Small and Micro Combined Heat and Power (CHP) Systems: Advanced Design, Performance, Materials and Applications (Woodhead Publishing Series in Energy)

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Small and micro combined heat and power (CHP) systems

© Woodhead Publishing Limited, 2011

CHP-Beith-Pre.indd 1

5/6/11 11:05:11 AM

Related titles: Stand-alone and hybrid wind energy systems (ISBN 978-1-84569-527-9) Wind power generation is fast becoming one of the leading renewable energy sources worldwide, with increasing penetration of stand-alone and hybrid wind energy systems, particularly in distributed, isolated, and community power networks. Advanced energy storage and grid integration systems are required to provide secure, reliable power supply to the end user. This book provides a comprehensive overview of the development of stand-alone and hybrid wind energy systems, as well as energy storage and buildinggrid-integration systems. Chapters cover the design, construction, monitoring, control and optimisation of stand-alone and hybrid wind energy technologies, and the continuing development of these systems. Solid oxide fuel cell technology (ISBN 978-1-84569-628-3) High temperature solid oxide fuel cell (SOFC) technology is a promising power generation option which features high electrical efficiency and low emissions of environmentally polluting gases such as CO2, Nox and SOx. It is ideal for distributed stationary power generation applications where both high-efficiency electricity and high-quality heat are in strong demand. This book presents a systematic and in-depth narrative of the technology from the perspective of fundamentals, providing comprehensive theoretical analysis and innovative characterisation techniques for SOFC technology. The book covers the development of SOFC technology, from cell materials and fabrication, to performance analysis and stability and durability issues. Waste to energy (WTE) conversion technology (ISBN 978-0-85709-011-9) Increasing global consumerism and population has led to an increase in the levels of waste produced. Energy recovery represents a useful, additional option in support of an improved and sustainable waste management hierarchy, in local energy supply and wider energy security. Advanced conversion technologies coupled with advanced pollution control systems can be employed to convert these calorific waste materials into clean energy, which can be integrated into buildings, distributed energy networks and national electricity grids. This book provides an integrated, comprehensive reference on waste to energy (WTE) conversion technology. Details of these books and a complete list of Woodhead’s titles can be obtained by:  visiting our web site at www.woodheadpublishing.com  contacting Customer Services (e-mail: [email protected]; fax: +44 (0) 1223 832819; tel.: +44 (0) 1223 499140 ext. 130; address: Woodhead Publishing Limited, 80 High Street, Sawston, Cambridge CB22 3HJ, UK)

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5/6/11 11:05:11 AM

Woodhead Publishing Series in Energy: Number 18

Small and micro combined heat and power (CHP) systems Advanced design, performance, materials and applications Edited by Robert Beith

Oxford

Cambridge

Philadelphia

New Delhi



5/6/11 11:05:11 AM

Published by Woodhead Publishing Limited, 80 High Street, Sawston, Cambridge CB22 3HJ, UK www.woodheadpublishing.com Woodhead Publishing, 1518 Walnut Street, Suite 1100, Philadelphia, PA 19102-3406, USA Woodhead Publishing India Private Limited, G-2, Vardaan House, 7/28 Ansari Road, Daryaganj, New Delhi – 110002, India www.woodheadpublishingindia.com First published 2011, Woodhead Publishing Limited © Woodhead Publishing Limited, 2011 The authors have asserted their moral rights. This book contains information obtained from authentic and highly regarded sources. Reprinted material is quoted with permission, and sources are indicated. Reasonable efforts have been made to publish reliable data and information, but the authors and the publisher cannot assume responsibility for the validity of all materials. Neither the authors nor the publisher, nor anyone else associated with this publication, shall be liable for any loss, damage or liability directly or indirectly caused or alleged to be caused by this book. Neither this book nor any part may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, microfilming and recording, or by any information storage or retrieval system, without permission in writing from Woodhead Publishing Limited. The consent of Woodhead Publishing Limited does not extend to copying for general distribution, for promotion, for creating new works, or for resale. Specific permission must be obtained in writing from Woodhead Publishing Limited for such copying. Trademark notice: Product or corporate names may be trademarks or registered trademarks, and are used only for identification and explanation, without intent to infringe. British Library Cataloguing in Publication Data A catalogue record for this book is available from the British Library. ISBN 978-1-84569-795-2 (print) ISBN 978-0-85709-275-5 (online) ISSN 2044-9364 Woodhead Publishing Series in Energy (print) ISSN 2044-9372 Woodhead Publishing Series in Energy (online) The publisher’s policy is to use permanent paper from mills that operate a sustainable forestry policy, and which has been manufactured from pulp which is processed using acidfree and elemental chlorine-free practices. Furthermore, the publisher ensures that the text paper and cover board used have met acceptable environmental accreditation standards. Typeset by Replika Press Pvt Ltd, India Printed by TJI Digital, Padstow, Cornwall, UK



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Contents

Contributor contact details

xiii

Woodhead Publishing Series in Energy

xvii

Preface

xxi

Part I Introduction to small and micro combined heat and power (CHP) systems 1

Overview of small and micro combined heat and power (CHP) systems J. Knowles, Barbreck Services, UK

1.1 1.2 1.3 1.4 1.5 1.6 1.7

Introduction to cogeneration – a short history Types of technology and potential applications Energy efficiency improvement Cost benefits and emissions reduction Grid connection Barriers to combined heat and power (CHP) Future trends

3 5 11 12 13 15 16

2

17

Techno-economic assessment of small and micro combined heat and power (CHP) systems A. D. Hawkes, Imperial College London, UK

2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

Introduction The economics of combined heat and power (CHP) Techno-economics for onsite generation A specific modelling methodology Case study: micro combined heat and power (CHP) Future trends Sources of further information and advice References

17 18 21 23 28 39 40 41

3



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vi

Contents

3

Thermodynamics, performance analysis and computational modelling of small and micro combined heat and power (CHP) systems T. T. Al-Shemmeri, Staffordshire University, UK

3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 4

4.1 4.2 4.3 4.4 4.5 4.6 4.7 5 5.1 5.2 5.3 5.4

Introduction Types of combined heat and power (CHP) systems Thermodynamics of cogeneration Performance analysis of cogeneration cycles Theory of heat exchangers Worked example Computational modelling of a combined heat and power (CHP) cycle Analysis of the computational model of the combined heat and power (CHP) system Case study: system performance of a biogas-driven small combined heat and power (CHP) system in a sewage works Sources of further information and advice References and further reading Integration of small and micro combined heat and power (CHP) systems into distributed energy systems J. Deuse, GDF-SUEZ – Tractebel Engineering, Belgium Distributed energy resources (DER) The value of distributed generation Conditions for profitable decentralized generation Evaluating the ‘full value’ of being network connected Recommendations to distribution system operators (DSO) and regulators Acknowledgement References Biomass fuels for small and micro combined heat and power (CHP) systems: resources, conversion and applications H. Liu, University of Nottingham, UK Introduction Characterisation of solid biomass fuels Biomass conversion technologies Current development of small and micro scale biomass combined heat and power (CHP) technologies

42 42 43 44 48 48 51 54 55 60 68 68

70 70 73 75 78 81 87 87

88 88 91 94 107



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Contents

5.5 5.6 5.7

Conclusions Acknowledgements References

vii

116 116 117

Part II Development of small and micro combined heat and power (CHP) systems and technology 6

Internal combustion and reciprocating engine systems for small and micro combined heat and power (CHP) applications R. Mikalsen, Newcastle University, UK

6.1 6.2 6.3 6.4 6.5 6.6 6.7

Introduction Types, properties and design of engine Engine operating characteristics and performance Installation and practical aspects Commercially available units Conclusions References

7

Microturbine systems for small combined heat and power (CHP) applications J. L. H. Backman and J. Kaikko, Lappeenranta University of Technology, Finland

125 125 126 133 138 140 145 145 147

7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8

Introduction Cycle performance Types and properties of microturbine components Operation Manufacturers and applications Future trends Sources of further information and advice References

147 152 160 166 172 174 176 176

8

Stirling engine systems for small and micro combined heat and power (CHP) applications J. Harrison, E.ON Engineering, UK

179

8.1 8.2 8.3 8.4 8.5

Introduction Definition of a Stirling engine Why Stirling engines are suited to micro combined heat and power (CHP) The Stirling cycle Types of Stirling engine

179 180 181 183 188



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Contents

8.6

Development of Stirling engines for micro combined heat and power (CHP) applications Micro combined heat and power (CHP) design and system integration Applications and future trends Sources of further information and advice References

8.7 8.8 8.9 8.10 9

9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 10

10.1 10.2 10.3 10.4 10.5 10.6 10.7

Organic Rankine cycle (ORC) based waste heat/waste fuel recovery systems for small combined heat and power (CHP) applications J. Larjola, Lappeenranta University of Technology, Finland Introduction Principle of the organic Rankine cycle (ORC) process Typical process heat sources and operating ranges for organic Rankine cycle (ORC) systems Benefits and disadvantages of organic Rankine cycle (ORC) process as compared to water-based systems Selection of working fluid for organic Rankine cycle (ORC) systems Process system alternatives Background and summary of commercial development and exploitation Efficiency and typical costs for current organic Rankine cycle (ORC) plants References Fuel cell systems for small and micro combined heat and power (CHP) applications D. J. L. Brett, University College London, UK, N. P. Brandon and A. D. Hawkes, Imperial College London, UK and I. Staffell, University of Birmingham, UK Introduction Fundamentals of operation, types and properties of fuel cells Fuel cell systems Operating conditions and performance Commercial development and future trends Sources of further information and advice References

189 199 203 205 205

206

206 206 207 213 219 221 223 230 231 233

233 234 239 246 253 257 257



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Contents

11

11.1 11.2 11.3 11.4 11.5 11.6 11.7 11.8 11.9 11.10 11.11 11.12 11.13 11.14 11.15 12

Heat-activated cooling technologies for small and micro combined heat and power (CHP) applications K. Gluesenkamp and R. Radermacher, University of Maryland, USA Introduction Introduction to small-scale trigeneration Types of cooling systems and their applications Open sorption cycles: desiccant dehumidification Closed sorption cycles: absorption and adsorption heat pumps Steam ejector cycle Component-specific efficiency and effectiveness metrics System-wide performance and efficiency metrics Advantages and limitations of heat-activated cooling Future trends Sources of further information and advice References Bibliography Appendix 1: Nomenclature and abbreviations Appendix 2: Notes on terminology Energy storage for small and micro combined heat and power (CHP) systems A. Price, Swanbarton Ltd, UK

12.1 12.2 12.3 12.4 12.5

Introduction Types of energy storage (ES) systems Applications of electrical energy storage Applications for combined heat and power (CHP) systems Grid services applications and relationship to combined heat and power (CHP) 12.6 Electrical vehicles 12.7 Large-scale and small-scale storage – conceptual planning 12.8 The development and application of thermal storage 12.9 Future trends 12.10 Sources of further information and advice

ix

262

262 263 267 269 279 284 285 290 296 297 299 301 303 305 305 307 307 308 309 315 317 318 318 318 321 322

Part III Application of small and micro combined heat and power (CHP) systems 13

325

Micro combined heat and power (CHP) systems for residential and small commercial buildings J. Harrison, E.ON Engineering, UK

13.1

Introduction

325 © Woodhead Publishing Limited, 2011


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x

Contents

13.2 13.3

Basic issues and energy requirements Types of system for residential and small commercial buildings Domestic applications for micro combined heat and power (CHP) Small commercial buildings and other potential applications Advantages and limitations Future trends Sources of further information and advice References

13.4 13.5 13.6 13.7 13.8 13.9 14

326 329 331 336 341 344 345 345

District and community heating aspects of combined heat and power (CHP) systems J. Clement, Aars District Heating, Denmark, N. Martin, Shetland Heat Energy and Power, UK and B. Magnus, COWI, Denmark

14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8 14.9

Introduction How to get started Heat sources Pipework installation issues and design considerations Control system and consumer installations Case study: Lerwick, Shetland Case study: Aars, Denmark Future trends Sources for further information and advice

347 348 349 351 353 359 360 363 364

15

Small combined heat and power (CHP) systems for commercial buildings and institutions R. Boukhanouf, University of Nottingham, UK

365

15.1 15.2 15.3

Introduction Basic issues and energy requirements Small combined heat and power (CHP) use in commercial buildings and institutions 15.4 Small-scale combined heat and power (CHP) technology 15.5 Application of small-scale combined heat and power (CHP) technology in buildings 15.6 Performance analysis and optimisation 15.7 Merits and limitations of small-scale combined heat and power (CHP) 15.8 Future trends 15.9 Sources of further information and advice 15.10 References

347

365 366 368 369 377 386 389 390 392 393



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Contents

16

Small and micro combined heat and power (CHP) systems for the food and beverage processing industries P. S. Varbanov and J. J. Klemeš, University of Pannonia, Hungary

16.1 16.2

Introduction Food processing and energy requirements – examples for specific food and drink industries 16.3 Heat and power integration of food total sites 16.4 Types of small and micro combined heat and power (chp) suitable for the food industry 16.5 Established combined heat and power (chp) technologies for the food industry 16.6 High-efficiency technologies in theoretical and demonstration stages 16.7 Integration of renewables and waste with food industry energy demands 16.8 Potential applications 16.9 Future trends 16.10 Sources of further information and advice 16.11 References 17

17.1 17.2 17.3 17.4 17.5 17.6 17.7 18

Biomass-based small and micro combined heat and power (CHP) systems: application and status in the United Kingdom A. V. Bridgwater, A. Alcala and M. E. Gyftopoulou, Aston University, UK UK energy policy and targets Renewables and combined heat and power (CHP) in the UK Technical challenges for small-scale biomass combined heat and power (CHP) systems Capital costs for small-scale biomass combined heat and power (CHP) systems Conclusions Acknowledgement References

Thermal-engine-based small and micro combined heat and power (CHP) systems for domestic applications: modelling micro-CHP deployment K. Mahkamov, Northumbria University, UK

18.1

Introduction

xi

395

395 396 397 400 404 406 411 414 419 421 423

427

427 429 450 452 455 456 456

459 459



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Contents

18.2

Prime movers deployed in micro and small combined heat and power (CHP) systems Product development in the micro and small combined heat and power (CHP) market Overview of the method for estimation of economical and environmental benefits from deployment of micro combined heat and power (MCHP) technology in buildings Heat demand modelling Electrical demand Performance mapping Economic and environmental analysis References

18.3 18.4

18.5 18.6 18.7 18.8 18.9

Epilogue

R. Beith, Beith & Associates, UK

Index

460 470

480 483 490 492 500 508 510

514



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(* = main contact)

Editor and Epilogue

Chapter 3

Robert Beith Beith & Associates Ltd 11 Links Avenue Felixstowe Suffolk IP11 9HD UK

T. T. Al-Shemmeri Faculty of Computing, Engineering and Technology Staffordshire University Stafford ST18 0AD UK

E-mail: [email protected]


Chapter 1

Chapter 4

J. Knowles Barbreck Services Station Road Muthill Perthshire PE5 2AR UK

J. Deuse Rue de Corbais 51 B1435 Hévillers Belgium E-mail: [email protected]

E-mail: joeknowles@barbreckservices. co.uk

Chapter 2 A. D. Hawkes Grantham Institute for Climate Change Imperial College London South Kensington London SW7 2AZ UK

formerly of Power System Consulting, Department of Power and Gas GDF-SUEZ Tractebel Engineering Avenue Ariane 7 B1200, Brussels Belgium




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xiv


Chapter 5

Chapters 8 and 13

H. Liu Department of Architecture and Built Environment Faculty of Engineering University of Nottingham University Park Nottingham NG7 2RD UK

J. Harrison Technology Consultant E.ON Engineering Newstead Court Sherwood Park Annesley NG15 0DR UK


E-mail: jeremy.harrison@microchap. info

Chapter 6

Chapter 9

R. Mikalsen Sir Joseph Swan Institute for Energy Research Newcastle University Newcastle upon Tyne NE1 7RU UK

J. Larjola LUT Energy Lappeenranta University of Technology P.O. Box 20 FI-53851 Lappeenranta Finland

E-mail: [email protected] E-mail: [email protected]

Chapter 7 J. L. H. Backman* and J. Kaikko LUT Energy Lappeenranta University of Technology P.O. Box 20 FI-53851 Lappeenranta Finland E-mail: [email protected] [email protected]

Chapter 10 D. J. L. Brett* The Centre for CO2 Technology University College London London UK E-mail: [email protected]

N. P. Brandon Department of Earth Science and Engineering Imperial College London London UK



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A. D. Hawkes Grantham Institute for Climate Change Imperial College London South Kensington London SW7 2AZ UK

Chapter 14



I. Staffell Department of Chemical Engineering University of Birmingham Birmingham UK

Chapter 15

Chapter 11 K. Gluesenkamp* and R. Radermacher 4164 Martin Hall University of Maryland College Park, MD 20742 USA E-mail: [email protected] [email protected]

Chapter 12 A. Price Swanbarton Limited The Old Cake House Dairy Farm Pinkney Malmesbury Wiltshire SN16 0NX UK

xv

J. Clement Aars Fjernvarmeforsyning a.m.b.a. Dybvad Møllevej 1 DK-9600 Aars Denmark

R. Boukhanouf Department of Architecture and Built Environment Faculty of Engineering University of Nottingham Nottingham NG7 2RD UK E-mail: rabah.boukhanouf@nottingham. ac.uk

Chapter 16 Petar Sabev Varbanov* and Jirˇ í Jaromír Klemeš Centre for Process Integration and Intensification – CPI2 Research Institute of Chemical Technology and Process Engineering Faculty of Information Technology University of Pannonia Egyetem u. 10 8200 Veszprém Hungary E-mail: [email protected] [email protected]




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xvi


Chapter 17

Chapter 18

A. V. Bridgwater*, A. Alcala and M. E. Gyftopoulou Bioenergy Research Group Aston University Birmingham B4 7ET UK

K. Mahkamov School of Computing Engineering and Information Sciences Ellison Building Northumbria University Newcastle upan Tyne NE1 8ST UK

E-mail: [email protected] [email protected]

E-mail: khamid.mahkamov@ northumbria.ac.uk



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1 Generating power at high efficiency: Combined cycle technology for sustainable energy production Eric Jeffs 2 Advanced separation techniques for nuclear fuel reprocessing and radioactive waste treatment Edited by Kenneth L. Nash and Gregg J. Lumetta 3 Bioalcohol production: Biochemical conversion of lignocellulosic biomass Edited by K.W. Waldron 4 Understanding and mitigating ageing in nuclear power plants: Materials and operational aspects of plant life management (PLiM) Edited by Philip G. Tipping 5 Advanced power plant materials, design and technology Edited by Dermot Roddy 6 Stand-alone and hybrid wind energy systems: Technology, energy storage and applications Edited by J.K. Kaldellis 7 Biodiesel science and technology: From soil to oil Jan C.J. Bart, Natale Palmeri and Stefano Cavallaro 8 Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 1: Carbon dioxide (CO2) capture, transport and industrial applications Edited by M. Mercedes Maroto-Valer 9 Geological repository systems for safe disposal of spent nuclear fuels and radioactive waste Edited by Joonhong Ahn and Michael J. Apted



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10 Wind energy systems: Optimising design and construction for safe and reliable operation Edited by John D. Sørensen and Jens N. Sørensen 11 Solid oxide fuel cell technology: Principles, performance and operations Kevin Huang and John Bannister Goodenough 12 13

Handbook of advanced radioactive waste conditioning technologies Edited by Michael I. Ojovan Nuclear reactor safety systems Edited by Dan Gabriel Cacuci

14 Materials for energy efficiency and thermal comfort in buildings Edited by Matthew R. Hall 15 Handbook of biofuels production: Processes and technologies Edited by Rafael Luque, Juan Campelo and James Clark 16 Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 2: Carbon dioxide (CO2) storage and utilisation Edited by M. Mercedes Maroto-Valer 17 Oxy-fuel combustion for power generation and carbon dioxide (CO2) capture Edited by Ligang Zheng 18 Small and micro combined heat and power (CHP) systems: Advanced design, performance, materials and applications Edited by Robert Beith 19 Hydrocarbon fuel conversion technology: Advanced processes for clean fuel production Edited by M. Rashid Khan 20 Modern gas turbine systems: High efficiency, low emission, fuel flexible power generation Edited by Peter Jansohn 21 Concentrating solar power (CSP) technology: Developments and applications Edited by Keith Lovegrove and Wes Stein 22 Nuclear corrosion science and engineering Edited by Damien Féron 23 Power plant life management and performance improvement Edited by John Oakey



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xix

24 Direct-drive wind and marine energy systems Edited by Markus Mueller 25 Advanced membrane science and technology for sustainable energy and environmental applications Edited by Angelo Basile and Suzana Nunes 26 Irradiation embrittlement of reactor pressure vessels (RPVs) in nuclear power plants Edited by Naoki Soneda 27 High temperature superconductors (HTS) for energy applications Edited by Ziad Melhem 28 Infrastructure and methodologies for the justification of nuclear power programmes Edited by Agustín Alonso Santos 29 Waste to energy (WtE) conversion technology Edited by Marco Castaldi 30 Polymer electrolyte membrane and direct methanol fuel cell technology Volume 1: Fundamentals and performance Edited by Christoph Hartnig and Christina Roth 31 Polymer electrolyte membrane and direct methanol fuel cell technology Volume 2: In situ characterisation techniques Edited by Christoph Hartnig and Christina Roth 32 Combined cycle systems for near-zero emission power generation Edited by Ashok Rao 33 Modern earth buildings: Materials, engineering, construction and applications Edited by Matthew R. Hall, Rick Lindsay and Meror Krayenhoff 34 Handbook of metropolitan sustainability: Understanding and improving the urban environment Edited by Frank Zeman 35 Functional materials for energy applications Edited by John Kilner, Stephen Skinner, Stuart Irvine and Peter Edwards 36 Nuclear decommissioning: Planning, execution and experience Edited by Michele Laraia 37 Nuclear fuel cycle science and engineering Edited by Ian Crossland 38 Electricity transmission, distribution and storage systems Edited by Ziad Melhem



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39 Advances in biodiesel preparation: Second generation processes and technologies Edited by Rafael Luque and Juan Antonio Melero 40 Biomass combustion science, technology and engineering Edited by Lasse Rosendahl 41 Ultra-supercritical coal power plant: Materials, technologies and optimisation Edited by Dongke Zhang 42 Radionuclide behaviour in the natural environment: Science, impacts and lessons for the nuclear industry Edited by Horst Geckeis and Christophe Poinssot



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Preface

A preface has the function of introducing scope, intention and method of a literary or other work. The broad scope in this book is to review in depth the prospects and opportunity for applying small- and micro-chp systems as energy providers for domestic residences and smaller institutional, commercial and industrial buildings. But you might ask ‘surely we are already well provided for in this area of services?’ We have modern gas fired hot water boilers which can be up to 90% efficient and we have a readily available mains electricity supply which we can conveniently ‘tap’ as needed, even though conversion efficiency is low. However, we are in a time of change where ‘energy resources’ have suddenly become an important and challenging issue and the scenario needs a re-think. In the twentieth century we were provided with a stable national electricity system by the government-owned CEGB (Central Electricity Generating Board) for England and Wales and equivalents in Scotland and Northern Ireland. These systems had slowly grown from many small local generators mid century, to regional and then a national grid network. Supply was based mainly on large, typically 500 MW size per unit, coal fired electricity generators backed by ample cheap coal resources. In parallel we had moved from local ‘coal gas’ producers (with gasometers for gas storage) to a national supply pipeline fed from the extensive gas wells in the North Sea. Then both gas and electricity were privatised by the Thatcher Government in the cause of ‘competitiveness’ towards the end of the century and the ‘dash for gas’ for new cheaper generation changed the supply balance. Nearly every home is now linked to the electricity network and over 80% to the gas grid. The twenty-first century has brought concerns about long-term sustainability of fossil fuels as our initially vast North Sea reserves are depleting and by 2020 this source may provide as little as 10% of our needs, which means reliance on long cross border pipelines and shipped LNG (Liquefied natural gas). These routes also have cost rise implications. Secondly, the major issue of ‘climate change’ has resulted in national energy policies which seek a broad and ongoing reduction in fossil fuel usage. The IPCC (International Panel of



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Climate Change) who operate under UN auspices, have promoted reduction of carbon discharges to atmosphere for all nations who are partners, of which there are over 190 countries. In the UK the government has responded by planning to generate a total of 15% of our energy needs through renewable sources by 2020. This is a huge challenge! To build up adequate capacity of such renewable energy plant will take time, and so will the building of possible new nuclear plant. But fossil energy reduction and carbon discharge reductions can also come from measures such as ‘energy saving’ and ‘using energy more efficiently’. Of course, the obvious energy savers, such as insulating buildings, low energy electrical appliances and light bulbs, are already being implemented. But using energy more efficiently nearly always means more complicated systems and results in increased equipment cost which is not always readily accommodated. However, applying CHP (combined heat and power) plant is one key example of how to increase efficiency. What happens is that electricity is produced from a conventional turbine/engine but then the waste heat is also collected for use in a process or for space heating. Overall efficiency typically rises from, say, 33% to 60–90% at peak. The problem is to find a heat demand local to the plant and cost goes up with this added equipment. But what was more expensive and more complicated and unacceptable in the days of cheap and readily available fuel may now be justified. Extra plant cost and complexity can be offset by better fuel economics and availability. As a matter of interest 2008 statistics show that the UK had installed 5569 MWe of CHP capacity of all sizes (which apart from heat duty) actually provided 7% of UK electricity supply. While units below 1 MWe only provided 218 MWe of this total, this represented only 1192 plants. There is, therefore, a huge scope for growth in this size range. While many of the existing CHP plants in this country are of multi MW size and are mainly large process/industrial plant related, the opportunity for CHP is now also being further considered and applied in the small and micro size range which is the subject of this book. There is no strict size definition, but typically ‘micro’ size could be 2–10 kW and be aimed mainly at domestic type applications, whereas ‘small’ CHP plants cover a wider range of applications from say 50 kW up to a few MW and are directed at larger establishments such as multi-dwelling blocks, hotels, hospitals, educational and community centres, commercial buildings, etc., and may even be suitable for small industrial sites. It is an application area where previously it would have been easier to pipe in gas and electricity, but where now it is definitely of interest to consider small- or micro-CHP, which would increase overall efficiency of fuel usage, avoid the 4–7% grid line losses and provide a measure of self sufficiency. The technology can also be used with biomass type fuels saving conventional gas and heating oil.



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There are government plans towards eventually building up locally controlled supply systems, often called DES (distributed energy systems), which really means local industry and communities building up their own supply network, which can still be supplemented by the grid when needed. Small- and micro-CHP would fit well in this scenario with other local energy sources. It should be pointed out that small- and micro-chp is on the agenda in many parts of the world. At the ‘micro scale’ Japan and now Germany and the USA, in particular, have already marketed conventional engine technology, using neatly contained and ‘outside located’ packages for domestic use. There are many tens of thousands of installations. UK has focussed more on developing Stirling or heat pump technology for domestic ‘in house’ application, with imminent commercial breakthrough. The Netherlands, Austria and Denmark are also contenders. The latter country is particularly relevant in applications for district heating for communities. All these and many other countries are also using ‘small scale’ CHP for all sorts of industrial, commercial, community and residential applications with mostly conventional engine technology, but with growth of micro turbines in North America. Involvement on such an international scale will ensure steady growth of this technology area. So the case for considering small- and micro-CHP in new build and even sometimes for replacement situations has been established. But there is the need for careful review and assessment of each potential application in terms of the mix and, pattern and optimisation of electricity and heat demand with time of day and year. Existing large scale CHP often has a big heat load as the main process demand and small electricity output for sale; the ratio can be as high as 6 to 1. New fuel cell designs can, however, offer a 1 to 1 ratio. Each installation can be different and has to be assessed so that the right type of equipment is installed for the duty. The aim of this book is to provide, from a wide range of experts, the widest coverage and description that we can of the different CHP technologies available and their typical applications. In addition, the aim is to produce enough background information for a serious assessment of performance capability, so that equipment installers can identify the most likely route for their particular duty. We have also tried to clarify the ‘state of art’ of each technology area. Some processes are still in the final stages of development even though major energy suppliers have imminent plans for marketing. Others are already in the market and being applied. The method of presentation of the book is to group the chapters into three parts. Part I includes an initial overview, followed by chapters on technicoeconomic appraisal, performance analysis and computational modelling, performance integration and possible integration into DES, and use of biomass fuels in CHP systems.



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Part II goes into more detail on each of the various technologies and fuels. There are seven chapters covering such areas as internal combustion reciprocating engines, microturbine systems, Stirling cycle engine systems, Organic Rankine Cycle systems, fuel cell systems, heat-activated cooling technologies, and energy storage methods for small and micro scale systems. Then in Part III we turn attention to areas of application with chapters on micro-chp for residential and small commercial buildings, small CHP for community-based district heating applications, small CHP systems for commercial buildings and institutions, small systems for the food industry, biomass-based CHP systems, and thermal engine-based CHP systems for domestic applications. It is not necessarily a book to read from cover to cover, but rather the purpose is to provide a range of information, some or more of which will be directly relevant to each reader’s application, and which will then provide a positive starting point for deciding whether and how to go ahead with small- or micro-CHP. It also provides a broad background to the technology for those wishing to update their knowledge on this subject which is one of growing importance. Robert Beith Beith & Associates Ltd Felixstowe



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Epilogue R. B e i t h, Beith & Associates, UK

Some closing comments are necessary to try and summarise, from the book’s contents, how small- and micro-CHP systems are currently positioned in the energy scene and to anticipate how they could develop in the future. I think the first point to make is that it is clearly demonstrated from the 18 chapters that there are a wide range of applications and equally a wide choice of technologies to fulfil the services needed. Each technology has specific characteristics which best suit certain duty requirements. It may be helpful if I present an outline of the market and technology as I see it.

Review of micro combined heat and power (CHP) Looking first at the micro-chp scene and the Stirling cycle, this has been developed over many years aimed at the domestic market and particularly in the UK. Initial units have been trialled in houses and it is considered that most of the problems have been resolved, such as low noise and cleanliness for in-house installation, acceptable maintenance cycles, reliability, high overall efficiency (even up to 95%). Cost is now apparently coming down to acceptable levels, but perhaps the main challenge has been how to match the typical duty of say 1 kW electricity and 5–7 kW heat output against a widely varying house demand. It seems that this electrical duty matches house ‘base load’ quite well and peak load can be ‘mains topped’. But the heat duty on earlier units was marginal and it is now accepted sometimes to add a simple supplementary heater. Two main electricity suppliers are said to be planning marketing of Stirling cycle equipment in the near future. Some larger units may be applied in bigger establishments but the market here is said by one author to be mature but small, compared with the potentially very large domestic scene. Domestic scale reciprocating gas/oil-fired micro-CHP units are already commercialised and being sold, mainly in Japan (say 20 000 per annum) and in limited quantities in the United States and Germany. These are sized for 2–5 kW, but the units have to be located outside because of noise, exhaust, etc. Another technology being developed for domestic and other services is the fuel cell. One UK developer is moving towards commercialisation in terms of technical design but it is believed that the cost is still high and demonstration of product life (target say 40 000 hours) is still not fully 510 © Woodhead Publishing Limited, 2011

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established. The technology is attractive with the typical duty of 1:1 ratio of electricity to heat and with much higher electricity output than a typical domestic Stirling cycle unit. The package is more a ‘system’ than a ‘unit’. It will, of course, have many applications other than just domestic services. So, for the domestic scene the technological groundwork is being well laid, but there has not yet been big market impact. There could be significant advances and perhaps a breakthrough in the near future, but two issues are important for this: (i) all domestic equipment has to be in standardised and ‘easy to install’ form for builders to understand, and (ii) householders will need to realise that these new systems operate in a different fashion and to adjust to this. For example, existing gas boilers are oversized so that they can bring temperature up quickly and then be turned off, whereas new microchp systems produce the heat more steadily but at a lower rate.

Review of small combined heat and power (CHP) Looking next at the ‘small’-CHP range, we find a number of process and equipment routes are being exploited. Perhaps the most widely used equipment is the gas/oil reciprocating engine, typically in size ranges of the order 50–2000 kWe. They are applied in many establishments and organisations (e.g. in many universities, offices, hospitals, community centres, etc.) and reported also in many food preparation processes, such as in the dairy, meat and sugar industries. It is likely there will be other industrial applications not reported in this book. Application tends to be where energy requirement is ‘round the clock’ and the plant duty is sized as near normal full load as possible, particularly for electricity supply as this is the expensive ‘buy in’ commodity. Usually in residential installations only low temperature heat is required for radiator systems, but this is not the case for many industries. There are applications in supermarkets, also, where the excess heat is used to drive lithium bromide, absorption refrigeration systems for cold stores. This makes for good economics where the heat output is large in relation to electricity and is not all required for heating. Supermarket sizes can typically be 1200 kWe. There are also a number of steam cycle plants typically in the 100–1000 kWe range, which mainly use biomass fuelling. Some of the smaller ones may be biogas-fuelled reciprocating engine plants. There are a range of such fuels, but typically wood (pellets or other), agricultural wastes, energy crops, or such as straw wastes are used. These plants tend to be in rural locations near biofuel sources to save transport costs. For instance, smaller plants may be fired from gas produced at a farm site anaerobic digestor (AD) or from manure processing. The pattern here is use of local available cheap fuels for local energy supply and carbon reduction is obviously one of the factors. Another equipment combination, also mainly using biofuels, is the use of



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the ORC (organic Rankine cycle) to produce electricity, using low boiling point fluids to drive a turbine. Low level waste heat from another source can drive the process. It is not thought economic below, say, 10 kWe but it is reported that 130 plants have been installed over 16 countries typically in the 200 kWe range. Another contender is the gas turbine/generator. One characteristic of these is the low electricity-to-heat ratio (can be 1:5 with only about 20% electricity efficiency) and also the physical size. They can be a good choice and competitive for larger-scale industrial/process plant situations where a big and steady process heat requirement exists and where spare electricity can be sold off; and maintenance costs are low. But at much smaller scale this route is possibly more expensive than the duty can support. However, TGs are available, mainly from US suppliers, in sizes from 30 kWe to 1000 kWh. We should not forget district heating (DH) applications and, looking at Denmark’s experience, where they have maximised this energy route, it can be noted that 60% of their population are served by DH driven by CHP. Systems often start smaller and are extended, but typically units will be 1 MW upward. They are sized to suit the housing needs in an area. They are usually gas-fired engines or at bigger scale steam turbines, sometimes using wood chip furnaces. Water heat stores are used for balancing on the heat duty side but there is no problem with electricity load not matching local needs, as this goes to the grid.

Conclusion and outlook So it is clear there are a wide range of technologies, systems and applications for small-CHP and steady growth in a number of areas. There is still a need to custom design each application – few are identical – but the equipment components are generally readily available. On the fuel side, gas is still the main resource, but there is a growing move towards biomass fuels and a need to improve standardisation/specification of these fuels on a more national basis. The cost of these fuels is also a variable to be taken into account, but of course this is also the case for fossil fuels. Finally, it seems clear that small-scale CHP will grow steadily and probably faster as experience develops from existing plants and as application is encouraged by energy and carbon saving benefits. But it is still essential to assess and design each application carefully from heat and electricity duty requirements to ensure a viable system, and this may limit expansion rate. Also, as was indicated for the micro-chp market, there is a need for owners/ users to realise they may need to operate in a different way than they would with the old formula of plenty of cheap fuel! Certainly this energy technology has good Government support with targets



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for CHP plant availability (all sizes) to almost double by 2020; and with incentives in terms of feed-in tariff (FIT) payments at the domestic scale, together with benefits in potential carbon discharge reductions. I noted, for instance, in one chapter that typically there could be a 10–20% carbon saving with the Stirling ‘system’ compared with conventional domestic gas-fired equipment. So in my view the future scenario for small- and micro-CHP is definitely encouraging.



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Overview of small and micro combined heat and power (CHP) systems

J. k n o w l e s, Barbreck Services, UK

Abstract: Though considered a modern energy efficient technology, combined heat and power (CHP) has its genesis in the factories of the industrial revolution during the late nineteenth century. It lost its place in industry to central electricity generation and national grids, but through the latter part of the last century, with the development of reliable prime movers and the advent of microprocessor-based controls, resurgence has taken place. Now, at the start of the twenty-first century, a combination of ever increasing energy use and the growing realisation of the damage done to our environment is demanding ever more innovative and efficient technologies. CHP is adopting these new technologies and applying microturbines, Stirling engines and fuel cells alongside the latest developments in more conventional systems. Key words: cogeneration, CHP, combined heat and power, energy efficiency, history, power, electricity, generation.

1.1

Introduction to cogeneration – a short history

It is not difficult to identify the genesis of CHP, except that the term combined heat and power would never have been uttered as the nineteenth century drew to a close. The industrial revolution brought about the mechanisation of manufacture across the whole spectrum of industry. It was driven by energy derived principally from the combustion of coal to generate steam which was converted into mechanical power in a steam engine. In a late nineteenth-century factory, this power would be transmitted via a system of shafts and pulleys to a variety of machines. A relatively small inventive step by the Victorian engineers recognised that the waste heat from power generation could be used within the factory to provide heating in winter, and in some cases to facilitate manufacturing processes. At the start of the twentieth century, mechanical power was progressively replaced by electricity, still generated within the factory and utilising waste heat. This was the early form of CHP as we know it today. It wasn’t long before excess power from factory-based CHP was ‘exported’ to local dwellings and other businesses close to the factory.


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Tom Casten,1 a pioneer of modern cogeneration technologies in the USA, points out that in 1902 the average efficiency of power generation in the industrial USA was 66%. One hundred years later, the best engineers using the latest technologies have striven to reduce the efficiency of delivered electricity to 33%. Of course, the early industrial power generation quotes a CHP efficiency of 66%; power generation devices of the time could only achieve 10–12%, so the major benefit was in the utilisation of the heat. The improvements from this low level of generating efficiency were in the centralisation of generation in large coal and later nuclear plants with efficiency of power generation exceeding 40%, and it is the remoteness of these plants which introduces grid losses that reduce the overall efficiency of power at the point of use. The formation of national grids made all of this possible, but to the detriment of the overall energy efficiency achieved by factory-based power generation systems. Strangely, it was the advent of a national grid in England which gave rise to another innovative CHP solution. In 1926 the young Oscar Faber,2 a trained structural engineer, won the first contract for his newly formed engineering consultancy. These were times of great unrest with high unemployment and frequent riots in the streets of London. In the reconstruction of the Bank of England in Threadneedle Street, Oscar Faber was asked to install power generation deep inside the building as the Bank feared that the new national grid could be a target in industrial disputes and wished to remove its dependence on external and centralised generation. A state of the art diesel engine power plant was installed, but Oscar had to deal with the problem of removal of the waste heat of power generation. Instead of simply ventilating the power hall, he installed a heating system for the building to utilise this heat, and even incorporated a system of pipes within the dome of the Bank to dissipate some of the excess heat to atmosphere – one of the first documented uses of CHP in a commercial building. In industry, CHP retained a place throughout the twentieth Century where onsite generation made sense for process, economic or security reasons. It is interesting to note that in the Act of Parliament which established the United Kingdom’s CEGB (Central Electricity Generating Board), reference is made to the need for industrial use to be found for the waste heat from power generation, but this was largely forgotten in the drive for ever larger and more efficient power stations which were sited on the coalfields to reduce the transportation costs of the fuel. Some industries have a very long history, not just in CHP, but in the use of renewable fuel in CHP. From the 1950s major modernisation of the cane sugar industry across the world saw the 1

Tom Casten of Trigen Inc. in a speech to the WADE conference, Amsterdam 2002. From the biography of Oscar Faber by his son, John Faber. Faber, J. (1989) Oscar Faber. Quiller Press, Shrewsbury. 2


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5

efficient use of the cane waste (called bagasse) to generate steam, some of which was used in the refining process, but the main use was to drive steam turbines which in turn powered the mill. These were relatively low efficiency single stage turbines dedicated to each of the mechanical processes of sugar extraction and refining. Today, a second generation of modernisation using high efficiency multi-stage turbines allows the same amount of bagasse to power the mill electrically and export up to 70% of the electricity produced to the local grid. Other industrial sectors that have naturally utilised waste product or heat in CHP include oil refineries and steel works. In the 1970s and 1980s, the widespread availability of natural gas allowed many energy intense industries to return to CHP as a means of reducing their energy costs. Based mainly on modern industrial gas turbines, a new level of sophistication began to be introduced through integrated control systems incorporating the earliest programmable electronic devices. As the cost of these systems dropped over time, they became accessible and useable on smaller generators, specifically reciprocating gas engine driven units, and CHP then became available in an ever increasing range of sizes and applications. As with many modern technologies, small-scale CHP was made possible by the advent of microprocessors. Then in the 1990s other innovations began to emerge which further broadened the variety and scope of CHP. The micro gas turbine showed great promise through the use of modern materials, air bearings and operation of an effective recuperative cycle where heat energy is exchanged between the hot exhaust and the air leaving the compressor before combustion to increase significantly the cycle efficiency. As the twenty-first century approached, the scale of CHP reached down to the true micro level, becoming available to help heat and power our homes. Among the technologies employed in micro-CHP is the Stirling engine, invented by the Reverend Robert Stirling, a minister of the Church of Scotland, as long ago as 1816. Practical applications of the Stirling engine were slow to emerge, though Philips undertook the development of the engine in the 1940s, one variation of which was the reverse Stirling cycle, used to produce low temperature liquid gases in cryogenics. As a heat engine, the Stirling engine is an external combustion machine which makes it suitable for the combustion of any fuel type, as the working internal parts of the engine never see the products of combustion. It also works very effectively at the small scale size required for domestic micro-CHP where it has found its first mass-market application.

1.2

Types of technology and potential applications

We have already seen that every form of power generation technology, from steam engines and steam turbines, through the range of reciprocating and rotating internal combustion engines of all sizes, then down to the micro


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sized gas turbines and external combustion engines, can be moulded into some form of combined heat and power. It might be thought that the only logical reason for the combustion of a fuel, fossil or renewable, should be the generation of power, and that the ‘waste’ heat element of this power generation should always be utilised. But to achieve such energy utopia, the technology has to be matched to applications. Table 1.1 lists the overall categories of CHP; all types below 2 MW fall in the range of ‘small or micro-chp’. The simple definition of CHP is a system where the waste heat of power generation provides beneficial use. It therefore follows that a primary need for the siting of any CHP system is where there is a demand for the heat output. Heat from a CHP system can be provided in any number of useful forms from high pressure steam to low pressure hot water; as hot gas or heated air; and through the use of absorption or adsorption refrigeration processes as chilled water or sub-zero brine for low temperature refrigeration applications. A further factor in application matching is the heat-to-power ratio of the site or process to be served by the CHP. In many cases it is advantageous to match as closely as possible these needs in the CHP system output; however, where a very large heat demand exists, it is common to export power from the system to the grid to ensure a thermal match. Less common is the export of heat due to transmission difficulties, though all district heating or cooling schemes do exactly that. The heat-to-power ratio can also determine which CHP technology is most appropriate. For example, an application requiring large amounts of steam will almost certainly be best served by a gas turbine where almost all of the heat energy is found in the high temperature exhaust which is ideal for steam generation. In a building which needs to be air conditioned, a trigeneration system based on a gas engine and lithium bromide absorption chiller is most likely to provide the best system match. Table 1.1 CHP base technologies CHP power Power range generation (applied to CHP) technology

Power efficiency range (%)

CHP efficiency (peak) (%)

CCGT* Gas turbine Steam turbine Reciprocating engine Micro-turbine** Fuel cell Stirling engine

30–55 20–45 15–40 25–40 25–30 30–40 10–25

85 80 75 95 75 75 80

20 MW to 600 MW 2 MW to 500 MW 500 kW to 100 MW 5 kW to 10 MW 30 kW to 250 kW 5 kW to 1 MW 1 kW to 50 kW

* Combined cycle gas and steam turbines ** Micro-turbines are small, radial flow gas turbines


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The key factors that determine the best CHP solution are therefore the type of thermal energy to be produced, and the heat-to-power ratio of the application. One other factor will influence the decision on technology, and that is the scale of the system which we will consider in the following paragraphs.

1.2.1 Large-scale CHP It is useful to outline the status of large-scale CHP so that the status of small- and micro-CHP can be put into perspective. Large-scale CHP covers the widest range of thermal and power output, and currently accounts for up to 90% of the installed capacity worldwide. Most large CHP installations are on industrial sites and include some very large installations in the range 300 MW to over 1 GW at large oil refineries. As the definition of large-scale CHP embraces anything over 2 MW, both the number and variety of applications are significant. The simplest form of large-scale CHP is found where the exhaust gas from an industrial gas turbine can be applied directly to heat a process, for example in the drying of bulk chemicals. The process must be tolerant of the products of combustion, which, from a modern gas turbine operating on natural gas, are exceptionally low in harmful emissions. More common in large industrial processes is the need for steam as a flexible and easily transported heat medium. The natural provider of large quantities of steam from waste heat is again the industrial gas turbine which in some applications can be operated in combined cycle with a steam turbine, the latter often receiving steam from the process or passing out to the process. A diminishing number of large-scale CHP systems have a steam turbine as the source of power. Exceptions to this are systems where heat can be recovered into steam from a high temperature process, or more commonly now when renewable fuels are burnt in the steam raising plant. Reciprocating engines also have a place in large-scale CHP, in particular where the heat-to-power match is relatively low. District heating systems will normally employ engines for that reason, to benefit not only from the low heat-to-power ratio, but also from the much higher efficiency of the engine which can extend operating periods against a seasonal heat demand. When making comparisons between gas turbine and gas engine CHP solutions, there are additional factors that may benefit the latter technology. The gas turbine performance is affected directly by the ambient air temperature at the compressor inlet, and significant derating of the turbine takes place as temperatures rise. Both power and efficiency are affected by any temperature change, whereas for most gas engines, a constant power and efficiency can be obtained at temperatures up to 30–35 °C. By actively cooling the intake air to the gas turbine, performance can be restored, generally at the cost of


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some thermal or electrical energy. The other drawback of the gas turbine is its relatively poor efficiency against part-load, whereas the gas engine will lose only a few percentage points between full load and 50%. So the best application for the gas turbine is a constant load with high heat-to-power ratio. A seldom deployed but highly effective solution for large-scale systems is to use a combination of a gas turbine with a number of gas engines. The turbine can be selected to provide the bulk of the heat demand whilst running at full load to provide a base level of power generation. The gas engines provide flexibility to cater for both electrical and heat demand fluctuations, and serve to increase the electrical generating efficiency of the combined system. Many large-scale systems are installed where there is a very significant heat demand, greatly in excess of the electrical demand of the site or process. The efficient production of electrical power in these CHP installations makes it viable to export excess power to the grid thereby raising the overall efficiency of the network.

