CIBSE AM12: 2013
The Chartered Institution of Building Services Engineers
222 Balham High Road, London, SW12 9BS
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Combined heat and
power for buildings
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The rights of publication or translation are reserved.
No part of this publication may be reproduced, stored in a
retrieval system or transmitted in any form or by any means
without the prior permission of the Institution.
© Second edition January 2013; The Chartered Institution of
Building Services Engineers London
Registered charity number 278104
ISBN 978-1-906846-30-5
This document is based on the best knowledge available at
the time of publication. However no responsibility of any
kind for any injury, death, loss, damage or delay however
caused resulting from the use of these recommendations
can be accepted by the Chartered Institution of Building
Services Engineers, the authors or others involved in its
publication. In adopting these recommendations for use each
adopter by doing so agrees to accept full responsibility for
any personal injury, death, loss, damage or delay arising out
of or in connection with their use by or on behalf of such
adopter irrespective of the cause or reason therefore and
agrees to defend, indemnify and hold harmless the Chartered
Institution of Building Services Engineers, the authors and
others involved in their publication from any and all liability
arising out of or in connection with such use as aforesaid
and irrespective of any negligence on the part of those
indemnified.
Typesetting and layout by CIBSE Publications
Printed in Great Britain by The Lavenham Press, Lavenham,
Suffolk CO10 9RN.
Cover illustration: The Energy Centre at the 2012 London
Olympic Park (architects: John McAslan and Partners). The
Energy Centre includes a gas-fired combined cooling, heating
and power (CCHP) plant to capture the heat generated by
electricity production. It also includes biomass-fired boilers
to generate heat and deliver low carbon energy. Cooling is
provided through a combination of electric, ammonia-based
chillers and absorption chillers, which are driven by heat
recovered from plant in the Energy Centre. (Photograph by
Hufton+Crow; courtesy of John McAslan and Partners.)
Note from the publisher
This publication is primarily intended to provide guidance to those responsible for the design,
installation, commissioning, operation and maintenance of building services. It is not intended
to be exhaustive or definitive and it will be necessary for users of the guidance given to exercise
their own professional judgement when deciding whether to abide by or depart from it.
CIBSE Applications Manual AM12: Small-scale chp for buildings was first published in
1999. With the growing concerns over global warming and the recognition of the role that
chp can play in delivering low carbon buildings this revised and updated edition has been
produced. A number of new sections have been added including:
——
a new chapter on district heating applications
——
more information on assessing environmental benefits
——
more detail on tri-generation and thermal storage.
Principal author
Paul Woods (AECOM)
AM12 Steering Group
The production of this publication has been greatly assisted by the work of the AM12
Steering Group. CIBSE are indebted to the following individuals and their organisations:
Phil Jones (chair)
Mark Anderson (Arup)
Huw Blackwell (Hoare Lea)
Lars Fabricius (SAV Systems)
Tony Gollogly (PB Energy Solutions)
Dr Julian Packer (Cogenco Ltd)
Dr Robin Wiltshire (BRE)
Reviewers
Detailed reviews have been carried out by the following. The CIBSE is very grateful for
their valuable contribution.
Dr Jonathan Williams (BRE)
Peter Pearson (Dalkia plc)
Huw Blackwell (Hoare Lea)
Dr Gregory Zdaniuk (Cofely GDF-Suez)
Acknowledgements (third edition)
CIBSE would like to acknowledge the valuable contributions provided by a wide range of
individuals and organisations including the following: AECOM, Cofely District Energy
Ltd, Combined Heat and Power Association (CHPA), Cogenco Ltd, Corporation of
London, Dalkia plc, EC Power A/S, EnerG Combined Power Ltd, David Hague (Cogen
Solutions Ltd), LowC Communities Ltd., SAV Systems, UK District Energy Association,
University of East Anglia, Veolia Environmental Services (UK) plc.
Editor
Ken Butcher
CIBSE Head of Knowledge
Nicholas Peake
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Foreword to the third edition
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Contents
1
Introduction
1.1
The energy challenges
1.2
What is chp?
1.3
Why chp should be considered
1.4
Scope of AM12
1.5
Purpose of AM12
1
1
1
3
4
4
Part 1: Technologies, applications and regulations
2
CHP and energy centres (fossil fuel)
2.1
Spark-ignition gas engines (50 kWe to 10 MWe)
2.2
Mini or small-scale chp (<50 kWe)
2.3
Micro gas turbine chp
2.4
Individual dwelling chp (<2 kWe)
2.5
Larger-scale chp
2.6
Fuel cells
2.7
Combined cooling, heating and power (tri-generation)
3
Renewable energy and CHP
3.1
Biomass chp using combustion of solid biomass fuel
3.2
Biogas chp using gasification of solid biomass fuel
3.3
Liquid biofuel chp
3.4
Energy from waste
3.5
Biomethane injection
3.6
Integration of chp with renewable energy sources
3.7
Integration of chp with heat pumps
8
8
9
10
10
11
11
11
4
CHP for individual buildings
4.1
Introduction
4.2
Building heating, cooling and electrical demands
4.3
Fuel and electricity tariffs
4.4
Principles of chp sizing
4.5
Design of building heating systems to benefit chp operation
4.6
Building applications most suitable for chp
4.7
chp to improve security of electricity supply
12
12
12
13
13
16
17
17
5
Application of CHP to supply district heating
5.1
Principles of district heating
5.2
Typical applications of dh and chp
5.3
Selling electricity and private wire networks
5.4
Efficient design of dh systems to benefit chp operation
5.5
Use of thermal storage
5.6
District cooling
5.7
Large-scale district heating
18
18
19
19
19
21
22
22
6
Primary energy savings and environmental impact of chp
6.1
Primary energy savings
6.2
CO2 savings and impact of emission factors
6.3
CO2 benefits from tri-generation
6.4
Other emissions to air
6.5
Noise
6.6
Other environmental impacts
22
22
24
26
26
27
27
7
Legislation and regulations and impact on CHP viability
7.1
Planning
7.2
Building Regulations
7.3
Climate Change Act
7.4
Carbon trading: CRC Energy Efficiency Scheme
and the EU Emissions Trading Scheme
7.5
CHP Quality Assurance Programme
7.6
Other financial mechanisms
7.7
Parallel operation with dno system
5
5
6
6
6
7
7
8
28
28
28
28
28
28
29
29
8
Feasibility studies
8.1
Introduction
8.2
Data gathering of energy demands and system temperatures
8.3
chp performance, heat recovery options
8.4
Optimum sizing of chp
8.5
Thermal storage
8.6
Tri-generation (cchp)
8.7
Integration with other low carbon technologies
8.8
Typical capital and maintenance costs and efficiencies
for gas-engine chp
8.9
Economic appraisal
8.10
Financing options
8.11
Feasibility report
30
30
30
33
33
33
34
34
34
9
39
39
39
40
41
43
43
44
44
44
45
45
46
47
47
48
49
Design
9.1
9.2
9.3
9.4
9.5
9.6
9.7
9.8
9.9
9.10
9.11
9.12
9.13
9.14
9.15
9.16
Allocation of responsibilities
Health and safety aspects
Energy balance for chp and heat recovery systems
System design: interfaces with heating circuit
System design: absorption chillers
System design: electrical interface
Fuel system
Combustion exhaust system
Combustion and ventilation air systems
Control systems
Maintenance facilities
Control of noise and vibration
Fire and gas detection and protection
Regulatory compliance and approvals
Specification: typical contents for chp package specification
Design of district heating
34
36
38
10
Procurement
Tendering
10.1
10.2
Assessment of tenders
51
51
52
11
Installation, commissioning and testing
11.1
Installation
11.2
Component testing, off-site testing
11.3
Commissioning
11.4
Client acceptance testing
53
53
53
54
55
12
Operation and maintenance
12.1
Operation
12.2
Operation and maintenance manuals
12.3
Maintenance and servicing
55
55
56
57
Part 3: Lessons learned
13
Lessons learned
13.1
Feasibility studies
13.2
Economic appraisals
13.3
Integration of chp into heating systems
13.4
District heating
13.5
Environmental impacts
13.6
Procurement
13.7
Detailed design and installation
13.8
Commissioning
13.9
Operation
13.10 Tri-generation and absorption chillers
59
59
59
60
60
60
60
61
61
61
61
References
62
Appendices
Appendix A1: Conversion factors
Appendix A2: Glossary of terms
64
64
64
Index
67
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Part 2: Project implementation
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1
Combined heat and power for buildings
1
Introduction
of the future low carbon energy strategies will increase the
costs of energy supply.
Key points:
——
Three energy challenges are climate change,
security of supply and competitive prices.
——
CHP can assist in meeting these challenges.
——
primary energy savings of 23–30% are possible.
1.1
The energy challenges
The UK faces three major challenges in its supply and use
of energy (see Figure 1.1).
First, the risks of climate change are now accepted and the
need to reduce cumulative CO2 emissions has become a
fundamental part of the energy policies of all countries
with the Copenhagen Accord committing us to joint action.
In the UK the Climate Change Act 2008 has set a legally
binding requirement for an 80% reduction in CO2 emissions
from 1990 levels by 2050.
Secondly, the UK has benefited from indigenous energy
resources of coal, oil and natural gas for many years. We are
now facing a new situation where we will be increasingly
importing fossil fuels from a declining resource against a
background of rising worldwide energy demand. At the
same time a significant proportion of power stations need
to be replaced as older coal-fired and nuclear stations need
to be closed. Energy security is becoming a more important
issue with concerns over the potential for gas supply
interruption from unstable regimes, higher world prices for
gas and the potential for power outages if investment is not
forthcoming.
The third challenge is to maintain competitive energy
prices to enable both industry and society to thrive. Many
CO2 reduction
In responding to these three challenges, energy strategies
also need to minimise the impact on the wider environment,
whether this is related to air quality in cities, visual impact
in the countryside or at sea, or the safe disposal of waste
products from energy systems.
Energy use in buildings is a major contributor to CO2
emissions and the supply of heat for space heating and hot
water is associated with approximately 16% of total UK
CO2 emissions (CCC, 2010). The role and responsibility of
the building services engineer in meeting these challenges
is therefore very significant.
Combined heat and power (chp) has been recognised as a
technology that can reduce CO2 emissions. It can also be
cost-effective to implement in many applications. The
greater efficiency of fuel utilisation will also help improve
energy security. chp thus has the potential to help meet all
of the three challenges outlined above.
The energy efficiency benefits obtained with a chp system
will still be needed even if the fuels used in the future are
low carbon, as such fuels will be in short supply and will
also have environmental impacts. Maximising the efficiency
of utilisation of renewable fuel will remain an important
part of the case for chp in the future.
1.2
What is CHP?
Our conventional energy supply system is based on the
separate production of electricity in power stations and
heat from boilers.
(also known as co­generation) is the name applied to
energy systems that produce both useful heat and electricity
in a single process.
chp
As a result of the second law of thermodynamics, power
stations reject to atmosphere about 50% to 60% of the
thermal energy used. In a chp plant a large proportion of
this heat is captured for use in heating buildings or for
process heat.
Energy prices
• Fuel poverty
• Competitive
economy
Figure 1.1 The energy challenges
Security of
supply
• Heat reliability
• Imported gas
• Power blackouts
Electrical energy is also lost in the transmission and
distribution of power to buildings and this energy can also
be saved if the chp generates electricity more locally.
Although the production of electricity by chp is less
efficient than that which can be achieved from central
power stations, the use of the heat that would otherwise be
rejected leads to a net saving in primary energy.
Combined heat and power for buildings
A comparison between the separate production of heat and
power and chp is shown in Figure 1.2.
The primary energy saving is calculated as:
——
Fuel used by chp = 100 units (35 units of electricity
and 45 units of heat produced)
——
Conventional electricity at 40% efficiency would
require 35/0.4 units of fuel = 88 units
——
Conventional heat at 80% efficiency would require
45/0.80 units of fuel = 56 units
——
Total fuel required for conventional supply = 88 +
56 = 144 units
So the potential saving in primary energy is about 30%.
Improvements in efficiency of boilers and power stations
are taking place. However, even if the boiler efficiency is
assumed to be 85% and the conventional electricity supply
efficiency improves to 45%, the primary energy saving
would still be 23%. chp efficiencies are also improving.
An important question is whether chp represents a more
efficient use of natural gas. In this case it is the efficiency of
gas power stations rather than the grid average that should
be used; currently this efficiency is about 43% (gross
calorific value basis) delivered to customers.
A more detailed discussion of primary energy saving and
CO2 emissions is given in section 6.
Types of CHP
1.2.1
There are a number of types of chp and these are discussed
in section 2 below.
The most common type for building applications, where
relatively low grade heat is required, is based on a sparkignition reciprocating gas engine directly driving a
generator to produce electrical power. Heat is typically
recovered from the engine jacket, the oil cooler and the
exhaust gases and, if the heat required is at low enough
temperature, from the intercooler. This type of chp was
developed in the 1980s and is supplied as a fully packaged
unit of which several thousand have been sold in the UK.
Gross calorific value and net calorific value
Efficiencies of power plant are conventionally expressed using
the net calorific value (ncv) of the fuel. This is the energy in the
fuel released when the combustion products are cooled but
excludes energy released from the condensation of water vapour
(latent heat). The gross calorific value (gcv) includes the energy
released from condensation and is thus a higher value.
As energy is sold on the basis of gcv it is important to convert the
energy efficiencies to gcv basis before carrying out any analysis.
A chp unit typically operates in parallel with the public
supply with additional electricity imported as required.
The heat output is commonly supplemented with boiler
plant at times of peak demand. A thermal store can be
included to smooth the heat demand, reduce the need for
peak boiler use and maximise electricity production at
times of higher elec­tricity prices. The boilers and public
electricity supply connections are normally sized to meet
the peak demands of the building when the chp is not
operating, as the chp unit requires regular maintenance.
The chp units are normally maintained by the supplier
under a long-term maintenance contract with remote
monitoring of the operation allowing faults to be identified
and visits scheduled to maximise availability.
It is important that other energy savings measures are fully
considered before the viability of a chp scheme is evaluated.
Failure to do so may result in the benefit of the chp scheme
being undermined by the later application of other energy
efficiency measures. It is usually more important to avoid
oversizing chp, rather than undersizing, unlike most
building services plant.
When comparing district heating supplied by chp with
conventional systems the energy inputs to the district
heating network for both heat losses and pumping energy
also need to be considered.
In summary, the higher primary energy efficiency obtained
with chp delivers the energy cost savings required to
finance the chp installation and results in lower CO2
emissions.
1.2.2
Applications
Losses
11
45
Heat
demand
45
35
Power
demand
35
Boiler 56
CHP
144
100
20
Power
88
station
53
Losses
Figure 1.2 The energy efficiency of chp (reproduced from GPG388
(Carbon Trust, 2004) by permission of the Carbon Trust)
A wide range of buildings can be suitable for chp systems.
The economic return on the investment is determined
partly by the operating hours, so buildings that have a yearround demand for heat will generally be the most econom­
ically attractive. These buildings include residential blocks,
hospitals, hotels and swimming pools. For other buildings,
chp systems will still be able to operate effectively and
reduce costs and emissions but the payback period will be
longer due to fewer operating hours in the year. Combining
the demands of buildings with different heat demand
profiles through a district heating (dh) network will
improve the operating hours of the chp but will of course
incur additional cost for the dh network. For large campustype sites, e.g. a university, the higher efficiencies and lower
costs associated with larger-scale chp often mean that a lack
of summer heat demand is less of a barrier. The chp is
simply operated for 8–9 months of the year.
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Introduction
1.2.3
3
Tri-generation
The term tri-generation is often used to describe a chp
system that also supplies heat to an absorption or adsorption
chiller so that heat, electricity and cooling are produced. If
the chp is efficient enough so that the heat has a low carbon
content then there can be additional CO2 benefits. As
discussed in section 6.1 the effective CO2 content of chp
heat is very dependent on the source of the electricity that
will be displaced and thus the benefit of using heat driven
chillers is expected to fall over time, especially when there
is no unabated coal-fired generation operating in summer.
However this change might be offset by future improvements
in the coefficient of performance (cop) of heat driven
chillers.
The additional running hours of the chp will generate
additional cost savings for the site that are needed to help
finance the additional cost of the absorption or adsorption
chiller.
1.3
Why CHP should be considered
chp is typically considered because of the following drivers:
——
lower operating costs
——
reduced CO2 emissions
——
greater security of supply for electricity
——
government policy and incentives
——
replacement of boiler capacity
——
efficient use of renewable fuels.
These are discussed in turn below.
1.3.1
Lower operating costs
Lower operating costs are achieved with a chp unit as the
energy purchased for a site changes as follows:
——
More gas is purchased as both electricity and heat is
produced from the chp.
——
Less electricity is purchased as the
electricity on-site.
chp
generates
power stations (e.g. natural gas) then a CO2 reduction of up
to 30% would be obtained for the energy produced by the
chp unit in accordance with Figure 1.1 above. For a given
site, the chp unit will not be perfectly matched to the heat
and electricity demands and boilers and the grid supply
will be needed to supplement its output. The CO2 reduction
for a typical site is therefore normally lower than 30%.
However, there is a secondary benefit from installing gasfired chp in the UK at present, which arises from displacing
coal-fired power generation that has about double the CO2
emissions of gas-fired power stations.
If the chp plant uses renewable fuels then further emissions
savings are possible allowing a site to achieve zero carbon
in operation.
The methodology for calculating CO2 reductions is
discussed further in section 6.2.
1.3.3
Security of electricity supply
The third reason for considering chp is to enhance the
security of electricity supply at the site. It is possible to
design chp systems to operate in ‘island’ mode, independent
of the public supply, and in some cases this will provide an
additional advantage for chp. However, chp units are not
equivalent to standby power generation as typically
provided by diesel generators, and they are less able to
accept sudden load changes. They will require regular
maintenance so will not always be available to operate and
may be sized to meet the heat load rather than the electrical
demand. A specific design to improve security of supply
would therefore need to consider a larger number of smaller
units to maximise availability, a higher total capacity or a
load shedding system to enable the site load to be controlled
to a level that the chp units can supply. Finally, if there are
times when the chp units are scheduled to be turned off
(e.g. at night) the start-up times need to be considered as
gas engines will take longer to start and reach full-load than
diesel-powered standby generators. The chp units can only
be started when supporting systems are also in operation,
e.g. ventilation and circulation pumps, heat rejection
capacity and gas fuel supply.
Maintenance costs for the chp unit need to be taken into
account. chp suppliers offer finance schemes that can
deliver savings without capital investment.
1.3.4
The efficiency of the boilers may change as a result of their
operation only in peak periods and the energy prices
charged for electricity and gas may also change as a result of
the different demand profiles.
As a recognition of the environmental benefits and energy
saving potential of chp, the UK Government has encouraged
chp through various mechanisms. These incentives are
discussed further in section 7 but are subject to change and
it will be necessary to check the latest position on the
relevant website.
1.3.2
Reduced CO2 emissions
systems reduce CO2 emissions as a result of their
improved energy efficiency. The CO2 emissions at the site
will increase as more fuel is consumed but this is more than
offset by the reduced CO2 emissions at power stations as
less electricity needs to be produced for the national grid
supply. The net reduction in CO2 emissions is thus
dependent on the CO2 emissions factors for the fuel for the
chp and boilers and for the electricity displaced by the chp.
If the same fuel emissions factor is assumed for chp and
chp
Government policy and financial
incentives
Local government planning policies are increasingly
requiring new buildings to adopt low and zero carbon
technologies beyond that required by the Building
Regulations for England and Wales*. In many cases chp
systems are an important component of the policy and the
interconnection of buildings to form district heating
networks, which then make chp systems more viable, is
also a key part of energy planning policies in some cities.
* Requirements may differ in Scotland and Northern Ireland.
Combined heat and power for buildings
Boiler replacement and district heating
——
is often considered in the context of replacement of
boilers. In some sites this leads to a review of whether the
heating system should be centralised or decentralised, i.e.
whether district heating should be retained, abandoned or
introduced. chp can be supplied at a range of sizes but is
generally more efficient at a larger scale, and its introduc­
tion at a time when boilers are being replaced provides an
opportunity to design the plant room to incorporate chp.
Part 2 (sections 8 to 12) provides guidance on each
aspect of implementation of a typical chp project
from feasibility study through design, specifications,
procurement, commissioning and operation and
maintenance.
——
Part 3 (section 13) provides lessons learned from
practical applications.
1.3.5
chp
1.3.6
CHP and renewable energy
There are a number of ways in which renewable fuels can
be used in conjunction with chp. The renewable fuels are
generally derived from biomass and as such are limited by
available land area. It is important therefore to maximise
the availability of this limited renewable fuel by using it in
the most efficient manner through chp.
1.4
Scope of AM12
1.4.1
Scale
A number of Government regulations impact on chp within
the UK and section 7 provides an overview of the legislation
current at the time of publication. Regulations change
frequently therefore it is essential that the reader checks
the current status of Government regulations or seeks
advice from the Combined Heat and Power Association
(CHPA) (http://www.chpa.co.uk).
Appendices provide conversion factors and a glossary of
terms.
1.4.4
Exclusions
Although district heating and cooling systems are included
in section 5, this is mainly in relation to the sizing and
operation of the chp system. More detailed guidance is
available on district heating design in other publications.
systems can range in size from 1 kW to hundreds of
MW of electrical generation. AM12 is intended to provide
information directed towards chp used to supply buildings
and so the emphasis is on smaller packaged chp units of
1 MWe or less, typically using reciprocating engines. A
section on district heating has been included, which
describes some of the differences that might arise for largerscale chp systems.
The scope of the manual also refers to, but excludes detail
of:
chp
——
prediction of energy usage patterns
——
building energy management systems (bems)
design
——
energy audits, and monitoring and targeting (m&t)
methods
Smaller-scale chp systems below 50 kWe tend to be preengineered as complete packages with controls and in some
cases thermal stores. For these types of systems, information
should be sought from suppliers as some of the information
in this manual may be less relevant.
——
other energy saving measures
——
other means of providing heat and/or power
——
uninterruptible power supplies (ups) and standby
generation.
1.4.2
A number of these are covered in other CIBSE publications,
see references.
Applications
This manual is intended to provide advice for designers of
systems in both new and existing buildings of all types
and scales. It is intended to assist the designer of the
building services for these buildings and does not attempt
to provide advice on how to design the chp unit itself. The
emphasis is on how chp can best be integrated into a
building’s engineered systems and how to evaluate the
operating cost and environmental benefits. In some cases,
the building heating system will need to be modified to
maximise the chp benefits and the manual also provides
information on the nature of these desirable changes.
chp
1.4.3
Organisation of the manual
Following this introduction, the remainder of AM12 is
divided into three parts:
——
Part 1 (sections 2 to 7) deals with chp technologies
and their application
1.5
Purpose of AM12
This manual is intended to be read by anyone concerned
with energy matters in buildings: building services
engineers, energy efficiency officers, energy managers,
consultants and designers.
The aim of the manual is to give the reader sufficient
background information and direction to promote, install
and manage successful chp installations to supply both new
and existing buildings. The manual aims to incorporate
experience gained and to describe best practice so as to
enable new installations to benefit from the lessons of the
past.
Some sections of the manual may also be relevant to
architects, planners and energy policy makers seeking to
deliver a lower carbon future.
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Part 1: Technologies, applications and regulations
5
Part 1: Technologies, applications and regulations
2
CHP and energy centres
(fossil fuel)
Key points:
units less than 1 MWe output are normally supplied as
a packaged unit within an acoustic enclosure. The enclosure
requires a ventilation system to provide combustion air and
to provide cooling to remove heat lost from the engine. In
some cases the heat in the ventilation air can be used
directly or indirectly but in most cases it is dissipated.
chp
——
Spark-ignition gas-engines are the predominant
prime-mover technology for CHP supplying
buildings.
——
CHP can be classified as micro (domestic scale
<2 kWe), mini or small-scale (<50 kWe) and
above 50 kWe.
——
Above about 200 kWe, most engines are turbocharged, which improves their electrical efficiency.
——
Heat can be recovered from the engine jacket, oil
cooler and exhaust gases. Additional heat can be
recovered at lower temperature by a condensing
exhaust heat exchanger, from the intercooler heat
rejection and from the ventilation air of the
acoustic enclosure.
chp systems can be characterised by both capacity and type.
The main characteristic of chp systems is the type of prime-
mover and common systems, based on fossil fuels, are
described below. Section 3 discusses chp systems that use
renewable fuels.
2.1
It is normal practice for the heat recovery system to be a
closed circuit as part of the chp package with a single
interface to the building heating system via a plate heat
exchanger.
Spark-ignition gas engines
(50 kWe to 10 MWe)
The most common type of chp is based on spark-ignition
gas engines. These are either purpose-designed for
stationary applications or derived from engines used in
vehicles. The size ranges from 50 kWe to around 10 MWe,
with a typical life of 10–15 years.
Gas engines are available in naturally aspirated and turbocharged types. Turbocharging is normally available in
engines larger than 200 kWe and typically improves
electrical efficiency from around 31% to 33% (gcv).
The main components of a chp unit based on spark-ignition
gas engine technology are:
——
prime mover: an engine to drive the generator
——
fuel system: providing gas at appropriate pressure
——
generator: to produce electricity, which is fed into
the building’s power distribution system
——
heat recovery system: to recover usable heat from the
engine
——
cooling system: to dissipate heat rejected from the
engine that cannot be used
——
combustion and ventilation air systems: to supply fresh
air to, and carry radiated and convected lost heat
away from, the engine
——
exhaust gas silencer and chimney: to safely dissipate
exhaust gases without causing a nuisance
——
control system: to maintain safe and efficient
operation, to synchronise with the public supply
and to provide a remote monitoring facility
——
enclosure: to achieve physical and environmental
protection for the engine and operators, and to
reduce noise.
The main components are shown in Figure 2.1.
Engine
exhaust
gases
In naturally aspirated engines, air is drawn into the engine
at atmospheric pressure without pre-compression. The
engine geometry and ambient conditions limit the air–fuel
mixture and, in high ambient temperature conditions,
engine performance is likely to be reduced.
In turbocharged engines, air for combustion (commonly
called ‘charge air’) is received via a compressor, driven by a
turbine in the exhaust gas stream. The resulting increased
air mass flow rate enables the engine power output to be
increased for a given engine frame size. A disadvantage of
this arrangement is that compression of the charge air
increases its temperature, and to avoid undesirable
combustion effects the air must be cooled in an intercooler
or after-cooler. The heat liberated from the intercooler may
be recovered to the building heating systems (if these are
designed to operate at a sufficiently low temperature) or
rejected to atmosphere. In conditions of high ambient
temperature the plant rating may be reduced depending on
the design and capacity of the intercooler cooling system.
Engine
exhaust
Gas or oil
Control
panel
Engine
Generator
Hot
water
supply
Exhaust heat
exchanger
Engine heat
exchanger
Cool return water
Figure 2.1 Principal components of a gas-engine chp unit (reproduced
from GPG388 (Carbon Trust, 2004) by permission of the Carbon Trust)
Combined heat and power for buildings
There are two main types of generator: synchronous and
asynchronous. Synchronous generators rotate at a governed
fixed speed, which is usually an integer multiple of the
supply system frequency, e.g. 1000, 1500 or 3000 r/min for a
50 Hz system. The generator maintains its own frequency
standard and can thus continue to run at the desired
frequency when isolated from the public supply.
Synchronisation with the main supply requires special
control and instrumentation equipment to match frequency,
phase and voltage on connection. Asynchronous generators
do not have the ability to maintain a frequency standard
but rely on the mains supply frequency to monitor and
maintain the desired generated frequency. This means that
operation in isolation as a standby mode is not possible.
The majority of chp schemes will use synchronous gener­
ators. Generators are typically low voltage up to 1 MWe and
are normally high voltage above 3 MWe. Between 1 MWe
and 3 MWe either are possible, depending on the relative
costs of generator, transformer and switchgear, and
maintenance costs.
Figure 2.2 illustrates a typical gas engine
acoustic enclosure doors open.
2.2
chp
unit with
Mini or small-scale CHP
(<50 kWe)
In recent years a new generation of small-scale chp systems
(<50 kWe) have been introduced. These have been designed
specifically to provide longer running hours between
servicing (10 000 hours is typical) and a sophisticated
control system. Much of this manual is directly applicable
to this type of chp. However, as the units tend to be
standardised, advice should be sought from the suppliers at
an early stage of design.
Typical applications will be in smaller commercial and
residential buildings. Figures 2.3 and 2.4 show examples of
this system type.
2.3
Micro gas turbine CHP
This type of chp is based around small-scale gas turbines,
which have been introduced in the last 10 years. Typically
such turbines produce an electrical output of about
100 kWe. Micro-turbines differ from larger-scale gas
turbines by running at high speed and a dc generator is
used together with an inverter. Their main benefit is that
maintenance intervals are much longer than for recipro­
cating engines, so availability is higher and maintenance
costs lower. However electrical efficiency is generally lower
than the equivalent sized spark-ignition gas engine chp.
2.4
Individual dwelling CHP
(< 2 kWe)
systems suitable for use in individual dwellings have
been the subject of considerable research and development
over the last 10 years. They offer the potential for obtaining
the benefits of chp without the need for, or cost of, district
heating and may offer a replacement for the domestic gas
boiler. Most systems include an auxiliary burner to enable
peak heating demands to be met.
chp
There are two principal types:
Figure 2.2 A typical gas engine chp unit with acoustic enclosure doors
open (photo courtesy of EnerG Combined Power Ltd)
Figure 2.3 Mini-chp system (photo courtesy of SAV Systems and
EC Power)
——
Stirling engine: this is a reciprocating engine but
with the heat energy provided through an external
heat exchanger. Its electrical efficiency is generally
much lower than the larger spark-ignition
reciprocating engines, however it can be well suited
to the small outputs of an individual dwelling chp
system. It will typically have a 1 kWe electricity
output.
——
Fuel cell: these utilise a chemical reaction to
generate electricity, rather than a combustion
process. The fuel cell offers the potential for a
higher electrical efficiency than other types of chp
and hence lower CO2 emissions and cost savings.
The high electrical efficiency also means that
Figure 2.4 Mini-chp system (photo courtesy of Baxi-SenerTec UK)
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operation will be viable even with only partial heat
recovery, and running hours can be extended to
improve operational savings. As a result of the high
efficiency the power output will be typically 2 kW,
sufficient to provide heating for the dwelling. The
output of fuel cells can be modulated to meet
variable energy demands, which is important in
individual dwellings where demands are highly
variable. The main challenges to development
include reducing initial cost, prolonging the life of
the fuel cell stack and reducing the size of the
system. Fuel cells are considered in more detail in
section 2.6.
At present, domestic chp is still in the early stages of
development and more experience is needed to establish
performance and the environmental and cost benefits. The
Carbon Trust has conducted early field trials of a number of
different types of units (Carbon Trust, 2011). The main
market is expected to be in larger detached houses, as in
higher density housing district heating and larger-scale
chp is likely to be preferred on efficiency or cost grounds.
2.5
2.5.1
Larger-scale CHP
Gas turbines
Gas turbines are available in the range 500 kWe to over
200 MWe, although the choice of models below 1000 kWe is
very limited. They are most commonly used in industrial
chp applications of 2.5 MWe and above, where the high
grade heat in the exhaust can be utilised to generate process
steam, or in conjunction with a waste heat boiler and a
steam turbine to generate additional electrical power
(known as a combined cycle gas turbine).
The electrical efficiency of gas turbines in open cycle (i.e.
without a steam turbine) is lower than reciprocating
engines for gas turbines of 500 to 1500 kWe. Larger turbines
have higher electrical efficiencies but still do not compare
well with spark-ignition gas engines when in open cycle
mode below about 5 MWe. In combined cycle applications
the electrical efficiency can be over 50% but the complexity
of this type of plant means that the scale required is typically
over 50 MWe.
Gas turbines require higher pressure gas than sparkignition gas engines, so a gas compressor is required. The
electricity used for the compressor is significant and so
sites with access to gas mains at higher pressure will be
more effective.
When considering chp, gas turbines have the advantage of
producing most of the available heat as high temperature
exhaust gas, which may be used to provide high temperature
hot water or steam. The firing of additional fuel into the
exhaust (supplementary or auxiliary firing) may be used to
produce additional heat at higher combustion efficiency
than conventional boilers.
There are several examples of gas turbine chp systems
supplying buildings, especially in hospitals or universities
where a steam distribution system exists. Some of these use
steam to supply absorption chillers.
7
2.5.2
Dual-fuel reciprocating engines
These engines use the compression-ignition principle as
used most commonly with diesel engines in vehicles. As
gas has been cheaper than oil for some time engines have
been developed where gas provides the main fuel but a
small amount of oil is also injected so that ignition takes
place when the cylinder is compressed. The advantage is a
higher electrical efficiency at the expense of a small
additional fuel cost and higher emissions of NOx, SOx and
particulates as a result of the use of oil.
An additional advantage is that it can also run on oil alone
should that prove financially beneficial (e.g. if an inter­
ruptible gas contract is used). The oil used may also be
derived from renewable sources.
There are a few examples of this type of chp engine but
mainly for larger district heating schemes (e.g. Citigen, in
the City of London, and Southampton). On the continent,
larger-scale spark-ignition engines are more common than
dual-fuel engines.
2.6
Fuel cells
A potential alternative to reciprocating engines and gas
turbines is the fuel cell. This is an electrochemical device
comprising an anode and a cathode separated by an
electrolyte. Fuel (hydrogen) is supplied continuously to the
anode and oxygen to the cathode. The chemical reaction
creates a voltage difference. Each cell generates about 1 volt
so a number of cells are combined to form a cell stack. As
hydrogen is not readily available, a reforming stage is
required (either external or internal to the fuel cell) to
convert a fuel such as natural gas to provide the hydrogenrich fuel source.
