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Distributed energy’s American opportunity

18

Volume 16 • Number 6

November - December 2015Contents

Features

8 America’s distributed energy opportunity Why forthcoming US federal regulations on emissions reduction are generally positive for

distributed energy, but have also created uncertainty within the industry.

By Craig Howie

14 Microgrids: more than remote power To ensure continuity of power supply and protect against grid faults and emergency

situations, ‘grid-connected’ microgrids are growing in popularity.

By Celine Mahieux and Alexandre Oudalov

18 Advantages of mechanical vapour recompression How mechanical vapour recompression (MVR) can improve energy efficiency in

process plants and offer possibilities for integrating renewable electricity and

demand side management.

By Egbert Klop

22 CHP’s grid balancing capability Energy management solutions can result in more economic CHP plant operation

and allow plants to participate in the smarter business of balancing the grid.

By Juha-Pekka Jalkanen

26 Intelligent maintenance with big data Data-based prognostic technology can determine the future condition of machines, laying

the foundation for intelligent maintenance planning.

By Moritz von Plate

On the cover: The Kendall Cogeneration Station in

Cambridge, Massachusetts, US. Photo credit: Jon Reis

Photography

1511cospp_2 2 11/2/15 3:28 PM

www.cospp.com 3

ISSN 1469–0349

Chairman: Robert F. Biolchini

Vice Chairman: Frank T. Lauinger

President and Chief Executive Officer: Mark C. Wilmoth

Executive Vice President, Corporate Development and Strategy: Jayne A. Gilsinger

Senior Vice President, Finance and Chief Financial Officer: Brian Conway

Group Publisher: Rich Baker

Publisher: Dr. Heather Johnstone

Managing Editor: Dr. Jacob Klimstra

Associate Editor: Tildy Bayar

Contributing Editor: Steve Hodgson

Design: Keith Hackett

Production Coordinator: Kimberlee Smith

Magazine Audience Development Manager Jesse Flyer

Sales Managers: Tom Marler Roy Morris Veronica Foster

Advertising:

Tom Marler on +44 (0)1992 656 608

or tomm@pennwell.com

Roy Morris on +44 (0) 1992 656 613

or rmorris@pennwell.com

Veronica Foster on +1 918 832 9256

or veronicaf@pennwell.com

Editorial/News:

e-mail: cospp@pennwell.com

Published by PennWell International Ltd,

The Water Tower,

Gunpowder Mill, Powdermill Lane,

Waltham Abbey, Essex EN9 1BN, UK

Tel: +44 1992 656 600

Fax: +44 1992 656 700

e-mail: cospp@pennwell.com

Web: www.cospp.com

© 2015 PennWell International Publications Ltd. All rights reserved.No part of this publication may be reproduced in any form orby any means, whether electronic, mechanical or otherwiseincluding photocopying, recording or any information storage orretrieval system without the prior written consent of the Publishers.While every attempt is made to ensure the accuracy of theinformation contained in this magazine, neither the Publishers,Editors nor the authors accept any liability for errors or omissions.Opinions expressed in this publication are not necessarily those ofthe Publishers or Editor.

Subscriptions: Qualified professionals may obtain freesubscriptions by visiting our website at www.cospp.com andcompleting an online subscription form. Extra copies of theseforms may be obtained from the publisher. The magazine mayalso be obtained on subscription; the price for one year (sixissues) is US$133 in Europe, US$153 elsewhere, including airmail postage. Digital copies are available at US$60. To start asubscription call COSPP at +1 847 763 9540. Cogeneration andOn-Site Power Production is published six times a year by PennwellCorp., The Water Tower, Gunpowder Mill, Powdermill Lane, WalthamAbbey, Essex EN9 1BN, UK, and distributed in the USA by SPP at 75Aberdeen Road, Emigsville, PA 17318-0437. Periodicals postagepaid at Emigsville, PA. POSTMASTER: send address changes toCogeneration and On-Site Power Production, c/o P.O. Box 437,Emigsville, PA 17318.

Reprints: If you would like to have a recent article reprinted for aconference or for use as marketing tool, please contact Rae LynnCooper. Email: raec@pennwell.com.

www.cospp.com

22 8

29 Genset maintenance dos and don’ts Because proper maintenance is as critical as the unit itself, we offer top tips for

maintaining your standby power installation.

By Tyson Robinett

32 Packaging CHP We look at the latest developments in packaged combined heat and power systems to

find out why good things come in ever-smaller packages.

By Tildy Bayar

Opinion

12 A bridge to economic development How fast-track power solutions can provide developing nations with rapid access to

reliable generating capacity and a better quality of life.

By Laurence Anderson

Regulars

4 Editor’s Letter

6 Insight

34 Genset Focus

36 Diary

36 Advertisers’ Index

1511cospp_3 3 11/2/15 3:28 PM

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 4

Editor’s Letter

About being best or super-best

When three people

stand on the

podium to receive

an Olympic plaque

or to be honoured for a World

Championship, I often think

it is not fair that only one gets

gold, and the others silver and

bronze. For me, all three are

super achievers. The difference

between the top athlete and the

second- and third-place winners

is often miniscule, and generally

depends on just a bit of good

luck.

In many cases there is even

evidence that a silver winner

is very unhappy, since just a

fraction more effort would have

yielded the golden plaque.

Having been so close to the

absolute championship can

cause frustration for an extended

period of time. A bronze winner,

however, is often grateful for

having reached the podium,

and leaving the bulk of the

contestants behind is already felt

as a great achievement. Okay,

bronze is not gold, but there is still

the silver winner in between.

Next time when you watch the

celebration of a championship,

you can verify this story just

by looking at the faces of the

winners. But apart from the

psychology, I like to stress that in

sports nowadays, the difference

in performance between winners

and losers is very small. The

ultimately achievable results are

asymptotically approaching the

theoretical limit.

I was thinking about sports

championships a few times at

POWER-GEN Asia in Bangkok

in early September. On the

power generation technology

track, we had a session on

gas turbines and one on

reciprocating engines. In each

session, four competing original

equipment manufacturers

highlighted the energy economy

of their equipment. These eight

presenters showed close to the

same fuel efficiency. This means

that they all follow the latest

technology and apply state-of-

the-art developments. Combined

cycles based on gas turbines

approach the 61% fuel efficiency

level, while reciprocating engines

appear to reach an amazing

50% efficiency level in simple

cycle mode.

Listening to almost the same

story from each presenter was a

little weird. Some speakers had

even borrowed pictures from

their competitors to show the

benefits of their products. In a

restaurant, you don’t repeat the

order to the waiter if you’d like

to have the same menu as your

table mate; you just say, “I’ll have

the same, please”. In the case

of the conference, the second,

third and fourth speakers could

have said: “We offer you the

same fuel efficiency as the first

speaker”. Next to that, showing

only general performance slides

during a presentation can be

boring. Such presentations

closely approach a sales pitch,

which is officially forbidden at

conferences.

To be a real champion who

beats the rest, you also have

to show the durability and

repeatability of your products.

Having a fraction higher or lower

efficiency is not so important in

practice. Unexpected downtime

and repair costs caused by

growing pains, inadequate

designs or poor spare-part

management are the real issues

that can be detrimental to a real-

life application.

That’s why I would like to see

many more papers presenting

actual operational results.

Papers and presentations giving

evidence of good performance

and proven lifetime profits are

much more relevant than just

showing a data sheet. A few days

ago, I witnessed a presentation

where a manufacturer promised

to extend the intervals between

maintenance actions by a factor

of four and a doubling of the life

of crucial components. These

are the things that potential

customers like to hear, preferably

with real-life evidence based on

user experience.

I would like to invite our readers

to send us articles on such

subjects. They would be very

welcome in this magazine.

PS: Visit www.cospp.comto see regular news updates, the current

issue of the magazine in full, and an archive of articles from previous issues.

It’s the same website address to sign-up for our weekly e-newsletter too.

Dr Jacob KlimstraManaging Editor

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Insight

6

Steve HodgsonContributing Editor

How extensive is the role

played by decentralised

energy in power systems

across the world? This is

not an easy question to answer,

partly because there doesn’t

appear to be any globally-

gathered data, and partly

because no two definitions of

decentralised energy agree. It

is certainly growing, though, as

all the major analysts agree.

The world’s power systems are

therefore in the early stages of

a transformation to a ‘cleaner,

more local future’, as Michael

Liebreich of Bloomberg New

Energy Finance described it this

summer.

Liebriech makes the point

that there is more going on

than the rise of renewables

and decarbonising electricity

generation: ‘There is a third level

on which the struggle between

defenders of clean and fossil

energy must be understood,

and that is in terms of the social

structures in which we want to

live.’ Liebreich continues: ‘While

fossil-based energy lends itself

to scale and centralisation ...

clean energy is inherently more

local, more distributed, more

accountable.’

Though sometimes confused,

the two terms – decentralised and

renewable – are by no means

synonymous. Some renewables

technologies just don’t fit the

decentralised description at all

– I’m thinking of remote, utility-

scale (and usually utility-owned)

offshore wind farms, and the

largest ground-mounted PV

arrays. But it’s true that large

proportions of the rest are local

in nature – feeding their output

to the host building or industrial

facility, or at least connecting

to local, low voltage distribution

grids.

Anyway, it’s not easy to find

reliable data on just decentralised

generation, although there have

been attempts in the past to

quantify the global picture. A

decade ago, an article in COSPP

magazine by Amory Lovins of

the US-based Rocky Mountain

Institute (RMI) suggested that

decentralised generation – it also

used the term micropower – was,

even then, bigger than nuclear

in both installed capacity and

annual output.

The RMI included most

renewables in its definition of

decentralised generation and

suggested a global micropower

capacity of 400 GW back then,

of which around 65% was fossil-

fuelled CHP; i.e., around 260

GW. The RMI says that, globally,

micropower now accounts for

slightly more than 25% of power

capacity, up from about 16% in

2004.

Whatever the history, the

current direction of travel is clear

and power systems are having

to change. One organisation

that has to fully understand

how systems should evolve to

accommodate decentralised

generation is the transmission

and distribution system operator.

Homing in on just one country,

Britain’s National Grid predicts

that small-scale distributed

generators will represent a third

of total UK generating capacity

by 2020, adding that the

concept of baseload supply will

be turned on its head, so that

distributed generators will supply

baseload power, and large-scale

centralised plants will be used to

meet peak demands and fixed

loads from businesses. Demand-

side response and management

will enable the market to balance

supply and demand.

This would be quite a different

system to that of a few years

ago, in which large and remote

coal, gas and nuclear-fuelled

power stations were dispatched

centrally, with smaller oil-fired

stations and pumped storage

plants used to balance the

system. Energy flowed in just one

direction – from generator to

user. Now, thousands of (much

smaller) power stations switch

themselves on as the sun rises,

the wind blows or the plant

operator sees fit according to

local loads, and power flows in

both directions.

Renewable or not,

decentralised energy is changing

electricity.

A more local energy future

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com

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Policy & markets: USA

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 8

Forthcoming US federal regulations on emissions reduction are generally

positive for distributed energy but have created uncertainty within the

industry, finds Craig Howie

The US Environmental

Protection Agency

(EPA) released

the final version

of its heavily anticipated

Clean Power Plan (CPP)

in early August, after

several revisions and some

4.3 million comments

submitted within the public

consultation period on the

1560 pages of regulations

which have lasted since the

EPA first announced its plans

for new limits in September

2013.

The agency’s goal is to

reduce carbon emissions

by 32% below 2005 levels by

2030, and to provide America’s

first national standard to limit

pollution from power plants.

US states are expected to

show compliance with the

recommendations by 2022,

on a gradual ‘glide path’ of

emissions reductions to 2030.

The plan is being authorised

under existing primary

legislation – the Clean Air

Act – so it does not have to

be presented to Congress

for approval. The Obama

administration expects that

implementing these emissions

limits will cost $8.4 billion

annually by 2030.

After the plan is entered

into the Federal Record, which

could happen as COSPP goes

to press, it will be subject within

60 days to an expected legal

challenge from 15 states which

are largely invested in the coal

industry, and which do not

necessarily have significant

distributed energy schemes

planned or in place.

Many in the industry have

compared the regulations

to the 2010 effort to create

New US policyA boon for distributed energy?

Absorption chiller at St Peter’s University in New Jersey Credit: ENER-G Rudox

1511cospp_8 8 11/2/15 3:29 PM

Policy & markets: USA

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 9

a national cap-and-trade

scheme for carbon emissions

– a plan that failed to pass the

US Senate.