1.2.2 Small-scale CHP Possibly the widest range of technologies and applications for CHP fall into the category of small-scale. The term small-scale can in itself, however, be confusing, but for the purpose of this section we will assume an individual CHP unit size of typically greater than 100 kW and less than 2 MW power output, and systems that are generally smaller than 10 MW where multiple power generators are installed. The prime mover technologies introduced for large-scale systems all find their place at the smaller scale, though there is a predominance of reciprocating gas engines in this area where their relatively low cost and superior generating efficiency come to the fore. Indeed, the wide range of outputs available from modern engines employing essentially the same technology extends all the way down into the micro-CHP sector. At the higher end of the small-scale range, generating efficiencies in excess of 40% have been achieved, and even at smaller sizes the power efficiency closely matches that of delivered centrally generated power. So in energy efficiency terms the heat recovered is a genuine bonus, and here again the reciprocating engine has excelled in CHP applications, achieving total energy efficiencies of up to 95% when used to heat air. A further reason for the relative dominance of the reciprocating engine is the close thermal match it can achieve for applications in the commercial and public building sector, both as CHP and in trigeneration systems. Turbines should not, however, be ignored, and there are now gas turbines available with good generating efficiency at around 2 MW power output. At the other end of the spectrum are a number of micro-turbine developments


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of up to 250 kW which achieve respectable efficiency levels through the use of the recuperated cycle where waste heat from the exhaust is recycled to the compressed air before combustion. Steam turbines also have their place, again mainly in heat recovery applications, but at low power, cycle efficiency remains low. There are even reciprocating and radial type steam engines appearing in the market which, though exhibiting typically low electrical generating efficiencies, can find niche applications in small thermal plants burning renewable or waste fuels. Developed decades ago for the US space program, fuel cells are now beginning to find land-based power generation application. There are many types of fuel cell either in the market or under development, and it is a technology that will still take many years to reach maturity and commercial viability. The principle of the fuel cell is simple, and indeed the antithesis of the process of electrolysis which uses electrical potential to split water into oxygen and hydrogen. In the fuel cell, these elements recombine across a membrane to form water, and in doing so release electrons which provide the power output of the cell. As neither pure oxygen nor hydrogen is cheaply available, current fuel cells operate on air and natural gas or similar hydrocarbon fuel from which the hydrogen is extracted in thermochemical processes. These processes account for the inefficiency of the fuel cell which is largely recoverable as heat which makes the fuel cell a useful CHP technology.

1.2.3 Trigeneration Many CHP systems serve seasonal demands such as the heating of buildings, and therefore only provide beneficial use during the colder months of the year. CHP in buildings has grown mainly in the densely populated areas of the northern hemisphere. However, the growing trend to air condition buildings allows other technologies to be added to CHP which utilise its thermal output to provide the cooling required in air conditioning. The principles of absorption refrigeration were first discovered back in 1777, and the first commercial machine was built in 1850 using the Aqueous Ammonia cycle. It was not until the 1920s that the lithium bromide cycle used in current water chillers became practical, and by fits and starts, the technology has developed into a flexible range of products to maximise the potential for CHP-based solutions. In the process, water is the refrigerant, and lithium bromide in solution is the absorbent. The driving principle of absorption refrigeration is that at a high vacuum, water will evaporate at a very low temperature. The application of heat to a weak solution of lithium bromide in water will drive off water vapour and produce a strong solution. Allowing the water vapour to pass into a vessel at even lower pressure, it is there condensed as it cools the chilled water, and recombines with the


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strong solution of lithium bromide, creating once again a weak solution. A simple low energy pump boosts the lithium bromide solution back to the higher pressure in the evaporator part of the system. Chilled water is used extensively in air conditioning systems in buildings, and in some industrial applications for process cooling. Absorption chillers therefore find increasing use in CHP systems, which are commonly referred to as trigeneration – where power, heat and cooling are provided from the same system. The measure of performance of a chiller system is the Coefficient of Performance (CoP) and is the ratio of the cooling produced by the process divided by the energy (heat in the case of an absorption system) input to the process. The simplest form of chiller used in CHP converts hot water into chilled water at a CoP of approximately 0.7. This is a single effect chiller, referring to the heat input being used only once to evaporate water from the lithium bromide solution. Where a higher grade of heat is available, as is the case from a steam generating CHP system, a double effect absorption chiller can be employed. In this device, the heat can be cascaded to provide secondary evaporation, boosting the CoP to around 1.3. Of course, the efficiency of the steam generation process limits the total amount of heat available, but on balance the system can provide more cooling from a more compact absorption chiller. A relatively recent innovation has seen a new form of lithium bromide absorption chiller in trigeneration systems. This has been termed the multi-energy chiller, and when matched to a gas engine CHP system it uses hot water from the jacket system in a single effect process and the exhaust gas separately in double effect to achieve a CoP of up to 1.05. The design of this chiller will also permit supplementary heat input to increase further the cooling output. A limitation of the lithium bromide process is the temperature to which the refrigerant (H2O) can cool the chilled water, which is generally limited to a minimum of 5 °C. Where a lower temperature is required by an industrial process, then the original Aqueous Ammonia process needs to be employed. In this process, ammonia is the refrigerant and water is the absorbent. Early, non-CHP applications of this process included the freezing of food and manufacture of ice cream. To achieve very low temperatures, only high grade heat from the CHP system can be used, and the lower the temperature to be achieved, the lower the CoP of the chilling system will be. For example, to achieve frozen food storage temperatures, the system would operate at a CoP of 0.2 or lower.

1.2.4 Micro-CHP At the smallest end of the CHP spectrum, there are technologies that can be applied to small buildings and individual homes. These are micro-CHP


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systems, not to be confused with the micro-turbines discussed earlier, though very small gas turbines could be employed in micro-CHP. More common technologies entering this part of the market are small reciprocating engines, Stirling engines and fuel cells. Reciprocating engines of similar output to a small family car can be used to provide CHP to small buildings in the private and public sectors, and have been developed to operate not only on natural gas, but both gas and liquid biofuels. Smaller engines with outputs below 5 kW might be applied to large homes, though very few houses will have a constant demand for this level of power generation. Small systems can also be applied to apartment blocks providing a miniature form of district heating, though where more than 15 homes are connected the technology is more appropriately small and not micro scale. In the more common domestic environment of the average family home, the Stirling engine has found its niche. Being an external combustion engine, there is a greatly reduced level of wear of the moving parts, so potential for very high reliability. It also operates extremely quietly as the combustion system resembles that of the familiar domestic boiler. Several of the pioneering manufacturers in this field have adopted the Sterling engine to produce a direct replacement device for the domestic boiler in both floor and wall mounted variants. Small fuel cells have also been developed for use in this sector of the market, and though the technology is still expensive to install, in time viability and performance will improve making this clean, efficient and virtually silent technology more widely applicable. All micro-scale technologies suffer to an extent from lower power generation efficiencies making it crucial to ensure a good match to the thermal demand of the application when considering micro-CHP. To encourage uptake and further development of micro-CHP, it is common to find financial incentives from governments or utility companies and, in turn, wider uptake will allow manufacturers to invest to reduce the cost of their product.

1.3

Energy efficiency improvement

The environmental benefit that CHP in all its forms brings is based solely on the energy efficiency improvement that is produced from generating power at a location where the heat energy which would otherwise be wasted can be used beneficially. There is a valid argument to be made that in every instance where a fuel is consumed, be it of fossil or renewable origin, we should seek to firstly produce power (electricity) from the high temperature combustion of the fuel, and secondly recover as much of the lower grade heat for the benefit of the location in which the fuel is consumed. This would require us to move all thermal power generation into our towns and cities



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where not only is the power consumed, but a benefit can be obtained from the waste heat in processes, comfort heating and cooling. Most nations have concentrated their power generation in large and remote locations so the implications of reversing this legacy policy are immense. However, while we need to burn fuels for power and heat, CHP will remain the most logical, economical and environmental way to do so. In thermal power generation systems, the driver for larger power plant was the need to strive for higher power generating efficiency. And it was the correct strategy when there were no concerns about fuel supply and little understanding of the damaging effect of CO2 on our environment. The highest efficiency achieved by a super-critical steam generating power plant is around 40%, and by the largest current gas turbine something less than 50%. When transmission losses and part-load operation are taken into account, more than 60% of the thermal energy of the fuels used to generate power is wasted. Similar generating efficiencies are available from the best CHP prime mover technologies, so from a purely energy use point of view, CHP will increasingly become the first choice when new thermal power plant is required. The range of heat uses from CHP is unlimited as has been described earlier, and only thermal processes which require intense heat such as metal refining and certain chemical processes cannot benefit directly. As has also been seen, the overall efficiency of a CHP system depends on the grade of heat required by the process to be served. High pressure steam systems will have the lowest overall efficiency whereas systems required to heat ambient air can recover heat from all waste sources including radiant heat from hot surfaces to achieve extremely high efficiency. When we consider the value of high efficiency achieved by CHP, it is the cost of the energy displaced by the CHP system which must be considered. The offset cost of imported electricity is generally the most valuable component, followed by the value of any electricity exported. The recovered heat on the other hand has a relatively low value equivalent only to the cost of producing the same amount of heat in a modern boiler or direct fired heater system. It is generally considered that the output of the absorption chiller in a trigeneration system offsets imported electricity used to power vapour compression chillers.

1.4

Cost benefits and emissions reduction

As we have seen, the electricity produced by the CHP system has the highest value, and in most cases will confer the highest element of cost benefit. Heat value, however, often offers the benefit which drives the investment decision which emphasises the importance of maximising the use of heat output from CHP. Not to be forgotten in the calculation of the cost benefits



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of CHP, however, is the relatively high cost to maintain the operation and performance of the CHP equipment. When compared to the cost of providing the same energy from alternative sources, these elements provide a simple evaluation of the viability of CHP. However, there are other considerations in the decision-making process. In the case of a new installation, the high initial cost of the CHP system may be partially offset by cost savings elsewhere, for example in heating and cooling equipment, or the cost of a grid connection. Where the CHP system performs a secondary role, such as providing standby power, the cost of a standby generator may be saved. In certain installations, the CO2 output from the CHP system can have a value providing it can be captured and utilised. A good example is in horticulture where cleaned exhaust gas is used to introduce additional CO 2 into greenhouses, aiding plant development. A less direct benefit from CO2 is becoming available through trading mechanisms designed to stimulate reductions in emissions. Initially only large energy users and larger CHP installations could economically benefit from these schemes, but ultimately, all CO2 saved by CHP may find a value. For smaller systems, this may come through taxation benefits, feed-in tariffs, or by valuing the recovered heat energy. Where they are applied, such measures can significantly impact the evaluation of the benefits of a CHP installation. Though generally considered a clean technology, the potential for CHP to produce significant levels of other pollutant emissions is not being ignored. Driven by ever tightening standards set in the USA and Europe, prime mover manufacturers have progressively reduced levels of NOx, CO and, where relevant, SOx and particulates either by improved combustion technologies or the addition of post combustion treatment of the emitted gases. The penalty is, however, a more complex and costly CHP installation with potentially higher operating costs.

1.5

Grid connection

One of the most important aspects of CHP installation design is to provide an economic but safe connection to the electricity grid. Almost all CHP systems operate connected to the grid and rules have been developed by almost all grid operators which ensure the safety of both the CHP installation and its connection. There are a number of key considerations in designing the connection.

1.5.1 Protection The connection rules are written to ensure that under a fault condition, the grid is fully protected whether the fault is with the CHP installation or on the grid itself. Various parameters are constantly measured at the



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point of connection of the CHP installation to determine whether a fault is developing. Frequency and voltage in any electrical network can vary over time; however, a significant change may indicate a developing fault, and if not reversed, then action will be taken to disconnect the CHP system from the grid if the limits of variation set by the connection code are exceeded. More certain indications of failure of an electrical system can be detected. A significant vector shift may be measured and used to determine an imminent fault requiring disconnection, and for larger systems the rate of change of frequency (RoCoF) is frequently employed. Though CHP systems can fail and require to be disconnected to protect the grid, more common on smaller scale systems are events on the grid which alter the measured parameters sufficiently to instigate operation of the protection devices. When deciding where to install the protection equipment, the possibility of operating the CHP system in island mode should be considered, so that the CHP can provide power to the site or part of the site during a prolonged grid outage. By carefully designing the connection together with a means of managing the CHP load, it is possible to achieve a seamless transfer from grid to island operation and back.

1.5.2 Synchronisation CHP systems can employ either synchronous or asynchronous generators. The latter are generally applied to smaller systems, and as they need to be connected to the grid to operate, they require no synchronisation equipment. All other systems need to be synchronised in order to connect to the grid. For rotating synchronous generators, the requirement is to closely match the key parameters of the generator to those of the grid before making the connection. Voltage needs to be closely set, but any small variation at the instant of connection is eliminated as the grid voltage dictates the connected level. Frequency needs to be very closely matched and, most importantly, phase angle needs to be within a few degrees before connection is made. The synchronisation system operates the governor on the prime mover to bring these parameters within connection tolerance, and modern electronic synchronisers operate fully automatically to achieve this.

1.5.3 System Fault Level Analysis Any changes to the system connected to the grid will have an effect on the fault level at the point of connection to the grid and beyond. In most countries the grid has been developed principally to operate in one direction, and has progressively become loaded to a point where any change can have major impacts. Distributed or embedded generation can be beneficial in reinforcing a weak grid, but such reinforcement can introduce local problems which



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require action to ensure the continued safe operation of the system. Though it is generally the larger CHP installations that will have the biggest impact, even modest installations on particular sections of a grid can cause problems, an example being the addition of a CHP system to a city centre grid which already has significant CHP or renewable generation capacity connected. It is important, therefore, to know the impact that the installation of a CHP system will have at the point of connection, and to commission a study of the effect on the grid of the changes. Most network operators require such studies to be carried out before licensing onsite generation, and they often provide a service to conduct the necessary analysis. Once the design of the connection is approved and the system installed, it is again normal for the network operator to require a test of the system and its protection to be witnessed by their engineers before generation in parallel can be permitted.

1.5.4 Inverters Connection of small CHP systems to the grid can also be made through an inverter, and most fuel cells and micro-turbines already connect by this method. The fuel cell generates d.c. power, and requires the inverter to convert this to a.c. In the case of the micro-turbine, its high rotational speed required the use of high frequency generators, and the inverted is utilised to convert this to grid frequency. More recently, inverter connection of specifically designed generators has been developed as a potentially simpler method of connecting smaller conventional CHP systems. Similar protection and connection issues need to be addressed for inverter systems.

1.5.5 Harmonics There is a limit to the harmonic distortion that can be tolerated at the point of connection, and again the network operator has set standards which must be complied with. Most CHP systems are unlikely to cause harmonic problems, but in rare cases, the connected system may be at or near the limit, and due account of the effect of adding a CHP system will need to be taken. The advent of inverter connections will potentially increase the incidence where harmonic studies are required.

1.6

Barriers to combined heat and power (CHP)

In almost all markets where CHP has been introduced, there have been legislative barriers to overcome, though it must be admitted that with good connection codes in place and more enlightened authorities, these have largely been removed. A particular difficulty in the past was to be allowed



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to connect CHP to the grid, and though much of the resistance of network operators has been removed, there is often a very cautious approach applied which might deter some developments. Where such caution is suspected, it is important to properly interrogate the network operator’s findings and to jointly seek an economic solution to any problem encountered. Most CHP developments are on a relatively small scale, and therefore have minimal local environmental impact, particularly where natural gas is the fuel. However, as more renewable fuels are consumed, there may be issues of storage, emissions and waste handling to be addressed to satisfy planning requirements. There is a trend towards the use of such fuels in larger district heating CHP systems which may also find resistance at community level. Perhaps the greatest barrier to CHP remains that of potential users and developers who may have concerns over the technology and the complications it may bring, or who have financial expectations that CHP cannot fulfil. We continue to see volatility in energy markets, and though the recent trend has been towards sustainably higher energy costs, there can still be sufficient price movement over a short period to deter investment. Any CHP development has to be considered on the basis of its lifecycle cost, but some commercial and industrial users have much shorter horizons and require short payback cycles.

1.7

Future trends

Predicting the future is always dangerous, but in the growing knowledge and acceptance of the negative effects of our carbon society and its likely demise, CHP will surely feature in any energy future where thermal as well as electrical demands exist. The fuels of the future will be hard won, therefore their efficient use will demand that CHP has a continuing role. It has often been said that CHP is a bridge technology to a renewable future, but it should be recognised more as a foundation on which the future can be built. For the immediate future, there are a number of exciting options including CHP networks where a number of CHP installations can be interlinked to satisfy the total thermal demand of a large site or collection of applications. In this concept, each application generates power to satisfy the immediately local thermal demand, and the excess electricity is consumed by the applications which have a power demand which does not match their thermal needs. There are also opportunities to integrate renewable technologies with CHP. For example, solar thermal has been used to supplement heat input to packaged trigeneration systems, boosting cooling output when it is most needed. The largest future opportunities are the tens of thousands of small to medium existing buildings and businesses that could benefit from CHP, and the millions of households where fully developed and deployed microCHP can help change the future.



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Techno-economic assessment of small and micro combined heat and power (CHP) systems A. D. H a w k e s, Imperial College London, UK

Abstract: This chapter introduces the economics of small-scale CHP systems. Beginning with a review of how decentralised energy resources can achieve economic value, it then discusses the sometimes ill-defined concept of techno-economics, and the variety of modelling techniques that underpin it. An optimisation method that pinpoints the key characteristics of commercially successful CHP is presented and applied to the case of microCHP in the UK, demonstrating that the heat-to-power ratio prime mover is the key driver of economic and environmental performance. Finally, the emerging tension between CHP and heat pumps is discussed in relation to future stringent emissions reduction targets. Key words: CHP, cogeneration, economics, techno-economics, optimisation, policy, CO2.

2.1

Introduction

Small-scale combined heat and power (CHP) is a class of technologies that have the potential to simultaneously tackle a number of energy policy aims surrounding the economics, environmental impacts and security of energy supply. Perhaps foremost among its credentials is the perceived ability to reduce greenhouse gas emissions arising from energy consumption at low private and social cost. As such, and given broader national and international efforts to mitigate climate change, CHP has benefitted from recent industry and political attention. In this process it has become apparent that tools to further assist development and introduction of systems could aid decision making and push this technology more into the mainstream. This chapter presents a techno-economic modelling framework designed to assist investors, CHP technology developers and policy makers in achieving conception to commissioning of ‘successful’ CHP products and installations. The modelling and supporting analysis is used to weigh up the ability of the technologies to meet commercial and policy aims, and to gauge the suitability and effectiveness of policy instruments in encouraging uptake where that uptake will aid in meeting policy objectives. CHP is a distinctive technology. Along with energy efficiency measures, 17 © Woodhead Publishing Limited, 2011


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it is one of the very few ‘interventions’ to address all three primary aims of energy policy convincingly. Both energy efficiency measures and CHP can be economically rational investments in that they can pay back within their lifetimes, and can reduce greenhouse gas and pollutant emissions, and improve energy security by reducing demand and diversifying and decentralising supply. But despite these benefits, the extent to which CHP can be deemed as ‘successful’ depends greatly on site-specific characteristics and the nature of the technology applied, not to mention an assortment of ‘external’ uncontrollable factors such as relative electricity and fuel prices, the speed and nature of change in the broader energy system, and the business models by which CHP systems are introduced. This chapter does not intend to tackle all of these issues in detail, but rather focuses on a specific facet of the economics of CHP. In order to achieve this, it is split into four main parts: a discussion of the general economic opportunities and challenges faced by decentralised energy resources, discussion of the concept of ‘techno-economic’ analyses, description of a technique to scope and assess CHP technologies, and a case study of an important subset of small-scale systems – micro-CHP for residential applications. It is hoped that this will give readers insight into the fundamentals of decentralisation, with specific focus on a method for development and assessment of CHP systems.

2.2

The economics of combined heat and power (CHP)

In any discussion of the economics of CHP, the topic of the relative price of electricity and fuel cannot be overlooked. This quantity is expressed via a metric known as the ‘spark spread’, which is a measure of the gross income a generator can expect to receive when they sell one unit of electricity after purchasing the fuel necessary to produce that electricity. For the case of CHP, the spark spread concept needs to be altered slightly to cater for the fact that CHP also produces heat, which has economic value. If we assume that the value of heat from the CHP is identical to the cost of producing heat in a boiler, it is possible to derive the following relationship between CHP spark spread, price and efficiencies: Êh ˆÊ ˆ spark ark spread ar pr CHP = EP – GP + Á o – 1˜ Á GP˜ he Ë he ¯ Ë hb ¯

2.1

where EP is the electricity price, GP is the gas price, and he, ho and hb are the CHP electrical efficiency, CHP overall (i.e. heat plus power) efficiency, and competing boiler efficiency, respectively. In the case where ho ≈ hb, this reduces to equation 2.2:



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Techno-economic assessment of small and micro CHP systems

Ê ˆ spark ark spread ar pr CHP = EP – Á GP˜ Ë ho ¯

19

2.2

and in the case of an extremely well-engineered system, where ho ≈ 1, the relationship further reduces to: spark Gap = EP – GP

2.3

Both Equations 2.2 and 2.3 are independent of the electrical efficiency of the generator, which is substantially different from the case of electricity-only generators for which the standard spark spread metric (where no value is afforded to heat) is usually calculated. Furthermore, the quantity in equation 2.3 is sometimes referred to as the ‘spark gap’, and is a relatively common measure of the competitiveness of CHP at any given point in time. Of course, CHP spark spread or spark gap does not include all the necessary information about the economics of CHP, and other sources and limitations of value can come from, for example, emissions trading permits, levies or levy exemptions for CHP, operational expenses, connection, distribution, the ability to utilise thermal energy, etc. Nonetheless, spark gap is a useful metric for a first approximation, and as stated above no discussion of CHP economics would be complete without it. Before moving on, it is worth briefing touching on the risk faced by investors in CHP as a result of fluctuation in the CHP spark spread. As one would expect, it varies from year to year, as displayed in Fig. 2.1. This figure

Electricity price (7/kWh) gas price (7/kWh)

Price/value (7/kWh)

CHP Spark spread (7/kWeh) 0.1

0.05

0 1998

2000

2002

2004 Year

2006

2008

2.1 Historical electricity and gas price of the UK from European Commission (2010), plotted against calculated CHP spark spread.



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shows fairly wide variation in the CHP spark spread, primarily as a result of electricity price drops after full energy market liberalisation in 2001. The situation has since improved, but the historical volatility certainly does not lend itself to this increased investment. In essence, exposure to the CHP spark spread does represent a risk, which is a noteworthy barrier for CHP uptake. In addition to the customary spark spread economics, there are a range of less tangible factors that bear upon the economics of CHP, both at each individual site and further upstream. These stem from the fact that CHP is a class of technologies that are a subset of the broader ‘decentralised’ or ‘distributed’ generation (DG) concept. Such systems are often attributed a variety of advantageous characteristics relating to their economics. Whilst 207 separate benefits can be identified according to Lovins et al. (2002), they typically fall into one of the following categories: 1. The ability to utilise waste heat. Specific to the case of CHP and integral in the preceding discussion of CHP spark spread, co-location of supply and demand allows thermal energy that would otherwise be wasted to be utilised onsite or nearby for some productive purpose. 2. Modularity and speed of installation. Unlike large centralised generators, distributed generators are modular and have short lead times for installation. Therefore, all other aspects being equal, there is less financial risk involved in investing in a large number of decentralised generators than one of their centralised counterparts. 3. Reduced requirement for upstream infrastructure. Installing generation assets near the point of demand implies that less centralised generation and transmissions and distribution (T&D) infrastructure will be required upstream, thus reducing total final cost. 4. Reduction in electricity T&D losses. Similarly to (3), siting electricity generation at or near the point of demand means that some T&D losses (which currently account for approximately 7% of all electricity generated in the UK) will be avoided because some electricity does not need to be transmitted. 5. Backup power or uninterruptable power supply (UPS). The ability to install generation onsite offers the possibility to provide backup power that improves the reliability of the total power supply (i.e. supplementing standard power system reliability). DG also offers flexibility in meeting reliability needs, where specific customers can be afforded appropriate levels of reliability depending on the value of the load being served. 6. Diversification of primary energy sources. A wide range of primary fuels are available for DG systems (e.g. wind, biomass, solar, wasteto-energy). Such diversification has evident energy security benefits, along with further ‘portfolio’ benefits of hedging risk via the ability to



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switch from one primary energy source to another when operating an aggregation of DG resources. 7. Access to ‘stranded’ or ‘distributed’ primary energy sources. The small scale and relative portability of generators means they can be located where the fuel is. For example, wind power needs to be located in windy places, and some bio or waste-to-energy sources may benefit from avoiding transportation of the fuel. The precise value of all of these benefits is challenging to estimate, as it depends on many factors relating to both the technology and site. Some studies have attempted to quantify them, but wide error bars are usually conceded, and results can rarely be generalised. In spite of the potential benefits, market rules and regulations can hinder the ability of smaller generators to access the value they create, via preventing market access on equitable terms or complicating permitting, installation and commissioning processes. In some senses such barriers may be reasonable as some DG technologies will not create value in one or more of the listed categories, and it is arguable that each installation needs to be judged on its own merits. This leads to one of the most important challenges with regard to DG: the uncertainty of performance or suitability of a particular technology in a specific setting creates the wish to assess each installation. This leads to imposition of measures such as permitting and licensing, impeding uptake and sometimes creating regulatory risk for the installer. As such, even installations that are likely to be acceptable and perform well are subject to procedures that discourage managers from investing time in even the first stages of scoping DG projects. Clearly the array of opportunities and challenges facing CHP are substantial, and not all can be addressed here. Instead we focus on one specific aspect: the techno-economics of CHP, beginning with an exploration of definitions and the scope of applicable techniques, followed by presentation of a modelling methodology and a case study of residential micro-CHP.

2.3

Techno-economics for onsite generation

Conventional power system models are rarely appropriate for analysing onsite generation. This is because they do not adequately capture the dynamics of site energy demand, and rarely consider the economics of ‘behind-the-meter’ generation or the range of site-specific constraints a typical installation faces. To address their shortcomings, models designed to analyse the economic and environmental performance of onsite generation technologies such as CHP are becoming more common. Whilst the aims, assumptions and structures of these models vary greatly, most can be classified as ‘techno-economic’, based on either simulation or optimisation approaches.



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Before delving into the details of a specific modelling approach, it is useful to explore the term ‘techno-economics’, which is only loosely defined and yet widely applied. In its most general form, it refers to studies that cross the disciplinary boundary between the physical sciences and economics. Many techno-economic studies are typified by a technical characterisation of an engineering system and the environment in which it operates, accompanied by modelling of its technical performance given particular state/s of input parameters (e.g., factors relevant to the performance and lifetime of the system). The results of such analyses are designed to be quantities that can be attributed economic value (e.g., annual electricity and fuel consumptions, maintenance requirements, etc). The economic part of the analysis takes these values and calculates standard metrics such as net present value, equivalent annual cost, payback periods, or risk-related metrics for the investment. Whilst this all-purpose description is very straightforward, the methods by which techno-economic modelling is performed vary greatly from study to study, and each approach presents specific strengths and weaknesses. A primary distinction between modelling methodologies lies in comparison of simulation and optimisation. Simulation models performance over time using a set of (potentially temporally interdependent) physical relationships. Conversely, optimisation models performance (potentially over time) where some variables are not fixed and can be adapted in order to maximise or minimise some defined objective, subject to constraints. Either modelling approach can be very simplistic or extremely sophisticated. Optimisation approaches can be further disaggregated into those regarding system design, and those regarding system operation. Equally, simulation approaches exist in a variety of forms and consider many different boundaries for analysis. The primary advantage of simulation is that it can be more easily used to explore transients in the technology itself and in the environment in which it operates, because highly non-linear interactions and even first-principles relationships can be readily incorporated into models. Whilst techno-economic optimisation rarely attempts to capture such detail explicitly, it has the advantage that technical and/or operational parameters do not need to be fixed. This means that it is possible to explore the characteristics of the technology, its control and/or its operational environment that lead to the ‘best’ outcome, as defined by the objective function of the optimisation. For this chapter, a unit commitment optimisation model based on steadystate efficiency characterisation has been chosen to assess the performance of CHP. For the interested reader, a definition and review of various unit commitment methodologies can be found in Padhy (2004). Dynamic/transient performance of the CHP is emulated via a set of operational constraints, adding elements of system and building response into the formulation. This optimisation approach is intended to provide useful information regarding the



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best system design and control, and can be used to explore the performance potential of emerging technologies. The superior thermal demand/response modelling of credible simulation models is drawn upon to create fixed thermal demand profiles for use in the case study presented later.

2.4

A specific modelling methodology

As discussed above, in order to investigate CHP economics, optimisation is applied. The inputs and outputs of this process are described in Fig. 2.2. The ‘processing’ element in Fig. 2.2 forms the core computational effort of the modelling, and is a mixed integer linear programming method implemented using Visual C++.NET and CPLEX 10. The model has been named CODEGen, which stands for ‘Cost Optimisation of Decentralised Energy Generation’. The mathematical formulation of the optimisation problem is not presented here, and the reader is referred to Hawkes et al. (2009a) for a complete description. Instead, a narrative of the basis of choice of the optimisation objective function and a conceptual outline of the mathematics are provided in the sub-sections below.

2.4.1 Choice of the central performance metric This section explores the choice of the objective (i.e., the primary performance metric to minimise or maximise) of the optimisation through consideration Inputs Technical inputs

Processing

Country-specific inputs

Techno-economic characterisation Capital cost Installation cost Maintenance cost Start/stop cost Minimum set point Min up/down time

Outputs

Performance assessment Economic conditions electricity/gas cost discount rates Energy demand (Heat and power) 5 minute – 1 hour precision

Maximum installed cost Codegen model Mixed integer linear programming

Optimum operating strategy Annual energy cost Energy consumed Greenhouse gas emissions

Ramp limits Capacity

Sensitivity analyses

2.2 The CODEGen model: inputs, outputs and flow diagram for optimisation modelling framework.



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of the modelling aims. The modelling framework must of course be tuned to these aims, which are: ∑

to understand the potential of CHP technology, and use it to assess the key market drivers, and assess the ability to meet policy aims; ∑ to investigate key technical parameters to understand their influence on economic and environmental credentials, with the aim of improving the knowledge of system developers; ∑ to use the modelling results to critique current, proposed and potential new policy and regulation surrounding the introduction of CHP. In one sense the aims all speak to the primary considerations of energy policy: economics, environment, and energy security and the ability of CHP to contribute to beneficial outcomes in these three areas. However, in order for the technologies to be commercially successful, consumers must adopt them in large numbers, so deployment pathways become relevant. Deployment models for microgeneration are considered to gain an understanding of what metrics may drive adoption/diffusion and demarcate successful CHP products. This leads to choice of a primary performance metric for the optimisation modelling (i.e. an objective function), and further assessment metrics. CHP commercial exploitation pathways The driving force in a CHP investment decision depends greatly on which stakeholder is making that investment. It order to gain understanding of appropriate metrics for modelling of the systems, it is useful to consider which actors are associated with each potential route to market. Watson (2004) developed a set of deployment models for microgeneration in general, and applied it in Sauter and Watson (2007) to investigate social acceptance of microgeneration. The deployment pathways they developed are: ∑

Plug-and-play. Where the decision to invest in microgeneration is taken autonomously by the building owner or occupier who independently finances it. ∑ Company control. Where more passive consumers provide a site for the system which is owned and/or operated by an energy service company (ESCO) or energy supplier. ∑ Community microgrid. Where a group of individuals and/or businesses group together to provide some of their collective energy needs, and own and may operate the units. As discussed in Hawkes et al. (2009a), the company control pathway is possibly the most effective for mass market introduction of efficiency and other measures in the built environment because it largely takes the investment decision out of the hands of the dwelling occupier, and therefore allows that



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decision to be more explicitly economically driven than in the plug-and-play pathway.1 This is also true in comparison with the community microgrids pathway, but in this case decisions may also be driven by the community’s particular needs and the potential for bolstering of the local economy in ways such as increased employment. Community microgrids are also less likely to constitute a mass market, although they may be a stepping-stone that proves concepts and raises the profile of successful approaches, leading to further uptake. Between the three pathways, only ESCO (or energy suppliers acting as ESCOs; the company control pathway) actors can almost always be assumed to be economically rational, making investment decisions based on classic parameters such as net present value. Therefore the success of the company control deployment pathway in allowing CHP to reach a mass market can be closely linked to the economic advantage the systems offer. Likewise with the plug-and-play pathway and community microgrids, other factors relating to diffusion of innovations as discussed in Rogers (2003) will also play a role, but economics is likely to remain central to decision making. Central performance metric It is clear that economics forms the central concern in terms of achieving a mass market for CHP under all three deployment pathways. It is not the sole issue, but where other factors such as social prestige of ‘greenness’ are addressed, economic profitability will be critical to achieving a large market share. For CHP, attitudes and expectations regarding performance are inextricably linked to those of incumbent heating and electricity systems. Therefore, the investment decision for CHP should be considered in comparison with that of the competing reference grid/boiler systems, and it is the capital cost difference between the two options (that provide an essentially comparable service) that the potential adopter faces. Therefore, the primary metric chosen to address these issues is the net present value of the CHP system with respect to the competing reference system. This metric is calculated as the discounted value of the annual profits the ECSO could obtain from installing CHP in the customer’s dwelling and operating it over its lifetime. The ESCO makes profit by charging the customer the same amount that they would have been charged if they had used the incumbent grid/boiler reference system. Therefore this metric is cost-neutral for the dwelling 1

It should be noted that provision of quality information is of great importance in the plug-and-play model. This is because household owners/occupiers frequently do not have the time or knowledge to assess the economics of a particular CHP installation. Provision of such advice by independent experts could go a long way to achieving appropriate uptake of micro-CHP under a plug-and-play model.



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occupier in that it assumes gains afforded through reduced operational costs are offset by the leasing cost (i.e., the annualised capital cost) of the CHP equipment. The net present value of the ESCO’s profits can act as a guide for maximum installed capital costs the ESCO would pay for the CHP system. The reader should also note that the metric could equally be interpreted as the maximum capital cost a dwelling occupier or community would pay for outright purchase of the CHP system in the plug-and-play or community microgrid models, if they were to accept the chosen cost of capital. The chosen central performance metric caters directly to the company control pathway, and also has relevance to the other deployment pathways. Importantly, it is formulated to avoid the issue of incorporating uncertain capital costs into economic calculations, indicating the maximum allowable capital cost rather than guessing at a specific capital cost. Carbon dioxide (CO2) performance metrics In addition to the economic metric, further gauges are required to understand the capability of CHP to aid in achieving the goals of energy policy. At present, foremost among these goals is reduction of greenhouse gas emissions. For greenhouse gas emissions reduction, the adopted metric is straightforward: the annual CO2 savings provided by the CHP system when compared to that of the competing reference system. This measure considers only the operational greenhouse gas emissions. Lifecycle emissions due to manufacturing, fuel chain, disposal/recycling are not included and for these aspects readers are referred to Pehnt (2008). The CO2 metric is calculated based on the results of the optimisation. Therefore it relates to a situation where the economic performance of the system has been optimised, leading to the CO2 related result. This implies that the primary driver for CHP adoption is assumed to be economic, and the influence of CHP on CO 2 is consequential.

2.4.2 Description of the optimisation problem The complete mathematical formulation for the optimisation problem will not be presented here, and the reader is referred to published descriptions of the method in Hawkes et al. (2009a). Instead, a brief description of the objective function, decision variables, and constraints of the optimisation are provided to clarify the conceptual framework. The objective function of the optimisation is the annual cost of meeting a given energy demand profile, which is minimised. The energy demand profiles consist of heat and electricity demand, and are represented by a set of ‘sample days’ that are deemed to adequately characterise the complete annual demand. Depending on the CHP application, the demands are represented as



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5-minute, half hourly, or hourly demand over each sample day, with more peaky demand profiles (such as residential demand) requiring finer temporal resolutions to properly capture demand dynamics following Hawkes and Leach (2005). The decision variables are: ∑

the output of the CHP prime mover in each time period (kWhe, kWhth), split piecewise by level of prime mover output to allow characterisation of non-linear efficiency profiles, ∑ the output of the supplementary thermal system in each time period (kWth), ∑ import of grid electricity in each time period (kWhe), ∑ charge to and discharge from electricity storage in each time period (kWhe), ∑ charge to and discharge from thermal energy storage in each time period (kWhe), ∑ yes/no variable to determine whether to switch on/off in each period. Optimisation constraints are: ∑ ∑ ∑ ∑ ∑ ∑

electricity demand must be met in each time period, thermal energy demand must be met in each time period, or exceeded by a small margin, the capacity of each system must not be exceeded, and charge/discharge rates for storage must not be exceeded, the minimum operating point of each system must be respected, maximum ramp rates of each system must be respected, constraints to impose start/stop costs.

The primary economic metric can be calculated from the value of the optimised objective function. This is achieved by calculating the cost of meeting the same energy demand with a defined reference system (e.g. a condensing boiler and grid electricity) and subtracting the value of the optimised objective function. The result is the annual saving provided by the system and, where a certain lifetime is assumed, the net present value of that annual saving can be calculated. This net present value is the primary economic metric as discussed above; it is the amount a rational investor would pay for the micro-CHP system over-and-above what they would pay for the competing reference system. Once this mathematical formulation is implemented, it may be used to explore a variety of technical, economic and policy-related aspects of CHP. In the following sections the case of micro-CHP for residential applications in the UK is considered, from the point of view of an investor/policy maker, and then a technology developer, each of which have differing interests. The CO2-related performance is also considered, culminating in a synthesis of



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the key characteristics of micro-CHP installations that are more likely to be commercially successful.

2.5

Case study: micro combined heat and power (CHP)

This case study applies the technique discussed above to examine an interesting emerging class of CHP technologies: that of micro-CHP for residential applications. These are essentially ‘home heating solutions’ designed to replace existing systems such as boilers or furnaces, and can provide both space heating and hot water, in addition to some electricity. The potential market for such systems is large, with ten-of-millions of boiler replacements occurring each year in Europe alone according to Micro-Map (2002). There are several examples of their development, demonstration, and commercialisation in, for example, Tokyo Gas Co. (2005) and Anon. (2007, 2008). The main prime mover technologies for micro-CHP are polymer electrolyte fuel cells (PEMFC), solid oxide fuel cells (SOFC), internal combustion engines (ICE), and Stirling engines. Each of these core technologies have individual limitations and performance characteristics, and they are at very different stages of development. This case study focuses on two key near-to-medium term technologies for Europe: ICEs and SOFCs. Specific results are based on the energy demand characteristics, energy prices and CO2 emissions rates of the UK in 2009, but the technique could be applied to any country and any time period. A summary of the input parameters for the case study is as follows. At the time of writing the average annual dwelling electricity demand in the UK was 4.3 MWh, and average annual total thermal demand was approximately 18 MWh, although wide variation around these values is observable. Energy prices were approximately 10p/kWh (U$0.15/kWh) for electricity and 2.5p/ kWh (U$0.0375/kWh) for gas. Grid-embodied CO2 rates were approximately 0.52 kgCO2/kWh, and gas was assumed to embody 0.19 kgCO2/kWh (net calorific value). Finally, details of the technical limitations and performance characteristics of the micro-CHP systems investigated can be found in Hawkes et al. (2009b). The primary distinction between prime movers in terms of techno-economics is their heat-to-power ratio (HPR), as discussed below. SOFCs have the lowest HPR of about 1 kWthh to 1 kWeh (1:1), whilst PEMFCs, ICEs and Stirling engines exhibit HPRs of approximately 2:1, 3:1, and 8:1, respectively. Finally, the lifetime of each system is assumed to be 10 years (equivalent to the average service life of the existing boiler stock), and the service interval is assumed to be the same as for a boiler (once per year, at an additional cost of £25 relative to a boiler service). The following analysis takes these inputs and applies them in the modelling methodology in two distinct ways: firstly, to inform investors regarding the



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key drivers and potential of each prime mover technology, and secondly, to inform system developers regarding which technical aspects upon which to focus research and development.

2.5.1 Techno-economic assessment for investors and policy makers It has been widely reported that there is a relationship between the thermal demand met by CHP units and their economic viability, with high and consistent thermal demand often associated with positive results. Whilst it is not expected that micro-CHP is an exception to this rule, it is informative to investigate the extent to which annual demand influences value, given the distinctive nature of residential tariffs and demand. It is also informative to investigate the influence of annual electricity demand. Figure 2.3 displays the variation in economic results for two key microCHP technologies with respect to the dwelling’s annual thermal demand (for this figure annual electricity demand has been held constant at the UK ICE Flat Bungalow Terrace Semi-detached Detached Linear fit (all)

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2.3 Sensitivity of economic performance of two micro-CHP systems (ICE – internal combustion engine, and SOFC – solid oxide fuel cell) to annual thermal demand in the target dwelling. Each subplot contains data for five typical UK construction types, and a linear fit to all data points.



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mean value of 4.3 MWh/year). Therefore the only source of variation in each plot is the annual thermal demand profile applied. Thermal demand scenarios correspond to each of the five dwelling construction types reported on in the UK census, with each construction type denoted by three markers corresponding to ‘existing’, ‘refurbished’ and ‘new’ insulation standards (i.e., decreasing thermal demand). Inspection of the figure reveals that the dependence of the economic result on annual thermal demand is evident in all cases, but is more obvious in the case of the micro-CHP prime mover with higher heat-to-power ratio (i.e., the internal combustion engine). The ICE is more exposed to lack of thermal demand, demonstrated by the relatively steep slope of the linear fit in the left subplot. The fuel cell-based system shows a more consistently positive economic result which does not change significantly as annual thermal demand decreases (with corresponding shallower slope on the linear fit). The key inference here is that SOFC-based systems are more economically resilient to changes in annual thermal demand than ICE-based systems. Figure 2.4 displays the sensitivity of the economic result to the dwelling’s annual electricity demand (plotted across three cases of annual thermal demand; SOFC

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2.4 Sensitivity of economic performance of two micro-CHP systems (ICE – internal combustion engine, and SOFC – solid oxide fuel cell) to annual electricity demand in the target dwelling. Each subplot contains data for five typical UK construction types, and a linear fit to all data points.



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an existing flat – ≈13 MWh/year (low); average existing terrace – ≈18 MWh/ year (average); and an existing detached house – ≈28.5 MWh/year (high)). These thermal demands include both space heating and domestic hot water demand. It is apparent from this figure that the fuel cell-based system shows strong dependence of economic result on annual electricity demand; much stronger than its sensitivity with respect to annual thermal demand observed in Fig. 2.3. Conversely, the engine-based system shows approximately the same sensitivity to annual thermal demand as it does to annual electricity demand. It can be deduced that electricity demand and thermal demand are both important for a positive economic result for the engine-based system, but onsite electricity demand is the primary driving factor for the fuel cellbased system. Overall the results in Figs 2.3 and 2.4 can be synthesised to arrive at a key conclusion for micro-CHP: those prime movers that produce heat are more likely to be more influenced by the level of annual thermal demand. Lack of thermal demand, or significant heat production for a given electricity output (i.e., a high heat-to-power ratio of the micro-CHP prime mover), corresponds to a constraint on system operation. Essentially these ‘thermal constraints’ limit the ability of a system to benefit economically from displacing onsite electricity demand. Conversely, the economic performance of systems that produce less heat (i.e., low heat-to-power ratio) is driven more by annual electricity demand. This relates to the fact that thermal constraints do not interfere so much with their operation, and they can therefore access the value associated with generating electricity to displace onsite demand which would otherwise have been met by more expensive grid electricity. Lack of onsite electricity demand obviously limits the ability of the system to displace it and gain access to this value. In summary, primary value for micro-CHP lies in generating to displace onsite electricity demand; access to this value is enabled by the presence of such demand, and the presence of thermal demand and/or application of a prime mover with a low heat-to-power ratio to avoid thermal constraints on operation.

2.5.2 Techno-economic assessment for technology developers Choice of prime mover nameplate capacity is an important concern for micro-CHP systems developers in terms of where their product fits into the market, and those concerned with assessing the economic credentials of micro-CHP. Therefore the sensitivity of economic performance to capacity choice is investigated here. This is important because examination of a single capacity system may miss valuable opportunities for micro-CHP developers to scale up or scale down their products. Figure 2.5 displays the difference in value between the micro-CHP system and the reference grid-boiler system



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(i.e., the central performance metric) for ICE and SOFC-based micro-CHP, with sensitivity of results to annual energy demands of three constructiontype variants. Figure 2.5 shows the notable variation in value between the two microCHP technologies with respect to competing conventional boiler systems. For a 1 kWe SOFC-based system operating in a mean demand situation (i.e., the terraced house in the right subplot) an investor with 12% cost of capital would pay approximately £800 (US$12002) more than what they would pay for the competing boiler. Conversely, a rational investor would only pay approximately an extra £400 (US$600) for the modelled ICE system.3 Moreover, Fig. 2.5 demonstrates that the current economic situation presents a challenge for any micro-CHP developer. This is because the manufacturing ICE

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2.5 Sensitivity of micro-CHP system value to prime mover capacity. Plotted for two prime mover types (ICE – internal combustion engine, and SOFC – solid oxide fuel cell) and for three dwelling construction types in the UK. 2

The exchange rate at the time of writing was applied here, where £1GBP ≈ US$1.50. Whilst one cannot draw conclusions regarding comparison between the economic attractiveness of the two technologies based on this result (because manufacturing and installation costs for systems incorporating each prime mover type are not yet readily observable), it is clear that fuel cell system developers have more breathing space. 3



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cost of including the micro-CHP prime mover and balance of plant (in addition to the boiler) in the system is likely to be considerable, and a challenge for system developers to attain with an allowable margin of less than £1000 (US$1500) including any potential profit. As such, early markets are likely to focus on houses with larger demands which have access to higher value, up to £1300 (US$1950) per installation, and on installations driven by noneconomic aspects such as environmental benefits. Also with regard to Fig. 2.5, it is instructive to note how the value per kWe installed changes with increasing prime mover capacity. Almost all the plotted lines have the largest positive slope between 0 kWe and 1 kWe prime mover capacity. As prime mover capacity increases thereafter, value per additional kWe installed decreases. Therefore there is probably no justification in providing a product to the UK residential market with prime mover capacity greater than approximately 1 kWe. This result does vary between technologies; the value per kWe installed for fuel cell-based systems is clearly not as sensitive to increasing capacity as the engine-based systems. At the far end of the scale, a comparatively large SOFC-based system has a value of roughly £2400 (US$3600) more than the competing boiler, and this could be a reasonable manufacturing proposition if economies of scale entail cheaper production (per kWe) of larger systems. Regardless of such possibilities, micro-CHP systems with 1 kWe capacity present the best per kWe installed value, and are probably the best proposition for a mass market which is dominated by single-residence dwellings in a mild climate. Aside from choice of capacity, many other high-level technical characteristics are of interest to micro-CHP system developers. For example, Fig. 2.6 displays the sensitivity of the economic result to a range of maximum allowable ramp rates. Ramp rates are important particularly for fuel cell-based systems, which may face durability issues under regular thermal cycling, and the developer faces a choice regarding whether or not to invest time in improving ramping performance. This question can be answered in that the figure clearly shows that variation in the maximum allowable ramp rate of the micro-CHP system does not have a significant influence on economic credentials. Only at very low maximum ramp rates below 20 Watts per minute is any influence discernable, and even then it is minor, corresponding to less than 5% of the value of the fuel cell-based micro-CHP systems. From a technology developer’s point of view, this means that they should not invest in creating systems that are able to ramp up and down quickly in response to changing conditions. Rather, they should focus on development of somewhat predictive control systems that can forecast when operation will be required and/or profitable. In a single residential dwelling this is relatively easily achieved, where the user programs a desired temperature profile, thus giving the system much advance warning of expected modes of operation.