Fuel cells have been developed both for stationary electricity
generation and also for vehicular applications. Typical sizes
currently available or in development as chp units range
from domestic scale 1 kWe units to 500 kWe. There are a
number of different types of fuel cell, which are characterised
by the electrolyte used.
The most common types for chp applications are:
——
Proton exchange membrane fuel cell (pemfc): This
operates at a low temperature of 80 °C and requires
higher grade hydrogen. Also known as solid
polymer fuel cells (spfc).
——
Phosphoric acid fuel cell (pafc): This type is closest to
being generally commercially available. It is less
sensitive to fuel quality.
——
Molten carbonate fuel cell (mcfc): The electrolyte is
typically a mix of lithium carbonate and potassium
carbonate. This is a high temperature fuel cell
operating at 650 °C, which allows internal
reformation of the fuel.
——
Solid oxide fuel cell (sofc): The electrolyte is a solid
ceramic and the operating temperature is 1000 °C.
This type has the potential for high electrical
efficiencies. It is also the basis for a domestic scale
fuel cell chp presently under development.
——
Alkaline fuel cells (afc): Fuel cells of this type use
hydrogen as a fuel and were originally developed
for space exploration applications. These are
Combined heat and power for buildings
unlikely to be used unless a hydrogen economy is
developed.
——
Direct methanol fuel cells (dmfc): These have been
developed for vehicular applications.
Fuel cells offer the potential for higher electrical efficiencies
than the equivalent sized reciprocating engines with figures
of 35% to 55% (gcv basis) quoted. This would result in
lower CO2 emissions. In addition, as the combustion
process is avoided emissions of nitrogen oxides are much
lower.
Although a few demonstration projects exist in the UK,
fuel cell chp has a much higher capital cost than
conventional gas-engines and the life expected from the
fuel stack is also limited to around 40 000 hours.
Fuel cells should be considered for applications where
continuous running can be expected as this will maximise
the stack life.
chiller utilisation is maximised and frequent start/stops are
avoided. The absorption chiller is normally sized so that its
heat requirement does not exceed the chp heat output as
otherwise boiler heat would be used for the absorption
chiller, which is less efficient than using electric chillers. If
there is no other heat demand in the summer cooling period
then the absorption chiller heat requirement will need to
match the chp heat output closely to avoid heat rejection or
part-load operation.
Absorption and adsorption chillers are normally only
considered for cooling loads greater than 250 kW.
The environmental benefits from tri-generation are
discussed in section 6.3.
3
Renewable energy
and CHP
Fuel cells generate dc electricity and so an inverter is
normally used to produce ac for parallel operation with the
grid supply.
Key points:
——
The temperature of heat available is typically 80 °C for
pemcs but higher temperatures are available from the sofc
and mcfc types.
Spark-ignition gas-engines are the predominant
type of CHP for buildings
——
CHP is a concept that can be applied to any
thermal electricity generation process.
——
CHP using renewable fuels: solid biomass, liquid
biofuels and biogas are feasible and there are a
wide range of technologies in use and under
development.
——
Further information is provided in BSRIA BG 9/2003: Fuel
cell technology: The scope for building services applications
(BSRIA, 2003).
If there is good heat utilisation over the year, CHP
should result in a more efficient use of renewable
biofuel which will always be a limited and
valuable resource .
——
Combining CHP and solar thermal is normally not
appropriate.
2.7
——
CHP and photovoltaics or wind are generally
compatible.
——
Gas-fired CHP and a biomass boiler may be
integrated but can be difficult to control
automatically, especially for small-scale systems.
——
CHP and heat pumps compete for the same base
heat load but could be complementary in the
future as marginal electricity grid emissions fall
and heat pumps become more viable.
Further technical developments include the use of hybrid
systems combining a high temperature fuel cell (mcfc and
sofc) with a micro-turbine to improve power efficiencies
further.
Combined cooling, heating and
power (tri-generation)
A chp unit can be seen as a source of low cost and low
carbon heat. This heat is normally used to displace boilers
but can also be used as heat source for an absorption or
adsorption chiller.
There are two basic types of absorption chiller: single effect
and double effect. Single effect chillers can use low
temperature hot water and have cops of around 0.7 and the
double effect chillers use higher temperature hot water,
steam or exhaust gases from the chp and cops are around
1.3. Units are also available which can use multiple heat
sources. The cops of such units are much less than those of
vapour compression chillers so it is important that the
carbon content of the heat from the chp is low and that the
cost of heat production is low. The lower cops also mean
that about twice as much heat needs to be rejected from the
condenser circuit.
The adsorption chiller uses a silica gel as the refrigerant,
which is alternately heated and cooled. This type of chiller
offers lower maintenance costs and higher efficiencies
when operating with lower temperature heat sources.
It would normally be the case that the absorption chiller is
sized to supply the base cooling load with vapour compres­
sion chillers used for peak periods so that the chp/absorption
3.1
Biomass CHP using combustion
of solid biomass fuel
The renewable fuel most likely to be considered for chp at
present is wood chips or wood pellets. These have found a
growing market for small boilers for heating. Wood pellets
are compacted small wood chips and sawdust. They have a
higher price than wood chips but have a lower moisture
content and hence a higher calorific value. They are also
denser and easier to transport and store.
The twin benefits of using biomass as a fuel for chp is that
the energy is produced from a renewable source and also
the energy in the fuel is used in the most efficient way. This
is important in the context of biomass as the amount of
biomass is limited in any given area and there will always
be competition for the land area needed for food production
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or amenity space. The main drawback of biomass chp is the
much higher capital cost for the chp plant compared to gasfired plant, especially at a small scale and limited operational
experience.
There are a number of types of chp that use conventional
combustion of the fuel. These are described below.
3.1.1
Steam turbines
Conventional steam turbine technology can be used for
biomass chp with an electrical output of greater than
2 MWe but are most suitable for systems over 10 MWe. It
offers robust, well proven technology, with a very good
part-load performance. However, at a small-scale, lower
electrical efficiencies (20–25%) along with high capital,
operating and maintenance costs are some of the
disadvantages. This option is best considered in the context
of a large district heating system. The steam turbine can be
designed either as an extraction condensing unit or a backpressure turbine. The former will be of benefit if there are
significant times of the year when the heat demand is lower
than the chp output and there are financial benefits from
maintaining electrical output.
3.1.2
Air turbine
Systems of this type use a micro-turbine supplied with air
heated from the combustion of the biomass. Additional
heat recovery is obtained from the exhaust gases rejected by
the heat exchanger, which heats the air for the turbine. The
benefit of this approach is that all of the components are
well proven. The disadvantage is that the micro-turbine is
relatively inefficient as the air temperature that can be
supplied is limited. The electrical efficiency is around 20%,
thermal efficiency about 50%.
3.1.3
Organic Rankine cycle (ORC)
Biomass chp systems based on orc technology are now
commercially available from a few manufacturers in Europe
but there is limited experience in the UK. These systems
use an organic working fluid with a lower boiling point
than water/steam, such as freon or an organic solvent. This
allows the system to work more efficiently at lower
temperatures and pressures, and at smaller scales more
suited to biomass fuel. Electrical outputs are typically in
the range 200 kWe to 2.0 MWe, with thermal to electrical
output typically around 5:1. The main drawback is the
relatively high capital cost.
3.1.4
9
in a modified gas engine to produce electricity and heat. It
is important to have a uniform product entering the gasifier
because carry-over of tars in the syngas can be a problem.
However the newer generation of gasifiers appear to have
made progress in overcoming this problem. Such systems
are supplied as fully integrated packaged units with the
gasifier and chp system running from the same control
system which can then be integrated into the building’s
bms. Gasification brings higher electrical efficiencies due to
gas engine technology having advantages over steam based
systems.
There is limited experience of wood gasifiers at a small
scale but there are now a few applications in the UK of
larger schemes of 1 to 5 MWe capacity. In Europe there are
several wood gasifiers of less than 1 MW capacity that have
been running successfully for some years, and this
technology is now starting to become available in the UK.
Gasifiers are most reliable in continuous operation so
proper consideration should be given to sizing and the use
of thermal stores to modulate the heat use in building
schemes. Capital costs remain high compared to bio-liquid
chp, but due to the relatively lower cost of solid biomass
against bio-liquid fuel, the returns in both operation and
investment can be attractive, especially where Government
incentives apply.
The use of solid biomass is generally seen as a more
sustainable solution as woodland is often on land that is
unsuitable for large-scale agriculture thus avoiding com­
petition with food production. However the sustainability
of any biomass resource needs to be carefully considered in
the light of competing uses and scale of demand (CCC,
2011).
The UK Government is currently promoting the sustainable
management of woodlands through various grant schemes,
leading to more fuel sources becoming available.
Gasification of biomass and use in chp can provide a more
efficient use of biomass in terms of CO2 saved per unit of
biomass fuel provided the heat produced is well utilised.
Wood chip size and moisture content are likely to be the
most important aspects of uniformity but gasifier
dimensions and internal design are also critical design
elements.
Stirling engine
The Stirling engine operates with an external heat source
so the products of combustion are separated from the
working fluid. Some small-scale biomass chp systems are
now commercially available. The electrical efficiency is
relatively low so a building with a high heat demand
relative to electrical demand would be preferred.
3.2
Biogas CHP using gasification
of solid biomass fuel
Gasification systems turn biomass material into a fuel
known as synthesis gas or syngas. This gas is then burned
Figure 3.1 Biomass gasifier used for chp (courtesy of the University of
East Anglia)
Combined heat and power for buildings
Tar problems can be minimised by operating at the
appropriate temperatures, which will vary depending on
the type of plant.
approved by the Office of the Gas and Electricity Markets
(Ofgem).
The liquid fuels currently available for chp are:
The production of biochar from the gasifier/pyrolysis plant
is potentially beneficial to the economics and overall
sustainability of the process.
——
100% biodiesel
——
pure vegetable oil, e.g. rape seed oil
3.3
——
bioethanol
——
generator fuel derived from waste oils from the food
industry.
Liquid biofuel CHP
Liquid biofuels (also known as ‘bioliquids’) are likely to be
well suited to chp engine applications as some may have
been developed for vehicle applications. As a result, higher
electrical efficiencies can be achieved compared to other
renewable chp technologies. The main concerns with this
technology are as follows:
——
——
The land taken for the production of the feedstock
for bioliquids may compete with food crops.
However, in many circumstances bioliquids are
produced from crops that are grown within the
practice of sustainable agriculture as part of
a standard crop rotation.
Where there is a change of land use to grow crops
for fuel the different CO2 impacts of the change of
land use need to be considered.
——
There may be a more beneficial application for the
fuel than use in chp for buildings.
——
There is limited long-term operating experience
with engines operating on these fuels.
——
The price of the fuel is relatively high.
——
The maintenance costs are higher.
——
NOx emissions are higher than for natural gas
engines, but can be mitigated through using higher
flue stacks.
——
The energy used for processing some fuels can be
high increasing the carbon content.
——
There is a need to store the fuel on-site and in some
cases keep its temperature above a minimum level.
Set against these disadvantages is the potential to achieve
higher chp electrical efficiency and also to receive financial
incentives such as Renewable Obligation Certificates
(ROCs). To receive ROCs the chp installation needs to be
Figure 3.2 Rapeseed oil energy centre (courtesy of LowC Communities
Ltd)
Information on the CO2 content (and other greenhouse
gases) of some bioliquids used for transport applications
can be obtained from the Department for Environment,
Food and Rural Affairs (DEFRA, 2011). However it is
recommended that fuel-specific factors are obtained from
other sources or from suppliers, as knowledge in this area is
still developing.
3.4
Energy from waste
3.4.1
Large-scale combustion and
steam turbines
The most established waste-to-energy technology is mass
combustion (incineration) to raise steam for a steam turbine
generator. Typically these are large-scale plants handling
over 100 000 tonnes p.a. of waste. The steam turbine can be
used as a chp plant either with steam extraction or as a
back-pressure turbine if there is sufficient base-load heat
demand. Typically such plants supply large district heating
schemes, such as those in Sheffield (see Figure 3.3) and
Nottingham.
3.4.2
Landfill gas
Landfill gas is produced when waste that has been landfilled
releases a methane rich gas. This can be used as fuel in gas
engines to produce electricity and in this form has been one
of the largest contributors of renewable electricity in recent
years. It would be possible to obtain heat from the gas
engine in a similar way to conventional gas engines and
supply a district heating network. An alternative approach
would be to pipe the landfill gas to a location closer to the
buildings and site the gas engine at that location.
Figure 3.3 The Sheffield energy from waste plant, which supplies the
city’s district heating network (courtesy of Veolia Environmental
Services (UK) plc)
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3.4.3
Anaerobic digestion (AD)
This process is used to treat organic wastes to produce a
biogas that can be used directly in spark-ignition gas
engines to produce electricity with some of the heat from
the engine used to drive the process. There is the potential
for additional heat recovery, which could be used to supply
a district heating scheme. The digestate produced as a
byproduct from the process can be used as a liquid fertiliser.
The volumes of waste and digestate are significant, so to
reduce transport costs the ad plants are normally sited in
rural areas close to the source of farm wastes. In the future
with food waste segregation ad plants may become more
widespread thereby providing opportunities for heat
recovery.
3.4.4
Advanced thermal treatment of waste
3.4.4.1
Gasification
This process can be applied to general waste streams and
involves heating the waste with restricted oxygen levels
which breaks down the material and releases a syngas, part
of which is used to provide heating for the process. The
surplus heat is used for the production of steam and a steam
turbine generator used for electricity production. This
provides the potential for the plant to operate in chp mode
to supply a district heating network. This technology is
relatively new, a recent example being at Newport, Isle of
Wight.
3.4.4.2
Pyrolysis
The pyrolysis process involves heating the waste in the
absence of oxygen and again a syngas can be produced.
This type of plant can be smaller-scale and the syngas could
be used with a gas engine with heat recovery for supplying
a district heating system. Pyrolysis processes can also be
designed to produce bio-oil. The solid byproduct biochar is
of interest as a soil conditioner and for carbon sequestration.
These plants can be smaller-scale and could therefore be
more easily integrated with urban district heating. An
example is the plant at Avonmouth, Somerset.
3.5
Biomethane injection
A further option for the future use of renewable fuels is the
production of biogas and conversion to biomethane of a
suitable quality to inject into the national gas grid. By this
means, chp can continue to use the national gas supply and
operate at high efficiencies but with a progressively
decreasing carbon content and an increasing renewable
fuel content. A few examples of biomethane injection based
on anaerobic digestion processes have been implemented
in the UK and a major study for National Grid (National
Grid, 2009) concluded that there was significant potential
from this resource, equivalent to between 15% and 48% of
the residential gas demand.
3.6
Integration of CHP with
renewable energy sources
A chp system is primarily designed to produce low carbon
heat. The best economic case will be obtained when the chp
unit operates for the maximum number of hours in the
11
year. In the summer period, the heat available from the chp
is likely to be greater than the heat demand so surplus low
carbon heat is available, assuming the chp is sized to supply
some of the space heating demand. chp is unlikely to be
sized to meet the peak heating demand so the use of boilers
in peak winter conditions would be expected. The chp unit
may not operate at night due to the low electricity price
although correct sizing of the unit and the use of thermal
stores can be used to meet any heat demand at night.
The above operating characteristics mean that integration
with other renewable energy sources needs to be carefully
considered to maximise the opportunities of the site:
——
If there is surplus heat in summer, solar thermal
systems will not be appropriate with chp as
currently they would offer only a small CO2 saving
compared to operating the chp plant. However, in
the future this could change as electricity emission
factors fall and CO2 content of heat from chp rises.
Using solar thermal with chp will reduce the
operating hours of the chp unit, which would
reduce its economic advantage.
——
If there is a need for peak heat demands to be met
from boilers in winter then biomass boilers could
have a role; a thermal store is recommended in this
case.
Solar photovoltaic panels will generate most in summer
when the chp output is lower and could therefore
complement chp operation if the site electricity demand is
relatively constant over the year. Small-scale wind would be
similarly compatible with chp but is likely to generate more
electricity in winter.
3.7
Integration of CHP with
heat pumps
Heat pumps are another form of low carbon heat with very
similar characteristics to chp. Whereas a chp plant sacrifices
electrical efficiency to produce heat at a useful temperature,
a heat pump requires electricity to raise the temperature of
the heat drawn from ambient sources.
As chp and heat pumps are a higher capital cost than
boilers, both will typically be sized to supply base heat load
and achieve long running hours and therefore are unlikely
to be compatible technologies.
Heat pumps are most suited to low temperature applications
such as underfloor heating and fresh air heating as the
coefficient of performance is related to the temperature at
which the heat is supplied. Heat pumps are also more
efficient when using elevated temperature heat sources, for
example heat rejection from cooling systems for buildings
where there is domestic hot water heating and a cooling
demand in summer.
is more suited to higher temperature applications
including domestic hot water heating and district heating
where a higher flow temperature reduces the cost of the
district heating network.
chp
With the current electricity emission factors, typically heat
from chp has a lower carbon content than heat from heat
pumps (see section 6, Figure 6.2). However in the future,
when the electricity system has reduced its carbon
Combined heat and power for buildings
4
CHP for individual buildings
Key points:
——
Use a load duration curve to study the demand
profiles.
——
Develop an operating model to simulate CHP
energy flows over the year with the appropriate
level of complexity.
——
Analyse a range of CHP sizes against a number of
economic and environmental parameters to
establish an optimum size.
——
Consider the benefits of thermal storage.
4.1
Introduction
The economic and environmental benefits of a chp scheme,
whether for new or existing buildings, are determined by a
number of factors:
——
building heat and power demand profiles
——
fuel and electricity tariffs
——
chp
plant rating and efficiencies
——
chp
maintenance costs
——
chp
plant running hours.
Although the above factors are shown as distinct items,
they are all interlinked. For the successful application of
any chp scheme, all the factors must be assessed together.
For any application, there may be a broad range of possible
solutions but only a limited number of optimum solutions.
In this section, the fundamental factors and how they
interact are examined.
This section discusses chp for individual buildings
although much of the information is also relevant for
district heating schemes connecting a number of buildings
together. The application of chp to district heating is
discussed in more detail in section 5.
For a detailed discussion of environmental benefits, see
section 6.
4.2
Building heating, cooling and
electrical demands
The application of a chp scheme in a building depends
initially upon the presence of heat and power demands and
the extent to which they are compatible with, or close to,
the optimum duty cycle of any prospective chp plant.
In existing buildings, heat and power demands are
substantially predetermined although they may be altered
by changing building occupancy, improving building
thermal efficiency, or adding new equipment or plant. The
chp designer may have only limited scope for altering peak
demands or profiles. Demand profiles for new buildings
must be assumed from design data or other means.
Both existing and new building heat and power demand
profiles may be modified by the choice of plant. Examples
include:
——
hws calorifiers utilising chp heat, rather than
electric heating at point of use
——
absorption chilling plant utilising chp heat rather
than power to produce the desired chilling.
chp units will be most effective in buildings where the ratio
of heat demand to power demand is steady throughout the
day between 1.3:1 and 2.0:1. However, even if these
conditions do not apply chp may still be viable — the main
factor influencing feasibility is the operating hours of the
chp plant. The operating hours may be improved by
connecting together buildings with different demand
patterns, e.g. a school or office and residential buildings or
by the use of a correctly sized thermal store.
Heat demand profiles can be visualised in a number of
ways. Particularly useful is the load duration curve, which
3000
Heat demand / kW
In the longer term, the marginal electricity emission factors
may vary significantly by season, time of day and as a result
of the output of wind farms. In this situation a hybrid
system using both chp and heat pumps combined with
significant heat storage could provide an optimum solution
whilst also contributing to the control of the national grid.
Determination of the heat and power demands will be made
by studying graphically presented demand load data.
Whereas conventional heating and power plant ratings are
set by maximum projected demands to cover seasonal
peaks, chp plant rating selection is affected by minimum
demands and seasonal and diurnal profiles. Consequently,
the building services engineer will need to be able to
establish the instantaneous values of heat and power usage
during the projected operating period of the chp plant. In
practice, half-hourly or hourly data may be used. Using
averaged data for a whole day or week may hide too many
variations in demand level to be a safe method of assessing
profiles, particularly for the final analysis and the choice of
chp plant.
2500
2000
1500
1000
500
0
0
249 497 745 993 1241 1489 1737 1985 2233 2481 2729 2977
Hours
Figure 4.1 Load duration curve for an office building
Percentage of total heat
emissions, the two technologies will become similar in
performance.
120
100
80
60
40
20
0
–20
0
500
1000
1500
2000
CHP heat input rate / kW
2500
Figure 4.2 Proportion of load supplied against chp capacity
3000
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takes the demand in each hour and plots this in descending
order. This enables the annual demand that can be met
from a given chp capacity to be determined (see Figures 4.1
and 4.2). For this example 80% of the annual demand can
be supplied with a chp unit sized at about 30% of the peak
demand.
——
A simpler approach would be to use a 24-hour
model for a typical day in each month (or a typical
weekday and weekend day in each month). However
the daily profiles still need to be determined for
each month. There is a loss of accuracy as the
variation of demand within each month is not
captured.
4.3
——
A further option is to assume a day/night split of
demand and calculate averages for each month.
This is clearly a simplification as the 24-hour
variation in demand is not modelled. This may not
be too much of a disadvantage if a thermal store is
included in the scheme which is sufficiently large
to result in a smoothed profile.
——
Another approach is to divide the demand profile
into a series of slices or ‘bins’ and calculate the chp
operation for each of these slices before summing
for the year. The disadvantage of this approach is
that it is not easy to reflect the variations in
electricity and fuel prices that are related to the
time of day or month of the year.
Fuel and electricity tariffs
The operating cost benefit of chp, i.e. the difference between
the cost of power and heat generated by chp plant and the
same power and heat generated conventionally, will depend
on the fuel and electricity prices. Where the electricity
price is relatively high compared to fuel, chp will achieve
high savings, but with low electricity prices and high fuel
prices savings will reduce. The difference between
electricity and gas prices is often referred to as the ‘sparkgap’ or ‘spark spread’. It is important to be aware of the
sensitivity of the economic savings to the relative difference
in energy prices. If both electricity and gas prices rise
together then the saving from chp operation will also
increase. The savings may be negative (losses) on night rate
electricity, particularly if the unit is operating at part load
in this period.
The cost of electricity generated by a gas engine chp
generator will be constant throughout the day, since gas
tariffs are independent of time of day (this is the case for
smaller contracts — larger schemes could obtain gas
contracts with varying prices through the year). The cost of
imported electricity varies through the day for many tariffs.
In the seasonal time of day (stod) tariffs the variation can
be very marked during winter month peak hours.
4.4
Principles of CHP sizing
Once an understanding of the site’s heat and electricity
demand profile has been established the designer is then
faced with the task of deciding on the size of the chp.
There is no straightforward way to size a chp. Some
guidance recommends sizing only to meet the lowest
demand that occurs — the base-load that will result in the
longest running hours and the shortest payback period.
However this is not necessarily the most economically
advantageous approach and certainly would limit the
amount of CO2 savings that could be achieved on a given
site.
The recommendations given below are a more rigorous
approach to the problem and allow both economic and
environmental benefits to be assessed.
4.4.1
Constructing an operating model
It would be normal practice to use a spreadsheet model to
carry out the calculations. This model can be constructed
in a number of ways:
——
The most accurate would be to use an hour by hour
model over a whole year with heat and electricity
demand profiles representing an average year. This
is the recommended approach for new buildings
where dynamic simulation modelling has been
carried out or for existing sites with actual metered
demand data.
Whereas in most engineering calculations it is possible to
make simplifications that result in a conservative or
pessimistic answer, simplifying a chp model generally will
result in a more optimistic result with respect to the chp
operating hours and hence the economic return.
Although developing an hour by hour model is the best
approach (and, in the absence of metered data, demand
profiles can be predicted or modelled assuming typical
occupancy patterns and external temperatures), in some
cases it may be sufficient to use a monthly model,
particularly where the availability of data is limited.
However the night/day split that typically is a function of
both heat demand and electricity price should always be
modelled as the differences in night and day operational
costs and heat demand are normally significant.
The operating model should be able to:
——
determine whether the chp is worth operating
based on the relative fuel and electricity prices in
each time period considered
——
determine the output of the chp to follow the heat
demand or electricity demand taking account of
part-load operation, and hence the chp fuel used
——
establish the heat needed from the peak and standby
boilers and hence the boiler fuel use
——
make allowance for chp downtime for maintenance
——
include any constraints on number of starts
(especially for gas turbines)
——
model the operation of a thermal store
——
determine the net import or export of electricity
and its costs/revenue
——
calculate the operating costs to compare with the
non-chp conventional operating costs.
4.4.2
Evaluating CHP options
Once the operating model has been set up it is necessary to
run a number of cases for a range of chp sizes starting with
a size that just meets the lowest demand (base-load sizing)
and increasing the capacity until say 90% of the annual heat
Combined heat and power for buildings
demand is satisfied by the chp plant. To carry out the
calculations it is necessary to have the following data for
each size of chp unit:
——
capital cost
——
efficiencies
——
maintenance costs
——
minimum turndown ratios
——
impact of number of starts.
the year. There comes a point when the additional
capital cost for a larger size cannot be justified on
the fewer hours of operation. Note that this
economic comparator gives different results to
maximising the irr, which will tend to result in a
smaller chp size that is simply maximising running
hours and meeting baseload demand.
As the chp size increases the CO2 savings will
increase. This is a result of the chp unit delivering
more of the heat demand. However, without a
thermal store, if the chp is too large it will have to
shut down in periods of low demand or reject
surplus heat. Hence there is typically an optimum
size which maximises the running hours and hence
the CO2 savings.
——
It is also necessary to carry out a net present value (npv)
calculation for each option (see section 8.9) and a CO2
emissions reduction calculation (see section 6.2).
The criteria for project evaluation are typically:
——
——
500
maximise the internal rate of return (irr) (or
minimise the payback period) for the project
investment
450
400
maximise the npv of the project investment
350
minimise the net present cost (the negative of npv)
of energy supply to the site.
300
MW·h
——
In addition, clients may also wish to take into account CO2
savings for each option. A value for the CO2 saved can be
included in the economic calculations if desired.
Typical results from such a sizing exercise will examine a
range of chp sizes as in Figures 4.3 to 4.5. Figure 4.3
represents a baseload sizing that maximises the chp plant’s
operating hours and will produce the shortest payback
period. Figure 4.4 shows a large chp installation that meets
much of the winter demand but is oversized for the summer
period when boilers have to be used. The operating hours
are much reduced accordingly. Figure 4.5 shows a chp size
that seeks to minimise the total costs of energy supply for
the site taking account of capital and operating costs. The
size is such that the summer demand can still be supplied
from the chp plant.
Figure 4.6 represents typical results for a chp project and
shows the irr, net present cost and CO2 emissions for a
range of chp sizes.
250
200
50
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 4.3 chp size too small; this will produce good payback for chp
but limited impact on site energy costs
500
450
400
350
300
Boiler heat produced
CHP heat output for
heating MW·h
Total space heating
and DHW demand
250
200
150
100
50
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 4.4 chp size is too large; the chp cannot supply heat in summer
when demand is low
500
450
400
350
300
Boiler heat produced
CHP heat output for
heating MW·h
Total space heating
and DHW demand
250
200
The results show that:
150
——
100
As the chp size increases the npv increases to a
maximum and then falls. There is therefore an
optimum size that maximises npv. This optimum
occurs as a larger chp unit will produce a greater
saving per hour of operation but will have a higher
capital cost and will operate for fewer hours over
Total space heating
and DHW demand
100
MW·h
In general it is better to undersize chp than oversize, as heat
demands are often overestimated and can reduce over time
as a result of energy efficiency improvements.
CHP heat output for
heating MW·h
150
MW·h
Selecting a chp size to provide the shortest payback period
and highest irr may not be the best option in terms of
minimising the total cost of energy supply for the site. This
is because the highest irr will tend to result in a chp sized
to meet the baseload and therefore have the longest
operating hours. A baseload chp will however have least
impact on the site’s energy costs as a whole, taking account
of boiler fuel use. Hence for most clients, minimising the
net present cost for the total site energy demands will be
more appropriate.
Boiler heat produced
50
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 4.5 chp size that may be optimum to minimise life cycle costs of
heat supply
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15
The comparison can result in two optimum points based on
either maximum npv or maximum CO2 savings. To resolve
this issue, two approaches can be taken:
——
the expected trading value through the CRC Energy
Efficiency Scheme or through the European
Union’s Energy Trading Scheme.
——
Include a value for the CO2 saved and re-run the
economic model with the CO2 saving creating an
additional revenue stream.
4.4.3
——
Calculate the cost per tonne of CO2 saved for each
increment of chp capacity and determine with the
client what additional capacity can be justified
when the chp investment is compared with other
options to save CO2.
If a baseload chp size is not the selected solution then
consideration needs to be given as to how the chp will
operate when heat demands are lower than its rated heat
output. A number of options can be evaluated:
The value of carbon could be derived from:
——
Operation at part-load: This is the most straight­
forward. However there is a loss of efficiency and
maintenance costs will increase. This is because
maintenance contracts are normally written in
terms of a charge per hour run, not on the basis of
electricity generation.
——
Use of multiple chp units: Using two or more chp
units would allow better load following and two
units of different sizes provide the greatest
flexibility. However there will be higher capital and
maintenance costs from using two units and also
some loss of efficiency (see below).
——
Use of a thermal store: A thermal store would enable
the chp to operate at full output for fewer hours in
the low demand period instead of modulating
down. The surplus heat would be stored for later in
the day when the chp would be turned off.
——
Heat rejection: To avoid part-load operation the
excess heat could be rejected to maintain chp
operation at full electrical output. This may have a
cost and environmental penalty (see below).
25
IRR / %
20
15
10
5
0
500
600
700
800
900
1000
CHP capacity / kW
1100
1200
500
Operation of CHP in low demand
(summer) periods
——
the shadow price of carbon published by the
Government
30
In practice more than one of these approaches may be used.
450
Net present value / kW
400
4.4.4
350
300
250
200
150
100
50
0
500
600
700
800
900
1000
CHP capacity / kW
1100
1200
1400
1200
CO2 savings / tonnes p.a.
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1000
800
600
400
0
500
The above discussion has focused particularly on heat.
Where the chp electricity is all sold to a licensed supplier,
i.e. there is no host site to take the electricity generated
directly, then optimising on heat demand will be correct.
Where there is the potential for export of electricity there
are additional complexities. If the electricity generated is
only a small part of the site demand it will be sufficient to
assume that the electricity generated displaces the incoming
electricity. Where the chp output is similar to the site
demand it is possible that the electricity supplier will
change the selling price to reflect the change in load factor
for the site, which can significantly affect the npv of a
potential project. Therefore the price structure that would
result from the installation of chp should be carefully
evaluated. Where there is significant export, the net
electricity income could fall off sharply as export prices are
much lower than import prices (typically 30–50% lower).
This can be a limiting factor on the size of the chp that can
be installed.
4.4.5
200
600
700
800
900
1000
CHP capacity / kW
1100
1200
Figure 4.6 Internal rate of return, net present value and CO2 savings
versus chp size
Export of electricity
Multiple units
In addition to sizing of a single chp it is also likely that the
option of using two or more chp units will need to be
evaluated. The same approach can be used. The capital
costs for two chp units will be higher than one unit of the
same total capacity and the maintenance costs higher and
the performance slightly less efficient. However the
Combined heat and power for buildings
advantage is that some maintenance can be programmed to
take place in periods of low demand when one engine can
be kept in operation, improving the overall availability, and
that periods of low demand can be supplied from one
engine, improving the percentage of heat that can be
supplied. It is not necessary to have two equal sized units
— greater flexibility is achieved by having two different
sizes. Again there is no substitute for detailed modelling of
this option against the demand profiles.
For small-scale chp (<50 kWe) there is unlikely to be a
significant capital or maintenance penalty for multiple
units and therefore their use is attractive as it offers a
significant gain in flexibility. These units are supplied with
a control system that provides automatic sequencing of the
units to follow electricity or heat demand.
4.4.6
Heat rejection
For a relatively small cost it is possible to include a heat
rejection system in the design. This can be achieved by
means of an air blast radiator or by a bypass damper in the
chp exhaust. This results in additional flexibility in that
the chp can continue to generate full electrical output even
when the heat demand is low. It can be economic to operate
in this manner if the electricity price is relatively high
compared to the gas price. It may still be better in terms of
CO2 reduction to operate with an element of heat rejection
depending on the electricity emissions factor used and the
relative efficiencies of chp and boilers.
4.5
Design of building heating
systems to benefit
CHP operation
heat demands are lower than forecast by the original
designers, especially if there have been subsequent fabric
efficiency improvements to the building. If heat emitters
are oversized it is possible to reduce the flow temperature
and rebalance the heat emitters to reduce return
temperatures.
There is some flexibility in the design of chp systems with
varying degrees of heat recovery as shown in Table 4.1. The
values for individual engines may differ from these figures
so discussions with the chp supplier at an early stage is
advisable.
Heat rejection equipment may be required if the
temperatures for heat demand and heat supply from chp
are not compatible; for example, the heat from the secondstage intercooler is frequently rejected as the heat demand
is normally above 40 °C. Clearly any heat rejection reduces
the benefits of having chp and will need to be limited. Heat
rejection may also be included to provide greater flexibility
in operation.