At the CPP’s release,

President Barack Obama

said: ‘There is such a thing as

being too late when it comes

to climate change.’ Distributed

energy is expected by many

to benefit from the new rules,

as decentralised, small-scale

power production that can be

aggregated to meet regular

demand, often linking with

main grids, is a good fit. Of

course, it helps that it can take

the form of renewables such

as solar and wind power, or

harness biogas or biomass

and geothermal power, and

often incorporate combined

heat and power (CHP).

Rob Thornton, president and

CEO of the International District

Energy Association (IDEA),

which has been working with

the EPA for 15 years and has

contributed to the language

and provisions in the CPP’s

current and revised forms, said

the plan is ‘a structured federal

guidance to the states to make

the electric generating industry

more efficient’. The emissions

regulations are ‘generally

favourable’ for the distributed

energy sector, he suggested,

but added that the ‘devil is in

the details,’ acknowledging

the states’ legal challenges.

‘We see it as being operable

in certain states; other states

remain to be determined.’

States are expected to

present their own plans to

achieve emissions reductions

in line with the federal

regulations, and can comply

by employing one of two

mechanisms. They can operate

on a rate-based system, where

they are allowed a certain

level of emissions per MWh

per unit; or on a mass-based

quota that sets an allowance

for aggregate total emissions.

The rules will affect states in

different ways depending on

which system they choose.

‘I think CPP is a reasonable

compliance measure that

can help those states at least

move the needle on reducing

emissions,’ Thornton said.

Moving the needle

To illustrate how distributed

energy can be utilised to

reduce emissions, Thornton

points to Kendall Cogeneration

Station in Cambridge,

Massachusetts, a 256 MW

gas-fired plant which, under

prior ownership, was a market-

based electricity generator.

Now under new ownership, the

station recovers heat that was

being rejected into the Charles

River, dramatically improving

the heat rate of the plant,

reducing thermal pollution

and supplying more heat to

the district network, where it is

displacing unregulated boilers.

Thornton said some

environmental groups have

expressed disappointment

that the plan does not lay out

an energy vision that is 100%

based on renewables such as

wind and solar power, but, to

Thornton, ‘incremental change

is better than none’. He notes

that ‘CPP gives us a vehicle

from which to explain and

demonstrate the advantages

of distributed energy,

particularly at scale.’

The state of Massachusetts

is a leading proponent of

distributed power alongside

California, New Jersey and

Maryland. And state-based

emissions initiatives have given

it a head start in complying

with the federal emissions

legislation, notes Moe Barry, a

spokesman for Energy Choice,

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Policy & markets: USA

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 10

rated from 100 kW to 7.5 MW.

The CPP rules were not a

surprise within the industry,

Barry says. ‘More stringent

emissions regulations have

been consistently happening,

it’s something we anticipated

happening.’

Energy Choice’s main focus

is utilising natural gas to collect

biogas emissions through

reciprocating engines. Barry

suggests that the key impact of

the federal rules will add some

cost to smaller projects through

the addition of emissions-

reducing technology such as

selective catalytic reduction

(SCR), which may deter some

buyers seeking units from

500 kW to 7.5 MW.

‘Emissions catalysts can

make a project less feasible.

You can still do it and you can

hit the emissions regulations,

it’s just [that] costs for some

of these beneficial CHP

technologies are a little more

difficult and harder to finalise,’

says Barry.

But he says the CPP ‘really

makes us confident we can

go to any part of the country,

where traditional forms of

power generation aren’t

feasible anymore. In the

northeast, we’re able to soften

the fear of what’s permissible

today and may be permissible

tomorrow.’

The CPP could also affect

one of America’s main users

of distributed energy: university

campuses. Princeton University

in New Jersey has also

benefited from the state’s long-

standing initiatives to promote

microgrids that provide more

reliability and resilience

of supply, of particular

importance when the state

dealt with Hurricane Sandy and

its aftermath in 2012. When the

hurricane hit, the university’s

15 MW of power provided

by a GE LM1600 gas turbine

serving 180 buildings and

12,000 people helped keep

the research facilities running.

Vital projects in the university’s

data centre could have

been lost without a separate

1.9 MW gas-fired reciprocating

engine that provides cooling

power from waste energy. The

university has also installed

16,528 solar panels.

With a setup like this already

in place, Ted Borer, Princeton’s

energy plant manager, says

that the ‘shock to the system’

of any new federal regulations

‘wouldn’t be nearly as strong.

We’re burning natural gas as

our primary fuel. Diesel is only a

backup, so there is low or zero

impact at our scale’ from the

CPP, Borer explained.

Alongside facilitating the

use of distributed power by

way of renewables including

solar and wind, some CHP

companies invested in natural

gas see increasing benefits

from the CPP regulations.

Tim Hade, a spokesman for

New York-based ENER-G Rudox,

which has supplied some 4000

backup power generators

utilising cogeneration, says:

‘We’re very interested in the

outcome of CPP and, in

particular, how it’s going to be

implemented. Right now there’s

a lot of uncertainty, but CPP is a

step in the right direction.

‘What will come out on the

other side,’ he says, ‘is policy

that integrates greater use of

natural gas.’

‘Ultimately we’re looking at

what states are doing in order

to comply, forward-thinking

the process that they come

up with to meet targets. That’s

a state we’re very interested

in focusing on. Conversely,

if a public utility is fighting

the rule, then we’re probably

going to stay away from those

states.’

However, some distributed

power providers see benefits in

seeking business in coal-reliant

states, seeing greater potential

than in states that already

have many such systems in

place.

Some 15 states have

joined a potential lawsuit to

challenge the CPP. While the

challenge is being led by West

Virginia, which is synonymous

with America’s coal industry,

states involved in the lawsuit

from the Midwest including

Indiana, Michigan and

Ohio also present significant

opportunities for CHP providers,

said Patricia Sharkey, policy

director for the Midwest

Cogeneration Association

(MCA), which has been

working to educate its member

organisations throughout coal-

reliant states.

The MCA is working to pull

together a distributed energy

template in partnership with

the Great Plains Institute,

while working on a potential

eight-state compact to

become ‘trading ready’ or by

way of a mass-based emissions

plan. Some states will be

dragged into the CPP ‘kicking

and screaming’, Sharkey said,

as it is a better alternative

than refusing to follow the

regulations, which then

would involve greater federal

oversight and allocation of

state energy resources.

‘Some utilities are very

friendly to the notion that

we’re moving into new era

of distributed generation as

part of the overall energy mix.

Others are fighting it tooth

and nail. Indiana [has] a lot

of resistance; [there is] a big

battle in Michigan. Ohio [is]

split also. That tells you that

some of the industry groups

really understand that energy

efficiency can lower the energy

costs,’ Sharkey noted. ‘They

have the potential to be doing

the kind of projects in our coal

states, have the potential to

offset coal emissions and keep

those plants going because

they’re able to buy allowances

from the industrial CHP

generators.’

Such additional funds

could be valuable given that

distributed energy and CHP

projects in the Midwest can

also be hindered by smaller-

margin spark spreads, lack of

money for regional greenhouse

gas initiatives, and reductions in

The Kendall Cogeneration Station in Cambridge, Massachusetts Credit: Jon Reis Photography

1511cospp_10 10 11/2/15 3:29 PM

Policy & markets: USA

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 11

federal aid for natural disaster

planning and response, which

can feed into distributed

energy. Even then, Sharkey says,

legislators in coal-reliant states

are keeping an eye on how

other states are responding

to the CPP legislation, as a

means of developing a ‘Plan

B’ response to avoiding the

federal oversight and allocation

plan: ‘There’s a lot of push and

pull, but the CHP component is

getting a lot of attention. CPP is

one more thumb on the scale

for CHP.’

One state without such

residual opposition is California,

which has learned its lessons

from its energy crisis of

2000–2001 when capacity

shortages led to blackouts.

It has, as a result, pursued

distributed energy as a matter

of political necessity.

The state’s use of coal

in electricity generation is

practically negligible, and it

operates an energy cap-and-

trade system under the nation’s

most stringent greenhouse gas

emissions regulations. Some

19% of its electricity comes

from renewable sources,

according to the California

Energy Commission.

Beth Vaughan, executive

director of the California

Cogeneration Council, said

that her group has fielded

multiple calls from businesses

headquartered outside the

state with one question: How

will this affect us?

But Vaughan, who has

also held positions in the

Canadian and New Zealand

governments advising on

climate change issues, cited a

lack of widespread distribution

of information at the federal

level as contributing to an

air of uncertainty about the

new regulations within the

distributed power industry.

‘Dissemination of information

is not consistently done at a

national level; you need to

get the communication in the

background,’ she says.

Despite this, the message to

companies already operating

within California’s heavily

regulated economy is: ‘Don’t

worry, you’re already covered’,

Vaughan says. However, she

notes that also high on the

priorities list should be: ‘How do

we go the extra mile?’

This is a message that the

American Council for an Energy

Efficient Economy, a non-profit

research organisation based

in Washington DC, may have

taken to heart.

In the wake of the CPP’s

release, the group has worked

to convene energy producers,

distributers and users in

working groups to discuss the

way CHP is treated under the

new EPA rules. Meegan Kelly,

a senior research analyst with

the group, thinks that such

outreach will help the EPA

reach its goal of significant

emissions reduction across

America.

‘We think that the CPP could

represent a big opportunity

for the distributed energy

sector and CPP can help

states achieve significantly

lower emissions, increase

competitiveness and energy

reliability and resiliency,’ Kelly

says. ‘Business owners are likely

to benefit from the cap-and-

trade aspect, lower operating

costs and by investing in

efficiency.’

Craig Howie is a journalist

based in Washington, DC

This article is available

on-line.

Please visit www.cospp.com

For more information, enter 6 at COSPP.hotims.com

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1511cospp_11 11 11/2/15 3:29 PM

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 12

Opinion

A bridge to economic developmentFast-track, turnkey power can provide developing nations with rapid access to reliable generating

capacity and a better quality of life, argues Laurence Anderson

Fast-track power:

According to the

I n t e r n a t i o n a l

Energy Agency,

1.3 billion

people – 18% of the world’s

population – are currently

without access to electricity,

and that number is expected

to grow by 2.1% per year

through 2040.

Approximately 80% of

that growth is forecast to

occur in non-OECD countries

throughout Africa, Latin

America and Asia, largely due

to rapid global population

growth that is spurring

industrialisation, demand for

a better quality of life and a

significant rise in the use of

electronic devices and power-

intensive appliances such as

refrigerators.

The need for additional

generating capacity has

only grown more crucial, and

a number of countries and

governments have voiced

commitments to bridging the

growing gap between supply

and demand.

In Southeast Asia, for

instance, Indonesia’s

government has pledged

that the nation would be 99%

electrified by 2020 – no small

order considering that the

current electrification rate is

approximately 74% and some

60 million people lack power.

In the Philippines, the

challenge to meet that

country’s pledge to attain

99% electrification by 2017

seems even more daunting,

with approximately 29 million

people – roughly 30% of its

population – currently without

access.

Similarly, in the US, the

Obama administration issued

a much-publicised pledge

last year to bring 30,000 MW

of new generating capacity to

Africa. To date, according to a

recent administration estimate,

the Power Africa initiative has

resulted in approximately

2500 MW of new capacity.

That’s enough to power

about 3.5 million homes on

a continent where the Africa

Progress Panel estimates

621 million lack electricity and

the population is forecast to

double by 2040.

While the panel suggests

that solar power is the key

to Africa’s future, the fact

remains that a diverse

portfolio of generating

technology is needed to

offset and compensate for the

disadvantages inherent in any

power technology.

In the case of solar, beyond

the limitation of intermittent

sunshine, there’s also the issue

of high initial cost. Therefore,

with or without the financial

assistance and incentives

that would be needed for

a massive solar build-out in

Africa and other developing

regions, conventional fossil-

powered generation is likely to

remain part of the mix for the

foreseeable future.

The same need for diverse

sources of power generation

can be found in those parts

of the world that are heavily

reliant on other renewables,

such as hydropower. Whether

it is due to the annual dry

season or unexpected

droughts, a number of

developing nations in Africa,

Asia and South America would

benefit from the availability

of supplemental or backup

generation.

Perhaps the greatest

challenge to closing the

power gap facing developing

nations is that bringing

permanent electric generation

online – from planning and

financing to construction and

eventual commissioning – can

take years. Throw in the lack of

available financing, political

instability, permitting hurdles

and socio-political events,

and the timeline can become

insurmountable for many

developing nations.

But that doesn’t mean that

the 1.3 billion people lacking

electricity should have to go

years – even decades – waiting

for this essential ingredient for

economic development and

a better quality of life.