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900 800 700 ICE 600

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2.6 Sensitivity of economic result to the maximum ramp rate for four micro-CHP technologies (ICE – internal combustion engine, PEMFC – polymer electrolyte membrane fuel cell, SOFC – solid oxide fuel cell, and Stirling engine). Results plotted for 1 kWe system operating in an average terraced house.

For the final example of the use of techno-economics to provide information to developers, Fig. 2.7 presents the sensitivity of the case for investment to minimum operating point (i.e., a proxy for turndown ratio) for four micro-CHP systems. Once again a clear differentiation is apparent between the prime mover technologies. The low heat-to-power ratio fuel cell-based systems are much more resilient to limited turndown characteristics than the higher heat-to-power ratio engine-based systems. For example, the Stirling engine-based system is unable to provide a positive case for investment if it cannot turn down below 0.4 kWe, whilst the fuel cell-based systems retain value even when they cannot turn down at all. The result in Fig. 2.7 presents a challenge for micro-CHP prime mover developers, because achieving efficient turndown in small systems is problematic, where the conventional wisdom is that balance of plant (BoP) energy consumptions become dominant and system efficiency drops off rapidly. The majority of 1 kWe engine-based units in field trials and commercially available (in Japan) are not able to turn down at all. They offer on/off operation only. Whilst this engineering decision could have been taken for a variety of technical reasons, the results of the analysis presented suggest turndown should be considered as a valuable system characteristic, even if that turndown involved operation at a few selected set-points. Should BoP



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2.7 Sensitivity of economic result to the minimum operating point for four micro-CHP technologies (ICE – internal combustion engine, PEMFC – polymer electrolyte membrane fuel cell, SOFC – solid oxide fuel cell, and Stirling engine). Results plotted for 1 kWe system operating in an average terraced house.

components be improved to the point where turndown to near-zero output whilst maintaining efficiency is possible, particularly for fuel cell-based systems, substantial additional value would become available to the owner/ operator, arguably increasing the value of the unit to the developer. This and the previous sub-sections have presented examples of how technoeconomic optimisation modelling might be used to assess the economic performance CHP. The following two sub-sections build on this analysis from a different perspective; that of the stakeholder who considers environmental performance to be important. A policy maker may be one example of such a stakeholder.

2.5.3 CO2 emissions reduction performance Figure 2.8 shows the sensitivity of annual CO2 emissions reductions to system nameplate capacity for the two key micro-CHP systems. There is clear differentiation between these prime mover technologies, with the fuel cell-based system offering a definitive performance advantage. Similarly to the results relating to the relative economics of micro-CHP systems presented in the previous sections, these CO2-related results can be attributed to the different heat-to-power ratios between the technologies. Those technologies



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with a low heat-to-power ratio prime mover are less constrained by lack of thermal demand and are subsequently able to generate more electricity and thereby gain CO2 credit for offsetting more grid electricity. A further point of interest from Fig. 2.8 is that the SOFC-based microCHP is able to virtually eliminate the entire operational CO2 footprint of the dwelling when a 4 kWe system is installed. Whilst such large nameplate capacity systems may be prohibitively expensive in the near term, the result still presents an interesting possibility for delivering housing in the line with the UK’s current low carbon policy. For example, the 4 kWe system could single-handedly achieve the UK government’s 2050 80% emissions reduction target for that dwelling. However, extension of this concept to a large number of dwellings is problematic because the result is underpinned by a high CO2 rate for grid electricity, which would not be the case if fuel cell micro-CHP produced a large portion of this grid electricity. It is also instructive to consider the sensitivity of the CO2 result to annual thermal demand (holding electricity demand constant), and annual ICE

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2.8 Sensitivity of CO2 reductions to prime mover capacity. CO2 reduction is with respect to the reference grid/boiler system, and plotted points are for two prime mover types (ICE – internal combustion engine, and SOFC – solid oxide fuel cell) and three dwelling construction types in the UK.



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electricity demand (holding thermal demand constant), once again mirroring the economic analysis. Figures 2.9 and 2.10 present these sensitivities for 1 kWe systems, operating in each of the five dwelling construction types and across ‘existing’, ‘refurbished’, and ‘new’ building thermal performance standards. Figure 2.9 shows that annual thermal demand can be important in microCHP achieving CO2 reductions. This is particularly apparent for the higher heat-to-power ratio (HPR) ICE-based systems. In contrast, the SOFC-based system provides reductions largely independent of annual thermal demand. These two cases relate once again to HPR; the ICE engine (higher HPR) is unable to provide reductions for low annual thermal demands because its operation is frequently curtailed by thermal constraints, whilst the SOFC-based prime mover (low HPR) can operate almost all the time because it rarely encounters these constraints regardless of the thermal demand scenario. Figure 2.10 shows the CO2 reduction achievable by 1 kWe micro-CHP systems across a range of annual electricity demand scenarios. This figure ICE

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2.9 Sensitivity of CO2 performance of two micro-CHP systems (ICE – internal combustion engine, and SOFC – solid oxide fuel cell) to annual thermal demand in the target dwelling. Each subplot contains data for five typical UK construction types, each with three insulation levels, and a linear fit to all data points.



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Small and micro combined heat and power (CHP) systems ICE

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2.10 Sensitivity of CO2 performance of two micro-CHP systems (ICE – internal combustion engine, and SOFC – solid oxide fuel cell) to annual thermal demand in the target dwelling. Each subplot contains data for five typical UK construction types, each with three insulation levels, and a linear fit to all data points.

demonstrates that there is little reliance of CO2 reduction on annual electricity demand for any specific construction type. This can be contrasted with the equivalent economic result presented in Fig. 2.4, which showed great dependence of economic result on annual electricity demand, particularly for low HPR prime movers. The reason for this contrasting CO2 result is that displaced grid electricity CO2 rates are the same regardless of whether generation is consumed onsite or exported to the grid (conversely, in the economic case, export attracts a lower value than onsite generation under central estimate values).

2.5.4 Key characteristics of commercially successful micro CHP The conclusion to be drawn from the case study of residential micro-CHP can be summarised as follows. The economic value of these systems (with respect to competing boiler systems) is driven by the combination of the ability to produce electricity and presence of onsite electricity demand to



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be met. It is limited by excessive thermal production and/or lack of thermal demand in the target dwelling. For appropriately sized prime movers, heatto-power ratio is the key technical metric that speaks to these issues because it captures the propensity of a prime mover to deliver electricity despite low thermal demands. At times of low thermal demand a micro-CHP prime mover with a low heat-to-power ratio will be able to continue operating (and displacing expensive electricity import) where a higher heat-to-power ratio technology will be required to modulate or switch off. The driving forces of CO2 reduction for micro-CHP are identical to those of economic value, with the exception that the annual electricity demand of the target dwelling is not important. This is because the CO2 credit obtained for displacing imported electricity is identical to that for exported electricity. Conversely, for the economic case, the value of displacing onsite electricity demand is substantially higher than the value of electricity exported to the grid. On the whole, technologies with low heat-to-power ratios, low thermal capacity, contributing to serving dwellings with larger annual electricity and thermal demands are best placed to access economic value. For CO2 reductions, technologies with low heat-to-power ratio, low thermal capacity, serving dwellings with larger annual thermal demand are best placed to provide savings. Therefore appropriately sized fuel cell-based micro-CHP technologies, which have the lowest heat-to-power ratios of the investigated systems, benefit from all of these attributes and provide the best performance. The SOFC-based systems as characterised here provide the largest allowable installed cost difference (with respect to competing boiler systems) and the greatest potential CO2 emissions reduction. Higher heat-to-power ratio ICEbased systems still exhibit competitive performance credentials, but are more challenged to provide savings when thermal demands are low. The primary caveat to these statements is that the final mass-manufactured installed costs of each technology are not yet observable. For example, the relative advantages of SOFCs may be less relevant if the final commercial products are much more expensive than internal combustion engines, which is arguably likely to be the case. Investigation of potential final installed cost of systems is beyond the scope of this chapter, but the analysis above has been designed to be applicable regardless of this.

2.6

Future trends

On the whole, small-scale CHP is a relatively established technology, with a variety of systems already commercially available, and with a growing market share. But the range of technologies captured by the term CHP is vast, spanning from the well-established internal combustion engine through to the most sophisticated bio-energy or fuel cell-based systems. As such, there are



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always emerging technologies under the CHP banner, and much potential for scale-up or scale-down of established systems. Over the past decade perhaps the most interesting development has been that of micro-CHP, which has not yet entered the market in force except in Japan, where internal combustion engines dominate. New technologies, particularly fuel cells as discussed in this chapter, could form an important part of this market in future. Indeed, several developers are planning market launch of relevant products within the next few years. Of course, history tells us that many of these systems may not turn out to be viable or may require more development. Looking further into the future, the international low carbon aspirations may force attention to be directed more towards technologies that can meet long-term greenhouse gas emissions reduction targets. CHP fuelled by fossil fuel-based gases will always be challenged in this regard, because even perfectly efficient utilisation of relatively clean natural gas results in production of approximately 0.19 kgCO2/kWh, so there is little room for achieving reductions of the magnitude required. Therefore alternative fuels and technologies must be considered in the future. At the time of writing, much attention is focused on two potential routes to deeper carbon reductions. These are the mass market introduction of heat pumps, and the decarbonisation of piped natural gas for use in CHP or boilers/furnaces. Given inherent limitations in decarbonising piped gas by injection of waste-to-energy and biomass sources, it seems likely that the key competitor to CHP in the coming decades will be heat pumps (for space and water heating applications). Nevertheless, heat pumps face their own set of unique challenges, primarily surrounding installation and technology cost and upstream infrastructure impacts, and as yet there is no considered solution to these issues. Research is required into classes and combinations of demand-side technologies that can meet low carbon targets, and it is fitting that CHP remains a consideration in this regard due to its potential for fuel flexibility, relatively low cost, and arguably complementary upstream infrastructure impacts. Ultimately CHP is likely to form part of a diversified solution to meeting energy needs, where its informed use in combination with alternative technologies such as heat pumps could serve to meet stringent carbon aspirations whilst simultaneously minimising infrastructure investment requirements in coming decades.

2.7

Sources of further information and advice

Interested readers may find the following bodies of work of interest: ∑

IEA ECBCS Annex 42 on Residential Cogeneration, investigating the performance of several micro-CHP systems using experimental data and building simulation approaches: available at http://cogen-sim.net/.



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∑ ∑

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IEA ECBCS Annex 54 on the Assessment of Microgeneration Technologies, a new Annex investigating integration of microgeneration technologies. The CHPA-funded report questioning ‘all-electric’ heating approaches versus combined heat and power in Speirs et al. (2010).

2.8

References

Anon. (2007). ‘Ceres Power funding to develop manufacturing’. Fuel Cells Bulletin 2007(7): 8. Anon. (2008). ‘CFCL invests in German facility, wins Nuon order’. Fuel Cells Bulletin 2008(4): 9–10. European Commission. (2010). ‘Eurostat Database: Energy Prices’. Retrieved 24 March 2010, from http://epp.eurostat.ec.europa.eu/portal/page/portal/energy/introduction. Hawkes, A. D. and M. A. Leach (2005). ‘Impacts of temporal precision in optimisation modelling of micro-combined heat and power’. Energy 30(10): 1759–1779. Hawkes, A. D., D. J. L. Brett and N. P. Brandon (2009a). ‘Fuel cell micro-CHP technoeconomics: Part 1 – model concept and formulation’. International Journal of Hydrogen Energy 34(23): 9545–9557. Hawkes, A. D., I. Staffell, D J. L. Brett and N. P. Brandon (2009b). ‘Fuel cells for micro-combined heat and power generation’. Energy & Environmental Science (Royal Society of Chemistry) 2(7): 729–744. Lovins, A., E. K. Datta, T. Feiler, K. R. Rábago, J. N. Swisher, A. Lehmann and K. Wicker (2002). Small Is Profitable: The Hidden Economic Benefits of Making Electrical Resources the Right Size. Snowmass, CO: Rocky Mountain Institute. Micro-Map (2002). Mini and Micro CHP – Market Assessment and Development Plan: Summary Report. London: FaberMaunsell Ltd. Padhy, N. P. (2004). ‘Unit commitment – a bibliographical survey’. IEEE Transactions on Power Systems 19(2): 1196–1205. Pehnt, M. (2008). ‘Environmental impacts of distributed energy systems – the case of micro cogeneration’. Environmental Science & Policy 11(1): 25–37. Rogers, E. M. (2003). Diffusion of Innovations. New York: Free Press. Sauter, R. and J. Watson (2007). ‘Strategies for the deployment of micro-generation: implications for social acceptance’. Energy Policy 35(5): 2770–2779. Speirs, J., R. Gross, S. Deshmukh, P. Heptonstall, L. Munuera, M. Leach and J. Torriti (2010). Building a roadmap for heat: 2050 scenarios and heat delivery in the UK, A Report by Imperial College London and University of Surrey for the Combined Heat and Power Association, London. Tokyo Gas Co. (2005). Sales of the residential gas engine cogeneration system ‘ECOWILL’ and establishment of the optional agreement ‘Residential cogeneration system contract’. Tokyo, Japan. Watson, J. (2004). ‘Co-provision in sustainable energy systems: the case of microgeneration’. Energy Policy 32(17): 1981–1990.



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3

Thermodynamics, performance analysis and computational modelling of small and micro combined heat and power (CHP) systems

T. T. A l - S h e m m e r i, Staffordshire University, UK

Abstract: Combined heat and power (CHP) production compared with single generation of power has two advantages: it helps to improve the utilisation of energy production and to reduce pollution. Cost-efficient operation of a CHP system can be planned using an optimisation model based on the thermodynamic principles involved in the behaviour of the system’s working fluid and operating conditions of the system’s components. However, the calculations are complex, lengthy and prone to errors. Hence a computerised model was written with the aim of helping the designer to examine the influence of the various parameters involved on the overall efficiency/utilisation of the plant under different conditions. The model in this chapter examines the effect of the varying demand on heat and power and calculates the performance parameters and the overall utilisation factor of the plant at any power/heat ratio. Finally, a case study is presented to demonstrate the system performance of a CHP system driven by biogas internal combustion engine. Key words: CHP, cogeneration, power generation, thermodynamic modelling.

3.1

Introduction

Fuels (such as coal, oil, natural gas, biomass and biogas) are burnt to release energy which is then harnessed to serve some useful purpose. The most basic form of the released energy is heat (as in a domestic boiler) and this can then be distributed via a heat-exchanger and a circulating fluid to be used for water and space heating. Good domestic boilers have good thermal efficiency in the range of 60–80% or even higher, so some heat is lost depending on the design, maintenance of the burner and on the type of fuel. In power plants, heat is used to drive steam turbines which are in turn coupled to an alternator thus producing electricity. In this mode, typically the system is only 30–40% efficient, hence two-thirds of the energy in the fuel is wasted. Most power stations are designed and built for the sole purpose of producing electricity, and all heat is dumped to the atmosphere. If these two requirements are well planned and the choice of system or location is carefully selected, it is possible to make use of the reject heat 42 © Woodhead Publishing Limited, 2011


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from the power utility, and hence improve the returns from the fuel, hence increase the efficiency of the system. This method of producing/using two outputs is known as cogeneration or combined heat and power (CHP). In CHP systems, the waste heat is used to provide process heat or space heating/ cooling for industrial facilities, district energy systems, and commercial buildings. By recycling this waste heat, cogeneration systems achieve typical effective electric efficiencies of 50–80% – a dramatic improvement over the average 33% efficiency of conventional fossil-fuelled power plants. The higher efficiencies of cogeneration improve productivity by reducing fuel costs and reduce greenhouse emissions.

3.2

Types of combined heat and power (CHP) systems

A cogeneration unit consists of the following three basic components: ∑

a primary mover in which fuel is converted into mechanical and/or thermal energy ∑ a generator to transform the mechanical energy into electricity ∑ a heat recovery system to collect the produced heat. Gas engines are normally used in situations where the heat is used for spatial heating. When higher temperature heat is needed, e.g. for process heating, gas turbines tend to be more appropriate. Traditionally, gas engines have been used for small-scale applications (200 kWe–5 MWe), while gas turbines and steam turbines have been used for large-scale applications (> 5 MWe). In recent years, however, the micro turbine (30 kWe–0.5 MWe) has come onto the market and entered use for many small-scale applications. Prime movers for CHP systems can be any of the following options: ∑ Steam turbines ∑ Gas turbines ∑ Internal combustion engines ∑ Solar systems ∑ Biomass external combustion systems ∑ Stirling engines. In conventional thermal power plants, only about one-third of the energy in the coal or oil appears as electrical power – two-thirds of the energy is thrown away in the form of lukewarm water, in cooling towers, to rivers or to the sea. Alteration of the design and operation of an electrical power plant to cogenerate useful heat and work improves energy utilisation. The heat must be provided at the correct temperature for space and hot water requirements of domestic, commercial and public buildings, or alternatively steam may be provided to meet industry’s needs for processes.



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44


The design of CHP systems will depend on the individual application. In order for CHP systems to be economically viable, it is essential to exploit every possibility of minimising cost by a fully logical approach both in the area of generation and in the transport and distribution of heat. Among other considerations are the following parameters: ∑ period of use of the existing generating plant ∑ electrical and thermal load capacities of the appropriate plant ∑ load variations, daily, diurnal, diversity of household, industrial, commercial loads ∑ flow temperatures in the supply network related to pipe diameter required ∑ methods used for metering, operation of tariffs, collection of charges. There are three general areas of cogeneration: ∑ combined heat and power for district heating ∑ combined heat and power for commercial buildings ∑ combined heat and power for industry. The reject heat from a conventional power plant is at too low a temperature for district heating purposes, but with some design changes, it can be raised with some loss in the production of electricity. From the point of view of electricity production the result is a loss of efficiency but, when combined electricity and useful heat production is considered, there is a considerable increase in the overall effectiveness over the same quantities of electricity and heat produced from the separate sources. As a general guide the overall efficiency of a domestic cogeneration (CHP/DH) system can be of the order of one and a half times greater than the efficiency from separate sources. Such an increase results in large projected fuel savings. For any CHP/DH scheme to be viable, the savings in fuel costs must be sufficient to provide for the extra capital costs of the scheme together with any inducements necessary to persuade potential customers to switch from their existing methods of heating. Industrial cogeneration (CHP) has been widely applied in industry for the production of electricity and process heat, especially in areas that have a high demand for process heat. In certain cases it may be necessary to utilise a boost fired burner to ensure the correct thermal quality of process heat as required by the consumer. If a large company has suitable electrical and process heat requirements, then it may be more economical to operate and maintain their own CHP system.

3.3

Thermodynamics of cogeneration

When designing CHP installations there are a number of design issues, design variables and operating factors to consider to achieve optimum plant



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45

performance. In order to analyse CHP systems, it is necessary to review the thermodynamics of the basic stand-alone power processes and the heat producing system and then to consider the CHP alternative. In this chapter typical analysis is based on the steam plant cycle as it shares the working fluid with the process heat. The following subsections present three scenarios in which such plants can operate.

3.3.1 Scenario one: power only Consider the basic power plant. The sole purpose is to convert a proportion of the input energy transferred to the working fluid into useful work. The remaining portion of the heat is rejected to rivers, lakes, oceans, or the atmosphere as waste heat. Wasting a large amount of heat is a price we have to pay to produce work, because electrical or mechanical work is the only form of energy on which many engineering devices can operate. Power only cycles have typical efficiencies in the region of 35%. Figure 3.1 shows a schematic diagram of the simple power-only plant operating on the basic Rankine cycle with superheated steam. The figure also displays the temperature–entropy property diagram of the cycle. It can be seen that this simple cycle is made up of four components/processes. The focus in this cycle is on the turbine unit, process 3–4, which represents the power output developed. Hence, optimising this process is vital to getting the best out of the system. The net power output from this system is given in terms of steam mass flow rate and enthalpies as:

Wnet = ms ¥ [(h3 – h4) – (h2 – h1)]

3.1

Where Wnet is the net work output from the system, ms is the mass flow

Boiler

3

Turbine 3

T 4

2

Condenser

2 1

Pump

4

1 S

3.1 A simple ‘power-only’ plant and its T-s cycle.



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46


rate system, hx is the enthalpy of steam at stake point xT (x represents any number corresponding to the cycle Fig. 3.3).

3.3.2 Scenario two: heat only Many systems or devices, however, require energy input in the form of heat, called process heat. Some industries that heavily rely on process heat are chemical, pulp and paper, oil production and refining, steel making, food processing, and textile industries. Process heat in these industries is usually supplied by steam at 5–7 bar and 150–200 °C. Energy is usually transferred to the steam by burning coal, oil or natural gas in a furnace. The process heat output from this system is given in terms of steam mass flow rate and enthalpies as (see Fig. 3.2): Qprocess = ms ¥ [(h3 – h4)]

3.2

The generation of high quality steam for process heating only is generally efficient, however, as in any practical situation, it suffers from losses due to: ∑ inefficient heat transfer surfaces ∑ losses in distribution ∑ irrecoverable thermal energy of the steam at exit from process heater. In spite of the above losses, a typical heat-only scheme has efficiency in excess of 80%.

3.3.3 Scenario three: combined heat and power In practice, industries that use large amounts of process heat also consume a large amount of electric power. Therefore, it makes economical as well as engineering sense to use the already existing work potential to produce PRV

3

T

Boiler

3

4 2

2 Pump

1

Process heater

4

1 S

3.2 A simple ‘process heating only’ plant and its T-s cycle.



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47

power while utilising thermal energy for process heat, instead of letting it go to waste. Such a plant is called a cogeneration plant. In general, cogeneration is the production of more than one useful form of energy (such as process heat and electric power) from the same energy source. A schematic of a typical steam-turbine cogeneration plant is shown in Fig. 3.3. Under normal operation, some steam is extracted from the turbine at some predetermined intermediate pressure (point 5). The rest of the steam expands to the condenser pressure (point 6) and is then cooled at constant pressure. The heat rejected from the condenser represents the waste heat for the cycle. At times of high demand for process heat, all the steam is routed to the process heating units and none to the condenser. The waste heat is zero in this mode. If this is not sufficient, some steam leaving the boiler is throttled by an expansion or pressure-reducing valve (PRV) to the extraction pressure (point 5) and is directed to the process heating unit. Maximum process heating is realised when all the steam leaving the boiler passes through the PRV. No power is produced in this mode. When there is no demand for process heat, all the steam passes through the turbine and the condenser, and the cogeneration plant operates as an ordinary steam power plant.

1

3

Boiler

2

Turbine

PRV 11

4

5

6

Process heater

10 Mixing Pump 2

7

Condenser

9

Pump 1

8

3.3 Combined heat and power plant.



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48


3.4

Performance analysis of cogeneration cycles

The following parameters are considered in evaluating the performance of a CHP. Referring to the CHP cycle in Fig. 3.3, the net power output from this system is given in terms of steam mass flow rate and enthalpies as: Wnet = ms ¥ [(h3 – h6) – (h9 – h8) – (h7 – h10)]

3.3

The process heat output from this system is given in terms of steam mass flow rate and enthalpies as: Qprocess = ms ¥ [(h4 – h7)]

3.4

The work ratio gives an indication of the proportion of useful power to that produced in the turbine. WR = [(h3 – h6) – (h9 – h8) – (h7 – h10)]/[(h3 – h6)]

3.5

The utilisation factor in cogeneration is used in place of the thermal efficiency, to describe the ratio of useful energy output divided by the energy input: Utilisation tilisation ffactor actor =

Network orkk output + P or Pro rocess heat eat heat supplied

3.6

The specific steam consumption (SSC) indicates the relative size of plant, i.e. mass flow per unit power output. This determines the compactness of the system so it is desirable to have this as low as possible, as less steam used to generate power implies less energy is wasted in pumping, heating, etc. SSC =

3.5

3600 kg/kWh Network or ork

3.7

Theory of heat exchangers

A heat exchanger is a device used for transferring heat from a hot fluid to a cold fluid. There are three different types of heat exchangers, depending on the geometry and the way in which the two fluids interact: ∑ ∑ ∑

double-pipe heat exchangers shell-and-tube heat exchangers cross-flow heat exchangers (see Fig. 3.4).

Heat exchange between a hot fluid and a cold fluid across the metal boundary of a heat exchanger is represented by equations: Cold fluid: Qa = mair ¥ Cpair ¥ DTair

3.8

Hot fluid: Qw = mwater ¥ Cpwater ¥ DTwater

3.9

heat exchanger Qex = AUm DTm

3.10



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49

Thi

DT1 Cross flow Tho

dq Tco

DT2

Tube flow

Tci

3.4 Cross-flow heat exchanger and a typical temperature profile.

where Q is the total heat transfer rate, A is the total internal contact area, and Um is the mean overall coefficient of heat transfer. There are three methods for evaluation/sizing heat exchangers.

3.5.1

The logarithmic mean temperature difference (LMTD)

The LMTD is defined by the four temperatures involved as follows: DT1 – DT2 ln((DT1 /DT2 )

3.11

where: DT1 = Th,i–Tc,o and DT2 = Th,o–T c,i

3.12

DTln =

3.5.2

The modified LMTD

This is applicable to other types of heat exchangers, with factors taken from correction charts to allow for deviation from the double pipe LMTD values. In most practical designs the two fluids will not flow in pure co-current, counter-flow or cross-flow fashion but will be some combination of all three. In the common ‘shell and tube’ heat exchanger, the temperature profile is further complicated by the fact that the shell side flow is not in one direction due to the presence of baffles. Baffles are installed to increase shell side fluid velocities and mixing and hence improve the shell side heat transfer coefficient. Clearly the simple logarithmic mean temperature difference equation cannot be directly applied in these cases and a correction factor (F) has to be applied to DTm (LMTD) for a simple double pipe heat exchanger. The analysis of multipass and cross-flow geometries is usually presented graphically utilising two system characteristic temperature ratios. Z=

Ti – To t –t ,P= i o to – ti Ti – t i

3.13



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50


where T and t denote the shell-side and tube-side temperatures, respectively, and i and o denote inlet and outlet respectively. The rate of heat transfer (Q) is given by Q = U ¥ A ¥ DTm ¥ F

3.14

Correction factor charts for common geometric are available in standard textbooks on heat transfer or heat exchangers.

3.5.3

The number of transfer units (NTU)-effectiveness method

This method for evaluating the performance of heat exchangers has the advantage that it does not require the calculation of the logarithmic mean temperature difference. its main use is to calculate achievable outlet temperatures by an existing heat exchanger of known area and construction upon a change in operating requirement or duty. The method depends on the evaluation of three dimensionless parameters: the effectiveness, the NTU and the capacity ratio, these are defined in the following paragraphs. Effectiveness (e) This is defined as the ratio of actual heat exchange to the maximum possible heat transfer Q Actual al heat ttransfer = maximum possible heat tra ransfer Qmax . where Qmax = (m Cp)min (Thi – Tci) . Q = m h Cph (Thi – Tho) . Q = m c Cpc (Tco – Tci)

e=

3.15 3.16 3.17 3.18

hence

e=

m h C Cpph (Thi – Tho ) m Cp (T – Tci ) or c c co  p )min  p )min (mC (mC min (Th hii – Tci ) min (Th hii – Tcci )

3.19

depending on which data are available. Number of transfer units (NTU) This is defined as: . NTU = UA/(m Cp)min

3.20



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51

The Capacity ratio This is defined as: . . R = (m Cp)min/(m Cp)max

3.21

It can be shown that for any heat exchanger, the effectiveness is:

e = Function of (NTU, capacity ratio, system geometry)

The analytical solutions to the above for various geometries are represented graphically by [R = Cpmin/Cpmax]. It is possible to use this method in three different ways: with any two unknowns, the third can be predicted: ∑ knowing the effectiveness and the NTU to predict the capacity ratio ∑ knowing the effectiveness and the capacity ratio to predict the NTU ∑ knowing the NTU and the capacity ratio to predict effectiveness. The NTU, capacity ratio (R), and the effectiveness are inter-related. They are often presented in the form of a chart for a specfic heat exchanger; so knowing any two quantities will help find the third quantity from the chart. Then, by calculating the Cmin/Cmax and the NTU, the effectiveness can be read from these charts. Once the effectiveness has been found, the heat load is calculated by:

Q = Effectiveness ¥ Cmin

3.6

¥ (Hot temperature in – Cold temperature in)

3.22

Worked example

In a CHP plant (see Fig. 3.3), steam enters the turbine at 7 MPa and 500 °C. Some steam is extracted from the turbine at 500 kPa for process heating. The remaining steam continues to expand to 10 kPa. Steam is then condensed at constant pressure and pumped to the boiler pressure of 7 MPa. At times of high demand for process heat, some steam leaving the boiler is throttled to 500 kPa and is routed to the process heater. The extraction fractions are adjusted so that steam leaves the process heater as a saturated liquid at 500 kPa. It is subsequently pumped to 7 MPa. The mass flow rate of steam through the boiler is 10 kg/s. Disregarding any pressure drops and heat losses in the piping, and assuming the turbine and the pump to be 100% isentropic, determine: (a) the rate at which process heat can be supplied when the turbine is bypassed, (b) the power produced when the process heater is bypassed, and (c) the rate of process heat supply and power output, when the PRV is



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52


closed, 50 percent of the steam is extracted from the turbine at 500 kPa for process heating and the remaining 50% expands through to the condenser.

Solution In this worked example, there are three scenarios of power and/or heat to be investigated. In order to evaluate each, it is important to determine the behaviour of the working fluid (water/steam) during the processes involved. The behaviour of water/steam undergoing various processes is best examined by following a property chart, and the best chart to use in such situations is the temperature-entropy chart for steam, as shown in Fig. 3.5. The CHP cycle is marked by locating the known points and condition at key points in the plant under a given working condition. Conditions such as operating pressure and temperature will help locate the various joints. The T-s chart, once completed, will allow the user to find the enthalpy (heat content) at each point, according to the analysis carried out in Section 3.4. Steam tables can also be used to find more accurate values, but using steam tables is time consuming compared with locating points on the T-s charts, and using charts is standard practice for designers and engineers. However, there is an even better method, using look-up tables or fitting equations to the behaviour of water/steam. Using computer-aided macros, it is nowadays possible to carry out such complex calculations, but for the

1,2,3

500

400 T (°C)

4

300

200

10 11

100

7

9

5

8

0 0

6 2

4 6 s (kJ kg–1 K–1)

8

10

3.5 Temperature-entropy chart for combined heat and power plant.



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53

sake of explaining how the performance of a ChP is evaluated, this worked example is completed by manual calculations base on properties found from the steam chart and tables. First of all, determine the enthalpy values at key points in the cycle: h1 = h2 = h3 = h4 = 3410.3 kJ/kg h5 = 2738.2 kJ/kg (¥5 = 0.995) h6 = 2153 kJ/kg (¥6 = 0.819) h7 = 640.23 kJ/kg h8 = 191.83 kJ/kg h9 = h8 + vf8 (P9 – P8) = 91.83 + 0.00101(7000 – 10) = 191.83 + 7.061 = 198.9 kJ/kg h10 = h7 + vf7 (P10 – P7) = 640.23 + 0.00109(7000 – 500) = 640.23 + 7.1 = 647.33 kJ/kg h11 =

m10.h10 + m9.h9 5 ¥ 647.33 + 5 ¥ 198.9 = = 423.11 kJ/kg m10 + m9 5+5

(a) Heat only The maximum rate of process heat is achieved when all the steam leaving the boiler is throttled and sent to the process heater and none is sent to the turbine: m· 4 = m· 7 = m· 1 = 10 kg/s; m· 3 = m· 5 = m· 6 = 0 Thus, Q· r.max = m· 1(h4 – h7) = 10[(3410.3 – 640.23)] = 27.700 MW (b) Power only When no process heat is supplied, all the steam leaving the boiler will pass through the turbine and will expand to the condenser pressure of 10 kPa, that is: m· 3 = m· 6 = m· 1 = 10 kg/s and m· 2 = m· 5 = 0 maximum turbine work is: W· t = m· 1(h3 – h6) = (10)[(3410.3 – 2153)] = 12.573 MW



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54


W· p = m· (h9 – h8) = (10)(198.9 – 191.83) = 0.070 MW W· Net = W· t – W· p = 12.503 MW (c) For a cogeneration operation (i) Process heat: Q· P = m· 5(h5 – h7) = 5.0(2738.2 – 640.23) = 10.489 MW (ii) Power: Wp = m5(h10 – h7) + m6(h9 – h8) = 5(647.23 – 640.23) + 5(198.9 –191.83) = 0.071 MW Wt = m· 3(h3 – h5) + m· 6(h5 – h6) = 10 (3410.3 – 2738.2) + 5.0 (2738.2 – 2153) = 9.647 MW Wnet = 9.647 – 0.071 = 9.576 MW (iii) The input heat supplied and utilisation factor: Q· in = m· 1(h1 – h11) = (10)[(3410.3 – 423.11)] = 29.872 MW

e=

3.7

Q p + Wnet 10.489 + 9.576 = = 0.67 Qin 29.872

Computational modelling of a combined heat and power (CHP) cycle

it is clear that analysing a combined heat and power cycle is a lengthy process. especially when optimum performance is to be achieved, the search for optimum operating conditions is determined by very many parameters. in order to assess how variable conditions affect a typical cycle, computational software is essential. To allow amendments to be made to cycle conditions, and to assess results in detail, an excel program was created. The software approach has the added advantage of eliminating errors and improving the accuracy of calculations. in this chapter it was decided to investigate the influence of varying some key conditions in the cycle and examine their effect on the performance of the ChP plant. The variable conditions included the boiler pressure superheated temperature, heat extraction pressure, turbine and pump isentropic efficiency, and percentage of heat extracted. To enable this to be evaluated in detail, it is important that only one variable is changed at a time, with all other conditions remaining constant. The program was created in Microsoft Excel 2007. Firstly, the steam table data were copied into Excel (Keenan et al., 1969).



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55

Using a combination of ‘if’, ‘Vlookup’ and ‘And’ functions, the steam table properties were extracted from the tables for the key points within the cycle. The isentropic efficiency of a pump or turbine is defined as the ratio of the actual work output vs the work output if the process between inlet and outlet is isentropic. Pump efficiency can be adjusted, amending h2 and h8 data as appropriate. The following calculations were used: h2 = h1 +

h2¢ – h1 Ep

h8 = h7 +

h8¢ – h7 Ep

Turbine efficiency can be adjusted, changing h5 and h6 data. The following calculations were used: h5 = h4 – Et(h4 – h¢5) h6 = h4 – Et(h4 – h¢6) The enthalpy value at h¢5 can be accurately calculated, even if the process heat inlet falls inside or outside of the saturation line, i.e., whether mixed phase or superheated. This process uses an ‘if’ function. if the dryness fraction of the extract process heat is mixed phase (i.e. x5 < 1), then h5 is calculated using the dryness fraction calculation below: h¢5 = hf + x5hfg If the dryness fraction is above 1 (i.e. superheated), then a lookup function matches the entropy value at s4, with the data in the extract process heat steam table at the superheated condition. Some interpolation goes ahead, and the exact value for h5 can be calculated.

3.8

Analysis of the computational model of the combined heat and power (CHP) system

The software developed for the combined heat and power plant was verified against manual calculations, and the results are compared and shown in Table 3.1. The maximum error between manual and Excel program methods is only a fraction of a percent. Such small errors can be explained by inconsistent rounding of numbers in the manual calculations. The simulation package developed here proved a very useful tool to investigate the various parameters involved in an accurate and fast way. One area for improvement is that the excel program could use the industrial formulation for calculation of properties of water and steam (known as ‘IAPWS Industrial Formulation 1997 for the Thermodynamic Properties of Water and Steam (IAPWS-IF97)’). This would increase cycle analysis availabilities, as there are instances where the steam tables have limited data. © Woodhead Publishing Limited, 2011


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Table 3.1 Verification of simulation results against manual calculations Designation

Manual method

Program method

Units

h 1 h2’ h 2 h 3 h 4 x 5 h5’ h 5 x 6 h6’ h 6 h 7 h8’ h 8

191.83 192.83 192.83 482.212 3410.3 1.05 2877.94 2877.94 0.8197 2153.27 2153.27 762.83 771.594 771.594

191.83 kJ/kg 192.739 kJ/kg 192.739 kJ/kg 482.166 kJ/kg 3410.3 kJ/kg 1.047 2877.974 kJ/kg 2877.974 kJ/kg 0.820 2153.174 kJ/kg 2153.174 kJ/kg 762.810 kJ/kg 771.594 kJ/kg 771.594 kJ/kg

Error (%) 0 0.047 0.047 0.0095 0 0.29 0.0012 0.0012 0.037 0.0045 0.0045 0.0026 0 0

Notes

Ideal Real

Ideal Real Ideal Real Ideal Real

3.8.1 Variable 1: superheat temperature It can be noticed that by increasing the superheated boiler exit temperature from 300 °C to 600 °C, the process heat available (at constant process heat pressure) increases by 32%, from 8.59 MW up to 11.35 MW. Pump work remains constant, regardless of the superheated maximum temperature. As the superheated boiler exit temperature increases from 300 °C to 600 °C, the net work increased by 53% and the utilisation factor increased by 5% (see Fig. 3.6). It is clear that, to maximise the process heat available, the boiler exit temperature should be superheated. The hotter the boiler exit gas, the more process heat will be available.

3.8.2 Variable 2: pump efficiency Keeping all other points constant, adjusting the pump efficiency can be analysed in isolation. It is clear that the pump work increases dramatically as the pump isentropic efficiency drops. A decrease in pump efficiency of 90% to 70% implies higher pumping power and less net work output, but has little effect on the utilisation factor of the plant. However, a drop in pump efficiency below 50% will have a more serious effect (see Fig. 3.7). Service and maintenance is therefore key in ensuring the plant performance is maintained at the highest level.

3.8.3 Variable 3: turbine efficiency Keeping all other points constant, adjusting the turbine isentropic efficiency results in some concerning results (Fig. 3.8). A drop in turbine efficiency has



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57 1.000

35.000

0.900 30.000 0.800 25.000

0.700

Heat/work (MW)

0.600

20.000

Process heat Net work Input heat supplied Utilisation factor

15.000

0.500 e 0.400

0.300

10.000

0.200 5.000 0.100 0.000 0.000 300 320 340 360 380 400 420 440 460 480 500 520 540 560 580 600 Superheat temperature (°C) Max. pressure

Intermediate Min. pressure pressure

Pump efficiency

Turbine efficiency

Max. Extraction temperature ratio

70 bar

10 bar

100%

100%

300–600 °C

0.1 bar

50%

3.6 The superheat temperature influence on CHP performance.

a large effect on the turbine work available. A drop in efficiency from 90% down to 70% results in a drop in turbine work of 28.5%. Not only that, a drop in turbine efficiency has a direct effect on process heat available and net work, resulting in a reduction of the utilisation factor. During this analysis, pump work and input heat supplied remain constant.

3.8.4 Variable 4: extraction ratio Keeping all other points constant, adjusting the extraction ratio provides an interesting analysis (Fig. 3.9). As expected, dropping the extraction ratio reduces the utilisation factor. At an extraction ratio of 100% (i.e. maximum process heat), the utilisation factor is 1. Also, as the extraction ratio increases,



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9.000

0.700

8.900

0.600

8.800

0.500

Net work

8.700

Utilisation factor

0.400

MW

Pump work (kW)

e

8.600

0.300

8.500

0.200

8.400

0.100

8.300

0.000 10

20

30

40 50 60 70 Pump efficiency (%)

80

90

100

Max. pressure


Pump efficiency

Turbine efficiency


70 bar

10 bar

10–100%

100%

500 °C

0.1 bar

50%

3.7 Pump efficiency influence on CHP performance.

the process heating available also increases. No great surprises here. However, the extraction ratio also has a direct impact on the turbine work. As the extraction ratio increases, more process heat becomes available. However, turbine work decreases.

3.8.5 Variable 5: maximum pressure – boiler Keeping all other points constant, adjusting the maximum boiler pressure reveals some important information (Fig. 3.10). Increasing the boiler pressure and keeping the superheated temperature constant reduces the process heating available. Conversely, turbine work increases. An increase from 10 to 50 bar for maximum pressure, results in an increase from 5.088 to 8.439 MW of turbine work. This is an increase of 40%. However, increasing



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59

35.000

0.700

30.000

0.600

25.000

0.500 Process heat Net work Input heat supplied Utilisation factor

MW

20.000

0.400 e

15.000

0.300

10.000

0.200

5.000

0.100

0.000

0.000 10

20

30

40 50 60 70 Turbine efficiency (%)

80

90

100

Max. pressure


Pump efficiency

Turbine efficiency


70 bar

10 bar

100%

10–100%

500 °C

0.1 bar

50%

3.8 Turbine efficiency influence on CHP performance.

the maximum pressure from 50 to 100 bar results in a turbine work increase from 8.439 to 9.378 MW. A rather disappointing 11% increase, based on a doubling of maximum pressure. As the maximum pressure increases, input heat supplied reduces slightly. Conversely, pump work and utilisation factor increase slightly.

3.8.6 Variable 6: heat extraction pressure – process heat Keeping all other points constant, adjusting the process heat extraction pressure reveals some somewhat surprising information (Fig. 3.11). Increasing the process heat extraction pressure from 10 to 80 bar results in a tiny increase in process heat available of just 1.1%, from 10.576 to 10.697 MW. However, as the process heat extraction pressure increases, turbine work decreases quite significantly, whereas the utilisation factor decreases marginally.



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60


35.000

1.200

30.000

1.000 Process heat Net work

25.000

Input heat supplied

0.800

Utilisation factor

e

20.000 MW

0.600

15.000 0.400 10.000

0.200

5.000

0.000

0.000 10

20

30

40 50 60 70 Extraction ratio (%)

80

90

100

Max. pressure


Pump efficiency

Turbine efficiency


70 bar

10 bar

100%

100%

500 °C

0.1 bar

10–100%

3.9 Extraction ratio influence on CHP performance.

3.9

Case study: system performance of a biogasdriven small combined heat and power (CHP) system in a sewage works

This case study was reported as part of a Masters degree thesis submitted by Brian Rose, who worked on this project. The project was concerned with the design, supply and commissioning of a CHP plant for the treatment of sewage waste. A significant amount of digester gas is generated as a by-product and, following a feasibility study, it was decided to install a CHP plant to enable the site to become totally self-sufficient in heat and power. Anaerobic digestion is a process in which organic matter is broken down naturally by bacterial action. As the name suggests, the process takes place in the absence of air, and in conditions of warmth and darkness. Anaerobic



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Thermodynamics, performance analysis & computational modelling 35.000

61 0.680

0.670

30.000

0.660 25.000 0.650

Process heat Net work

20.000

Input heat supplied

0.640

MW

Utilisation factor

e 0.630

15.000

0.620 10.000 0.610 5.000

0.000 Max. pressure

0.600

0.590 10

20

30

40 50 60 70 Boiler pressure (bar)

Intermediate Min. Pump pressure pressure efficiency

10–100 bar 10 bar

0.1 bar

100%

80

90

100

Turbine efficiency


100%

500 °C

50%

3.10 Maximum boiler pressure influence on CHP performance.

digestion is commonly used to convert residues from farming, food manufacture and human waste. Sewage sludge is supplied to a heated vessel (the digester) where fermentation takes place in an oxygen-free environment. Microbial bacteria, which reside in the digester, feed on the organic matter and gases are evolved. The resulting digester gas is approximately 65% methane, 35% carbon dioxide, and has a gross calorific value in the range 20–23 MJ/m3. This level of energy content is sufficiently high to power an internal combustion engine.

3.9.1 Choice of prime mover Following an extensive feasibility study, a lean-burn spark ignition engine was selected as the prime mover for the CHP plant. The main advantages of the lean burn engine deemed relevant to this application were:



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35.000

0.700

30.000

0.600

25.000

0.500 Process heat Net work

20.000 MW

Input heat supplied

0.400

Utilisation factor

e

15.000

0.300

10.000

0.200

5.000

0.100

0.000

10

20

30 40 50 60 Extraction pressure (bar)

70

80

0.000

Max. pressure


Pump efficiency

Turbine efficiency


80 bar

10–80 bar

100%

100%

500 °C

0.1 bar

50%

3.11 Process heat extraction pressure influence on CHP performance.

∑ low emissions levels attainable with lean-burn ∑ heat-to-power ratio closely matched the requirements of the process ∑ high-grade heat suitable for the digestion process ∑ high levels of machine reliability ∑ relatively low capital cost compared to a gas turbine. Each engine is an 8-cylinder turbo-charged lean-burn engine, operating at a constant speed of 1000 rev/min with a compression ratio of 9:1 and a displacement of 142.5 litres. The engine is coupled to a 6-pole synchronous alternator, which generates 1.49 MWe rated electrical power at 11 kV and 50 Hz. A total of five engines are installed, giving the installation a maximum installed capacity of approximately 7.5 MWe. In practice, however, only three or four engines are operated at any given time to allow for routine



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engine maintenance and servicing. Each engine is fitted with a specially enlarged carburettor orifice to handle the increased gas flows through the engine. The engine is tuned for lean-burn operation, i.e. 100% excess air (equivalence ratio f = 2.0). A compact plate-type heat exchanger is employed to recover rejected heat from the engine-cooling jacket (Fig. 3.12). The heat exchanger is arranged so that it receives return water from the digester process at 59 °C and raises its temperature to about 70 ºC prior to further heating in the exhaust heat economiser. High-grade heat is recovered from the engine exhaust gas by means of an extended surface type heat exchanger. Exhaust gases at 360 °C are used to produce hot water at a temperature of 77 °C as required for the digester process.