In larger systems where part of the demand is required as
steam and part as hot water it is possible to have a low
pressure steam-raising heat exchanger in the exhaust and
separate heat recovery for low temperature hot water from
the engine jacket/oil cooler circuit. This is often achieved
by ducting the chp exhaust to a fired shell steam boiler
modified to accept this exhaust gas flow to supplement its
output. Exhaust gas can also be used directly as the heat
source for an absorption chiller.
If the majority of the heat demand is high temperature or
steam, and if the site is large enough, a gas turbine could be
considered where all of the heat (typically >3 MWe) is
available as high temperature exhaust gases.
Many of the problems of poor chp performance are a result
of inadequate attention to the integration of chp into the
heating circuit design. Analysis of the design is necessary at
all part-load operating conditions, not just under maximum
demand.
The building services heating system will assist the chp
operation if it is designed with low return temperatures
There are a number of key objectives for the integration of
chp:
Flow temperature
Return temperature
—
<40 ºCHeat recovery from
second-stage intercooler
possible
—
<50 ºCCondensing exhaust
heat exchanger possible
80 ºC (max.)
As low as possible
but <60 ºC
90 ºC
70–75 ºCStandard conditions
suitable for most chp
units
—
>75 ºCRisk of chp tripping out
if this temperature is
exceeded
>100 ºC
—Leaks will result in flash
steam
110 ºC
70 ºCThis is feasible if the
heat recovery is in two
stages with the higher
temperatures from the
exhaust boiler
(1)
The chp unit should operate in preference to the
boilers at all times.
(2)
The chp unit output remains at maximum when
boilers need to be used to meet the demand.
(3)
The heat recovery from the chp unit is optimised.
(4)
The chp unit should always be able to generate
heat, even at part-load.
(5)
The building heating system should be designed so
that return temperatures do not result in the chp
unit shutting down unnecessarily.
Operating temperatures with spark-ignition gas engine
For new buildings the designer has the opportunity to
select flow and return temperatures for the heating circuits
to suit the chp plant, condensing boilers and the design of
the heat emitters.
In retrofit situations, the existing operating temperatures
will be a constraint. Often heat emitters are oversized and
Table 4.1 Operating temperatures on building services systems and heat
recovery opportunities
Low pressure steam from exhaust; 90 ºC hot water from jacket
Constraints
Small-scale chp
Two separate heat
recovery circuits
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(e.g. below 70 °C and preferably lower) and a variable
volume control system. This will reduce the risk of the chp
shutting down prematurely as a result of rising return
temperatures under part-load conditions. Low return
temperatures also enable thermal storage to be incorporated
more effectively as the amount of energy stored per unit of
volume increases. Further discussion of the design of
heating circuits for chp is given in section 9.
4.6
Building applications most
suitable for CHP
Building heat and power loads and profiles are, to a greater
or lesser extent, dependent on occupancy. Hence, buildings
that are suitable for chp schemes are those where occupancy
and energy use regimes normally extend beyond the normal
9 to 5 weekday office hours.
Buildings with high domestic hot water heating demands
are attractive as they will provide the opportunity for the
chp to operate in summer.
4.6.2
plant is less commonly applied in the applications
shown in Table 4.3, but these are nonetheless contenders
for further consideration.
chp
Any building that includes a swimming pool should be
viewed as having the potential for a chp scheme for both
domestic and pool water heating.
If the heat/power profile of a building does not immediately
seem appropriate, further analysis may identify alternative
conditions that would improve the viability. Examples
include:
——
Using heat-driven absorption or adsorption chilling
plant to extend the base load heat demand into the
summer months. Absorption chillers may save CO2
and avoid the use of greenhouse gases as refrigerants.
——
Energy linking with other nearby buildings that
have a complementary heat/power profile. This is
the basis on which university systems are often suc­
ces­sful where accommodation units and academic
buildings exist on the same campus.
The connection of buildings of different types in a mixed
use scheme or through district heating will generally result
in longer operating hours.
It is important to estimate how the demand may vary over
a typical 24-hour period as assuming a uniform average
demand is likely to result in an optimistic assessment of
chp.
4.6.1
Table 4.3 Less common applications for chp schemes
Application
Reason
Offices/town hallsEspecially where normal occupancy extends
into the evening; may be combined with
absorption chilling
MuseumsNeed to maintain stable temperature conditions,
independently of opening hours
Common applications of CHP
Buildings that have historically proved suitable for
schemes are shown in Table 4.2.
Applications with potential for CHP
chp
Data centres
Year round cooling demand
Prisons
24-hour occupancy
Schools
Extended occupancy, particularly for:
— boarding schools
— schools with swimming pools
— adult education centres
Large retail stores and
shopping centres
Extended operating hours; potential benefit
from an associated absorption chilling plant
Table 4.2 Suitable applications for chp schemes
Application
Reason
Swimming poolsContinuous demand for pool heating and pump
power. High demand for domestic hot water
Leisure centresOperate from early morning to late evening.
High demand for domestic hot water
Hospitals24-hour operation. Need high ambient
temperatures for patient care. High demand for
domestic hot water
Residential homesElderly residents needing high ambient
temperatures. High demand for domestic hot
water
HotelsLong operating hours, need to maintain
customer comfort. Often include leisure
facilities. High demand for domestic hot water
District heatingPotential for long operating hours due to
linking of buildings with differing demand
profiles and economies of scale
University campusOffice/teaching areas require heat during the
day and for evening activities. Accommodation
areas require heat early morning and evenings
Military sites and
24-hour operation and occupancy. Requirement
barracksfor standby generating capacity for critical
operational facilities. Normally centralised
domestic hot water for accommodation blocks
24-hour operation and occupancy. Requirement
Police, fire and
ambulance stationsfor standby generating capacity for critical
operational facilities
4.7
CHP to improve security of
electricity supply
The presence of a chp generator could provide the security
of being able to maintain an energy supply in the event of a
failure in the public electricity supply. The extent to which
this will apply will depend upon the way in which the
electrical system is configured.
Careful consideration must be given to the final arrangement
to resolve the potentially conflicting requirements of chp
plant (i.e. near continuous running, load limitations and
maintenance requirements) and conventional standby
generators (i.e. low running hours, high availability and
independence of standby supply).
In particular, chp should not be used for life safety systems
as there will be significant downtime for chp maintenance.
Separate diesel standby generators should always be used.
Combined heat and power for buildings
Additional electrical protection will be required to ensure
that systems can safely be returned to normal operation on
restoration of the public supply.
Where standby operation is considered, the load connected
to the generator under distribution network operator (dno)
failure conditions must be within the generator’s rating.
Load shedding arrangements may be required, but may be
difficult and expensive to achieve. Gas engines cannot
accommodate as large a step change in load as diesel engines
so if a chp unit is being used for standby purposes, the load
will need to be controlled to avoid step changes in load
greater than about 30% of maximum output.
Where standby plants can be run on peak-lopping or
regional peak export duty during winter months (stor
contracts) when tariff margins are greatest, the additional
cost to upgrade to chp plant operation may well be
worthwhile. In these circumstances, the savings on power
import charges and reductions in plant operation may be
recovered, even if running hours are as low as 1000 hours
per year.
5
Application of CHP to
supply district heating
Key points:
——
The difference between flow and return
temperatures for district heating should be at
least 30 °C.
——
Heat emitters and domestic hot water heating
systems should be designed to achieve low return
temperatures.
——
Controls should be variable volume (two-port
control valves) to maintain low return
temperatures at part-load and minimise
pumping energy.
——
Where bypasses are included the bypass flow rate
should be limited and controlled so as to
maintain a minimum flow temperature in the
network.
5.1
Principles of district heating
District heating (dh) is not an energy supply technology; it
is only a means of transporting heat to a number of buildings
such that a wider variety of heat sources can be used. In
addition, the inclusion in the dh scheme of buildings of
varied type, size, age and occupancy patterns results in a
diversity of demand that tends to reduce peaks and provide
more continuous demands. This can be advantageous for
chp systems and other high capital cost plant where longer
running hours will improve the economic case.
Note: many of the principles set out below are also applicable
to any large heating circuit and the distinction between
district heating and building services heating design is
somewhat arbitrary.
A dh network consists of flow and return pipes connecting
each building’s heating system to a centralised pumping
arrangement. At the building connections the dh water can
be used directly in the building’s heating system (direct
connection) or through a heat exchanger (indirect
connection). A direct connection can also be used with a
mixing system where the flow temperature in the building
heating system can be lower than in the dh network.
An efficient dh system will have a flow/return differential
temperature between 30 °C and 50 °C to reduce flow rates
on the network and keep pipe sizes small. The system will
also be more efficient if return temperatures do not rise
under part load conditions as this would involve additional
pumping energy and heat losses from the return pipe. The
use of two-port control valves and variable flow systems
within the building heating systems is therefore strongly
recom­mended.
A dh network will need to ensure that the flow temperature
is maintained above a set level at all points of the network
and this typically is achieved by using bypasses to maintain
a minimum flow rate. The best system is where these
bypasses are temperature controlled to avoid unnecessary
bypass flows, which would add to pumping energy.
The dh system will operate as a variable flow system and
variable speed pumps should be used to minimise energy
consumption using pressure differential sensors within the
network to control pump speed. Often multiple pumps are
used to enable the flow rate and head requirements to be
followed more closely.
A fundamental requirement for a dh network is that the
design flow rate can be supplied to all customers during
maximum demand periods. This means that the flow rate
into each customer’s connection must be limited regardless
of the differential pressure on the network. This is most
easily achieved using a differential pressure control valve
(dpcv) to limit the pressure across the heat exchanger or
control valve, or across the building heating system in the
case of direct connection. The dpcv is then adjusted (using
a balancing valve in addition, if necessary) to set the
required design flow rate.
In addition to chp plant of all types and scale, dh networks
can be supplied with heat from:
——
fossil fuel boilers
——
biomass boilers
——
industrial waste heat sources with a heat pump to
raise the temperature if necessary
——
large-scale solar thermal systems
——
large-scale heat pump systems, especially with
ground or river as the heat source or in combination
with district cooling
——
deep geothermal heat.
The efficiency of heat pumps depends strongly on the
temperature at which heat is supplied as well as the tempera­
ture of the heat source. This means that the flow temperature
from a dh network supplied by a heat pump will probably
be below 80 °C for efficiency reasons.
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5.2
Typical applications of
DH and CHP
A dh network is a significant capital investment and any
scheme should be seen as a long-term strategic infrastructure
suitable for sites with a long life. The advantage of dh is
that, provided routes for the pipework are carefully chosen,
alterations to any given building will not have a major
impact on the operation of the central plant. In this respect
a chp system supplying a dh scheme is more flexible than if
chp were to be installed in each building in an area.
Typical applications where a diversity of demand will lead
to more constant heat loads and longer running hours for
chp include:
——
——
5.3
New mixed use developments including housing, offices,
retail and leisure: this type of scheme has the
potential for reasonable summer heat demands for
domestic hot water, daytime heating demands from
offices and retail and evening heat demands from
leisure and housing.
University campus: a wide range of academic
buildings often exists including laboratories where
high air change rates can lead to significant heat
demands. If student accommodation is provided on
the campus, this will result in extended heating
through the evening. Many universities, libraries
and leisure facilities function with long opening
hours. Student accommodation is often used in the
summer for short courses and conferences.
Selling electricity and private
wire networks
Unlike a building or campus application, a chp plant
installed to supply a district heating network may not be
displacing imported electricity but will have to sell
electricity to a customer that may not have any connection
with the heat supply. There are a number of options
available:
——
selling to a licensed supplier who will then sell on
to their customers
——
direct sale to a large electricity user using a
dedicated cable connection
——
sale to one or more customers using the existing
distribution network operator (dno) infrastructure
through paying use of system charges
——
direct sales to the buildings in the area using a
private wire network
——
‘netting off ’ chp generation as part of a large
electricity sales contract.
For a private network, terms will need to be offered for the
use of the system by other electricity suppliers if competition
on electricity supply is to be maintained.
19
5.4
Efficient design of DH systems
to benefit CHP operation
5.4.1
New buildings or buildings with
extensive refurbishment
If new building services are being specified to operate in
conjunction with a dh supply there is the potential to
optimise the design to the benefit of the dh system.
Ultimately this will lead to lower energy supply costs and
lower CO2 emissions, even though the initial cost for the
building services may be slightly higher. The main design
principles to be followed are:
——
Selection of low operating temperatures and
especially low return temperatures. Typical space
heating circuit temperatures of 60–70 °C flow and
40 °C return should be considered.
——
Selection of hot water heating systems to deliver
low return temperatures using the dh supply;
typically this would involve:
instantaneous plate heat exchangers to
(a)
meet peak hot water demands
storage of hot water but with heating
(b)
provided by external plate heat exchangers.
The domestic hot water heat exchangers should be sized to
give a dh return temperature of 40 °C (preferably lower).
Storage calorifiers should be avoided as the return tempera­
tures will be higher than the stored temperature except at
cold start-up.
Variable volume control systems should be used with twoport control valves to ensure return temperatures on the dh
network do not rise at part-load.
Bypass flows in the heating circuit should be avoided to
prevent rising return temperatures at part-load. If bypasses
are necessary to maintain flow temperatures they should be
temperature controlled and only open to allow the
minimum flow rate when needed.
A design and control system that ensures that heat is taken
from the dh network as the priority heat source and that if
boilers within the building are retained for use in peak
periods the heat taken from the dh network remains at its
maximum level when the boilers operate.
Correct commissioning is needed to ensure that the
intended design return temperatures are achieved. There
will always be a tendency in commissioning to have higher
return tempera­tures than design and higher heating circuit
flow rates as this will be seen as providing greater margin.
This approach should be avoided.
The location of the dh heat exchanger in the circuit is an
important consideration to achieve the above objectives.
Where on-site boilers are installed or retained, the heat
exchanger can be in either a series or parallel arrangement
with the boilers, however, if it is in parallel a common
header bypass should be avoided and the dh heat exchanger
and boilers should have separate shunt pumps.
Combined heat and power for buildings
Energy centre
DH network
Building connection (indirect)
Building heating system
Controls
(D)
CHP
Peak
boiler
Thermal
store
(A)
(E)
(J)
(B)
M
(F)
(C)
(A) Thermal store to minimise use of
peak boiler
(B) Variable speed pumps with a range
of duties to suit demand pattern
(C) Temperature controlled bypass at
extremities of network
(H)
(G) Plate heat exchanger sized for close
return temperatures
(D) Differential pressure control valve to limit
maximum flow and limit pressure across
control valve (E)
(E) Two-port control valve to ensure variable
volume in DH network and to vary secondary
temperature
(F) Heat meter to encourage careful use of
energy
(G)
(H) Two-port control valve to maintain low
return temperature
(J) Heat emitters sized to give low return
temperature
Figure 5.1 Features of an efficient district heating system
5.4.2
Existing buildings
For existing buildings the dh supply may meet the peak
demand of the building or supply only part of the demand
with peak demands being met by boilers installed within
the building.
5.4.2.1
DH supplies peak demand
In this case the dh company will provide a heat exchanger
that can be installed either in parallel with the boilers or in
the return to the boilers. The dh company will wish to have
return water at as low a temperature as possible and the
contract for the supply of heat may include penalties for
high return temperatures or incentive payments for lower
return temperatures. The maximum supply rate into the
building will be constrained by two factors: the size of the
heat exchanger and the primary flow rate from the dh
system. The flow rate will be determined by assumed return
temperature and if the secondary (building side) return
temperatures rise above this assumed value the heat
delivered to the building will be lower than the agreed
figure. It is therefore necessary for the building services
designer to ensure that the temperatures set out in the
contract can be achieved. The key issues are:
——
Checking that the building circuit flow temperature
does not exceed the design value at time of peak
demand (this will be a set point on the dh heat
exchanger control).
——
Limiting any bypasses in the heating system to the
minimum compatible with avoiding dead legs. It
would be preferable for such bypasses to be
temperature controlled.
——
Ensuring that the system is balanced so that at
times of peak demand the return temperature is at
design condition. This may require balancing of all
heat emitters and ahu coils in the building. This
re-balancing will not only help the dh network but
will also avoid unnecessary pumping energy on the
building system.
The above considerations should ensure that the peak
demand situation is satisfactory. At part load conditions the
dh network energy (pumping and heat loss) can be
minimised by ensuring that return temperatures do not
rise above (and preferably fall below) the peak design return
temperature. This will not be achieved if three-port control
valves are used. It would be preferable for such systems to
be converted to operate as variable volume, two-port control
valves and it may be worth establishing with the dh
company how such a change could be financed through the
heat service contract. The recommendations for new
buildings above would then apply for the conversion works.
These conversion works may be justified on the energy
savings generated within the building, irrespective of any
district heating or chp benefit.
It is also possible that the operating temperatures could be
lowered, which will benefit the dh system. It is likely that
there will be a general oversizing of heat emitters as a result
of design margins or possibly as a result of improved
insulation after the services were installed. It may be
possible to examine bems data to see whether control valves
are fully open at times of peak demand. If they are not then
this would indicate potential for reducing temperatures. A
gradual reduction in flow temperature whilst monitoring
internal conditions through a winter period would enable
the lowest maximum required flow temperature to be
established.
5.4.2.2
DH supplies part of demand
In this case the dh supplies part of the demand and there
will be an agreed maximum supply rate so that the dh
network will only meet a proportion of the annual demand,
with the building boilers being required to operate at times
of peak demand.
The guidance above should be followed but in addition:
——
the dh heat exchanger should be used as the priority
heat source in preference to the boilers
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——
21
when the boilers are also required to operate, the
heat exchanger should continue to supply its
maximum heat output.
dh
These requirements are most easily achieved by connecting
the dh heat exchanger into the return pipe before a common
header. This may require some pipework modifications to
combine the returns.
5.5
Use of thermal storage
The use of a thermal store in association with a chp system
(and often with other low carbon heating technology)
brings four potential advantages:
——
It enables heat demands greater than the maximum
output of the chp to be met from chp heat stored
earlier thus reducing the use of boilers and
increasing chp running hours.
——
It enables heat demands lower than the minimum
turndown of the chp to be met from chp heat stored
earlier reducing the use of boilers and increasing
chp running hours.
——
It enables the chp unit to operate at full output
rather than at part-load thus improving its
efficiency.
——
It allows heat demands to be supplied outside the
normal economic operating regime of the chp, e.g.
at night when electricity prices are low and it would
not be economic to run the chp thus reducing the
use of boilers.
5.5.1
Figure 5.2 Thermal store supplying a small district heating system
(courtesy of Cofely District Energy Ltd.)
Designing a thermal store
Thermal stores consist of a cylindrical vessel of hot water.
This should be installed between flow and return circuits
and will remain full of water at all times.
For a store located internally there will be space constraints,
and costs will also be dependent on volume. So it is prefer­
able to reduce the size of the store as far as possible. This is
achieved by maximising the temperature difference between
flow and return on the heating circuit. As the flow tempera­
ture is normally limited to about 90 °C, in practice this
means having as low a return temperature as is practicable.
The other benefit to having a large temperature difference
is that the depth of the mixing layer between the hotter
flow water and the cooler return water is smaller. The water
in this mixing layer cannot be delivered to the scheme so
the useful volume of the store is reduced by this amount.
The depth of the layer can be minimised as a proportion of
the volume of the store by:
——
having taller cylinders (i.e. large height to diameter
ratio)
——
by using low return temperatures, and therefore a
greater difference in density between flow and
return
——
ensuring there is flow into the store only during
filling and recovering of energy, and no flow
through the store when the demand and supply is
matched
Figure 5.3 Thermal store at the London 2012 Olympic Park (courtesy of
Cofely District Energy Ltd.)
——
ensuring velocities at entry and exit are low by
using large diameter pipe connections and baffle
plates.
A higher flow temperature can be used for the chp and store
circuit than that supplied to the building by using a variable
temperature mixing valve. This enables the maximum
temperature difference to be achieved within the store so
that more heat energy can be stored.
5.5.2
Combined heat and power for buildings
Sizing of the thermal store
To establish the optimum size of the store it is necessary to
use an hour by hour operating model preferably for the
whole year, and to carry out a series of calculations with a
range of store sizes. The aim would be to optimise on the
npv or CO2 emissions savings, as described in section 4.4.
If it is considered that the most important aspect of the
store is to meet the demand at times when the chp is not
operating, then this would be a fairly straightforward
calculation as the store would need to hold the heat energy
required to supply all of the heat demand in this period.
5.6
District cooling
Many of the principles outlined above apply equally to
district cooling (except that temperatures are reversed).
District cooling systems have limited temperature differ­
ences (e.g. 4 °C to 14 °C) so controlling pumping energy by
avoiding low return temperatures at part-load is important.
A direct connection will avoid the need for a temperature
differential across a heat exchanger, which could be of
benefit in reducing flow rates.
The limited temperature difference available inevitably
means larger pipe sizes and higher capital costs. Hence
district cooling systems tend to be found only where there
is high density of cooling demand with good load factors.
The cooling source may be provided by absorption or
adsorption chillers supplied by chp or by large efficient
vapour compression chillers.
An alternative approach is to install absorption chillers in
the buildings, supplied from the dh network.
5.7
Large-scale district heating
Large-scale district heating operates on the same principles
as described above. The main difference is that the chp
heat source may be a major power station and will be
operated primarily to generate electricity. As a result a
flexible design is often used where the steam is extracted
from the steam turbine when required for heat and there is
full condensing capability so that electricity generation can
be maximised when there is low heat demand. This
flexibility can be used to advantage when combined with
large-scale heat storage as heat can be extracted from the
steam turbine at night, when electricity demand is low, and
stored for the following day.
The other feature of large-scale district heating is the
ability to use multiple heat sources and to vary their relative
contribution in both the short-term and long-term to
minimise operating costs and CO2 emissions. This could be
an important advantage in the future, when CO2 emissions
associated with grid electricity are lower, as a means of
avoiding the risk of having ‘stranded’ assets that are less
beneficial, which could be the case with smaller schemes
where gas fired chp is the only realistic heat source.
District heating networks are now installed using preinsulated pipe systems buried directly in the ground. These
comprise a steel carrier pipe, rigid polyurethane pipe
insulation and a high density polyethylene outer casing. A
surveillance system is included to detect the ingress of
moisture into the insulation that could cause corrosion.
High water quality needs to be maintained using chemical
and physical water treatment. Smaller pipe systems using
low temperatures and pressures can use pre-insulated allplastic systems with cross-linked polyethylene (pex) or
polybutylene (pb) carrier pipes.
6
Primary energy savings
and environmental
impact of CHP
Key points:
——
The equivalent heat efficiency of CHP is given by:
CHP thermal efficiency
CHP equivalent = —————————————
heat efficiency
CHP electrical efficiency
1 – ——————————
Grid efficiency
(
)
This efficiency can be compared directly with a
boiler efficiency.
——
Equivalent heat efficiency for a heat pump is
given by:
Heat pump equivalent = CoP Í grid efficiency
heat efficiency
——
The CO2 content of a unit of heat supplied by CHP
is given by:
CO2 content = [Ef – (Ee Í he)] / hh
where Ef is the fuel emission factor, Ee is the
electricity emission factor, he and hh are the CHP
electrical and thermal efficiencies respectively.
6.1
Primary energy savings
The energy efficiency of heat supply can be calculated using
the ‘equivalent heat efficiency’ concept and used to compare
heating options.
For a boiler:
Heat output
Equivalent heat efficiency = —————–
(6.1)
Fuel used
For a heat pump:
Heat output
Equivalent heat efficiency = —————————–
Primary energy input
Heat output
= —————————————––
(Electricity used / Grid efficiency)
= cop Í he, grid
(6.2)
where cop is the coefficient of performance (i.e. useful heat
output divided by the electricity consumption over the
year) and he, grid is the grid efficiency.
The grid efficiency is given by:
Robert W M Gichuba, rgichuba@yahoo.com, 10:51am 23/09/2013, 1, 35351
22
Delivered electricity
he, grid = ————————–——
Primary fuel input (Fps)
23
(6.3)
The performance of a chp system needs to be defined in
terms of two factors, i.e:
Thermal efficiency (hh) = ­­­­­­­­­Hchp / Fchp
(6.4)
where Hchp is the useful heat output and Fchp is the fuel
input.
Electrical efficiency (he) = Echp / Fchp
(6.5)
where Echp is the electricity generated and Fchp is the fuel
input.
Note: the chp performance can also be defined using total
efficiency (i.e. heat plus electricity, divided by fuel input),
or heat-to-power ratio plus one of the two efficiencies
defined above; however two parameters are always needed
to define chp performance.
The equivalent heat efficiency for chp is given by:
Heat output
Equivalent heat efficiency (hh,eq) = —————–
Net fuel used
The net fuel used is the chp fuel (Fchp) minus the power
station fuel (Fps) displaced by chp electricity generated
(Echp).
Therefore the equivalent heat efficiency is:
hh,eq = Hchp / (Fchp – Fps)
(6.6)
Substituting for Fps from equation 6.3:
hh,eq = Hchp / [Fchp – (Echp / he, grid)]
Substituting for Echp from equation 6.5:
and so the chp electrical efficiency will therefore generally
be lower than the best power station efficiency. However,
electricity grid losses also need to be taken into account,
which reduces the effective grid electrical efficiency at the
point of supply, narrowing the gap with chp. In equation
6.7, as the chp electrical efficiency tends towards the grid
efficiency then the equivalent heat efficiency tends towards
infinity, i.e. the heat would eventually be rejected close to
ambient temperature and could be classed as ‘waste heat’.
At the other extreme, if the chp electrical efficiency tends
towards zero then the chp equivalent heat efficiency tends
towards the chp thermal efficiency, i.e. the chp is tending to
become the equivalent of a boiler. So the most efficient chp
is where the electrical efficiency is as high as possible.
Equation 6.7 can be plotted in various ways and Figure 6.1
shows how the equivalent heat efficiency varies with chp
electrical efficiency for three different grid efficiencies
(40%, 45% and 50%) and for a total chp efficiency (thermal
plus electrical) constant at 80% in all cases.
Figure 6.1 shows that the equivalent heat efficiency
increases as the chp electrical efficiency increases. The
increase is significant; for the 40% grid efficiency case the
chp equivalent heat efficiency increases from 200% to 360%
for an increase in electrical efficiency from 30% to 35%.
Similarly, to maintain the same equivalent heat efficiency of
200% as the grid efficiency improves from 40% to 50%, the
chp electrical efficiency would need to improve from 30%
to 40%.
All of the chp equivalent heat efficiencies are higher than
those for boilers, which are typically 80% to 90%. Figure 6.1
can also be used to compare chp with heat pumps. From
equation 6.2, for example, with a grid efficiency of 40%, a
heat pump with a cop of 3 has an equivalent heat efficiency
of 120% (i.e. 3 Í 40%) and a chp with an electrical efficiency
of 20% would have the same equivalent heat efficiency.
However, for a grid efficiency of 50%, a heat pump with a
cop of 4 would have an equivalent heat efficiency of 200%
(i.e. 4 Í 50%) and a chp would need to have an electrical
efficiency of 40% to be as efficient.
hh,eq = Hchp / [Fchp – (Fchp he / he, grid)]
400
Rearranging gives:
hh,eq = (Hchp / Fchp) / [1 – (he / he, grid)]
Substituting for (Hchp / Fchp) from equation 6.4:
hh,eq = hh / [1 – (he / he, grid)]
(6.7)
i.e:
chp thermal efficiency
chp equivalent
= ————————————
heat efficiency
chp electrical efficiency
1 – ————————–——
Grid efficiency
(
)
Equation 6.7 is fundamental to chp performance and merits
further explanation. One implication of the second law of
thermodynamics is that the highest electrical efficiency
will be achieved when discharging heat at the lowest
possible cold sink temperature, i.e. ambient temperature.
For heat to be useful it will always need to be above ambient
Equivalent heat efficiency / %
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Part 1: Technologies, applications and regulations
350
300
250
200
150
100
50
0
15%
20%
25%
30%
35%
CHP electrical efficiency
Grid efficiency 40%
Grid efficiency 50%
Grid efficiency 45%
Heat pump CoP 4
grid efficiency 50%
40%
45%
Heat pump CoP 3·5
grid efficiiency 45%
Heat pump CoP 3
grid efficiency 40%
Gas boiler at 85%
efficiency
Figure 6.1 Equivalent heat efficiencies for chp (chp total efficiency =
80%)
Combined heat and power for buildings
The current grid efficiency is about 39% as calculated from
Table 5.6 of the Digest of UK Energy Statistics (DECC, 2010).
This excludes transmission and distribution electrical
losses so the average efficiency for delivered energy is
around 36%.
energy efficiency gains and hence the mitigation of climate
change, it does not take account of the variation in CO2
emissions that result from using different types of fuel.
Typical equivalent heat efficiencies calculated from the
above equations are as follows.
The CO2 savings associated with chp can be established by
calculating the total CO2 emissions for the building or
district heating scheme both with and without chp
installed; the difference is the CO2 saving.
For current technology and a grid efficiency of, say, 40%:
Without chp:
——
Individual gas boiler: 85%
——
Air source heat pump (cop = 2.5): 100%
——
Gas-engine chp (35% electrical efficiency and 45%
thermal efficiency): 360%
For future technology and a grid efficiency of, say, 50%:
——
Individual gas boiler: 85%
——
Air source heat pump (cop = 2.5) = 125%
——
chp
——
Heat pump (cop = 4): 200%
——
chp
(35% electrical efficiency and 45% thermal
efficiency): 150%
(40% electrical efficiency and 40% thermal
efficiency): 200%.
Equation 6.7 shows the importance of achieving a high
electrical efficiency for the chp plant in relation to the grid
efficiency. As grid efficiency improves, chp electrical
efficiency will also need to improve if the benefits of chp
are to be maintained, for example by the use of fuel cells or,
at a larger-scale, combined cycle gas turbines.
It is more meaningful to consider the relative energy
efficiencies of chp and conventional grid electricity when
both sources are using the same fuel (i.e. natural gas).
Currently gas-fired power stations are about 47% efficient
or 43% efficient after taking account of grid losses, although
these efficiencies are likely to improve with the new
generation of combined cycle gas turbine (ccgt) plant
being constructed, so the figures given above for 50% grid
efficiency may be achieved for gas-fired power stations in
the future.
Often chp efficiencies are quoted as being 80% (referring to
the total efficiency) and then compared with the grid
efficiency of 40%, thus indicating a doubling of energy
efficiency. As the analysis above shows, this is a false
comparison, for a low chp electrical efficiency of, say, 15%,
a chp total efficiency of 80% may be only slightly better
than a boiler. Similarly, heat pumps are often claimed to
have an efficiency of more than 100% (which is true
provided that cop Í grid efficiency >100%) and that this
must therefore always be better than a chp that has a
practical maximum total efficiency of 80%. Again, this is an
erroneous conclusion — the chp equivalent heat efficiency
can be significantly better than a heat pump depending on
the seasonal cop of the heat pump, the chp electrical
efficiency and the electricity grid efficiency.
6.2
CO2 savings and impact of
emission factors
Although the primary energy approach described in section
6.1 provides some useful insights into the potential for
CO2 emissions = [(H / hboiler) Í Ef,boiler] + (P Í Eelec)
(6.8)
where H is total heat consumption for the site (MW·h),
hboiler is the boiler efficiency, Ef,boiler is the emissions factor
for the boiler fuel (kg/MW·h), P is the electrical consumption
for the site (MW·h) and Eelec is the emissions factor for
electricity (kg/MW·h).
With chp:
CO2 emissions = [(H – Hchp) / hboiler Í Ef,boiler]
+ (Fchp Í Ef,chp) + [(P – Pchp) Í Eelec]
(6.9)
where Hchp is the heat supplied from chp (MW·h), Fchp is
the fuel used by the chp (MW·h), Ef,chp is the emissions
factor for the chp fuel (kg/MW·h) and Pchp is the electricity
supplied by chp (MW·h)
The boiler efficiency (hboiler) is the heat produced divided
by the fuel input (based on gross calorific value (gcv)).
The above equations assume that the boiler efficiency is
constant whereas in some cases the boiler efficiency may be
reduced by the addition of chp if the boilers operate
intermittently and at lower load.
This approach results in a single absolute CO2 saving for
the site and does not involve assigning this saving to either
heat or electricity.
Net (lower) calorific value and gross (higher) calorific value
Energy efficiencies are defined by the ratio of useful energy
produced to the energy in the fuel that is used. There are two
definitions for the calorific value of the fuel used to convert the
volume or mass of a fuel to energy:
—net calorific value (NCV) is the energy recovered from the
combustion gases but excluding the latent heat recovered
from the water vapour produced
—gross calorific value (GVC) includes the energy that can be
obtained by condensing the water vapour.
Energy is sold using GCV and emission factors are based on GCV.
It is therefore important to use GCV efficiencies in calculations of
cost-effectiveness and environmental impact of CHP.
There is a convention in the power industry to state efficiencies
in terms of NCV and so the efficiencies used must be carefully
checked and converted to GCV if necessary.
The conversion from NCV to GCV depends on the fuel used. For
UK natural gas, the GCV is 1.108 times the NCV, so an efficiency
quoted using NCV needs to be divided by this conversion factor
to provide an efficiency based on GCV.
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6.2.1
25
CO2 emissions due to heat supplied
If it is necessary to compare chp with other options a similar
approach can be used to calculate the site CO2 emissions.
However it may also be useful to compare the options on
the basis of the CO2 content of the heat supplied. The chp
unit is installed to provide heat, not electricity and, on this
basis, its CO2 emissions can be compared with, say, a
biomass boiler. It will be the heat demand that is constant
in each case.
The method given below calculates the CO2 emissions
associated with a unit of heat produced by the different
technologies.
For a boiler, the CO2 emissions associated with heat output
are given by the fuel emission factor divided by the
efficiency; for a heat pump, they are given by the electricity
emission factor divided by the cop.
