Just as important to the owner, deep
cleaning between tubes can be performed.
CO2 blasting penetrates and completely
cleans modules located deep within the
HRSG, eliminating the time and expense of
mechanically spreading tubes to obtain
access to tubes not within the technicians
line of sight. CO2blasting has been proven by
over 20 years of industry experience and has
been recognized by HRSG manufacturers as a
cleaning best practice (see Figure 1).
The general cleaning process is illustrated
in Figure 2. CO2pellets are fed into a portable
machine that is connected to a high-pressure
Figure 2: The CO2pellet blast cleaning process is illustrated.
Figure 4: Typical fouling and bridging of HRSG tubes shown before cleaning.
Figure 5: The same tubes shown in Figure 4 have been restored to new
and clean condition after CO2blast cleaning.
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Heat recovery steam generators
Power Engineering InternationalJune 2014
Case Study 1: Regaining lost performance
Monitoring important performance data
points at a nominal 500 MW combined cycle
plant located in the northeastern US is part
of the plants ongoing HRSG maintenance
and cleaning program. The data collected
is used to develop performance trends and
an estimate of the power output that can
be restored by cleaning. A simple economic
analysis compares the value of lost power
sales revenue when running with a fouled
HRSG, with the lost revenue incurred for anoutage and the cost of an HRSG cleaning.
This analysis quickly informs the plant owners
when a cleaning should be scheduled.
Data collected from the plant historian
before and after an HRSG cleaning is shown
in Table 1. The plant power output restored
as a direct result of the cleaning was
1120 kW. Also, the plant normally operates at
a 90 per cent capacity factor and sells power
into the market at US3.5 cents/kWh off-peak,
a very conservative sell price for this analysis.
Assuming the plant can sell the additionalpower generated, the gross savings resulting
from the restored power is around $309,000
per year. The owners payback for the HRSG
cleaning is a matter of weeks.
Another approach to calculating the
value of an HRSG cleaning is to calculate
the fuel savings that occur when a plant
runs at a fixed power output. In that situation
the fuel savings are a function of the plants
improved plant heat rate. If the gas-side
HRSG pressure drop increases by four inches
(10 cm) WC due to fouling, the resulting heat
rate increase can be determined from plant-
specific design data. For the purposes of
this case study, the heat rate improvement is
approximated as proportional to the power
restored (1120/500,000) or 0.22 per cent. As
the typical 500 MW combined cycle plant has
a gross heat rate of around 7000 Btu/kWh, the
heat rate restoration is around 16 Btu/kWh. If
fuel is purchased at $3.50/million Btu then the
annual fuel savings for the improved heat rate
is around $220,000 per year.
Case Study 2: Avoiding unexpected cost
The second case study involves a combined-
cycle/cogeneration plant located in the UKthat produces steam and electricity for two
paperboard mills. The plant uses a General
Electric LM6000 and a Siemens steam turbine.
Sticky combustion products were
condensing out on the HRSG economizer
tubes as a tar-like substance because the
flue gas temperature had dipped below the
dew point. In addition, ceramic fibre insulation
blocks used in the HRSG combustion zone
were deteriorating, with fibre strands coming
loose into the gas flow and sticking on the
economizer fin tubes. The combined effectwas a loss of heat transfer in the economizer
and a rise in the HRSG gas-side pressure drop
that severely decreased steam production.
The plant owners initial diagnosis was to
replace the entire economizer module with
one that is equipped with an economizer
recirculation system.
An economizer recirculation system takes
a portion of the hotter economizer outlet
water and returns it to the inlet to ensure the
economizer tube metal temperature remains
above the dew point temperature, thereby
avoiding condensation of sticky combustion
productions.
However, procuring an expensive new
economizer module was going to require
at least 40 days, putting the plant owners
at commercial risk for failing to supply the
contracted amount of steam.
As an alternative approach, the plant
owner investigated cryogenic cleaning of
the economizer even though, at the time,
there was no large boiler experience with the
technology within the UK, only cleaning of
small equipment, such as motors or generator
windings.
The plant owner sent representatives tothe US to observe the cleaning process in
action and the decision was made to bring
the process to the UK for the first time. The CO2
pellet blasting equipment was shipped to the
UK for a planned HRSG outage. Figures 7 and
8 show the state of economizer tube fouling
before and after cleaning. Figure 9 shows
the debris removed from the HRSG after the
cleaning was completed.
The cleaning process was very successful
and at the close of the outage the plant
resumed supply of the contracted amountsof steam to the customer. By selecting CO
2
pellet cleaning, the plant owner avoided
an unnecessary replacement economizer
expense, sidestepped an extended outage
for the economizer replacement, and avoided
an unpleasant contract discussion.
Chris Nortonis President and Randy Martin
Vice-President at Environmental Alternatives,
Inc, a US-based company providing solutions
for nuclear decommissioning and industrial
cleaning applications. www.eai-inc.com
Visit www.PowerEngineeringInt.comfor more informationi
Figure 7: Fouling in this economizer was reducing customer processsteam flow and increasing HRSG pressure drop to unacceptable levels. A
replacement economizer was thought to be the only solution.
Figure 8: Economizer fouling was eliminated during a short maintenanceoutage and the plant was quickly able to resume full process steam
supply to its customer. In addition, the reduced gas side pressure dropimproved the combustion turbine operating efficiency.
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The growth forecast in global
nuclear generating capacity,
estimated by several agencies
at the end of 2013 to be at least
17 per cent by 2030, makes it clear
that continuous commitment
to safety, and the development of systems
to eliminate hazardous factors, remain of
paramount importance.
Despite their small footprints relative to
an entire nuclear power production (NPP)
installation, sealing systems play a significant
role in ensuring overall safety. Reliableand efficient performance in their specific
applications is of the utmost importance.
Maintaining the highest level of safety
while ensuring the effective performance of a
nuclear power plant typically comes down to
one statement: Keep it tight. There are many
considerations involved in the development
and continuous improvement of qualified
sealing products, flange assemblies and
sealing systems installed in the base of
pressurized water reactor nuclear power plants
(PWR NPP), as well as important organizational
changes and production improvements.
An understanding of the problem, in this
case leakage, helps to clarify the solution:
the effective sealing of mechanical joints. An
outline of the long-term collaboration between
the French Atomic Energy Commission (CEA)
and Technetics Group operating the Maestral
Seal Qualification Laboratory at Pier