3.9.2 Engine performance An initial appraisal of the engine thermal efficiency at full load capacity indicates a heat-to-power ratio of 1.56:1, representing a thermal efficiency Exhaust

Tout = 88°C

M

Economiser Qr = 1093 kW Gas engine BP = 1575 kW Alternator output = 1500 kW

Tin = 78.6°C Tout = 77 °C Digester m = 22 kg/s

Tin = 59 °C

Jacket circuit

M

Heat exchanger Qr = 782 kW Oil cooler

Intercooler circuit

key to symbols M

Control valve Pump

2-Stage radiator Note: mass and energy flowsat 100% design capacity

3.12 CHP system flow diagram.



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of 39.1%, when calculated on the saturated lower calorific value of the fuel = 32.9 MJ/m3 (@ 39.1 MJ/m3 dry gross saturated lower calorific value). When the engine is operating at part load, the gross thermal efficiency falls to approximately 28.9% at 22% load rating. The inter-relationships between efficiency heat rejection and thermal efficiency of the engine are illustrated in Fig. 3.13. Approximately 1.87 MW of high-grade heat is available when the engine operates at its maximum capacity of 1.57 MW brake power. The overall energy balance for the engine operating at 100% capacity can be illustrated in the form of a Sankey diagram (Fig. 3.14).

3.9.3 Heat recovery system The requirement for process heat is 1.7 MW at an outgoing temperature of 77 °C (±3 °C). The temperature of the process water is raised in two Jacket heat Intercooler heat

Exhaust heat Thermal efficiency

1200

Lube oil heat

45 40

1000

30

Heat rejection (kWth)

800

25 600 20

Thermal efficiency (%)

35

15

400

10 200 5

0 0

500

1000 1500 Shaft power (kWb)

0 2000

3.13 Engine efficiency and heat rejection.



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65

Exhaust losses 1092 kW (27%)

High-grade heat Fuel input 4037 kW(100%)

Useful work Low-grade heat

Radiation 50 kW(1.2%)

High-grade heat

Shaft power 1577 kW (39.1%)

Jacket Lube oil Intercooler heat cooling heat 144 kW(3.6%) 391 kW(9.7%) 783 kW(19.4%)

3.14 Sankey diagram for a single generation scheme (engine at 100% rated capacity without heat recovery).

stages by passing it first through the jacket water heat exchanger then finally through the exhaust heat economiser. The heat exchanger employed is a compact type plate heat exchanger, which has a multiple pass arrangement. This type of heat exchanger has a very small hydraulic radius in the fluid flow channels, which reduces the effect of the laminar fluid film at the interface between the fluid and the heat exchanger. The overall heat transfer coefficient is enhanced by the use of turbulence-inducing patterns within the fluid flow channels of the heat exchanger. As a result, very high energy transfer rates per unit area can be achieved when compared to a traditional shell and tube type heat exchanger. The compact heat exchanger (CHE) employed in this particular application operates under the conditions given in Table 3.2. The overall heat transfer coefficient was very high (9798 W/m2K), as would be expected for this type of heat exchanger. The overall effectiveness was quite low, but this could be attributed largely to the higher thermal capacity ratio of the fluid streams. It can be shown that heat exchanger effectiveness decreases with increasing thermal capacity ratio (where thermal capacity ratio R = Cpmin/Cpmax). The approach temperature was also higher than would be expected of a CHE unit, but this was unavoidable in this particular application. Cooling of the engine coolant would result in high thermal stresses in the engine.



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Table 3.2 Compact heat exchanger performance (at full load condition) Parameter

Units

Fluid Flow rate kg/s Inlet temperature °C Exit temperature °C Specific heat capacity KJ/kgK Thermal capacity ratio – Surface area m2 Heat exchanged kW Overall heat transfer coefficient, U W/m2K Overall effectiveness e Approach temperature °C

Hot stream

Cold stream

50% glycol 20.6 88 73.9 3.435 1.184 13.2 996.4 9798 0.52 17.4

water 21.1 59 70.6 4.066

Table 3.3 Economiser performance (at full load condition) Parameter

Units

Fluid Flow rate kg/s Inlet temperature °C Exit temperature ∞C Specific heat capacity KJ/kgK Thermal capacity ratio – Surface area m2 Heat exchanged kW Overall heat transfer coefficient, U W/m2K Overall effectiveness e Approach temperature °C

Hot stream

Cold stream

Flue gases 3.02 338 118 1.11 0.273 137.4 736.8 43 0.883 38.9

water 21.1 70.6 79.2 4.066

3.9.4 Exhaust Heat Recovery The exhaust heat exchanger is an extended surface heat exchanger, which consists of a double bank of finned tubes inserted in the flue gas stream of the engine. Exhaust gases flow over the external surfaces of the finned tubes, which contain the heat transfer media. The overall heat transfer coefficient was very low (U = 43 W/m2K), mainly due to large hydraulic radius of the fluid passages in the heat exchanger. The economiser was specially designed for low flow resistance on the flue gas side of the economiser, due to a limitation on the exhaust system backpressure of 508 mm H2O. The overall effectiveness though was very high (e = 0.883), this being due to the low thermal capacity ratio between the flue gas and the water (see Table 3.3).

3.9.5 Overall system performance With the incorporation of heat recovery equipment, the performance of the combined heat and power system becomes 82% at maximum design capacity (Fig. 3.15). Using biogas fuel to operate the system displaces emissions from combustion of fossil fuels from centralised power generation plants.



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Thermodynamics, performance analysis & computational modelling Exhaust losses 285 kW(7.1%)

67

Overall thermal efficiency = 82%

Fuel input 5982 kW (100%)

High-grade heat

Economiser heat recovery 737 kW(18.3%)

Power

Electrical power 1577 kW(39.1%)

Jacket heat High-grade heat recovery 998 kW(24.7%)

Radiation 50 kW(1.2%)

Intercooler heat 391 kW(9.7%)

Radiator heat rejection 297 kW(4.9%)

3.15 Sankey diagram for a cogeneration scheme (engine at 100% rated capacity with heat recovery). Table 3.4 Emissions reduction per generator Pollutant

Biogas CHP emissions (g/kWh)

Centralised power generation (g/kWh)a

Emissions reduction due to power + heat (tonnes/year)

CO2 NOx SO2

696 0.15 0.04

720 1.9 5.2

15,488 30 74

a

The data given for centralised power generation assumes a mix of 50% coal, 47% gas, and 3% oil, inclusive of 5% transmission losses. A boiler efficiency of 80% was assumed in the calculation of emissions reductions due to heat recovery.

The degree of displacement is further improved by the incorporation of heat recovery to offset fuel consumption, which would otherwise be consumed in process heating. The overall displacement effect is summarised in Table 3.4, and assumes that the plant would be operational for 8760 hours per annum.

3.9.6 Conclusions ∑

The use of biogas fuel in this installation demonstrates the viability of a renewable energy source. This system not only reduces dependency on



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∑ ∑

∑ ∑ ∑


fossil fuel, but also exhibits a high level of thermal efficiency through heat recovery consumption local to the point of generation. The installation enables the sewage treatment processing plant to be self-sufficient in its energy needs, i.e. no energy is imported from the national grid. The installation uses a free source of energy which would otherwise vent to atmosphere, which, if imported as premium natural gas, would cost £389,000 per generator (based on 3536 MWh imported at 1.1 p/ kWh tariff). This type of installation offers further diversity in sources of energy, and helps reduce national dependence on finite reserves of traditional fossil fuel. Due to its high level of efficiency, the installation is exempt from the climate change levy taxation of 0.15 p/kWh, producing an annual saving of £2,900 per generator. This particular installation uses 100% renewable energy and is therefore exempt, producing an annual saving of approximately £43,700 per generator based on 10% of the potential 1.32 GWhe energy produced per annum.

In economic terms, the plant is able to exploit a free energy source, which would otherwise be vented to atmosphere from the digestion process. As a result, the sewage treatment plant is self-sufficient in energy, and is in fact able to export electrical energy to the national grid at times of low in-house demand.

3.10


http://www.theiet.org/publishing/books/renewable/cogeneration.cfm http://www.chpa.co.uk/ http://www.cibse.org/index.cfm?go=page.view&item=385 http://www.publications.parliament.uk/pa/cm199899/cmselect/ cmenvaud/159/9022306.htm http://www.carbontrust.co.uk/emerging-technologies/current-focus-areas/ pages/micro-combined-heat-power.aspx http://www.iea.org/files/CHPbrochure09.pdf

3.11

References and further reading

Boyce, M.P. (2010) Handbook for Cogeneration and Combined Cycle Power Plants, 2nd edn. ASME Publications, New York. Keenan, J. H., Keyes, F.G., Hill, P.G. and Moore, J. G. (1969) Steam tables, John Wiley & Sons, New York.



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Kehlhofer, R., Hannemann, F., Stirnimann, F. and Rukes, B. (2009) Combined-Cycle Gas and Steam Turbine Power Plants, 3rd edn. PennWell Corp., Tulsa, OK. Horlock, J. H. (2001) Combined Power Plants: Including Combined Cycle Gas Turbine (Ccgt) Plants. Krieger Publishing Company, Malabar, FL.



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4

Integration of small and micro combined heat and power (CHP) systems into distributed energy systems

J. D e u s e, GDF-SUEZ – Tractebel Engineering, Belgium

Abstract: During the last decades electrical systems have undergone a transformation, which is still underway and is supposed to lead from the ‘vertical integration’ model to a fully open electricity market. This process presently overlaps with the development of distributed energy resources (DER) that brings under a single concept electricity generation, storage of energy and demand response, all at small scale. DER development raises a number of issues for the different stakeholders. However, it is obviously an opportunity for new, emerging market players, but it brings also new perspectives for incumbents. Participation of DER in the different energy markets requires the setting up of upgraded structures for aggregating small energy sources. This chapter summarizes why dispersed generation is innovating in the electrical power system context. It shows how distributed generation can represent value for the system and it evaluates the significant economic advantage of being interconnected. It concludes with recommendations to wire companies and to regulatory bodies. Key words: distributed energy resources (DER), distributed generation (DG), distribution system operators (DSO), smart grids, regulation.

4.1

Distributed energy resources (DER)

4.1.1 Initial developments in power systems Before addressing the issue of integration of DER in the power system, it is useful to recall briefly the development of the production of mechanical energy during the nineteenth century as well as the transition to electricity as a multi-purpose energy resource. From the beginning of the industrial revolution, with the introduction of the steam engine, ‘power generation’ meant ‘centralization’. This was the result of the physical and technical principles that lie behind these complex processes and the ‘hierarchy’ of the different forms of energy. These physical principles are still present today and have induced a strong opposition between production, on the one hand, and consumption, on the other. Historically the steam machine was built in front of each workshop where the mechanical power generated was distributed to different machines 70 © Woodhead Publishing Limited, 2011


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71

using a system consisting of transmission shafts, pulleys and belts. The size of the production machine was already significantly larger than the average power consumer process in the workshop. Therefore, ‘centralization’ of power generation existed prior to the birth of the electricity sector. When electricity development started, things did not change immediately. The structure of the distribution of the mechanical power in workshops remained more or less as it was, partly because electrical machines were extremely costly. Thus the steam engine was replaced by a single electric motor. However, a certain concentration took place upstream, because it was no longer necessary to place generation and utilization of energy side by side. The complexity of the energy transformation process leading to electricity production provoked the development of larger factories. The flexibility of the transmission and distribution of electricity, particularly using alternating current, allowed the increasing separation of power generation and the various industrial processes. Within the factory, the electricity generating units were installed in the same building, called the ‘power plant’, in French ‘la centrale électrique’, an expression where the notion of centralization is obvious. The security of supply for the different workshops was strengthened as they were fed by all these units operating in parallel rather than being dependent on a single local steam engine. This shows that electricity is inherently an activity organized about the network. The next step consisted in the development of the connection between neighbouring factories to ensure the sharing of reserves. This permitted the same level of reliability to be reached while limiting the cost of development of the system. The principles that justify network interconnection were already at work. This is due to the relatively lower cost of high voltage (HV) networks compared to the cost of power plants. It is important to note that distributed generation (DG), which is a component of DER, is not a return to a solution or situation from the past. It is really a new era for electrical systems. Indeed, for the first time since the beginning of the electricity generating industry, one can consider that for certain applications and certain primary energy sources, the production of electricity by very small units could become profitable in the short term. The DG label is less a question of size than a matter of ratio. Indeed a generation unit of 10 MW installed in a large interconnected system can be considered as a decentralized generation, whereas the same unit installed in a system of 100 MW of peak power, would probably be considered as ‘centralized’. Soon it will be possible to consider combined production of heat and electricity (cogeneration) facilities designed for being installed in single family houses and leading to profitable operation without any incentives beyond ‘green certificates’. Within 10 to 20 years it may also be the case for photovoltaic conversion. Never in the past has it been possible to use energy conversion processes of such a small size. Today, it is becoming possible



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to generate electricity with generators having a size which is comparable to the size of load components.

4.1.2 Reliability of supply The economic value of local generation is highest when it is interconnected with the network. This is a direct consequence of the fundamental properties of any electrical system requesting, among other things, the real-time adjustment of the balance between production and consumption both for active and reactive powers. This requires specific technical solutions that the liberalization of the energy market has made more complex. Reliability of supply does not play the central role it played under the ‘vertical integration’ paradigm for the planning of generation. Most often in the present situation of the electricity market there is no longer any clear standard for setting the requested over-capacity in terms of generation which should be available to ensure the reliability of supply objectives. At best it is developed at generation company level. The need to build a new plant is only determined by the market.1 Such a position, however, is not absolute. In the United States, PJM, for example, checks on a yearly basis the evolution of future performance in terms of reliability.2 In the description that follows, to simplify the approach and as a first approximation, the system will be considered using the ‘vertical integration’ paradigm. The reliability of supply consists of two complementary aspects: the adequacy on the one hand and security on the other. The first, adequacy, means that the system is able to generate and transmit power from generating plants to the load for a set of standard situations including ‘normal’ and ‘abnormal’ situations which must also be carefully defined. ‘Abnormal’ means that the system is weakened due to the unavailability of some of its elements, whether these be the result of maintenance activities or the occurrence of sudden unexpected ‘events’, hence the concept of ‘secured events’.3 The second, security, means that the system must be robust for guaranteeing a stable operation when faced with these secured events. This robustness is based on the concept of preventive safety margins that must be respected during system operation. In the case of more serious incidents, the preservation of the integrity of the power system involves specific operational procedures and also the deployment of automatic countermeasures known as defence plans. This decomposition of the reliability concept into adequacy and security aspects is valid independently of the size of the network. Ensuring the reliability of any system involves, therefore, specific means allowing for the adjustment in the short, medium and long terms of the active and the reactive power balance. Indeed, voltage and frequency stability depends highly on the balance between production and consumption. The network physically



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aggregates loads and production. The safe operation of the electrical power system assumes a ‘sufficient control’ of generation. This is implemented through the ‘aggregation’ of the various generating plants by means of communication channels (this is an extension of the earlier practice, but now considering smaller units) or it is based on ‘statistical’ principles (micro cogeneration status can be stochastically assessed according to weather forecasts for example at lower cost). Furthermore, demand response can be included as an innovative manner of stabilizing system operation.

4.2

The value of distributed generation

Successful integration of distributed generation can result from consistent and progressive actions that consider the technical aspects first, then the market architecture and of course the associated regulatory framework. The methodology that was developed as part of the EU-DEEP research project4 started from a simple assumption: most of the physical properties of electrical systems cannot be circumvented; as a result, the in-depth analysis of system behaviour is the route to the identification of solutions that can be effectively deployed. This then allows the selection of the most effective market mechanisms. In particular it is fundamental to propose solutions that are able to reveal the actual value that DER can represent for the network, and for the system beyond the potential gains that it allows in terms of externalities. However, the ‘sustainable’ economy of distributed generation, without incentives, has not yet been demonstrated. According to new actors, distributed generation has many advantages which should be remunerated. For traditional players, especially distribution system operators (DSO), the connection of distributed generation raises many questions, such as voltage setting, operation of protection, risks related to island operation (‘anti-islanding’ protection) and the increase in short-circuit power. A lack of clarity results also from the appellation ‘distribution network’. In some cases it means medium and low voltage networks, but for others it means a network from as high a voltage as 132 kV down to the low voltage network. But this can also be a consequence of the attitude of some of the market players who are not willing to play this new game.

4.2.1 Technical aspects In fact, most of the issues relating to distributed generation can be solved without systematically causing additional costs for the network, especially for production that does not violate the design criteria of the distribution network. The assessment that the ‘value’ DER represents for the network is based



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on the comparison of islanded and interconnected situations. Fair comparison of solutions supposes similar performance in terms of actual reliability of supply and comparable technical and economic contexts. For example, an energy balance between generation and consumption set up on an annual basis has no meaning, when considering the operation of the electrical power system. Determining the advantages or disadvantages of DER requires the application of specific methodologies for the assessment of costs and benefits of various options under consideration. These cost–benefit studies should integrate all positive and negative consequences, in particular those related to the distribution networks. Making the approach more relevant requires taking into account the increasing penetration rates of DER. This helps distinguish local issues typically related to the distribution network which appear first, then systemic issues that concern the system as a whole. This leads to investigations about power system control in normal as well as in abnormal situations. This includes the impact of the extremely high penetration proportion of DER on the behaviour of the system under emergency conditions that require significant technical upgrades.

4.2.2 The value for the system Three main issues must be addressed: how to get DER into the wholesale energy market, how to build upgraded use of system charge schemes and rules for transmission and distribution companies, and finally how to determine support and incentive programmes, if they are deemed useful for society or absolutely necessary to initiate a promising technology. The participation of DER in the wholesale market means taking part in the primary markets, spot market as well as ancillary services market, but also to secondary markets, forward markets as well as to various hedging instruments. Due to the small size of DER units, the accession to these markets requires new solutions, including aggregation, to allow them to reach the required scale. The additional value of DER is essentially related to its position in the system.5 Time interval metering of load and generation, associated with appropriate treatment (‘profiling’ individual contribution or via ex post detailed analyses) would allow the determination of the footprint of the local generation or local consumption on the network. Similar charging solutions already exist for transmission costs, the compensation of losses and for congestion management, such as the ‘competitive locational price’. Another example is the ‘TRIAD’ concept as applied by NGET in the UK.



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4.2.3 Market regulation The profitable integration of DER remains questionable for the smallest ones. Indeed economies of scale, here expressed in terms of mass production, do not seem sufficient for the time being to lead to competitive generation costs compared to traditional generating units. Presently, the price of electricity for low voltage customers includes two main components: the energy price and ‘use of network’ charges. These latter are obviously maximum at low voltage, as all layers of the network are playing a role. If DER is operating at the right moment, that is to say during peak consumption in its neighbourhood, it represents a significant value for the network. New pricing methodologies mentioned above are able to remunerate local generation in a network that is dominated by the load and vice versa.5,6 The sustainable economy of DER is closely linked to the regulatory framework. Innovative regulatory environments may limit in the long term the cost of distribution networks. Distribution of electrical energy is expensive. A minimum density of customer is required to justify the development of a network. However, as soon as a client is connected to a network it has, as a client, additional benefits as a producer as well as a consumer. The price of the network, paid through ‘use of system charges’ mechanisms is certainly high, but still generally highly competitive when compared to islanded operation. The next section is an attempt to evaluate this additional value.

4.3

Conditions for profitable decentralized generation

Sustainable development of DG, combined heat and power units in the short term and renewable energy units in the longer term means the adequate optimization of the different components of the installation, but also of the interaction with the external system. Indeed the present chapter shows that islanding operation cannot be profitable except in regions of very low density of customers. Cogeneration of heat and power is most often the best approach for increasing the overall efficiency of a plant and for reducing the consumption of primary energy. But this is seldom true as far as the profitability of the installation is concerred. This is due in large part to the capital intensive character of electricity generation. Furthermore, fairly long amortization periods are usually considered necessary in the electrical supply industry. For example, combined cycle plants based on combustion turbines, heat recovery steam generators and condensing steam turbines are amortized in 15 years, classical coal units are amortized in 20 years and this could be even longer for new nuclear power plants as these are now built for a 60-year operational



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lifetime. This has to be compared with other branches of the industry where profitability is expected in a fairly shorter period of about 3–5 years. Reducing generating costs means taking the right action on various parameters that must be optimized as follows: ∑ the initial investment must be kept as low as possible; ∑ the overall efficiency of the installation must be high enough; ∑ the efficiency of electricity generation is less important than the overall efficiency and the reduction of initial investment has to be prioritized; ∑ a good design based on heat demand is the main objective and the minimum demand for heat is particularly important; ∑ the installation must be viewed in connection with the electricity network and the electricity power system. For small or micro-units, the scale effect that led to multi MW power plants up to 1600 MW turbo-generators, becomes the mass production in fully automatic factories. The design of the unit must be such that overall efficiency is kept as high as possible at an acceptable cost. As an example, Stirling conversion units that until recently were characterized by fairly low efficiencies can now be designed with an overall efficiency of about 40%7. However, such high figures can only be obtained at very high costs that are only compatible with the space industry. Lower efficiency machines using equivalent technical solutions, like free-piston and oscillating permanent magnet generator with efficiencies about 20% can be used for making cogeneration boilers. The additional cost required to turn a boiler into a micro-CHP must be kept as low as possible and the marginal cost of each additional efficiency point for electricity generation must be carefully checked. Present condensing boilers are characterized by a nominal efficiency of about 108% (base: low heating value of the fuel) and by a seasonal efficiency of about 90%. The part of the investment within the cost of heat is extremely low (for large industrial boilers it is of the order of 1%). It is of utmost importance to keep the overall efficiency as high as possible. In fact due to the increased complexity of the conversion process, including the increased weight of the boiler, it is generally not possible to maintain the efficiency figures of conventional boilers. It is nevertheless possible today to reach a nominal efficiency slightly above 100% with Stirling boilers. It is here important to note the advantage of the Stirling conversion: its ability to use various primary fuels such as natural gas, fuel-oil and even wood pellets. The degradation of the overall efficiency with micro-turbines can be significant, mainly for smaller machines. This is due to the considerable mechanical difficulty of reducing the clearance between fixed and rotating parts of the machines. This is definitely a disadvantage for the smaller machines. The aforementioned characteristics are to be tuned at the design



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stage of the generating unit with the best possible balance between reliability, efficiency and cost. The next step concerns the optimization of the installation. The case of industrial sites, such as the chemical industry, will be considered as an example. Such installations are generally supposed to feed heat at different pressures. These installations are most often designed as follows. The cogeneration unit is designed based on the minimum heat requirement, corresponding to summer conditions. The additional supply of heat is generated by classical boilers. When natural gas is used as primary energy, the initial conversion takes place in a combustion unit coupled to a synchronous machine which generates electricity. The heat content of exhaust gases is converted into steam in a heat recovery steam generator which is often equipped with additional burners that are sometimes able to be switched to autonomous operation in case of a trip of the combustion turbine (this requires a fresh air supply with auxiliary fans). When heat must be supplied to different processes under different pressure conditions, steam turbines are often used, backpressure units or condensing units with extraction of steam located at different stages of the steam expansion. These steam turbines are also coupled to a synchronous, sometimes asynchronous generator, supplying electricity to the industrial steam network. To keep the reliability of the installation at an acceptable level, but at as low investment cost as possible, pressure reducers are installed in parallel and are operated in case of steam turbine trips. Relief valves are also used at different pressure levels in order to keep the required minimum flow in the plant in case of process trip for making the operation of pressure reducers stable. Usually cogeneration plants are designed to operate at full load for about 8760 hours per year, excluding maintenance period. For micro cogeneration, which can be viewed as the last cogeneration segment of customers that are not yet equipped, things are a little bit more complicated because the equivalent full load duration is most often not high enough (about 3500 hours of full load equivalent period for micro-CHP in the UK). Figure 4.1 gives the evolution of the mean cost of electricity as a function of the full load duration, from 1000 to 8760 hours per year. The installation is supposed to operate for 15 years with maintenance costs corresponding to 5% per year (this is practically equivalent to three majors overhauls, each of them corresponding to one-third of the initial cost, which is usually the case for internal combustion machines). Natural gas price is 750/MWh, electrical efficiency 35%, total efficiency 85%, competing boiler yearly efficiency 90%, cogeneration investment 72000/kW, and the selected discount rate is 8%. For domestic customers, an optimized design, based on the minimum demand of heat, would lead to a fairly limited installed power for heating the daily consumption of hot water. For example, for a family of two adults



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Small and micro combined heat and power (CHP) systems 7400 CHP generation cost (EUR/MWh)

Investment 7350

Fuel

7300 7250 7200 7150 7100 750 70 1000

2000

3000 4000 5000 6000 7000 Full load working hours per year (hours)

8000

8760

4.1 Generation cost versus full load working hours.

and two children, 1.5 kWh output for heat is sufficient. This is significantly lower than the 6 kWh of heat output of future Stirling boilers. This figure is most often the result of another approach which is based on the electrical side of the installation. Indeed the objective is to feed the home in electricity for compensating approximately the yearly consumption (mean value estimated at about 3500 kWh per year in England), hence the power of the generator of about 1 kWe. This power is lower than the equivalent peak consumption of a domestic customer; consequently, at first sight, it cannot be harmful for the network. This means that the design of the network is not seriously compromised, it would seem.

4.4

Evaluating the ‘full value’ of being network connected

What is the ‘full value’ of being interconnected to the network? A methodological approach has been set up to answer this question in EUDEEP Deliverable D11.8 This value is in relation to the large flexibility for balancing load and generation when a site is connected to the network. Indeed the short-term power peak can reach the maximum subscribed power of the site (e.g., up to about 15–20 kW for domestic clients) whereas the peak consumption for the network, considering diversity, is only about 1.5 kW (at system level) or 3 kW (at distribution transformer level) for mean European domestic customers (assuming that electricity is not used for house heating). The basic assumption is to evaluate the performance of the installation presenting an equivalent reliability of supply. The reference is given by the network performance (valid for the region where the considered site is located). Then a simplified model of the site is set up, with the site operating as an island. The size of the machine is selected for being able to feed the



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load. The demand is supposed to be given by interval metering. The ‘time window’ could be a quarter of an hour, half an hour, etc. The number of machines operating in parallel is selected to achieve the required performance in terms of reliability of supply. The full operational details are not necessarily taken into account as orders of magnitude only are considered. The present worth evaluation for the whole expected operational life of the installation is calculating taking into account different assumptions (investment, operational and maintenance costs, discount rate, utilization of the plant, etc.). This permits the determination of the expected mean costs of electricity.9 The comparison of this cost with the ‘real’ price of electricity, including network costs, gives an evaluation of the ‘true value’ of being network connected. Given the experience of different experiments that have been implemented within the EU-DEEP project, it is not necessarily straightforward to develop this type of ‘equivalent’ installation. Some adjustments must be made to make this comparison possible. This is particularly the case for domestic installations. This is essentially due to the lack of diversity when a single installation is considered, the difference between load and generation functions (load and generation curves) and finally due to the the large instantaneous variations that usually characterize load behaviour. Technical performance during operation is evaluated by determining the dynamic behaviour of the site disconnected from the network, based on measurements made in the field using sufficiently high sample rates (e.g., up to 50 samples per second). The methodology has been used for determining an order of magnitude of the ‘full value’ of being connected to the distribution system. It corresponds to the difference between the total cost of electricity supplied by the system and the mean generating cost of electricity produced locally, in islanding. The determination has been made assuming that the islanded installation presents the same performance as the distribution network in terms of overall reliability of supply. In the presented examples the mean system reliability has been set at about 99.99 to 99.995, which corresponds to the performance of a network presenting ‘good reliability’. This methodology has been used to develop five cases based on the tests implemented within the EU-DEEP project. Two are based on ‘market segments’ experiments implemented in Grenoble (internal combustion cogeneration plant with islanded capabilities – two variants, one with three or four generators and another one with a combination of UPS, CHP and one or two backup generators) and in Athens (a trigeneration plant based on a micro-turbine with storage and two variants with respectively 100% and 50% loading factor). The three additional cases have been selected to complete the picture: one ‘big’ site characterized by a high diversity of demand (Kapodistrian University of Athens) and two cases inspired from the domestic customer installations in the Berlin test where 10 micro-CHP systems have



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been installed and remotely operated for one year. However, the specific issues of islanded operation for such sites require characteristics that are not found in the Berlin site tests. Therefore two fictitious cases have been built. The first one considers a CHP installation, based on an efficient fuel cell able to work marginally in open cycle. The second one considers a combination of photovoltaic (PV) and cogeneration with different PV investments. This gives a large diversity of situations allowing for extrapolating to futuristic plants. The results are summarized in Figs 4.2 and 4.3. Figure 4.2 considers the first sites corresponding to generation of some hundreds of kW up to MW. Costs figures are given assuming two values corresponding to two different levels of reliability of supply. For each case the upper value (square) corresponds to the installation fulfilling the reliability performance; the lower value (diamond) corresponds to the second best solution in terms of reliability. This permits a range of costs to be set up for which the performances are ‘acceptable’. In general the second site corresponds to the same installation where one generator has been removed. This is the case for the Grenoble SM (synchronous machine), Grenoble UPS with one or two backup synchronous generators and for the NTUA inspired tests. For Kapodistrian University (NKUA) two different installations have been considered; the first one is characterized by 21 units (defined by the strict application of the reliability

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Integration of small & micro combined heat & power systems sofc chp sofc Elec.

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4.3 Generation costs evaluated for small customer islanded sites.

calculation) and the second one by 12 units (this is more in line with practical approaches). The generation costs are in that case determined for CHP as well as for electricity generation. Figure 4.3 summarizes the results for the domestic customer installations. The solid oxide fuel cell (SOFC) case includes the cost reductions that are expected for the near future, whereas the renewable energy source and combined heat and power solution (RES-CHP) presents results assuming the extension of an already existing installation. Both these installations are marginally able to supply the electrical energy with the reliability objectives set up initially. These figures must be compared with the cost of electricity delivered by the power system: for example, in the low voltage network, 7160–200/ MWh (taxes included), where ‘use of system’ charges represent about 45 to 50%. This indicates an advantage when compared to islanded operation of the order of about 7200/MWh minimum, except for the case of NTUA characterized by 100% utilization, which is not fully realistic when assuming islanded operation.

4.5

Recommendations to distribution system operators (DSO) and regulators

Autonomous operation of small size sites is generally not competitive when compared to the network connection. Hence, in general, DER will be connected to the distribution network. The rational integration in the system supposes fully open collaboration between DSO and regulatory bodies. Technical analyses have shown that efficient and sustainable solutions exist. They assume first that new designs have been defined, and second that adequate regulatory frameworks have been deployed. Both these aspects are summarized below as recommendations for DSO and regulators.



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4.5.1 New designs for distribution networks Context Increasing the proportion of DER in the distribution network can have significant impacts on the network infrastructure; the type and the size of the considered DG are of utmost importance. DER has the potential to deliver services to DSOs and transmission system operators (TSOs) via entities aggregating multiple small resources dispersed in the distribution network. It is expected that these opportunities will increase in the future when medium voltage (MV) and low voltage (LV) distribution networks lose their unconditional adequacy (the ‘fit and forget’ principle being no longer fulfilled). For the sake of clarity it is important to distinguish ‘thick’ from ‘thin’ distribution networks (respectively, operating HV-MV-LV or MV-LV grids only). In ‘thick’ distribution systems the range of services that can be delivered today or in the short term is broader. In ‘thin’ distribution systems, the range of services that can be delivered is limited to balancing services for TSOs. Future services that could be delivered by DER in MV and LV distribution networks are related to limited contribution to voltage control or reactive power compensation, and not to power flow management. For the more critical constraints, such as voltage control in ‘N-1’ situations, the corrective action corresponds rather to generation curtailment than to active management of sources. Active management is an appealing solution but it supposes the existence of control margins, otherwise it means limitation to DER output. Design criteria for distribution networks might be upgraded if limitations to DER output cannot be accepted. Increasing the ‘DER hosting capacity’ of the network, whether or not active management is used, requires the setting up of new design criteria for developing or exploiting distribution networks. This is necessary because margins are needed if reduction in power injection is to be avoided as much as possible. This means that ‘exogenous’ objectives are necessary for fixing limits: limitation of peak generation for each customer in connection with peak load (diversity included), objective in terms of penetration for DER, limits set to generation control, etc. The impact of an increased number of DER on the cost of the system depends on the types of DER considered and on the network where they are connected. The additional investment costs due to DER integration depend on energy policy choices, including the associated operational rules that are imposed, including the possibility to control power injection in case of contingencies. ‘Exogenous’ objectives, in close connection with the more general objectives of energy policies, are necessary for fixing these targets: limitation of DER generation power per connection, objective in terms of penetration for DER, limits set for generation control in normal and abnormal conditions such as fault



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handling and DER’s ‘fault-ride-through’ capability, etc. This would lead to extensions to grid codes to comprise equipment with lower power ratings than today. New design New design criteria for distribution networks can easily be developed as soon as clear objectives are defined. These objectives should be defined outside of the electrical supply industry, but with its participation. The exact sharing between design upgrades and active management is an integral part of the process. The key aspects here are the existing voltage control margins, homogeneity of the feeders resulting in similar voltage behaviour, DER characteristics, its size, its design and the relationship between load and local generation (i.e. coincidence between the peak generation and peak demand or vice versa). As a result, when determining the ‘hosting capacity’ (the proportion of DER that can be operated in the system without inconvenience), it is important to use the network design criteria as the reference, but also to consider the specificities of the considered DER in connection with the local conditions prevailing in the network. Distribution networks developed using the traditional ‘fit-and-forget’ principle often exhibit operational margins that allow for accepting a significant proportion of DER, particularly in urban and semi-urban networks. The extension of the ‘fit-and-forget’ principle should be based on the ‘reinterpretation’ of network design criteria. As voltage drops along feeders, the voltage set point is traditionally adjusted near to the upper limit at the feeding HV-MV substation, allowing at the same time system losses to be reduced. In the presence of local generation and in the case of non-homogeneous location of load and generation along feeders, voltage profiles can increase and decrease along the various feeders depending on the coincidence between load and generation on them. The reference voltage must therefore be adjusted downwards which allows the ‘fit and forget’ approach to be preserved. This supposes, however, sufficient regularity in terms of behaviour of the load and generation customers. Existing margins can be expanded using active voltage management when a certain degree of homogeneity exists between feeders, or even more when considering active management of individual DER sources. When the voltage margins following the ‘fit-and-forget’ principle are insufficient, one needs to dynamically change the voltage control settings in the HV-MV substation. However, this supposes that the load shapes of the different feeders exhibit similar voltage characteristics as significant voltage lack of homogeneity can push the voltage outside of the acceptable range. Due to this lack of homogeneity, or if the DER installations lay outside of the network design rules, i.e. the size of the DER installations is not at all in line with the mean



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demand of the clients in the neighbourhood, there is a risk of technical issues such as over-voltages or overload of network elements. This implies that either penetration ratios should be reduced in these types of networks, or active management of sources is needed, including occasional generation curtailment. In fact, an optimal design for distribution could be characterized by active voltage management during normal conditions, and active DER management for ‘N-1’ contingency situations only. Technical objections to DER in distribution are often true in principle, but do not often materialize when real contexts and realistic parameters are considered. Protection schemes as used in the distribution systems are not adequate in the presence of DER. This is one of the critical questions with the protection of micro grids. However, as long as distribution networks are involved, due to the physical properties of the power system, the operation of protection schemes is dominated by the short-circuit power supplied by the HV network. Furthermore, small DER units installed in low voltage generally do not supply short-circuit power, hence they cannot disturb the operation of protection. For radial networks (MV and LV part of distribution), the EU-DEEP project proposed new design rules that take care of one of the most critical issues: voltage control in rural networks. Indeed, distribution networks experience voltage drops/rises on the different circuits as a function of their respective loading. Control or compensating equipment is therefore provided to offset the resultant variation in voltage. The basic requirements leading to a ‘flexible’ system assume full ‘non-homogeneity’ for local generation and consumption. The main consequences of such distribution network design rules are: ∑

HV–MV distribution substations become able to operate at nominal power to or from the distribution network. ∑ Full ‘non-homogeneity’ between feeders can be accepted without issues in terms of voltage control. ∑ HV–MV substations do operate at nominal medium voltage under all circumstances, which is slightly lower than in the present situation. ∑ Distribution transformers are set at their nominal transformer ratio, at least for MV feeders, allowing changes of their operating point from consumption to generation, and vice versa. ∑ In low load density regions, where distribution networks can be near to voltage drop limits, reinforcement of the system may be needed using, for example, larger cross-section lines or cables. For massive DER deployment in distribution networks or for the connection of quite large lumped DER in the network, several technical issues must be faced:



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∑

Rural networks might be limited by voltage control issues in the presence of DER. ∑ Urban networks might be limited by thermal capacity as well as fault level issues, whenever rotating machines are connected. ∑ In general, large amounts of DER connected to the network will lead to more complex power flows in the distribution network.

4.5.2 New regulatory frameworks Net tariffs can be used provisionally at small scale by default of adequate metering systems. Some regulatory arrangements implement net metering, hence the ability to reduce the ‘use of system’ charges when installing a DER. This can represent a significant part of the revenues needed to cover the costs of the installation. This becomes an issue for DSO when faced with a significant penetration of such DER. Present ‘use of system’ tariffs are generally built on two terms: fixed charges related to the subscribed peak demand and variable energy-based charges proportional to the consumption. Owing to the lack of metering infrastructure, the above terms are estimated on a specified time window (typically one year), the sites where generation and consumption remain balanced throughout this period do not pay for the ‘use of system’. This can deeply affect the financial status of DSO. Given the fact that hosting of DER units can sometimes lead to increased costs for the DSO, they should not be ‘punished’ for hosting more DERs. Distribution network charges schemes must be urgently revisited: since net pricing is not cost reflective, DSO’s business could be at risk under large deployment of DER. Therefore, a sustainable framework has been proposed for allocating distribution network investment costs to customers and distributed generation. These charges must be transparent and nondiscriminatory, meaning that ideally each market participant (load/generation) must be charged on the basis of a good estimation of the real costs that they impose on the distribution network. A new efficient ‘use of system’ charges method, based on a ‘marginal’ approach has been developed allowing for unveiling the footprint of load or generation on the distribution network infrastructure. The impact of load and generation must be determined separately as they play symmetrical but complementary roles. Ideally they should be determined for all upstream elements in the network. But such an implementation requires large-scale deployment of smart metering with automatic meter reading and heavy ex post data treatment. New EU targets are pushing towards more renewable energy and energy efficient distributed CHP units. With demand flexibility, these trends will change the way electricity is generated, transported and used. The integration of DER poses a valid challenge to both industry and regulators. Estimation



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of their technical and cost impacts remains an issue. So far, most regulators have remained fairly passive and short-sighted, whereas it has been shown that engineering models can adequately estimate both the technical and some of the economic aspects of this integration. A crucial and still open question is, then, to what extent and for what purpose can normative engineering models provide relevant information for economic network regulation? System operators have the responsibility to develop and to maintain the transmission and distributions networks following exogenously defined targets. New conditions mean new targets in relation to updated energy policy objectives. This is a process that must be catalyzed by regulatory bodies. The most suitable regulatory environment must be implemented with longterm objectives for a smooth, sustainable development of the distribution networks. Long-term planning of the distribution system is an essential part of the activities of a distribution network operator. Normative models are an attempt to model the planning problem without duplicating the industry planning process. Attractive from a regulatory point of view, they help the regulator overcome the difficulties resulting from the lack of information. These norm models are just special cases of engineering cost functions leading to a high-level representation of the considered network. However, they can include all distribution network cost drivers in order to enable finding the right balance between these cost drivers and the investment required in the network. By doing so, the connection and reinforcement costs, as well as the benefits obtained with DER, could be quantified from a system point of view. Efficient ‘use of system’ tariffs for distribution should consider: ∑ ∑ ∑ ∑ ∑ ∑

Bills of customer based on kW and kWh components of the supply. A clear separation of ‘use of system’ tariffs from incentives is mandatory. For sites equipped with DER, load and generation must be treated independently. This allows for the deployment of ‘use of system’ tariffs that are able to reveal the value of DER (or loads in a part of the network dominated by generation) as ‘network replacement’. But for being applicable down to low voltage networks, the method requires large-scale metering systems as well as ex post data management. This asks for simplification. Different stages of simplification are possible. However, caution must be exercised to keep the ‘essence’ of the tariff during this simplification process. Furthermore, equality of treatment principles must also be integrated to avoid penalizing customers due to their location in the network, like the remote end of feeder; and ‘use of system’ tariffs must be made stable from one year to the next.



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Acknowledgement

This work has been partly funded by the European Commission as part of EU-DEEP, a European Project supported by the Sixth Framework Programme for Research and Technological Development.

4.7

References

[1] Strbac, G. and Jenkins, N. (2002) ‘Network Security of the Future UK Electricity System’, Report to Performance and Innovation Unit (PIU). [2] Lambert, J.D. (2001) Creating Competitive Power Markets: The PJM Model, PennWell Corporation, Tulsa, OK. [3] Ofgem/DTI (2004) Planning and Operating standards under BETTA, An Ofgem/ DTI consultation document, Vols 1 and 2, July. [4] EU-DEEP Project: www.eu-deep.com [5] Deuse, J., Grenard, S., Benintendi, D., Agrell, P.J. and Bogetoft, P. (2007) ‘Use of system charges methodology and norm models for distribution system including DER’, CIRED 19th Int. Conf. on Electricity Distribution, Vienna. [6] Deuse, J. and Purchala, K. (2009) ‘DER profitability, distribution network development and regulation’, CIRED 20th Int. Conf. on Electricity Distribution, Prague. [7] Sunpower (2010) High performance free-piston Stirling engines. Available at: http:// www.sunpower.com/lib/sitefiles/pdf/productlit/Engine%20Brochure.pdf [8] EU-DEEP Deliverable D11, ‘Determination of the value of being network connected application to 5 cases’, downloadable from: www.eu-deep.com/ [9] Willis, H.L. and Scott W.G. (2000) Distributed Power Generation: planning and evaluation, Marcel Dekker, New York.



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5

Biomass fuels for small and micro combined heat and power (CHP) systems: resources, conversion and applications

H. L i u, University of Nottingham, UK

Abstract: Section 5.1 outlines the significance of biomass as a fuel in the world energy supply scene and defines biomass and bioenergy categories. This section also notes the scope and extent of biomass as a renewable energy resource, how it fits in the CO2 cycle and the different types of biomass available. In Section 5.2 the characterisation methods of solid biomass fuels are explained. Section 5.3 goes into detail on the various biomass energy conversion technologies available, of which there are many. Finally, in Section 5.4, having laid the ground concerning the biomass options available for use as an energy resource, current developments in the small- and micro-scale CHP systems are explored and some commercial applications cited. Key words: biomass combined heat and power, biomass CHP, biomass conversion technologies, biomass characterisation, biomass fuels.

5.1

Introduction

Because it is expected that conventional fossil fuels such as oil and natural gas will eventually run out, alternatives that provide the usefulness, flexibility and economy of these fossil fuels have been sought for many years. In addition, many scientists, environmentalists, governments and other non-government organisations believe that the accelerated utilisation of fossil fuels over the past decades is the main cause of ‘global warming’ and this forces us to look for cheap and environmentally friendly alternatives to fossil fuels more urgently than ever before (IEA WEO 2009). One of these alternatives is as close as the kitchen waste or the plants outside – ‘biomass’: a source of energy that is both as old as humankind and as new as the morning paper. Biomass resources are increasingly used as alternative fuels for transportation, space heating and power generation because of the persistent high energy prices and pressures on carbon dioxide (CO2) mitigation. Biomass is a very broad term which is used to describe material of recent biological origin that can be used either as a source of energy or for its chemical components. As such, biomass includes trees, crops and other plants, as well as agricultural and forest residues. Biomass also includes many materials that 88 © Woodhead Publishing Limited, 2011


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are considered as waste by society such as food and drink manufacturing effluents, sludges, manures, industrial (organic) by-products and the organic fraction of household waste. In many ways biomass can be considered as a form of stored solar energy. The energy of the sun is ‘captured’ through the process of photosynthesis in growing plants (Klass 2004). There are a number of common terms related to ‘biomass’, some of which have been misused or misunderstood on occasions and are worth further clarifications here (Klass 2004): ∑ ‘Bioenergy’: the general term for energy derived from biomass; ∑ ‘Biofuel’: a solid, gaseous, or liquid fuel produced from biomass; ∑ ‘Biogas’: a medium-energy-content gaseous fuel, generally containing 40–80 vol% methane, produced from biomass by anaerobic digestion; ∑ ‘Landfill gas’: a medium-energy-content fuel gas, rich in methane and carbon dioxide produced by landfills that contain municipal solid wastes and other waste biomass; ∑ ‘Energy crops’: plants grown specifically for energy use.

5.1.1 Biomass – a renewable energy resource Both burning biomass and burning fossil fuels release carbon dioxide (CO2) to the atmosphere. However, there is a vital difference between the two cases: burning fossil fuels releases CO2 that has been locked up for millions of years in the ground, affecting the natural CO2 cycle and resulting in an increase in the CO2 concentration in the atmosphere. By contrast, burning biomass simply returns to the atmosphere the CO2 that was absorbed as the plants grew over a relatively short period of time (a few years to ca. a decade). The same amount of CO2 which was absorbed from the air via the photosynthesis process while the biomass plant was growing is released back into the air when biomass is burned and there is no net release of CO2 to the atmosphere, i.e. it is CO2-neutral, if the cycle of growth and harvest is sustained. Therefore, biomass can be considered as a renewable energy resource (Fig. 5.1). Some net release of CO2 would take place if the production (planting, harvesting, processing) or transportation of the biomass fuel involved the use of fossil fuels. This part of CO2 can be significant for some biofuels which have low energy ratios (Hoefnagels et al. 2010, Cherubini 2010). There are many types of biomass and they can be grouped by different methods in different countries. The IEA Bioenergy Education Website on Biomass and Bioenergy (IEA Bioenergy 2010a) groups biomass into categories of woody biomass, non-woody biomass and organic wastes. Woody biomass mainly includes: ∑

forest residues, e.g. thinning, pruning or any other leftover plant material after cutting;



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Atmospheric CO2, water and sunlight

Cycle time: Ca. 1–10 years Carbon dioxides released back to the atmosphere

Converted into new plant material via photosynthesis

Harvested and used as a fuel

5.1 Biomass is a renewable energy resource.

∑ ∑

fuel wood, e.g. logs or any other form to be used in small stoves; wood waste from wood-processing industry, e.g. bark, sawdust, shavings and offcuts; ∑ short rotation forestry, e.g. willow, poplar and eucalyptus; ∑ woodlands/woody urban biomass, e.g. tree trimmings, the green and woody portion of municipal solid waste. Non-woody biomass mainly includes: ∑

agricultural crops, e.g. various annual and perennial non-woody energy crops such as Miscanthus, Switchgrass, traditional agricultural crops such as maize/corn, rapeseed, and sunflowers which can be used as animal/ human food and liquid biofuels production feedstock; ∑ crop residues, e.g. rice or coconuts husks, maize cobs and cereal straw; ∑ processing residues, e.g. bagasse from sugar cane processing and olive marc from olive oil extraction. Organic waste biomass mainly includes: ∑ ∑

animal wastes, e.g. manure from pigs, chickens and cattle; sewage sludge, domestic and municipal sewage from mainly human waste;



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organic wastes produced by households and institutional buildings such as paper, food, leather and vegetable wastes.