For a chp plant, the CO2 emissions are given by:
(
) (
fuel
chp-generated elec.
Í
–
Í
fuel emission factor
elec. emission factor
————————–————————————
chp heat generated
chp
)
This can be expressed in terms of the chp thermal efficiency
and chp electrical efficiency as follows:
Fchp Í Ef – Echp Í Ee
CO2 content of chp heat = ————————–—
Hchp
= (Ef / hh) – Ee (he / hh)
= (Ef – Ee he ) / hh
(6.10)
where Echp , Hchp and Fchp are the chp energy flows for
electricity generated, heat and fuel respectively, Ef is the
fuel emission factor, Ee is the electricity emission factor,
and he and hh are the chp electrical and thermal efficiencies
respectively.
Another type of chp plant is where heat is extracted in the
form of low pressure steam from a power station built
primarily for electricity generation, irrespective of the
energy source (i.e. fossil fuel, energy from waste, biomass or
nuclear). When steam is extracted from the steam turbine
at a useful temperature, there will be a reduction in the
electricity generated. In this case the CO2 content of heat
relates to the emissions from other power stations on the
system that would have to operate in order to replace this
‘lost’ electricity. The ratio of heat extracted to electricity
reduction is termed the ‘z-factor’ and is typically in the
range of 6 to 8. Hence:
CO2 content of heat extraction = Ee / z
(6.11)
The above equations have been plotted graphically as
Figure 6.2 for comparison, with the main variable being the
electricity emission factor for the grid supply. It is assumed
that gas is the fuel used for chp and a gas emission factor of
198 g/kW·h (DCLG, 2010).
Figure 6.2 demonstrates that the key issue in the comparison
is the emission factor assumed for the grid electricity. As
the electricity supply is composed of a mix of power stations
with wide variation in emissions factor (from hydro­
electricity and wind energy with near zero emissions to
coal-fired power stations with around 900 g/kW·he), it is
not obvious which emissions factor to use.
An average emissions factor is the approach taken within
Part L of the Building Regulations 2010 (DCLG, 2010)
where 529 g/kW·he is to be used in assessing the benefits
from displacing grid electricity.
Figure 6.2 also shows the importance of electrical efficiency
of the chp in achieving low CO2 emissions.
Long-term decarbonisation of the electricity grid will mean
that, over time, chp systems will save less CO2 as they will
be competing with lower-carbon grid electricity. However,
natural gas fired chp with efficiencies greater than 20%
electricity and 60% thermal will still result in CO2 savings
provided unabated gas fired power stations are still
operating on the system.
It is possible that the gas supply will also be decarbonised
through the injection of biomethane, which may offset
some of the reductions in CO2 savings. chp would make
better use of this renewable energy.
In the longer term beyond 2030, it may be necessary to
move away from the small-scale natural gas fired plant that
dominates the chp market at present to the use of renewable
fuels or extraction of heat from major power stations,
together with the greater use of district heating. District
heating systems may also use low carbon heat sources other
than chp, including heat pumps. The impact on chp
applications will depend greatly on the rate of
decarbonisation of the grid.
In addition to the comparison of technologies on the basis
of CO2 emissions, the flexibility of generation is likely to
become important as the amount of intermittent wind
energy increases. The use of local smaller generators that
CO2 emissions per kW·h heat / (g / kW·h)
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Part 1: Technologies, applications and regulations
300
250
200
150
100
50
0
–50
–150
300
350
400
450
500
550
600
650
CO2 emissions per kWh electricity / g/kWh
CHP at 25%
700
Gas boiler at 85%
CHP at 35%
Heat pump (CoP = 2)
CHP at 42%
Heat pump (CoP = 3)
Steam turbine extraction z=7
Figure 6.2 CO2 emissions for heat from various sources against electricity
emissions factor (Note: stated chp efficiencies relate to electrical
efficiency; total chp efficiency (i.e. thermal plus electrical) is kept
constant at 80%. All efficiencies are on gcv basis)
Combined heat and power for buildings
can respond quickly could have a valuable role in helping
to balance the grid.
6.3
CO2 benefits from tri-generation
The CO2 benefits from tri-generation can be assessed in a
similar way by first calculating the CO2 content of heat
from chp and then the CO2 content of ‘coolth’ from the
absorption chiller from:
CO2 content of coolth is the CO2 content of the heat supplied divided by the cop of the heat-driven chiller.
This can then be compared with the CO2 content of coolth
from a conventional electrically driven chiller from:
CO2 content of electricity
CO2 content of coolth = ——————————––
cop of electric chiller
(6.12)
CO2 emissions per kW·h heat / (g / kW·h)
Typical results for a single effect absorption chiller coupled
to a gas fired chp system with a range of electrical efficiencies
are plotted as Figure 6.3. It can be seen that with current
electricity emission factors of around 500 g/kW·h, trigeneration offers some benefits compared to an electric
chiller with a cop of 4, but if the electricity emission factor
falls to around 400 g/kW·h (as is predicted) there will be no
CO2 savings even for a very efficient chp. A detailed
comparison of relative benefits is recommended given that
cops for electrically driven chillers are improving. Account
should also be taken of ancillary electricity for condenser
cooling, as a single effect absorption chiller will require
around twice the energy of an electrically driven chiller for
its heat rejection system.
300
250
As with most fuel combustion sources, the principal means
for reducing the impact is to ensure good dispersion of the
combustion gases away from people who might be affected
(the term ‘sensitive receptors’ is used). This can be achieved
by using a sufficiently high stack to ensure dispersion by
the air such that ground level concentrations are low. Care
needs to be taken when there are tall buildings in the
vicinity. Generally stacks should be at a height above the
roof line to avoid turbulence around the building, which
could cause the plume to return downwards and reach
occupants of the building. Stack exit velocities should be
10–15 m/s. Using lower exhaust temperatures to maximise
heat recovery may have the undesirable effect of reducing
the buoyancy of the plume.
Engine emissions are determined by the quality of fuel, the
mixture of air and fuel, and the efficiency of the combustion
process. For a given engine, maximum shaft power output
will be achieved when combustion takes place under
stoichiometric conditions, i.e. just the right amount of
oxygen for the amount of fuel. However, this will not
achieve minimum emissions.
It is normal to supply engines with an excess of oxygen (air)
to reduce the NOx and CO levels. Both of these pollutants
are addressed in the UK Air Quality Strategy (DEFRA,
2007), which identifies that NOx in particular can have
adverse effects on human health and can contribute to
acidification of the environment. Most engine manufac­
turers design engines to comply with recognised emission
standards.
Where stringent emission conditions are demanded,
emission control may be achieved by use of lean-burn
engines (air flow 1.5 to 2.0 times stoichiometric conditions).
Selective catalytic reduction systems can be employed and
are designed to reduce NOx by 95% or more. Oxidation
catalysts may be designed to reduce CO and non-methane
hydrocarbons (nmhcs). Reductions of 90% in CO and
50–70% in nmhcs may be achieved.
200
150
100
50
Selection of catalytic reduction systems is an area where
specialist advice should be sought.
0
-50
Catalysts will have a finite life and it is necessary to factor
in the cost of their replacement over the life of the scheme.
-100
-150
300
potentially have a negative impact on the local environment
and will need to be assessed and controlled.
350
400
450
500
550
600
650
CO2 emissions per kW·h electricity / (g / kW·h)
700
Tri-generation at 25%
Tri-generation at 42%
Tri-generation at 35%
Chiller (CoP = 4)
6.4.1
Particulate emissions
Figure 6.3 Comparison of tri-generation with electrically driven chillers
(Note: tri-generation efficiencies refer to the chp electrical efficiency;
overall chp efficiency is taken as 80% in all cases)
Where natural gas, or clean synthesis gas (‘syngas’) from
advanced gasification, is used as the fuel, particulate
emissions are not a concern. However the range of fuels for
chp is expanding and particulate emissions need to be
considered when using biomass or any liquid fuels.
6.4
6.4.2
Other emissions to air
Although CO2 emissions are the main concern with regard
to climate change, N2O is also a greenhouse gas. In addition,
NOx emissions are associated with poor air quality in cities
leading to public health concerns. Whilst chp units will
displace electricity generated at remote power stations and
provide global environmental benefits, the local emissions
Relevant legislation and guidance
The third edition of Chimney Heights: 1956 Clean Air Act
Memorandum (DoE, 1981) was produced specifically for
dealing with emissions from conventional boilers in use at
the time and can continue to be used for boiler emissions
unless other criteria apply to the site, e.g. under the
European Directive on Integrated Pollution Prevention
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and Control (‘the IPPC Directive’). However, it should not
be used in the calculation of chimney heights for chp gas
engine emissions.
In some larger schemes dispersion modelling may be
required to demonstrate the levels of NOx concentration at
ground level as part of a planning application. In other
schemes applying the guidance in HMIP Technical
Guidance Note D1 (HMIP, 1993) should be followed
whether using new purpose-built chimneys or re-using
existing.
If the site comes under the provisions of the IPPC Directive,
the Environment Agency will almost certainly require
dispersion modelling to be carried out using approved
software, rather than a D1 calculation.
6.4.3
Flue dispersion modelling
Whilst not mandatory, HMIP Technical Guidance Note D1
may be used as the benchmark for determining the
appropriate stack height. However this was not originally
written for gas-fired chp systems. A more appropriate
method is to carry out a modelling exercise to establish the
impact of the emissions on ground concentrations, and
from this model determine the optimum height that
balances impact on air quality with cost and visual impact.
This is typically the information that would be needed for
a planning application for a large installation, especially if
the site is located within an Air Quality Management Area.
It is advisable to discuss the project in advance with the
local Environmental Health Officer to determine the
information that is required to be submitted with a planning
application.
The Local Authority, the Environment Agency, the Scottish
Environment Protection Agency (SEPA) or the Northern
Ireland Environment Agency who grant approval may
require particular operating parameters to be used in the
calculation of chimney height. They may also require a
copy of any D1 or dispersion modelling calculations, so
early contact with the appropriate authority is recommended
to avoid conflict or disagreement at a later date.
The installation of a chimney calculated to meet D1 or
using dispersion modelling is not a guarantee that the site
will not cause a nuisance. The calculation is based upon the
98th percentile of meteorological conditions (Guidance
Note D1, paragraph 2.6 refers) and there remains the risk of
a smell being detected during engine operation under
abnormal weather conditions or sudden gusts of winds
carrying undiluted exhaust down to ground level.
Special consideration may be necessary for occupied
buildings that are close to chimneys or are relatively tall
with opening windows at high level. D1 and dispersion
modelling only consider ground level concentrations, so
taller occupied buildings may be subjected to higher
concentration levels of pollutants than are expected at
ground level.
6.4.4
Air quality objectives
Under the authority of the Environment Act 1995 the
Secretary of State has issued The Air Quality (England)
Regulations 2000 Statutory Instrument 2000 No. 928. This
sets short and long term air quality objective levels
27
(measured at ground level, not at chimney discharge) for
seven substances, including nitrogen dioxide, carbon
monoxide and sulphur dioxide, which are relevant to chp
gas engines and fired boilers. This was supplemented in
2007 by DEFRA’s Air Quality Strategy for England, Scotland,
Wales and Northern Ireland (DEFRA, 2007).
6.5
Noise
Reciprocating engines and their auxiliaries will generate
noise that must be attenuated to acceptable levels. The
degree of attenuation will depend on the target limits of
noise to be achieved:
——
in plant room
——
in adjacent areas
——
at air inlets and exhaust outlets
——
at nearby buildings.
suppliers should be able to provide noise data for the
units which are external to the acoustic enclosure and the
exhaust air terminations. Most small-scale chp units will be
supplied within acoustic enclosures, which in many cases
will be adequate to achieve all required noise targets.
chp
Additionally, noise levels from other aspects of an
installation, in particular the exhaust flues and the venti­
lation and heat rejection systems, will need consider­ation
at the feasibility stage.
Consideration of the noise impacts of the plant relative to
existing background noise levels both inside and outside
the building, and within the plant room for health and
safety purposes, may affect the design of the development
to ensure that potentially adverse effects are minimised.
The starting point is to determine the background noise
levels by measurement.
Acoustic mitigation is discussed in section 9.12.
6.6
Other environmental impacts
engines need lubricating oil to maintain efficient
operation. This needs to be regularly replaced and
appropriate storage provided on-site if the chp engine is
being maintained in-house rather than by external
contractors. Oil spills can have an adverse effect on the
environment and waterways in particular. There is a need
to consider the use of bunded stores and oil interceptors
with remote alarms where large volumes of oil are involved.
chp
There may also be a visible water vapour plume from the
exhaust as a result of condensation on cold days and this
may be of concern to local residents, even though such a
plume indicates good heat recovery conditions.
As with the combustion exhaust outlet, consideration must
also be given to the ventilation air exhausted from the
engine enclosure. This should be discharged to a well
ventilated area that will not cause a nuisance; there is a risk
of odour, even though it is only heated air.
The engine crankcase breather pipe will need to be
terminated at a suitable point away from ventilation air
intakes.
7
Combined heat and power for buildings
Legislation and
regulations that impact
on CHP viability
Key points:
reduction in greenhouse gas emissions by 2050, the first
such commitment made by any nation. To support the
achievement of this target, the Act empowers the
Government to set 5-year carbon budgets. The Act also
establishes a Committee on Climate Change to advise the
Government on the emission reduction target for each
carbon budget and progress towards meeting them.
There are a number of Regulations that impact on CHP
including important financial incentives.
The first report of the Committee on Climate Change was
published on 1st December 2008.
Regulations are subject to change and although this
section summarises the main areas of legislation that
impact CHP, readers must consult relevant Government
websites or the Combined Heat and Power Association
(CHPA) for the latest information.
This confirmed that an 80% reduction by 2050 was an
appropriate target to support global efforts to avoid
dangerous climate change, and that the emission reduction
target should relate to all greenhouse gases and include
emissions from UK aviation and shipping.
Regulations associated with the generation, distribution
and supply of electricity are also important for CHP systems
and early liaison with the local Distribution Network
Operator is recommended to establish the interface
requirements
7.1
Planning
The energy strategy for new buildings is often influenced
by local and regional planning policies. The latest policy
and draft policies and associated supplementary planning
guidance or area development plans should be consulted to
establish whether chp is seen as a preferred technology and
whether there is the potential for a wider district heating
network to be established in the area.
If chp is to be incorporated there will be a number of
detailed planning considerations. Planning approval will
be required for the building and information will need to
be provided on emissions, noise and visual impact. For
biomass chp, planners will also require information on
expected vehicle movements. For large installations a full
Environmental Impact Assessment may be required.
Planning is currently the responsibility of the Department
of Communities and Local Government (DCLG).
7.2
Building Regulations
For new buildings in England and Wales, Part L of the
Building Regulations* will influence the design of the
building fabric, its services and the heat sources used. The
ways in which chp, renewable fuels and district heating are
treated within the Regulations need to be carefully studied
to ensure that the most up to date information is being
used.
In addition to the Building Regulations Approved
Documents there are accompanying Compliance Guides
that contain information relevant to chp and district
heating.
7.3
Climate Change Act
The Climate Change Act 2008 came into force on 26th
November 2008. It is significant as it contains a legally
binding commitment for the UK to achieve an 80%
* Requirements may differ in Scotland and Northern Ireland.
The main impact of this legislation is that CO2 reduction
targets have considerable influence in overall policy
direction. It also shows that there will need to be a
progressive reduction in CO2 emissions from the electricity
system against which local chp systems will be compared.
This means that over time, the CO2 savings from natural
gas fired chp are likely to decrease leading to pressures to
either improve chp efficiency or convert to alternative
renewable fuels.
7.4
Carbon trading: CRC Energy
Efficiency Scheme and the
EU Emissions Trading System
7.4.1
CRC Energy Efficiency Scheme
The CRC Energy Efficiency Scheme (previously known as
the Carbon Reduction Commitment) aims to reduce carbon
emissions from large commercial and public sector bodies
in the UK. ‘Large’ is defined as electricity consumption
greater than 6000 MW·h per annum.
7.4.2
EU Emissions Trading Scheme
The European Union Emissions Trading Scheme (EU
ETS) is a form of market regulation resulting from the EU
Directive 2003/87/EC (the ‘Emissions Trading Directive’).
Only the larger combustion plants (with a site fuel input
greater than 20 MW) are under a mandatory requirement to
participate in the EU ETS. If chp is introduced, the fuel
use, and hence local CO2 emissions on the site, will increase
(but decrease globally) and therefore it is necessary to
obtain additional ETS allowances for the site.
7.5
CHP Quality Assurance
Programme
Three of the fiscal incentives that have historically provided
support for chp schemes (namely, exemption from the
Climate Change Levy, eligibility for Enhanced Capital
Allowances and free allocation of allowances under Phase 2
of the EU Emission Trading Scheme) require that the
scheme be certified as ‘good quality chp’. This is a standard
under the Combined Heat and Power Quality Assurance
(CHPQA) programme (managed by the Department of
Energy and Climate Change (DECC)), for which a detailed
assessment methodology has been developed. This method­
ology is set out in CHPQA Guidance Notes (CHPQA,
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2012). The CHPQA methodology was amended in January
2009. Good quality chp must be certified as such by the
award of a certificate from the CHPQA (a ‘CHPQA
certificate’). CHPQA requires compliant metering and
annual performance monitoring.
Enhanced Capital Allowances
Enhanced Capital Allowances (ECAs) were introduced in
2001 as part of the UK Government’s commitment under
the Kyoto Agreement to reduce UK carbon dioxide
emissions. ECAs are a 100% first year allowance (fya),
which can be claimed in the year the expenditure was
incurred on the provision of the qualifying equipment.
ECAs can only be claimed on a chp installation, if a
Certificate of Energy Efficiency has been issued by the
Secretary of State. This certificate can only be issued if the
chp installation meets the requirements of the Combined
Heat and Power Quality Assurance (CHPQA) standard and
obtains quality-certification.
The CHPQA Scheme provides a series of guidance notes on
compliance; Guidance Note 42: Use of CHPQA to Obtain
Enhanced Capital Allowances deals specifically with ECAs
and can be found on the CHPQA website (CHPQA, 2012).
The rules relating to the claiming of capital allowances are
a complex area of the UK tax system. Professional advice
should be sought at the initial stages of any chp project
where capital allowances are being considered.
7.6
Other financial mechanisms
7.6.1
Renewables Obligation
The Renewables Obligation is the main support mechanism
of large scale renewable energy schemes in the UK. It
imposes a requirement on electricity generators to source
an annual percentage of the electricity they supply from
renewable sources. This percentage rises annually, and will
be approximately 15% by 2015. For each MW·h of renewable
energy supplied, the energy supplier receives a tradable
Renewables Obligation Certificate (ROC). A supplier must
annually surrender sufficient ROCs to cover the required
29
number of MW·h imposed on it under the Renewables
Obligation. If insufficient ROCs have been issued to the
supplier, the supplier may buy further ROCs on the ROCs
market, or pay a charge into the ‘buy-out’ fund. Proceeds in
the buy-out fund are annually recycled back to suppliers
presenting ROCs. The Government is currently proposing
an alternative to ROCs using a ‘Contract for Difference’
(CfD) based incentive model.
7.6.2
Feed-in tariffs
The Government has introduced legislation for feed-in
tariffs for electricity generated from renewable sources
below 5 MWe capacity and for gas-fired chp below 50 kWe.
The technologies that currently qualify include micro-chp,
defined as less than 2 kWe and biomass chp systems less
than 5 MWe. Feed-in tariffs and their scope are subject to
change to reflect the latest policy aspirations and the latest
position should be checked prior to any economic analysis.
7.6.3
Renewable heat incentive
The Government is currently introducing a Renewable
Heat Incentive. This would result in additional income for
heat delivered from energy sources classed as renewable,
including biomass boilers and heat pumps. Gas-fired chp
projects will not benefit from this scheme but the heat
produced from renewables-fired chp will qualify.
7.7
Parallel operation with
DNO system
In order to connect the chp in parallel with the public
electricity system (the ‘grid’) a Connection Agreement
must be in place with the local distribution network
operator (dno). The dno will need to approve the operation
of the plant with tests to demonstrate that the unit will
disconnect from the dno system in the event of a fault to
avoid feeding power onto the dno system under fault
conditions. The detailed requirements are contained in
Engineering Recommendations G/59/2 (ENA, 2011a) and
G/83/1 (ENA, 2011b) obtainable from the Energy Networks
Association (http://2010.energynetworks.org). A generation
licence is only required for exporting more than 10 MW of
power.
Combined heat and power for buildings
Part 2: Project implementation
8
Feasibility studies
8.1
Introduction
The object of the feasibility phase of a project is to determine
whether or not it is worth the investment of time and
resources necessary to develop the initial concept of a chp
scheme into an actual engineering project. One important
aim is to identify and reject unsuitable schemes at an early
stage to avoid abortive costs. At this stage, chp schemes
should be compared with other appropriate alternatives,
e.g. installing condensing boilers, biomass boilers etc. For
chp projects with potential for further development, the
feasibility phase will ensure that sufficient consideration is
given to acquiring adequate information upon which sound
decisions may be based. The feasibility stage, carried out by
technical personnel, will marshal the arguments necessary
for obtaining financial approval from the relevant nontechnical decision makers.
can be considered. At this stage the considerations
are related to matching of heat and power demands
rather than economic analysis.
——
Economic options appraisal: once a technically viable
option (or normally more than one option) has been
identified, the financial viability may be investigated
through an economic appraisal. Again, the aim is to
quickly identify projects that are unsuitable and to
provide sound arguments for proceeding with those
that are.
——
Recommendation to proceed to design and tender: the
information obtained during the data gathering,
initial technical evaluation and economic appraisal
stages will form the basis for any recommendation
to proceed to design and tender. If the project is
identified as currently unsuitable for further
consideration the reasons for such rejection should
be recorded and other information retained for
reconsideration at a later date, should circum­
stances change. Where the project is suitable for
further consideration, information should be made
available for framing the recommendation to
decision makers for the further development of the
project.
Once the feasibility phase is successfully completed, the
project can be developed to detailed design with confidence
that the necessary information is to hand and that an
economically sound project will result.
The client can choose to use either a consultant or
equipment supplier for the feasibility study. In either case,
the client’s in-house staff will probably need to do much of
the groundwork of gathering data on current energy use.
schemes may be considered as a retrofit measure in an
existing building or included in the plant specification for
a new building. In each case, the arguments for and against
a chp scheme will be formed by comparison with the
appropriate conventional plant alternative.
The following sections amplify aspects of these activities.
8.2
chp
Figure 8.1 provides an overview of the feasibility process.
The key steps involved in the feasibility stage are described
briefly below:
——
——
——
Project initiation: project initiation may come from
many quarters but in essence someone will have
made a decision to consider a chp scheme. The
drivers for this decision may have been financial,
environmental or regulatory. There may be no
commitment of funding and only superficial
support for the idea; however, the project is now
underway.
Data gathering: the first task for the project is to
gather together the data that will be used to assess
viability. For an accurate feasibility study, the scope
of the required data is extensive. The higher the
quality of data gathered, the greater the accuracy of
any study. The process of gathering data should not
be regarded as a once-only event, but as an activity
that will continue throughout the project as more
information becomes available.
Initial technical evaluation: when sufficient infor­
mation is available, the project may proceed to a
stage when the capacity of any potential chp plant
Data gathering of energy
demands and system
temperatures
The scope of data that may form part of any chp scheme
investigation can be extensive, from the purely technical
aspects of energy use to the financial aspects of project
appraisal. Some of the data will be readily available, others
may require further investigation. At this stage, approval of
the project is not assured but the level of data gathered
should be sufficient to progress to subsequent phases.
8.2.1
Energy consumption
A minimum understanding of site energy demands is
required to make any assessment of the viability of the chp
scheme. Some data will be readily available (e.g. quarterly
or monthly fuel bills), whereas other data (e.g. energy
profiles for a week or a day) may require special data
acquisition. The scope of data required should be assessed
since the project should not proceed from one stage to the
next without sufficient, sound data.
Energy consumption will need to be understood in
considerable detail for full implementation of a chp scheme.
Whereas for conventional power and heating systems, the
capacity of the plant installed is determined largely by the
maximum demands (which consequently results in the
plant operating at part load most of the time), chp schemes
require high plant utilisation to achieve the necessary
economic viability. Consequently, for selecting a chp
scheme, the minimum energy demands in the running
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Receive client brief
Gather data on
energy use
Obtain details of
site and plantrooms
Process data to produce
heat and electricity
demand profiles
Establish energy prices
to be used in model
Consider physical
arrangement and
interfaces
Construct operating
model
Capital cost estimates
Maintenance cost
estimates
Optimise CHP size
Optimise thermal store
Update capital cost
estimates for selected
scheme
Finalise operating
model
Finalise energy prices
and incentives
Evironmental appraisal
Economic appraisal
Figure 8.1 Typical feasibility
study flow diagram
Reporting
period are as important as, and often more important than,
the maximum demands.
For building applications of chp there are usually significant
differences between winter and summer demands. An
understanding of these differences will be important in
determining the capacity and expected running hours for
the selected chp scheme.
In the ideal case, data that identify heat and power energy
demands at hourly intervals throughout the year will be
obtained from monitoring of electricity, heat or gas meters.
Where this is the case, it will be relatively easy to optimise
the chp size based on a full hour by hour simulation over
the year.
Data available from monthly energy bills will give a coarser
consumption profile that will identify how consumption
varies with season. However, these monthly profiles will
not give any guidance on how energy consumption profiles
vary on a daily or hourly basis. Using monthly data to assess
loads available for a chp scheme can be misleading and
over-optimistic where there is significant variation in
demand over 24 hours (e.g. between day and night). Using
monthly average profiles will tend to overestimate the
potential operating hours from chp during the shoulder
months.
Where the scope of data immediately available is not
deemed sufficient, particularly with respect to energy
consumption, specific energy surveys, temporary metering
and audits may be required. If time is available, sample
monitoring of meters on representative days (weekday and
weekend, heat and power demand data) in each month
would be beneficial; otherwise, days in late spring or early
autumn should be selected as it is in the shoulder months
where greatest accuracy is needed.
8.2.1.1
Electricity demand data
For larger sites, electricity half-hourly demand data are
normally available from the electricity supply company at
the supply meter point. Judgments must be made regarding
the suitability of this information; i.e. does the information
from the metering point accurately represent the consump­
tion of the building under consideration and are there other
buildings served from that point?
8.2.1.2
Combined heat and power for buildings
Heat demand data
Heat demand information is often available only for fuel
supplied on a monthly, or intermittent, basis. In these
circumstances, a dedicated monitoring exercise may be
required. Ideally, monitoring should be at the point of use
and include representative weekdays and weekends. In
converting from fuel use to heat demand, a pessimistic
boiler efficiency should be assumed.
——
distribution layouts
——
possible connection points.
Future changes to demand
Most chp generators in the size range being considered
(<1 MWe) will generate at 415 V using step-up or stepdown transformers to achieve other voltages. For larger
generators there may be a case for using an hv generator to
avoid the cost and space for the transformer. The hv
generators are more expensive and a detailed cost
comparison will be needed. There will also be staffing
implications from the need for qualified hv operators.
As well as considering existing energy consumption,
consideration should also be given to future changes in
consumption. These may be prompted by:
Approval from the distribution network operator (dno) to
connect the selected chp capacity and to export if needed
should be sought at the earliest opportunity.
8.2.1.3
——
implementation
measures
of
various
energy
efficiency
——
creating new facilities
——
discontinuing old processes
——
changes in operation, organisation or occupancy
patterns.
The impact of any projected changes must be considered
very carefully to assess whether the changes would enhance
or detract from the chp scheme viability, and to what extent.
These aspects may be evaluated by sensitivity analysis of
any calculations, i.e. by reviewing changes to calculated
outputs from the selective alteration of key input
parameters.
8.2.1.4
Demands in new buildings
In the case of new buildings, the heat and power demand
profiles must be estimated. Such estimates may be based on
a combination of:
System fault level information is required in relation to the
incoming supply system (information from the dno) and
for the building system. The existing fault levels will
determine whether or not there is fault capacity to accept a
new generator without requiring enhancements or upgrades
to system wiring or switchgear. Where system fault levels
are inadequate, the necessary alterations to switchgear and
wiring may make the project uneconomic.
The electrical distribution system and switchgear should
be examined to identify likely points into which the
generated supply may be fed and the extent of any additional
switchgear required. Likely points may be spare switchgear
or extendible boards.
If the anticipated site loads are such that the chp will need
to export electricity at certain times an export agreement
and a power purchase agreement will be required.
8.2.2.2
Heat systems
——
building design data
——
dynamic simulation model of the building
For the heat distribution systems the following should be
identified:
——
projected occupancy patterns
——
——
benchmark data from similar buildings
heating systems in use, e.g.
hws, steam, warm air
——
empirical data from energy models or consumption
codes for different buildings by type of use, floor
area, volume, etc.
——
operating temperatures, especially return tempera­
tures
——
users, peak loads and load profiles
——
existing plant performance, age and condition.
The confidence level attached to the demand profiles
derived must be recognised when selecting a suitable chp
plant rating.
8.2.2
Energy systems
Knowledge is required not only of the raw energy
consumption data, but also of how the energy is transferred
around the building.
8.2.2.1
Electrical systems
For electricity, the following information is required:
——
supply voltage, e.g. 11 kV/415 V
——
system voltages used in building, e.g. 415 V
——
system fault levels
——
switchgear arrangements
lthw, mthw, hthw,
Heat from chp is most effectively absorbed in systems with
an operating temperature of 80 ºC or below, and with a near
constant demand through the year.
Control and instrumentation systems also need consider­
ation to identify the extent to which any new plant could or
should be integrated into existing systems. At the simplest
level, a chp unit would be self-monitored by its own standalone controls, while at the most sophisticated level the chp
scheme will be remotely monitored by a physically distant
service organisation and be fully integrated with the
building’s own building energy management system
(bems).
The initial task is to identify the state of current control
systems and to determine in broad terms what the control
and operating strategies will be for the prospective new chp
scheme.
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8.2.3
33
Fuel
Fuel options for most chp plant are natural gas, lpg, gas oil,
biogas and liquid biofuels. For the majority of installations,
natural gas will be the fuel of first choice as it can be
supplied virtually on demand and requires no on-site
storage facility.
Exhaust
gas loss
19%
Heat loss from
engine and generator
5%
Electricity
34% generated
Fuel
100%
At this stage it is necessary to establish the condition of any
existing gas supply arrangement, in respect of:
——
pipe size, pressure, capacity
——
metering capacity
——
supply agreement details
——
users of gas on site.
availability and cost of providing supply
——
where gas could be used on site (apart from
plant).
Figure 8.2 Energy flows in a typical gas engine chp unit (turbocharged)
can be used to provide low temperature heating (see also
Table 9.2).
chp
The likely capacity of gas supply required to support the
chp plant and other users should be estimated. Where the
supply pressure available is not adequate, a gas pressure
booster may be required. This will impact upon energy
consumption, space and cost.
Contracts for the supply of gas should be investigated.
Contracts may be for firm or, for the larger units, interrup­
tible supplies. Interruptible gas is cheaper than a firm gas
supply but the likely chance of a gas interruption should be
considered and taken into account; unless a standby fuel is
available, the use of interruptible gas may result in consider­
able expenditure in importing electricity during peak tariff
periods.
Dual-fuel options, which will necessitate some liquid fuel
storage on site, may be considered for engines over 500 kWe.
These engines benefit from higher electrical efficiency but
still require some pilot oil use when running on gas. They
can be run only on oil to take advantage of an interruptible
gas supply.
8.3
Useful
heat
recovery
6%
Intercooler
heat rejection
Where gas is not immediately available, it is necessary to
establish:
——
36%
CHP performance, heat
recovery options
An early decision will be the operating temperatures and
the impact on the chp design. Consideration should be
given to whether heat recovery from the intercooler is
feasible and the amount of heat recovery possible from the
exhaust gases. Figure 8.2 shows the energy flows from a chp
unit and the potential for heat recovery.
8.4
Optimum sizing of CHP
Once the heat and power demands have been established
the optimum chp size can be determined following the
approach outlined in section 4.4.
An operating model will be set up to enable the annual
energy flows arising from chp operation to be determined,
from which operating costs and savings can be evaluated.
This operating model needs to be subjected to sensitivity
runs on energy prices and also on variations in site energy
demands.
As it is not possible to continuously match heat and power
demands, the planned operating strategy will often require
one or more of the following:
——
additional heat from conventional boilers or heat
rejection
——
power importing or exporting
——
modulation of chp output.
The costs for a number of different operating strategies
may need to be tested prior to carrying out final optimisation
runs, for example:
——
Is exporting power more worthwhile than part-load
operation?
——
Is heat rejection more worthwhile than part-load
operation?
——
Is operating at night beneficial?
——
What is the best way to utilise a thermal store?
Particular attention should be paid to exhaust gas
temperature if high grade heat is required on site, e.g. to
raise steam. chp gas engines are fitted with increasingly
larger turbochargers in order to maximise the chp electrical
efficiency. This removes more energy from the exhaust
gases and hence lowers the exhaust gas temperature. Lower
temperature exhaust reduces the potential for high
temperature heat generation, especially steam raising.
8.5
In some cases the surplus heat from the engine that is
normally ventilated out of the chp enclosure or plant room
——
Thermal storage
The feasibility study should consider the benefits of
thermal storage and assess the optimum size and the
practical issues associated with installing the storage vessel.
The size of the store will be influenced by the selection of
operating temperatures. The potential benefits of a thermal
store are as follows:
It enables peaks in demand to be met by the chp by
smoothing the demand profile.
