power engineering 2014 n06

8/10/2019 Power Engineering 2014 n06

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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

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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




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




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.

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10/52

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


11/52

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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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



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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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



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.


Pumps


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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16/52

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


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




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




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




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.



20/52

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.


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.


21/52

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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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24/5222 www.PowerEngineeringInt.com


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


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

power engineering 2014 n06

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