5.1.2 Biomass potential to the world energy supply At the present time, the world is heavily reliant on fossil fuels for energy supply – over 80% of the current annual world energy consumption (~500 Exajoules) comes from coal, petroleum oil and natural gas (EIA IEO 2010). However, the reserves of fossil fuels are finite and subject to depletion as they are consumed – millions of years are required to form fossil fuels in the earth. Currently, biomass is the fourth largest energy resources after coal, oil and natural gas – the current rate of the world biomass energy consumption is estimated to be in the region of 50 EJ/y which is about 10% of the world total primary energy consumption (IEA Bioenergy 2009). Biomass is the only natural, renewable carbon resource known that is large enough to be used as a substitute for fossil fuels. Some projections have shown that the world’s bioenergy potential seems to be large enough to meet global energy demand in 2050 (Ladanai and Vinterbäck 2009). The annual global primary production of biomass is equivalent to the 4,500 EJ of solar energy captured each year (Ladanai and Vinterbäck 2009) and the rate of energy storage by land biomass is in the order of 3000 EJ/y (Larkin et al. 2004). However, only a small portion of the global energy stored by biomass can be considered as sustainable biomass resources, which is generally believed to be in the region of 250 EJ/y, being equivalent to about 50% of the current global energy consumption (Ladanai and Vinterbäck 2009, European Biomass Industry Association 2010). The future potential of the global biomass energy depends on many factors, such as land availability and productivity, and the advancement of biomass conversion technologies (Fischer and Schrattenholzer 2001, Hoogwijk et al. 2003, Demirbas et al. 2009, Ladanai and Vinterbäck 2009). But it is reasonable to assume that biomass could sustainably contribute between a quarter and a third of the future global energy mix (IEA Bioenergy 2009).

5.2

Characterisation of solid biomass fuels

Proximate analysis, ultimate analysis and calorific value are commonly used to characterise solid biomass fuels. The proximate analysis serves as a simple means for determining the behaviour of a solid biomass fuel when it is heated. It determines the contents of moisture, volatile matter, ash and fixed carbon of the fuel. On the other hand, the main purpose of an ultimate analysis is to determine the elemental composition of the solid fuel



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substance. The calorific value of a fuel is a direct measure of the chemical energy stored in the fuel. Due to the inhomogeneous nature of solid biomass fuels, it is notoriously difficult to prepare small quantities (in the order of grams) of representative samples for biomass characterisation tests. Therefore, strict sampling and preparation procedures specified by the British/European standard BS EN 14778-1:2005 have to be followed by any proximate, ultimate and calorific value tests of solid biomass fuels described below.

5.2.1 Proximate analysis Since an appreciable amount of water vapour is released when a solid biomass fuel is heated to above the boiling temperature of water, the first parameter of a proximate analysis is the moisture content of the fuel. The moisture content is determined by drying solid biomass samples at 105 °C in air atmosphere until constant mass is achieved and percentage moisture calculated from the loss in mass of the sample. Standard procedures for the determination of moisture content of solid biomass fuels are specified by three British/European standards BS EN 14774-1:2009, BS EN 14774-2:2009 and BS EN 14774-3:2009. Another major loss occurs when a solid biomass fuel is heated in a covered crucible or in other apparatus which prevents the oxidation of the carbon residue. This loss is referred to as the volatile matter and constitutes the second parameter of the proximate analysis. Volatile matter is determined with the sample being heated out of contact with ambient air at 900 °C for 7 minutes. Standard procedures for the determination of volatile matter of solid biomass fuels are specified by the British/European standard BS EN 15148:2009. If the remaining residue is further combusted, the residue left after the combustion is called ash, and the weight loss on combustion is referred to as ‘fixed carbon’. Fixed carbon and ash contents constitute the third and fourth parameters of the proximate analysis. This part of proximate analysis, i.e. the combustion of the residue, is carried out in a furnace at 550 °C and the standard procedures are specified by the British/European standard BS EN 14775:2009. It is not always practical to conduct the above various determinations stepwise. Therefore, one set of samples could be used for the moisture content determination, and another set of samples for the combined moisture and volatile matter loss, and still another set of samples for ash determination.

5.2.2 Ultimate analysis The main purpose of ultimate analysis is to determine the elemental composition of a solid biomass fuel. The main elements of solid biomass fuels include



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carbon (C), hydrogen (H), nitrogen (N), sulphur (S) and oxygen (O) but for some solid biomass fuels chlorine (Cl) and other elements may also be of interest. Nowadays, the ultimate analyses of sold biomass fuels are usually carried out with fully automated instruments. The instrumental method for the determination of total carbon, hydrogen and nitrogen contents in solid biomass fuels is described by the British/European standard CEN/TS 15104:2005, whereas the methods for the determination of the total sulphur and total chlorine content in solid biomass fuels are specified by the British/European standard CEN/TS 15289:2006. Sometimes, the determinations of the major elements (Al, Ca, Fe, Mg, P, K, Si, Na and Ti) and the minor elements (As, Cd, Co, Cr, Cu etc.) of solid biomass fuels are also necessary and required. The British/European standards CEN/TS 15290:2006 and CEN/TS15297:2006 describe and specify the corresponding methods and procedures.

5.2.3 Calorific value The calorific value of a fuel is the number of heat units evolved when unit mass (or unit volume in the case of a gas) of a fuel is completely burned and the combustion products are cooled to 298 K. This definition of calorific value includes the provision that the products of combustion are cooled to 298 K which means the sensible heat and the latent heat of condensation of the water produced during combustion are included in the heat liberated. Therefore, the calorific value of the fuel is designated as ‘gross calorific value (GCV)’ or ‘high heating values (HHV)’. However, with many industrial applications, the latent heat of condensation is not given up and the total heat liberated per unit mass (or volume) of the fuel is less. The calorific value in the case where the water remains as vapour is designated as ‘net calorific value (NCV)’ or ‘low heating value (LHV)’. The gross calorific value of a solid biomass fuel is usually determined experimentally by a bomb calorimeter, whereas the net calorific value of the fuel is usually calculated from the gross calorific value and the ultimate analysis of the fuel. Specific experimental procedures and calculation formulae are detailed by the British/European standard BS EN 14918:2009. Many solid biomass fuels contain high moisture content which greatly affects the net calorific value as illustrated by Fig. 5.2 and Table 5.1 (Larkin et al. 2004).

5.2.4 Calculation of analyses to different bases The analytical data of solid biomass fuels may be reported on different bases including as analysed (air-dried, ad), as-received (ar), dry basis (db) and dry and ash-free (daf). Most analytical values on a particular basis may be converted to any other basis by multiplying it by the appropriate formula



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Small and micro combined heat and power (CHP) systems 20 NCV (MJ/kg, as received)

18 16 14 12 10 8 6 4 2 0 0

10

20 30 40 50 60 Moisture content (as received), %

70

80

5.2 Effect of moisture content on the net calorific value of a biomass fuel. Table 5.1 Average net calorific value of solid biomass fuels (Larkin et al. 2004) Fuel

Net calorific value

(GJ/tonne)

(GJ/m3)

Wood (green, 60% moisture) Wood (air-dried, 20% moisture) Wood (oven-dried, 0% moisture) Grass (fresh-cut) Straw (as harvested, baled) Domestic refuse (as collected) Coal (UK average)

6 15 18 4 15 9 28

7 9 9 3 1.5 1.5 50

given in Table 5.2, after insertion of the numerical values for the symbols. However, for some parameters (H, O and net calorific value) there is a direct involvement of the moisture content. Further details on the calculation of analyses to different bases are described by the British/International standard CEN/TS 15296:2006. Table 5.3 shows the proximate, ultimate analyses and gross calorific values of selected solid biomass fuels (Gaur and Reed 1995). The proximate and ultimate analyses of more solid biomass fuels can be found in many references such as Gaur and Reed (1995), Annalmalai and Puri (2007), and biomass databases such as Phyllis (2010).

5.3

Biomass conversion technologies

Most biomass materials are initially solid, bulky and expensive to transport over appreciable distances. They often contain high moisture content and decompose rather quickly, so few of them are good long-term energy stores. If



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95

Table 5.2 Formulae for calculation of results to different bases* Given

Wanted As analysed (air dried, ad)

As received (ar)

Dry (d)

Dry, ash, free (daf)

As analysed (air dried, ad)

1

100 – Mar 100 – Mad

100 100 – Mad

100 100 – (Mad + Aad )

As received (ar)

100 – Mad 100 – Mar

1

100 100 – Mar

100 – (Mad + Aad ) 100

Dry (d)

100 – Mad 100

100 – Mar 100

1

100 100 – Ad

Dry, ash, free (daf)

100 – (Mad + Aad ) 100

100 – (Mar + Aar ) 100

100 – Aad 100

1

*M – moisture content (%), A – ash content (%) Table 5.3 Proximate, ultimate analyses and gross calorific values of selected solid biomass fuels (dry basis) (Gaur and Reed 1995) Name

Fixed Volatiles Ash C carbon (%) (%) (%) (%)

H (%)

O (%)

N S GCV (%) (%) (MJ/kg)

Wood Ponderosa pine 17.17

82.54

0.29 49.25

5.99 44.38 0.06 0.03 20.02

Energy crop poplar

16.35

82.32

1.33 48.45

5.85 43.89 0.47 0.01 19.38

Processed biomass Plywood 15.77

82.14

2.09 48.13

5.87 42.46 1.45 0.00 18.96

agricultural wheat straw

19.80

71.30

8.90 43.20

5.00 42.18 0.61 0.11 17.51

coal Pittsburgh seam 55.80

33.90

10.30 75.50

5.00

4.90 1.20 3.10 31.75

biomass fuels are to compete with our present fossil fuels, they must be able to meet the demand for appropriate forms of energy at competitive prices. The most important criteria for new forms of energy are their availability and transportability. The premium fossil fuels – oil and natural gas – are valued because their energy can be stored with little loss and made available where and when we need it. Biomass energy conversion technologies can be classified in terms of either the conversion process they use or their end product. The following biomass conversion processes will be briefly discussed: ∑

Thermochemical processes Combustion



to produce

heat



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96

∑ ∑


Gasification Pyrolysis Biological processes  Fermentation  Anaerobic digestion Chemical/Mechanical processes  

to produce to produce

fuel gas bio-oil or charcoal

to produce to produce to produce

bio-ethanol biogas bio-diesel

5.3.1 Combustion of solid biomass fuels Direct combustion is the most common way of converting biomass to energy – both heat and electricity – and worldwide it already provides over 90% of the energy generated from biomass (Van Loo and Koppejan 2007). Direct combustion of solid biomass fuels is well understood, relatively straightforward, commercially available, and can be regarded as a proven technology. Biomass combustion systems can be easily integrated with existing infrastructure. In theory, it is possible to burn any type of biomass but in practice combustion is feasible only for biomass with moisture content of lower than ca. 50% (Goyal et al. 2008). Combustion of a solid biomass fuel can be characterised by a three-stage process (Fig. 5.3). The first stage is drying, i.e. the evaporation of any water in the fuel. This stage does not produce energy but consumes energy. Then in the combustion process itself, there are two further stages: the volatile release (devolatisation) and combustion stage – the volatile matter is released as a mixture of vapours (CO, CO2, H2, H2O, CxHy, etc.) as the temperature of the fuel rises, the combustion of volatile matter produces the flame seen around the burning solid fuel; and the char combustion stage – the solid which remains consists of char together with any inert matter and the char (mainly carbon) burns to produce CO2, whilst the inert matter becomes clinker, slag or bottom ash. A feature of solid biomass fuels is that three-quarters or more of their energy is in the volatile matter (unlike coal, where the fraction is usually

H 2O

Volatiles burn in gas phase to form CO2, CO, H2O, etc.

CO Æ CO2 CO

O2 C Æ CO ASH

Drying

Devolatisation (Pyrolysis): volatiles evolved, char remains

Char combustion

5.3 Stages of solid biomass fuel combustion.



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97

less than half). The design of any biomass combustion facility should ensure that the volatile matter of the fuel is burnt to completion. The heterogeneous chemical reactions of biomass char with oxygen from air are also important – the char combustion stage is the slowest of the three stages described above. To achieve overall high combustion efficiency, a sufficient combustion time has to be provided for the char combustion stage. Most solid biomass materials can be burnt to produce heat for use in situ or at not too great a distance. However, simple physical processing, involving sorting, chipping, compressing, air-drying, etc., is usually necessary for most solid biomass materials to be used in efficient combustion processes. Some raw solid biomass materials require further pre-treatment before they can be used in conventional combustion plants. For example, household waste, as collected, is not an ideal fuel for combustion because of its variable contents, high moisture content and low calorific value. But it can be burned in specially designed MSW (municipal solid waste) combustion (incineration) plants or converted to RDF (refuse-derived fuel) or d-RDF (densified refuse-derived fuel) to be burned alone or co-fired with coal in conventional combustion plants (Larkin et al. 2004). Modern systems for burning solid biomass fuels are as varied as the solid biomass fuels themselves, ranging in size from small stoves through domestic

5.4 A 50 kW wood pellet boiler installed at the Department of Architecture and Built Environment, University of Nottingham, UK.



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98


5.5 An Arimax Bio Energy boiler burning woodchips for small district heating in Finland.

space and water heating systems to large boilers producing megawatts of heat and/or electricity (Figs 5.4 and 5.5). Van Loo and Koppejan (2007) provide a comprehensive review of biomass combustion basic principles and industrial applications and therefore it is an indispensible reference for biomass combustion researchers and practitioners. Biomass combustion produces a range of pollutants including carbon monoxide, nitrogen oxides, particulates, smoke, etc., and can have potential operational problems whether burning in dedicated combustion plants or co-firing with coal (Demirbas 2005, Van Loo and Koppejan 2007, Khan et al. 2009, H. Liu et al. 2010a). However, biomass combustion can be CO2neutral if the cycle of biomass growth and harvest is sustained.

5.3.2 Biomass gasification Thermochemical gasification is the conversion by partial oxidation at elevated temperature of a carbonaceous feedstock such as biomass into a gaseous energy carrier (Liu and Neubauer 2010). This gas contains carbon monoxide, carbon dioxide, hydrogen, methane, higher hydrocarbons such as ethane and ethene, water, nitrogen (if air is used as the oxidising agent) and various contaminants such as small char particles, ash, tars and oils. The partial oxidation can be carried out using air, oxygen, steam or a mixture of them. Air is a cheap and widely used gasification agent but air gasification of biomass produces a low calorific value gas (ca. 3–6 MJ/Nm3) which is suitable



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99

for boiler, engine and turbine operation but not for pipeline transportation due to its low energy density (Wang et al. 2008). Oxygen gasification of biomass produces a medium calorific value gas (ca. 10–15 MJ/m3) suitable for limited pipeline distribution and as synthesis gas for conversion, for example, to methanol and gasoline. Such a medium calorific value gas can also be produced by steam gasification. Gasification is not a new process and has been around for over a century (BEF 2010, Liu and Neubauer 2010). ‘Coal gas’, the product of coal gasification, was widely used in the UK and elsewhere for many decades. ‘Wood gas’, the product of wood gasification, was used for heating, lighting and even as vehicle fuel. Both ‘coal gas’ and ‘wood gas’ were gradually superseded by natural gas from around 1930. But during the Second World War, over a million biomass gasifiers were built for the civilian sector while the military used up all the gasoline. The oil crisis of the 1970s also sparked a renewed interest in biomass gasification systems all over the world (BEF 2010). There are many different designs of gasifiers (Basu 2010), but with the same set of main gasification reactions: those of hot steam and oxygen interacting with the solid fuel (Liu and Neubauer 2010). The gasification reactions can only proceed at elevated temperatures (a few hundred to over a thousand degrees Celsius) and pressures (from a little above atmospheric pressure to 30 times this). Similar to the combustion stages shown in Fig. 5.3, the gasification process begins with the drying of the solid fuel to evaporate moisture, followed by the release of the volatiles from the heated solid, leaving the char. Volatiles and char in turn undergo partial oxidation reactions with steam and oxygen, resulting in the combustible gas. Figure 5.6 compares the three thermochemical conversion processes of biomass: combustion, gasification and pyrolysis. Although biomass gasification has been practised for over 100 years, so far it has had a very limited commercial impact on the energy market due to competition from other fuel sources and other energy forms. The past decade has seen a major resurgence of interest in biomass gasification processes mostly due to environmental and political pressures required of CO2 mitigation Solid biomass feedstock Greater than stoichiometric air/O2

Limited air/O2

No air/O2

Combustion

Gasification

Pyrolysis

Heat + flue gas + ash

Gas + ash + tar

Gas + oil + char

5.6 Comparison of thermochemical conversion processes of biomass.



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100


measures. Very few biomass gasification processes have proved economically viable, although the technology has progressed steadily. However, there is sufficient expertise and knowledge now available to have a high level of confidence in modern gasification processes. Small gasification plants (70 °C

50–200 °C

Fuels

H2

H2, CO

H2

H2

Sulphur (as S, H2S)

< 0.1 ppm

< 1 ppm

< 50 ppm

?

CO

< 10–100 ppma

Fuel

< 0.5–1%

< 0.2%

CO2

Diluent

Diluent

Diluent

< 100–400 ppm or < 0.5–5%b

CH4

Diluent

Fuel/Diluentc Diluent

Diluent

NH3

Poison

< 0.5%

?

Fuel tolerance

PEFC

< 4%

Abbreviations: PTFE (polytetrafluoroethylene – better known as Teflon™), PFSA (perfluorosulfonic acid – for example Nafion™), YSZ (yttria-stabilised zirconia), LSM (lanthanum-strontium-managanate). a Standard Pt anode catalysts can only withstand CO concentrations up to 10 ppm, and PtRu alloys up to 30 ppm (Song, 2002). These limits can be extended by bleeding air into the anode and using alternative bi-layer catalysts (Uribe et al., 2004; Ball and Thompsett, 2002). b CO2 tolerance is highly dependent on the cell design. Strongly bonded nickel and silver electrodes with a circulating electrolyte can be tolerant, while platinum and carbon with an immobilised electrolyte are highly sensitive. c Internal reforming is possible with SOFC anodes, making desulphurised natural gas a viable fuel. The long lifetimes required for domestic CHP operation have not yet been demonstrated by these systems though.

graphite powders and resins are used, along with the fluorinated polymer electrolytes found in modern chlorine electrolysis cells. High purity hydrogen fuel is required to avoid performance degradation, as the electrocatalysts are easily poisoned by carbon monoxide and other impurities. Management of fuel impurities and hydration of the polymer electrolyte requires relatively complex and expensive engineering solutions, and current work is aimed at relaxing these strict requirements by increasing the operating temperature to over 100 °C (Zhang et al., 2006).



4/5/11 9:23:37 AM

Fuel cell systems for small and micro CHP applications

239

SOFCs instead use ceramics and specialist chromium alloys or steels that can withstand high temperatures. For micro-CHP applications there is a trend to move from the high temperature region (850–1000 °C) used in early large-scale systems, into the so-called intermediate temperature (IT) range of 500–750 °C (Brett et al., 2008). This allows a wider range of materials to be used, giving cheaper fabrication and improved resilience to cycling ceramic components between ambient and operating temperatures. Lower temperature operation also affords more rapid start-up and shut-down, reduced corrosion rate of metallic components, more robust construction through the use of compressive seals and metallic interconnects as well as the advantage of greatly simplified system requirements (Brett et al., 2008).

10.3

Fuel cell systems

10.3.1 Fuel cell stack Figure 10.3 shows a generic fuel cell system for CHP applications running on reformed hydrogen from natural gas. The major balance-of-plant (BoP) items are shown (i.e., the auxiliary components that enable the fuel cell to operate); however, there are many additional components required for

Fuel in Fuel processor, CO removal and H2S removal

Purge

Inverter DC/AC

DC power

Ejector

Air humidifier

HEX Tank

Compressor/ blower

230 VAC

Air in

Water reservoir

Exhaust

Fuel cell

Make-up water Pump

Heat load

Condenser

HEX

Exhaust

Reservoir

Pump

Pump

Pump Low temp radiator, space heat or HEX to tank

Water cycle

Fuel cycle

Thermal cycle

Air cycle

Electrical power

10.3 Schematic diagram of a stationary fuel cell CHP system.



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240


operation such as pressure valves, mass flow controllers, sensors, control systems, etc. that are not included. The key issues for each of the main components of the system are now described. The combination of individual fuel cells into an interconnected ‘stack’ represents the main and most expensive component of the entire system. The stack is composed of individual cells (anode, electrolyte and cathode) electrically interconnected using bipolar plates that also distribute reactant to the electrodes. PEFC stacks are usually interspersed with cooling plates that circulate demineralised water, while SOFC stacks rely on air for cooling.

10.3.2 Fuel processor Converting natural gas into an acceptably pure supply of hydrogen requires several processing stages, as outlined in Fig. 10.4. The required stages for each type of fuel cell stack are integrated into a single, compact fuel processing unit, along with the thermal management systems and a steam generator to supply water vapour to the reformer and shifter (Echigo et al., 2004; Yasuda et al., 2001). An SOFC fuel processor is typically composed of a desulphuriser and pre-reformer; whereas PEFCs require a larger reformer, and additional shift reactor and gas clean-up stage, all of which add to the cost and complexity, and erode the total system efficiency. The ability of SOFCs to operate at high efficiency on hydrocarbon fuels is a major advantage over low temperature fuel cells, particularly for micro-CHP applications. Natural gas (or other hydrocarbon fuels) can be converted to hydrogen via a range of processes, including: steam reforming, partial oxidation and autothermal reforming (Kolb, 2008). Steam reforming is generally the preferred method as it produces higher concentrations of hydrogen, and thus requires up to 30% less hydrocarbon fuel (Hubert et al., 2006). The hydrogen rich steam leaving the reformer will contain a proportion of CO and sulphurous compounds (usually converted to H2S in the reforming stage) from the fuel source and added odorants. Both of these molecules are poisonous to PEFCs, while SOFCs are able to use CO as a fuel but remain highly sensitive to many sulphur-containing molecules (Lohsoontorn et al., 2008a; 2008b). These must therefore be removed, usually by reacting with ZnO or adsorption using activated carbon. These units will need to be changed periodically, adding to the maintenance cost of the system. Other desulphurisation techniques exist, but most are not suitable for such smallscale applications (Kolb, 2008). For PEFCs, the level of CO entering the fuel cell needs to be reduced to the order of 5

>0.5

>1

>1

>1

>25

Electrical efficiency (LHV)

15–30%

20–40% 10–30%

30–35%

30–50%

8–15%

15–35%

Overall fuel utilization factor (LHV)

80–90%

80–90% 70–90%

75–85%

75–85%

70–80% 75–85%

Heat:electricity 1.7–4.5 ratio range

1.0–3.5

1.4–8

1.2–1.8

0.5–1.8

6–7

Lower temperature (°C)/(°F) and type

65–75 150–170 Cooling jackets

65–85 150–185 Cooling jackets

40–75 60–80 105–170 140–175 Gas Exhaust cooler

–

10–50 – 50–120 Condenser

Higher temperature (°C)/(°F) and type

480–730 250–500 200–300 >700 900–1350 480–930 390–570 >1300 Exhaust Exhaust Flue gas Reformer (if equipped)

700–1000 1300– 1800 Exhaust

~200 ~390 Flue gas

1.2–4.5

~260 ~500 Exhaust

but the more value the heat will have for driving a heat-activated device. In designing a CHP heat recovery system, the heat recovery loop can be a series circuit or two parallel (split-stream) circuits; if a series circuit is chosen, then it can either flow to the high-temperature (e.g. exhaust) component first or last. Since small CHP units on the market today are primarily designed for low temperature, heating season uses, most utilize a series circuitry which cools the high-temperature component first. The tradeoffs are summarized in Table 11.2.

11.2.2 Overview of cooling technologies and applications Low-grade heat is typically an inevitable byproduct of electricity production. Its capture and distribution are therefore relatively straightforward, requiring only heat exchangers and piping to capture and distribute this heat energy that would otherwise be dissipated to the environment. This straightforward configuration is known as cogeneration or CHP, and a schematic is shown in Fig. 11.1 with numerical values typical of a system based on a small internal combustion engine (ICE). On the other hand, using waste heat to cool a working fluid below ambient temperature requires additional equipment. Since three useful products are produced (electricity, usable heat, and space cooling or refrigeration), this



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266


Table 11.2 Heat recovery circuitry options and tradeoffs for small-scale ICE, PEMFC, SE and ORC CHP prime movers Series circuit

Parallel circuit

Order of recovery

High-temperature component first

Low-temperature component first

(Separate loops)

Effect on electrical efficiency

None (ICE/PEMFC) Lower h (SE/ORC)

None (ICE/PEMFC) None (ICE/PEMFC) Higher h (SE/ORC) Highest h (SE/ORC)

Effect on heat recovery efficiency

Higher hHR

Lower hHR

Lower hHR

Effect on heat recovery temperature

Lower T

Higher T

One very high stream One moderate stream

Comments

Currently most common circuitry

Return T must be Increases complexity sufficiently cool and parasitic loads

Electricity (15–30%)

Input

Fuel (100%)

Prime mover

Recovered heat (50–65%) Exhaust losses (5–15%) Convection and radiation (3–7%)

Desired outputs

Heat losses

11.1 Energy flow schematic of a generic CHP (cogeneration) system. Numerical efficiency ranges are on an HHV basis; they are representative of a small ICE prime mover with heat recovered from both the exhaust and the cooling jackets, and with cabinet insulation to lessen convection and radiation losses from the prime mover surfaces.

is called trigeneration or combined cooling, heat and power (CCHP). The flow of energy involved in CCHP is shown in Fig. 11.2. Note that the heat rejected from the heat-activated cooling device (HACD) is likely still hot enough to be used for preheating domestic hot water (DHW), swimming pool heating, industrial process pre heating, or other uses. However, the amount of heat rejected by the HACD may exceed the demand for such low-grade heat (especially during the cooling season), and thus most is likely to be rejected to the environment. The output region enclosed by dotted lines in Fig. 11.2 indicates this variable utility of the heat rejected from the HACD. The ability to replace electrical consumption with the use of low-grade heat allows a trigeneration system to provide cooling in addition to electricity,



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Heat-activated cooling technologies for small and micro CHP Electricity

Input

Fuel (100%)

Prime mover

Recovered heat

Cooling

267

Desired outputs

HACT Heat rejection

Exhaust losses Convection and radiation

Heat losses

11.2 Energy flow schematic of a generic CCHP (trigeneration) system. Heat rejected from the HACT may still be at a high enough temperature to be useful, e.g. as DHW preheating or swimming pool water heating, or it may be considered a heat loss if rejected directly to the ambient.

without increasing fuel consumption. It also has the advantage of increasing the system utilization rate during the cooling season. Small-scale installations in the 5–100 kW range generally serve industrial facilities, commercial facilities or larger residential complexes. Micro systems (under 5 kW electric) are generally used for residential or small commercial applications. In general, any of the three energy products produced by a trigeneration system can either be utilized directly at the site of generation or be exported off-site. In the case of small-scale systems, electricity is typically exported easily (by selling electricity back to the grid). Although thermal energy is not usually viable for export in small systems, it is relatively easy to store (e.g. in a hot water tank). On the other hand, electricity storage is generally expensive. For installations independent of the grid, electrical storage is still possible (e.g. in batteries), but as long as a grid is available to absorb the excess electricity, then ‘net metering’ is the most cost-effective and energy efficient solution for dealing with times of excess electricity production. In organizing the discussion of heat-activated cooling devices, a choice must be made between a classification scheme based on applications, and one based on cycle types and working fluids. In the interest of clarity, the sections on system types are organized around cycle types and working fluids, with comments regarding applications incorporated where appropriate. Additionally, Table 11.3 has been provided for easy cross reference between applications and the appropriate corresponding cycle types.

11.3

Types of cooling systems and their applications

Heat-activated cooling technologies can most broadly be classified as either open or closed cycles. In open cycles, atmospheric air is the working fluid,



4/5/11 9:24:12 AM


Sorption cycles

>50

H2O/CaCl2 75–135

60–100

H2O/LiCl

70–120

Methanol/activated carbon

55–150

55–220

Water/Zeolite (various)

Zeolite (various)

60–120

Water/Silica gel (various)

>90

120–150

Single effect NH3/H2O

Silica gel

75–105

Tregeneration (°C)

–20 to 20

–

–

–

–

–25 to 20

>0 to 20

>0 to 20

–25 to 20

>0 to 20

Tcooling (°C)

unknown

–

–

–

–

>100 W

>100 W

>3 kW

>100 W

>10 kW

Cooling capacity (total)

Cooling

Characteristics for applications

Single effect H2O/LiBr

Thermo-mechanical Ejector (various)

Open

Closed

Cycle types

Desiccant dehumidification

Adsorption heat pump

Absorption

Table 11.3 Matrix connecting cooling cycles with applications

Solid

Liquid


4/5/11 9:24:12 AM

35 kW

Under devel.

>3 kW

–

–

–

–

–

Latent cooling capacity

Dehumidification

Heat-activated cooling technologies for small and micro CHP

269

and it is drawn into the system and exhausted out of it with only partial or no recirculation. In closed cycles, the working fluid is circulated repeatedly through the cycle without any loss of mass, allowing various working fluids to be chosen based on their thermodynamic properties, such as water, ammonia, alcohols, hydrocarbons, salt solutions, and other fluids. Open cycles discussed in this chapter are liquid and solid desiccant processes. Closed cycles discussed are absorption, adsorption and steam ejector heat pump cycles.

11.3.1 Background on sorption processes Nearly all open and closed thermally-driven cycles for cooling and dehumidification rely on sorption processes (with the exception of the thermomechanical ejector cycle). Sorption processes can be divided into absorption and adsorption. In absorption, absorbate molecules are dissolved into (i.e. incorporated into the bulk of) an absorbent material, changing the chemical makeup of the absorbent. On the other hand, the adsorption process involves adhesion of molecules to a surface at a gas–solid interface due to van der Waals (secondary) bonding (e.g. hydrogen bonding), leaving the chemical makeup of the adsorbent unchanged. This means that the absorption capacity of absorbent media scales with absorbent volume; whereas adsorption capacity of adsorbent media scales with interfacial surface area. The sorption rates of both adsorption and absorption processes scale with interfacial surface area, since mass transfer can only occur at the gas–solid or gas–liquid interface.

11.4

Open sorption cycles: desiccant dehumidification

A desiccant material can be an absorbent or an adsorbent. Absorbent desiccant materials are generally aqueous salt solutions, although triethylene glycol has been proposed (water is also used as an absorbent in closed absorption cycles, described in Section 11.5). In contrast, adsorbent desiccant media are created by either (1) using packed beds of solid adsorbent grains or pellets or (2) applying a solid desiccant such as silica gel or activated carbon as a thin coating to high surface area materials such as a honeycomb of aluminum or a finned heat exchanger. The coated finned heat exchanger approach allows heat to be added to (and removed from) the desiccant material by an internal heat transfer fluid such as water, while the packed bed and honeycomb approaches require that an airstream be used to regenerate the desiccant. Although a wide variety of materials have at least some affinity for water, additional properties are important to make a material practical as a desiccant. Particularly important are (1) a large water capacity per unit weight (and per unit volume) of desiccant material, (2) chemical and physical stability over many cycles of sorption and regeneration, and (3) resistance or immunity



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270


to contamination with dust and other contaminants present in the process and regeneration air streams. Additionally, the specific characteristics of the material’s sorption isotherms must match the desired application (e.g. regeneration temperature and desired process air humidity ratio). There are both liquid and solid hygroscopic materials that make good desiccants. The hygroscopic nature of the sorbent surface lowers the vapor saturation pressure of water at the surface. When the desiccant surface vapor pressure is lower than the partial pressure of water in the air over the surface, sorption of water will take place from the air to the desiccant. Sorption continues until the desiccant becomes saturated (i.e. until the vapor pressure differential between the surface and the surrounding air equalizes, achieving equilibrium). The desiccant can then be dried, or regenerated, by heating it to raise the vapor pressure above the surrounding air’s water vapor partial pressure. By cyclically saturating a desiccant material with moisture from the process air, regenerating (drying) the desiccant material in a heated regeneration air stream (which is exhausted outdoors), and cooling the desiccant with process air for sorption again, moisture can be removed from a building’s process air and exhausted to the surroundings. Three realizations of this basic principle are shown in Fig. 11.3. The primary input of energy to a desiccant system is heat to drive the desorption (regeneration) process, and 0.02

RH = 0.8 RH = 0.6 RH = 0.4

Humidity ratio (kgH2O/kgdry

air)

Saturation line Ambient

0.015

0.01

A

RH = 0.2

B

C

Setpoint

Pressure = 101.3 kPa 0.005 10

20

30 T (°C)

40

50

11.3 Airside psychrometric state points for three possible dehumidification processes, all of which cool and dehumidify ambient air to the same setpoint. Path ambient A-B-setpoint: conventional process, which removes moisture by cooling the air along the saturation line and reheating; path ambient-C-setpoint: rotary solid desiccant wheel with sensible-only cooling coil; path ambient-setpoint: liquid desiccant with sorption occurring directly on chilled wet desiccant cooling coils.



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271

fortunately the temperature required to regenerate many desiccants (i.e. the temperature of the desiccant isotherm at which the desiccant vapor pressure exceeds the ambient or regeneration water partial pressure) is within reach of small-scale CHP systems.

11.4.1 Solid (adsorptive) desiccant cycles

1

Regeneration inlet

4

2

Process outlet

3

Indoor loads

5

Cooling coil

Process inlet

6

Desiccant wheel

Regeneration outlet

Regenerator

The solid desiccant cycle is typically arranged as a desiccant-coated rotary heat exchanger (commonly referred to as a desiccant wheel) which rotates very slowly through process and regeneration air streams. A basic cycle is shown in Figs 11.4 and 11.5. Since the process air must first cool the desiccant before the desiccant can begin to dehumidify it, the first few degrees of

11.4 Basic desiccant wheel schematic. 0.02

0.8 0.6 RH = 0.4

RH = 0.2 30 °C


air)

25 °C

6

20 °C

0.015

1

15 °C

4

0.01

Pre

2 3 0.005 10

20

30

40

T (°C)

50

5 ssu

60

re

=1 01. 3

kPa

70

80

11.5 Air side psychrometric state points for a basic desiccant wheel, for typical indoor and outdoor summer conditions in the Southeastern US. Regeneration inlet is assumed to be outgoing ventilation air.



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272


rotation into the dehumidification section are actually devoted to sensible cooling of the desiccant (and the medium to which it adheres or within which it is packed). However, due to the slow rotation speed of the wheel, this has only a small effect on the process air temperature. The outlet air conditions are not uniform around the wheel, but they become homogeneously mixed downstream, and these mixed averages are depicted in Fig. 11.5. Solid desiccant materials and substrates There are many substances that are hygroscopic, but relatively few of these have the large surface area required to serve as a practical desiccant. The surface is where a desiccant actually interacts and exchanges moisture with the surrounding airstream. Thus it makes sense to maximize the surface area of a given volume (or mass) of desiccant material. This is achieved through selecting materials with high porosity. Several materials have been developed to serve as practical desiccants. An important distinction exists between the zeolites and all other desiccants (such as silica gel, activated carbon, and activated alumina). Zeolites have Silica gel Zeolite Activated carbon

T

m ed

T

lo

Desiccant moisture content (kgH2O/kgadsorbent)

w

0.4

0.2

h

T hig

0 Increasing water vapor pressure at desiccant surface

11.6 Qualitative equilibrium isotherms (for illustrative purposes only) for adsorption of water by silica gel, zeolite, and activated carbon. Each isotherm shows, for a given desiccant temperature, the equilibrium adsorbed moisture content as a function of the vapor pressure at the adsorbent surface (this corresponds to the partial pressure of water when the desiccant is in thermal equilibrium with air). Isotherms are shown for three adsorbent temperatures for silica gel, and for clarity only one is shown for zeolite and activated carbon.



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uniform pore size due to their crystalline pore structure (Ruthven, 1984, p. 9), while the other desiccants have a distribution of pore sizes centered on some mean value. For all desiccant types, typical pore diameters range from a few Angstroms to a few tens of Angstroms (Ruthven, 1984, p. 4). Every desiccant material has a set of equilibrium sorption isotherms with a characteristic shape in a graph of moisture content vs. surface vapor pressure. A qualitative comparison of the equilibrium isotherm shapes for the most common solid desiccants is shown in Fig. 11.6. From this figure, the relative characteristics of each desiccant are apparent. Compared with other water-adsorbing materials, silica gel has the widest operating range (though large swings in surface vapor pressure are required for large moisture removal) and a large capacity. The uniform pore size of zeolite is evident in the relatively sharp transition in moisture content that occurs over a narrow region of vapor pressure. A wide variety of zeolites are available, and depending on the type of zeolite, this transition can occur at higher or lower vapor pressure, and may correspond to a larger or smaller jump in moisture content. Thus zeolites have a fairly narrow operating range, but a high level of moisture transport can be accomplished with fairly small swings in vapor pressure. The one shown in Fig. 11.4 can be seen to have a high affinity for water at very low vapor pressures, making it effective at deep drying, although its utility in removing latent load for occupied spaces would be limited. The other important aspect to consider when looking at isotherm data for a substance is the temperature dependence of the isotherms. For an example of such a chart, see Fig. 11.13 in Section 11.5.2. The hygroscopic nature of a desiccant means that, when the desiccant is relatively dry, water vapor will spontaneously adsorb onto its surface in an exothermic reaction. In fact, this will occur even at temperatures above the psychrometric dewpoint of the surrounding air (another way of saying this is that the vapor pressure at the desiccant surface is much lower than that over a surface of liquid water at the same temperature). The reversible nature of this reaction is equally important: heating the desiccant can desorb the water off the desiccant surface (a phase change requiring a heat input equal to the heat of sorption). Importantly, the temperature required to regenerate (i.e. dry) many desiccants is well below the boiling point of water, and within reach of the low-temperature waste heat recovery utilized in small- and micro-CHP systems. Thus, by exposing a desiccant material alternately to a process air stream (i.e. one to be dehumidified) and to a hot exhaust airstream (which is exhausted to the environment), the desiccant can be alternately saturated with moisture and regenerated. This is the basis of the basic solid desiccant process depicted in Figs 11.4 and 11.5.



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Desiccant wheel configuration options For solid desiccant systems, a large number of configurations are possible when designing the internal components of a desiccant wheel unit. Every desiccant system has the essential components of a desiccant and a regenerator, and a system could be designed with single or multiple stages of these. In addition, single or multiple heat recovery exchangers (which transfer heat but not moisture), evaporative coolers, and sensible cooling coils or evaporators can be chosen. The number of possible combinations and sequences is enormous, and only a relatively small number have been studied in detail. Starting with the most basic cycle, some configurations that have already been explored and implemented are described below. Basic cycle The most basic configuration of a desiccant wheel consists of simply an adsorbent-coated wheel rotating between two air streams, with a sensible cooling coil (or evaporator) to remove the sensible load, as shown in Fig. 11.4. The rotation speed of the wheel is generally low enough (~1 rotation per minute) that the sensible energy transferred from the regeneration airstream to the process airstream is small. However, the water vapor adsorbed onto the desiccant surface in the process stream undergoes a phase change from vapor to an adsorbed quasi-liquid (an adsorbed substance generally has internal energy somewhere between its solid and liquid forms at the given temperature). The release of that latent heat raises the process air temperature, and in practice this sensible heat gain is roughly equal to the latent energy removed from the process stream. In this sense the desiccant wheel is a constant enthalpy device that exchanges latent energy for sensible energy, simultaneously dehumidifying and heating the process airstream. Even in this most basic configuration, a desiccant wheel can be very helpful. Since the process stream is dehumidified already, the evaporator/ cooling coil need only provide sensible cooling. Thus it only has to cool the process air to the desired dry bulb temperature, rather than all the way to the (much cooler) desired dew point temperature, improving the cooling system COP and capacity. Cycle enhancements Although heating the process air is undesirable, it does provide valuable opportunities. In fact, often the temperature of the dehumidified air leaving the wheel is so high as to be significantly above ambient temperature, allowing sensible heat exchange with the ambient air through a run-around loop, heat pipe, thermosiphon, or sensible wheel. Additionally, a large efficiency gain



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2

Evaporative cooling

6

3

Regeneration inlet

5

4

Indoor loads

1

7

Cooling coil

8

Sensible wheel

Process inlet

9

Desiccant wheel

Regeneration outlet

Regenerator

can be achieved by utilizing outgoing ventilation air as the heat sink for this sensible exchange, then subsequently heating it for use as the regeneration air stream. This can simultaneously reduce the sensible load remaining for the sensible cooling coil and reduce the regeneration heat required to regenerate the desiccant. In terms of packaging, a particularly convenient and common configuration is to include a sensible energy exchange wheel in series with the desiccant wheel, as shown schematically in Fig. 11.7 and on a psychrometric chart in Fig. 11.8. This wheel exchanges sensible energy without transferring moisture, preheating the regeneration air before it reaches the heater, and cooling the dehumidified process air before it reaches the conditioned space, cooling coil, evaporator, or air handling unit. This simultaneously reduces

Process outlet

11.7 Schematic of enhanced desiccant wheel with sensible exchange wheel and evaporative cooling. 0.02

25 °C

0.8 0.6 RH = 0.4 30 °C

RH = 0.2

1

air)


9

20 °C

0.015

15 °C

6 5

0.01 4

0.005 10

8

7

20

2

3

30

Pressure = 101.3 kPa

40

T (°C)

50

60

70

80

11.8 Representative average air side state points for enhanced desiccant wheel (with sensible exchange wheel and regenerationside evaporative cooling) in psychrometric chart.



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the sensible load required of the cooling coil and reduces the amount of heat required for regeneration. Once a sensible wheel has been added to the system, another possible enhancement is to add evaporative cooling to the regeneration side, before the sensible wheel (as also shown in Fig. 11.7). Although this may adversely affect the regeneration of the desiccant wheel, it also introduces the possibility of cooling the dehumidified process stream down to the wet bulb temperature of the regeneration inlet air. In one configuration, the outgoing ventilation (i.e. building exhaust) air is available for sequential use, first as a heat sink for the heat of adsorption, and next as the regeneration air stream. With this configuration, under the right climatic conditions and with a sufficiently effective sensible wheel, the dehumidified air can even be cooled below the setpoint temperature of the space, completely abdicating the need for any cooling equipment beyond the desiccant wheel itself. In practice, however, the climatic conditions amenable to this scenario are not very common, and even sophisticated desiccant wheel configurations for space cooling of occupied buildings are generally installed with supplementary sensible cooling equipment (such as vapor compression cooling). An absorption or adsorption heat pump could also be used for the supplemental sensible cooling. Evaporative cooling of the regeneration air, given sequential use of the regeneration air as heat sink and for regeneration, does have an adverse effect on the regeneration process. This adverse effect can be simply expressed in two scenarios: (1) for a fixed amount of heat input to the regenerative heat exchanger, it increases the RH of the regeneration air (and thus diminishes the moisture removal capacity of the wheel), or (2) for a fixed amount of moisture removal, it increases the required heat to the regenerator. Thus, in cases where a desiccant wheel installation has excess moisture removal capacity, evaporative cooling and sequential use of the regeneration air is an attractive option for reducing supplemental HVAC capacity requirements. In cases where the desiccant wheel does not have excess moisture removal capacity, this adverse effect can be circumvented by using a parallel approach to evaporative cooling/heat sinking and regeneration. In a parallel arrangement, outgoing ventilation air is evaporatively cooled, passes over the sensible wheel, and is exhausted. Meanwhile a separate air stream (perhaps outdoor air) is used for regeneration. This opens additional possibilities for providing total (sensible and latent) cooling with a solid desiccant humidifier without supplementary equipment. Additional configurations have been explored, including two-stage (parallel) regeneration for improved thermal COP (Kodama et al., 2003); dual desiccant wheels and dual cooling coils, and multiple-stage (serial) regeneration stages for more complete dehumidification (Henning et al., 2007); three- and fourwheel arrangements for high humidity climates (Kodama et al., 2003); and many more.



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11.4.2 Liquid (absorptive) desiccant processes Compared with solid desiccants, liquid desiccants have the advantage of very high specific moisture capacity: in fact, LiCl will absorb 10 times its own mass of water if allowed to reach equilibrium in a 90% RH environment (ASHRAE, 2005). However, the degree to which the absorption process approaches the equilibrium state depends on the amount of surface area exposed to air and the contact time with air. A quiescent liquid/air interface is not sufficient to achieve practical absorption rates. Thus, in order to increase surface area, most liquid desiccant systems either spray the desiccant into an air stream, or pass the air stream through an extended surface contact medium through which a falling film of desiccant falls. In the case of spraying, small droplet sizes clearly have an excellent ratio of surface area to volume, and smaller droplets also fall more slowly, achieving a longer residence time in the air stream. However, any spraying process creates a distribution of droplet sizes, and when the average vertical velocity of the falling droplets is comparable to or slower than the airflow velocity, many smaller droplets will be carried upward with the air stream, requiring additional filtering equipment to prevent them entering the process air stream. This filtering becomes a necessity even for falling film systems, as high local velocities through the media create very small liquid droplets that can be carried with the air stream. Two more advantages of liquid desiccants are that they can be regenerated with a lower temperature than most solid desiccants (although recently developed zeolites can also achieve low regeneration temperatures), and the liquid desiccant solution can be heated and cooled independently of the process and regeneration air streams (e.g. in liquid-to-liquid heat exchangers). This prevents the heat of regeneration from being dumped into the process air stream, and allows unheated air (ambient or building exhaust air) to be used for regeneration. This is shown in Fig. 11.9. Additionally, separating the desiccant heating and cooling processes presents the opportunity for recuperative heating of the diluted absorbent with the strong absorbent where the solution temperatures overlap. Liquid desiccant solutions The most common solution used in liquid desiccant dehumidification is aqueous LiCl, LiBr, CaCl2 and triethylene glycol are possibilities that have been experimented with. A liquid desiccant’s vapor pressure is basically proportional to its temperature and absorbent concentration. An equilibrium isotherm of LiCl is shown in Fig. 11.10.