Combined heat and power for buildings
——
Night-time heat demands may be met with surplus
chp heat produced during the day (as the electricity
value at night is normally insufficient to justify chp
operation at night).
——
At times of low heat demand (in summer) the chp
can be operated for fewer hours but at higher
output. (Without a store the demand may be below
the chp unit’s acceptable turndown limit)
8.6
Tri-generation (CCHP)
The use of heat driven chillers is normally a second stage of
a feasibility study, once the case for a chp supplying heat
has been established. It is rare for the cooling demand to
determine the chp capacity so the usual approach is to
assess how much surplus heat is available from the chp in
summer and how well this matches the cooling demand.
The cooling demand profiles also need to be estimated to
enable the tri-generation system to be optimised.
Absorption chillers have a relatively high capital cost so
their operating hours need to be maximised, i.e. the
absorption chiller needs to be sized to meet a base load
cooling demand.
8.7
Integration with other low
carbon technologies
Capital cost / (£/kWe)
Other technologies to supply heat and power may need to
be considered especially for new-build projects and the
interaction with the chp system should be quantified to
ensure that two technologies are not competing to supply
the same demand.
8.8
Capital costs for gas-engine chp will generally fall in
specific terms (£/kWe) with the capacity of chp as shown in
Figure 8.3. These costs include the supply and installation
of the chp assuming the minimum amount of interfacing
with or alteration of existing systems which will need to be
assessed on a site specific basis. Costs are at 2010 price
levels.
Maintenance costs are provided in Figure 8.4. Although
these are expressed in p/kW·h of electricity generated for
comparison purposes it is more typical for maintenance
contracts to be written in terms of a fixed cost per hour of
operation, so operating at part load will effectively incur
additional maintenance costs per unit of energy produced.
Generally, specific maintenance costs reduce with the chp
capacity. Costs are provided at 2010 price levels.
Typical chp unit electrical efficiencies are shown in Figure
8.5. Efficiencies generally rise with the size of unit but there
are significant variations for any given size. Efficiencies are
given on gcv basis.
2500
8.9
Economic appraisal
2000
8.9.1
Simple payback period
1500
This is the simplest of appraisal techniques and calculates
how many years will elapse before the project capital costs
have been recovered by the operational cost savings.
1000
A typical economic calculation is shown in Table 8.1 for a
300 kWe plant sized to run for 5000 hours a year. The
formulae that can be used in a spreadsheet are given.
500
0
0
1000
1500
2000
2500
CHP electrical capacity / kWe
Figure 8.3 Typical capital costs for gas engine chp units (2010 price
levels) allowing for minimum interfaces with electrical and heating
systems
500
The basis of the calculation is first to compute the saving in
any hour of operation from the difference between the
conventional cost for producing the same amount of heat
and electricity that would be produced by the chp and the
chp operating cost (chp fuel + chp maintenance). When
the hourly saving has been calculated the annual saving is
2·5
45
40
2·0
Electrical efficiency / %
Maintenance cost / (p/kWe·h)
Typical capital and
maintenance costs and
efficiencies for gas-engine CHP
1·5
1·0
0·5
35
30
25
20
15
10
5
0
0
500
1000
1500
2000
CHP electrical capacity / kWe
2500
Figure 8.4 Typical maintenance costs for gas-engine chp units (2010
price levels)
0
0
500
1000
1500
2000
CHP electrical capacity / kWe
2500
Figure 8.5 Typical electrical efficiencies for gas engine chp units with
capacity
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Table 8.1 Example of estimation of chp savings and simple payback period using a spreadsheet
Item
Units
reference
Manual calculation
Spreadsheet formula
Example
Average electrical output
kWe
A
B2
300
Average heat output
kWt
B
B3
450
Overall chp efficiency
%
C
B4
80%
kW
D=(A+B)/C
B5=(B2+B3)/B4
938
Average electricity price
p/kW·h
E
B6
7
Gas/oil price
p/kW·h
F
B7
2
Fuel input (gross cv basis)
Conventional boiler efficiency
%
G
B8
80%
chp
maintenance costs
p/kW·h
H
B9
1.1
chp
hours run per year
hours
J
B10
5000
system costs:
— capital and installation
£
K
B12
300 000
L=AÍE/100
M=B/GÍF/100
N=L+M
B14=B2*B6/100
B15=(B3/B8)*B7/100
B16=B14+B15
21.00
11.25
32.25
£/h
£/h
£/h
P=DÍF/100
Q=AÍH/100
R=P+Q
B18=B5*B7/100
B19=B2*B9/100
B20=B18+B19
18.75
3.3
22.05
benefit:
— operating cost savings
— annual operating cost savings
£/h
£/year
S=N–R
T=SÍJ
B22=B16-B20
B23=B22*B10
10.2
51 000
Simple payback period
years
U=K/T
B24=B12/B23
5.9
chp
Conventional operating costs:
— electricity costs
£/h
— boiler fuel costs
£/h
— total conventional operating costs £/h
operating costs:
— fuel
— maintenance
— total chp operating costs
chp
chp
simply obtained by multiplying by the operating hours (in
this case 5000). The payback period is the capital cost
divided by the annual operating saving.
The electricity and gas prices used for these calculations is
an average price experienced by the user for the operating
period. For a more rigorous analysis, it may be necessary to
differentiate between energy consumption and costs in
winter and summer seasons or by month as a result of
different electricity or fuel prices.
This example shows a payback period of 5.9 years, which
typically would make the project worth investigating
further.
The accuracy of the final result depends upon the reliability
of input information. However, by setting up a spreadsheet
model it is a straightforward process to test the sensitivity
of the result to fluctuations in input parameters such as the
gas or electricity price.
Each organisation will have its own project evaluation
criteria. It should be noted that simple payback approach
assumes constant operational savings and ignores the
project benefits beyond the payback period (which may be
higher if energy prices rise). Where multiple investment
options are being compared a simple payback period is also
of limited value as the capital investments may vary
significantly. For a project that could generate variable
revenues over a period in excess of 10 years, or where there
are many options to evaluate, a discounted cashflow analysis
is more appropriate.
8.9.2
Discounted cashflow analysis
An alternative to the simple payback approach is the use of
discounted cashflow analysis. The underlying principle is
that the value of money is time dependent. For example,
the buying power of £1 today is greater than the buying
power of £1 in five years’ time. This is not as a result of
inflation but because the £1 today can be invested to provide
additional value in the future. The reduction in future
value is calculated by the use of a discount rate:
Discount factor in each year = 1 / (1 + r)n
where r is the discount rate (%) and n is the number of years
after initial investment.
For example, at a discount rate of 8%, an income of £1 in
five years’ time will be worth £0.68.
In comparing a range of options such as several different
sizes of chp and other low carbon heat source investments
there are two measures that can be used:
——
net present value (npv)
——
internal rate of return (irr)
The npv can be seen as the total value of the project
expressed in terms of a sum of money at today’s value,
equivalent to a capital cost. If the npv is positive then the
project is viable.
The npv calculation requires the discount rate and the term
of the analysis to be defined.
Combined heat and power for buildings
Table 8.2 Illustration of calculation of net present value (npv) and internal rate of return (irr)
Item
Year
0
Capital cost
Operating saving
Cashflow
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
300 000
—
51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000
–300 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000 51 000
Discount rate
8%
Discount factor
—
Discounted
cashflow
0.926
0.857
0.794
0.735
0.681
0.630
0.583
0.540
0.500
0.463
0.429
0.397
0.368
0.340
0.315
–300 000 47 222 43 724 40 485 37 487 34 710 32 139 29 758 27 554 25 513 23 623 21 873 20 253 18 753 17 364 16 077
Net present value 136 533
Internal rate
of return
14.9%
The irr is the discount rate that would result in a zero npv
and also requires the term of the analysis to be defined.
Both of these functions are available within Microsoft®
Excel; the ‘Help’ function will provide further guidance.
Each organisation will have a view on what discount rate
should be employed, depending on their cost of capital and
attitude to the perceived project risks.
The starting point of npv calculations is the identification
of the cash inflows and outflows for each year under
consideration.
The npv calculations shown in Table 8.2 analyse the same
300 kWe chp plant over a projected life of 15 years. In this
example, operating savings have been assumed to be
constant over the period but these could be changed
depending on the particular installation. For example,
maintenance costs may be predicted to rise over the 15 year
period as the chp ages or electricity and gas prices may be
predicted to rise.
The final value of npv represents the cash benefit at today’s
value of implementing the chp scheme as opposed to
retaining conventional arrangements. In this example, the
benefit is £136 553.
When a number of projects or schemes are being considered,
the one with the highest npv would be preferred.
The irr value for the project identifies the return that
money invested elsewhere would have to earn to give a
better return than the chosen project. Many companies and
organisations will set a ‘hurdle’ rate of return that must be
achieved for a project to receive funding. The threshold
rate may vary depending on the type of project being
considered.
Table 8.2 also shows the results of calculating the irr, which
in this case is 14.9%.
8.9.3
Sensitivity of results
For any appraisal technique, care must be taken regarding
the reliability of input data and the sensitivity of results to
changes. When using computer based spreadsheets, the
recalculation of results for various inputs is a simple matter.
The aim of any sensitivity analysis is to give confidence in
the project viability under variations in key project
parameters including:
——
heat and power demands
——
gas and electricity prices
——
capital expenditure.
As discussed in section 7 there may be incentive schemes
available that need to be included in the economic appraisal.
The availability of such schemes should be checked prior to
carrying out each analysis.
8.10
Financing options
8.10.1
Capital purchase
Under capital purchase the user of the chp scheme finances
the installation. By so doing the user gains all the financial
benefits and the greatest return on investment, but also
takes on all the risks. The decision on whether to pursue
the capital purchase route will depend on the availability of
capital or directly financed borrowing, other demands for
capital, and the company view on the management and
risks associated with the chp scheme.
Any bid for funds for capital purchase will undoubtedly
need a well presented financial case to demonstrate that the
project meets the necessary internal funding criteria. There
may also be a lead time between bidding and funds being
made available.
A risk assessment should be carried out. Some risks can be
mitigated through contracts, e.g. a guaranteed fixed price
construction contract, a long-term maintenance contract
and longer-term gas or electricity contracts.
8.10.2
Equipment supplier finance (ESF)
Under esf schemes, the equipment supplier finances the
purchase and installation of the chp plant, at no initial cost
to the user, and retains ownership of the plant. The user
normally pays for the fuel used by the chp plant, buys
electricity from the supplier, and receives the chp heat for
no additional charge.
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The equipment supplier recovers the cost of the chp unit by
charging for the generated electricity over a fixed contract
period of up to 15 years. No charge is levied for heat
recovered from the chp plant. The electricity price may be
at an agreed tariff, or at a set discount to imported electricity.
esf contracts will normally be long term, 10 to 15 years, and
so will need agreed review mechanisms to keep the benefits
of the project equitable to both user and supplier. Electricity
price charges may be varied based on an agreed indexing
formula.
chp equipment suppliers often have esf schemes under
their own brand name, which include design, installation,
monitoring and maintenance. The availability of a number
of such schemes opens the opportunity for competitive
tendering for esf.
Whichever esf scheme is chosen, the following factors
should be carefully considered:
——
what is included: equipment, modifications, fuels
——
what is excluded: equipment, modifications, fuels
——
performance guarantees
——
payments for non-availability from supplier
——
payments for poor efficiency
——
payments if the user cannot take the outputs
——
monitoring and maintenance arrangements
(including breakdown repairs and planned
overhauls)
——
length of contract (normally >10 years)
——
price, including standing and unit charges
——
basis of price calculation:
•
price review mechanism
•
responsibility for
CHPQA returns
licences,
approvals,
—
technical and financial soundness of the supplier
—
termination of contract, at full term or before
—
ownership of plant at termination
—
condition of plant at termination
—
options to buy chp plant before contract end.
The esf contract may contain some statement of guaranteed
performance, i.e. guaranteed number of hours running per
year and guaranteed power output, backed up by an agreed
scale of charges if performance targets are not achieved, but
the principle is that payments are only made for the energy
supplied.
Achievement of performance targets, and hence liability
for non-performance, is not solely the responsibility of the
esf provider. For instance, the contract may commit the
user to accepting all the heat energy from the engine. If the
user cannot utilise the heat, and heat rejection equipment
has not been installed, the plant will shut down on overtemperature. This situation may be caused by:
——
reductions in building demand following changes
in usage patterns
——
implementation of other energy saving measures
——
facilities being taken out of use for major renovation,
e.g. swimming pool repairs.
In these circumstances, the liability for non-performance of
the chp plant will rest with the user, not the esf provider.
Some chp users have started with an esf arrangement but
upon seeing the reliability and financial benefit of the chp
plant have purchased the plant outright from the esf
provider. In order that this option is available, the original
contract should include mechanisms for making such a
change. To assist this process, a schedule of plant values for
each year of the contract may be included.
Ultimately, an esf arrangement should represent a
partnership between supplier and user wherein the supplier
is able to recover the capital outlay in a reasonable period
and the user achieves acceptable savings.
8.10.3
Contract energy management (CEM)
Contract energy management (cem) is an extension of esf
schemes to a point where the cem company takes much
greater responsibility for the system, including purchase of
fuels and, in many cases, operation and maintenance of the
entire building energy systems, with the user buying the
energy provided. cem schemes will often form part of a total
energy supply service, part of which is chp. The company
may not be an equipment supplier but a service company
specialising in the installation and operation of energy
plant.
The cem company, which is funding the capital elements of
the project, has to recover its investments through the term
of the contract and make an appropriate profit. cem
arrangements may be one of the following options:
——
fixed fee: services are supplied for a fixed charge
irrespective of usage
——
energy supply: the user agrees to buy a certain
quantity of energy at an agreed unit price
——
shared savings: cem company and user share the chp
savings benefits.
The essence of a cem scheme is for a partnership between
the cem provider and user as with esf. Normally, on
termination of the cem contract, ownership of the plant
transfers to the user. This may be when the plant is 10 to 15
years old. The user needs to ensure, during original contract
negotiations, that at contract termination the plant will be
in a fit state for continued useful life and not in immediate
need of major refurbishment or replacement.
8.10.4
Energy service companies (ESCOs)
An esco is a further stage in contracting out energy
facilities. Under esco agreements the end user will define
the energy needs in terms of delivered result, e.g:
——
specified internal room temperatures
——
specified levels of illumination.
The esco then undertakes to provide the service in a costeffective manner. Under these arrangements the esco may
undertake:
Combined heat and power for buildings
——
installation of energy efficient plant, which may
include chp plant
(h)
——
operation and maintenance of energy producing
plant
——
maintenance of energy consuming plant
——
implementation of energy efficiency measures to
the building fabric, e.g. thermal insulation.
The aim is to secure funding approval to proceed to full
system specification, at which point, with more accurate
information to hand, the economic appraisal may be re-run
for confirmation of funding approval before going to
contract.
‘Energy performance contracting’ is a further type of
contract in which chp can be integrated.
8.10.5
Leasing
Leasing arrangements will provide financing for a chp
scheme, but will not confer any of the operating advantages
of esf or cem. Forms of lease commonly available include:
——
lease purchase, in which the client owns the plant
on expiry of the lease
——
operating lease, where the client is only effectively
renting the chp plant with no prospect of ownership.
In all cases options for leasing would need careful scrutiny
by suitably qualified people.
Joint ventures
8.10.6
A joint venture is where potential chp users and possibly
suppliers enter a funding partnership to install a chp
scheme. Such arrangements may beneficially introduce an
appropriate range of expertise. Where more than one
potential chp user is involved, it may bring a complementary
pattern of heat and power demand that no single user could
provide. A potential disadvantage is that is that they can be
costly, complex and time consuming to arrange.
financing options.
At any stage in the foregoing process, the scheme may be
determined to be unsuitable for development. In such
circumstances, the evidence for rejection should be reviewed to assess whether there are other conditions which
would make the scheme viable, for example:
——
changes in operating profile
——
inclusion or exclusion of other buildings
——
reassessment of financial criteria.
If the project is to be rejected, the reasons for that decision
should be recorded and retained with sufficient information
to allow a review after a period of time, or when other
factors alter.
8.11.2
Statement of requirements
The final task at the feasibility stage is to write the outline
statement of requirements that will identify the key features
of the proposed chp scheme, e.g:
——
heat and power rating (acceptable range)
——
operating hours per day
——
requirement for modulation of output, following
heat or power demands
——
requirement for heat rejection
8.11
Feasibility report
——
fuel supply
8.11.1
Recommendation
——
requirement for operation on mains failure
——
uses of heat
——
whether heat driven chillers are included
——
location of chp plant and auxiliaries
——
route of exhaust, pipework and cabling systems
——
provision of thermal storage
——
compatibility with existing heating systems and
controls or modifications required
——
noise and vibration requirements
——
arrangement for connection to electrical system
——
outline control requirements
——
outline maintenance strategy, in-house or contract
——
heat or power export
——
design and procurement strategies.
With the benefit of the economic appraisal and with
knowledge of the organisation’s requirements for
consideration of funding, all necessary information should
now be available to present to management a report that
should outline:
(a)
the technical solution:
•
chp
•
operating pattern
•
how it will be installed
•
modifications needed to existing systems
•
how it will be maintained
capacity
(b)
project capital costs
(c)
project operating savings
(d)
energy consumption savings
(e)
CO2 savings
(f)
other relevant issues, e.g. environmental impacts
(g)
economic appraisal results
This statement forms the essential detail upon which the
subsequent design will be based.
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Part 2: Project implementation
9
Design
9.1
Allocation of responsibilities
The design process ultimately leads to the detailed
specification of all aspects of the chp scheme, during the
course of which various choices and decisions will be made.
Before the specification is written, the division of
responsibilities not only for the design but also for the
installation, operation and maintenance of the plant needs
to be decided. Only when these decisions have been made
can the specification cover all aspects in a consistent
manner. It is possible to keep some options open until
further information on the costs of the options is available,
since the selection will depend on a consideration of the
benefits, as well as the risks, associated with each option.
The responsibility for the design and specification may be
divided among:
——
client’s engineer
——
consulting engineer
——
main contractor
——
chp
supplier.
The client needs to nominate at least one responsible
organisation to the following activities:
——
Initial design: this may be carried out by the client’s
engineer or the consulting engineer. The output
would be a concept design or performance
specification.
——
Detailed design: this may be carried out by the
client’s engineer or consulting engineer if using a
standard construction contract or the main
contractor or chp supplier if using a ‘design and
build’ type of contract. The chp supplier will design
the chp package. A main contractor is more
frequently used when the project involves more
extended scope of work including for example a
building or district heating. In some cases the
consulting engineer may be novated to the main
contractor to maintain design continuity.
——
Tender action: this would be carried out by the client
supported by the consulting engineer. Life cycle
costs should be compared, including chp main­
tenance.
——
Installation and construction: the main contractor or
supplier would be responsible for the instal­
lation of the chp. The chp supplier would normally
be appointed for commissioning even if they were
not directly involved in the installation. Where
there is a complex controls interface the main
contractor will also need to be closely involved at
the commissioning stage.
chp
——
Operation and maintenance: a suitable division of
responsibility would need to be agreed between the
client and the chp supplier (see also section 12.3.3).
The choice of who undertakes each element of the project
may be biased by organisational preferences and by the
scale of the project. A single small chp plant (<100 kWe) in
a local swimming pool may not warrant the involvement of
consultants. A hotel chain considering chp schemes for
several sites may benefit from a consultant’s input and from
a broader choice of equipment suppliers. It is often the case
that the main contractor route is followed for more complex
installations and in some cases the main contractor may
also be appointed as an energy services company (esco) to
operate the scheme under a long-term contract. In the latter
case there is clearly an advantage in placing the design
responsibility with the esco.
9.2
Health and safety aspects
The building services engineer, or others within the
organisation, must ensure compliance with all current
health and safety legislation. Items listed have particular
relevance to small-scale chp installations:
——
Construction (Design and Management) Regulations
2007
——
Electricity at Work Regulations 1989
——
Gas Safety (Installation and Use) Regulations 1998
——
Control of Noise at Work Regulations 2005
The following outlines some of the relevant points of each
of the above regulations; the reader must consult the
regulations and comply fully with them.
9.2.1
Construction (Design and
Management) Regulations 2007
The ‘CDM Regulations’ require the appointment by the
client of a planning co-ordinator, whose role is to ensure
that health and safety risks associated with the construction,
operation and demolition have been identified and
mitigated initially through the design phase. Any risks that
cannot be mitigated need to be documented and passed
through to the contractor and ultimately to the owner and
occupier. Designers will be appointed to carry out design
risk assessments. The use of chp will bring some additional
potential risks, especially in the area of operation, as regular
specialist maintenance will be required. Storage and
handling of materials and safe access will be important
issues.
9.2.2
Electricity at Work Regulations 1989
There is no mandatory scheme for the registration of
electrical contractors but there are several recognised
bodies to which electrical contractors may belong. These
include:
——
National Inspection
Installation
——
Electrical Contractors Association
——
Electrical Contractors Association (Scotland)
——
National Association of Professional Inspectors
and Testers.
9.2.3
Council
for
Electrical
Gas Safety (Installation and Use)
Regulations 1998
The Gas Safety (Installation and Use) Regulations 1998
require anyone installing and connecting gas fired plant in
domestic and commercial premises (e.g. schools, hospitals,
Combined heat and power for buildings
offices) to be registered with the Gas Safe Register for the
relevant equipment.
Gas fired chp engines implicitly have a risk of explosion
from gas leakage. This risk may be small, but it cannot be
ignored. Protective measures must be included from
inception and may include the following:
——
——
Dilution ventilation: even where there is adequate
ventilation to cool the engine, care must be taken to
ensure that there are no areas with little or no air
movement where gas may build up to dangerous
levels.
Gas leakage detection equipment: this will be linked
to audible and visible alarm systems and to the
engine control system. At a predetermined low
level, alarms and warnings should be activated. At
higher levels, the plant should shut down
automatically.
9.2.4
Control of Noise at Work Regulations
chp plant generates high levels of noise but, by the provision
of acoustic enclosures, the noise hazard may be minimised.
Chapter 5 of CIBSE Guide B (CIBSE, 2001–2) provides
details on the Control of Noise at Work Regulations 2005.
9.3
Energy balance for CHP and
heat recovery systems
engines liberate heat as the result of the combustion of
fuel. The heat that is not converted to electrical output may
be recovered at various temperatures as shown in Table 9.2
(typical figures, data will vary between chp units).
chp
Heat recovery, normally by heat exchanger to the
appropriate building services circuits, is dependent on
being able to match the building services and engine
parameters. The overall thermal efficiency of the chp
scheme may be as high as 90% where suitable applications
exist with low temperature heat demands. In many
applications, however, it is not possible to utilise all the
available heat, and a lower overall efficiency will be
achieved. Figure 9.1 shows a typical arrangement of a heat
recovery circuit from a gas engine chp unit.
Figure 9.1 illustrates the following features:
——
exhaust heat exchanger is in series with jacket
cooler
Combustion
air
Heat
rejection
Exhaust
gases
Turbocharger
Exhaust heat
exchanger
Table 9.2 Typical heat energy for two gas-engines
Item
Percentage of input energy available
for heat recovery (gcv basis)
Turbocharged
engine (500 kWe)
Naturally aspirated
engine (90 kWe)
Exhaust gases (c. 450–120 °C)
21%
17%
Jacket and oil cooling (80–95 °C)
15%
33%
After-coolers (45 °C)
6%
n/a
Alternator and engine block
radiation (30 °C)
5%
5%
Heat remaining in flue
gases (<120 °C)
19%
15%
(Electrical generation
34%
30%)
——
heat rejection from aftercooler is available at all
times
——
heat rejection from the main chp-side heat recovery
circuit can be included as an option, frost protection
must be considered.
More complex circuits are available when it is necessary to
supply heat at two different temperatures, for example low
pressure steam could be supplied from the exhaust heat
exchanger and low temperature hot water from the engine
jacket circuit.
On larger engines there may be two or three stages of turbocharging and some of the aftercooler heat can be usefully
recovered. Even on smaller engines, if a sufficiently low
return temperature is maintained under all demand
conditions, the intercooler heat can be included in the heat
recovery circuits.
For exhaust gas heat recovery, a shell-and-tube heat
exchanger is placed in the exhaust stream close to the
engine. For jacket water heat recovery, a plate heat
exchanger or similar is placed between the engine cooling
circuit and the building service being heated, usually the
main lthw circuit.
The rating of heat rejection equipment will depend on
whether it is required to reject all of the engine heat, (i.e. so
the chp can run at full output in electricity only mode) or
only a specified proportion of the heat is rejected (i.e. to
enable some flexibility of operation). This in turn will be
determined from assessments of the minimum heat loads
that may be expected from the building in planned
Heat
rejection
(optional)
Gasengine
jacket
To
building
heating
system
Oil
cooler
Start-up
valve
Typical limit of
CHP unit supply
Figure 9.1 Typical heat recovery
schematic for gas-engine chp
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operating periods. If the chp plant is to be used as a standby
generator, full heat rejection capacity is required.
As an alternative to heat rejection from an air cooler,
exhaust gases can be diverted from the exhaust heat
exchanger by means of a bypass stack. This is more
commonly used for gas turbines where all of the heat is
recovered from the exhaust gases.
Boiler
Heat
load
Boiler
X
9.4
System design: interfaces with
heating circuit
CHP
As discussed in section 4.5, there are a number of key
objectives for the integration of chp into a heating system:
Position A
——
that the chp unit should operate in preference to
the boilers (when it is economic to do so)
——
that when boilers also need to be used to meet the
heat demand the chp unit output remains at its
maximum heat output
Note: If thermal store used
then a non-return valve is
required at point X
——
that the heat recovery from the chp unit is optimised
Figure 9.2
——
that the chp unit is always able to generate useful
heat even at part load
——
that the heating system is designed so that return
temperatures do not result in the chp unit shutting
down unnecessarily
——
that the efficiency of the boilers is not significantly
worsened by the addition of the chp.
It is important to understand how the building heating
system has been designed. For example, heating systems
might comprise a variable volume system using two-port
control valves and variable speed pumps or a constant
volume system using three-port control valves and fixed
speed pumps. Either of these systems may be constant
temperature or variable temperature (weather compensated).
The boiler circuit may have a common primary pump or
each boiler may be separately pumped. There may be a
common ‘low loss header’ with multiple flows and returns.
There may be a mix of systems installed on larger sites/
buildings.
Part of the analysis of the heating system should involve a
consideration of operating temperatures to understand how
flow temperatures can be varied and, more importantly, the
likely variation of return temperatures which are solely a
function of the building heating systems and controls.
There are two principal ways of integrating the
into a heating circuit:
——
in series with the boilers
——
in parallel with the boilers.
9.4.1
chp
unit
Series arrangement
In this design (see Figure 9.2), the chp unit is connected to
either the common return supplying the boilers (position
A) or the common return from the heating system (position
B). The chp pump ensures a constant flow to the chp unit.
As this connection involves minimal impact on the boiler
circuit and its controls it is commonly used when
retrofitting chp into an existing building.
Thermal store
T
Hot
T
layer
T
T
Cold
layer T
T
chp
CHP
Position B
located in series with boilers
If the heating system uses variable flow control then the
return temperature will be approximately constant. When
the flow rate drops below that of the chp flow rate some
recirculation of chp flow will occur leading to higher
temperatures onto the chp and part load operation. If the
heating system is a constant flow system then the return
temperature will increase under part-load, unless weather
compensation is used, again resulting in part load operation
of the chp to match the load.
The benefit of this system is that the chp unit is always
used in preference to the boilers (meeting objective 1, see
section 4.5). If the required flow temperature is achieved by
the chp the boilers will not fire as they are controlled by the
boiler thermostats. The boiler thermostat should be set a
few degrees lower than the chp supply temperature.
A disadvantage of this circuit is that, as the return
temperature will be increased by the injection of heat from
the chp, any benefit from the use of condensing boilers to
meet the remaining heat demand is likely to be significantly
reduced. The addition of chp in series with condensing
boilers could lead to a loss of efficiency of the boilers.
The chp will remain at maximum output at times of high
heat demand as it will continue to receive a constant flow of
water and will be unaffected by the boiler operation, thus
meeting objective 2.
To optimise the heat recovery from the chp unit (objective
3) the selection of operating temperatures for the heating
circuit need to be considered. If heat recovery from the
intercooler is to be achieved, consistently low return
temperatures will be needed (typically 40 ºC to 45 ºC). Low
flow and return temperatures will also enable maximum
heat recovery from the exhaust gases. If the chp unit is to
continue to operate with maximum heat recovery under
part-load, the return temperature must not rise above the
manufacturer’s set point at which part load operation
commences (typically 75–80 ºC). This operating limit
should be checked with the chp supplier.
Although the chp unit is connected to the lowest
temperature part of the heating circuit, it is still possible
Combined heat and power for buildings
that the chp will modulate down or turn off if the return
temperature is allowed to rise under part-load (objective 4).
With constant volume circuits and three-port valves this
could easily occur. The result would be that the chp
modulates down and ultimately turns off even though there
is sufficient load to maintain it in operation. This situation
should be avoided by changing at least part of the system to
two-port controls to limit recirculation and to check that
there are no fixed bypasses in the system. If weather
compensation is used then the flow and return temperatures
will be lower under part-load and the risk of the chp turning
off unnecessarily is reduced.
It will generally be better to install the chp in a common
return before the low loss header (position B in Figure 9.2)
to avoid recirculation via the header. This may involve
significant changes to pipework in order to combine the
returns from several circuits.
Flow
header
CHP
Boiler
Boiler
Heat
load
DPS
Variable
speed
pumps
Pumps are controlled in
sequence to ensure maximum
heat from CHP and to control
flow from flow header to return
header to near zero
Figure 9.3
chp
Return
header
DPS = differential
pressure sensor
connected in parallel with boilers
T
A thermal store can be added to this circuit as shown in
Figure 9.2 with an additional pump in the circuit. The
store discharge pump can then be sized to deliver more flow
than the chp plant potentially meeting peak demands from
the site.
9.4.2
T
T
CHP
Boiler
Objective 2 requires the chp heat output to be maintained
when the boilers are operating, which is more complex to
achieve with this circuit especially where the capacity of
the first boiler to be enabled is similar to or greater than
that of the chp.
If there is a low loss header in the circuit, the chp flow rate
and boiler flow rate would be maintained but the return
water temperature would rise as a result of recirculation of
flow water into the return via the header. As a result, the
chp would modulate down and the load would be shared
between the chp and the boilers. To avoid this problem and
maintain the chp heat output at maximum output the flow
rate through the boiler would need to be controlled, either
with a modulating valve or a variable speed pump so as to
prevent the recirculation flow in the header and thus
maintain the return temperature onto the chp unit. A
suitable control signal could be provided from the difference
in temperature between the return water from the load and
the return water from the header. However, this would be
difficult to achieve if there are multiple zone circuits that
may be designed with different return temperatures. A
better solution would be to split the header into two parts
(flow and return) and arrange for a bypass to be installed
with a flow sensor so that the recirculation flow can be
measured directly, e.g. with an orifice plate or regulating
valve. The controls will also need to be set such that any
minimum flow rate required through the boiler (as defined
by the manufacturer) is always achieved once the boiler is
enabled. This circuit is shown in Figure 9.3.
The above controls issues are more easily resolved when
there is a thermal store in the circuit. In this case the excess
flow when the boiler operates can be accommodated by the
thermal store and the boiler can be turned on and off to
maintain the top of the store at a set temperature without
Heat
load
T
T
Parallel arrangement
In this design, the chp unit is connected between flow and
return in parallel with the boilers. Objective 1 can be
achieved by designating the chp unit as the lead boiler in
the boiler sequencer controls.
Boiler
Thermal
store Hot layer
Cool layer
T
Figure 9.4
chp
connected in parallel with thermal store
affecting the running of the chp (see Figure 9.4). Further
details on the control of a thermal store with chp are given
below.
Optimising the heat recovery (objective 3) can be achieved
with this circuit provided the system temperatures are
selected appropriately and preferably a variable volume
system is used so that return temperatures are maintained
at low levels. The system can incorporate condensing
boilers as the chp will not raise the return temperature onto
the boilers.
If a common primary pump is used there will need to be
motorised valves on the chp unit and boilers to control the
flow to each heating unit but separate pumps for each heat
source would normally be a more efficient pumping
arrangement.
In both of these circuits, if there is a heat rejection circuit
incorporated this should be interlocked with the boiler
controls to prevent boiler firing if the chp heat is not being
fully utilised.
9.4.3
Operation of CHP with a
thermal store
A thermal store will only be successful with a variable flow
building heating system that can maintain low and constant
return temperatures so that the stored energy is maximised.
The simplest form of a thermal store operates automatically
as it is inherently self balancing. When the demand for heat
is less than the heat output of the chp there will be surplus
flow from the chp into the store and the store will fill with
the flow water. When the demand is greater than the chp
output there will be insufficient flow from the chp and
some water will flow out of the store to meet the demand.
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The chp controls will be set so as to fill the store and turn
the chp off when it is nearly fully charged with water at the
flow temperature. The chp will turn on again when the
temperature at or near the top of the store is below a set
point and the store is nearly fully discharged, giving ‘room’
for the chp to generate again. There is no benefit in storing
boiler heat so the boilers should be controlled to maintain
the top of the store at the required flow temperature with
this control set-point a few degrees below that of the chp
set-point.
The store is always full of water and relies on the
stratification between the hotter flow layer and the cooler
return layer. If there is a large difference between these
temperatures the degree of mixing between the layers will
be reduced. Operation of the store over a period of time will
lead to a gradual increase in the depth of the mixing layer.