Reliable power

generation – fast

Fast-track, turnkey power,

available using state-of-the-

art gas turbine technology

and diesel- and gas-powered

reciprocating generators,

offers myriad benefits as a

bridge to a better quality of life

and economic growth while

permanent power stations are

progressing along the long

path to reality. Among the

benefits of interim fast-track

power are:

• Mobile power modules

and gas turbines are easily

transportable by land, sea

and air;

• Power modules and gas

turbines can be bundled,

providing scalable

generating capacity from

approximately 10 MW to

500 MW or more;Laurence Anderson

1511cospp_12 12 11/2/15 3:29 PM

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 13

Opinion

• Installation and

commissioning are rapid

due to minimal construction

and setup required for this

modular solution;

• Rapid installation means

reliable power in weeks not

years – for as long as the

need exists;

• Distributed power means the

capacity can be located

near demand, reducing the

need for transmission and

distribution infrastructure,

while also cutting the power

loss that occurs as electricity

travels long distances across

the grid;

• Up-front customer

investment is minimal,

avoiding long-term

financing and credit issues;

• Mobile, modular design

allows the plants to be

rapidly demobilised and

removed from the site

when a permanent solution

becomes available.

A promising future

Beyond the pent-up demand

for power and the long

timeline to bring permanent

generation online, I am seeing

three other factors that should

drive increased adoption of

interim fast-track power.

The first is that on-site power

solutions can be tailored

to the unique requirements

of each country and

customer. Developing nations

increasingly need a range

of technologies and types of

fuels and voltages, as well as

scalability in project size and

duration. In addition, services

that encompass engineering

and design, project planning,

installation, construction,

commissioning, operation and

maintenance, balance of plant

and decommissioning are

especially attractive in remote

areas of the developing world

looking to industrialise and

grow their local economies.

Case in point is our recent

project in Myanmar, where 70%

of the population lives in rural

locations and approximately

three quarters of the people

are without electricity. In 2014,

APR Energy signed the first

agreement between a US-

based power generation

company and the government

of Myanmar since the lifting

of sanctions by Western

nations. Within 90 days, the

company had installed and

commissioned 82 MW of gas-

fired power and later added

another 20 MW of capacity.

While this fast-track solution

provides the power equivalent

needed to electrify six million

homes in central Myanmar,

this generation predominantly

is being used to grow the

country’s manufacturing

base south of Mandalay. As

Myanmar manufacturing

expands, jobs are created,

household income and

purchasing power rises, and

the production of revenue-

generating export products

grows.

The suitability of mobile,

modular generating

equipment also makes this

an ideal solution for energy-

intensive industries such as

mining, where operations

typically are in remote

locations, far removed from

the power grid. Remote

mining projects in places like

Botswana and Mozambique

required round-the-clock

power and the ability to meet

variable load requirements

until the power was no longer

needed.

The second factor that I see

driving growth for interim, fast-

track power is an increased

demand for mobile gas

turbines, which offer a higher

power density, resulting in

a reduced footprint, and

lower emissions and quieter

operation than reciprocating

generators. They also provide

significantly greater grid

stability, as well as ancillary

services such as spinning

reserves, positive frequency

control and power system

stabilisation.

The growing interest in gas

turbines brings me to the third

factor I see driving growth in

interim fast-track power: the

shale gas explosion and a shift

to abundant, low-cost natural

gas as a fuel of choice for

electric generation.

In developing nations rich

in these natural resources,

declining worldwide

hydrocarbon pricing and

reduced export revenues have

become a disincentive for

exploration-and-production

companies to tap into vast

reserves off the coast of West

Africa, parts of Southeast Asia

and elsewhere.

Mobile gas turbines are an

ideal way for these nations to

monetise the economic value

of their idle gas resources,

and to transform this energy

into electric power that will

support industrialisation and

manufacturing of products

that might generate higher

export revenues. Then, as

the economic wealth of

these developing countries

grows – thanks to this gas

turbine-powered bridge –

they will begin to amass the

financial resources to invest in

permanent generation.

A meeting at the Center

for Strategic and International

Studies, held this past May,

provided an early glimpse

into what future demand

might look like for LNG. An

executive from the Panama

Canal Authority explained

that when the expansion of

the locks was being designed,

LNG shipments were not

a consideration. When the

expansion is completed in the

next year, two LNG shipments

per week from the US are

expected to pass through the

canal, en route to Asia – quickly

ramping up to three shipments

per day.

The executive noted that,

one day, some of the LNG

passing through the canal

could be off-loaded in

Panama – opening the door

to the possible creation of a

regional electricity hub, fueling

300 MW–400 MW of combined-

cycle generation to serve

Panama and its Colombian

neighbors to the south, and

Costa Rica and Nicaragua to

the north.

The interim power industry

is ideally positioned to

provide a bridging solution

that utilises mobile gas

turbines while permanent

LNG-powered generating

capacity is developed – in

Central America and across

the globe.

Bridge to a better life

While the challenge of

providing reliable electric

power to the billions of people

living in developing and remote

parts of the world is massive

and growing, it is one that can

– and will – be overcome. My

optimism is fueled by a simple

truth: the benefits of providing

this essential ingredient far

outweigh the cost of these

commitments.

That said, permanent power

generation – much like Rome –

can’t be built in a day.

Fortunately, with interim

fast-track power, we have

a readily available bridge

that can facilitate near-term

industrial growth and help

developing nations and

billions of people around the

world to attain the improved

quality of life they desire.

Laurence Anderson is CEO

of APR Energy

www.aprenegy.com

This article is available

on-line.

Please visit www.cospp.com

1511cospp_13 13 11/2/15 3:29 PM

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 14

The modern-day microgrid

Microgrids:more than remote power

Microgrids offer an economical way to ensure continuity of power supply and protection against grid faults

and emergency situations, write Celine Mahieux and Alexandre Oudalov

.

Recent years have seen

a significant growth in

interest in microgrids

as a way of providing

access to electricity in off-grid

locations like remote villages,

mines and islands. Now,

microgrids are increasingly

being deployed as a way

to improve local power

resilience, reduce reliance on

fossil fuels and defer large-

scale grid investments in

areas that have a connection

to the main electricity grid.

This ‘grid-connected’ version

of microgrids is growing in

popularity as a way to meet

rising power demands, take

advantage of the falling cost

of renewable sources, and

improve supply resilience

and autonomy (especially

for critical applications).

They provide an economical

way of ensuring continuity of

supply and protection against

grid faults and emergency

situations.

While many microgrids still

rely on diesel generators as

their energy source, the falling

costs of wind and solar power,

the availability of efficient

energy storage technologies

and the availability of

affordable wide-area

communication infrastructure

are making microgrids based

on multiple generation sources

a highly attractive proposition.

Modern microgrids combine

distributed energy resources

and loads in a controlled,

co-ordinated way. Grid-

connected microgrids can

also deliver additional value by

supporting the grid restoration

process after a major failure

(black-start capability) and

bolstering the grid during

periods of heavy demand.

At the same time, energy

suppliers and industrial

and commercial users are

increasingly interested in

moving away from reliance

on fossil fuels and drawing

from more sustainable and

eco-friendly sources such

as solar and wind. In areas

where the grid is weak,

microgrids can provide a

reliable electricity supply while

dramatically reducing fuel

consumption and carbon

footprint. They offer the flexibility

and scalability to grow in line

with demand, and can be

deployed in significantly less

time than that needed to

complete a grid expansion

project.

The ability to isolate such

microgrids from the main grid

seamlessly when needed is

an important feature. Fast-

reacting energy sources play

a vital role in providing the

resilience to ensure continuity

of supply for critical loads.

The modern microgrid

In many ways, microgrids

are scaled-down versions of

traditional power grids. A key

distinguishing feature is their

Microgrids are increasingly being deployed in grid-connected areas Credit: ABB

1511cospp_14 14 11/2/15 3:29 PM

The modern-day microgrid

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 15

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Combined cyclecloser proximity between

generation sources and

user loads. The system can

be designed and controlled

to increase power supply

reliability. Microgrids typically

integrate renewable energy

sources such as solar, wind

power, small hydro, geothermal,

waste-to-energy and

combined heat and power

(CHP) systems. Microgrids are

increasingly being equipped

with energy storage systems,

as batteries become more

cost-competitive.

The system is controlled

through a microgrid control

system that can incorporate

demand–response so that

demand can be matched to

available supply in the safest

and most optimised way. A

flywheel- or battery-based

grid stabilising system may

be included to offer real and

reactive power support.

The microgrid control

system performs dynamic

control over energy sources,

enabling autonomous

and automatic self-healing

operation. During normal

usage the grid-connected

microgrid will remain physically

connected to the main grid.

Microgrids interoperate with

existing power systems and

information systems and have

the ability to feed power back

to the grid to support its stable

operation. At periods of peak

load a microgrid may limit the

power it takes from the grid, or

even reduce it to zero. Only in

the case of main grid failure

or planned maintenance will it

implement a physical isolation

of its local generation and

loads without affecting the

utility grid’s integrity.

Resilience and

independence

Even in developed markets

with established grids,

there are rising concerns

over the resilience and

quality of the power supply

among certain end-users.

In critical applications, grid-

connected microgrids are

able to disconnect seamlessly

(becoming ‘islanded’) and

continue to generate power

reliably in the event of a fault,

natural disaster or even outside

attack. In areas where the grid

is weak, such grid-connected

microgrids satisfy the need to

ensure continuity of supply.

In recent years microgrids

have been suggested as a

potential solution after natural

disasters in the US highlighted

the vulnerability of distribution

power grids based on

overhead power lines.

While absolute power

reliability is important in some

sectors, many industries

are also looking to reduce

energy costs and reliance on

fossil fuels for peak shaving

or backup power, whatever

the condition or availability

of the main grid. Here, multi-

generation microgrids provide

the flexibility to take advantage

of a number of options for

self-consumption.

Utilities can choose to deploy

grid-connected microgrids as

a way of deferring investment

in expansion or upgrading of

the main grid. Such deferrals

can produce financial

value to utilities by reducing

capital expenditure in the

short to medium term. Smart

control of the microgrid’s

distributed energy resources

and integration into markets

enables the provision of

ancillary services for the grid

operator and creates new

value propositions.

In grid-connected

microgrids, the connection

is made through a Point

of Connection (POC) or

Point of Common Coupling

(PCC), which enables it to

import or export electricity

as commercial or technical

conditions dictate.

For more information, enter 7 at COSPP.hotims.com

1511cospp_15 15 11/2/15 3:29 PM

The modern-day microgrid

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 16

Microgrid components

Modern microgrid solutions

incorporate a number of key

components.

Control system

The first is the microgrid

control system, which uses

distributed agents to control

individual loads, network

switches, generators or storage

devices to provide intelligent

power management and

efficient microgrid operation.

The system calculates the

most economical power

configuration, ensuring a

proper balance of supply

and demand to maximise

renewable energy integration.

It also optimises the network’s

generator operations so the

entire system performs at

peak potential, and ensures

a compliant grid-connected

microgrid solution.

Power stabilisation and

energy storage system

Second is energy storage that

plays an important role both in

microgrid stabilisation and in

renewable energy time-shifts

to bridge peaks and troughs

in power generation and

consumption. However, the two

functions require very different

technologies for energy

storage.

Flywheel grid stabilisation

technology enables a high

instantaneous penetration of

renewable generation sources

by providing synthetic inertia

and grid-forming capabilities.

This stabilises power systems

against fluctuations in

frequency and voltage caused

by variable renewable sources

or microgrid loads. It stabilises

the electricity network and

reduces downtime by rapidly

absorbing power surges or by

injecting power to make up for

short-term troughs, in order to

maintain high-quality voltage

and frequency.

For microgrid stabilisation

the energy storage system

must provide a very fast

response while possibly being

called several times per

minute. This demands high

power output but small stored

energy.

For renewable energy time-

shifts, battery-based energy

storage systems should be

capable of storing energy for a

few hours to bridge the peaks

of energy production and

consumption.

Meeting both requirements

typically requires a hybrid

system with a combination

of underlying storage

technologies, each with

different performance

characteristics (cycle life

and response time). A hybrid

energy storage system will

combine the benefits of each

storage medium and offer

lower total cost compared with

individual units.

Protection system

A protection system is needed

to respond to utility-grid and

microgrid faults. With a utility-

grid fault, protection should

immediately isolate the

microgrid in order to protect

the microgrid loads. For faults

inside the microgrid, protection

should isolate the smallest

possible section of the feeder.

Optimal energy management

system

Thermal loads usually

represent a considerable

part of total energy used

by end consumers. There is

significant potential for cost

savings, particularly through

the use of CHP systems,

which allow consumers to

realise greater efficiencies by

capturing waste heat from

power generators. Therefore,

cost-effective microgrid

energy management requires

good co-ordination between

thermal energy storage

and other thermal sources,

and between thermal and

electrical systems.

System planning and design

tools

System modeling is

important during all phases

of microgrid development

– from the conceptual

design and feasibility study,

through construction, to

final acceptance testing.