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Air-air HX Regeneration air outlet

Process air outlet

Air-air HX

Qcooling to ambient P2 Qheating

Process air inlet P1

Regeneration air inlet

from prime mover

Desiccantdesiccant HX

P3

11.9 Schematic of one possible liquid desiccant dehumidification system. Pump P3 flows just enough to maintain fixed solution concentrations in the sumps of the conditioner and regenerator. It is also possible to have cooling coils immersed in the process air stream, with the desiccant spray forming films over them.

12 LiCl Desiccant moisture content (kgH2O/kgabsorbent)

10 8 6 4 2 0 10

30 50 70 Relative humidity (%)

90

11.10 Equilibrium isotherm for aqueous LiCl. Isotherm will shift up with a decrease in solution temperature (or down with an increase in temperature).



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11.4.3 System integration options Several choices remain in designing a desiccant wheel or liquid desiccant installation. The desiccant dehumidifier is generally configured to be in series with the unit that provides sensible cooling to the space (a cooling coil, evaporator, or air handling unit). In some cases, however, the desiccant unit can be installed in parallel with and independent of the existing HVAC system. This would make sense for a retrofit where, for example, a sensible heat recovery wheel is incorporated into the desiccant wheel unit. For a given desiccant dehumidification unit, where the stages of desiccation, regeneration, heat recovery, and evaporative cooling are in place, some decisions remain about how the unit is integrated with the building’s HVAC system: ∑ Choice of regeneration air stream source: outdoor air, outgoing ventilation (exhaust) air stream, or some combination. ∑ Choice of process air stream source: outdoor makeup air, recirculated conditioned air, or some combination. Schinner and Radermacher (1999) have performed detailed modeling of a combined desiccant/absorption system, demonstrating promising potential for such a system. The most efficient arrangement was predicted to be the use of building ventilation exhaust air for desiccant regeneration, and makeup (outdoor) air for the desiccant process air.

11.5

Closed sorption cycles: absorption and adsorption heat pumps

The two kinds of closed sorption cycles are absorption and adsorption heat pump cycles.3 Absorption refers to the sorption of a solvent into the bulk of a fluid or material, while adsorption refers to the sorption of a solvent onto the surface of a material. Of these, the absorption cycle is very well established (indeed the first form of mechanical ice production was based on an absorption cycle, invented in 1846 by Ferdinand Carré) and today there are many commercialized absorption heat pump products. Adsorption heat pumps also have a very long history, and adsorptive processes have been used extensively in open desiccant dehumidification systems (not to mention separation processes in the chemical and pharmaceutical industries). However, only a few commercial products are available today, and the adsorption heat pump is a technology currently under intense development. It is instructive to compare heat-driven heat pumps to the basic reverse 3

Throughout this chapter, the term heat pump is used in the generic sense to refer to devices that transfer heat from a lower temperature source to a higher temperature sink, whether the intended application is cooling or heating.



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Rankine (mechanical vapor compression) heat pump cycle, which is overwhelmingly the most widespread heat pump technology today. In the reverse Rankine cycle, a mechanical compressor compresses refrigerant vapor to a high temperature and pressure state, a condenser cools (and therefore condenses) the refrigerant at constant pressure, an expansion valve expands the refrigerant adiabatically, and an evaporator heats (thereby evaporating) the refrigerant at constant pressure back to vapor to complete the cycle. Absorption and adsorption heat pumps differ from the reverse Rankine cycle by replacing the mechanically powered compressor with thermally powered sorption equipment, taking advantage of the temperature dependence of sorption isotherms to achieve a high-pressure refrigerant vapor state. The various types of absorption and adsorption heat pumps are defined and distinguished by the sorption materials and methods they use to transform low-pressure refrigerant vapor into high-pressure vapor.

11.5.1 Absorption heat pumps The vast majority of absorption heat pumps use either water/LiBr or ammonia/ water as their refrigerant/absorbent working pair. The LiBr-based system has a better COP, but to prevent damage to the system by freezing of the water refrigerant, its evaporator temperature cannot go below 0 °C. Moreover, the solubility characteristics of LiBr in water are such that absorber cooling must be performed at relatively low temperature and/or low concentration to avoid crystallization. In contrast, the ammonia/water system is able to achieve the much lower temperatures required for refrigeration and freezing applications, but because of the toxicity of ammonia vapor, these systems must be either large enough to justify the overhead of safety measures (as in the case of large commercial refrigeration), or small enough to circumvent regulations related to the mass of ammonia in the system (as in the case of domestic refrigerators). Manufacturers associated with absorption systems with cooling capacity under 20 kW (~6 RT) include Broad (China), Yazaki (Japan), ClimateWell (Sweden), Rotartica (Spain), Robur (Italy), and Pink GmbH (Germany). Fundamentally, absorption heat pumps accomplish the feat of compressing refrigerant vapor with only a very small amount of mechanical input by pumping the refrigerant to high pressure as a liquid rather than compressing it as a vapor.4 The crucial element of the design, then, is how to convert low 4 The efficiency of a pump or compressor can be defined as the required work input per unit of fluid mass flow rate. The drastically higher efficiency of pumping liquid compared with compressing gas can be easily explained. Compared with the vapor phase, a refrigerant’s liquid phase has a much higher density, higher viscosity, and lower compressibility. Higher density means a smaller device with potentially lower fluid velocities are possible, higher viscosity means less leakage will occur, and most importantly, lower compressibility means less flow work (pressure-volume work) must be done.



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pressure vapor into a liquid, and high pressure liquid into a vapor. These two tasks are accomplished with heat-powered absorption and desorption. An absorption heat pump is best shown schematically as if superimposed on a Dühring diagram, as shown in Fig. 11.11, where increasing height corresponds to increasing pressure, horizontal distance to temperature, and each diagonal line is a particular absorbent equilibrium concentration. In an absorption heat pump, vapor leaves the evaporator as it is absorbed into strong solution in the absorber. This releases the refrigerant’s latent heat of absorption, so that the absorber must be actively cooled.5 Eventually, as the absorbent becomes nearly saturated with refrigerant, it is pumped to a high pressure desorber (also called a generator), first being pre-heated in the solution heat exchanger. In the desorber, heat is added to the dilute solution, evaporating the refrigerant, making the solution stronger and driving high pressure refrigerant vapor to the condenser. The remaining strong liquid solution need only be cooled and depressurized to absorb refrigerant vapor again. The solution is pre-cooled in the solution heat exchanger (HX), adiabatically cooled through a throttling valve, and arrives back at the absorber to complete the absorption/desorption cycle. The balance of the system (evaporator, condenser, and expansion valve) operates as in a reverse Rankine (i.e. vapor compression) cycle. An important efficiency improvement to the absorption cycle is achieved by the generator-absorber heat exchange cycle, commonly known as the Qcondensation Condenser

Qdesorption Refrigerant (vapor)

Desorber

Weak solution

Refrigerant (liquid)

Solution HX W

Refrigerant (two-phase) Evaporator

Qevaporation

Refrigerant (vapor)

Strong solution High pressure side Low pressure side

Absorber

Qabsorption

11.11 Schematic of an absorption heat pump cycle. 5

The absorber will be cooled towards the ambient dry bulb temperature in an air-cooled system, and towards the ambient wet bulb temperature in a water-cooled system with cooling tower.



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GAX cycle. The GAX cycle can be thought of as the logical extension of extending the solution heat exchanger into the desorber (generator) and absorber. The latent heat of absorption which is gained by the absorber is used to provide heat to the desorber, and the latent heat of desorption released by the desorber cools the absorber. In this way, less heat needs to be added to the desorber, and similarly less heat needs to be rejected to the ambient from the absorber. This is only possible if temperatures overlap between the desorber and absorber, generally precluding GAX from water/ LiBr systems. The most important consideration when choosing a cycle type for a cogeneration system is the available waste heat temperature. Since every heat-activated cooling system has a minimum regeneration temperature, and since many small cogeneration systems have a relatively low waste heat temperature, many cooling technologies are impractical for use with small CHP. For example, a micro-CHP device may produce hot water at 80 °C, just hot enough to drive a single-effect absorption chiller but not nearly hot enough for a double- or triple-effect chiller. For applications with low heat recovery temperature, it may be necessary to utilize a half-effect absorption cycle. The half-effect cycle requires an additional absorber, desorber, solution heat exchanger, and solution pump, and also has a lower COP than the single-effect cycle. However, the required driving temperature is significantly lower.

11.5.2 Adsorption heat pumps In common with the absorption cycle, the adsorption heat pump replaces the mechanical compressor of the reverse Rankine cycle with sorption equipment. However, adsorption is used instead of absorption, and no solution pump is needed. Compared with absorption heat pumps, adsorption heat pumps are less well developed and generally have a lower thermal COP, but have a wider range of possible working pairs (see Table 11.3), a wider range of regeneration temperatures, and can have lower parasitic power requirements. One major challenge of adsorption heat pumps is packaging the adsorbent to achieve good heat and mass transfer within a reasonable volume and mass. Manufacturers associated with small adsorption systems include Jiangsu Shuangliang (China) Mayekawa (Japan), and SorTech AG (Germany). In an adsorption heat pump, shown in Figs 11.12 and 11.13, two adsorbentcoated heat exchangers (or adsorbent beds) are placed in separate sealed chambers. Each coated heat exchanger has piping to allow heating or cooling water to flow within. Thus, by heating one of the heat exchangers (the desorber), refrigerant will be desorbed from its surface, pressurizing its chamber until the upper valve opens, allowing refrigerant vapor to pass to the condenser (which is cooled by ambient-temperature water). The condensed refrigerant



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Condenser

Active or passive check valves Desorber

Expansion orifice

Adsorber

283

Heat transfer fluid temperatures: Low (e.g. 10 °C) Moderate (e.g. 30 °C) High (e.g. 70 °C) Refrigerant pressures:

Evaporator

Low (e.g. 0.01 atm) High (e.g. 0.04 atm)

11.12 Adsorption heat pump schematic.

6

fr ig e tio ran n t lin e

X

=

0

2 .1

6 X

=

0

7 .0

4 X

=

0

ra

Re

=

3

4 .0

X

tu

8

X

2 0.

sa

Vapor pressure (kPa)

12

X

4

55

4

= =

0

2 .0

0.

0

2

14

49 Refrigerant Tsaturation (°C)

16

43 37 31

3

25

2

19

1.5

13

1 –0.0033

–0.0031

–0.0029 –1/Tadsorbent (–K–1)

–0.0027

7 –0.0025

11.13 Dühring diagram for water on silica gel 3A, plotted from state equation given in Ng et al. (2001). X denotes the value of kgH2O/ kgadsorbent for each isostere (line of constant adsorbent loading). Dotted lines: simple (non-recuperative) adsorption cycle operating with the following conditions: Tdesorption = 80 °C (176 °F, –0.00283 in diagram); Trejection = 32 °C (90 °F, –0.00328 in diagram), corresponding to a pure water vapor pressure of 4.76 kPa; Tevaporation = 10 °C (50 °F), corresponding to a pure water vapor pressure of 1.23 kPa.

drips by gravity to an expansion orifice or valve and adiabatically cools upon expansion. The expansion process generates two-phase refrigerant, with the liquid refrigerant evaporating from the surfaces of the evaporator to provide cooling capacity. The pressure differential across the expansion orifice is maintained by cooling the second coated heat exchanger (the adsorber) with



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ambient-temperature water, thus causing refrigerant vapor to adsorb onto its coated surface. This arrangement can be maintained until the desorber approaches a ‘dry’ state and the adsorber approaches a saturated state. The adsorber/desorber roles of the two coated heat exchangers are then reversed, allowing the process to continue. Thus the adsorption heat pump is a periodic cooling device – although when operating properly, an excess of liquid refrigerant will build up on the evaporator during the peak sorption period, which buffers the capacity delivered by the evaporator during adsorption/ desorption switching periods. The necessity of periodically heating and cooling the adsorber heat exchangers and associated piping accounts for the generally lower thermal COP of adsorption systems compared with absorption systems, since heating this ‘dead mass’ consumes driving heat (which is then rejected to the ambient in the next adsorption phase) without contributing additional cooling capacity. However, since no solution pump is required for an adsorption heat pump, the potential exists for improving the ECOP compared with absorption systems. Also, the wide variety of adsorbents available and in development, particularly a diversity of zeolites, hold much promise for enabling adsorption heat pumps to efficiently operate under a wide range of conditions, including utilizing much lower heat source temperatures than required by absorption systems. Refrigerant/adsorbent working pairs that have been used for adsorption heat pumps include water/silica gel, water/zeolite, ammonia/activated carbon, butane/silica gel, methanol/silica gel and others. Since adsorption involves van der Waals bonding, and since hydrogen bonding is the strongest form of van der Waals bonding, the use of small polar molecules such as water, ammonia and methanol as refrigerants tends to result in the best performance.

11.6

Steam ejector cycle

Whereas sorption heat pumps replace the compressor of a VCC with a set of thermally-driven sorption equipment, the ejector cycle replaces the compressor with a boiler, feed pump, and ejector: a mechanically simple device with no moving parts (Fig. 11.14). However, although the ejector cycle (Fig. 11.15) is attractive for its simplicity, it does not achieve as high a performance as sorption heat pumps. Also, currently there are no commercially available cooling products based on the ejector cycle, although there is much ongoing research. The ejector cycle most commonly uses water as a working fluid, although various compounds have been tried (see Sun, 1999). The steam ejector refrigeration cycle was utilized widely during the 1930s, and until recently, very little further development has been pursued. Current areas of research include improving the COP and developing systems that can operate with lower boiler temperatures (to enable waste heat and solar firing).



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Heat-activated cooling technologies for small and micro CHP Throat

Mixing Converging/diverging nozzle

285

Subsonic

chamber

diffuser

Primary or ‘motive’ fluid

Mixed Outlet

Shock

Fluid velocity

Secondary or ‘entrained’ fluid

Sonic velocity

Ejector length

11.14 Schematic of an ejector with fluid velocity profiles. Solid double line: fully mixed fluid; solid single line: primary fluid; dotted line: secondary fluid (figure adapted from Sun, 1999). Qdriving Boiler Pr ehe at

W

Pressure

er

Qrejected

Condenser

e Ej

ct

or

Pre -co ole r

Evaporator Qevap Temperature

11.15 Ejector cycle schematic, shown with two optional pre-heating and pre-cooling heat exchangers for improved capacity and COP.

11.7

Component-specific efficiency and effectiveness metrics

The figures of merit most commonly used for describing the performance of cooling devices are the COP, thermal COP, and the specific cooling power. These metrics are useful for sorption heat pumps and dehumidification systems



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that provide sensible or total (sensible and latent) cooling. However, some desiccant dehumidification configurations provide latent cooling without sensible cooling, and a distinct approach must be taken to evaluate their effectiveness.

11.7.1 Thermal coefficient of performance (COP) and Carnot COP The thermal COP is analogous to the more familiar COP used with vapor compression cycle (VCC) heat pumps. However, whereas the VCC COP is the ratio of delivered heat or cooling power to the electrical or mechanical power input, the denominator in the thermal COP is the thermal power input. The advantages of HACTs are obscured by the fact that this important distinction is often overlooked. It is important to remember the more thermodynamically valuable nature of electricity compared with fuel or heat when comparing VCC COPs to thermal COPs. In this regard, if it is assumed that three units of fuel (i.e. high-temperature heat) are required to produce one unit of electricity, then an electrically-driven heat pump with a COP of 3 will have equivalent source fuel utilization rate to a fuel-fired, heat-activated heat pump with a COP of only 1. In the case of waste-heat-activated cooling technologies, the accounting is even more favorable towards the HACT. For example, imagine that facility ‘A’ utilizes a CCHP system which incorporates a waste-heat-driven HACD with a COP of 0.5, while facility ‘B’ utilizes grid electricity and a VCC heat pump with a COP of 4. Depending on factors such as equipment utilization rate, the assumed conversion efficiency of the electric grid, climate, and many others, facility ‘A’ might turn out to use less source fuel energy than facility ‘B’ to meet the same loads throughout the year (it will likely also eliminate expensive demand charges on its electric bill which are usually incurred during the hottest days of the year). This highlights the need to take a system-wide approach to system performance, rather than simply focusing on the COP values for different cooling technologies. Another perspective on thermal COP is provided by comparing it with the Carnot limit for a given regeneration temperature. This is shown for typical system COPs in Fig. 11.16. System-wide approaches to measuring efficiency are addressed in Section 11.8. Figure 11.16 shows the typical ranges of firing temperature and COP for absorption, adsorption and ejector cycles. Of the plotted technologies, four are commercially available: (1,2) single-effect H2O/LiBr or NH4/H2O machines, (3) double-effect H2O/LiBr machines, and (4) adsorption machines with various working pairs. The various working pairs for adsorption machines are discussed in Section 11.5.2. Although the potential exists for large COP improvements with multi-stage adsorption machines (see Douss and Meunier,



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287

ol

in

g

n

je re

Adsorption Single effect 1 cycles H2O/LiBr

Double effect NH3/H2O Single effect NH3/H2O

0.5 0

Triple effect H2O/LiBr

Double effect H2O/LiBr

T

co

ct

1.5

T

Thermal COPcooling

2

io

Th e CO rm P al c

co ar ol n in g fo ot = r 35 = 10 °C °C and

2.5

Half effect H2O/LiBr 35

75

Ejector cycles

115 155 195 Regeneration temperature (°C)

235

11.16 Thermal COP vs. regeneration temperature for various HACT.

1989), this possibility is left out of the figure since experimental results for such a machine are not well established. An interesting note to Fig. 11.16 is that the COP range for a given absorption technology is flat – the COP for single-effect H2O/LiBr absorption, for example, does not increase with increasing firing temperature. This is a consequence of the working fluid properties. If a higher heat source temperature is available, utilizing a double-effect system does increase COP, but the COP for double-effect is also flat. This dependence of performance on working fluid pair (and not heat source temperature) is in fact a general characteristic of sorption heat pumps. The region in Fig. 11.16 for adsorption cycles displays a diagonal tilt because it represents a family of working pairs. Although not sorption-based, the ejector cycle region also represents a family of working fluids and geometries. The Carnot COP of a VCC heat pump is the best possible performance achievable between two source/sink temperatures, given a mechanical or electrical input. It is derived in every thermodynamics fundamentals textbook. The Carnot thermal COP of a HACD is derived in Herold et al. (1996) by coupling a Carnot power production cycle to a Carnot heat pump cooling cycle. It is assumed that (1) the work produced by the power cycle equals the work consumed by the cooling cycle, and (2) the heat rejection temperature of the power cycle equals the heat rejection temperature of the cooling cycle. There are thus three temperatures involved in calculating the Carnot thermal COP for cooling: the low temperature (i.e. evaporator) heat source (T0), the heat rejection temperature (T1), and the high temperature heat source (T2). The resulting expression is given in Equation 11.1, where the first quotient is the Carnot efficiency for a power cycle and the second is the Carnot COP for a cooling cycle:



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Ê T – T1ˆ Ê T0 ˆ COpcarnot,thermal, cooling = Á 2 Ë T2 ˜¯ ÁË T1 – T0 ˜¯

11.1 This efficiency limit can equivalently be applied to an engine-driven VCC device or to a directly heat-activated cooling device. Thus, considering the various energy conversion and transmission losses incurred by centrally generating power and distributing it to utility customers’ VCC systems, it is not surprising that a directly-fired HACD should be able to demonstrate source-energy efficiency comparable to or better than conventional VCC systems. Of course, this is especially the case when the HACD is driven by low-grade heat that is rejected from an on-site power cycle or collected by a solar collector. Although not discussed in detail in this chapter, it is important to note that most cooling devices are also capable of running in a heating mode during the heating season. The Carnot thermal COP for heating mode is given by Equation 11.2. Ê T – T0 ˆ Ê T1 ˆ COpcarnot,thermal, heating = Á 2 Ë T2 ˜¯ ÁË T1 – T0 ˜¯

= COPCarnot,thermal,cooling + 1

11.2

The fact that the heating COP (even for a system far from the Carnot ideal) is always greater than 1 means that the installation of a heat-activated heat pump can provide benefits both during the heating and cooling seasons. For heating use, the evaporator would be heated by the ambient, and the heat rejected by the condenser and adsorber would be used for space heating. For example, with a heating thermal COP of 1.5, an adsorption machine could provide 1.5 kW of space heating at 35 °C (95 °F) for every kW of heat produced at higher temperature by the prime mover. The thermal COP of heat-activated machines can generally be expressed as a simple ratio of useful thermal output to the thermal input, as in Equation 11.3, but can also include the parasitic loads (e.g. electricity to run pump and fan motors) required by the device. Further, there are at least two ways of accounting for parasitic loads: as subtracted from the cooling energy (Equation 11.4) or added to the regeneration energy (Equation 11.5).

COpcooling =

Qcooling Qregeneration

COpcooling =

Qcooling – Wparasitics Qregeneration

COpcooling =

Qcooling Qregeneration + Wparasitics

11.3

11.4

11.5



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In any equation accounting for parasitic loads, the parasitic could also be weighted by the electric conversion efficiency, giving the amount of fuel that must be burned to supply the parasitic load. Taking this approach, Equation 11.6 could be substituted into Equation 11.4 or 11.5 above to replace the parasitic term to achieve an energy efficiency accounting using only thermal terms: Wparasitics helectrical

11.6 The performance of a heat-activated cooling device can also be expressed as the electric COP, or ECOP, which neglects thermal inputs and is the cooling output divided by the electrical parasitics, as shown in Equation 11.7. This definition makes sense if the heat driving the system is assumed to be truly free, and it demonstrates the reduction in electricity consumption of a HACD compared with a VCC. That the ECOP of a HACD exceeds the COP of a VCC is a necessary (but not necessarily sufficient) condition for demonstrating improved energy efficiency of the HACD. In practice, the electrical parasitics involved in running an absorption chiller are not insignificant, but the ECOP of an absorption system still easily surpasses the COP of a VCC. The ECOP of an adsorption chiller is generally even more favorable since pressurization of the working fluid is accomplished thermally rather than mechanically. There is no theoretical limit to the ECOP; indeed HACD have been built that require no electricity at all. Qparasitics,equiv =

ECOPcooling =

Qcooling Wparasitics

11.7 Thus, there are at least six possibilities for how to calculate the efficiency of a heat-activated sensible or total cooling device on a First Law basis. Further, when the choice of lower heating value vs. higher heating value is considered for the efficiency term in Equation 11.6, there are at least eight calculation possibilities (and the continuous range of numerical values that can be used for that efficiency term means the possibilities are infinite). Additionally, any thermal COP value can be divided by the Carnot thermal COP value to obtain a Second Law efficiency (which is always between 0 and 1). No definition is inherently better than another. Clearly, however, one must be careful in assessing efficiency claims, and should clearly state assumptions when reporting efficiencies, as a manipulative or careless choice of efficiency definition can have misleading results.

11.7.2 Desiccant dehumidification effectiveness Defining the effectiveness of a desiccant dehumidification process is complicated by the fact that a desiccant wheel can be useful without © Woodhead Publishing Limited, 2011


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actually providing any reduction in the energy content (enthalpy) of the process air. For example, as noted in Section 11.4, the process air exiting a desiccant-coated wheel experiences essentially no change in enthalpy, as it is sensibly heated to the same degree it is latently cooled. Thus, for the most basic desiccant wheel configuration (Figs 11.7 and 11.8), if any one of Equations 11.3–11.5 were applied, the cooling provided would be zero! Thus these definitions are clearly not helpful for the basic configuration. Since the primary objective of dehumidification is moisture removal, Equation 11.8 makes intuitive sense, and is commonly used. Parasitic energy consumption could be subtracted from the latent heat removal term, or added to the regeneration term, following the pattern of Equations 11.4–11.6. However, as the primary ‘parasitic’ effect of a desiccant wheel may be an increase in pressure drop that must be overcome by the ventilation fan, or perhaps an increase in air flow rate, defining the parasitic load may not be straightforward. Another possibility is to define the dehumidification effectiveness relative to the ideal of removing all moisture from the process air (Equation 11.9). However, drier is not always better if an ideal humidity level has been reached, and this definition does not provide fair comparisons among different ambient conditions.

e dW,1 =

Qlatent Qregeneration

e dW,2 =

Qlatent w – w out = in Qlatent,max w in

11.8

11.9 The effectiveness definitions for dehumidification in Equations 11.8 and 11.9 can be useful for comparing one dehumidifying device to another under similar conditions, where dehumidification is the only objective. However, cycle enhancements to remove sensible load, such as adding a sensible wheel to a desiccant wheel system, will be under-appreciated by these definitions. For a desiccant dehumidification configuration that provides total cooling, Equations 11.3–11.5, or a system-wide performance metric, would be more appropriate.

11.8

System-wide performance and efficiency metrics

Attempting to define and interpret the component-specific efficiencies for each component in a CCHP system can be difficult, and sometimes the fuel consumption to meet a given set of loads can be improved by sacrificing one component’s individual performance to benefit another’s (e.g., in a combined



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cycle power plant, the Brayton topping cycle’s exhaust gas temperature and pressure are increased to benefit the Rankine bottoming cycle and improve the plant’s overall thermal efficiency). Thus, in many cases it makes more sense to calculate the system-wide performance, capturing the interactions and synergies among components into a single metric which can be compared with alternative integrated systems.

11.8.1 Energy content of fuel There are basically two alternatives to account for the fuel input to a system: the lower heating value (LHV) basis or the higher heating value (HHV) basis. Each alternative is commonly used, and the choice is fairly arbitrary since results in either basis are readily interconverted. However, arbitrariness does not mean unimportance; indeed the choice of heat value should always be stated when reporting any performance metric that involves the fuel energy, such as system efficiency. Unfortunately, this choice is often not specified when efficiency values are reported, leading to much confusion and difficulty in comparing systems. Both heating value definitions include all the sensible energy removed from an exhaust stream by cooling it to 25 °C (77 °F). However, the LHV assumes that all water vapor formed by combustion remains vapor, while the HHV assumes that all water vapor condenses. HHV is typically 7% to 11% higher than LHV for hydrocarbon fuels. Consider the energy accounting consequences for the CHP system shown in Fig. 11.1 if the fuel basis is changed from HHV to LHV. The electrical and hot water energy flows (i.e. kW or Btu/hr) out of the system will clearly not be altered by this change in fuel accounting, so their efficiencies will be increased by an amount inversely proportional to the decrease in fuel energy (e.g. from 18% HHV electrical efficiency to 20% LHV electrical efficiency, corresponding to a 10% lower LHV energy content than HHV energy content). On the other hand, in order to arrive at a proper First Law energy balance on the system, the exhaust flow needs to be evaluated with respect to a reference state, and this reference state must correspond to the reference state used in the fuel heating value definition. For a prime mover with a sufficiently effective exhaust gas heat exchanger and a relatively low heat recovery temperature, it is possible to cool the exhaust gas below its dew point (about 60 °C/140 °F for stoichiometric combustion of natural gas in air), thereby transferring latent heat from the exhaust to the heat recovery fluid. Thus the use of the LHV reference state can allow the exhaust mass flow out of the system to be considered a heat flow into the system, making possible an overall fuel utilization rate greater than 1.



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11.8.2 System-wide metrics The most commonly used system-wide performance metric is the fuel utilization factor shown in Equation 11.10.6 This is a simple First Law accounting of the useful energy flows (regardless of temperature or type) obtained from the system, divided by the fuel input. While straightforward to calculate and understand, it does not account for the thermodynamic or economic value of any outputs. FuF =

Welectric + Qcooling + Qheating Qfuel,hhV or lhV

11.10 An accounting of the energy flows based on the Second Law of Thermodynamics is shown in Equation 11.11, where the heating and cooling flows are weighted by the theoretical efficiency of a Carnot heat pump operating between the relevant source and sink temperatures (i.e. the second quotient of Equation 11.1), and electrical power and fuel are equivalent to their First Law values. Although this definition is derived directly from thermodynamics, is does not always correspond with the realities of economics, or with the actual efficiencies of alternative heating and cooling methods. Welectric +

Qcooling Qheating + hcarnot, heating hcarnot, cooling Qfuel,hhV or lhV

h2nd law = 11.11 In the US, the 1978 PURPA regulations define a combined efficiency for qualifying cogeneration facilities, given in Equation 11.12. The factor of 2 in this definition has no direct thermodynamic justification, and the resulting efficiency value will generally fall between the values calculated by the FUF and the Second Law efficiency.

hpuRpa =

Welectric +

Qheating 2

Qfuel,hhV or lhV

11.12

6

The fuel utilization factor adds together types of energy of very different value (electricity and low-grade heat) without any weighting or correction factor to normalize them. It is therefore misleading (although commonplace) to refer to it as the ‘overall efficiency’ or ‘combined efficiency.’ This terminology distinction for CCHP systems is analogous to VCC heat pump performance being characterized by a ‘coefficient of performance’ rather than an efficiency, since the VCC COP similarly does not correct for the difference in value between its numerator and denominator. Incidentally, since the thermal COP of a HACD is a ratio of comparable energies, it could legitimately be called an efficiency, unlike the COP of a VCC. This, again, underscores the incomparability of VCC COP and thermal COP values.



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The fuel utilization efficiency shown in Equation 11.13 is a practical definition for comparing different systems.7 It weights each energy flow by how it would be produced by an alternative conventional device. Importantly, this means that all four terms in Equation 11.13 (i.e. work, fuel, heating, and cooling) are converted to units of energy of comparable value, making it more thermodynamically justifiable than Equation 11.10 from an exergetic standpoint. It is, however, up to the discretion of the user to choose baseline system efficiencies, making it less thermodynamically rigorous than Equation 11.11. Also note that Equation 11.13 is not directly bounded by the First Law, and can exceed 1. The calculation is straightforward when assuming baseline devices that are fuel-fired (such as a furnace, where hheater = 0.8 (LHV) would be a reasonable choice). However, if a VCC device is chosen as a baseline system, then the overall fuel utilization of that device (rather than its COP) must be considered, which also requires an assumption be made for electric grid efficiency. For example, if the baseline cooling device is chosen to be a VCC air conditioner, an appropriate choice for hAC, assuming an air conditioner with COP of 3 and a grid efficiency of 1/3 (LHV), would be hheater = (3) (1/3) = 1 (LHV). Of course a similar procedure applies to calculating hheater for an electrically-driven space-heating heat pump. Welectric +

Qcooling Qheating + hheater, fuel–basis hac,fuel–basis Qfuel,hhV or lhV

hfuel utilization = 11.13 The fuel chargeable to power (FCP) is based on the premise that the CHP system heat output displaces the use of a boiler, with electricity being produced as a byproduct. Under this premise, it makes sense to calculate an electrical efficiency where the fuel that would have fired a boiler is subtracted from the fuel the CHP system consumed. This can be generalized to include cooling outputs, as in Equation 11.14. Fcp = Qfuel,hhV or lhV –

Qheating Qcooling – hboiler hVcs

11.14 In common usage, the FCP ignores cooling and is often expressed as a heat rate (i.e. a ratio of inputs to outputs). In Equation 11.15 it is generalized to include cooling and expressed as the FCP efficiency, a ratio of inputs to outputs (the inverse of the FCP heat rate).

7

Here, fuel utilization efficiency is defined distinctly from the fuel utilization factor. In common usage, these terms are used interchangeably, and additional explanation is required to distinguish them.



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hFcp = Qfuel –

Welectric Qheating

–

Qcooling

11.15

hheater,fuel–basis hac,fuel–basis The FCP efficiency metric (Equation 11.15) is very similar to the fuel utilization efficiency (Equation 11.13), except that the fuel chargeable to heating and cooling is subtracted from the inputs rather than credited to the outputs. A comparison of these two metrics is shown in Fig. 11.17. There are three pairs of lines in Fig. 11.17. Each pair compares the fuel utilization efficiency with the FCP efficiency, and each pair uses a different independent variable while holding others constant. The pair with crosses varies the electrical efficiency while holding fixed the heating and cooling efficiencies; the pair with squares varies the heating efficiency while fixing the electrical and cooling efficiencies; and the pair with pluses varies the cooling efficiency while fixing the electrical and heating efficiencies. A similar exercise can be carried out for the several other efficiency definitions given in this section, and each definition will exhibit distinct values and trends. This reinforces the importance of a critical approach to evaluating and reporting efficiency values.

Efficiency metric value

1 0.8

hFU = f (Welectric)

0.6

hFCP = f (Welectric) hFU = f (Qheating)

0.4

hFCP = f (Qheating) hFU = f (Qcooling) hFCP = f (Qcooling)

0.2 0 0 0.2 0.4 0.6 Independent variable as fraction of fuel input

11.17 Comparison of fuel utilization rate (Equation 11.13) and fuelchargeable to power efficiency (Equation 11.15), assuming hheater, fuel– basis = 0.8 and hAC,fuel–basis = 1.05. Solid lines: fuel utilization efficiency. Dotted lines: FCP efficiency. Crosses: as functions of electrical output of system, holding fixed, as fractions of fuel input, Qheating = 0.6 and Qcooling = 0; squares: as function of Qheating holding fixed Welectric = 0.25 and Qcooling = 0; pluses: as function of Qcooling holding fixed Welectric = 0.25 and Qheating = 0.



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11.8.3 Comparative performance relative to baseline systems Comparing to baseline systems is a more empirical approach, of a less thermodynamically fundamental nature than metrics such as the COP. It can often be more useful when a direct comparison to conventional systems is desired. However, any comparative performance estimate can easily have a wide span of outcomes, depending on the choice of baseline system, the assumptions made about the baseline system, and the way that various energy flows are accounted for. One choice for comparing a proposed CCHP system to a baseline one is to use a metric such as the fuel utilization efficiency (Equation 11.13), and the other is to build models of the proposed system and the baseline system to evaluate the relative performance by detailed system simulation. A simple example of this approach is shown in Figs 11.18–11.20, in which the fuel required to meet one unit of loads in a residence is calculated for three systems. For all cases it is assumed that there is a 4:1 ratio of cooling 35% 0.76 Btu fuel

3.0 COPAC

Elec.

hel

0.8 Btu Cool air

losses 80% hwater heater

0.25 Fuel

0.2 DHW

11.18 Zero-order model of baseline non-CHP system with VCC cooling device and fuel-fired water heater with efficiency of 80%. The conversion efficiency of fuel to electricity is chosen to be typical for a Rankine-cycle-dominated electric grid. Net fuel consumption: 1.01 units per unit loads. rted Expo id r g to

0.07 fuel offset 4.5

25% 0.76 Btu Fuel

COPAC

Elec. hel

Waste heat

hHR

Hot water

90%

losses

eDW

0.8 Btu Cool air

Dry air 0.2 DHW

11.19 Zero-order model of CCHP system with desiccant wheel and VCC. The desiccant wheel is assumed to boost the heat pump COP from 3 to 4.5 by separating sensible and latent cooling, and to provide 20% of the driving heat as sensible cooling via an advanced configuration such as that shown in Fig. 11.7. Excess electricity produced offsets production by the grid, assumed to have an efficiency of 35%. Net fuel consumption: 0.69 units per unit loads.



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25% 1.99 Btu Fuel

hel

Elec.

Waste heat

Exporte

90% hHR

d d to gri

Offsets 1.42 Btu fuel

0.7 Hot water

COPabs

0.8 Cool air

0.2 DHW losses

11.20 Zero-order model of CCHP system with absorption chiller. Electricity produced offsets production by the grid, assumed to have an efficiency of 35%. Net fuel consumption: 0.57 units per unit loads.

to DHW loads. The height of each box is proportional to the energy it represents. Figure 11.18 shows a zero-order model (i.e. components are described by fixed values without any independent variables) of a baseline system consisting of a grid-electricity-powered VCC and a fuel-fired hot water heater. The baseline system requires 1.01 units of fuel (0.76 off-site and 0.25 on-site) for every unit of loads. A simple zero-order model of a CCHP system with desiccant cooling is shown in Fig. 11.19. This system requires 0.76 units of fuel on-site for every unit of load, but also is a net producer of electricity. When credit is issued for this production (assuming it offsets grid electricity that would have been produced with an efficiency of 35%), it requires only 0.69 net units of fuel. A zero-order model of a CCHP system with absorption cooling is shown schematically in Fig. 11.20. This system requires more on-site fuel consumption, but also produces a significant excess of electricity. When credit is issued for this electricity, it only consumes 0.57 net units of fuel for each unit of load. This simple example demonstrates the potential for fuel savings with CCHP systems, and demonstrates the basic methodology of using system modeling to compare system alternatives. Costs can easily be assigned to components and to imported and exported energy to make economic as well as energetic performance comparisons.

11.9

Advantages and limitations of heat-activated cooling

Heat-activated cooling and small-scale CHP systems have a synergistic combination. Without available waste heat, heat-activated cooling technologies © Woodhead Publishing Limited, 2011


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must be direct-fired, and in that case they struggle to compete with conventional cooling methods, both on a cost and an energy basis. Small-scale CHP, without any heat-activated cooling device, often struggles to demonstrate sufficient operating hours throughout the year to justify the capital expenditure on CHP equipment, and may demonstrate only marginally improved energy efficiency compared with state-of-the-art standard energy solutions. However, combining small-scale CHP with HACT can increase both system operating hours and system fuel efficiency. Thus, integration with CHP can justify the energetic and cost performance of HACT, and vice versa. The integrated system performs better than the sum of its parts. On the other hand, heat-activated cooling for small-scale CHP does suffer some limitations. Most importantly, adding more components to a CHP system increases the initial capital cost, in a technology where high initial cost is a fundamental challenge. Secondly, system complexity is also increased, and many heat-activated cooling technologies do not yet have commercial products that are well proven in terms of reliability and longterm performance.

11.10 Future trends With the proliferation of small-scale CHP installations and an increased emphasis globally on fuel efficiency, small-scale heat-activated cooling technologies have a promising long-term outlook. Although current CHP manufacturers for domestic and commercial CHP applications will probably first succeed in the climate zones most amenable to CHP (i.e. climates with long, heating-dominated seasons), manufacturers will be looking for ways to expand to other regions. As costs for both CHP systems and HACT come down, and as the efficiency benefits are more fully appreciated, HACT can help justify the economics of installation to a much wider set of markets, including residences in cooling-dominated climate regions, commercial establishments with large latent HVAC loads, and industrial applications with large cooling loads. In general, the capacity of a HACD increases with higher regeneration temperature; while a CHP prime mover has a higher overall efficiency with a lower heat recovery temperature, which extracts the most possible energy from the exhaust and minimizes convective and radiative losses. This fundamental compromise requires technological advances that enable high thermal COPs with lower regeneration temperatures (e.g. advanced desiccant polymers for desiccant wheels and advanced regenerative adsorption heat pumps). As energy efficiency requirements for HVAC equipment continue to become more stringent, manufacturers are exploiting various technologies proven to improve efficiency, and most of these interact positively with HACT. For example, a VCC system set up for separate sensible and latent



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cooling can be supplemented with a desiccant dehumidifier. Utilization of low temperature difference (DT) heat exchangers enhances the incentive to keep air conditioning evaporator temperatures high, and thus it becomes even more important to perform dehumidification separately from sensible cooling. Higher standards of thermal comfort will incentivize systems that operate efficiently at part load, since they may have to be sized larger to meet higher design-day requirements, and in this area absorption chillers excel. A combination of higher thermal comfort standards and tighter building envelope will increase ventilation requirements, which in turn enhances the benefits of dedicated dehumidification equipment. Further, a CCHP system such as a liquid dessicant/absorption system with on-site power generation can abdicate the need for vapor compression systems altogether, greatly reducing peak electricity demand and reducing fuel consumption. Finally, fuel-flexible external combustion engines and waste-heat or direct-fired HACT can provide a hedge against uncertainty of any one fuel source. Many HACT have proven to be more efficient solutions to cooling. The four primary barriers to widespread adoption are first cost, system complexity, inherent efficiency limits, and parasitic power consumption. 1. The generally higher first cost of HACT is the most important barrier to more widespread adoption. The fundamental solutions to this are a major shift in energy prices, which would more dramatically reward energy efficiency over first cost, and economies of scale as more units are made, lowering first cost. 2. Complexity of HACT is often cited as a development barrier, but this issue amounts merely to an engineering challenge which can be overcome given sufficient incentive to commercialize a product. 3. A more fundamental issue with HACT is the limits set by Carnot efficiency – but as this chapter has demonstrated, this is primarily an apparent shortfall, resulting from the erroneous direct comparison of thermal COP and mechanical/electrical COP. Furthermore, when fuel is used sequentially, first in a prime mover or process requiring high temperature, and next in a HACD (or when low-temperature solar heat is used), then the use of HACT can boost the overall fuel efficiency well above what is achievable by conventional systems. 4. A final issue with HACT is parasitic power consumption, which tends to increase as pumps and heat exchangers are added to a HACD to improve the thermal COP. If parasitic power consumption is not smartly managed in the design phase, the electrical consumption of a HACD can end up being comparable to the conventional system it replaces – but this potential pitfall can be overcome by good design. Thus, many of the HACT discussed in this chapter are ready for deployment today, and many more could quickly become widespread given appropriate changes in energy priorities. © Woodhead Publishing Limited, 2011


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11.11 Sources of further information and advice 11.11.1 General – trigeneration Wu and Wang (2006) provide an overview of CCHP technologies for microup to large-scale systems. The European Union-funded PolySMART project (Polygeneration with advanced Small and Medium scale thermally driven Air-conditioning and Refrigeration Technology) has many publications available at www.polysmart.org. Neil Petchers’ Combined Heating, Cooling & Power Handbook (2003) contains two chapters (within Section VII) on absorption cooling and desiccant dehumidification (including solid desiccant beds) and how they are relevant to CHP. Review articles on solar cooling are also relevant due to the interest in low-temperature regeneration shared by solar and small-scale CCHP applications – see Hwang et al. (2008), Kim and Infante Ferreira (2008), and Anyanwu (2003, 2004). Onovwiona and Ugursal (2006) provide an overview of residential CHP prime movers.

11.11.2 General – heat-activated cooling devices The IEA Heat Pump Program Annex 34, ‘Thermally Driven Heat Pumps for Heating and Cooling,’ is scheduled to be completed in 2011 (www. annex34.org). A US Department of Energy-funded report covers thermally activated technologies: see TIAX (2004). Also, the IEA Solar Heating and Cooling Program Task 25, ‘Solar-Assisted Air-Conditioning of Buildings’ dealt largely with low regeneration temperature heat-activated devices, and was completed in 2004 – see Henning (2007) and www.iea-shc.org/task25. Pons et al. (1999) provide a comparative compilation of the performances of various sorption systems for heating, cooling, and refrigeration applications. The International Sorption Heat Pump Conference, originally dedicated to absorption machines, has been expanded to encompass all sorption cooling and dehumidification processes, as well as cogeneration and fundamentals of heat and mass transfer. It is held in various countries approximately every three years since 1982, including Seoul, Korea in 2008 and Padua, Italy in 2011. Many compilations of these conference proceedings are available, including Radermacher et al. (1994), Nikanpour and Hosatte (1996), and Schweigler et al. (1999).

11.11.3 Desiccant dehumidification Munters Corporation produces desiccant-based dehumidification products for industrial, commercial, and residential applications. Brundrett’s Handbook of Dehumidification Technology (1987) provides an overview of traditional desiccant and other dehumidification processes, although specific information



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on low regeneration temperature processes is hard to find. For information on enhanced desiccant processes, including those that handle sensible load, recent academic literature is the best source (see bibliography for starting points). Also the ASHRAE Handbook: Systems (2008, Chapter 23) contains a helpful overview of desiccant dehumidification.

11.11.4 Absorption heat pumps Absorption Chillers and Heat Pumps by Herold et al. (1996) covers the theory and operation of absorption devices. The ASHRAE Handbook: Refrigeration (2006, Chapter 41) contains an overview of absorption chillers, and the ASHRAE Handbook: Fundamentals (2005, Chapter 22) deals with the basics of sorption fundamentals. The IEA Heat Pump Program Annex 24, ‘Absorption Machines for Heating and Cooling in Future Energy Systems’ was completed in 1999 – see www.heatpumpcentre.org – and among their publications is a list of absorption equipment manufacturers. Proceedings from the International Sorption Heat Pump Conference (held every three years) along with articles in the academic literature – particularly in the International Journal of Refrigeration (published by the International Institute of Refrigeration) – provide additional resources.

11.11.5 Adsorption heat pumps There is not a comprehensive reference for adsorption heat pumps, and perhaps the most helpful way to discover more about them is to take a combined approach: for adsorption fundamentals (which are well established owing to their importance in chemical processing), several helpful books are available; and for heat pump application-specific information, more recent review articles in the academic literature provide information. Coverage of adsorption fundamentals can be found in Ruthven’s Principles of Adsorption and Adsorption Processes (1984) and R.T. Yang’s Adsorbents: Fundamentals and Applications (2003). Naturally these volumes do not contain information on the most recent advances in adsorbents (nor do they directly address HACT), but nevertheless have excellent and clear discussions of the classifications of adsorbents, their thermodynamics, equilibrium models, and kinetics. Basmadjian’s Little Adsorption Book: A Practical Guide for Engineers and Scientists (1997) provides a more succinct overview of the fundamentals. With respect to recent advances, Sumathy et al. (2003), Lambert and Jones (2005) and Demir et al. (2008) provide excellent reviews of adsorption heat pump working pairs and cycle enhancements, and also provide useful comparisons to other heat-activated cooling technologies. Power Partners, Inc. is currently manufacturing water/silica gel units in North America of 30



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tons and larger (Power Partners, Inc., 2010). Finally, Yong and Wang (2007) review over 100 patents related to adsorption heat pumps, most issued since 2000.

11.11.6 Ejector refrigeration cycle Well-established ejector performance studies for boiler temperatures of 120–140 °C are readily available; see Chunnanond and Aphornratana (2004a). For low firing temperature ejector cycles, see Sun (1999), Godefroy et al. (2007), Chunnanond and Aphornratana (2004b), Yapıcı and Ersoy (2005) Yapıcı and Yetişen (2007), and Meyer et al. (2009).

11.11.7 Performance metrics Petrov et al. (2004) provide an excellent discussion of efficiency metrics in the context of CCHP systems with case study examples. Carnot COPs and efficiencies of various heat-activated devices are derived in Herold et al. (1996). Tozer and James (1997) derive performance limits for multiple effect machines, and Meunier et al. (1997) discuss the theoretical performance limits for adsorption heat pumps. For desiccant wheels, Mandegari and Pahlavanzadeh (2009) discuss conventional metrics and propose new ones.