At intervals the store will need to be ‘refreshed’ by filling it
completely with water at the flow temperature. This may
happen anyway as a result of a normal daily cycle, e.g. at the
end of the day the store may be completely full of flow water
at high temperature ready for the night period; however at
other times it may be necessary to temporarily arrange for
the standby boilers or chp to operate in order to completely
fill the store.
43
highest temperature part of the circuit upstream of
any mixing valves.
——
The temperature drop across the absorption chiller
on the hot water side can be small and the return
temperatures at both full and part load need to be
checked against the maximum chp return tempera­
ture.
——
The absorption chiller needs to operate against a
baseload cooling demand to maximise its running
hours. The simplest way to achieve this is to use the
absorption chiller to pre-cool the chilled water
return to the main electric chillers.
——
In analysing the economic case for an absorption
chiller in a new-build scheme, a decision needs to
be made as to whether the capacity of the main
electric chillers will be reduced such that the
additional cost for the absorption chiller is the
extra-over cost compared to an electric chiller. If
the capacity of the electric chillers is reduced then
the availability of the chp and absorption chiller in
the summer needs to be considered taking account
of chp maintenance downtime.
9.6
9.4.4
Control of flow temperature
off CHP unit
When the chp unit is operating at full output, there will be
a nearly constant rise in temperature across the connected
heating circuit. The designer will need to consider if this
raises issues for the other parts of the circuit. For example,
if the return temperature is low under part-load the flow
temperature off the chp will also be lower than the design
set-point. This could lead to unnecessary boiler firing, less
heat being stored in a thermal store or more pumping
energy on the distribution system. Normally a fixed flow
temperature is required from the chp unit and a mixing
circuit should be used to control the flow temperature off
the unit by injecting flow water into the return as required.
A more detailed discussion of the issues of interfacing chp
with boiler systems is given in the BSRIA Guide BG 2/2007
(BSRIA, 2007) and the HVCA Good Practice Guide TR37
(HVCA, 2008). chp suppliers will also be able to provide
guidance.
9.4.5
Small-scale CHP systems (<50 kWe)
Small-scale chp system suppliers produce a range of
packages that incorporate all the necessary controls and
often include a thermal store. However, the common issues
outlined above still apply, i.e. the need to design heating
circuits with lower return temperatures of 50 °C or below,
and to avoid recirculation of flow water into the return.
9.5
System design: absorption
chillers
Absorption chillers can be incorporated as simply another
heating demand in the main circuit; however, the following
points need to be considered:
——
With single effect absorption chillers the capital
cost is dependent on the temperature of hot water
supplied so the connection should be made to the
System design: electrical
interface
Power from the generator (normally at 415 V, 50 Hz,
3-phase) will be connected to the building’s electrical
distribution system at a convenient location. This may be
at a spare breaker cubicle on an existing busbar or at a new
bus-section within the associated switchgear.
In all cases, the building power distribution system must be
checked to ensure that system fault levels are not exceeded.
If fault levels are likely to be exceeded, additional reinforce­
ment of the distribution system may be required.
Where power distribution systems operate at 11 kV then
415 V generators and step-up transformers may be used as
an alternative to generation at 11 kV. Low voltage generators
and transformers are likely to be the preferred option below
2 MWe.
In most cases the chp generator will be connected to the
public electricity supply and will be operated in parallel. It
is necessary to obtain a Connection Agreement with the
local distribution network operator (dno). Contact should
be made with the dno as early as possible. The Electricity
Networks Association publishes the following guides,
which show how the Connection Agreement can be
obtained. These guides also refer to the other documents
that may be relevant.
——
Distributed Generation Connection Guide: A Guide for
connecting generation that falls under G59/2 to the
distribution network (ENA, 2011a)
——
Distributed Generation Connection Guide: A Guide for
connecting generation that falls under G83/1 (Stages 1
and 2) to the distribution network (ENA, 2011b).
The G83/1 is for chp units below 11.04 kWe 3-phase and
3.68 kWe for single phase.
Where a standby power facility is required, special care
must be taken to ensure that loads seen by the generator
under standby power conditions are within the generator’s
Heat
output
Combined heat and power for buildings
Generator
protection
Load
protection
Supply
protection
Synchronisation
Building
PES
Alternator
Prime mover
M
Generator
contactor
Mains
switch
Metering
Building
——
IGEM/UP/6: Application of compressors to natural gas
fuel systems (IGEM, 2009b)
——
IGEM/UP/9: Application of natural gas and fuel oil
systems to gas turbines and supplementary and auxiliaryfired burners (IGEM, 2004)
A chp unit must not be specified as a standby generator for
safety critical systems as there will be periods when the chp
will be on outage for maintenance.
A typical connection schematic is shown in Figure 9.5
above. The chp control panel will also provide power to the
chp auxiliary equipment.
9.7
Fuel system
Natural gas is available in most areas of the UK and to most
sites where a chp scheme is likely to be considered. The
pressure of the gas may be suitable for smaller spark ignition
engines but gas boosters may be required for larger higher
efficiency engines. The building services engineer should
ensure that the pressure and capacity of the current system
are adequate to satisfy the needs of the proposed chp system
and other usage on site. If long distances are involved
between the gas supply and the chp installation, adequate
allowances must be made for pressure drop.
If the site supply pressure is marginal or low, it may be
possible to negotiate for gas to be supplied at a higher
supply pressure instead of installing a pressure booster at
site. The capital and operating costs (i.e. electricity use) for
gas compressors can be significant, especially for gas
turbines where higher pressure gas is required.
The minimum equipment configuration and testing
necessary for the safe installation of a gas fuelled engine are
described in the following publications issued by the
Institution of Gas Engineers and Managers:
——
IGEM/UP/1: Soundness testing and purging of
industrial and commercial gas installations (IGEM,
2005a)
——
IGEM/UP/2: Gas installation pipework, boosters and
compressors on industrial and commercial premises
(IGEM, 2005b)
——
IGEM/UP/3: Gas fuelled spark ignition and dual
fuel engines (IGEM, undated)
——
IGEM/UP/4: Commissioning of gas fired plant on
industrial and commercial premises (IGEM, 2009a)
PES
Figure 9.5 Typical electrical
connection arrangement
(pes = public electricity supply)
Supply LV loads
capacity. If there is a shutdown and a need for the gas engine
to take on load immediately after starting, the rate at which
load is imposed on the unit needs to be carefully controlled.
PES
supply
9.8
Combustion exhaust system
The primary function of the exhaust system is to carry the
products of combustion away from the engine safely. As
engines are often located in basements, and exhaust outlets
are typically at roof level, careful consideration must be
given to exhaust duct routing and insulation to contain
heat, vibration and noise. Catalytic converters may be
included in the exhaust system either separately or
combined with silencers. A typical system is shown in
Figure 9.6. Care must be taken to ensure that exhaust gases
are not re-circulated into the building or engine intake
systems. Guidance on the avoidance of recirculation may
be found in CIBSE TM21: Minimising pollution at air intakes
(CIBSE 1999).
The design of the exhaust system must consider the effects
of over-pressure and vacuum which can occur during backfires.
9.9
Combustion and ventilation
air systems
An air supply system is required at the engine for
combustion, general cooling and ventilation.
The two functions, i.e. cooling air supply and combustion
air supply, may be satisfied by common or separate systems.
For very small installations (<100 kWe) it may be perfectly
satisfactory to draw cooling and combustion air directly
from the surrounding plant room without recourse to
special ducting, provided the plant room is naturally
ventilated. For larger engines, separate fresh air supply
ducting is normally used in order to obtain sufficiently cool
combustion air and to obtain a cleaner air supply. Since
engine power output reduces as charge air temperature
increases, care must be taken with the location of
combustion air intakes to avoid recirculation.
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Features of exhaust system:
• Long radius bends in exhaust to minimise back pressure
• Flexible connections to allow for expansion and vibration
• Vibration/noise attenuation measures in pipe supports
• Condensate drain traps at appropriate positions
• Horizontal sections slope towards drains
• All welded construction recommended
Absorptive
stainless
steel
silencer
Rigid support
Sliding support
Reactive
stainless steel
silencer
CHP
unit
Exhaust heat exchanger
Condensate
trap and drain
Condensate trap
and drain
Figure 9.6 Typical exhaust
system
Although the majority of the available heat from the engine
is recovered, a significant amount of heat radiated from the
engine surfaces and rejected from an air-cooled alternator
needs to be dissipated. Typically this heat is about 5% of the
fuel input (see Table 9.2). This is most easily achieved by
providing a once-through ventilation system to the unit
enclosure or plant room. Air may be drawn from the plant
room; however, this is likely to be at an elevated temperature
and may have some contaminants and so an external air
supply is preferable. To minimise the electricity use of the
ventilation fans low pressure ducts are used and the space
for this ductwork and the location of the air inlet and outlet
terminations are often critical in determining the location
and feasibility of the chp installation.
——
modulate output when running to match the heat
or power demand, or the electricity tariff
——
adjust alternator excitation to achieve a desired
power factor
——
monitor performance of the engine and shed load
or shut down if required
——
revert to predetermined safe conditions on any
failure or parameter excursion
——
connect and disconnect the generator from the
building electrical distribution system
——
provide power supplies to chp auxiliary equipment.
In some cases this heat rejection can be used for low grade
process use such as air heating of greenhouses. It would also
be possible to reduce the volumes of air, and hence fan
power, by using a chiller to cool the air with heat recovery
from the chiller condensers, i.e. acting as a heat pump.
These functions will be achieved by the chp unit controls
however the local bems may be configured to interface with
the chp system so that the building owner can have visibility
of the chp operation. The key interfaces with the bems are
likely to include:
9.10
Control systems
——
start/stop signal based on time control to suit the
site and the electricity supply contract prices
——
Control, instrumentation and monitoring of chp systems is
concerned with:
status of the chp unit (e.g. started/running/
synchronised/stopped/tripped)
——
output of the chp unit (e.g. kW generated)
——
ensuring that the
efficiently
——
——
integrating the heat produced with the building
heat systems
monitoring of energy meters and circuit
temperatures (although these may be directly
monitored rather than through an interface with
the chp controls).
——
synchronising, paralleling and disconnecting the
generator safely
An overview of the structure of a typical controls system is
given in Figure 9.7 below.
——
monitoring the chp plant for performance,
maintenance and accounting purposes.
chp
engine runs safely and
Systems are typically designed around microprocessor
controllers communicating with remote pc-based control
and monitoring stations, often at the chp plant supplier’s
offices.
The control system will be required to:
——
stop and start the engine at predetermined times
and/or match building loads or electrical tariffs
9.11
Maintenance facilities
In designing the chp system provision needs to be made for
any facilities required for the maintenance of the equipment.
Access to the chp prime mover will be required on a regular
basis with sufficient space provided to carry out the work in
a safe manner. Where there are multiple chp units it is
desirable to be able to maintain one unit whilst the other is
in operation, which implies the use of separate acoustic
enclosures.
Combined heat and power for buildings
Figure 9.7 Overview of control
systems for chp
Distribution switchboard
Generator
Synchronisation
Mains monitoring and protection
Metering
Generator control,
monitoring and protection
Engine
Engine
control, monitoring
and protection
Fuel system
monitoring and
protection
Fuel
system
Heat
recovery
system
Heat recovering
control, monitoring
and protection
CHP
CHP controls
Modem link to remote
monitoring and control
positions, e.g.
maintenance contractor
Building
heat
systems
Plant room
monitoring and
control position
There may be a requirement to provide storage facilities for
tools and consumables and an early discussion with the chp
supplier, who may also be appointed to carry out the
maintenance, is recommended.
The storage and handling of lubricating oil requires
particular attention to minimise health and safety risks
during delivery of new and removal of used oil. Larger
systems will typically use on-site storage of ‘clean’ and
‘dirty’ oil.
9.12
Mains
electricity
supply
Control of noise and vibration
Prime movers used for chp will always require some form of
enclosure and mounting to provide attenuation of:
——
airborne noise
——
structure-borne noise
——
exhaust and ventilation systems noise
——
vibration from engine feet and pipe systems.
In all cases, it is the responsibility of the owner to specify
the noise and vibration requirements for the installation. In
many cases, packaged solutions that include an acoustic
enclosure may be all that is required. However, in other
circumstances, such as where very stringent noise limits are
required or where transmitted vibration could be a cause
for complaint, detailed monitoring and evaluation of the
building may be required, together with special attention to
use of acoustic treatment and anti-vibration mounts. This
is a complex area that will often require specialist advice.
BEMS
Figure 9.8 opposite illustrates the following measures,
which may be required to achieve appropriate noise and
vibration attenuation:
——
A: a concrete plinth or inertia base isolated from
the plant room floor with suitable resilient material
——
B: anti-vibration mounts between the plinth and
module frame
——
C: anti-vibration mounts between the module
frame and engine/generator base plate
——
D: flexible connections on all pipe systems to and
from the engine and generator
——
E: generous bends in electrical cables
——
F: noise attenuating ducts on the ventilation supply
and exhaust to plant room and module
——
G: appropriate penetration details to maintain the
construction’s sound insulation performance where
ducts, pipes, cables, exhaust flues pass through
module and plant room boundaries
——
H: flexible connection(s) in exhaust flues to
accommodate expansion and attenuate vibration
——
I: noise/vibration attenuating pipe supports
——
J: silencer(s) in exhaust system
——
K: acoustic cladding of module
——
L: acoustic cladding of plant room walls and ceiling
——
M: acoustic cladding of doors with acoustic seals to
module and plant room
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(I)
(G)
(N)
(J)
(N)
Figure 9.8 Potential approaches
to noise and vibration control
(L)
(H)
(K)
(G)
(F)
(F)
(J)
(F)
(F)
(H)
(E)
Engine
(M)
Plant
room
floor
(M)
Engine and
generator
bed plate
Generator
Module bed
plate
(C)
(D)
(N)
(A)
——
(E)
Concrete plinth
N: vibration-absorbent packing between pipes and
pipe clamps.
Not all the measures shown will be necessary in every
installation. However, if required, a very high degree of
noise and vibration attenuation may be achieved. For
example a chp unit installed in an office block, directly
adjacent to executive facilities, may require a very high
degree of attenuation, whereas a chp unit installed in a
detached boiler house may require a much lower degree of
attenuation.
Most small chp units, up to about 500 kWe, will normally
be supplied with a dedicated acoustic enclosure. Larger
machines may be installed in plant rooms without an
acoustic enclosure where the plant room itself is designed
for acoustic control. Alternatively a larger engine may have
an acoustic enclosure installed on site around the unit. A
key issue to consider the provision of a suitable environment
for maintenance of the engine with sufficient space and for
noise levels to be low enough for a working environment
including for the case where multiple units are installed
and other chp units may be in operation.
Weatherproof acoustic enclosures may also be specified
allowing the unit to be installed outside the building on a
suitable hardstand.
Exhaust noise attenuation can be achieved by the careful
selection of silencers. Depending on the location and route
of the exhaust, noise may need to be minimised along its
route as well as at the outlet. In situations where there are
buildings nearby, the problems of minimising transmitted
or reflected noise must also be considered. Specialist advice
may be required in this area.
Flexible connections in pipe systems should be fitted in
strict accordance with the manufacturer’s recommendations.
The function of the flexible connection is to provide
vibration isolation, not to correct for pipe misalignment. If
it is used in that manner, it may fail prematurely.
In addition to the main chp installation the noise impact
from auxiliary equipment will need to be assessed. In
particular heat rejection equipment, whether for the main
(B)
Noise-absorbent
layer between
frame and plinth
heat recovery circuit or the intercooler, can often be
overlooked. As the heat rejection equipment needs to be in
free air it is difficult to provide further attenuation after the
coils and fans have been sized.
Detailed guidance on noise and vibration criteria and their
control is set down in chapter 5 of CIBSE Guide B (CIBSE,
2001–2).
9.13
Fire and gas detection
and protection
Whilst fire and gas detection systems are not a mandatory
requirement, many buildings’ insurance companies will
require some form of protection/detection. At the lowest
level, this will be a simple detector linked into the normal
building fire alarm/warning system. At the other extreme,
fire/gas detectors will be linked to the engine control and
gas supply system, as well as the building alarm system.
Automatic gas supply shut-off valves will be required where
chp units are installed alongside conventional boilers.
Where required, automatic module fire suppression systems
may also be installed. The necessary level of detection,
protection and suppression must be determined for each
installation.
9.14
Regulatory compliance
and approvals
The main regulatory system at present is the Climate
Change Levy exemption available for ‘good quality’ chp. To
achieve this exemption, annual fuel use, useful heat
produced and electricity generated need to be measured
using meters that comply with an accuracy standard.
Approvals in the form of a connection agreement will need
to be obtained from the local district network operator
(dno) to connect the chp unit and to export power if this is
envisaged. The dno will need to witness the testing of the
G59-compliant (ENA, 2011a) controller before permitting
operation.
Combined heat and power for buildings
9.15
Specification: typical contents
for CHP package specification
Demarcations between CHP contract and others
The most fundamental part of the specification is to define
the scope of supply. This is partly achieved by clearly
defining demarcation points for:
Space available, internal or external siting
A ground floor location is recommended. Restrictions on
siting the unit and requirements if it is to be installed
externally. Consideration needs to be given to the space
required for routine maintenance and for the subsequent
removal of the chp for major overhauls/repairs.
——
heating circuits
Fuel supply
——
electrical connections
The type of fuel available and its supply pressure.
——
fuel supply
——
flue termination
——
ventilation inlet and outlet
——
whether interconnecting pipework to heat rejection
equipment is included
——
bems
——
telephone connection for external communication
——
make-up water to engine cooling circuit
——
lubricating oil storage and delivery system
——
drain points
——
civil works
——
floor finish.
interfaces
CHP capacity
The required capacity of the chp unit(s) will need to be
defined. This may be expressed in terms of its electrical or
heat output, although the heat capacity is more logical as it
is the heat demand that determines the chp size. However,
it is important not to be too restrictive about the required
capacity as a range can be specified to allow suppliers to
offer standard units from which the preferred option can be
selected.
Voltage generated
The generator voltage will need to be specified and, if low
voltage is preferred, whether a transformer is to be included
as part of the package
Exhaust termination
A complete exhaust system may be specified including the
height at which the exhaust should terminate. Alternatively
the limit to the exhaust system from which others will
connect will be defined, together with an initial deter­
mination of the acceptable backpressure.
Acoustic constraints
The acoustic constraints on the design need to be provided,
normally following either the planning conditions or
recommendations of an acoustic report.
NOx limits
Allowable NOx limits should be given.
Other planning conditions
There may be specific planning conditions that need to be
met.
Fire detection/suppression and interface with main fire
detection system
Specific requirements for fire detection and suppression
including the need for interfacing with main plant room
systems.
Heating circuit temperatures
Controls and mode of operation
The flow and return temperatures under design conditions
(maximum heat output) need to be given together with the
likely range of these under part load conditions.
Description of how the plant is expected to be operated to
meet heat or electricity demands, to modulate in output
and any restrictions on time of operation; anticipated
number of starts.
Heat rejection requirements
The requirements for heat rejection from the unit need to
be defined, e.g. whether all of the heat from the unit needs
to be capable of being rejected to maintain electricity
output.
Monitoring and BEMS interface
Requirement to provide an interface to a bems for
monitoring purposes, e.g. ‘run’, ‘trip’ and meter outputs.
Ambient temperatures
Metering
The maximum and minimum ambient air temperatures at
which the heat rejection equipment needs to be designed to
should be specified.
The meters to be installed should be specified, together
with accuracy standards commensurate with CHPQA
requirements.
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Lubricating oil system
9.16
The requirements for handling lubricating oil during
changes, and the need for clean and dirty oil storage on site
if required.
District heating (dh) is increasingly recognised as an
important option to deliver low carbon heating supply. In
many cases, chp systems are the preferred heat source for
dh, although biomass boilers are also used. A full treatment
of the design of district heating is not provided here and
reference should be made to other guidance, in particular:
Delivery
Specific constraints to be provided, e.g. availability of
lifting equipment, times at which delivery can be made,
responsibility for off-loading and positioning.
Commissioning
Design of district heating
——
Technical Guide to District Heating (BRE, 2012)
——
Research reports and guides published by the
International Energy Agency District Heating and
Cooling Annex (IEA, 2011)
——
Guidelines for District Heating Substations (Euroheat,
2008).
Scope of commissioning activities, requirements to provide
information on commissioning including commissioning
procedures, any impact on site activities, recording of
commissioning results, witnessing by client representative.
In developing a district heating system design there are a
number of key issues to be considered.
Off-site testing
The operating temperatures to be used
Requirements for testing and acceptance criteria.
Arrangement for test including notice to be given to client
for witnessing of tests. Whether tests are on-load or
functional.
Specific requirements for documentation and format of
documentation, drawings, manuals, test certificates.
systems will be more cost-effective if the temperature
difference between flow and return is maximised so that
flow rates are reduced. The flow temperature is normally
limited to a maximum of 130 °C so that a long life is
achieved for the pre-insulated pipe systems. Lower flow
temperatures would be more appropriate for gas engine chp
systems. Return temperatures should be reduced as far as
possible, although an economic balance is reached where
low return temperatures would result in higher costs for
larger radiators or air handling unit coils than the cost
savings on the dh network. It is recommended that, for new
systems, radiator circuit temperatures of 70 ºC (flow) and
40 °C (return) are used with a maximum return temperature
of 25 °C from instantaneous domestic hot water heat
exchangers. Lower temperatures will help ensure that dh
systems are compatible with other low carbon heat sources
in the future including extraction of heat from steam
turbine power stations and large-scale heat pumps.
Maintenance contract
Whether there is hydraulic separation at the
connections to buildings or dwellings
On-site testing
The requirements for performance tests and reliability tests
to be given including acceptance criteria. Procedure to be
followed if performance test does not pass and any
compensation (liquidated damages payments).
Documentation
It is recommended that a maintenance contract is offered at
the same time as the tender is submitted for the supply of
the unit. Key requirements for this contract are to be given
including: period of contract, guarantees on availability,
principles of compensation and indexing of costs.
Training
Training to be provided to client’s personnel to be specified.
Requirements to liaise with DNO
Any requirements to liaise with the dno to arrange witness
tests and provide ‘G59’-compliant equipment.
Requirements to liaise with others
There may be requirements to liaise with other organisations
to carry out tests, e.g. Fire Officer.
dh
The dh system water can be used directly in the building or
dwelling heating system, or indirectly by installing a plate
heat exchanger. If a heat exchanger is used the dh system is
protected from contamination by the building heating
system and there is more flexibility in the choice of dh
operating temperatures and pressures. However, the
additional cost and complexity mean that direct connection
is often used, especially for connecting individual dwellings.
A direct connection will minimise the return temperature
as there is no temperature difference required at the
interface, resulting in a small improvement in dh efficiency.
In addition, the dh system pressure difference will provide
the circulation pressure for the dwelling avoiding the
energy use of a secondary pump.
The way in which domestic hot water is produced
Domestic hot water can be produced using an indirect coil
in a cylinder or through an instantaneous plate heat
exchanger. The latter will result in much lower return
temperatures, which will be of benefit to the dh system.
Combined heat and power for buildings
The control of design (maximum) flow rates
The design of internal pipe distribution in housing
An essential requirement of a dh system is to maintain
balanced flows, i.e. the flow rate taken by any building or
dwelling should be limited to the maximum design value.
This is achieved by using differential pressure control
valves at each supply point.
Where there are significant lengths of distribution pipework
within a block of flats care must be taken to prevent heat
losses from the pipes and hydraulic interface units causing
overheating in summer. Horizontal runs in long unventi­
lated corridors are to be avoided. It is often preferable to
use more risers than to rely on horizontal distribution. The
aim should be to minimise the lengths of distribution. If
risers are located within the dwelling, provision should be
made for the risers to be ventilated at high level to ensure
unwanted heat can be dissipated in summer. Such
ventilation paths can be shut off in winter to enable pipe
heat losses to provide useful heat to the building.
The use of variable flow control principles
It is preferable to adopt a variable volume control system
for the dh system and all of the building heating systems
connected. This will ensure that pumping energy is
minimised through reducing the volume of water to be
pumped and the pressure drops to be met, and also reduces
heat losses through ensuring that return temperatures
remain low under part load conditions.
The control of pumps
Pumping energy will be more significant in dh systems
than small-scale heating circuits and so it is important to
design an efficient pumping arrangement. The energy can
be minimised by selecting multiple pumps with a range of
duties — both flow rate and head, to suit the requirements
for the variation in heat demands on the network. Variable
speed drives should be used to take full advantage of the
variable flow systems.
The sizing of distribution pipework
Peak design flow rates will be determined from the required
space heating and hot water demands. Diversity of demand
for space heating will be limited unless the scheme is very
large and contains a mix of types of buildings when a
diversity factor of 0.7 to 0.8 can be applied. Where domestic
hot water is provided by instantaneous heat exchangers a
diversity factor can be used for sizing of the local
distribution pipework as shown in Figure 9.9. Experience
from continental schemes indicates that the BS 6700 (BSI,
2009a) factors are too conservative and Danish Standard
DS 439: 2009 (Dansk Standard, 2009) diversity factors are
recommended for sizing supplies to multiple dwellings.
This standard contains the following equation, which was
used to generate Figure 9.9:
Pmax = 1.19 N + 18.8 N 0.5 + 17.6
The location of peak and standby boilers
As the chp plant will require regular maintenance, it is
normal practice to install peak and standby boilers. It is
simplest to locate these at the central energy centre.
However, if boilers are installed or retained within buildings
there would be additional benefits of security of supply and
lower dh network costs. The dh network need only be sized
to deliver the chp heat, not the peak heat demand in this
case. In these cases it may be appropriate for the dh
company to offer an interruptible heat supply contract.
where Pmax is the total heat rate required for dhw production
for the group of dwellings (kW) and N is the number of
dwellings.
From this equation it can be seen that the heat rate for a
single dwelling has been taken as 37.5 kW, which is typical.
However, the diversity factors will be similar for larger
dhw heat exchangers for dwellings.
Pre-insulated pipe systems
The design of a building’s heating system and controls has
a significant impact on the efficiency and cost-effectiveness
of the dh network. A variable volume control approach
should be used so that the return temperature on the dh
system remains low under part-load. This reduces pumping
energy and ensures heat recovery is maximised from chp. It
also means that a thermal store will be more feasible. If
bypasses are required within the heating system these
should be temperature controlled. With an indirect
connection system, it is important to ensure that the
primary (dh side) flow is also controlled otherwise
unnecessary primary circulation will occur leading to
higher return temperatures.
——
steel carrier pipe, rigid polyurethane insulation,
high density polyethylene casing (BS EN 253) (BSI,
2009b)
——
cross-linked polyethylene carrier pipe, flexible
insulation and outer casing
There is a need to define clear demarcation points between
the dh system and the building system, both for construction
and operation; normally this is defined at the flange of an
isolating valve. The building owner would normally own
the heat exchanger substation except for the heat meter,
which would be owned by the dh company.
1·0
0·9
0·8
0·7
0·6
0·5
0·4
0·3
0·2
0·1
0
1
5
10
20
30
40
50
60
70
80
90
100
110
120
130
140
150
160
170
180
190
There are a number of types of pre-insulated district
heating pipework systems:
Diversity factor
The design of a building’s heating systems
Number of dwellings
Figure 9.9 Diversity factor for instantaneous domestic hot water heat
exchangers
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polybutylene carrier pipe, flexible insulation and
outer casing.
——
a statement of deliverables
——
guarantees
The plastic carrier pipe systems have a degree of flexibility,
which means that the smaller diameters can be supplied in
rolls of 50 m length, thus reducing the number of joints to
be used and enabling ground obstructions to be easily
avoided. Generally the heat losses are likely to be higher
than for the equivalent steel system. The main benefit is
resistance to corrosion.
——
a statement of liquidated damages
——
quality and acceptance tests
——
health and safety
——
insurance requirements.
A surveillance system is normally incorporated in the steelin-plastic system, which enables ground water ingress into
the insulation to be detected and located prior to the onset
of external corrosion. This is recommended as it can result
in significant savings in dh repair costs.
10
Procurement
10.1
Tendering
Tenders sent out to prospective bidders should contain:
——
a technical performance specification
——
conditions of contract.
The purchase of the chp unit is frequently accompanied by
the procurement of a maintenance contract. Indeed this is
recommended both to ensure that the best expertise is used
to maintain the plant and to pass on the risks for poor
reliability to the supplier of the unit. The total cost of the
maintenance of the unit over 15 years is significant and can
be as much as the initial cost of the purchase. So it is
important to tender the maintenance contract at the same
time as for the supply and installation, and to compare
tenders on both aspects of the offer as part of a single life
cycle evaluation.
10.1.1
Technical performance specification
The technical performance specification is developed from
the preceding design stage information. To the greatest
extent possible, the specification should identify the
outcome or output of any particular feature, not what has to
be done to achieve it. The aim of this approach is to clarify
the responsibility between purchaser and supplier for the
provision of supply and adequacy for purpose.
If the purchaser gives a prescriptive description of how a
feature is to be achieved and that subsequently fails, then
the purchaser, not the supplier, may be liable for the failure.
If the purchaser identifies what is required from the system
and the supplied system does not meet that requirement,
the supplier may be held liable for such failures.
10.1.2
Conditions of contract
Conditions of contract may be adopted from any appropriate
standard form in accordance with an organisation’s normal
practice. MF/1: Model form of general conditions of contract
(IMechE, 2010) is suitable for use with chp projects.
Whatever form of contract is used the following may be
included:
——
model conditions
10.1.3
Selection of tenderers
The procedures for selecting tenderers will vary between
organisations but may involve:
——
advertising for potential tenderers through trade or
EU journals
——
selecting tenderers from known suppliers or
approved vendor lists.
Certain public sector and utilities contracts must be
advertised, under EU rules, normally through the Official
Journal of the European Union (OJEU). This will impose
time restrictions on the process.
Assessment criteria for the selection of potential tenderers
may include seeking evidence of:
——
relevant experience
——
financial status
——
insurance status
——
quality system accreditation
——
capacity to carry out work in desired time-scale
——
health and safety record.
The objective is to have sufficient tenderers to achieve a
realistic level of competition for the works, i.e. where the
companies tendering are in genuine competition but where
the purchasing organisation’s building services engineer is
not overwhelmed by bids.
10.1.4
Tender assessment criteria
Tender assessment criteria should be developed in parallel
with the invitation to tender (itt). Criteria may include:
——
compliance with the itt:
•
technical, including schedules of exclusions
where required
•
commercial
•
presentational
——
price and life cycle costs
——
proposed installation programmes
——
proposed payment schedule
——
maintenance capability
——
guarantees and after sales service.
10.1.5
Invitation to tender
The itt should be sent to each potential tenderer with a
clear statement of the response time, and the presentation
required.
Combined heat and power for buildings
10.2
Assessment of tenders
——
operating benefits based on guaranteed performance
efficiencies
10.2.1
Initial review of tenders
——
availability based on guaranteed levels in main­
tenance contracts
——
maintenance costs over life of the economic
analysis.
When tenders are received, they should be examined and
assessed against the agreed format. Responses from
manufacturers or suppliers should be considered for
compliance with such items as:
——
generator voltage
——
gross and net power output in kW
——
heat output by kWt and temperature
——
dimensions
——
weight
——
specific fuel consumption
——
on-engine monitoring and control
——
performance guarantees, e.g. reliability, availability
and utilisation over the proposed duty cycle
——
manufacturers’ experience with similar machines
in similar usage
——
maintenance requirements
——
capital cost
——
installation cost
——
maintenance cost.
Records of the tender review should be maintained,
particularly in formal or statutory tendering processes,
when records of the assessment procedure can later be
requested for inspection.
Subject to the maintenance contract terms being similar
and an assessment of other qualitative matters, e.g. level of
back-up, experience of similar projects, financial stability
etc., the tender offering the lowest npv can be recommended.
A weighting system may be employed to score the
qualitative criteria in a consistent manner.
The review should include revisiting the operating pattern
for the machines that are offered so as to optimise the
returns for each proposed scheme and hence to be able to
select a preferred scheme.
This review should follow the same format as the earlier
appraisals. It will be useful at this time to include a
sensitivity analysis to assess the effect on the payback
period of changes to fuel and energy prices. The building
services engineer will then have a better idea of the factors
affecting the future financial viability of the project.
Financing
10.2.4
The result of the invitation to tender may have an influence
on the means of financing the project. For instance:
——
Project costs may have reached a pre-determined
level that requires a different approach.
——
None of the tenderers may be able to offer the
required or preferred finance package.
With all returned tender responses available, the building
services engineer should check for completeness of
technical or commercial information and ask tenderers to
forward any information that is outstanding. The objective
is to ensure that sufficient information is available to
recommend a preferred tenderer and avoid the potential for
additional costs during the contract due to unforeseen
items.
——
The payback period may be short enough to permit
capital purchase rather than leasing.
The assessment of tenders should continue to the agreed
format to a point where a preferred tenderer can be selected.
It is always possible that in the early stages, two tenderers
may be effectively equal and further negotiations will be
necessary before a decision can be made.
10.2.5
10.2.2
Rationalisation of tenders
10.2.3
Economic reviews
Once tenders have been assessed and specific information is
available on the cost of the project and potential savings,
the building services engineer should carry out a further
economic appraisal to demonstrate that the scheme still
meets the management’s financial criteria.
The basis for the tender appraisal should be to reassess the
project economics in accordance with the client’s financial
parameters for each tender, taking account of:
units cost
——
chp
——
installation costs
In any event, the building services engineer should review
the means of financing the chp scheme to ensure compliance
with management guidelines and to obtain best value for
money, commensurate with acceptable risk.