For example, when an

existing diesel-based backup

power supply is extended

with a large amount of

fluctuating renewable energy

resources, stable operation

of the microgrid cannot

be guaranteed. In order to

optimally dimension a grid-

stabilising device and to tune

its control parameters, the

dynamic behaviour of legacy

diesel gensets has to be

known.

Grid storage in Australia

Australian operator SP

AusNet has deployed a

containerised microgrid

solution encompassing

battery, transformer and diesel

generator for a Grid Energy

Storage System (GESS) in

Melbourne, Victoria, Australia.

This provides active and

reactive power support during

periods of high demand, and

enables smooth transition into

islanded/off-grid operation on

command or in emergencies. It

has also enabled investments

in expanded power line

capacity to be deferred.

AusNet Services, Victoria’s

largest energy delivery service

company, began investigating

GESS in 2013. It chose to trial

the technology to explore

its ability to manage peak

demand, with the potential to

defer investment in network

upgrades.

The GESS consists of a

1 MWh 1C lithium battery

system operating in

combination with a diesel

generator, transformer and an

SF6 gas circuit breaker-based

ring main unit with associated

power protection systems.

Located at an end-of-line

distribution feeder in the

northern suburbs of Melbourne,

the system was commissioned

in December 2014, and

is currently undergoing a

two-year trial. The GESS is the

first system of this type and size

in Australia, and the trial aims

to explore the benefits to peak

demand management, power

system quality and network

investment deferral.

AusNet Services is

investigating the capabilities

of grid-connected microgrids

to provide peak demand

support. With a generation

source embedded close to the

load, the utility aims to study the

effect on postponing network

investment in feeder line

upgrades to support increased

loads. The belief is that such

an embedded generation

source can also be used to

provide peak load support

by reducing the upstream

feeder requirements during

peak consumption periods

by supplying the loads locally.

AusNet is also investigating the

effect on local system quality

and stability that the GESS

will provide, including power

ABB’s South African factory is to host a solar-diesel microgrid Credit: ABB

1511cospp_16 16 11/2/15 3:29 PM

The modern-day microgrid

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 17

factor correction, voltage

support, harmonics, flicker and

negative sequence voltage

suppression.

In addition, AusNet is

investigating the capabilities

of the GESS to operate as an

islanded system, and how

these improve the reliability

of supply and system stability

in the case of larger network

faults. In the event of a fault, the

GESS islands the downstream

feeder, creating an islanded

microgrid which the GESS

supplies until its energy

reserves are depleted or the

fault is cleared. When the fault

is cleared, the GESS reconnects

to the grid and transfers

the supply back to network

and begins recharging the

batteries on a scheduled,

preset programmed time of

day.

Heritage building goes

carbon-neutral

A microgrid solution helped

Legion House, an office

building in Sydney’s central

business district, become

Australia’s first carbon-neutral

and autonomous heritage-

listed building. It generates

its own power on-site from

renewable sources, and can

operate independently of the

mains electricity grid.

The building’s owner

Grocon, Australia’s largest

privately-owned development,

construction and investment

management company,

wanted to create its own

renewable electricity on site

through biomass gasification,

fuelled by wood chips and

waste paper collected from the

50-storey office block. Legion

House can run in ‘islanded

mode’, operating fully from

on-site power generation.

The building’s location

meant it was not able to rely

on solar or wind for renewable

power generation. Instead

it uses two synchronised

gas-fired generators

connected to the stabilisation

and storage system, which

serve as a common power

bus to provide a base

electrical load, while the

battery-based energy storage

system dampens the effects of

instantaneous load steps. The

system exports spare electrical

power to the adjacent tower

building. The battery power

system is also used to serve the

overnight electrical load as

well as minimise the generator

operating hours.

The microgrid’s stabilisation

and battery-based energy

storage systems ensure the

tenants have continuous

access to a reliable electricity

supply. They stabilise the

internal (islanded) power

network against fluctuations

in frequency and voltage that

can be caused by essential

building services such as

elevators and air conditioning

systems. The solution uses

advanced control algorithms

to manage real and reactive

power that is rapidly injected or

absorbed to control the power

balance, voltage, frequency

and general grid stability.

The energy monitoring

control system and battery

monitoring system monitor

and control the batteries to

provide 100 kVA/80 kW power

for up to four hours of electricity

supply. The system monitors

and controls various battery

parameters, including battery

temperature, to maximise

service life, and it can also be

remotely accessed.

Backup power for ABB

in South Africa

ABB is itself installing an

integrated solar–diesel

microgrid at its Longmeadow

premises in Johannesburg,

South Africa. This will integrate

multiple energy sources and

battery-based stabilisation

technology to ensure

continuity of supply.

ABB’s 96,000 m3 facility

houses the company’s country

headquarters, as well as

medium-voltage switchgear

manufacturing and protection

panel assembly facilities.

The microgrid solution

includes a 750 kW rooftop

solar photovoltaic (PV) array

and 1 MVA/380 kWh battery-

based grid stabiliser, which will

help to maximise the use of

clean solar energy and ensure

uninterrupted power supply

to keep the lights on and the

factories running even in the

event of a power outage on

the main grid supply.

Celine Mahieux is

Research Area Manager:

Innovative Applications

and Electrification at ABB.

Alexandre Oudalov is Senior

Principal Scientist with ABB

Corporate Research.

www.abb.com

This article is available on-

line.

Please visit www.cospp.com

For more information, enter 8 at COSPP.hotims.com

1511cospp_17 17 11/2/15 3:29 PM

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 18

Steam recompression

Steaming ahead

Steam recompression

is an economically

and energetically

attractive technique.

Steam is still a major energy

carrier in all branches of the

chemical industry. It can

be used at several pressure

and temperature levels.

High-pressure steam is used

to drive turbines while low-

pressure steam delivers

process heating.

As soon as the steam

pressure drops below 5 bar, it

hardly has any value since the

corresponding temperature

of approximately 150oC is

too low. However, efficient

recompressing of this steam

yields a valuable energy

carrier: a waste product

becomes useful. The process

is called Mechanical Vapour

Recompression (MVR).

The thermodynamic

principle

MVR is an open heat pump

system. Through compression,

both pressure and temperature

increase, together with the

corresponding saturation

temperature. The required

compression energy is very

small compared to the

amount of latent heat present

in the recycled steam.

In the example in Figure

1, the added compressor

energy is only 310 kJ per kg

steam, whereas the latent heat

of the compressed steam is

3060 kJ/kg. The process is

illustrated by the solid red line.

The system operates as a heat

transformer that upgrades

the quality of the heat in the

steam.

It is primarily the isentropic

efficiency (approximately 75%)

of the compression process

that causes superheating of

the steam. This superheating

can be compensated by

injecting boiler feed water

so that the desired steam

with MVR

Mechanical vapour recompression (MVR) can improve energy efficiency in

process plants and offers possibilities for integrating renewable electricity and

demand side management, writes Egbert Klop

1511cospp_18 18 11/2/15 3:29 PM

Steam recompression

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 19

temperature is created.

One might state that the

overheating of the steam is

transformed into additional

steam production. In the

example shown in Figure 1,

an additional 11% of steam

is produced by injecting

boiler feed water of 70oC.

The trick of the process is

avoiding condensation of the

steam and retaining the latent

heat.

Figure 2 shows the

schematic representation

of steam recompression

and water injection

(de-superheating) based

on two-stage compression.

The knock-out drums and

the demisters prevent erosive

damage to the compressor

blades caused by water drops.

The recycle valve is needed

for the startup process: the

steam will be recycled until the

desired condition has been

reached.

Energetic performance

The energetic performance of

MVR is commonly expressed in

the coefficient of performance

(COP), as is the case with

standard heat pumps. The

COP gives the ratio of the net

recovered heat and the energy

used by the compressor. In

this case, the net heat is the

steam production including

the additional steam yield by

water injection.

Typical economical and

energy-efficient applications

have a minimum COP of 3.5.

Some applications of MVR

prove that a COP of 10 or even

higher is achievable.

Key elements for a high

COP are:

- A low ratio of the absolute

steam pressures. A guideline

for the maximum ratio is 6;

in daily practice the ratio is

about 3;

- A minimum capacity. A

guideline is a minimum of

one tonne of steam per

hour;

- Water injection after

compression.

MVR is very effective

in comparison with other

techniques. Simple electrical

heating yields a COP of only

1. Systems that turn hot water

into steam by means of a

heat pump are also being

developed, but such systems

are hardly available on the

market yet. An interesting

development in this context is

the Radiax compressor from

Bronswerk Heat Transfer.

Available compressor

technology

For MVR, a wide range of

compressors is available. The

compressor type depends on

the pressure and temperature

ratios, the absolute pressure

and the volume flow. Figure

3 gives an overview of the

operating range of the

available compressors, using

atmospheric steam as the

starting point.

Benefits of steam

recompression

The technical and financial

investment risks of MVR are

low. MVR is primarily interesting

for processes with a surplus

of low-pressure or flash steam.

Examples of the benefits are:

- Payback periods between

one and three years;

- Reduced waste of energy;

- Higher energy efficiency and

less use of fossil fuel;

- Flexibility in steam

production;

- High compressor capacity:

up to 200 tonnes per hour;

- Flexibility can be created by

putting compression units in

parallel;

- Control of the power/heat

ratio in case of combined

heat and power;

- Demand-Side Management

depending on the electricity

price. Systems are generally

switched off at an electricity

price exceeding €100

($113)/MWh;

- The possibility of using

renewable electricity for the

compression process;

- Proven technology.

Economic aspects

MVR is always custom-made.

The return on investment

depends on the following

factors:

- The capacity of the

installation;

- The price of the output

steam, which generally

depends on the gas price;

- The pressure ratio;

- The value of the input ‘waste’

steam;

- The electricity price.

A number of business cases

have shown that MVR is

‘Bull gear’ multi-stage compressorCredit: Atlas Copco

Efficient steam recompression yields a valuable energy carrier: a waste product becomes usefulCredit: Atlas Copco

1511cospp_19 19 11/2/15 3:29 PM

Steam recompression

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 20

economically quite robust.

This is supported by extensive

sensitivity analyses in which

the electricity price, the value

of the input steam, the value

of the produced steam and

the level of investment vary.

At a ratio of three between

the electricity price and the

gas price per energy unit, the

investment is still profitable,

provided a good COP is

present.

Typical electricity prices

for large industrial users are

€50/MWh. In practice, it is not

the electricity price but the

capital expenditure for MVR

and the price of natural gas

that determine its economic

viability. If renewable electricity

is used, the carbon footprint is

even reduced.

Effect on the

cogeneration sector

High gas prices and low

electricity prices in Europe

are drastically limiting the

economic possibilities of CHP.

Existing installations are often

stopped or mothballed. The

flexible application of MVR

means that excess electricity

does not have to be dumped

at low prices, but can be used.

This reduces the occurrence

of excessively low electricity

prices that hamper the

profitability of CHP. A continued

use of CHP will help reduce

fossil fuel consumption as well

as greenhouse gas emissions.

Social benefits of

electrically-driven MVR

Beyond the direct economic

benefits for the user of

MVR, there are a number of

synergetic effects.

The opportunity to use

renewable electricity,

especially in periods when

production exceeds demand,

is very welcome. Also, the

combined heat and power

(CHP) sector as well as the

grid operator benefit from the

possibilities of MVR.

Policy measures in the

EU have resulted in a large

increase in variable electricity

production from renewables.

This means there will be an

increase in the volatility of

electricity production, mainly

caused by the subsidies

for renewables. MVR is an

excellent tool for balancing

based on Demand-Side

Management.

Co-operation between the

different sectors is key to a

more sustainable society. MVR

is a major tool, provided it will

be applied at a large scale in

industry.

Dutch research organisation

ECN has predicted the

perspective for MVR at an

electric power of 2000 MW in

the Netherlands. This compares

with a thermal energy flow of

around 20 GW.

MVR case studies

In the following three case

studies, the technical and

economical feasibility of

steam recompression are

shown. Cases one and two

show the upgrading of steam

for different capacities, while

case three shows the use and

upgrading of flash steam from

condensate.

The main conclusion from

these cases is that steam

recompression is a very

economical way of improving

energy efficiency, with a simple

payback period between

one and three years. It will be

clear that a high number of

annual running hours boosts

profitability.

Looking at the effect of the

annual running hours on the

economics of cases one and

two, it is obvious that the Capex

dominates the economic

viability.

Upgrading the steam

Two cases have been

evaluated: first, the almost

continuous (8000 hours/

year) upgrading of 50 tonnes/

hour of steam (saturated) at

a gauge pressure of 3.5 bar

to 12 bar; and second, the

upgrading of 10 tonnes/hour

steam at a gauge pressure

of 1.5 bar to 9 bar during

6000 hours/year.