11.12 References American Society of Heating Refrigeration and Air Conditioning Engineers (ASHRAE) (2005) ASHRAE Handbook: Fundamentals. American Society of Heating Refrigeration and Air Conditioning Engineers (ASHRAE) (2006) ASHRAE Handbook: Refrigeration. American Society of Heating Refrigeration and Air Conditioning Engineers (ASHRAE) (2008) ASHRAE Handbook: Systems. Anyanwu, E. E. (2003) ‘Review of solid adsorption solar refrigerator I: an overview of the refrigeration cycle’, Energy Conversion and Management, 44(2), 301–312. Anyanwu, E. E. (2004) ‘Review of solid adsorption solar refrigeration II: an overview of the principles and theory’, Energy Conversion and Management, 45(7–8), 1279–1295. Basmadjian, D. (1997) The little adsorption book: a practical guide for engineers and scientists, Boca Raton, FL: CRC Press. Brundrett, G. W. (1987) Handbook of dehumidification technology, London: Butterworths. Chunnanond, K. and Aphornratana, S. (2004a) ‘An experimental investigation of a steam ejector refrigerator: the analysis of the pressure profile along the ejector’, Applied Thermal Engineering, 24(2–3), 311–322. Chunnanond, K. and Aphornratana, S. (2004b) ‘Ejectors: applications in refrigeration technology’, Renewable and Sustainable Energy Reviews, 8(2), 129–155. Demir, H., Mobedi, M. and Ülkü, S. (2008) ‘A review on adsorption heat pump: problems and solutions’, Renewable and Sustainable Energy Reviews, 12(9), 2381–2403.



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Douss, N. and Meunier, F. (1989) ‘Experimental study of cascading adsorption cycles’, Chemical Engineering Science, 44(2), 225–235. Godefroy, J., Boukhanouf, R. and Riffat, S. (2007) ‘Design, testing and mathematical modelling of a small-scale CHP and cooling system (small CHP-ejector trigeneration)’, Applied Thermal Engineering, 27(1), 68–77. Henning, H.-M. (ed.) (2007) Solar-assisted air-conditioning in buildings: a handbook for planners, 2nd rev. edn, London: Springer. Henning, H.-M., Pagano, T., Mola, S. and Wiemken, E. (2007) ‘Micro tri-generation system for indoor air conditioning in the Mediterranean climate’, Applied Thermal Engineering, 27, 2188–2194. Herold, K. E., Radermacher, R. and Klein, S. A. (1996) Absorption Chillers and Heat Pumps, Boca Raton, FL: CRC Press. Hwang, Y., Radermacher, R., Al Alili, A. and Kubo, I. (2008) ‘Review of solar cooling technologies’, HVAC & R Research, 14, 507–528. Kim, D. S. and Infante Ferreira, C. A. (2008) ‘Solar refrigeration options – a state-ofthe-art review’, International Journal of Refrigeration, 31(1), 3–15. Kodama, A., Hirose, T. and Okano, H. (2003) Low-temperature heat driven adsorptive desiccant cooling improved for the use in humid weather, translated by Saha, B., Akisawa, A. and Koyama, S., Fukuoka, Japan. Lambert, M. A. and Jones, B. J. (2005) ‘Review of regenerative adsorption heat pumps’, Journal of Thermophysics and Heat Transfer, 19(4), 471–485. Mandegari, M. A. and Pahlavanzadeh, H. (2009) ‘Introduction of a new definition for effectiveness of desiccant wheels’, Energy, 34, 797–803. Meunier, F., Poyelle, F. and LeVan, M. D. (1997) ‘Second-law analysis of adsorptive refrigeration cycles: the role of thermal coupling entropy production’, Applied Thermal Engineering, 17(1), 43–55. Meyer, A. J., Harms, T. M. and Dobson, R. T. (2009) ‘Steam jet ejector cooling powered by waste or solar heat’, Renewable Energy, 34(1), 297–306. Ng, K. C., Chua, H. T., Chung, C. Y., Loke, C. H., Kashiwagi, T., Akisawa, A. and Saha, B. B. (2001) ‘Experimental investigation of the silica gel-water adsorption isotherm characteristics’, Applied Thermal Engineering, 21(16), 1631–1642. Nikanpour, D. and Hosatte, S. (1996) Conference Proceedings: International Absorption Heat Pump Conference, Montreal, Canada, September 17-20, 1996, Québec: CANMETEDRL, Natural Resources Canada. Onovwiona, H. I. and Ugursal, V. I. (2006) ‘Residential cogeneration systems: review of the current technology’, Renewable and Sustainable Energy Reviews, 10(5), 389–431. Petchers, N. (2003) Combined heating, cooling & power handbook: technologies & applications: an integrated approach to energy resource optimization, Lilburn, GA: Fairmont Press. Petrov, A. Y., Zaltash, A., Labinov, S. D., Rizy, D. T., Liao, X. and Radermacher, R. (2004) Evaluation of different efficiency concepts of an integrated energy system (IES), Anaheim, CA: American Society of Mechanical Engineers, 347–356. Pons, M., Meunier, F., Cacciola, G., Critoph, R. E., Groll, M., Puigjaner, L., Spinner, B. and Ziegler, F. (1999) ‘Thermodynamic based comparison of sorption systems for cooling and heat pumping’, International Journal of Refrigeration, 22(1), 5–17. Power Partners, Inc. (2010) ‘Eco-Max Adsorption Chillers’, [online], available at: http:// www.eco-maxchillers.com/ (accessed June 2010). Radermacher, R., Herold, K., Miller, W., Perez-Blanco, H., Ryan, W. and Vleit, G. (1994) Proceedings of the International Absorption Heat Pump Conference, translated by New Orleans, Louisiana: American Society of Mechanical Engineers, viii, 534 p. © Woodhead Publishing Limited, 2011


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Ruthven, D. M. (1984) Principles of adsorption and adsorption processes, New York: Wiley. Schinner Jr, E. N. and Radermacher, R. (1999) ‘Performance analysis of a combined desiccant/absorption air-conditioning system’, HVAC and R Research, 5, 77–84. Schweigler, C., Summerer, S., Hellman, H.-M. and Ziegler, F., eds. (1999) Proceedings of the International Sorption Heat Pump Conference, March 24-26, 1999, Munich, Germany, Lang Offsetdruck GmbH. Sumathy, K., Yeung, K. H. and Yong, L. (2003) ‘Technology development in the solar adsorption refrigeration systems’, Progress in Energy and Combustion Science, 29(4), 301–327. Sun, D.-W. (1999) ‘Comparative study of the performance of an ejector refrigeration cycle operating with various refrigerants’, Energy Conversion and Management, 40(8), 873–884. TIAX (2004) Review of Thermally Activated Technologies.A Distributed Energy Program Report for the US DOE Office of Energy Efficiency and Renewable Energy, TIAX LLC. Tozer, R. M. and James, R. W. (1997) ‘Fundamental thermodynamics of ideal absorption cycles’, International Journal of Refrigeration, 20(2), 120–135. Wu, D. W. and Wang, R. Z. (2006) ‘Combined cooling, heating and power: a review’, Progress in Energy and Combustion Science, 32(5–6), 459–495. Yang, R. T. (2003) Adsorbents: fundamentals and applications, Hoboken, NJ: WileyInterscience. Yapıcı, R. and Ersoy, H. K. (2005) ‘Performance characteristics of the ejector refrigeration system based on the constant area ejector flow model’, Energy Conversion and Management, 46(18–19), 3117–3135. Yapıcı, R. and Yetişen, C. C. (2007) ‘Experimental study on ejector refrigeration system powered by low grade heat’, Energy Conversion and Management, 48(5), 1560–1568. Yong, L. and Wang, R. Z. (2007) ‘Adsorption refrigeration: a survey of novel technologies’, Recent Patents on Engineering, 1(1), 1–21.

11.13 Bibliography Alefeld, G. and Radermacher, R. (1994) Heat conversion systems, Boca Raton, FL: CRC Press. Angrisani, G., Minichiello, F., Roselli, C. and Sasso, M. (2010) ‘Desiccant Hvac system driven by a micro-CHP: experimental analysis’, Energy and Buildings, 42(11), 2028–2035. Bejan, A. (1982) Entropy generation through heat and fluid flow, New York: Wiley. Castro, J., Oliva, A., Carlos David, P.-S. and Oliet, C. (2008) Recent developments in the design of a new air-cooled, hot-water-driven H2O-LiBr absorption chiller, New York: American Society of Heating, Refrigeration and Air Conditoning Engineers, 288–299. Castro, J., Oliva, A., Perez-Segarra, C. D. and Oliet, C. (2008) ‘Modelling of the heat exchangers of a small capacity, hot water driven, air-cooled H2O-LiBr absorption cooling machine’, International Journal of Refrigeration, 31, 75–86. Dinçer, I. (2003) Refrigeration Systems and Applications, New York: John Wiley and Sons.



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Goodheart, K. A. (2000) Low Firing Temperature Absorption Chiller System, unpublished thesis, University of Wisconsin-Madison. Gulen, S. C. (2010) ‘A proposed definition of CHP efficiency’, POWER Magazine, June. Huangfu, Y., Wu, J. Y., Wang, R. Z. and Xia, Z. Z. (2007) ‘Experimental investigation of adsorption chiller for micro-scale BCHP system application’, Energy and Buildings, 39(2), 120–127. Jin, W., Cun Nan, L., Jian Hua, L., Si Chang, L. and Jun, C. (2009) A New Air-Conditioning System of Liquid Desiccant and Evaporation Cooling, Power and Energy Engineering Conference, 2009. APPEEC. Kim, D. S. and Infante Ferreira, C. A. (2003) Solar Absorption Cooling, 1st progress report for NOVEM, October, Delft University of Technology. Kong, X. Q., Wang, R. Z. and Huang, X. H. (2004) ‘Energy efficiency and economic feasibility of CCHP driven by Stirling engine’, Energy Conversion and Management, 45(9–10), 1433–1442. Liao, X. (2004) The development of an air-cooled absorption chiller concept and its integration in CHP systems, unpublished thesis, University of Maryland. Mei, V. C., Chen, F. C., Lavan, Z., Collier, R. K. and Meckler, G. (1992) An assessment of desiccant cooling and dehumidification technology, Oak Ridge National Laboratory, US Department of Energy. Mitsubishi Plastics (2008) ‘Zeolitic water vapor adsorbent AQSOA’, available at: http:// www.aaasaveenergy.com/products/001/pdf/AQSOA_1210E.pdf Nayak, S. M. (2005) Experimental and theoretical investigation of integrated engine generator–liquid desiccant system, unpublished thesis, University of Maryland. Nayak, S. M., Hwang, Y. and Radermacher, R. (2009) ‘Performance characterization of gas engine generator integrated with a liquid desiccant dehumidification system’, Applied Thermal Engineering, 29(2–3), 479–490. Nia, F. E., van Paassen, D. and Saidi, M. H. (2006) ‘Modeling and simulation of desiccant wheel for air conditioning’, Energy and Buildings, 38(10), 1230–1239. Niu, J. L. and Zhang, L. Z. (2002) ‘Effects of wall thickness on the heat and moisture transfers in desiccant wheels for air dehumidification and enthalpy recovery’, International Communications in Heat and Mass Transfer, 29(2), 255–268. Peltier, R. V. (2001) ‘How efficient is ‘efficiency’?’, POWER Magazine, 145(2), 105. Peltier, R. (2010) ‘Plant efficiency: begin with the right definitions’, POWER Magazine, February. Saha, B. B., Akisawa, A. and Koyama, S. (2003) Proceedings of the International Seminar on Thermally Powered Sorption Technology, December 4–5, 2003, Chikushi Campus, Kyushu University, Fukuoka, Japan. Srikhirin, P., Aphornratana, S. and Chungpaibulpatana, S. (2001) ‘A review of absorption refrigeration technologies’, Renewable and Sustainable Energy Reviews, 5(4), 343–372. Sumathy, K., Huang, Z. C. and Li, Z. F. (2002) ‘Solar absorption cooling with low grade heat source – a strategy of development in South China’, Solar Energy, 72(2), 155–165. Wang, R. Z. (2001) ‘Adsorption refrigeration research in Shanghai Jiao Tong University’, Renewable and Sustainable Energy Reviews, 5(1), 1–37. Zhang, X. J., Dai, Y. J. and Wang, R. Z. (2003) ‘A simulation study of heat and mass transfer in a honeycombed rotary desiccant dehumidifier’, Applied Thermal Engineering, 23(8), 989–1003.



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11.14 Appendix 1: Nomenclature and abbreviations AC – air conditioning CCHP – combined cooling, heating and power CHP – combined heating and power CI – compression ignition COP – coefficient of performance DHW – domestic hot water DW – desiccant wheel FC – fuel cell FCP – fuel chargeable to power GAX – generator-absorber exchange HACT – heat-activated cooling technology HACD – heat-activated cooling device HHV – higher heating value of a fuel HR – heat recovery HVAC – heating, ventilation and air conditioning HX – heat exchanger ICE – internal combustion engine IEA – International Energy Agency, founded 1974 by the OECD LHV – lower heating value of a fuel ORC – organic Rankine cycle MT – microturbine PEMFC – proton exchange membrane fuel cell PM – prime mover, the primary fuel conversion device in a CHP system PURPA – Public Utilities Regulatory Policies Act of 1978 RH – relative humidity RT – refrigeration ton, equivalent to 3517 W or 12 000 Btu/hr of cooling capacity SEER – seasonal energy efficiency ratio SI – spark ignition SOFC – solid oxide fuel cell T – temperature (°C) or (°F) or (K) or (R) VCC – vapor compression cycle W – work, usually electrical energy or power (kW) e – effectiveness (dimensionless) h – efficiency (dimensionless) w – humidity ratio (gH2O/kgdry air)

11.15 Appendix 2: Notes on terminology ‘Trigeneration’ and ‘combined cooling, heating and power (CCHP)’ are used interchangeably in this chapter. Additional equivalent terms in use include



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‘combined heating, cooling and power (CHCP)’ and ‘cooling, heating and power (CHP)’ (in this chapter CHP is used to mean combined heat and power, exclusive of cooling). More comprehensive terms in use include polygeneration and integrated energy systems (IES). ‘Heat-activated cooling technology/technologies (HACT)’ and ‘heatactivated cooling device(s) (HACD)’ are used interchangeably, as appropriate, in this chapter. Additional equivalent terms in use include ‘heat-driven’, ‘thermally-activated’, and ‘thermally-driven’, combined with either ‘cooling’, ‘refrigeration’, ‘chillers’, and/or ‘technology/device’, giving rise to an abundance of equivalent potential abbreviations such as TAT, TAC, TDC, etc.



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12

Energy storage for small and micro combined heat and power (CHP) systems

A. p r i c e, Swanbarton Ltd, UK

Abstract: Several types of energy storage technologies are described and assessed for their suitability for applications alongside CHP systems. The technical and commercial requirements are described. Distributed energy storage is also a means of providing grid or network services which can provide an additional economic benefit from the storage device. Electrical energy storage is shown to be a complementary technology to CHP systems and may also be considered in conjunction with, or as an alternative to, thermal energy storage. Key words: energy storage, electricity storage, thermal storage.

12.1

Introduction

The use of energy storage on power systems has been limited due to technical and commercial considerations. Early power systems relied on extensive use of batteries, mostly of the lead acid accumulator type, in order to provide stability and simplify operation. The change from direct current local systems to interconnected alternating current systems caused the demise of night storage accumulators as AC to DC conversion was limited to rotary convertors. Today large-scale energy storage is mostly represented by pumped hydroelectricity storage – with a worldwide capacity of more than 100 GW – and some network connected battery storage and other types of energy storage systems. Non-grid connected systems tend to have more examples of battery storage – as shown by remote farms or ranches using batteries to run lighting circuits when the generator is not running. The predominant use of smaller scale energy storage is for uninterruptible power supplies (UPS) – systems based on batteries, flywheels, and fuel cells are all in use. There is considerable interest in energy storage – the perceived applications include energy management, islanding capability and power trading.

12.1.1 Energy management applications Energy management applications include storing ‘off peak’ generated electricity for use at a later time, where ‘off peak’ may refer to time of day 307 © Woodhead Publishing Limited, 2011


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(such as overnight), times when a power market price for energy is low or where a producer may not have a use or demand for the energy. Popular attention is drawn to energy management because of the perceived need to store surplus electricity which may be generated from mini farms or other remote resources.

12.1.2 Islanding capability applications Islanding capability applications would enable a small power system comprised of a generator, store and load to operate either as part of a network, or independently in the event of a network failure. A co-generation project, where a CHP installation operates in a grid connected mode will often be required to disconnect itself from the network in the event of a network failure. This disconnection is required to protect the network (and those working on it) from power re-energising a section of line which might be expected to be inactive. In order to provide islanding capability, a local cogeneration project would need to have isolated systems for disconnection and a safe, and approved means of reconnecting to the network when the external power supply is restored.

12.1.3 Power trading Power trading is the action of buying energy from the market at a low cost and selling it at a higher cost at a later time. Sometimes known (incorrectly) as energy arbitrage, as it is an inter-temporal process, the financial parameters involved require a significant knowledge of, and investment in, energy trading.

12.2

Types of energy storage (ES) systems

12.2.1 Definition and scope Although energy can be stored in many forms, for the purposes of this chapter, the scope will be limited to those devices that will be charged by electrical means and when discharged, convert the stored energy back to electrical energy. This scope excludes the use of hydrogen and fuel cell systems which are described in another chapter. Energy storage is defined as the conversion of electrical energy from a power network into a form in which it can be stored until converted back to electrical energy. For completeness, a section has been included on thermal energy storage and the overlap between this and electrical energy storage.



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12.2.2 Overview of types Energy storage systems can be classified in many ways, by type of storage medium, by size, applications or commercial status (Table 12.1). Many energy storage technologies are modular, and assembled from a number of components arranged in series and parallel. By its nomenclature, a battery is a collection of cells – the largest batteries assembled are in the order of tens of MW and hundreds of MWh, although most would be in the size range up to about 10 MW. Capacitors for energy storage tend to be grouped in smaller installations by power rating, and their storage capacity is limited. Electrolysers and fuel cells have been installed in MW size installations and, where there is large-scale fuel storage, the energy capacity can be measured in hours or days. Flywheel systems are also becoming larger. While industrial machines are rated in tens or hundreds of kW, installations of 10 or 20 MW are now under construction.

12.3

Applications of electrical energy storage

An energy storage device can be used to: ∑ ∑

provide power over short durations – seconds or minutes provide power over longer durations – minutes to hours or days

In order to keep a power system stable, generation must equal demand plus losses at all times. If generation falls, voltage and frequency drop, machines slow down, lights dim and eventually the system fails. At the other extreme, if generation exceeds demand and losses, the effects can be catastrophic. A short duration interruption, even of an AC cycle (0.02 seconds at 50 Hz) can cause damage to computers, computer controlled equipment and precision machinery. Customers protect themselves against this occurrence by installing uninterruptible power supplies (UPS).

12.3.1 Types of uninterruptible power supply (UPS) Most commercial UPS systems consist of three sub-systems: ∑

an energy storage device, usually a flywheel or battery with an AC/DC power conversion system ∑ switchgear and isolators ∑ a separate generator which can be started to provide resilience of supply beyond the energy storage capacity of the storage device. These can be installed to protect a single load, such as a computer, or to protect larger installations such as offices, shops or factories. UPS systems to protect domestic computers are readily available from



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Not yet available

e.g. MeOH, chemical hydrides

Chemical

Other storage media

Commercially Power quality available Standby power Commercially available Power quality Commercially available Multi functional Commercially Multi functional available Commercially available Multi functional Early stage of commercialisation Multi functional Early stage of Remote area commercialisation applications Early stage of commercialisation

Electro- Low temperature Lead acid chemical batteries NiCd Lithium cells High temperature Sodium batteries sulphur Sodium nickel chloride Flow batteries Zinc bromine Vanadium Hydrogen Electrolyser/fuel cycle cell combination

Mechanical Potential energy Pumped hydro Mature in storage medium Compressed air energy Mature technology, but storage (CAES) limited commercial take-up Kinetic energy in Low speed Commercially storage medium flywheels available Advanced Commercially flywheels available

No

Yes

Yes Yes Yes

Yes Yes Yes

Yes

Yes

Yes

Potential

No

No

Power quality, reliability Energy management, reserve Energy management, reserve Uninterruptible power supplies Power quality/ Energy management

Yes

Power quality

Early stage commercial Some commercial examples

Electrical Capacitors Super conductors

Capacitors and ultracapacitors Superconducting Magnetic Energy Storage (SMES)

Relevance to small-scale CHP and distributed generation

Type Sub-group Examples Development Typical status applications

Table 12.1 The development status of energy storage devices



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Thermal

Hot water Commercially available Ceramics Commercially available Molten Early stage of commercialisation salt/ steam Ice Commercially available Thermal storage Under development and heat engines

Peak shaving Peak shaving Integration of renewables Peak shaving Energy management Yes Potential

Yes Yes Yes

312


computer stores. They are installed between the domestic wall socket and the computer using standard plugs. Care needs to be taken to ensure that the UPS has the power capacity (kW) required to sustain the computer, or other device, as well as the energy rating to provide resilience against the duration of the power interruption. Typically this is of the order of 15 minutes, which is sufficient to close down a computer safely. Increasing the discharge duration increases the cost of these systems significantly. Modern computers are now often rated at lower powers than earlier machines, thereby either increasing the resilience time, or decreasing the cost of the energy storage system. These devices are usually based on valve regulated lead acid batteries, which provide a cost effective solution with low maintenance. In many instances, a commercial or industrial scale UPS is supplemented by a standby generator, which is started after 1 or 2 minutes. This continues to supply the load for as long as there is fuel. For some of those larger installations, flywheels are used as an alternative to batteries. The flywheel might be integrated with the standby generator, which improves reliability by directly linking the mechanical systems. While UPS solve the technical problems caused by interruptions to the power supply, some equipment requires a very stable, continuous power supply with no fluctuation to the expected smooth voltage profile. This higher performance is achieved by specifying increased standards for the power conversion system. For many small systems, this will be hidden from the user, but will be of significance for medium and larger-scale projects.

12.3.2 Types of energy storage technologies for integration with CHP systems Smaller-scale systems in use for small- and micro-CHP projects are unlikely to make use of larger-scale technologies such as pumped hydro or underground compressed air energy storage directly, but if the CHP systems are connected to the grid network, they will, of course, be making indirect use of such systems. This point is often overlooked – that introducing electricity storage at any point in the network has an impact through the system. The conceptual difficulty is that finance does not always follow the flow of electrons in an equitable manner. The location and ownership of the storage device are prime considerations in the financial analysis of the storage device. The installer or operator may not gain an economic return on the whole value of the investment.

12.3.3 Mechanical systems Flywheels have been available as UPS for many years, but some developers are now offering these as energy storage devices in their own right. Flywheels



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are typically characterised as either high speed or low speed. As the energy storage capacity is proportional to the square of the rotational speed, increasing the speed is an effective method of increasing the capacity of the system. Flywheel systems would have a high cycle lifetime, low maintenance costs and would have simple requirements in terms of siting. The interface to the power network is usually based on a variable frequency power conversion system, which can accommodate changes in the flywheel speed, but producing a constant frequency power output. Although the maximum energy storage capacity of the flywheel is fixed by the parameters of the rotary mass, the power rating and hence the discharge time can be varied, so that it is feasible to consider flywheels with a low power rating but a discharge time measured in terms of minutes or even hours. Figure 12.1 shows a matrix of large scale flywheels operating in combined mode connected to the power network to provide 1 MW of power for frequency regulation. Figure 12.2 illustrates the size of a single 50 kW flywheel system. There are currently two large-scale compressed air energy storage (CAES) plants operating. Figure 12.3 shows the 110 MW CAES plant built in McIntosh, Alabama, USA that has been operating since 1991. Although large scale (100+ MW) compressed air systems are considered out of scope for small-scale CHP applications, MW scale compressed air installations are now being considered. EPRI expects to run a demonstration MW scale CAES plant using air storage in above ground pipes (derived from the oil and gas industry). Figure 12.4. illustrates a typical system diagram.

12.1 A 1 MW flywheel energy store system under construction in New York State (source: Beacon Power Corporation).



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12.2 A 50 kW demonstration flywheel.

12.3 CAES Plant, Alabama (source: EPRI).



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Exhaust

Heat exchanger Inlet Clutch

Clutch Motor/generator

Compressor Combustor fuel

Turbine/ expander

Underground air storage

12.4 Diagram of a typical CAES system.

12.4

Applications for combined heat and power (CHP) systems

12.4.1 Establishment scale CHP systems are usually installed on premises where there is a constant heat load, and, ideally, reasonably constant electrical load. Many CHP systems installed in the past 20 years have considered the electricity generated as a useful byproduct and not the main reason for installing the plant. The purpose of integrating energy storage is to optimise the generation and onsite consumption of electricity with the use of the storage device and energy exchanges with the network. The analysis is dependent on a number of factors: ∑ ownership and operation of the CHP plant ∑ ownership and operation of the energy storage plant ∑ whether the installation is a net product or consumer of electricity ∑ the commercial arrangements for import and export of electricity. The costs may be considerably lower to install a new CHP/storage system than retrofitting storage to an existing installation. More recently, with the



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drive towards sustainability, more businesses and organisations are striving to become energy neutral or self-sufficient in energy. Such considerations can influence decisions, making it possible to consider the use of storage even when the investment is not rewarded by payback.

12.4.2 Domestic scale For small installations, such as houses or apartment blocks, installing storage may have severe impacts on the economics of the heating system. As CHP installations may receive feed in tariffs for on-site production under the arrangements for micro power, there is little incentive to use on-site storage unless the import purchase price exceeds the value of the feed in tariff when multiplied by the inverse of the efficiency of the storage device. The Japanese research group CRIEPI (Central Research Institute of the Electric Power Industry) is undertaking active development work to introduce battery energy storage into all-electric houses which use heat pumps as the heating source. The control system will also be adapted to permit the introduction of electric and plug-in hybrid vehicles.

12.4.3 The economic case If such CHP systems are not eligible for feed-in tariff support, then the financial calculation is simplified, and the benefit can be expressed in terms of the difference between the value of exported power against the price of imported power.

For example: Exported power

25% round trip efficiency loss

1 kWh = £0.06

1 kWh to store = 0.75 kWh output

£0.06 = £0.08 0.75 On peak purchase price of imported power = £0.12/kWh

Effective cost of stored power =

Such economics ignore the following: ∑ capital cost of the energy storage equipment ∑ capital cost of the installation ∑ annual operating costs (maintenance, insurance, rates, rent of additional land) ∑ trading costs ∑ other grant aid. Integrating CHP with electrical energy storage is therefore only likely to happen if there are very simple trading arrangements (for example, based on



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net metering), or if the installation is large enough to justify either trading costs directly or when traded through an aggregator.

12.4.4 Costs of storage The cost of an energy storage installation is dependent on a number of factors. For a relatively simple installation, such as a domestic UPS system where a device may be purchased from a catalogue and installation costs are low, it is easy to estimate the overall project cost. As soon as the project enters a bespoke phase, costs have a tendency to increase as specialist skills and equipment are required. Costs will be lower when established technologies such as lead acid batteries or ice storage are used. Advanced batteries, such as lithium chemistries, high temperature batteries or flow batteries will have much higher costs. The costs of the power conversion system and switchgear may be between 50 and 100% of the cost of the battery.

12.5

Grid services applications and relationship to combined heat and power (CHP)

Grid services fall into two broad groups ∑ ∑

localised services, such as voltage control system services, such as frequency regulation and reserves.

Distributed generation can have positive and negative effects on the operation of a distribution network. Traditionally, distribution networks have been installed on the basis of a radial system, with power generated centrally and distributed to users through the distribution network. Voltages were set so that the consumers at the end of each distribution line were served with an electrical supply that was within the regulated limits (230 V ± 10%). Adding distributed generation to the extremities of the network can significantly alter the voltage at points on the network. The power electronics associated with a storage device can be used to mitigate these effects, maintaining the voltage within the defined limits. However, such services are the responsibility of the distribution company and a private owner of storage would not normally be expected to provide these services. The transmission system operator has a duty to maintain the system frequency within defined limits. In order to do this, the system must be kept in balance, that is, generation must match demand, plus losses. The system is balanced for energy across trading periods (30 minutes in Great Britain) and constantly for power. In Great Britain, the National Grid Company instructs generating companies and demand customers to increase and decrease their supply and demand to maintain the balance. These participants use a variety



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of different contracts depending on the type of service being provided. Examples of these services include: ∑ ∑

frequency response short-term operating reserve.

An owner of a CHP plant could contract for these services, but the addition of a storage plant makes it easier to provide those services without necessarily imposing on the operation of the CHP plant. In many instances it may be possible to provide these services for a few hours each day.

12.6

Electrical vehicles

There is considerable interest in the use of electric vehicles as a means of decarbonising the power network. The assumption is that the energy used to charge the electric vehicles will be generated from the sustainable resources. Operators of CHP plant, especially where there is a variable demand for electricity, may be able to balance the heat and electrical load, particularly at off-peak periods, by charging electric vehicles. Many sustainable resources, such as solar photovoltaic and wind are variable and not continuous and it is appropriate to consider the use of storage as a means of not spilling electricity. However, this should be balanced against the use of the grid as a sink for such electricity and as a source for generation. An example of a battery system is shown in Fig. 12.5. The vanadium battery is charged from an associated PV panel. The stored energy is used exclusively to charge a fleet of electrically powered motorbikes.

12.7

Large-scale and small-scale storage – conceptual planning

Many different models can be postulated for the installation of energy storage and these also relate to its integration with CHP. Whilst the most impact is obtained by placing the storage as close to the end consumer as possible (as this aggregates the benefit of storage from the consumer back to the source of generation), economies of scale may mean that the specific costs of installing storage at the consumer’s point of connection is high. Savings could be made by introducing storage at higher levels in the distribution network, not only in specific equipment and capital costs, but also in trading and other commercial costs.

12.8

The development and application of thermal storage

This chapter has considered the case of using a storage medium as the intermediate stage between electricity charge and discharge. It is quite © Woodhead Publishing Limited, 2011


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12.5 Vanadium battery (source: Cellstrom).

possible to use a storage device which uses thermal storage as the intermediate medium, and such thermodynamic cycles are under development. One modification is to use heat as the charging method, and this is adapted in the molten salt storage system typically installed in conjunction with solar concentrating thermal plants (see Fig. 12.6). The concentrated solar radiation is used to raise the temperature of a molten salt, which is contained in wellinsulated containers. During periods of darkness, the molten salt is used to raise steam which drives a turbine to generate power. Another modification is to use the heat directly, without recourse to generating electricity. This reduces the efficiency loss of the overall system. This is similar to the principle of the night storage heater, which was popular in Britain in the 1960s. Bricks were heated by electricity at night, and an arrangement of vents was used to allow the heat to warm the house over the next 17 hours. The premise was economics – the electricity generated at night from base load generating plant (coal and nuclear) was at lower cost than supplying power from peaking plant during the afternoon and early evening peak. Customers received an incentive in that night time electricity was at lower cost than the normal day time rate. Domestic thermal storage is still available, and the aesthetics and performance of the devices have improved considerably. Where a self-producer of electricity has a heat requirement,



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(a)

(b)

12.6 (a) Parabolic trough collectors, Almeira Spain (source: SPIE). (b) Experimental solid media storage unit with a capacity of 400 KWh (source: SPIE).

it would be quite feasible to use thermal energy storage as a means of time shifting energy production to suit the consumer’s demand profile. A further variation is to use off-peak – or surplus – electricity to produce ice. During peak periods, air can be blown over the ice or through cooling loops to cool buildings, saving on the use of the full air conditioning load.



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Some commercial buildings, such as supermarkets and cold stores could also use the large thermal version of deep freezers and refrigerators as a proxy store. Thermal storage appears to the grid as a demand customer and can therefore contribute to the supply of resources by shutting off demand, and also to respond to high frequency events by switching on, when necessary. A recently announced development in the United States links a 5 MW concentrated solar power plant with a thermal storage plant at the ‘Solar Zone’ which is part of the University of Arizona Science and Technology Park. This large project has an estimated cost of more than $32 million.

12.9

Future trends

The smart grid is seen as a way of integrating all forms of generation and demand to operate the network in the most efficient manner. Some include a vision of control of industrial loads, even at and before domestic level and the incorporation of a smart meter which has time of day pricing. At the distribution and transmission level the transformers, switchgear and lines and cables are controlled to ensure that lines are run under optimum conditions and variable generation is used effectively. This complex vision can be simplified by the use of storage at key points in the network. American Electric Power (AEP) propose the introduction of Community Energy Storage (see Fig. 12.7) where storage is located at the local distribution transformer. The store acts as a local buffer, aggregating distributed generation and demand on the circuits downstream of the share.

12.7 Community Energy Storage: 5 kW, 20 kWh Community Energy Storage by Redflow Technologies Ltd.



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The Community Energy Storage is controlled by the network, charged and discharged to provide a stable power flow from the utility into, or out of, the battery. AEP see that this buffer will protect this network from the large and variable power flows that may arise from the introduction of electric vehicles and domestic charging.

12.10 Sources of further information and advice Electricity Storage Association: www.electricitystorage.org Department of Energy and Climate Change: www.decc.gov.uk Feed in tariffs: see DECC announcement http://www.decc.gov.uk/en/content/ cms/news/pn10_010/pn10_010.aspx (accessed 1 February 2010). Energy Saving Trust: www.energysavingtrust.org.uk Numerous renewable energy equipment suppliers.



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13

Micro combined heat and power (CHP) systems for residential and small commercial buildings

J. H a r r i s o n, E.ON Engineering, UK

Abstract: The principal market for micro-CHP is as a replacement for gas boilers in the 18 million or so existing homes in the UK currently provided with gas-fired central heating systems. In addition there are a significant number of potential applications of micro-CHP in small commercial and residential buildings. In order to gain the optimum benefit from micro-CHP, it is essential to ensure that an appropriate technology is selected to integrate with the energy systems of the building. This chapter describes the key characteristics of the leading micro-CHP technologies, external and internal combustion engines and fuel cells, and how these align with the relevant applications. Key words: Stirling engine, internal combustion engine, fuel cells, microCHP.

13.1

Introduction

It is widely held that the principal market for micro-CHP is as a direct replacement of around 12 million of the 18 million gas central heating boilers, representing potential annual sales of up to 1.5 million units. This is based on the premise of simple economic payback of the investment cost of the product recoverable within an acceptable period for a 1 kWe Stirling engine micro-CHP package.1 Whilst a useful metric, it is rather simplistic, does not hold true for other micro-CHP technologies, and takes no account of potential applications in other building types. Micro-CHP derives its principal environmental and economic benefit from generating electricity as a byproduct of an existing thermal load. It replaces the gas boiler in a hydronic central heating system, producing space and water heating just as the boiler might do. It requires a primary fuel input and does not claim to be renewable, but is a low carbon and extremely energy efficient technology. As might be expected, the micro-CHP product has a higher initial cost than the boiler it replaces and must recover this cost from the value of the electricity it produces. Clearly, the more electricity that can be produced from a given thermal load, the higher the electrical output and the consequent operational income. However, it is almost invariably true 325 © Woodhead Publishing Limited, 2011


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that the higher the electrical output, the higher the capital cost so that here is both a compromise in the quest for electrical efficiency in producing a product at an appropriate cost and a natural match for different technologies to different thermal loads. The principal technologies considered relevant to mass market micro-CHP are internal combustion engines (ICE), external combustion engines (such as Stirling engines) and fuel cells. Of the latter, the high electrical efficiency and potential for low capital cost make SOFC (solid oxide fuel cells) the most promising fuel cell technology, although these are still at a relatively early stage of development and there are no commercially available products in the UK or Europe. Each of these technologies has characteristics making it more or less applicable to differing building types and thermal load profiles. However, micro-CHP is still a relatively immature technology and products continue to be developed to fulfil the requirements of various market sectors, able to compete more effectively with alternatives such as gas boilers, heat pump and larger-scale CHP technologies.

13.2

Basic issues and energy requirements

Although there are certain characteristics which make applications more or less attractive and viable, there are also some fundamental criteria which must be fulfilled to make an application viable. These include fuel availability, adequate thermal demands and an accommodating regulatory environment.

13.2.1 Economic rationale for micro-CHP The most fundamental economic factor required for viability of micro-CHP is that it must be able to recover the initial investment from the value of the electricity produced in lieu of heat from the primary fuel. It therefore holds true that the value of electricity must exceed that of heat by a significant amount. The ratio of electricity and gas prices is commonly known as ‘spark spread’ and, whilst it is generally the case that this ratio is around 3:1, reflecting in part the dominance of gas as a primary fuel input to central generating plant, it is not the case in countries such as Norway and Sweden where there is no widely available natural gas network, but an abundance of low cost hydroelectric power. In countries such as the UK, however, where retail electricity prices are around 11p/kWh and gas 3.5p/kWh, the cost of heat produced in a gas boiler with 90% efficiency is just under 4p/kWh. Thus, assuming the total efficiency of the micro-CHP unit to be equivalent to that of the gas boiler, each unit of electricity produced costs the consumer the lost opportunity cost of one unit of heat (4p), but is worth the value of displaced electricity



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(11p) assuming further that the electricity is consumed within the home and not exported. Each unit of electricity thus generates a net income of 7p; an annual production of 3000 kWh is worth up to £210. For domestic investments, this could justify a marginal capital cost of around £600 for the mass market of consumers who require a three-year payback and up to £1000 for a smaller proportion of the market who are satisfied with a payback of five years. Considering that the average UK householder moves home every seven to eight years on average, even an investment of £1500 would seem rational and early adopters of other microgeneration technologies such as PV have been prepared to invest with paybacks in excess of a century as an environmental gesture! Figure 13.1 illustrates the simplified concept of electricity generation at the expense of heat for the major micro-CHP technologies. The importance of this is that the value of each unit of electricity produced is the same (in both economic and environmental terms) regardless of the technology or its electrical efficiency; a higher electrical efficiency product will generate more units of electricity for a given heat load (and will consequently consume proportionately more gas) so that its overall income is higher, but the value per kWh of electricity is exactly the same. This belies the widely held, but erroneous view that low efficiency micro-CHP technologies are somehow environmentally inferior to higher electrical efficiency products. Indeed, the reality for currently available, high electrical efficiency ICE products is that they do not achieve the same total efficiency as gas boilers so that the saving per unit electricity generated is reduced by the cost of additional gas burned. It is of course necessary that for economic viability, the micro-CHP unit must run for enough hours each year to generate sufficient electricity to

Solid oxide fuel cell

IC engine

Heat Electricity Loss

Stirling engine

Gas boiler 0%

20%

40%

60%

80%

100%

13.1 Economic rationale for micro-CHP.



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recover the initial investment. That requires an extended heating period; not necessarily a high peak demand, but preferably a long moderate heat demand in order to make full use of the heat demand to generate electricity for at least 2500 hours annually. However, technologies currently under development such as fuel cells with very low heat-to-power ratios may be able to achieve economic viability for homes with much smaller thermal demands so that some SOFC technologies are able to operate continuous baseload to meet domestic hot water (DHW) demand with an electrical output of 1 kWe every hour of the year.

13.2.2 Fuel availability The majority of micro-CHP products are designed to operate using natural gas as a fuel input and this represents the substantial market in Europe. Although it is possible to operate micro-CHP using alternative fuels such as liquid petroleum gas (LPG), fuel oil and even biofuels,2 these are relatively expensive and do not constitute a significant potential market. It is therefore natural that access to a natural gas network is an essential requirement for mass market micro-CHP applications. In the UK the majority (18 million of the 24 million or so homes) are indeed connected to the natural gas network and are equipped with gas-fired central heating. Germany and the Netherlands also have a majority of heating systems based on hydronic natural gas central heating.

13.2.3 Regulatory environment Although not essential, it is certainly preferable that the energy market is liberalised, allowing connection of micro-CHP units to the LV electricity network and being able to provide rewards for the export of electricity to the grid. In Japan, where it is not possible to recover value for any excess generation exported to the grid, products are designed to deliver sub-optimal performance to avoid export. Although such products are made viable by the application of grants and other subsidies, the liberalised markets of many European states offer a much better prospect of sustainable economic viability.

13.2.4 Technical requirements for micro-CHP viability In addition to these criteria for economic viability, there are also physical constraints on the technologies themselves as they must be suitable for installation either in the home or in other appropriate buildings. Micro-CHP is intrinsically different from conventional CHP in that it serves the highly volatile thermal and electrical loads in individual homes



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in contrast to the more stable demands arising from the diversified loads characteristic of larger systems serving multiple homes or other building types. Therefore it is implicit that power cannot be wholly provided from CHP and that such systems will, in the majority of circumstances, be grid connected and exchange electrical energy with the network. Residential electrical loads fluctuate from below 100 We and can peak at over 20 kWe. Another complication is that residential heating systems typically operate for only around 2500 hours per year, much less than the normal CHP criteria (typically 6000 hours) for commercial viability. In addition, most manufacturers recognise it is not acceptable either practically or economically to service units more often than once annually, such as is required for gas boilers. Taken together these constraints impose severe technical demands on micro-CHP which are only just being resolved. For commercial buildings, nursing homes and similar buildings it is normal to have space allocated to a plant room which may contain bulky, relatively noisy equipment with regular access for service; in such applications ICE technology may be most appropriate particularly as this technology is able to deliver relatively high electrical efficiencies from a wide range of manufacturers. For individual homes, however, it is necessary to incorporate the micro-CHP product within the occupied space so that noise, vibration and physical bulk must be limited, as must intrusive service access requirements. It is therefore not possible to consider all technologies as equally suitable for all applications, although as a rule, technologies suitable for domestic installation are likely to be suitable also for commercial plant room applications subject to the necessary cost criteria.

13.3

Types of system for residential and small commercial buildings

Although all micro-CHP products have the common characteristic of producing heat and power from a primary fuel, fossil or otherwise, there are many different technologies acting as the ‘prime mover’, each with its own particular characteristics which make it more or less suitable for any given application. Alternatives, discussed in greater detail elsewhere in this book, include various types of engines, fuel cells, turbines and novel devices such as thermo-electric convertors.

13.3.1 External combustion engines External combustion engines separate the combustion process (which is the energy input to the engine) from the working gas, which undergoes pressure fluctuations and hence does useful work. The continuous, controlled external combustion process offers significant advantages in terms of low



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emissions, high efficiency, low noise and vibration and potentially long life and extended service intervals, although it must be conceded that these characteristics have yet to be demonstrated in the relatively immature products currently approaching commercialisation. Stirling engines have long been considered the leading micro-CHP technology, but have so far failed to reach the market in significant numbers, although it is expected that both WhisperGen and Baxi will launch their mass-produced 1 kWe products on the UK market during 2010 through the energy companies E.ON and British Gas, respectively. Both products have an electrical output around 1 kWe and electrical efficiencies approaching 15% and with overall efficiencies similar to those of gas boilers. For a typical UK home they would be expected to generate around 3000 kWh of low carbon electricity with a value of up to £200 if all the generated power were consumed on site and an additional £300 from the proposed FIT (feed-in tariff) subsidy. However, it should be noted that promoters of these technologies recommend their installation in larger homes with higher than average thermal demands in order to maximise the income from electricity generation and minimise payback; such homes, with an annual thermal demand of greater than 18 000 kWh constitute around half of the gas centrally heated homes in the UK.

13.3.2 Internal combustion engines Internal combustion engines inject fuel and air into the cylinders where combustion occurs. The resulting temperature and pressure changes of the fuel/air mixture (which is also the working gas) act on the piston to produce useful work. This is mature technology, able to draw on extensive experience in both stationary and automotive applications, although the characteristic high emissions, noise and vibration as well as high service requirements inherent in this technology, raise significant challenges for micro-CHP applications. However, current products available from as little as 1 kWe and with a range of outputs up to 50 kWe (the upper limit of microgeneration*) seem to have substantially overcome each of these challenges and there are around 100 000 Honda Ecowill (1 kWe) units installed in Japanese homes and over 10 000 Baxi Dachs (5 kWe) units installed in large homes and similar buildings in Europe. With an electrical efficiency in excess of 25%, the electrical output of these products in many homes can be quite substantial, possibly as much as 4000 kWh per year and generating an income of around £240† (excluding *As defined by the UK Government in the Climate Change and Sustainable Energy Act 2007. † As the total efficiency of the leading current ICE product is significantly less than that of a gas boiler, the higher production cost of each unit of electricity results in a net income of only 6p.



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subsidies which could add another £400 in the UK). The relatively low heat to power ratio of 3:1 requires the inclusion of a supplementary burner in the micro-CHP package, but makes installation in lower thermal demand homes economically viable.

13.3.3 Fuel cells In a fuel cell, the chemical energy within the fuel is converted directly into electricity (with byproducts of heat and water) without any mechanical drive or generator. Generally speaking they have a much higher electrical conversion efficiency than other technologies, particularly in the case of SOFC technologies, but are relatively inflexible in performance, requiring more or less continuous operation to avoid thermal cycling and the consequent induced mechanical stresses. The leading SOFC technology with an electrical efficiency of 60% and a heat to power ratio of 1:2 operates to provide DHW (domestic hot water) throughout the year, any requirement for space heating being met by the supplementary burner included within the package. In theory, this product would be technically suitable for every gas heated home in the country, although it is a relatively bulky product, requiring a substantial thermal store to capture the ‘waste’ thermal energy in the form of hot water and is thus probably best suited to homes with the necessary available space.

13.3.4 Other novel technologies There are numerous experimental technologies which may at some future date result in useable products. These include thermo-ionic and thermoelectric technologies which utilise temperature difference acting on metals or semi-conductors to produce electricity together with thermo-photovoltaic units which convert the radiant energy emitted by the burner to produce electricity using infra-red sensitive PV cells.

13.4

Domestic applications for micro combined heat and power (CHP)

There is currently a limited number of prime mover technologies on which micro-CHP systems suitable for individual homes can be based. Given the relative technical immaturity of micro-CHP, it is not always currently possible to identify a micro-CHP product ideally matched to the specific application. The mass market for micro-CHP is for stationary, on-grid applications, primarily in domestic buildings ranging from individual detached houses to multi-storey, apartment blocks. It should be acknowledged that, for some of these applications, particularly very high density apartments, some form



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of communal CHP system may be more appropriate from an economic and environmental perspective, although even in such instances, the desire for independence and personal control may make micro-CHP the preferred option from the user’s point of view. As noted earlier, by far the largest potential market for micro-CHP is for installation in individual homes which currently have gas-fuelled hydronic central heating systems. The technology is particularly relevant to provide heating in larger, less energy efficient homes where all practical, cost effective measures have already been taken to reduce energy cost, but where a significant thermal demand remains, so-called ‘hard to treat’ homes.