Report
As a conclusion to the tender phase, the building services
engineer should prepare a report formally summarising:
——
the result of the invitation to tender
——
a recommendation on the preferred tenderer
——
the project costs associated with the preferred
tenderer
——
the result of the economic appraisal
——
recommendation for future action:
——
•
proceed with project, or
•
stop at the present time
the need for any further work before contract
placement, e.g. finalise contract terms, programme
etc.
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Part 2: Project implementation
11
Installation,
commissioning
and testing
11.1
Installation
The installation must be installed by a competent contractor
and comply with the latest legislation and in accordance
with other guidance published by CIBSE, IET, IGEM etc
——
Whilst the following list is not exhaustive, careful
consideration should be given to the following points:
——
——
——
Pre-installation and construction:
fall
under
CDM
•
Who is taking responsibility once the
becomes live?
•
Does the chp and ancillary equipment have
a fire or gas system?
•
How is this going to be connected into the
end user system?
hv
Testing, flushing and filling:
•
Has the local planning inspector accepted
the installation?
•
Has the electrical installation been tested to
IET Regulations, witnessed and signed off?
•
Has the mechanical installation been
pressure tested and witnessed?
•
Have water samples been carried out on
new and existing system?
•
Does the contract
Regulations?
•
Who is the principal contractor?
•
Has flushing been carried out satisfactorily?
•
Who is the cdm coordinator?
•
Is dosing required on the water systems?
•
Who is responsible for informing the
Health and Safety Executive?
•
Is pipe work exposed to external conditions,
is glycol required in system?
•
Who is responsible for arranging ‘G59’
protection?
•
Has the system been commissioned and
witnessed?
•
Is planning permission required?
•
Is the system ready to ‘go live’?
•
Is there a construction plan in place?
•
Has a health and safety risk assessment
been carried out?
•
Has a detailed site survey been completed?
•
Has a detailed client review discussion
taken place?
——
Installation:
•
Has planning approval been obtained prior
to commencing on site?
•
Is there a construction programme in place?
•
Have site inductions taken place?
•
Have competent contractors been engaged?
•
Do all personnel have the correct
qualifications and Construction Skills
Certificate Scheme (CSCS) cards in place?
•
Are Risk Assessments and Method
Statements in place prior to commencing
works?
•
Have permits been issued to allow works to
commence?
•
Have regular site progress meetings been
arranged?
•
Are toolbox talks in place?
Final connections:
•
Have the tie-in points been identified?
•
Have the risks been identified when tying
into existing system?
•
Is a high voltage (hv) study required prior
to connecting to hv?
•
Have the tappings on the new
former been set correctly?
hv
trans­
‘Go live’ stage:
•
Has the installation been signed off?
•
Has the commissioning been completed?
•
Is there a permit to work in place to allow
‘go live’?
•
Has the ‘G59’ test been completed?
•
Who is taking responsibility for the system
when operational?
•
What period is allowed and required for
initial proving of the chp controls under
actual site demand conditions?
Specialist systems, such as tri-generation, or systems with
island mode operation will require additional checks.
11.2
Component testing,
off-site testing
The chp unit must be CE-marked, to ensure that it conforms
with the essential requirements of applicable EC directives
The chp unit is made up of a number of components that
are individually tested and designed to allow them to fit
within the general arrangement of the chp system. A
thorough test of all equipment (where possible) is
conducted. However, unless a thermal and electrical load is
available, the unit performance cannot be checked. This is
normally done when on site and fully connected to the
client’s system.
Where the system has ‘island’ mode or ‘no-break’ facility,
additional hardware and design is required to enable the
system to support the facility. A ‘soft’ test will be carried out
by the manufacturer to ensure the correct interlocks and
transfer operates when required. However, it is important
that a number of ‘live’ tests are carried out on the client’s
Combined heat and power for buildings
premises when fully commissioned and connected to the
client’s system to check compatibility and correct operation.
——
What is to be tested or trialled?
——
How is the test or trial to be conducted?
Initial works:
——
Who will carry out the test?
•
design approved for manufacture
——
•
general arrangement drawing completed.
Are any special approvals required e.g. dno
verification of G59 compliance prior to permitting
generation?
——
When is the test or trial to be conducted?
A typical regime for testing of a
comprise:
——
——
——
——
The sequence for on-site stw should be agreed in advance.
The stw programme should include:
chp
chp
unit off-site will
build:
•
COSSH Assessment
•
during the day
•
machine risk assessment
•
at night
•
assemble chp
•
at week-end
•
complete build checklist prior to offering to
test.
Prior to energising:
•
gas test, purging and certification
•
IET testing and certification
•
system pressure tested and filled with water
•
system lubrication added.
——
Will the test have an impact on the normal operation
of the building?
——
Who is to witness the test?
The stages of site stw will commonly follow the pattern:
——
installation checks to ensure that all equipment is
fitted as required by drawings
——
static testing of systems:
System testing:
•
pressure testing of pipe systems
•
assign test engineer
•
•
complete pre-commission test sheets
line checks and earth resistance checks of
electrical systems
•
energise system
——
dynamic running checks of individual equipment
•
load software
——
functional checks of all safety devices
•
run and tune engine
——
•
complete commissioning test sheets
generator and switchboard performance and safety
trials
•
collate performance data and sign off as
commissioned
——
operational running checks of complete systems
——
•
glycol added once fully satisfied and prior
to dispatch (when required)
proving of all normal and reversionary operating
modes.
•
system identification added
•
system made safe and secure for dispatch
•
transport to client location.
During the course of the testing programme the client is
normally invited to witness the tests.
11.3
Commissioning
11.3.1
Co-ordination
Commissioning a new chp plant should be a planned,
progressive and sequential process of setting to work (stw).
A considerable degree of test and trial may be carried out at
the supplier’s factory, particularly for smaller engines or
packaged units. Where factory testing is possible, the
maximum advantage should be taken of this opportunity to
carry out all possible tests. On completion of factory testing,
testing on site will be reduced to:
——
items that could not be tested in the factory
——
checking that factory test results are still valid.
11.3.2
Documentation
The contractor must present a full dossier with all relevant
information, e.g. test methods and results, at the end of the
test.
Any defects identified during the stw, whether in the
factory or on site, should be recorded and assessed for
impact. Some may prevent further testing without
rectification; others may be acknowledged for rectification
later. Whatever decision is reached, it should be logged for
future reference.
11.3.3
Handover
Finally, stw will culminate in an acceptance trial and report
which, if successful, will lead to handover. At handover all
relevant parties should sign a certificate. The ‘taking-over
certificate’ in MF/1* or similar form may be used. The
certificate should include reference to all outstanding
defects (‘snagging list’) with the agreed responsibility and
action for rectification, and any agreed retention against
the contract price.
* MF/1 (Revision 5): Model Form of General Conditions of Contract
(London: Institution of Engineering and Technology) (2010)
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Part 2: Project implementation
11.4
Client acceptance testing
Typically there will be three sets of acceptance testing:
——
——
——
proving of the functionality of all equipment,
controls, interlocks etc.
12.1
12.1.1
——
conditions of heat or power to initiate a shut-down
to a standby mode
——
conditions of heat or power to initiate a re-start
from standby
——
operation of other plant during periods when the
plant is on, including plant sequencing
chp
performance testing to confirm that the unit is
operating as the supplier’s proposals
——
reliability testing: operating under normal
conditions for a limited period of, say, 1 week to
prove that the engine and systems are reliable.
plant response to engine parameters entering
warning levels, e.g. rising lubrication oil temper­
ature
——
plant response to partial failure of control and
monitoring system, e.g. failure of remote modem
link
——
plant response to failure of local electricity supply
——
level of plant operation and control that is possible
without the normal automatic systems
——
location and authority of normal plant control:
from where and by whom.
Consideration needs to be given during the tender
preparation stage to the availability of suitable site demands
for heating, electricity and, in the case of tri-generation,
cooling to enable testing and commissioning to be
completed. This is particularly an issue for new buildings
or when the commissioning is planned for the summer.
Electrical demand is less critical if export is permitted but
in some cases an electrical load bank can be provided
temporarily. If full heat rejection facility is included in the
scope, the chp operation can normally be fully tested.
However, some aspects of the controls may need to be
carried out later (such as how boilers are sequenced with
the chp as the site heat demand varies). Where a thermal
store is incorporated this may be sufficient to provide a
heating load. It may be necessary to carry out some of the
final proving at a later date, say during the heating season,
and this can be allowed for within the contract.
12
55
Operation and
maintenance
Operation
Strategy for using the CHP plant
In the feasibility study, consideration was given to the way
in which the chp plant might be operated. This was
developed further in the tender stage in order to assess
accurately the annual savings from and economic
justification for the project. If an operation and maintenance
agreement has been signed with a contractor, this may
reference operating periods and annual energy production
as key performance factors.
The building services engineer will already have planned
and set into the control system such features as:
——
the normal start and stop time each day: determined
by electricity tariff times and/or building usage
——
conditions for heat and power demand before the
plant can start
——
number of attempts and maximum time to start,
run and parallel before declaring failed start and
shutting down
——
protection of starter motors
——
protection of circuit breakers
——
conditions of heat or power to initiate a modulation
of plant output
Each of the items above needs to be addressed to ensure
that the operator (as distinct from the building services
engineer) understands what to expect or demand of the chp
plant.
The pattern of operation should remain within the building
services engineer’s overall control. It may be set up and
adjusted by the remote monitoring contractor in agreement
with the building services engineer for plant that is under
performance based maintenance contracts. Otherwise,
alterations to the operating pattern may be made through
the building bems, by adjustable timers or by other semiautomatic means within the chp plant control system.
The interaction of other plant in particular requires careful
consideration.
It is usual that, when running, the chp unit becomes the
lead boiler. However, to achieve this with other boilers, or
even other chp plant, requires careful selection of the chp
plant and boiler on/off set temperatures, and of the sensing
positions, to ensure that the plants operate in the correct
sequence. Different temperature schedules may be required
when the chp plant is running and when it is shut down.
If heat raising plant is not co-ordinated in this manner, the
boilers may suppress the chp plant at times when all
conditions would otherwise be favourable for chp operation.
12.1.2
Monitoring benefits
The chp plant will be installed, in most cases, because of
the financial benefit achieved by displacing the more
expensive combination of imported power and boilergenerated heat. It is therefore incumbent upon the building
owner’s or operator’s services engineer to maintain and
monitor records to ensure that the plant delivers the benefit.
As a minimum, records should show:
——
running hours: from the chp plant hours-run meter
——
fuel consumption: from the chp plant’s meter
——
usable electrical power generated: from chp plant
kW·h meter, minus any parasitic loads for each
tariff period
Combined heat and power for buildings
——
usable heat generated: estimated, if not directly
metered
——
the duration and cause of any plant stoppages.
Should any changes to the operation of the chp plant be
contemplated? Re-running the financial appraisal, or
monthly reports, should provide the answer as to whether
the proposed change should proceed.
These minimum records may be taken directly from the
automatically monitored records provided by the o&m
company or by other local means. In most instances, the
building services engineer will wish to see a fuller record of
performance than the bare minimum. A balance needs to
be struck regarding the frequency and detail of information
presented to the building services engineer to ensure that it
is sufficient for purpose without being overwhelming.
The building services engineer may also wish to initiate
changes that improve the overall building operation and
economics. Any changes to the chp plant operating pattern
should take into account the cost implications for existing
operation and maintenance agreements.
On modern pc-based data logging systems, it is possible to
retain considerable volumes of data for later analysis.
Normally a hierarchy of data retention will be established,
e.g.:
The provision of services to operate the plant on a day-today basis and to attend to breakdowns may be the subject of
a service agreement with a specialist contractor. The
building services engineer will be able to forecast the
operating periods and generating profiles of the chp plant
to assist in negotiating the service agreement.
——
last hour: all data recorded
——
last day: one data set per hour plus all start/stop
signals, alarms and warnings
——
last three months: one data set per week, plus all start/
stop signals, alarms and warnings.
Records of plant performance should be converted
periodically into a costed record of benefit that will compare
the actual cost of running the chp plant with the cost of
providing the equivalent heat and power by conventional
means, in effect validating the financial appraisal.
The information required to achieve the necessary results
is:
——
cost of fuel for the chp plant: from gas bills
——
cost of chp generated electricity: from the chp contract
——
cost of chp plant maintenance: from the chp contract
——
equivalent cost of importing chp generated power: from
electricity bills
——
equivalent cost of boiler firing: from boiler records.
The data may be entered into the spreadsheet used in the
feasibility study, formatted to suit the analysis required, or
presented in any other suitable form.
Performance records should be updated and reviewed as
often as required. Many organisations keep records monthly
and find them a useful way of keeping senior management
informed of the chp scheme and its continuing financial
benefit to the organisation.
Information about plant stoppages is particularly important
in relation to payments in performance based contracts.
Liability for non-performance of the plant will be dependent
on the reason for non-performance.
12.1.3
12.1.4
12.2
Operation and maintenance
manuals
12.2.1
Manuals
The provision of operation and maintenance manuals will
have been specified in the contract specification. These
manuals are required by the building services engineer,
irrespective of whether the supplying contractor is
providing maintenance services. Holding the manuals will
allow, should circumstances dictate, the operation and
maintenance of the plant using in-house resources or the
placement of an alternative operation and maintenance
contract.
The manuals must be clear and comprehensive. The
building services engineer should ensure that manuals are
received from the supplying contractor before plant handover.
The manuals should cover:
——
health and safety warnings
——
plant data sheets
——
general and detailed descriptions of engines and all
equipment
——
installation guidance notes
——
general arrangement drawings
——
circuit and schematic diagrams
——
commissioning procedures, records and test sheets
——
operating instructions
——
detailed maintenance instructions and schedules
for all equipment
——
diagnostic fault finding information
——
passwords to access control system
——
listing and descriptions of special tools
——
recommended spares holdings and ordering infor­
mation.
Changes in operation
If fuel tariffs change, the monthly reports should identify
the change in benefit. Such a change may be the prompt
that is required to re-examine the way in which the chp
plant is being operated; for example, should a new running
pattern be adopted (e.g. continuous operation rather than
17 hours per day)?
Provision of operating services
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Part 2: Project implementation
12.3
57
Maintenance and servicing
plant requires maintenance as a necessity. The
purchaser should understand the need for, and degree of,
maintenance required and set in motion the means of
delivering a suitable service.
chp
12.3.1
——
daily or weekly checks:
•
performance monitoring checks
•
visual inspection of plant for leaks and
unusual noises
•
visual check on oil level in oil make-up tank
Delivery of maintenance
Maintenance may be carried out by:
——
in-house staff
——
equipment suppliers
——
specialist contractors.
——
The costs and benefits, or risks, associated with each option
will determine the choice of who should carry out
maintenance.
Many organisations choose some form of contract
maintenance with equipment suppliers or specialist
contractors (see section 12.3.3 below).
12.3.2
Maintenance schedules for chp plant will vary depending
on the exact machine. The following schedule is an example
of the items that may be included for a typical gas-engine:
Schedules of maintenance
Maintenance of a gas-fired spark-ignition chp installation
will include activities that will be scheduled on an hoursrun basis, as well as activities that will depend on inspections
or condition monitoring.
Individual engine and equipment suppliers will provide
detailed statements on the scope of maintenance for their
equipment. These statements should be observed carefully
in order to:
——
ensure the enduring life of equipment
——
maintain the
warranties
——
co-ordinate scheduling of major services.
performance
guarantees
routine service (typically every 1000 hours):
•
check running records for plant performance
trends
•
check starter battery condition.
•
change engine oil
•
change oil filter
•
send oil sample for analysis
•
check spark plugs and renew as required
•
check air filter and clean or change as
required
•
check oil tank level and top up as required
•
check ht leads for wear and corrosion
•
check and reset valve clearances as required;
record high recession
•
change rocker box gaskets
•
check engine coolant level; top up antifreeze
as required
•
check battery terminals for tightness
•
clean out engine catchment area; wipe clean
•
visually inspect all engine and control panel
wiring
•
visually inspect all water flexible connection
hoses and expansion joints for deterioration
•
check and clean in-line water filters, if fitted
•
check condensate pot level
•
visually inspect close coupled engine/
generator connection
•
visually inspect anti-vibration mounts
supporting engine/generator monoblock
•
restart engine; visually inspect for fluid
leaks, unusual noises, loose fittings
and
The maintenance requirements of machines are now more
frequently being determined by condition monitoring of
the plant. Particularly where fully automatic monitoring
and data logging is used, deviations in plant performance
can be identified early and appropriate remedial steps
taken. Not every slight deviation in condition will evoke an
immediate maintenance response.
Condition monitoring of bearings is a valuable tool for
making an early diagnosis of incipient bearing failure.
•
Oil sample monitoring may also be used. Laboratory
analysis of the oil would look for:
check engine performance; set up using gas
analyser
•
check and record exhaust back pressure
——
water or glycol contamination: indicating leakage
of engine coolant into the oil circuits
•
check operation/control of dry air cooler
and 3-port valve
——
changes in viscosity, acidity, oxidation, nitration
and other conditions: indicating that the oil needs
to be changed
•
check unit controls, metering, monitoring
and communications.
——
metal particulate contamination: indicating engine
bearing or component wear
——
non-metallic particulate contamination.
Further servicing requirements will depend on the
equipment selected and the feedback from condition
monitoring. The requirements will be influenced by the
hours run, the frequency of starts and the type of fuel.
Combined heat and power for buildings
It is important that full records of maintenance activities
carried out are kept and that these are provided to the
owner.
12.3.3
Contracted-out maintenance
The level of maintenance contracted out may cover a very
wide range of options. The following are examples of
typical cover:
——
——
Service only: The maintenance contractor will carry
out a pre-set list of maintenance tasks to a
predetermined time schedule only. All tasks in
excess of the standard predefined tasks will be
extras. Spares and consumables quoted in the stated
tasks will be included in the price but all other
spares will be extras. The user is responsible for
calling in the maintenance contractor for any defect
rectification at additional cost.
Service only with remote monitoring: The same as
‘service only’ with the addition that the contractor
is also monitoring the chp plant performance and
should therefore identify plant failures (or the need
for early attention) and can discuss with the user
whether the attendance of a service engineer is
required.
——
Comprehensive service with remote monitoring: The
maintenance contractor will carry out pre-defined
maintenance tasks and will respond to defect callouts. The range of spares included in the price will
be greater than for ‘service only’.
——
Comprehensive service with performance guarantee:
The maintenance contractor takes on almost total
responsibility for ensuring that the plant achieves
specified performance levels. Performance may be
determined in terms of guaranteed availability of
hours run and in terms of heat and power generated.
The contractor carries out all planned maintenance
activities and is responsible for addressing all
unplanned defects. The contractor provides a near
immediate call-out response to breakdowns.
——
Monitoring service only: The monitoring contractor
takes no responsibility for ensuring that the plant
achieves any particular level of service but provides
the client with reports of plant monthly perfor­
mance, operation outside of normal limits and
trips, with the time and type of fault. Other services
may be included such as monthly savings reports,
diagnostic assistance from data analysis, prediction
of service interval. This level of service provision is
relatively rare and, if adopted, needs careful
consideration to ensure that all parties are aware of
the scope and limits of their responsibilities.
The client must also select which elements of the
maintenance will be contracted out.
For all maintenance arrangements, it is important to
establish agreed or contracted response times, and defect
call-outs, since all lost running time detracts from the chp
scheme’s financial benefit. It is possible for an otherwise
well designed and installed chp plant to be out of action for
1000 hours in a year if faults are not promptly attended to.
This may include downtime at times of highest electricity
price and greatest heat demand.
As a guide, planned downtime for a plant running 8000
hours per year should not exceed 400 hours, and unplanned
downtime a further 400 hours in an average year without a
major overhaul. The best systems should achieve a total
downtime of less than 600 hours per year, most of this being
for planned maintenance and therefore carried out at times
of least inconvenience.
For plants running only 4000 hours per year, most planned
downtime could be programmed outside the duty hours.
Where maintenance is scheduled at weekends, premium
payments may be incurred.
Where performance guarantees are involved, clear and
careful agreement of the performance criteria are required.
Issues to be clarified include:
——
Output performance: Is power used by chp plant
auxiliaries, fuel systems and heat rejection systems
included or excluded? These parasitic loads may be
significant but they should be excluded from any
calculation of chp scheme benefit to the user, since
without the chp scheme these loads would not exist.
——
Hours available; hours run: how will downtime be
logged and attributed to cause, e.g. planned
maintenance, defect or unplanned maintenance,
building heat or power demand too low etc.? On
remotely monitored systems, the data logger may
record the fact that a chp plant has been manually
tripped locally and interpret this as the user
deciding not to run the plant. Such an event would
therefore not count against the maintainer, whereas
the user may have been responding to a request to
shut down from the maintainer.
12.3.4
In-house maintenance
If the purchaser takes on any part of the operating service
or maintenance of the chp plant, the division of respon­
sibility with any specialist contractor must be clearly
identified.
A normal chp plant requires daily observation, either
locally or via a remote terminal, to check for good operation
and to identify trends that may indicate future problems.
Other functions may require weekly or monthly checks,
with main services being needed every six months. Oil
changes may be required every 6 to 8 weeks (1000 to 1500
hours running). To ensure that appropriate maintenance is
carried out, the building services engineer should establish
maintenance schedules following the manufacturer’s
recommendations.
12.3.5
Consumable spare parts
The contract specification should allow for the immediate
provision on handover of an appropriate range of
consumable spares recommended by the supplier. When
selecting spares holdings, judgment must be exercised in
relation to:
——
the convenience of immediate availability
——
space required for storage
——
anticipated draw-off rates
——
the shelf-life of spares
——
the cost of cash tied up in stock
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——
the likelihood of the need and the impact of nonavailability
——
the ability to source spares when required.
All spares should be detailed in a spares listing within the
operating and maintenance manuals. This listing should
59
also include all relevant references, sources of supply and
ordering information.
The precise level of spares holdings may ultimately be
determined by the arrangements made for maintenance
and service.
Part 3: Lessons learned
13
Lessons learned
——
The following checklist of do’s and don’ts summarises
some of the guidance provided within the body of the
guide. It is divided into the following headings following
the stages of a project development:
Ensure that efficiencies and gas consumption rates
are defined using gross calorific value and always
check this with the chp supplier.
——
Discuss with the local authority the local Air
Quality Objectives and assess the impact of chp;
this may involve dispersion modelling.
——
Feasibility studies
——
——
Economic appraisals
——
Integration of chp into heating circuits
——
District heating
——
Environmental impact
Consider adequacy of gas supply (noting that
normally gas consumption increases significantly
with the installation of chp). Gas suppliers will
need to know the ‘supply hourly quantity’ (shq)
(i.e. the maximum hourly gas consumption), the
‘supply offtake quantity’ (soq) (i.e. the maximum
daily consumption) , and the ‘annual quantity’ (aq)
of gas required.
——
Procurement
——
Installation
——
——
Commissioning
Check the gas pressure available at maximum
demand and compare this with the engine
requirements to assess whether gas boosters will be
required.
——
Operation
——
——
Tri-generation and absorption chillers
Establish how supplies of heat and power are
maintained during chp maintenance periods.
——
Confirm suitable space exists for
access.
——
Establish how adequate ventilation is provided to
the chp enclosure and plant room.
——
Consider location for heat rejection equipment
taking account of potential issue of noise generation.
13.1
——
Feasibility studies
Establish heat and power demands in as much
detail as possible, which could involve installing
temporary metering or monitoring equipment.
——
Consider opportunity for connection to nearby
buildings with different heat demand profiles.
——
If steam or mthw is to be generated by exhaust
gases then consider uses for lthw, or consider
options for converting system to lthw.
——
Discuss the proposed project with the distribution
network operator at the earliest stage to identify
any issues concerning fault level contribution and
reinforcement works, and make an early application
for connection using the appropriate G59/2 or
G83/1 application forms.
——
Consider the extent of on-site electrical infra­
structure works.
——
Evaluate whether for larger schemes hv generators
would be preferred to using step-up transformers
——
In most cases limit the maximum size of the chp to
the electrical base load to avoid significant export
which attracts much lower value. Boilers can be
used to meet peak heat demands.
13.2
chp
with good
Economic appraisals
——
Define the criteria for assessment with the client
and agree period of analysis and discount rates to be
used.
——
Ensure all maintenance and operating costs are
included: routine and non-routine, consumables
including lubricating oil.
——
Try to establish true market levels for gas and
electricity prices: simply taking current contract
prices may be misleading if these are for different
contract periods ending at different dates. Refer to
statistics and forecasts published by the Department
of Energy and Climate Change (DECC).
——
Consider other economic benefits that may accrue
through regulatory incentives, e.g. CRC Energy
Efficiency Scheme, Climate Change Levy
exemption.
Combined heat and power for buildings
——
Make sure that the maintenance regime and the
cost implications are understood.
——
Carry out sensitivity analysis on energy prices and
availability, reflecting any compensation terms
within the proposed maintenance contract.
13.3
Integration of CHP into
heating systems
——
For new-build schemes, select flow and return
temperatures of heating circuits to optimise chp
operation and prevent chp tripping on high return
temperatures.
——
Ensure chp acts as the lead heat source at all times.
——
Consider whether the chp is connected to the
common return to the boilers or connected in
parallel and, if in parallel, the control approach to
give priority to chp.
——
Evaluate the benefits of thermal storage and locate
the thermal store between the flow and return,
maximising the temperature difference in the store.
——
Avoid the use of a low loss header if this risks high
return temperatures onto the chp at part-load.
——
Ensure suitable access is provided for maintenance
and subsequent removal and replacement of chp.
13.4
Prevention and Control (IPPC) regulations or only
under the Clean Air Act 1993.
——
Use HMIP Technical Guidance Note (Dispersion)
D1: Guidelines on Discharge Stack Heights for
Polluting Emissions (June 1993) (HMIP, 1993) for the
calculation of chimney height.
——
If the site comes under the IPPC Regulations carry
out dispersion modelling using EA-approved
software.
——
Obtain accurate emissions data from the chp engine
manufacturer. NO2 is 6 or 7 times more toxic than
NO, so the chimney height calculation will be
sensitive to their relative proportions as well as
total NOx content in exhaust gas.
——
If local Air Quality Objectives are to be met,
background levels of common pollutants are
available in Table 2 in HMIP Technical Guidance
Note D1 or from the UK Air Quality Archive
(http://www.airquality.co.uk/index.php).
——
Check the calculation for each fuel and at part load
to find the most onerous condition, taking account
of emissions from both chp and fuel for all realistic
operating scenarios.
——
Design entire flue gas system and stack for
minimum internal volume (to minimise residence
time between engine and top of stack) consistent
with meeting the chp engine manufacturer’s
maximum backpressure limitation (allow a design
margin for fouling etc).
District heating
——
For new schemes select low return temperatures to
reduce flow rates on dh network.
——
——
For existing schemes consider potential for
reducing return temperatures by investigating
degree of oversizing and rebalancing heat emitters.
Ensure stack discharge velocity is within specified
limits (typically between 10 and 15 m/s depending
upon heat content).
——
——
Consider benefits of investing in new heat emitters
to reduce return temperatures.
If using dispersion modelling, the following design
guidance is suggested in the absence of other
criteria set by the regulatory authorities:
——
Ensure all controls operate as variable volume (2port valves) not constant volume (3-port valves).
——
Limit the scope for bypasses in the network whilst
maintaining minimum circuit flow temperatures.
——
Use variable speed pumps to reduce electrical
energy use.
——
Consider the impact of particulates for some types
of chp/fuels.
——
Evaluate whether and where heat meters are to be
installed and how these will be read.
——
——
Establish where hydraulic breaks in the system are
needed and select hydraulic interface units and
heating substations as appropriate.
Carry out background noise measurements in
accordance with BS 7445: Description and
measurement of environmental noise (BSI, 2003).
——
Agree design basis with local authority for noise
control taking account of possible restrictions in
operating hours.
——
13.5
——
Check that pressure constraints for all equipment
are not violated in terms of static pressure, peak
pressure, minimum pressure to avoid cavitation
and differential pressures.
Environmental impacts
Liaise with local authority or Environment Agency
(EA)/ Scottish Environment Protection Agency
(SEPA)/ Northern Ireland Environment Agency
(EHSNI) (as appropriate) at an early stage to agree
design basis and reporting standards and whether
the scheme falls under the Integrated Pollution
13.6
•
the maximum plant contribution should be
less than 10% of the 1-hour mean target
value
•
the annual mean of the plant emissions plus
existing background concentrations should
be less than the annual mean target value.
Procurement
——
Choose form of contract and the allocation of design
responsibility.
——
Define demarcation and interface points.
——
Consider whether chp supplier is to be the main
contractor or a sub-contractor depending on the
scope of work.
——
Establish how the project opportunity will be
advertised.
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Part 3: Lessons learned
——
Assess tenders on a whole life cost basis, not just on
a capital cost basis.
——
Electrical efficiency is probably the biggest single
factor contributing to overall cost effectiveness.
——
To carry out the tender analysis, produce a spread­
sheet that enables sensitivity of variables such as
gas price, electricity value etc to be tested.
——
——
——
13.7
——
Negotiate maintenance contract with chp supplier
at the same time as the construction contract and
incorporate in the tender analysis:
13.8
Commissioning
——
Agree a commissioning/proving trial scope and
programme.
——
Establish who pays for fuel used for commissioning
and who owns the electricity generated.
——
Ensure metering is calibrated and operational prior
to commissioning and that it complies with
CHPQA standards (CHPQA, 2009).
——
Consider what load will be available for heating,
cooling and electricity at the time that commission­
ing is planned and whether a load bank (for
example) is needed.
——
Obtain a connection agreement from the dno and
negotiate an import/export agreement with an
electricity supplier (if export is contemplated).
Ensure a Meter Operator (mo) is appointed if
exporting.
•
ensure availability calculation method and
compensation terms is agreed
•
check for total limits of liability
•
check for exclusions, e.g. for major failures
•
check for provision of standard reports
•
check for use of subcontractors
——
•
check for supply of materials and removal
of waste.
Ensure CHPQA form F1 is completed in good time
and nominate the Responsible Person.
——
Complete CHPQA form F3 (forecast of
performance) in good time.
——
Apply to Secretary of State for Climate Change
Levy (CCL) exemption certificate in good time.
——
Submit CCL forms PP10/PP11 to fuel suppliers in
good time prior to commissioning.
——
Validate engine power and heat outputs and effi­
ciencies against supplier performance guarantees.
——
Carry out a reliability run over several days.
Ensure requirements of the Construction Design
and Management Regulations 2007 (‘CDM
Regulations’) have been considered: appointment
of principal contractor, cdm co-ordinator etc.
Evaluate risks and transfer operational risk to
supplier as far as is practicable.
chp
Detailed design and installation
chp
Develop detailed control strategy to deliver the
optimum economic and environmental perfor­
mance.
13.9
——
Is the existing bems control to be extended to
control the chp or will the chp supplier provide a
standalone control system?
——
Agree response time to attend chp breakdowns.
——
Agree how remote monitoring is carried out.
——
——
Ensure local authority planning approvals are in
place for all aspects of the project (if necessary write
into contract).
Supplier to have responsibility for all chp-integrated
components.
——
Agree availability guarantee covers all
integrated components.
——
Ensure all service input and output requirements
are known and designed-in.
——
Ensure chp running regime and decision factors
(e.g. tariffs) are documented and understood.
——
Ensure design is robust in all aspects before contract
is signed.
——
Track the chp performance and availability and
manage the maintenance provider.
——
Anticipate any site heating, dhw and steam
downtimes and detail these in the installation
programme.
——
Submit CHPQA form F4 to CHPQA before 31st
March each year to obtain CCL exemption.
——
Agree all demarcation/take-over points in the
design phase.
13.10
——
Supplier/installer to keep the project timing plan
up-to-date throughout the project.
——
If an absorption chiller is to be included check its
sensitivity to input temperature.
——
Allow enough time for all phases of the commission­
ing period.
——
——
Ensure major items of equipment have mean time
between failures (mtbf) information.
Establish the additional heat rejection requirement
for the absorption chiller, which is typically double
the capacity required for conventional vapour
compression chillers.
——
Consider impact on power factor of chp generation.
——
——
Ensure heat rejection circuit has frost protection.
Identify and resolve any pre-existing problems
with a cooling system, heat rejection system, water
treatment etc before installing an absorption chiller.
Operation
chp-
Tri-generation and
absorption chillers
Combined heat and power for buildings
——
Design the absorption chiller system for full load
operation (by the incorporation of thermal stores if
necessary) as cop may drop by up to 33% at partload.
——
Consider variable speed control of absorbent pump
to improve the cop at low load.
——
Consider access and floor-loading (a typical 2 MW
double-effect steam chiller weighs 12.5 tonnes
empty and 16.7 tonnes when operating).
——
Ensure ambient of >5 °C in chiller room to prevent
crystallisation.
——
Crystallisation can be prevented if the following are
considered:
——
•
avoid cooling water temperature colder
than design by the use of mixing valves etc.
•
avoid sudden changes in cooling water
temperature.
Ensure heat supply is completely shut off when not
required.
Carbon Trust (2011) Micro CHP (Combined Heat and Power) Accelerator —
Final report CTC788 (Carbon Trust). Available at http://www.carbontrust.
com/resources/reports/technology/micro-chp-accelerator (accessed May
2012).
CCC (2010) The Fourth Carbon Budget — Reducing emissions through the
2020s (London: Committee on Climate Change). Available at http://www.
theccc.org.uk/reports/fourth-carbon-budget (accessed May 2012).
CCC (2011) Bioenergy Review (London: Committee on Climate Change).
Available at http://www.theccc.org.uk/reports/bioenergy-review (accessed
May 2012).