In both cases, there is

no current application for

low quality steam, and it

therefore has no economic

value at present. The steam

is condensed, which even

requires electric energy for the

cooling fans of the condensers.

This aspect has been

neglected in the evaluation.

In both cases, the steam has

been compressed to a level

that can be used in the process.

Two-stage compression is

required because of the high

pressure ratio. Water is injected

between the two stages to

reduce overheating, and

consequently to improve the

efficiency. Figure 2. Steam recompression and water injection based on two-stage compression Source: Atlas Copco

Figure 1. Pressure-enthalpy diagram for steam recompression with waterinjection Source: Industrial Energy Experts

Recompression (compressor efficiency 75%) Recompression (compressor efficiency 100%) Water injection Thermal process

Enthalpy

1511cospp_20 20 11/2/15 3:29 PM

Steam recompression

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Case 1:

• Steam flow: 50 tonnes/hour

• Absolute input steam

pressure: 4.5 bar

• Absolute output steam

pressure: 13 bar

• Compressor power: 4.4 MW

• COP: 9.8

• Running hours: 8000 hours/

year

• Reference energy costs:

7600 k€/year

• Energy costs MVR:

1760 k€/year

• Cost reduction:

5840 k€/year

• Capital investment: 5700 k€

• Simple payback period: one

year

Case 2:

• Steam flow: 10 tonnes/hour

• Absolute input steam

pressure: 2.5 bar

• Absolute output steam

pressure: 10 bar

• Compressor power: 1.1 MW

• COP: 7.9

• Running hours: 6000 hours/

year

• Reference energy costs:

1140 k€/year

• Energy costs MVR: 330 k€/

year

• Cost reduction: 810 k€/year

• Capital investment: 2090 k€

• Simple payback period:

2.6 years

Case 3: flash steam

In this case, energy that is still

available in intermediate- or

high-pressure condensate

is used. By reducing the

condensate pressure, part

of the condensate flashes to

steam. In case 3, condensate

of 8 bar is flashed at a pressure

of 2.5 bar. This is then increased

to 6 bar by MVR.

• Condensate flow (absolute

pressure 8 bar): 50 tonnes/

hour

• Absolute flash pressure:

2.5 bar

• Flash steam flow: 3.2 tonnes/

hour

• Compressor power: 257 kW

• COP: 10.3

• Running hours: 8000 hours/

year

• Reference energy costs:

486 k€/year

• Energy costs MVR:

103k€/year

• Cost reduction: 383 k€/year

• Capital investment: 800 k€

• Simple payback period:

2.1 years

Egbert Klop is Managing

Director of Industrial Energy

Experts

www.ieexperts.nl

This article is available

on-line.

Please visit www.cospp.com

Figure 3. Functional ranges of compressors for vapour recompressionSource: GEA Wiegand

1511cospp_21 21 11/2/15 3:29 PM

CHP’s grid balancing capability

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 22

Grid balancingwith district heating

Energy management solutions can guarantee more economic CHP plant operation

and allow plants to participate in the smarter business of balancing the grid,

writes Juha-Pekka Jalkanen

Today’s energy

systems have

become increasingly

complex because

of two major challenges.

Wind and solar, along with

energy storage, pose the first

challenge to the balance

management of any energy-

producing system. The

second challenge is the

continuous turbulence in

electricity pricing. When

wind is abundant, electricity

prices drop radically to a

very low level. The price

changes also need to be

considered at the plants as

quickly as possible.

Although district heat needs

to be produced, a plant must

assess how profitable electricity

production is when selecting

production units for district heat.

Reaching optimal production

is more demanding than ever,

so plants need to plan better

and forecast the future. They

also must react more quickly

to changes in the market, and

produce more electricity at

times when it is most profitable

to do so. How can they know

what the electricity price will

be today? How much heat

is needed? Additionally, how

can they take care of process

disturbances and be ready to

participate in the intraday or

reserve power market?

Synchronising networks

Combined heat and power

(CHP) is used to produce

electricity along with heat

for industrial processes or

heating. The main difference

between the networks lies in

the fact that the heat network

operates locally with the CHP

plant having active control

over it, whereas the balance

in the electricity network is

controlled by the transmission

system operator.

Because day-ahead

electricity prices are at the

Finland’s Fortum Suomenoja combined heat and power plant

Credit: Valmet

1511cospp_22 22 11/2/15 3:29 PM

CHP’s grid balancing capability

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 23

level of a low-cost commodity,

there may be more business

motivation for participating in

the regulating power market.

The key is to find the right

combination of controlling

the heating network and

participating in balancing the

electricity network. This puts

the CHP plant in a key role as

a bridge to enable a smooth

synchronisation of resources.

In the end, the two networks

should not only be sustainable,

they must also be affordable

and reliable. These goals

can be achieved by a clever

co-ordination of various

players in the energy markets

and a smart mix of energy

sources – and the right tools to

control the results.

Novel concepts for

sustainability

FLEXe stands for building

flexibility into energy systems.

The FLEXe consortium aims to

achieve a better energy system

for the future. TEKES, the Finnish

Funding Agency for Innovation,

is funding the project. The goal

is to enable companies to

create novel technological

and business concepts to

ease the disruptive transition

from the current energy

system towards one that

combines smartness, flexibility,

environmental performance

and economic success.

The consortium consists of

17 companies and 10 research

institutes or universities in

Finland. Thanks to a broad

spectrum of competencies,

FLEXe covers the whole energy

system value chain.

As the only company in the

programme that concentrates

on advanced plant-level

and district heating network

controls, Valmet’s role is to

study how to support system-

level flexibility by means of

advanced controls. The target

is to get information from

different business models to

understand future developing

needs. This will enable Valmet

to create a path for companies

to migrate to new systems.

Valmet will specifically study

the optimal operation and

control strategies of power

plants and heat networks in this

new and flexible operational

environment.

Plan, optimise, control

To enable CHP plants to plan

and forecast more effectively

as well as become more

proactive, the Valmet DNA

Energy Management platform

allows plants to plan their

energy production in the

most optimal way. In addition,

energy management controls,

information sharing and

updated production plans

give plants the quick reaction

ability they need.

Valmet DNA Energy

Management is a modular

energy management system,

delivered in collaboration with

partner Energy Opticon Ab in

Sweden. The system forecasts

district heat demand and

optimises production, allowing

units to achieve the best

total economic costs and to

determine the optimal times for

unit startups and shutdowns.

A common user interface

for all personnel improves

communication. Thanks to a

uniform way of planning, fewer

human errors occur.

Valmet DNA Steam Network

Manager and Valmet DNA

District Heating Manager

are part of the energy

management controls. Costs

are minimised because

disturbances can be corrected

quickly, and power generation

can be maximised by keeping

plant availability as high as

possible.

A holistic approach for

district heating

Fortum’s Suomenoja CHP

plant in Finland produces

heat for households in the

greater Espoo region, and

electricity for the national grid.

Its large and complex network

consists of multiple units. The

power plant produces about

1800 GWh of electricity and

2200 GWh of district heat per

year.

Suomenoja is the first power

plant in Finland to optimise

its district heating network

using the DNA District Heating

Manager solution, which

is based on multivariable

model predictive control. Until

the optimisation, operating

conditions in the plant’s

district heating network were

maintained manually, and

operators had to run the

network with more heat than

necessary. At the same time,

constant temperature and

pressure fluctuations at the

plant posed risks for severe

disturbances. The goal was to

provide Suomenoja with both

economic and environmental

benefits through better control

of its network.

Better control of temperature

and pressure fluctuations

in the heat plant minimises

heat stress to the district heat

piping, and is thus one tool

to avoid severe disturbances.

Better control of the pressure

difference throughout the

network also eliminates

the need to produce any

additional heat, resulting in

higher energy efficiency.

The DNA District Heating

Manager keeps heat

production and consumption

accurately balanced

throughout the whole network.

The CHP, heat-only units and

pumping stations are all

controlled by a single controller,

which takes into account the

dynamic interconnections of

all controlled units.

The co-ordinated control

of all production units and

pumping stations allows heat

loads to be transferred from

one area to another with

flexible allocation of heat loads

between production units.

Accurate control improves

heat delivery efficiency by

decreasing the heat losses in

the network.

While the heat production of

the CHP units varies according

to electricity prices, or they

participate in the balance

control of the electricity grid

frequency, the heat-only

stations keep the entire district

heating network stabilised. This

allows all units to be run at

economically optimised loads

and enables a fast response

to unexpected disturbances,

heat demand changes,

electricity prices and grid

balance actions.

Ultimately, all improvements

contribute to the reduction

Realised ELSPOT price

and power

Forecasted ELBAS and regulating power prices

Unit availabilities

Current loadsDH load forecast

Natural Gas forecasts(price and

availability)

Optimal loads for units + Deviation from optimum loads

Optimisation(plant model, other fuel prices)

Intraday production planning at Tampereen Sähkölaitos in Finland. Optimisation enables calculating the weekly production forecast and the day-ahead production plan. Source: Valmet

1511cospp_23 23 11/2/15 3:29 PM

CHP’s grid balancing capability

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 24

of fuel consumption and

CO2 emissions, making CHP

production an even more

environmentally friendly and

economical form of heating.

Optimisation and

forecasting

Tampereen Sähkölaitos Group,

based in Tampere, Finland, is

a regional operator in energy

with approximately 130,000

customers. The 120-year-old

group provides electricity,

district heating, district cooling

and natural gas.

In 2014, Tampereen

Sähkölaitos Group chose

Valmet as a supplier for the

production optimisation

system for the entire Tampereen

Sähkölaitos. The system

features district heat demand

forecasting and production

optimisation of all five power

plants and peak heat centres.

‘Our three main reasons for

implementing the production

optimisation system at

Tampereen Sähkölaitos were to

help the electricity traders plan

the production, to improve

communication between

the traders and the control

room, and to allow the use of

the same optimisation model

for long-term production

optimisation – and even for

budgeting,’ says Marko Ketola,

Senior Specialist at Tampereen

Sähkölaitos.

An accurate forecast of

the district heat demand

forms the basis for decisions.

Optimisation enables

calculating the weekly

production forecast and the

day-ahead production plan to

support electricity trading and

the intraday production plan.

The traders who work 24/7

make the plan for production.

Due to the lower electricity

prices, the production

environment has become

more complex. For instance,

bypassing the turbine is used

more often. Therefore, it is more

difficult to manually optimise

and plan production.

‘In addition to their expertise,

traders now have the tools

for making the production

plan. This reduces errors

and improves the planning

accuracy,’ Ketola says.

The production optimisation

system is integrated within the

automation and information

systems of the company

and individual plants, and

is connected to Tampereen

Sähkölaitos’s financial

system. Therefore the current

production and consumption

rates, availability of the

production units, electricity

purchase data and fuel

prices can be used to quickly

update the production plan,

whenever there are changes

in the market and process

environment. Thus, even

electricity market changes are

reflected in the latest optimal

production plan.

Tight integration also ensures

that the communication

between control rooms and

traders is improved. The current

plan, and any deviation from

it, are shown in the operator’s

interface in the control system.

Communication is also

important, according to

Marko Ketola. ‘Earlier, this was

mainly based on phone calls.

Now, there is a common user

interface that displays the plan

and the reasons behind the

plan. There’s a common basis

to discuss and from which to

make production decisions,’

he says.

The system does not

remove the need to talk, but it

enhances transparency and

thereby production efficiency.

Integration with the control

system makes it possible to

use the district heat demand

forecast and the optimal

production plan to control

production.

Over the long term,

systematically collecting

history and monitoring

information on forecasts,

plans, actual production

and deviations from the plan

enable Tampereen Sähkölaitos

to economically follow up its

energy production. This means

that it is possible to decrease

production costs for district

heat and increase profits from

electricity production.

The upside of being in

balance

With the use of energy

management and controls

for district heating networks, it

is possible for a plant to play

an active role in improving the

overall production economy

and ultimately balancing the

grid.

Short-term benefits include

using the same planning

principles for each shift,

minimising the chance for

human error and eliminating

differences in running the plant.

Also, when the day-ahead

electricity is planned and

communicated to everyone,

the controls can support the

plant in keeping the target.

Additionally, a CHP plant

can capitalise on the potential

offered through electricity

trading. With changes in the

market, weather or process, it

is possible to quickly calculate

and utilise a new production

plan for the current day or

the following hours. This allows

plants to participate in the

short-term market.

In all, it makes sound

business sense for a CHP plant

to proactively participate in

balancing the electricity grid,

not only on the day-ahead

and intraday markets, but

also as a frequency-controlled

power reserve.

CHP plants that take

advantage of advanced

energy management

solutions and district heating

controls can decrease the

production costs of heat

and maximise profits from

electricity sales. This makes

production within complex

networks easier to plan,

optimise and control. In turn,

CHP plants can take a more

profitable role in the future’s

sustainable, reliable, flexible

and affordable energy system.

Juha-Pekka Jalkanen is

Director, Power Automation

Solutions at Valmet.

www.valmet.com

This article is available

on-line.

Please visit www.cospp.com

District

heating

network

Heat

storages

Electricity

storageConven-

tional

producers

Solar

power

Process

steam

demand

Wind

power

Heat-

only-boilers

Pumping

stations

Geothermal

heat

Electrical

network

Consumers

& Prosumers

CHP plantsLink between grid and heat network

The key is to find the right combination of controlling the heating network and participating in balancing the electricity network. This puts the CHP plant in a key role. Source: Valmet

1511cospp_24 24 11/2/15 3:29 PM

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Operations & maintenance

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 26

Big dataand intelligent maintenance

Data-based prognostic technology can determine the future condition

of machines, laying the foundation for intelligent maintenance planning,

writes Moritz von Plate

The world’s energy

needs are constantly

growing. Worldwide

population growth

and the continuing

industrialisation of emerging

economies, notably China

and India, are the major

causes for this growth in

energy consumption, which

has a negative impact on

the environment. According

to the Intergovernmental

Panel on Climate Change

(IPCC), anthropogenic

greenhouse gas emissions,

i.e., emissions caused

by human activity, have

increased significantly since

pre-industrial times and are

currently at an all-time high.

Green technologies, such

as cogeneration plants,

have therefore become

increasingly relevant for

energy production and will

become even more relevant

in the future.

Thanks to the new

technologies of the Internet

of Things, it is now possible

to perform cost-effective

maintenance measures that

can increase security and

prevent unplanned outages

in cogeneration plants. Such

new technologies make it

possible to analyse process

and condition data of plants

and make prognoses of

the system’s future state. In

addition, these prognoses

change the way in which

people make decisions.

The role of data

The industry is offered totally

new possibilities through the

Internet of Things, especially

when it comes to process

optimisation and automation.

The way has been paved for

profound changes to industrial

processes by implementing

modern information

technologies. In the course

of advanced digitalisation,

machines are linked with one

another and collected data is

used to intelligently co-ordinate

and improve processes. When

it comes to maintenance and

operational management,

Big Data technologies enable

a data-based and future-

oriented prognostic strategy.

For example, thanks

to innovative Big Data

technologies, prognoses

on the future condition of

a machine or its individual

components can be

created. With a prognostic

approach, users receive a

data-based prognosis and

can adjust maintenance

plans accordingly. Further,

unnecessary costs or

unplanned outages can

be avoided, for example by

replacing parts in time, i.e., not

too early and not too late. In

this context, prognostics can

be defined as an ‘objective

and data-based forecast

of future conditions with an

explicit time reference’. In

practical terms, this means

that prognostic reports can

provide information on the

future condition of machines

or machine components for

a period of mostly weeks or

months or, in special cases,

even years.

Predictive diagnostics

vs prognostics

This prognostic approach is not

synonymous with the so-called

Predictive Diagnostics or

Predictive Analytics. Predictive

Diagnostics recognises initial

early warning indicators for

future malfunctions by means

of data abnormalities, and

provides diagnostic findings

about the current condition. Yet

it does not provide information

on when an abnormality will

turn into a malfunction, i.e.,

when the time frame until the

next malfunction arises will

close (tomorrow, in a week, or

is it still months?). Prognostics,

on the other hand, not only

reports on when one can

expect a malfunction, but also

indicates when the time frame

during which measures can

be taken will close.

Because the prognoses are

calculated for each machine

individually, they are not based

on average data from other

machines or manufacturers’

specifications. This has the

advantage that the individual

performance curves, the

operational strategy and, if

applicable, previous data on

historical incidents is included

in the prognoses. This results

1511cospp_26 26 11/2/15 3:29 PM

Operations & maintenance

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 27

in the prognoses reaching a

higher level of precision and

reliability. When calculating

prognoses, the historical data

runs through a number of

different steps. These consist

of stochastic methods and

include highly developed

algorithms. The result is an

explicit future risk profile that

illustrates the probability of

malfunctions over time.

The requirement for a

prognosis is to collect and

store enough process data

(e.g., rotation frequency,

speed, temperature and

pressure) and condition

data (e.g., vibration data,

lubrication data and housing

temperature). An ideal time

frame of data history is three

to five years, whereby it is

possible to complete a reliable

prognosis with a shorter time-

frame. The storage format does

not play an important role. It is

more important to ensure that

the data is as complete as it

can be, as this will increase the

validity of the statistics.

Condition-based

maintenance

Instead of relying on fixed

maintenance intervals or

waiting for something to

break, the information from a

prognostic report can be used

to ensure that maintenance

and repair work can be carried

out when needed. Parts will

not be replaced too early on

speculation, but rather when it

is necessary from a technical

point of view. Apart from this,

by means of the prognostic

reports and good data

processing, it is also possible

to recognise the effect that

various operational scenarios

will have on the equipment’s

remaining useful life (RUL),

transparently and objectively.

By doing so, the RUL can be

actively managed through

adjusting the operational

mode.

How the installation

works

Introducing transparency into

the RUL and, ideally, being

able to actively control it were

the aims of a project in which

Cassantec implemented

the solution in a fossil fuel-

fired power plant. The active

management of the RUL

should take place in such a

way that the duration of the

RUL and the operational mode

are balanced to achieve the

desired outcome. Additionally,

maintenance activities should

be optimised to lower the

operational and repair costs.

Such a project is divided into

two phases. As a prerequisite,

historical available condition

and process data from

the power plant must be

collected and prepared for

further processing. During

the first phase – the so-called

configuration phase – the

power plant experts and

Cassantec ascertain the

correlations between data

parameters and specific

malfunctions. The second

phase is prepared based on

this foundation: the actual

calculation and prognoses

of the risk of malfunctions.

This phase also includes the

fine-tuning of the preliminary

component specific warning

and alarm levels.

How the solution works

at a cogeneration plant

The first prognostic reports

compiled for a cogeneration

plant have already delivered

valuable findings for the

operator. For example, by

implementing a scenario

analysis which determines

the dependence of the data

on the operational regime, it

is possible to find a new and

optimised mode of operation

for the equipment. This can

have a positive effect on

the RUL of the equipment, its

reliability and the need for

maintenance.

Based on results produced

by the prognostic solution,

the energy provider receives

valuable insight into the

relationship between

operational strategy and

the RUL of the power plant

and, in particular, the critical

equipment. This goes much

further than the information

available from conventional

condition monitoring and

diagnosis. The results enable the

operator to make well-founded

decisions on the adjustment

of his or her operation and

maintenance plan for the

An illustrative excerpt from a prognostic report for one example generator Source: Cassantec

The colour green represents a low risk of malfunction Source: Cassantec

1511cospp_27 27 11/2/15 3:29 PM

Operations & maintenance

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 28

critical equipment, in order to

be able to optimise its usage

in three fundamental aspects:

considerable extension of the

RUL, minimising maintenance

costs through optimisation of

the maintenance plan, and

specific information on when

a component will need to be

replaced.

When the operator decides

to expand the implementation

of the prognostic solution to

other similar plants in the fleet,

the configuration phase, as

outlined above, is significantly

shortened. In addition, the

operator can expect extensive

savings in maintenance and

repairs, and a comprehensive

understanding of the condition

of the machinery and of the

factors that influence the RUL.

Fleet-wide implementation

also leads to a fleet-wide

learning effect that boosts the

initial advantages.

How people will make

decisions in the future

Whether consciously or

unconsciously, humans make

hundreds of choices every day.

Gerhard Roth, a professor at

the Institute for Brain Research

in Bremen, has determined

that, quite often, gut decisions

are the better choice. When

choosing what to eat for

breakfast or what to wear,

that is perhaps the best way;

however, for more complex

decisions the basis should

not be intuitive. Especially

when the cause and effect of

a problem are not clear and

decision-makers are faced

with complex structures, data-

based facts can put them

on the right track. Algorithms

help people solve complex

problems such as the

maintenance of equipment,

and help them make better

judgments.

At present, the basis for

making many decisions is still

often experience or intuition.

Humans have their own

‘computer’, the brain. However,

the brain is not immune to

prejudice. Even factors such

as the weather or one’s mood

demonstrably and significantly

influence decisions. Often

many important characteristics

are lacking for a proper

analysis and assessment,

but an algorithm that is

programmed in advance is

subject to fewer such errors

in reasoning. Mathematical

foundations offer the possibility

that decision-makers receive

a formula that is objective,

transparent and applicable to

different situations.

Thus, for example, through

the use of Cassantec’s

prognostic reports, a

foundation is created to

make sound decisions for

maintenance strategies – for

example, to pool maintenance

interventions intelligently and

to plan them in time to avoid

costly overtime and night shifts.

Maintenance plans will no

longer be created periodically

and based on experience, but

with a transparent, data-based

structure. This saves companies

huge costs.

What is holding us back

Society is at the beginning

of a digital transformation.

Industry 4.0 and the Internet

of Things offer enormous

potential to change and

exercise a positive influence

over the way employees

work. Yet technologies such

as prognostics also face

challenges. The prudent

application of prognostic

solutions requires that

reliability and maintenance

professionals possess an

extended skillset: the ability

to articulate risk, to explicate

forecasts, and to consider

both in asset management

decisions. Prognostics

complements and requires

operator experience and

manufacturer know-how, but

it also necessitates a shift

in thinking and language

towards a risk management

approach. In the long

run, though, it is clear that

companies and professionals

must face these challenges.

Companies that have not

already started collecting data

for sophisticated analyses, and

that are not planning to make

use of the new possibilities,

will eventually reach the point

where they can no longer

compete in the digitalised

environment.

The foundation for

intelligent planning

The use of complex data

analytics in order to control

and improve processes is

increasing in the age of Big

Data and the Internet of Things.

When it comes to maintenance

and repair activities, the use of

big data analytics is likewise

increasing. With the help

of data-based prognostic

technology, the future

condition of machines can

be determined. This creates

the foundation for intelligent

maintenance planning.

Instead of fixed intervals,

maintenance will now only take

place when it is technically

necessary. Implementation

in a cogeneration plant can

increase the understanding

and transparency for the

plant. The foresight derived

from prognostics can

enable an active control

and expansion of the RUL.

Moritz von Plate is CEO of

Cassantec

www.cassantec.com

This article is available

on-line.

Please visit www.cospp.com

Advantages of prognostics:

• Maintenance can be carried out when it is technically necessary, which reduces the number of maintenance interventions;

• The influence of the operational regime on the RUL becomes transparent, which means that it is possible to actively manage RUL;

• It becomes apparent well in advance when the risk of a malfunction will reach the risk tolerance threshold. This allows for avoidance of unplanned malfunctions;

• Repairs can be planned in advance and then conducted when the impact of operational interruptions is at its lowest;

• The processing and presentation of the data provides transparency and enables fleet-wide comparisons over time;

• Decision-making competency can be increased by means of objective information, the machine will gain in safety and reliability, and the reduction of (unplanned) malfunctions will save budget.

The dots show the exact data reading points Source: Cassantec

1511cospp_28 28 11/2/15 3:29 PM

Operations & maintenance

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 29

The dos and don’ts

of genset maintenance

A standby power system is only as reliable as those responsible for operating

and maintaining it. Proper maintenance is as critical as the unit itself,

writes Tyson Robinett

It’s your worst nightmare:

the power goes off and

stays off.

A utility outage can be

disastrous for any business,

often arriving unexpectedly

and occurring at the worst

possible moment. Although

the majority of utility outages

tend to be infrequent and of

short duration, catastrophic

losses can occur if electrical

power from the utility is lost,

even for a short time.

Around the world, major

power failures are occurring

more frequently. This is due, in

part, to the world’s increasing

demand on electrical grids,

but Mother Nature also

plays a major role. Research

shows that the number of

weather-related incidents has

increased worldwide during

the past 40 years. In fact, as I

write this, Hurricane Joaquin

left destruction in its path as the

Category 4 storm hammered

parts of the Bahamas and

Bermuda and brought record-

breaking flooding to South

Carolina. Crews throughout

the Caribbean and the US

east coast are scrambling to

restore power or to brace for

what may come.

Growing risks worldwide make backup power more crucial than everCredit: MTU Onsite Energy

1511cospp_29 29 11/2/15 3:29 PM

Operations & maintenance

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 30

There will always be an

amount of uncertainty when

it comes to utility outages,

but there are ways to reduce

risk. Businesses around the

world are producing their own

emergency power during

outages with the help of

on-site diesel-powered backup

generator sets. However, just

having a generator is not

enough.