CHPQA (2009) CHPQA Standard: Quality Assurance for Combined Heat
and Power Issue 3 (London: Department of Energy and Climate Change).
Available at http://chpqa.decc.gov.uk/chpqa-documents (accessed May
2012).
CHPQA (2012) CHPQA Guidance notes (website) (London: Department
of Energy and Climate Change). http://chpqa.decc.gov.uk/guidance-notes
(accessed May 2012).
CIBSE (2001–2) ‘Noise and vibration control for hvca’, ch. 5 in Heating,
ventilating, air conditioning and refrigeration CIBSE Guide B (London:
Chartered Institution of Building Services Engineers).
——
Provide a ups to run the absorbent pump for 20
minutes after a power cut.
——
Over-size external heat rejection if possible as
reduced heat rejection capacity will severely restrict
absorption chiller output.
CIBSE (1999) Minimising pollution at air intakes CIBSE TM21 (London:
Chartered Institution of Building Services Engineers).
——
Allow adequate time for commissioning: absorption
chillers require two weeks to establish passivated
internal coating after first charging with refrigerant
and chemicals, and after any subsequent opening to
atmosphere.
Construction (Design and Management) Regulations 2007 (SI 320/2007)
(London: The Stationery Office). Available at http://www.legislation.gov.
uk/uksi/2007/320 (accessed May 2012).
——
Remember that a suitable cooling load is needed for
commissioning.
——
Ensure operators are adequately trained in
absorption chiller operation and in particular the
conditions and transients likely to cause crystal­
lisation.
References
BRE (2012) Wiltshire R Technical Guide to District Heating (Garston: IHS/
BRE Press).
BSI (2003) BS 7445: Description and measurement of environmental noise:
Part 1: 2003: Guide to quantities and procedures; Part 2: 1991: Guide to the
acquisition of data pertinent to land use; Part 3: 1991: Guide to application to
noise limits (London: British Standards Institution).
BSI (2009a) BS 6700: 2006+A1: 2009: Design, installation, testing and
maintenance of services supplying water for domestic use within buildings and
their curtilages. Specification (London: British Standards Institution).
(BSI (2009b) BS EN 253: 2009: District heating pipes. Preinsulated bonded
pipe systems for directly buried hot water networks. Pipe assembly of steel service
pipe, polyurethane thermal insulation and outer casing of polyethylene (London:
British Standards Institution).
Control of Noise at Work Regulations 2005 (SI 2005/1643) (London: The
Stationery Office). Available at http://www.legislation.gov.uk/uksi/2005/
1643 (accessed May 2012).
Dansk Standard (2009) DS 439: 2009: Code of Practice for domestic water
supply installations (Charlottenlund, Denmark: Dansk Standard).
DCLG (2010) Approved Document L: Conservation of fuel and power (4 parts)
Building Regulations Part L Approved Documents (London: Department
for Communities and Local Government). Available at http://www.
planningportal.gov.uk/buildingregulations/approveddocuments/partl/
approved (accessed May 2010).
DECC (2010) Chapter 5, Table 5.6 in Digest of UK Energy Statistics
(London: Department of Energy and Climate Change). Available at http://
www.decc.gov.uk/en/content/cms/statistics/publications/dukes/dukes.aspx
(accessed May 2012).
DEFRA (2007) The Air Quality Strategy for England, Scotland, Wales and
Northern Ireland (London: Department for Environment, Food and Rural
Affairs). Available at http://www.defra.gov.uk/environment/quality/air/
air-quality/approach (accessed May 2012)
DEFRA (2011) 2011 Guidelines to Defra/DECC’s GHG Conversion Factors
for Company Reporting: Methodology Paper for Emission Factors (London:
Department for Environment, Food and Rural Affairs). Available at
http://www.defra.gov.uk/publications/2011/09/01/ghg-conversion-factorsreporting (accessed May 2012).
BSRIA (2003) Galliers S Fuel Cell Technology: The scope for building services
applications BSRIA BG 9/2003 (Bracknell: BSRIA).
DoE (1981) Chimney Heights: 1956 Clean Air Act Memorandum (London:
Her Majesty’s Stationery Office)
BSRIA (2007) Teekaram A, Palmer A and Parker J CHP for existing
buildings. Guidance for design and installation BSRIA BG2/2007 (Bracknell:
BSRIA).
Electricity at Work Regulations 1989 (SI 1989/635) (London: The
Stationery
Office).
Available
at
http://www.legislation.gov.uk/
uksi/1989/635 (accessed May 2012).
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ENA (2011a) Distributed Generation Connection Guide: A Guide for connecting
generation that falls under G59/2 to the distribution network Version 3.2 June
2011 (London: Energy Network Association). Available at http://www.
energynetworks.org/electricity/engineering/distributed-generation.html
(accessed May 2012).
ENA (2011b) Distributed Generation Connection Guide: A Guide for connecting
generation that falls under G83/1 (Stages 1 and 2) to the distribution network
Version 3.2 June 2011 (London: Energy Network Association). Available
at http://www.energynetworks.org/electricity/engineering/distributedgeneration.html (accessed May 2012).
Euroheat (2008) Guidelines for District Heating Substations (Brussels,
Belgium: Euroheat & Power). Available at http://www.euroheat.org/
Technical-guidelines-28.aspx (accessed May 2012).
The Gas Safety (Installation and Use) Regulations 1998 (SI 1998/2451)
(London: The Stationery Office). Available at http://www.legislation.gov.
uk/uksi/1998/2451 (accessed May 2012).
HMIP (1993) Guidelines on Discharge Stack Heights for Polluting Emissions
HMIP Technical Guidance Note (Dispersion) D1 (London: The
Stationery Office).
IGEM (undated) Gas fuelled spark ignition and dual fuel engines IGEM/UP/3
Edition 2 (Kegworth: Institution of Gas Engineers and Managers).
IGEM (2005a) Soundness testing and purging of industrial and commercial gas
installations IGEM/UP/1 Edition 2 (Kegworth: Institution of Gas
Engineers and Managers).
IGEM (2005b) Gas installation pipework, boosters and compressors on industrial
and commercial premises IGEM/UP/2 Edition 2 (Kegworth: Institution of
Gas Engineers and Managers).
IGEM (2009a) Commissioning of gas fired plant on industrial and commercial
premises IGEM/UP/4 Edition 3 (Kegworth: Institution of Gas Engineers
and Managers).
IGEM (2009b) Application of compressors to natural gas fuel systems IGEM/
UP/6 Edition 2 (Kegworth: Institution of Gas Engineers and Managers).
IGEM (2004) Application of natural gas and fuel oil systems to gas turbines and
supplementary and auxiliary-fired burners IGEM/UP/9 Edition 2 (Kegworth:
Institution of Gas Engineers and Managers).
HVCA (2008) Installation of Combined Heat and Power HVCA TR37
London: Building and Engineering Services Association).
IMechE (2010) Home or overseas contracts for the supply of electrical, electronic
or mechanical plant — with erection IMechE Model forms of general
conditions of contract MF/1 (Revision 5) (London: Institution of
Mechanical Engineers).
IEA (2011) District Heating and Cooling (website) IEA Annex X
(International Energy Agency). http://www.iea-dhc.org (accessed May
2012).
National Grid (2009) The Potential for Renewable Gas in the UK (National
Grid). Available at http://www.nationalgrid.com/uk/Media+Centre/
Documents/biogas.htm (accessed May 2012).
Appendices
Appendix A1: Conversion factors
Table A1.1 Energy unit conversion factors
Table A1.3 SI multiples
To
Prefix
Symbol
Factor
From
Joule
Joule­1
3.6 Í 106
kW·h
Therm 105.5 Í
BTU
106
1.055 Í 103
kW·h
Therm
BTU
kilo
k
103
0.2778 Í 10–6
9.48 Í 10–9
0.948 Í 10–3
mega
M
106
1
34.12 Í 10–3
0.2931 Í
10–3
0.293 Í 10–3
3.412 Í 103
giga
G
109
10–6
1
tera
T
1012
10 Í 10–6
1
peta
P
1015
exa
E
1018
10 Í
Table A1.2 Miscellaneous conversions
Multiply
by
to obtain
ton
1.1016
tonne
tonne
0.984
ton
pound (lb)
0.454
kilogramme
Table A1.3 Typical calorific values for fuels
gallon
4.546
litre
Fuel
litre
0.220
gallon
Gross
Net
cubic foot
0.028
m3
Fuel oil to BS 2869 Class D
45.0
42.2
m3
35.315
cubic foot
Natural gas at 15 °C, 1013.25 mbar
38.6
34.7
Calorific value / MJ·kg–1
Combined heat and power for buildings
Appendix A2: Glossary of terms
The definitions given here relate specifically to the context
of chp installations. Terms may have broader or alternative
meanings in other contexts.
Absorption refrigeration. Refrigeration plant that uses heat instead of
electricity as the driving energy source, utilising, for example, lithium
bromide and water as the working fluid.
Adsorption refrigeration. Refrigeration caused by the evaporation of
water at low pressure as it is attracted to an adsorber such as silica-gel.
Alternator. A machine whose shaft is driven by an engine or turbine and
converts mechanical energy into alternating current (ac) electricity. Also
called a generator.
Auxiliary firing. The burning of fuel (with its requisite air supply) in
waste heat boilers when the generator set is not running but the site heat
supply is to be maintained.
Availability charge. The charge made for maintaining an agreed electrical
supply capacity to a consumer’s premises.
Construction (Design and Management) Regulations 2007 (CDM2007).
The Construction (Design and Management ) Regulations 2007 came into
force on 6th April 2007; they replace the CDM Regulations 1994 and the
Construction (Health, Safety and Welfare) Regulations 1996. The key aim
of CDM2007 is to integrate health and safety into the management of a
project and to encourage everyone involved, to work together. The
principles of cdm apply to all construction projects; however, notification
applies where work:
—
will last more than 30 days, or
—will involve more than four persons working on site at any time,
or
—
will involve more than 500 person days.
CDM Regulations identify task functions of the client, designers, the cdm
coordinator, principal contractor and contractors that must be carried out
by nominated bodies.
Contract energy management (cem). A service providing technical,
financial and management resources to implement an energy saving
project. Remuneration for the service is often by retention of a proportion
of the savings. The cem contractor can also bear a higher proportion of the
financial risk of any investment.
Building energy management system (bems). A computer-based system
for remote control and monitoring of building services used for interactive
energy management.
Cylindrical rotor generator. A type of electricity generator. As frequency
depends on the speed multiplied by the number of pole pairs, higher
speeds require fewer poles and the excitor winding can be accommodated
in radial slots machined into the periphery of the rotor.
Calorific value (cv). The heat energy available from a fuel when it is
completely burnt, expressed as heat energy units per unit of weight or
volume of the fuel. The gross or higher calorific value (gcv/hcv) is the
total heat energy available when all the products of combustion are cooled
to standard conditions and the heat released from the condensation of
water vapour is included. The net or lower calorific value (ncv/lcv) is the
total heat energy released from combustion excluding the latent heat of
the water vapour from condensation of the products of combustion.
Demand; maximum demand; demand profile. The rate at which energy
is required, expressed in kW or MW. It is usually related to a time period,
typically half an hour, e.g. 1 kW·h used over half an hour is a demand rate
of 2 kW. Maximum demand is the highest half-hourly rate at which
electricity is required during a month or year. Peak load or peak demand
are the terms usually used for heat energy. A graph of demand rate over a
typical day, for example, is the demand profile.
Cascade control. A system that automatically starts up or stops units in a
predetermined sequence to meet variations in the energy demands being
served. The sequence may be changed periodically to ensure that the
running time of each unit is approximately equal.
Catalytic converters. Devices used to convert undesirable components of
exhaust gases into other less objectionable forms. There are two catalytic
conversion processes relevant to chp plant:
Selective catalytic reduction. Reduction of NOx by injecting
—
ammonia ahead of a vanadium or titanium catalyst to initiate a
chemical reaction to convert NOx and NH3 into N2 and H2O;
>95% reduction of NOx may be achieved.
—
Oxidation catalytic conversion. Reduction of CO and nonmethane hydrocarbons by use of an oxidation catalyst.
Conversion of CH3 through CH8 is highly temperature depend­
ent, requiring temperatures above 415 °C for any significant
reduction.
cchp.
See Tri-generation.
CO, carbon monoxide; CO2, carbon dioxide. Oxides of carbon produced
by fuel combustion. CO represents incomplete combus­tion and can be
burnt to CO2 , which is the product of complete combustion.
Coefficient of performance (cop). For a refrigeration system, the ratio of
useful cooling effect to the total energy input to the system. For a heat
pump system the ratio of useful heating effect to the total energy input to
the system.
Diesel engine. A generic term for compression ignition reciprocating
engines, whatever the fuel used.
Discount factor. The factor used to convert net annual cash flow to
present value, depending on the interest rate and the number of years from
present. Calculated by a derivation of the compound interest formula:
df
= 1/ (1 + r /100) n
where r is the interest rate (%), n is the number of years from present.
Discounted cash flow (dcf); internal rate of return (irr). The
discounting rate that gives a ‘break even’ result, i.e. zero net present value.
It can be compared with other investments or the cost of borrowing.
Discounted cash flow (dcf), net present value (npv). The value of cash
inflows less the value of cash outflows over the life of a project, with all
future cash flows discounted back to present day values. Used to compare
optional projects against a common index
Distribution Network Operator (dno). The companies that own and
operate the public electricity network under licence.
Dual-fuel. The use of two fuels in a prime mover or boiler. They may be
alternatives, e.g. with one as standby if the main fuel supply is interrupted,
or simultaneous, e.g. gas plus a small proportion of diesel used in
compression ignition engines.
Co-generation. See Combined heat and power.
Energy audit. A review of energy use and costs normally performed in
conjunction with a site investigation.
Combined heat and power (chp). Combined generation of heat and
electricity. Also known as co-generation.
Energy manager. A person in an organisation with responsibility for
energy matters.
Compression ignition. System used in reciprocating engines whereby
fuel is injected after compression of the air and is ignited by the heat
generated by compression. As pre-ignition is thereby eliminated, higher
compression ratios than with spark ignition engines can be utilised, with
corresponding higher energy conversion efficiency.
Energy service companies (escos). Companies offering a total energy
supply service who take responsibility for provision, financing, operation
and maintenance of energy facilities. Energy services contracts may be
worded to define the outcome of the service provided, temperatures and
light levels, rather than how much energy is to be supplied.
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Appendices
65
Energy survey, comprehensive. A detailed site investigation of specified
aspects of energy use providing firm recommendations for energy saving
measures.
Medium temperature hot water (mthw). Pressurised hot water at 95 ºC
to 120 ºC used for space heating and process.
Energy survey, concise. A short site examination of specified aspects of
energy use to identify potential energy saving measures.
Monitoring and target setting (m&t). A method of energy management
in which real energy consumption is recorded regularly and related to
specific variables to allow comparison with the standard or target values
calculated. Corrective action is then taken where appropriate.
Excess air. Reciprocating engines and gas turbines have to operate with
far more air than is needed purely for the combustion of the fuel. This
excess over requirements forms the major proportion of the exhaust gases
and is termed excess air.
Fault level. The maximum prospective current that can flow under a
3-phase short-circuit condition. It should be noted that it may vary
according to the point in the system at which the fault occurs. The
magnitude of the fault level has a major influence on the choice and design
of the equipment to be used.
Montreal Protocol. International agreement signed at Montreal in 1990
to control the use of and ultimately reduce the release of substances into
the atmosphere that contribute to depletion of the ozone layer. Substances
covered by the protocol include those used as refrigerants and firesuppressants such as:
—
cfc:
—
hcfc:
—
hfc:
hydrofluorocarbon
Gas supply, interruptible. A supply of gas, which may be interrupted
within specified limits at the discretion of the supply company allowing
lower contract prices than a firm supply for large users. The allowable
interruption period is negotiable.
—
btm:
bromotrifluoromethane
—
bcf:
Gas supply, firm. A supply of gas available continuously.
Network. The distribution system which links energy production to
energy usage. Mostly applied to electricity.
Frequency. The number of times per second that alternating current
changes direction. Frequency is expressed as hertz (Hz). The public
electricity supply frequency in the UK is 50 Hz.
Generator. An alternator or dc generator. ‘Generator set’ refers to the
combination of prime mover and generator.
Heat exchanger. A device in which heat is transferred from one fluid
stream to another without mixing. There must obviously be a temperature
difference between the streams for heat exchange to occur. They are
characterised by the method of construction or operation, e.g. shell-andtube, plate, rotary.
Heat-to-power ratio. The amounts of heat energy and electricity produced
by a chp unit, expressed as a ratio.
High temperature hot water (hthw). Pressurised hot water at 120 ºC and
above used for space and/or process heating.
In-duct burner. A burner sited inside the duct of the air or gas stream it is
heating, and thus also adding its combustion products to the stream. A
typical method of supplementary firing where direct heat recovery is
employed.
ippc.
Integrated pollution prevention and control
Load factor. The average intensity of usage of energy producing or
consuming plant expressed as a percentage of its maximum rating. An
annual load factor, for example, would be:
Annual heat consumption Í 100
Load factor (%) = ——————————————
Peak demand Í 8760
Low temperature hot water (lthw). Hot water at up to 95 ºC used for
space heating and low temperature process.
Maximum demand (md). Maximum power, measured in kW or kVA,
supplied to a customer by a supply/distribution company, equal to twice
the largest number of kW·h or kVA·h consumed during any half-hour in a
specified period (usually a month). Charges for maximum demand usually
vary seasonally.
Measures, medium cost. Investment measures that involve a medium
level of capital expenditure.
Measures, good housekeeping. Actions that can be taken to save energy,
requiring no capital expenditure.
Measures, low cost. Energy saving measures requiring minimal capital
expenditure.
Measures, high cost. Measures involving major capital expenditure that
may need further study and authorisation at executive level.
chlorofluorocarbon
hydrochlorofluorocarbon
bromochlorofluoromethane
Parasitic load. Electricity used within the chp plant itself and therefore
reducing the amount available for beneficial use.
Particulate. Particles of solid matter, usually of very small size, derived
from the fuel either directly or as a result of incomplete combustion and
considered deleterious emissions.
Performance guarantees. Performance guarantees may be defined by
reference to absolute measures such as absolute quantity of heat or power
produced. However, these will depend on uncontrollable factors such as
warm or cold winters. Alternative measures attempt to assess the degree to
which the plant was capable of providing its specified output. These
indicators are availability, reliability and utilisation and are defined below,
where A is the actual hours plant was run during period (h), P is the
planned operating hours in period, S is the scheduled plant downtime for
maintenance and U is the unscheduled plant downtime for plant defects.
Availability defines what might reasonably be expected of, or is achieved
from, the plant allowing for scheduled and unscheduled downtime:
P – (S + U)
Availability = ­­­­—————
P
Reliability measures the unscheduled downtime of the plant:
P – (S + U)
Reliability = ­­­­—————
P–S
Utilisation is a measure that takes into account when the plant was actually
running and so includes all occasions when the plant was prevented from
operating by external factors, e.g. low heat load:
Utilisation = A / P
Performance indicator (pi). The value of annual energy consumption
related to a building or site characteristic; most commonly kW·h per
square metre of floor area under consideration.
Planning co-ordinator. Function defined under the CDM Regulations.
The planning co-ordinator is responsible for collating information for the
health and safety file.
Combined heat and power for buildings
Power factor. The quantification of the time lag between the voltage wave
and the current wave expressed as the cosine of the angle (f ) between true
(active) power (kW) and apparent (reactive) power (kVA).
cos f = [kW] / [kVA]
Supply contracts usually have a direct or indirect penalty charge for poor
power factor (say below 0.95), which can be avoided by installing power
factor correction equipment.
Premium. A general term to describe the quality of a fuel in terms of
handling/storage combustion, consistency of composition, pollutants etc.,
e.g. natural gas high premium, heavy fuel oil low premium. Fuel price
usually follows premium value.
Principal contractor. A function defined under the CDM Regulations.
Programmable logic control (plc). A programmable device for the
control of a system accor­ding to a predetermined logic.
Reciprocating engine. Machine in which the mechanical power is
produced by the to-and-fro (‘reciprocating’) movement of a piston within
a cylinder; such machines are so called to distinguish them from purely
rotating machines such as turbines.
Salient pole generator. A type of electricity generator. As frequency
depends on speed multiplied by the number of pole pairs, lower speeds
require more poles than can be accommodated within the rotor periphery.
The excitor winding is therefore formed with copper strip or coils of wire
attached to the surface of the rotor.
Sankey diagram. A diagram demonstrating graphically and in true
proportion the energy flows in a system, starting with the energy sources
and showing losses, heat exchange loops etc. to the degree desired.
Shell-type boiler. A cylindrical steam, hot water or thermal boiler, usually
horizontal but possibly vertical. The shell contains water or oil that is
heated by the burner flame and combustion products in a chamber and
tube or annular flueways inside the shell. Sometimes called a fire tube
boiler in contrast to the water tube boiler. A typical shell boiler is in fact a
specialised shell-and-tube heat exchanger.
Simple payback period. The time calculated to recover an investment
when the capital cost of implementing a measure is divided by the net
annual saving.
Soft-start. A technique for starting a motor from rest which reduces the
maximum current drawn during start-up.
SOx. A generic term for oxides of sulphur produced by the combustion of
sulphur in the fuel, and considered as deleterious emissions. Their
presence in flue gases can restrict thermal efficiency, because if the flue gas
temperature is reduced below specific levels, highly corrosive sulphurous
and sulphuric acids are deposited on heat exchange surfaces.
Spark ignition. A reciprocating engine that utilises an electrical spark to
ignite the compressed air/fuel mixture in the cylinders.
stw.
Setting to work, taken to include testing and commissioning
Supplementary firing. The firing of additional fuel in the chp heat
recovery unit, utilising the hot oxygen present in the prime mover exhaust
gases as excess air.
Synchronism. The condition whereby generator frequency, voltage levels
and phase angle match those of the public supply. When operating in
parallel mode, it is obligatory to maintain these levels within closely
specified limits.
Total energy plant. See Combined heat and power.
Transformers (voltage). A device with primary and secondary windings
to convert the voltage of electricity from one value to another. Transformers
may be step-up or step-down, i.e. voltage increased or reduced, and there
may be more than one secondary tapping to give a choice of output voltage.
Shaft efficiency. That percentage of its initial energy supply that a prime
mover delivers as mechanical energy at its output shaft.
Tri-generation. Combination of chp with absorption chilling to give
simultaneous production of heat, power and cooling; often power and heat
in winter, power and cooling in summer.
Shell-and-tube heat exchanger. A unit having a bundle of tubes contained
in a cylindrical shell. One fluid flows through the tubes, the other through
the shell.
Uninterruptible power supply (ups). Device for maintaining power to a
service for a limited period following a supply failure. Used to maintain
essential service supply and to allow for controlled shut-down of sensitive
equipment.
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Index
Index
Note: page numbers in italics refer to figures.
absorption chillers 8, 34, 43, 61–62, 64
acceptance criteria 49
acceptance testing 55
acoustic enclosures 6, 47
adsorption chillers 8, 64
air quality management 26–27
air supply systems 44–45
air turbines 9
ambient temperatures 5, 48
anaerobic digestion (ad) 11
asynchronous generators 6
auxiliary firing 7, 64
availability, plant 58, 66
availability charge 64
(building energy management systems)
45, 64
biogas chp 9–10, 11
bioliquids 10
biomass chp 8–9
biomass gasifiers 9–10, 11
biomethane injection 11
building applications 2, 17
building energy management system (bems)
45, 64
building heating systems, integration with
16–17, 20–21, 32, 41–43, 50, 60
Building Regulations 28
bypass flows 19, 20
bems
calorific values (cv) 24, 64
capacity see sizing
capital costs 34
carbon emissions 3, 14–15, 24–25, 28, 64
Carbon Reduction Commitment (CRC) 28
carbon trading 28
cascade control 42, 64
catalytic converters 26, 44, 64
CDM Regulations (2007) 39
cem (contract energy management) 37, 65
chimneys 27
CHPA (Combined Heat and Power Association) 4
CHPQA (CHP Quality Assurance Programme)
28–29
client acceptance testing 55
Climate Change Act (2008) 28
Climate Change Levy exemption 47
CO2 emissions 3, 14–15, 24–25, 28, 64
coefficient of performance (cop) 22
combined cooling, heating and power (cchp)
see tri-generation
Combined Heat and Power Association (CHPA) 4
combustion air supply 44
combustion exhaust systems 44, 45
combustion gases 26–27
commissioning 49, 54, 61
component testing 53–54
compression ignition 7, 65
condition monitoring 57
Construction (Design and Management) Regulations 39
consultants 39
consumable spare parts 58–59
contract energy management (cem) 37, 65
contractors
responsibilities 39
selection 51
contracts
maintenance 58
67
contracts (continued)
procurement 51–52
Control of Noise at Work Regulations (2005)
40
control systems 32, 45, 46
conversion factors 64
cooling air supply 44
cooling demand 12–13
cooling systems 8, 22
cost appraisal 34–36, 52, 59–60
CRC Energy Efficiency Scheme 28
cylindrical rotor generator 65
data logging 56
delivery of equipment 49
demand loads 12–13, 30–32, 65
design 39–51, 61
diesel engines 7, 65
differential pressure control valves (dpvc) 18
discounted cash flow (dcf) 35–36, 65
distribution network operators (dno) 65
grid connection 29, 32, 43, 47
district cooling 22
district heating 4, 18–22, 49, 60
diversity of demand 19, 50
dno see distribution network operators (dno)
documentation 49, 54, 56
domestic chp 6–7
downtime 58
dpcv (differential pressure control valves) 18
dual-fuel options 33, 65
dual-fuel reciprocating engines 7
economic appraisal 34–36, 52, 59–60
electrical demand 12, 31
electrical efficiency 23, 34
electrical generators 6, 32, 65
micro-turbines 6
standby operation 17–18, 43–44
voltage generated 48
electrical systems 32, 43–44
Electricity at Work Regulations (1989) 39
electricity export 15, 19, 29
electricity tariffs 13
emission control 26
emission reduction targets 28
emissions trading 28
energy audits 31, 65
energy demand 12–13, 30–33
energy efficiencies 2, 22–24, 28
energy flows 33
energy from waste 10–11
energy manager 65
energy savings 2, 22–26
energy service companies (esco) 37–38, 65
energy strategy 1, 28
energy surveys 31, 65
energy tariffs 13, 56
energy units 64
Enhanced Capital Allowances (ECAs) 29
environmental impacts 26–27, 60
see also CO2 emissions
equipment supplier finance (esf) 36–37
equivalent heat efficiency 22–23
escos (energy service companies) 37–38, 65
European Union Emissions Trading Scheme
(EU ETS) 28
excess air 26, 65
exhaust gases
air quality issues 26–27
heat recovery 5, 16, 33, 40, 45
temperature 33
exhaust noise 47
exhaust systems 44
exhaust termination 48
existing buildings 20–21
fault levels 32, 43, 65
feasibility studies 30–38, 59
feed-in tariffs 15, 29
financial appraisal 34–36, 52, 59–60
financial incentives 3, 28–29
financing options 36–38, 52
fire detection, protection and suppression
47, 48
flow control 41, 42, 50
flow rates 18, 20
flow temperature see operating temperatures
flue dispersion modelling 27
flue gases see exhaust gases
flushing and filling 53
fuel cells 6–7, 7–8
fuel oil, calorific value 64
fuel options 33
fuel supply 48
fuel tariffs 13, 56
gas boilers
CO2 emissions 25
equivalent heat efficiency 23, 24
gas detection systems 47
gas engine chp units 5–6
gas leakage detection 40
gas safety 39–40, 44
Gas Safety (Installation and Use) Regulations
(1998) 39–40
gas supply 33, 44, 65
gas turbine chp 6, 7
gas-fired power stations
relative CO2 emissions 3, 25
relative efficiencies 23, 24
gasification systems 9–10, 11
generators see electrical generators
government policy 3, 28–29
grid connection 29, 32, 43, 47
grid efficiency 22–24
gross calorific value (gvc) 24
handover 54
health and safety 39–40, 44
heat demand 12–13, 32
heat distribution systems 16–17, 32, 41–42, 50
heat efficiency 22–24
heat exchangers 5, 16, 40, 65
district heating 19, 49
domestic hot water 19
heat pumps 11–12, 18
CO2 emissions 25
equivalent heat efficiency 22, 23, 24
heat recovery 16, 41
exhaust gases 5, 16, 33, 40, 45
options 33
ventilation exhaust 33, 45
heat rejection 16, 40, 45, 47, 48
heating systems see building heating systems
heat-to-power ratio 23, 65
high temperature hot water (hthw) 7, 65
hot water heating 19
demand 12, 16, 17
district heating 49, 50
hydrogen fuel 7
in-duct burners 65
installation 53, 61
instrumentation 32, 45
insulation, pipe systems 50–51
integrated pollution prevention and control
(ippc) 26–27, 65
intercooler heat recovery 5, 33, 40, 41
internal rate of return (irr) 14, 15, 35–36, 65
investment appraisal 13–15, 34–36
invitations to tender (itt) 51
ippc (integrated pollution prevention and control) 26–27, 65
joint ventures 38
landfill gas 10
leasing arrangements 38
legislation 28–29
health and safety 39
plant emissions 26–27
liquid biofuels 10
load control 18
load factor 65
load profiles 12–13, 30–32
low temperature hot water (lthw) 16, 65
lubricating oil storage and handling 27, 46, 49
m&t
(monitoring and target setting) 37, 66
maintenance 45–46, 57–59
contracts 49, 58
costs 34
manuals 56
schedules 57
maintenance costs 34
maximum demand (md) 18, 65
measures (energy efficiency) 2, 65–66
medium temperature hot water (mthw). 66
metering 31, 32, 48
micro gas turbine chp 6, 9
mini-chp 6
monitoring
energy demand 31, 32
plant 45, 46, 48, 55–56, 57, 58
monitoring and target setting (m&t) 37, 66
Montreal Protocol 66
multiple chp units 15–16
multiple heat sources 22
natural gas
calorific value 24, 64
efficient use of 2
supply 33
net calorific value (ncv) 24
net present value (npv) 14, 15, 35–36, 65
new buildings 19, 32
noise control 27, 46–47
NOx emissions 10, 26, 27, 48
occupancy, building 17
off-site testing 49, 53–54
oil sample monitoring 57
oil spillage 27
operating temperatures 16–17, 41
control of 43
district heating 18, 19, 20, 49
specification 48
thermal stores 21
operation of plant 55–56, 61
operating costs 3, 34
Combined heat and power for buildings
operating hours 12, 15
operating manuals 56
operating models 13
operating services 56
operating strategies 33, 48, 55
organic Rankine cycle (orc) 9
package specification 48–49
parasitic loads 58, 66
particulate emissions 26, 66
part-load operation 15, 19, 20, 41, 43
peak boilers 19, 20–21, 50
peak demand 12, 13, 20–21
performance of plant 33
energy efficiencies 2, 22–24
guarantees 58, 66
monitoring 56
performance indicator (pi) 66
specification for tendering 51
targets 37
pipe systems 22, 47, 50
insulation 50–51
planning conditions 48
planning co-ordinator 39, 66
planning legislation 28
pollution control 26–27
power demand 12, 31
power distribution systems 43–44
power factor 66
power stations
district heating schemes 22
relative CO2 emissions 3, 25
relative efficiencies 23, 24
pre-insulated pipework 50–51
premium (fuel quality) 66
principal contractor 66
procurement 51–52, 60–61
programmable logic control (plc) 66
pump control 50
pyrolysis 11
Quality Assurance (CHPQA) Programme
28–29
reciprocating engines 2, 6, 7, 66
refurbished buildings 19
regulatory systems 47
reliability of plant 58, 66
renewable energy and chp 8–12, 11, 25
Renewable Heat Incentive 29
Renewable Obligation Certificates (ROCs) 29
responsibilities 39
retrofit 20–21
return temperatures see operating temperatures
ROCs (Renewable Obligation Certificates) 29
salient pole generators 66
Sankey diagram 66
scope of package 48
security of electricity supply 3, 17–18, 25–26
servicing of plant 57–59
setting to work (stw) 54, 66
shaft efficiency 66
shell-and-tube heat exchangers 40, 66
shell-type boilers 16, 66
simple payback period 34–35, 66
siting of plant 48
sizing
chp plant 13–16, 33, 48
distribution pipework 50
small-scale chp 6–7, 9, 16, 43
soft-start 43–44, 66
solar photovoltaic 11
solar thermal 11
SOx 66
spare parts 58–59
spark-ignition gas engines 5–6, 66
specification 48–49
standby boilers 50
standby operation 18, 43–44
steam turbines 9, 10
Stirling engines 6, 9
stw (setting to work) 54, 66
sulphur oxides 66
supplementary firing 7, 66
synchronism 66
synchronous generators 6
syngas 9, 11
system testing 53–54
tariffs 13, 56
feed-in 15, 29
technical specification 48–49, 51
tenders 51–52
testing of plant 49, 53–54
thermal efficiency 22–23
thermal storage 15, 21–22
feasibility studies 33–34
operational issues 42–43
thermal treatment of waste 11
training requirements 49
transformers (voltage) 32, 43, 67
tri-generation 3, 8, 26, 34, 61–62, 67
turbocharged engines 5, 33, 40
types of chp 2
UK Building Regulations 28
UK government policy 3, 28–29
uninterruptible power supply (ups) 67
utilisation of plant 2, 17, 30–31, 66
variable flow control 41, 50
ventilation air exhaust
air quality issues 27
heat recovery 33, 45
ventilation of plant 40, 44–45
vibration control 46–47
voltage generated 48
waste-to-energy technology 10–11
water quality 22
wind turbines 11
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