A standby power system

is only as reliable as those

responsible for operating

and maintaining it. Proper

maintenance is as critical as

the unit itself and can be the

difference in having the lights

needed to perform emergency

surgery in a critical moment, or

powering airport terminals on

a stormy winter day.

To ensure that your

emergency power system is

operable when most needed,

this guide addresses a few key

do’s and don’ts to ensure that

your generator set remains

operable in the event of an

outage.

DO: Plan maintenance

It may seem obvious, but

establishing a maintenance

schedule is paramount to

generator reliability. Planned

maintenance programmes

ensure emergency standby

power systems remain in a

constant state of readiness.

Planned maintenance

also ensures proper system

performance, while preventing

the risk of safety hazards for

onsite personnel.

It’s important to establish a

maintenance schedule that is

based on the specific power

application and the severity of

the environment. For example,

if the generator set is located

in an extremely cold or hot

climate, or is exposed to salt air,

the system may require special

needs, such as maintenance

and inspection in more

frequent intervals.

When undertaking this

task, large facilities should

engage their local generator

set distributor to provide

support in creating a plan

customised to the exact needs

of the facility. Working with a

distributor also ensures that

the maintenance is completed

on a regular schedule with full

documentation and according

to the manufacturer’s

recommendations.

A preventative maintenance

plan should include the

following:

• Inspections;

• Oil changes;

• Cooling system service;

• Fuel system service;

• Testing starting batteries;

• Regular engine exercise

under load;

• Documentation tracking

what’s been done.

The best maintenance plans

include more than the engine

generator. The entire power

distribution system should be

considered. For example, the

switchgear should be cleaned,

calibrated and scanned.

Additional preventative

maintenance should also

be performed according to

industry codes and standards.

DO: Train personnel

Once you have a maintenance

schedule in place, adhere to it

by conducting the required

service and testing. Regular

maintenance and periodic

testing is required by code in

mission-critical applications.

Only properly trained service

technicians should do this. For

facilities with on-site service

technicians, operator training

and testing is not optional.

Untrained and inexperienced

technicians often overlook

incremental failures that

can lead to large system

malfunctions.

Personnel training begins

during the commissioning

process and should cover

system operation, record-

keeping and periodic

maintenance. Operators must

also be familiar with all the

power system components,

alarm conditions, and

operation and maintenance

procedures. Special attention

should be given to critical

subsystems such as fuel

storage and delivery, starting

batteries, engine coolant

heaters, and airflow in and out

of the generator building or

enclosure. Frequent retraining

is also necessary, along with

making sure that personnel

maintain an operational

history of the power system.

Genset manufacturers and

distributor service technicians

are available to help and,

at a minimum, should work

alongside on-site service

managers, as they are

usually the most qualified.

Distributor service technicians,

in addition to being trained

on the equipment, follow the

maintenance procedures as

recommended for standby

generator systems by bodies

such as NFPA, NEMA and EGSA.

Most will also carry with them

the necessary replacement

parts, oil and fuel.

DO: Test under real-

world conditions

At least once a year, facilities

should exercise the power

system under the actual facility

load and full-emergency

conditions to verify that the

system will start, run and

accept the rated load.

Running for up to several

hours under these conditions

helps to test all the system

components. When operated

with the actual building

load, the entire power system

should be tested, including the

automatic transfer switches

and switchgear.

Resistive load bank testing

is the most common way of

testing a generator set to its

A trained technician performing maintenanceCredit: Central Power Systems & Services

1511cospp_30 30 11/2/15 3:29 PM

Operations & maintenance

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 31

full nameplate rating. Without

any interruption to the building,

this test will help identify any

possible weaknesses under

controlled conditions that

would lead to overheating

or shutting down. Running a

resistive load bank test with an

artificial load should take no

longer than eight hours unless

there are government and

military specifications, which

may require up to 24 hours for

testing.

Reactive load bank testing

is another method which

allows for proper calibration

of load sharing and voltage-

regulating systems in parallel

operation installations.

However, it is usually only

used for new installations with

critical large motor loads to

ensure the generator will not

deteriorate or change once

tested and proven at startup.

Regular testing and

systems monitoring can be

the difference between a

generator starting during an

emergency and one stalling

out. Besides verifying that the

generator set will start and

run, periodic exercise has the

benefit of heating up diesel fuel

and eliminating accumulated

condensation in the fuel tank.

Since clogged fuel filters and

fuel contamination are among

the leading causes of power

system malfunctions, the

cycling and refreshing of fuel is

an important step in ensuring

overall system reliability.

DON’T: Ignore fuel

storage

Standby generator systems

are more susceptible to fuel

contamination because the

fuel sits idle and unused for

long periods. If left untreated,

fuel will substantially degrade.

Fuel supplies should be

replenished regularly to

ensure reliable starting and to

prevent clogged fuel filters. In

addition, fuel quality should be

tested often. Primary types of

degradation include:

• Water contamination

Water builds up from

condensation on the interior

walls and on top of the fuel

tank. This occurs almost

every day when the outdoor

temperature increases faster

than the temperature inside

the fuel and tank.

• Microbial organisms

Microbes are always present

in diesel fuel. Too many

will prematurely clog filters,

which will not be evident

until the engine must pull full

load.

• Gelling Diesel fuel freezes at

a much higher temperature

than most other fuels.

Standard diesel can freeze

at any temperature below

0°C, which will lead to gelling

and clogged fuel pipelines.

• Degradation Diesel fuel

starts to degrade after six

months and can render

fuel completely useless after

two years. Additives, fuel

filtering, regular sampling

and diesel fuel supplements

help prevent or remove

contaminants that can

lead to degraded fuel and

significant engine damage.

DON’T: Ignore the

battery

Maintenance of a generator

set’s starter battery is critical

to ensuring sufficient ampere

capacity to start the engine.

Nearly 50% of emergency

genset failures are attributed

to weak starting batteries. As a

preventative measure, replace

batteries every two years.

During maintenance

checks, trained technicians

should carry out the following

tests to ensure batteries

are meeting required

specifications:

• Specific gravity Test the

battery’s Specific Gravity

level with a hydrometer and

compare the levels with

the battery supplier. Before

beginning testing, ensure

that the battery is rested with

no charge or discharge for

24 hours.

• Equalise charge Although

equalising charging isn’t

recommended to be used

routinely, there should be

occasional checks to ensure

that every plate in each cell

reaches a full state of charge

in their respective positions.

• Battery capacity testing

Ensure that the battery is

fully charged initially. Next,

use a resistive battery tester

to place a load of 5% of

battery capacity to measure

the battery’s handle.

• Visual check for corrosion

and dirt Dirt can block

current flow in connectors

and cause resistance

between terminals. Clean

dirty or corroded terminals

and connectors with a wire

brush dipped in a solution of

baking soda and water. After

cleaning, rinse with clean

water and coat terminals

with a thin coat of petroleum

jelly or a corrosion inhibitor.

Electrolyte level checks are

also important. If fluid levels in

battery cells drop below the

top level of the separator, add

distilled water to cover the

plates. Lastly, if leakages are

found due to a cracked battery

casing or spilled electrolyte,

replace the entire battery.

Standby generator sets

are reliable systems with

normal availability in excess

of 98% on an annual basis.

To get the highest reliability,

facilities should take great

care to plan and employ

frequent maintenance and

testing. When done in close

co-ordination with a local

distributor and the factory, this

co-ordination can help identify

potential failure modes,

develop solutions before

problems occur and decrease

downtime. By considering

the factors outlined above,

managers of mission-critical

facilities can be assured

that they will never be left

in the dark.

Tyson Robinett is general

manager in the air, light and

power generation division

at Central Power Systems &

Services

www.cpower.com

This article is available

on-line.

Please visit www.cospp.com

Technicians will carry the necessary replacement parts, oil and fuelCredit: Central Power Systems & Services

1511cospp_31 31 11/2/15 3:29 PM

Evolving packaged CHP systems

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 32

Packaging CHPUse of packaged combined heat and power systems is growing steadily for a

number of key application segments. Tildy Bayar spoke to two sector insiders to

find out what’s involved, and why good things come in ever-smaller packages.

Use of packaged

combined heat

and power (CHP)

systems is growing

steadily in the key markets

of the US, Europe and Asia

Pacific, largely due to

technology improvements

and cost reductions.

Within a packaged CHP

system can be found the

prime mover, alternator, heat

exchangers and a control

panel. These elements are ‘all

packaged into a large box

that can be dropped into

an application, which allows

the customer or installer to

connect up to a heating

system, add fuel and electrical

connections, and it’s pretty

much ready to go,’ says

Scott Briance, sales support

manager for UK utility Veolia’s

CHP team.

‘The vast majority’ of

commercial CHP systems

Veolia sells today are

packaged, Briance says,

especially for new buildings.

Installing a packaged system

in a new plant room can be

‘almost like buying a large

industrial boiler these days – it’s

a similar purchasing process,’

he notes.

Packaged CHP systems

are also gaining momentum

as replacements for boilers.

Devon Manz, chief marketing

officer with GE’s Distributed

Power business, notes that

packaged CHP systems are

‘big business’ in Eastern Europe,

where they are replacing

older coal-fired boilers in

commercial installations

and district heating plants.

A packaged system can be

installed at an existing plant

‘relatively easily’, he says, citing

examples of ‘buildings where

they’ve taken down one wall

and extended the building

a little bit, or moved things

around inside’.

Sizing is a big issue

Briance notes that 50%–60%

of CHP systems of 500 kW

and below face space

restrictions. Veolia generally

requires one metre of unused

space around a packaged

installation in order to leave

room for maintenance activity.

‘All of our packages have

big doors on the side to allow

full access to three of the four

sides,’ Briance says, ‘and they

need a metre to open’. He

says measures can be taken

including designing special

doors and making the box

smaller. ‘We package the

components as tightly as we

can whilst maintaining access

to key service areas such as

filters, spark plugs and oil,’

he says. ‘It’s always a bit of a

compromise, and is all done

through careful design. We

have put CHPs into situations

where there is less than half

a metre all the way round,

but we had to change our

standard design to allow the

level of access required.’

Within the CHP package,

the necessary components

must fit into the available

space around the engine,

with the length and width

of the package determined

by the engine’s size. While

all packaged CHP systems

generally contain very

similar components, different

manufacturers will design

their packages differently

depending on maintenance

considerations. ‘Some

manufacturers might package

very tightly in order to get the

overall size down, but they

might have to compromise the

ability to service,’ says Briance.

‘Traditionally our CHPs have

had the engine at the bottom

below the exhaust gas heat

exchanger,’ he says, but ‘on

one 200 kW unit that large

tube was getting so close to

the top of the engine that

the engineers were struggling

to change the spark plugs.’

In the revised design ‘we’ve

moved the heat exchanger

to a low level so it is alongside

the engine.’ He notes that the

firm attempts ‘to stick as close

to as possible to the standard

design most of the time – but

it’s not always possible.’

GE’s CHP packages can

use either gas engines or gas

turbines. According to Manz,

‘Engines are definitely up and

coming, and can provide

higher overall electricity and

efficiency, but I don’t think

you can get more power out

per square foot than from an

aeroderivative gas turbine.

In locations where space is

1511cospp_32 32 11/2/15 3:29 PM

Evolving packaged CHP systems

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 33

extremely tight, turbines are

the right choice – they are

used for offshore oil and gas

applications. For airports and

hospitals, space is of high

value and they look at turbines

because they need both

power and heat anyway.’

GE’s gas engine-based

packaged CHP systems

include the engine, genset,

cooling system and heat

recovery system in a 40-foot

(12-metre) container which

can be shipped to a site

and, Manz says, installed with

minimal resources and effort.

However, he notes that most

of the firm’s turbine-based

systems are larger and must

be built on-site, requiring ‘more

site-intensive labour to get

them up and running’.

‘With a gas engine,’ he

says, ‘we supply the complete

system and take the hot water

from the package. The system

recovers heat from the engine,

exhaust and cooling system,

so you pipe it up to your system

to pump hot water through a

plant or building. The same can

be done for turbines, although

it is a much bigger system and

waste heat recovery system.’

The cost equation

The cost of a packaged CHP

system will vary, says Briance,

and whether it is cheaper than

a bespoke system will depend

on the scale of the installation

required. For smaller projects,

given that packaged systems

are designed for ease of

installation, he says ‘it’s

probably cheaper to buy

a packaged CHP where

possible’.

However, he notes that

‘a major revolution in cheap

CHP’ is unlikely given that there

aren’t many costs that can

be cut. Since the prime mover

needs to be good quality and

high efficiency, and to work

reliably for a lifetime of up to

20 years, it tends to be more

costly – but ‘we would never

risk the quality of the overall

product [by saving money on

the prime mover],’ Briance says,

‘because it tends to be a false

economy’. In addition, much

of the equipment that goes

into a CHP package ‘is already

quite mass-produced, and the

costs are what the costs are.’

Still, prices for packaged CHP

systems ‘have stayed pretty

stable over the last few years,

and if anything have gone

slightly up’, he notes.

‘With the current spark

gap I would expect a 200 kW–

250 kW CHP to pay back in less

than four years,’ he explains.

‘We tend to see that 500 kW

and above will be under

three-year payback times for

a full installation. We have

calculated payback times of

less than two years.’

Hospitals, Briance says, are

‘more than capable of taking

around 1 MW of electrical CHP,

if not more’, so their payback

times tend to be relatively

short – and they also expect

a high level of availability and

service. Hotels which choose

CHP ‘look for a specific IRR

– around 19%–20%, which

comes in around a four-year

payback time. Four to five

years is more acceptable in

the hotel industry, and more

realistic for the size of the CHP

they’re taking – around the

200 kW–300 kW mark,’ he notes,

‘similarly to leisure centres.’

For Manz, the costs

associated with a packaged

CHP system will depend on the

needs of the facility. If steam

is the main need, he says, he

would advise the customer

to purchase a gas turbine-

based system. Gas turbines

‘have a lower overall electrical

efficiency and higher exhaust

temperatures, so they can

produce a higher quality and

volume of steam,’ he says. If

the customer’s main need is

hot water, for which the highest

overall efficiency is needed, he

recommends a gas engine-

based system.

If electrical power is the main

need, Manz’s recommendation

would vary depending on

how much power is desired.

An apartment building will

require ‘several megawatts’ of

heat, with around 70 MW for

an airport and 50 MW for a

hospital – it ‘varies dramatically,’

he says, and requires different

equipment combinations.

‘One gas turbine can supply

50 MW of heat; for a hot water

project you might need 50 MW,

so we can do multiple engines.

The maximum heat output is

not always required,’ he says,

‘but for some customers heat

is extremely valuable and they

want maximum heat, while

electrical efficiency is not as

important.’

When asked what kinds

of businesses tend to buy

packaged CHP systems, Manz

replies: ‘All of them’. Uptake in

greenhouses is growing mainly

in Russia, he says, because of

food industry demand, and

uptake by airports, hospitals,

hotels, apartment complexes,

industry and breweries is

growing worldwide.

Manz cites Eastern Europe

(especially the Czech

Republic, Hungary, Poland

and Romania), Russia and the

Netherlands as particularly

strong market segments, with

the latter country being a

robust region for cogeneration

systems because of its

greenhouses.

Smaller packages with

more functionality

Briance sees packaged CHP

systems reducing in size over

time. He says the systems ‘will

slowly but surely get smaller’ as

engine technology improves.

He also foresees the addition

of more functionality, and

thus more equipment, to the

package.

One of the biggest changes

to the packaged CHP segment

over the next four to five years is

‘how manufacturers package

a product that can provide the

emissions required by modern

cities whilst keeping overall

cost down.’ Veolia is ‘regularly

asked to do larger engines with

the same emissions output

as smaller ones,’ he says,

which means the use of SCRs,

which are ‘starting to get more

prevalent’. However, he notes

that ‘whenever a SCR needs to

be put onto a CHP, it becomes

a very bespoke product’, and

while he envisions that SCR

technology will become part

of the standard CHP package

in future, ‘we’re not there quite

yet.’

This article is available

on-line.

Please visit www.cospp.com

50% of CHP systems face space restrictions Credit: GE

1511cospp_33 33 11/2/15 3:29 PM

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 34

Genset Focus

Genset Focus

Genset shift to gas predicted The diesel-fuelled genset

market is poised for continued

growth in most regions and

power classes, a new report

from Navigant Research

shows. However, diesel is facing

increasing competition from

natural gas generators in

certain markets.

Continued growth in the

supply of unconventional

gas resources and tightening

regulations targeting stationary

generator emissions may

signal a shift toward cleaner-

burning natural gas systems.

In the short term, though,

countries with strong economic

and/or population growth

rates coupled with unreliable

power grid infrastructure and

blackouts will continue to drive

diesel genset sales.

Global diesel genset

capacity additions are

expected to increase from

62.5 GW in 2015 to 103.7 GW in

2024.

Powering the world’s largest vessel

Floating liquefied natural gas

(FLNG) facilities are ground-

breaking, helping to unlock

large energy reserves from

new fields that were previously

not economical to reach – but

first the facilities themselves

need a power supply.

One of the great strengths

of turbine-driven power

generation is its ability to

operate reliably in remote and

difficult-to-access locations

and also to generate high

levels of output for its size and

weight.

When it comes to stand-

alone power systems, there

can be few projects that

present more of a challenge

than floating offshore projects,

and perhaps the best example

of these is Prelude – a FLNG

facility that is currently the

biggest vessel in the world.

The giant hull – which

by definition is not a ship

as it does not have its own

propulsion system, instead

needing to be towed by tugs

– is 488 metres long and when

finished will weigh more than

600,000 tonnes.

It was launched in 2013 and

is still being fitted out with the

large amount of equipment

needed to safely store and

process millions of tonnes

of LNG each year. When

completed, it will be located

120 miles off the northwest

coast of Australia.

Running an LNG facility

of this size involves countless

pumps, valves and control

systems, as well as the need

to keep thousands of tonnes

of liquid gas at temperatures

below -162°C and to support

a permanent crew of 120

people. This requires a sizeable,

constant and reliable source

of energy.

This is being delivered by

steam turbines, connected

to a suite of three 40 MW

synchronous generators

supplied by Brush, an energy

solutions provider for the

global power industry. The

two-pole DAX units used on

the project are similar to those

used around the world in

public utility, cogeneration and

industrial applications, but with

additional attention paid to

framing and mounting of the

generator to account for the

pitch and roll motion present

onboard a vessel.

Blair Illingworth, chief

executive of Brush, says: ‘The

power source on an FLNG

facility is absolutely critical. The

reliability of DAX generators

is a big part of why they are

popular for powering facilities

such as hospitals and large

industrial plants. The fact that

they have been selected for

this project is testament to their

reputation for dependable

performance in critical

applications.

‘As well as reliability, the

other major factors on a

floating facility are footprint

size and weight – every extra

kilogramme adds to the overall

displacement of the vessel,

for which there is a strict limit,

and space will always be at a

premium. Another strength of

the DAX generators is their high

level of power output for their

relatively compact dimensions.

‘A further key part of the

criteria for the generator

was minimal requirement

for ongoing maintenance,’

Illingworth continues. ‘By

following the prescribed

operation and maintenance

regimes, DAX generators

typically have a life expectancy

of 25 years or 10,000 starts,

so this was obviously also

appealing to the project team.

‘When you consider that

at the heart of one of our

generators is a single-piece

steel forging weighing several

tonnes and rotating at

3600 rpm, this highlights the

criticality of the design and

manufacturing processes used

by Brush. The generators are

a superb example of a large

number of highly developed

components working together

to deliver truly impressive

longevity and performance.’

1511cospp_34 34 11/2/15 3:29 PM

Genset Focus

www.cospp.com Cogeneration & On–Site Power Production | November - December 2015 35

Rolls-Royce gensets to power Bangladesh steel factory

Rolls-Royce is to supply eight

gas-fired gensets to power

what will be Bangladesh’s

largest steel factory.

The factory, located in

the port city of Chittagong

and owned by industrial

conglomerate the Abul Khair

group, is undergoing expansion

and, once completed, will

be Bangladesh’s largest steel

milling facility.

The gensets will total 50 MW

in capacity and are based

on medium-speed 20-cylinder

Type B35:40V20AG2 gas

engines from Bergen Engines.

They are scheduled to be

commissioned in 2016.

The power will be used

on-site, Rolls-Royce said, while

the Abul Khair group plans to

use the exhaust gas for steam

production in future.

Caterpillar gensets to power US gas-fired plant

Caterpillar is to install a

38.8 MW power plant in

Owatonna, Minnesota, US.

Powered by four Cat

G20CM34 gensets, the new

plant replaces one that

was damaged by flooding

in 2010. Owatonna Energy

Station will be built, owned

and operated by Southern

Minnesota Municipal Power

Agency (SMMPA), a collective

of 18 municipal utilities, with

construction scheduled to

begin in 2016.

Each 20-cylinder gas-fired

genset will produce up to

10 MW and is equipped with

Cat’s electronic control system

to ensure precise fuel delivery,

the company noted.

‘We are pleased to be

working with Caterpillar again

on this important resource,’

said Dave Geschwind, SMMPA’s

CEO. ‘This project will help the

agency further diversify its

resource mix with additional

natural gas generation, and

it will be an important asset in

managing future capacity and

energy costs.’

‘Considering the new

plant’s fast start, high

efficiency and low emissions,

SMMPA will be able to offer

very valuable services to the

local system operator,’ said

Claudio Martino, regional

sales director with Caterpillar.

‘It will provide black start

capability, enabling SMMPA

and the residents of

Owatonna to better manage

their power needs.

‘Instead of relying on

remote resources, the region

can generate power in their

own back yard in a reliable

and cost-effective manner.’

Flexible low-load gensets are ‘game changers’ says report

Traditional gensets are being

modified to run in low-load

mode with minimal fuel

consumption, but with the

ability to respond quickly to

output changes from an allied

solar photoltaic (PV) array or

changes in demand. Such

devices are finding increasing

application in the mining

industry.

A new study, ‘Low-load

Gensets for Solar-diesel Hybrid

Plants in the Mining Industry’,

analyses the technical

and strategic fit of low-load

gensets for solar-diesel hybrid

applications, finding that

low-load gensets almost

double the solar penetration

rate in hybrid systems and are

more efficient in these plants.

This solution could

considerably lower mines’

operational costs, the report

notes, adding that the fast

spinning reserve of low-load

diesel systems ensures supply

in case of variation of demand

or of PV production losses, for

example from shading.

An attractive target for solar–

diesel hybrid plants is the mining

industry as power consumption

is usually high and mines are

typically in remote locations

with high costs for diesel and

for its transport, the analysis

concludes.

‘The demand for raw

materials has slowed down

and prices have decreased

recently. The mining industry is

facing substantial challenges.

Reducing the costs of

operations such as energy

expenditures has become an

important competitive factor,’

said Dr Thomas Hillig, CEO of

consultancy THEnergy and

author of the report.

‘One of the game changers

could be low-load diesel hybrid

power plants giving maximal

room to locally produced

inexpensive solar and/or wind

energy,’ he added. ‘Even at the

current low oil prices, optimized

hybrid technologies normally

beat the current conventional

diesel-based electricity prices.

The additional investment

including the PV system has

usually a payback period

in the range of four to seven

years.

1511cospp_35 35 11/2/15 3:29 PM

Cogeneration & On–Site Power Production | November - December 2015 www.cospp.com 36

Diary

Send details of your event to Cogeneration and On-Site Power Production:

e-mail: cospp@pennwell.com

Diary of eventsChatham House/Energy

Transitions

9–10 November

London, UK

www.chathamhouse.org/

conferences/energy-transitions

7th Annual Middle East

District Cooling Summit

10–11 November

Doha, Qatar

www.cleanenergybusinesscouncil.

com/event/7th-annual-middle-

east-district-cooling-summit

Heat 2015

25 November

London, UK

www.theade.co.uk

4th Annual District Energy

Asia

2–3 December

Beijing, China

www.districtenergyasia.com

POWER-GEN International

8–10 December

Las Vegas, Nevada, USA

www.power-gen.com

World Future Energy Summit

18–21 January 2016

Abu Dhabi, UAE

www.worldfutureenergysummit.

com

International Low Carbon

Heat & Water Conference &

Showcase

23 January 2016

Glasgow, Scotland

www.scottish-enterprise.com/

events/2016/02/international-

2016-low-carbon-heat-and-water-

conference-showcase

Campus Energy 2016

8–12 February 2016

Austin, Texas, USA

www.ideacampus2016.org/

Western Turbine Users Inc

20–23 March 2016

Palm Springs, California, USA

http://wtui.com

COGEN Europe Annual

Conference 2016

22–23 March 2016

Brussels, Belgium

www.cogeneurope.eu/cogen-

europe-annual-conference--gala-

dinner-2016_282375.html

POWER-GEN Russia

19–21 April 2016

Moscow, Russian Federation

www.powergen-russia.com

POWER-GEN India & Central

Asia

19–21 May 2016

New Delhi, India

www.indiapowerevents.com

POWER-GEN Europe

21–23 June 2016

Milan, Italy

www.powergeneurope.com

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