13.4.1 Complementary applications of micro-CHP in housing Currently available micro-CHP products simply provide space and water heating together with electricity. This limits their operating hours to periods when space heating is required in winter plus an additional limited duration outside the heating season, perhaps an hour or so daily, when there is still a demand for hot water. Some commentators have suggested measures to enhance the performance of their micro-CHP concepts by extending the potential operating hours to meet other heat-based loads. In theory, opportunities do exist for more complex, hybrid packages including cooling to make use of the heat output and thus generate more electricity outside the heating season. However, in practice, absorption cooling has yet to be demonstrated successfully at this scale. Still others propose the application of the generated electricity to power a vapour compression heat pump to maximise the thermal output of the unit, either on a continuous basis or for peaking purposes; this same principle could be applied as a fuel arbitrage measure in the longer term when the dominant domestic heating technology may be air source heat pumps. During periods of limited electricity availability from intermittent renewable sources, effectively the micro-CHP unit becomes a component of a bivalent heat pump heating package.

13.4.2 The existing homes market It has already been explained that the micro-CHP technologies currently under consideration are assumed to replace the boiler in a hydronic system. The majority of UK homes (18 million out of 25 million) are equipped with such central heating systems, as are those of the Netherlands and Germany, generally assumed to be the other two key European markets. At the same time the majority of the 1.5 million gas boilers sold each year are for replacement of boilers in existing systems when they reach the end of their useful life, typically after 10–15 years. It therefore seems logical to focus



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marketing activities on this substantial market provided that the micro-CHP technology matches the thermal characteristics of the home. Not only do existing homes tend to have relatively higher thermal demands than newer, better insulated homes, but the heat-to-power ratio also aligns well with that of Stirling-based systems currently being introduced to the market. Around 85% of energy use within the home is for space and water heating, the remaining 15% is electricity3, as shown in Fig. 13.2. Thus the output of the micro-CHP unit, matching as it does this ratio, has the potential to meet the majority of the home’s energy requirements in a most cost-effective manner. One other key issue in the existing home sector is that of ‘hard to treat’ homes; many existing homes have already had all practical insulation measures applied, so that the only viable way of further improving the efficiency of the home is by installing an energy saving energy system such as micro-CHP or heat pumps. Yet other homes are constructed in such a way that precludes the application of cost-effective insulation measures, such as homes with solid walls, particularly listed buildings or those with attractive external features. Of course, one further compelling reason to focus on this market is that there is an established route to market with logistics, installers and marketing resources already delivering 1.5 million boilers annually. This should allow micro-CHP to make significant impact without requiring the long lead times characteristic of central plant alternatives such as nuclear power or carbon capture and sequestration (CCS); micro-CHP delivers power from day one of installation and an installation rate of 1.5 million a year represents around 1.5 GWe additional generating capacity annually, equivalent to one modern nuclear power station which would require 10 years to build and would not generate a single kilowatt hour until fully completed. Cooking 5% Lights and appliances 10%

Water heating 23%

Space heating 62%

13.2 Domestic energy consumption by end use.



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Scope of micro-CHP in existing homes The criteria for economic viability have already been discussed, outlining the requirement for payback within a reasonable period. This payback is determined largely by the thermal demand of the property in question, a minimum of 18 000 kWh being considered the threshold for lower efficiency Stirling engines. As can be seen from Fig. 13.3 which shows the distribution of gas consumption in all UK homes, this represents a target market of around 9 million homes; more electrically efficient micro-CHP technologies may become viable in smaller homes. At the extreme, products such as the CFCL SOFC unit with a heat-to-power ratio of 1:2 may be able to operate continuously to cover domestic hot water demand alone, so making it suitable for all homes with a thermal demand in excess of 2600 kWh, virtually the entire housing stock. Such products would be provided with an integral supplementary boiler to provide space heating, so it would also be able to meet the full thermal demand of even the largest homes. Objections to micro-CHP There remain those who object to the installation of current micro-CHP technologies on the basis that we should wait until more (electrically) efficient products become available. This belief is flawed; such inaction would waste the opportunity to make immediate, if modest, savings whilst we await the improved products and, as explained earlier, micro-CHP products, as gas boilers, undergo a regular replacement cycle, allowing the early products to be replaced with the enhanced performance models in due course. Still others believe we should not install any fossil-fuelled products at all, but instead await the arrival of low carbon renewable energy to fuel heat pumps,4 failing to appreciate the timescales involved and the urgent need to make the best use of our current finite gas resources until the ultimate low carbon future is attained. Another instance of the better being the enemy of the good! It is also worth considering the likely roadmap from our currently installed domestic heating systems dominated by gas-fired hydronic central heating to one in which heat pumps incrementally displace those gas boilers. There is likely to be a very significant, some would say catastrophic, shortfall in electrical generating capacity within the next decade*; this capacity shortfall would be compounded by a rapid shift to an electrified heat sector. The parallel introduction of heat pumps requiring additional electrical generating capacity and micro-CHP, which might contribute to that capacity, seems to be one effective means of achieving both decarbonised heat and avoiding *Both E.ON and EdF in the UK have indicated an anticipated shortfall in generating capacity of around 45 GWe by 2016 if they are forced to close existing coal-fired power plants to comply with the EU LCPD Directive.



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© Woodhead Publishing Limited, 2011 0

500 000

1 000 000

1 500 000

2 000 000

2 500 000

Gas consumption band (kWh per annum)

13.3 Number of UK domestic gas consumers by consumption.

Number of customers in consumption

300 0 600 0 900 0 12 000 15 000 18 000 21 000 24 000 27 000 30 000 33 000 36 000 39 000 42 000 45 000 48 000 51 000 54 000 57 000 60 000 63 000 66 000 69 000 72 000 75 000 150 000 300 0 0 450 0 00 600 0 000

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overload of the electricity generation and distribution networks in the short to medium term.

13.4.3 The new-build housing market When designing and building new homes, there is the opportunity to make decisions based on the optimum combination of high performance construction and an integrated energy system. Too often, unfortunately, the innate conservativism of the construction industry and their assumptions about public aspirations, result in the major housing developers choosing to construct very poorly performing homes. They are then forced to resort to ‘addon’, sometimes tokenist (usually disproportionately costly) microgeneration solutions to comply with the increasingly stringent building regulations. Under such a scenario it is possible that micro-CHP systems will continue to be installed in traditionally constructed homes for some years although it is clear that by 2016, when zero carbon homes become mandatory, it will no longer be possible to justify micro-CHP using fossil fuels.

13.5

Small commercial buildings and other potential applications

This section considers the potential for micro-CHP units (possibly in multiple modular configurations) in small commercial buildings including residential, office, educational and other relevant applications. It can be seen from Table 13.1 that there is a much broader range of technologies which may be suitable for non-domestic applications, although the potential number of viable installations is significantly less. In addition to these stationary applications, there is also considerable global potential for micro-CHP in mobile and remote stand-alone configurations, but these are considered outside the scope of this publication. Such applications might include cabin heaters for trucks, range extenders for electric vehicles, off-grid residential and other stand-alone applications such as auxiliary power units (APU) in marine and military systems. Indeed the WhisperGen micro-CHP unit began life as a diesel-fired APU/heating system for marine applications. However, it should be recognised that the relatively low electrical efficiency of Stirling engines makes them less than ideal for applications where the primary concern is electrical generation; fuel cells are better suited to such applications.

13.5.1 UK commercial market The UK small commercial market is more fragmented than the domestic market and has a much smaller overall potential. However, there are a



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Existing homes

� � � �

Offices

Emergency

Laundrettes

�

�

�

� � � �

� � �

� �

� � �

� �

� �

� �

� � �

� � �

5 kWe ic engine

� �

� �

� �

�

� � �

� � �

15 kWe ic engine

� �

� �

� � �

� � �

50 kWe ic engine

Note: The stars indicate the suitability of each technology to the respective application – the more stars the better the suitability.

�

�

�

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� � �

Schools

�

�

Restaurants

�

� �

�

�

� � �

� � �

2 kWe sofc

Hotels

�

� �

1 kWe sofc

� �

� � �

1 kWe ic engine

Sheltered

New homes

1 kWe Stirling

Table 13.1 Preferred technologies for micro-CHP applications

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number of niche markets where micro-CHP may find applications that are less sensitive to initial investment costs than the domestic market. Such areas are where there is a large demand for hot water and lighting throughout the year, prime examples being small hotels and hairdressing establishments. However, it is almost inevitable that commercial establishments which do not have a residential component are destined to have relatively low running hours simply because they are only occupied for around one-third of the day during the heating season. Schools are even less attractive due to the long holiday periods which further reduce the potential for extended operating hours, although in most cases it is possible to make use of thermal storage to extend operating hours of the CHP system during term time well beyond the occupied period by storing heat for later (or peaking) use. However, it is important to consider the likely use of the electricity generated as avoided import is clearly more valuable than the price attributed to export; it is therefore necessary to match generation to consumption as closely as possible. The following types of commercial applications, although not exhaustive, should provide an impression of the potential for micro-CHP technologies in respective building types. The summary is intended to illustrate relevant technologies, but due to the rather varied size of offices, hotels, etc., each case needs to be considered on its own merits. Applications worth consideration include the following. ∑

Hotels, where thermal demand and thus economic viability may be assessed on the basis of number of bedrooms. Each room will have a space heating demand plus a demand for sanitary hot water; on an aggregate basis it is likely that the diversified demand will be similar to a house for multiple room establishments. The prime market is probably the 13 0005 or so small hotels with 4–15 bedrooms for smaller 1–3 kWe electrical output units; the larger ICE-based units are well suited to hotels with more rooms and, although this text is focused on micro-CHP, there is clearly an overlap with larger-scale CHP plants depending on the size and thermal demands of the establishment in question. ∑ Residential and nursing homes as well as sheltered flats provide an excellent potential for micro-CHP due to the relatively high continuous thermal demands throughout the year for both space and water heating. In the majority of cases it is likely that micro-CHP units in the range of 5–15 kWe corresponding to a thermal output of 12–30 kWt would be able to achieve adequate run hours to attain a good economic return. There are in the region of 16 000 such establishments in the UK. ∑ Restaurants and pubs may have high space heating requirements, but over relatively short periods and hot water requirements tend to be light. A micro-CHP unit is unlikely to be utilised for more than 2000 hours per year, resulting in rather poor paybacks. However, if there are live-in



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tenants or rooms to let, such buildings would be prospective installations with the same characteristics as a large house. ∑ Offices, where economic viability is assessed on the basis of floor area and implied thermal demand. Although in terms of numbers, offices appear to offer a substantial market (there are over 100 000 offices with floor areas less than 100 m2) ,6 heating needs are relatively low due to the high level of internal gains from computers, lighting and other equipment. There is little requirement for water heating, giving no summer load for the CHP unit. Even in winter there is potentially a mismatch between electrical use and heating demand, since, although the electrical load in offices is fairly constant throughout the occupied period, the heating demand will be at its highest just before the start of occupancy.7 There is a further challenge to viability as offices are rarely owner occupied and there is little incentive for landlords to include micro-CHP or indeed to provide any energy efficiency measures. ∑ Emergency service buildings (police, fire and ambulance stations) which are continuously occupied and with a constant electrical demand as well as similar thermal requirements to large homes may provide a significant opportunity for micro-CHP, particularly if the unit is capable of stand-alone operation, clearly a benefit for such establishments; there are around 12 000 in the UK. ∑ Laundrettes, hairdressers and similar premises with a significant hot water and electrical demand; there are around 11 000 of these in the UK. ∑ There are also around 10 000 small schools which may benefit from micro-CHP, although it is difficult to justify the investment from the relatively short-run hours unless the building is also used for community purposes during the evenings and school holidays, or in the case of boarding schools which may effectively be considered as student halls of residence and be suitable for small-scale CHP or become part of larger CHP schemes across a campus, for example. In summary, the potential for small commercial applications suggests a market in excess of 100 000 premises. This aligns reasonably well with the gas consumption profile data which indicate a market of around 107 000 consumers with relevant gas consumptions. Depending on the size of microCHP unit under consideration, it is possible that more than one unit may be installed in some kind of cascade arrangement as shown in (Fig. 13.4). Although the larger micro-CHP units including ICE-based products can achieve high electrical efficiencies, extended service intervals and low capital cost due to their level of industrial maturity, it is possible that as production volumes of smaller units increase, their cost may become competitive with these larger units and provide a greater degree of operational flexibility. This



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13.4 Multiple EC Power 15 kWe ICE units in sheltered housing scheme.

may be particularly true for SOFC where the basic fuel cell stack may be effectively scaled by modularisation with relatively little impact on capital cost other than the balance of plant components. Assuming a replacement rate of 5% (as for domestic heating systems), and an average of two micro-CHP units per application, this represents a potential market of 5000 units per year in the small commercial sector, very much smaller than the domestic market, but conceivably less technically challenging and addressable on the basis of ‘rational’ economic decisions.



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341

Advantages and limitations

13.6.1 Competing technology solutions Micro-CHP clearly has a significant role to play in a range of applications, but it is important to ensure that the appropriate technology is selected for each application. This may be Stirling engines for larger thermal demand properties, fuel cells for lower energy consuming homes and we should not be afraid to acknowledge that, in some cases, some other form of energy system altogether may be more appropriate. Micro-CHP is most cost effective where there is an adequate heat load to justify the investment and where a natural gas supply is available, but in other cases alternative technology solutions may be required. For example, practical constraints of physical size and issues with provision of mains gas supply combined with the low thermal demand of individual apartments within high rise blocks might favour community heating in preference to micro-CHP, whereas alternative technologies such as heat pumps or biomass heating are potential options in rural areas where no gas supply is available. Community heating District heating (DH), also known as community heating (CH) is relatively uncommon in the UK, with only 1% market share. This is to some extent a reflection of the high level of owner-occupation and the desire to have independent control, allied to a traditional focus in the UK on low first cost. It is also difficult to see how the conflicting demands of DH (which logically requires all homes in an area to be connected for economic viability) and a competitive market (which demands that all customers may choose their energy supplier and their energy system) can be resolved. Various studies8 have identified up to 5 million homes within areas with sufficiently high heat densities to justify district heating.* The areas identified tend to be central urban sites with high rise apartments, unsuitable for micro-CHP both from a heat loss perspective and due to the physical size and construction of the properties. Micro-CHP and DH can therefore be considered complementary rather than competing technologies, although, where practical, micro-CHP is preferable on economic and environmental grounds.9 Figure 13.5 illustrates the relative merits of various micro-CHP technologies compared with conventional gas boiler central heating plus either solar *

Note that the viability is extremely sensitive to discount rate due to the high initial cost. The 5 million figure (which includes input from the 2002 PB Power study) assumes 6%, whereas, for a rate of 9% about 400 000 and for 12%, less than 200 000 homes would be viable.



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Small and micro combined heat and power (CHP) systems Boiler (70%) PV Micro CHP (10%) Micro CHP (20%) Micro CHP (50%)

Boiler (86%) Wind Micro CHP (15%) 500 kW 0%

9000 Boiler (70%)

Annual CO2 emissions (kG)

8500 8000

Boiler (86%)

7500

We 500 k

Boiler + PV

4000

h

7000 6500

M CHP (SE)

6000 5500 M CHP (FC)

5000 4500 4000

0%

5%

10%

15%

20%

13.5 Comparative annual CO2 emissions for micro-CHP and CH/CHP.

PV or micro wind for a typical home with an annual thermal demand of 18 000 kWh and 6000 kWh electrical demand. For each of these technology combinations, the annual CO2 emissions can be seen on the vertical axis. It clearly demonstrates the environmental benefits of micro-CHP compared with these more expensive and less effective technologies, even for the lowest efficiency, Stirling engine-based micro-CHP products.10 Figure 13.5 also shows the emissions for an alternative, small (500 kWe) CHP plant connected to a small community heat network. The major disadvantage of such a system in efficiency terms is the inevitable heat distribution losses; the horizontal axis shows the assumed heat distribution losses from zero to 20%, a figure of 10% being fairly typical for a welldesigned modern system. However, the same point made above in reference to the long lead times of central electricity generating plant could also be levelled against CH as it too requires substantial, expensive and timeconsuming infrastructure investment before any useful energy is delivered at all. Whereas micro-CHP offers incremental investment risk, large-scale community heating, like nuclear, CCS, etc., requires a level of market certainty over a long period which has not so far been forthcoming. However, one major advantage of CH over micro- and small-scale CHP schemes is that, whilst the latter are largely confined to gas–fired applications, larger-scale



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systems are able to make use of both energy from waste and a wide range of alternative fuels and provide opportunities for fuel switching in response to availability. Other microgeneration technologies Depending on the space and water heating requirements of the home, the availability of a natural gas supply or alternative fuels and a host of other factors, there may be alternative microgeneration technologies which may offer alternative or complementary benefits to micro-CHP. Such technologies include biomass boilers, air and ground source heat pumps, solar thermal, micro-wind and micro-hydro. However, one of the key benefits of microCHP compared with technologies such as solar thermal, PV and microwind, is that it is a non-discretionary purchase. In other words, micro-CHP replaces an essential component of any home, namely the central heating boiler. So, as with heat pumps and biomass boilers, the investment cost of micro-CHP needs to be considered as an incremental cost compared with the alternative gas boiler, whereas the discretionary technologies need to justify their entire cost. After all you don’t need a PV system, but you do need space heating. Conventional central plant Figure 13.6 illustrates the comparative electrical and thermal efficiencies of the main micro-CHP technologies. For example, SOFC micro-CHP has an electrical efficiency of 50% and a thermal efficiency of 40% in this diagram. These are overlaid on the alternative, conventional central generating plant 90

Thermal efficiency (%)

80

Stirling engine

70

IC engine

60

PEM fuel cell

50 40

Solid oxide fuel cell

30 20 10 0 0

10

20 30 40 Electrical efficiency (%)

50

60

13.6 Comparative efficiencies of micro-CHP and conventional options.



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option providing electricity at an efficiency of 45% and 35% (representing CCGT and UK average delivered efficiencies) and heat provided by gas boilers, with state-of-the-art condensing gas boilers and typical UK gas boilers delivering efficiencies of 90% and 70%, respectively. The solid line represents the best available conventional technology, whilst the broken line is more representative of typical UK practice. Despite the variation in relative electrical and thermal efficiencies, there is no case in which microCHP performs worse than centrally generated electricity and gas boiler central heating.

13.7

Future trends

As micro-CHP enters the commercial phase, the products themselves are reaching a level of maturity which primarily requires developments to be of a ‘design for manufacture’ nature rather than addressing fundamental issues of performance and reliability. Considerations of product acceptability are also being addressed with a focus on issues such as control, interfacing with the consumer and education to ensure householders gain the most value from the operation of their micro-CHP products. The products also need to be adapted to the peculiar requirements of each market, and technology development of higher efficiency, smaller, quieter, cheaper products continues. One particularly encouraging development is the rapid progress currently being made by fuel cells which are already demonstrating exceptionally high levels of electrical efficiency, leading to the potential for application in the majority of homes. At the same time, it is becoming apparent that the implementation of micro-CHP can be accelerated by the availability of ‘enabling technologies’ such as advanced controls and metering which improve the performance within the home and which allow the true value of micro-CHP generation to be realized. Whilst there is no one technology which can overcome the challenges of UK energy policy, there is no doubt that micro-CHP can deliver a substantial and possibly the greatest individual contribution to the joint goals of eliminating fuel poverty, carbon mitigation, competitiveness and security of supply within the housing sector. There is a need to develop a range of technology solutions to meet the range of needs of different dwelling types, households and logistic constraints. It is therefore likely that new products will continue to be introduced to the market to provide householders with a range of complementary options including heat pumps, micro-wind, biomass and solar thermal technologies. Perhaps most importantly, aside from the specific developments of enhanced performance products, additional products from a variety of manufacturers and other inevitable developments of a maturing technology, there is a growing recognition that micro-CHP and other technologies must not be viewed as



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isolated components of the energy system; we must consider their synergies. The simplistic advocacy of individual technologies whether larger-scale CHP, conventional central plant solutions or alternative microgeneration technologies is giving way to an understanding that there is no one technology which is able to meet the energy demands of all consumers and applications and that we need a diversified portfolio encompassing all available low carbon, energy efficient technologies. But more than this, the technologies may not just complement one another; they may depend on one another. As we enter an era which is likely to see the emergence of very large-scale intermittent renewable generation, we need to consider the ability to arbitrage fuels, swap loads between fuel types and ideally to design systems in which, for example, the electrical output from gas-fired micro-CHP can be used to support the intermittent output of wind generation either directly through the VPP (virtual power plant) concept, or indirectly by supplying electricity to drive heat pumps when wind power is constrained. In summary, micro-CHP should be seen as a medium-term transitional technology supporting the implementation of an electrified heat sector as we move towards a zero carbon future, but may also retain a long-term, even permanent role in support of such a system.

13.8


∑

General information on micro-CHP and related technologies with links to manufacturers and additional resources: http://www.microchap.info ∑ General information on microgeneration technologies with links to manufacturers and additional resources: http://www.microgenerationoracle.com/index.htm ∑ Links page to government and institutional websites providing information on energy issues as well as organisations active in the field of distributed energy in general and CHP in particular: http://www.microchap.info/ LINKS.HTM

13.9

References

1 Harrison J and Redford S (2001), Potential benefits of micro CHP, Energy Saving Trust. 2 Harrison J. (2003), Micro CHP in rural areas, Renewable Energy World. 3 Department of Trade and Industry (1999), UK energy sector indicators. 4 McKay D (2009), Sustainable Energy without the hot air, UIT, Cambridge. 5 EA Technology (2000), Micro CHP – Review of emerging technologies, products, applications & markets. EA Technology report. 6 Herring H, Hardcastle R and Phillipson R (1998), Energy use and energy efficiency in UK commercial and public buildings up to the year 2000, Stationery Office Books. © Woodhead Publishing Limited, 2011


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7 Moss K (1994), Energy consumption in public and commercial buildings, BRE Information Paper, IP 16/94. 8 BRE (2003), The Potential for Community Heating in the UK, Carbon Trust. 9 Harrison J (2002), ‘Options for upgrading residential CHP’, COGEN Europe Conference Paper. 10 Harrison J (2007), ‘Micro CHP and microgeneration’, Claverton Energy Group Conference.



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14

District and community heating aspects of combined heat and power (CHP) systems

J. C l e m e n t, Aars District Heating, Denmark, N. Ma r t i n, Shetland Heat Energy and Power, UK and B. Ma g n us, COWI, Denmark

Abstract: This chapter focuses mainly on the district and community heating aspects of small CHP systems, the heat sources and control systems and contains issues to be considered before a new district heating system is to be established. Further, this chapter contains some of the preconditions for getting started and overall design considerations. These experiences are based on projects established primarily in Denmark and the UK and with case studies from Aars in Denmark and Lerwick in Shetland. Key words: district heating, improved efficiency, fuel flexibility, CO2 reduction, CO2 neutral heating, heat and energy storage.

14.1

Introduction

District heating (DH) is a very old principle and was already used by the Romans some 2000 years ago. Of course, it has developed since then, but in principle it remains a central heating system expanded to contain more than just one house, and the heating is today transported from boiler to house in pre-insulated pipes. It is a relatively simple system and the principles are easy to understand, but still district heating is often called one of the best kept secrets because it is buried under the ground and very few people know about it. Even in Denmark, where 60% of all houses are connected to district heating systems, very few people knows about district heating in detail and many do not even know from where the heating comes. One of the reasons for this situation is that very few problems arise with the system, the limited space demand and almost no maintenance in the home. When designed according to the recognized recommendations, the system is extremely robust and the number of hours when there is no heating is very limited. In areas with district heating there are only a limited number of individual stacks and therefore the air quality is high and nobody thinks about the heating of the house. It is just something you have as long as you pay the bill and can be compared to buying your water or your electricity and who knows where these services come from? One of the main reasons for establishing district heating is that heating 347 © Woodhead Publishing Limited, 2011


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of houses and preparation of hot tap water do not need high-level energy carriers like fossil fuels or electricity but can use low-level sources as surplus energy from, for example, power production and industrial processes. When used as a byproduct from power production, the fuel efficiency is more than doubled, from typically 35–45% in power plants to 85–95% in combined heat and power (CHP) plants. Further, the district heating system gives a better fuel flexibility and enables a number of local resources such as straw, wood, different waste products, biogas, sun, wind, geothermal energy, etc., to be used for heating. This is good for the local economy and the overall environment as the energy efficiency is improved and the emissions from the heat generation can be controlled and limited due to the central generators and monitoring possibilities that exist in a centralized installation of a certain size range. District heating water has a further advantage: it is easy to store and, with a storage tank, daily variations in heat consumption can easily be handled. It is therefore not necessary to have generation capacity available for the peak demand and the heat production can be stable or, if there is surplus energy from a process at any time, it can be stored in the storage tank.

14.2

How to get started

In Denmark, district heating covers more than 60% of the housing stock which is among the highest rates in the world. The last 40% of Danish houses are in natural gas areas, are in rural locations or in small towns with fewer than 100 houses. They are supplied by individual boilers with natural gas and oil but also wood pellets and straw boilers are used. The high connection rate to district heating was helped along by the two energy crises in the 1970s when oil prices more than doubled, and a political wish to become less dependent on oil and coal from abroad. Energy planning was introduced in all major towns and cities in Denmark, where areas were dedicated to district heating and some cities also introduced compulsory connection to DH systems. Many of the big DH schemes were owned and operated by municipalities but often the establishment of a new district heating system was started by individuals who had the energy, charisma and enthusiasm for the idea of having a local and flexible heat supply. DH is comparable in cost to other heat sources and often cheaper, but some of the small gas-fired CHP plants have experienced a change in the preconditions with higher gas prices and lower electricity prices and they can only put the deficit on the heating cost. Preconditions for getting a DH system up and running include: ∑ getting customers committed to take the heating ∑ a heat source that can provide competitive energy prices ∑ political support as the municipality has to give permits for the © Woodhead Publishing Limited, 2011


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establishment of the system and they do also have control over a number of buildings that could become good customers ∑ financial resources to handle the investments which are long term and with a long payback period ∑ an organization with knowledge of handling a project like this, both setting up the preconditions for the project, the design and operation, and developing a plan. When a DH project starts, it must be recognized that it is as long-term, ongoing project. You can finish your first, second and third stages, but you will never finish developing your DH system. When the system in the town is fully developed, you can start thinking about connecting to neighbours and connection to new heat sources or developing new heat sources. Lerwick and Aars are two good examples (explained in more detail in Sections 14.6 and 14.7) but almost every district heating company can improve or expand, and this will continue with the development of technology and knowledge.

14.3

Heat sources

The heat sources available for district heating have developed rapidly in recent years. Economy, environment and sustainability are important drivers when it comes to choosing the right heat source. In the 1960s and 1970s fossil fuels were cheap and easily available and there was limited focus on the environment. However, first the energy crises in the 1970s and then the slow depletion of natural gas (Denmark will not be self-sufficient in gas from around 2016) and the global warming commitments have changed the focus. Now sustainability and security of supply are the most important factors when setting up a new system, but also in developing an existing system. With the development of wind farms the electricity market will experience frequent imbalances, therefore even electricity can be a sustainable heat source when used at the right time. Large-scale electric boilers or heat pumps can help balance electricity consumption with generation, and DH systems with storage tanks can easily adapt to these variations.

14.3.1 Size considerations It is evident there is a considerable difference between summer load and winter load, the actual difference depending on the temperature and wind factors, but in the UK and Denmark the factor of heat demand is probably 4–5 times larger during winter compared to summer. During the summer the need for heating is very limited and heat produced is primarily used for heating tap water and heat loss from the pipe system. When designing the plant, a general principle is the heat source with the lowest production price has the highest investment cost. Therefore the © Woodhead Publishing Limited, 2011


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plant should consist of a base plant able to supply, e.g., 60% of the peak load and a peak and reserve plant covering the last 40%. A rule of thumb, 60% of the peak load will cover 90% of the yearly energy production and therefore it is of little importance what the production cost is with the peak load installations.

14.3.2 Examples of heat sources The following is a short introduction to a number of possible heat sources. Biomass Biomass is often available locally and can consist of straw, wood chips, wood pellets, shredded roots, and other residues from forestry and farming. Most commonly these plants are heat only but there are a few CHP plants. Biogas In Denmark there are only a few plants using biogas, but in Germany and other parts of Europe the number of such plants is increasing. They provide gas from landfill sites, composting facilities and anaerobic digestors accepting a range of green and wet wastes. Biogas, which is mainly methane based, can be used in, e.g., gas engines producing both power and heating resulting in a very high efficiency. Waste to energy Energy from waste is very common in Denmark and provides a considerable amount of the district heating. Most plants are built as CHP installations, but because of the very corrosive flue gases the steam generators can only operate to steam temperatures around 400–440 °C. The efficiency is therefore relatively low if these plants are only producing electricity and even an optimized plant will not achieve more than ~30% efficiency. However, the combination of heat and power production can give efficiencies above 95% and with flue gas condensation even above 100%. This is possible because the efficiency is calculated with the lower heating value and these fuels contain some moisture. Fossil fuel Typically fossil fuel plants use light fuel oil or natural gas. These plants are used as peak and reserve load installations as the investment cost is low and © Woodhead Publishing Limited, 2011


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the operation relatively simple. Natural gas is also used in CHP plant with gas engines but these are often smaller plants and have relatively high heating prices as the gas prices have risen and electricity prices gone down. Other heat sources The other heat source in Danish district heating systems are geothermal, with only a few plants running but more are currently under development. Waste heat from industrial processes and solar heating are growing fast at the moment and these systems can count as an energy sawing initiative.

14.4

Pipework installation issues and design considerations

District heating pipes have the prime purpose of distributing the energy to customers with the lowest possible heat and pressure. The physical layout of a district heating network has to be based on the location of the consumers as well as geographical conditions of the area to cover ground levels of the landscape, etc. At the same time the pipes have to be protected against corrosion and damage from other utilities, etc. The standard pipes are today insulated with polyurethane foam and have containment pipes of steel or polyethylene. Branch pipes are often flexible and the dimensions depend on the differential pressure available over the length of the pipe and the overall condition of the DH system. If the DH system is old, it can contain some dirt and therefore very small pipes (< 16 or 20 mm) should be avoided but new branch pipes are made down to 12 mm inside diameter in the media pipe. These very small diameters gives very little heat loss and a cold pipe takes limited time to heat up, but if the main pipe contains some dirt the clogging of the branch is a risk factor. Older pipe systems are of different quality and, depending on the water quality and general operating conditions, they can be either in good condition or very bad condition. To clean the water particle filters are installed as part flow filters, but if a pipe is clogged there is no alternative but to flush the pipes. New pipes are of a high quality and there will be no problems with them if they are installed according to the specifications and not damaged by other utility companies. Some problems have been caused by cable diggers who are just ploughing their cables into the ground with little or no consideration for other pipes. Regarding the installation of pipework in the ground, there can be problems in installing pipes in streets and built-up areas as there are usually many existing services already laid in the ground. On some occasions re-routing of existing systems is necessary or the heating pipework may have to be installed deeper. It is also possible to drill a ‘tunnel’ and drag the pipe through. These



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problems become more difficult with bigger pipe diameters, but the pipes used are flexible and tough and can be manipulated satisfactorily. It is true to say that there are usually some problems, but potential consumers have always been connected regardless of such problems.

14.4.1 Pipe size considerations The optimal sizing of the main pipes is difficult as the pipes have a lifetime of 40 years and therefore need to be designed for a future load compared to when they are installed. The initial pipe design has to include a development plan for the main pipes going from the plant to the areas being supplied, and new areas to be connected must include a plan for how and when customers are to be connected. When an area is developed it is therefore a big advantage if the connection rate is high from the beginning as the heat loss is then optimized. The installation cost is also a lot cheaper if consumers are connected when the mains pipes are installed. To get people connected, customer information and promotion is therefore essential and often combined with a discount rate for connections carried out during the initial installation of the pipes. If the connection rate is too low, the system will operate with a high heat loss but, if the connection rate on the other hand is too high compared to the connection plan, the pipes might need to be upgraded before the end of the lifespan. To get some heat load on the system from the beginning, it is a good idea to concentrate on the larger consumers such as hospitals, swimming pools, sports centres, schools and public buildings and areas developed with new housing, and initially connect them as they will ensure a good flow in the pipes. If the areas with the larger consumers are developed first, it also ensures that the system will work and a reasonable base load is applied to the system. If there is little knowledge about district heating, it is also an advantage to have proven the system with an initial installation before large-scale expansion, as mouth-to-mouth promotion is often one of the most efficient ways of getting new customers.

14.4.2 Consumer education As the capacity of the pipes is linked closely to the temperature difference between flow and return, it is important to get the consumers to cool the water and extract as much heat as possible. The heat loss in the return pipes also depends on the temperature, so the consumers are therefore an integral part of the DH system and it is important to get them to follow some simple rules to make the overall system operate with the lowest losses and cost. These rules include the following.



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∑

Install radiators designed for District Heating, e.g. 60–70 °C flow temperature and return at 30–40 °C. ∑ Use all the radiators in the house to ensure the best cooling of the DH water. ∑ Keep doors closed to rooms where you want lower temperatures. ∑ Avoid temperatures lower than 16 °C when operating with lower temperatures during night-time. This is to avoid big changes in heat demand during the day, as the maximum heat demand is what pipes and heat sources are designed for. Heat loss from the house is very limited at lower temperatures, therefore nobody gains much by going to lower house temperatures. Basically it is more economical to operate at the system design duty than at low load. ∑ Give a bonus to those who can achieve good cooling. Further, a good customer relationship can be an advantage as an aware customer keeps an eye open and if there are, e.g., leaks in the system, they can help find them. If an aware customer sees an area with no snow during the winter period or steam coming from underground, they would know this could come from a DH pipe and be an important informant for the operators.

14.5

Control system and consumer installations

The commitment of the system is to ensure all costomers have sufficient heating. The temperature, differential pressure and static pressure need to be sufficient to heat the house and make hot water within the safe temperature parameters at all times. In the design of a district heating network, the following basic items must be observed and considered. Figure 14.1 outlines the general overall principles of a DH supply unit with a CHP unit as the base unit and oil-fired boiler as backup, the pressurising system and supply of treated water. Figure 14.2 outlines the principles of a DH supply unit also including a heat storage tank for optimized operation of the producing units and able to average the daily variations. Figure 14.3 outlines a standard consumer installation with direct space heating by means of radiators and hot tap water supply through a plate heat exchanger. The supply to customers can also include a heat exchanger to ensure the water in the radiators and the distribution pipes are separated. For example, in Aars it is a direct system as shown in Fig. 14.3, but in Lerwick, Shetland, all customers are supplied through a heat exchanger.

14.5.1 Pressurizing and static pressure The pressure in the district heating network must be calculated and designed on the basis of the ground levels of the area covered. The pressure in the



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Engine

Oil boiler

Consumers

B

Pressurising system Water treatment Raw water

14.1 Boiler station with a CHP unit as the base unit.

Engine

Oil or biomass boiler

Heat storage

Consumers

B

Pressurising system Water treatment Raw water

14.2 Boiler station with a heat storage tank.

pipes must ensure there is water coverage at the highest locations under all operating conditions, preventing air and raw water intake at defect connections or consumer installations. Normally the pressure in a distribution network is also kept below 10 barg at all locations. If the network needs



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Main valves

F

T

T Differential pressure control valve

Temperature control valve

Plate heat exchanger

Space heating

T

T

Cold tap water

Hot tap water

T

Radiators with thermostatic valves T

Radiators with thermostatic valves

14.3 Standard consumer installation with direct space heating by means of radiators and hot tap water supply through a plate heat exchanger.

District heating network

Strainer

Energy meter

Radiators with thermostatic valves

356


to cover areas with a large variation in ground level it has to be separated into pressure zones by large heat exchanger units or by booster pumps and pressure reduction valves. The ‘static pressure’ is the pressure that remains in the district heating network when the system is at rest, e.g. with all pumps stopped. The static pressure should be kept at a level that gives approx. 1 barg at the highest ground level in the network. The pressurizing system is in most cases brought as a pre-assembled unit with a pressure-less reservoir, with pumps to add water to the network at low pressure and mechanical valves to drain water at high pressure. The design capacity of the pressurizing system is based on the water volume in the network, enabling the system to drain water at a sufficient rate when the whole network is heated up from standstill, and again add sufficient water if the system cools down as a result of a break down, lack of heat power, etc. It is also essential that the reservoir of the pressurizing system is designed to prevent oxygen uptake in the water. Differential pressure The differential pressure between flow and return pipe in the network creates the flow rate through the customer installations. The lowest differential pressure at the individual customer depends on the pressure loss in their internal installations, but normally 0.3 bar is sufficient. The differential pressure in the network is established by the main pumps installed at the DH plant. The main pumps are designed for highest possible energy efficiency on the loads that occur in the highest number of running hours during the year. In the design process loads for summer and winter are considered as well as the redundancy or backup philosophy, and the number of pumps is determined, i.e. two 100% capacity pumps, or maybe three 50% capacity pumps. The location of the main pumps also has to be considered in the system layout. Normally the best solution will be to locate the pumps in the return pipe pumping through boilers, heat exchangers, etc., as this will keep a pressure on the producing units securing against steam generation in the system.

14.5.2 Heat storage tank In DH networks based on CHP units, biomass boiler units or maybe surplus energy from local wind turbines, it is of great benefit to incorporate a heat storage tank to equalize the difference between production and demand in the network. CHP units can be operated at full load during periods with high electricity prices, and relatively slow reacting biomass or waste-to-energy boilers often run optimal at constant load, regardless of the peak loads in the



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network. The heat storage tank is in its simplest form an insulated pressurized tank with diffusers at the top and bottom to make the flow in and out of the tank at a low velocity, thus building up a layer division between hot and cold water (Fig. 14.4).

14.5.3 Water quality in the network In order to reduce risk of corrosion, leaks, deposits and bacterial growth in the district heating network, it is essential to establish and maintain the right quality of the circulated water. In smaller DH networks the makeup water is normally prepared in a pre-assembled softening unit where the calcium and magnesium salts in the water are exchanged with sodium salt which do not cause the disadvantages of hard water. Adding special chemicals raises the pH value in the water and prevents growth of bacteria. The pH value is monitored and additional chemicals dosed on a continuous basis, keeping the pH value at approx. 9.5.

14.4 Heat storage in Aars to account for daily variations in heat consumption, size 800 m3.



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14.5.4 Flow temperature The flow temperature in the DH network should be kept as low as possible to reduce the losses throughout the year. The temperature should, on the other hand, be high enough to ensure sufficient heating and hot tap water for customers located at the furthest point in the network. Space heating Space heating depends on the dimensions of radiators, and district heating often requires larger radiators than for a traditional boiler system as the DH system is more efficient when the return temperature is as low as possible. These radiators are, though, only marginally bigger and can be combined with under floorheating as they can operate at flow temperatures as low as 30 °C. This will ensure a very low return temperature. A traditional consumer boiler installation often operates with a high return temperature as this is needed to protect the boiler itself from corrosion, and the ‘losses’ from both flow and return pipes is within the premises thus all adding to the heating. Losses from district heating are mainly located in the exterior network and this is reduced by low return temperatures. So when including existing consumer space heating installations, there might be a need to increase radiator sizes and there must be focus on removing all bypasses in the installations. Hot tap water The hot tap water must be kept above 55 °C to limit the risk of bacteria growth. This is often the dimensioning criteria for the district heating temperatures during summer operation and consumer installations should also be designed with consideration to where in the network they are located. If close to the plant the temperatures and pressure are higher and direct heat exchangers can easily be used, but at some distance the temperatures will be lower and the differential pressure also lower therefore, so a hot water tank might be the best solution as the operation of the DH system needs to take account of the designed consumer installations to avoid customer complaints.

14.5.5 Customer billing system Different billing systems have been used in DH systems through the ages, previously based on items such as consumed cubic meters, area of heating surfaces, floor area, etc. Due to temperature drop in the widespread network, different flow temperatures were available to consumers thus giving a different energy price. The availability of cheap electronic energy meters have nowadays resulted in energy-based billing giving the same price per



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energy unit to all customers, normally combined with a standing charge based on size of installation and maximum heating demand. Also the customer’s ability to return the water at a low temperature has in recent years been integrated in the tariffs. It is important to get the right balance between the different elements of the billing system to support incentives such as cooling, and still to keep the district heating energy price attractive compared to other sources.

14.6

Case study: Lerwick, Shetland

Designed in 1998, installation started in 1999 with main pipes to some parts of the town where the main customers and some of the larger ones were located, such as hospitals, swimming pools, sports centres, schools and public buildings and areas developed with new housing. This system is one of the most successful district heating systems in the UK and during its 10-year life span has now covered most of the town of Lerwick with more than 1000 customers. The system started as a result of heat from a 6.5 MW Energy from Waste plant built during the same period as the initial design and establishment of the DH system. The main drivers were the Shetland Islands Council and the Shetland Charitable Trust ensuring capital. The Trust had funds accumulated from oil activities from the 1970s and was allowed to invest funds to benefit the Shetland economy. District heating schemes are very capital intensive requiring a large investment at the start. This tends to be the main obstacle to the development of such schemes when payback is over a long term. The most difficult task to retrofit a district heating scheme in an existing town in the UK is to obtain low return temperatures. Buildings were originally designed on a 82 °C supply and a 71 °C return. As the quality of customers’ systems was questionable it was decided that there would be no direct feeds into a building heating system so that heat exchangers would be required, meaning the supply temperature would have to be above 87 °C. In addition the connection rate was expected to be low to start with until the scheme proved itself, so 95 °C was decided upon to allow for heat losses. Whilst a return temperature of around 70 °C was anticipated in general, it was found that many systems were overdesigned and that they could run at lower temperatures. An additional return line was run to the swimming pool which only needed to heat water to 30 °C and could lower the overall water from the town at a beneficial tariff. Initially the return was 65 °C but with new build and refurbishments over 10 years the return is down to 55 °C and it is hoped that this will be reduced to 50 °C over the next 10 years. Lowering the supply temperature to 90 °C is also a possibility. The scheme had problems at the start with many objectors against the scheme primarily because it was expensive and an unfamiliar technology.



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Falling oil prices did not make the marketing easy. By the following year oil prices had risen steeply and word of mouth on how good the system was starting selling the scheme, outstripping the local ability to connect, which produced a long waiting list. By 2010 the scheme had over 50 km of pipe and about 50% of the households within reach of the pipes connected. Most of the largest heat users are now connected. Non-domestic customers are 10% of the total but account for 60% of the heat consumed. At two of the largest consumers, arrangements were made to take over the former boilers and keep them ‘in mothballs’ ready for use to feed into the scheme should flow from the Energy from Waste (EFW) plant or boilers have to be interrupted for maintenance purposes. As the installations had backup and were designed for worst case scenarios, they had sufficient spare capacity. It is anticipated that the lifespan of the boilers being kept in standby will be prolonged for many years. By 2006 the demand had grown so large that the backup oil boilers were consuming enough oil to meet morning peakloads to justify a 12 MWh thermal storage tank to store surplus heat during the early hours which was being dumped by coolers. Right from the start electronic ultrasonic heat meters were installed. Whilst initially read from an external plug, the meters had radio modules installed that could relay most of the readings back to the office thus enabling accurate billing and monitoring of cooling by customers. The scheme reached the output of the EfW plant in 2010 and numerous new sources of heat are being examined including front runner of wind turbines feeding into a large thermal storage tank. The potential increase of output from the EfW plant is also possible by the installation of an internal water jacket provided more waste becomes available. Whilst the scheme has brought environmental benefits in reducing emissions and landfill, it is the economic benefits that initially justified the scheme and these have been exceeded. With the reduction in imported fuels where money would have left the islands, reduced maintenance and capital costs of large customers and jobs created, economic returns (after deducting all costs and adding resultant benefits) of between 15 and 25% have been achieved.

14.7

Case study: Aars, Denmark

The DH system was established in 1955 with initially 26 customers signing up to the system. The initiative was taken by some local entrepreneurs who could see the local benefits from investment in this plant. Low heating costs and a safe supply of heat was essential to develop the town further. The first system was based on fossil fuels and the pipes were steel pipes in concrete ducts insulated with Rockwool and Leka stones, but from the 1960s the first pre-insulated pipes were installed. Oil was the main heat source, but the oil crisis influenced the design towards the development of alternative fuel



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sources and the Municipality and the District Heating Company developed plans for a Waste to Energy (WtE) plant (Fig. 14.5). The first WtE plant (6.5 MW) was established in 1985 and commissioned in 1986 together with a coal-fired (5 MW) peak and reserve boiler. The site was in the outskirts of the town and a transmission pipe was installed to supply the former oilfired boiler stations. As the town expanded, the new areas were connected to district heating via a heating plan and therefore the connection rates in these areas were 100%. This was very efficient and gave a good utilization of the pipes and the base load from the WtE plant was used during most of the year. The waste amount also increased and in 1995 the next incinerator was installed increasing the capacity by more than 100%. This was a combined heat and power line and included a 3 MW turbine together with a 10 MW heat capacity. This capacity was too big for the summer load and coolers had to be installed as there was a waste treatment obligation. The summer load only allows one incinerator to be in operation and the challenge was then to further expand the district heating area. Compulsory connection was approved by the municipality and during a 10-year period all houses within the district heating area had to connect. Now all houses in Aars are connected and in 2009 a neighbouring town was connected via a 7.5 km transmission pipe (Fig. 14.6). The transmission pipe has a special design to both take account of heat loss and pumping loss. It is a twin pipe with a DN125 in the flow giving high flow velocity and a DN150 in the return giving low pressure loss. Both

14.5 The Energy from Waste plant in Aars, seen from the east at the entrance to the town.



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14.6 A twin pipe with two different dimensions. This is the 7.5 km transmission pipe between Aars and Hornum in Denmark.

pipes are built into the same insulation dimension as a DN150/DN150 pipe to ensure optimum insulation, resulting in a temperature loss in the flow pipe of only 1 °C during winter operation in the 7.5 km long transmission pipe. The neighbouring town has a gas engine CHP plant and, in combination with the Energy from Waste plant in Aars, there is a possibility only to operate the engines when the electricity market is out of balance and giving high prices for regulating power. Further, a 1 MW electric boiler is installed and the purpose of this is to use some of the surplus electricity from the wind turbines. When operated it is at negative electricity prices, at down to – £150/ MWh. In total 4300 customers are now connected to the DH system and a few of the other neighbouring towns with gas engine CHP plants are also interested in connecting to Aars as the heating cost is low, there is still a little surplus energy during the summer period and the two incinerator lines could easily operate for longer periods. The project economies of these projects are to be investigated in 2010.



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14.8

363

Future trends

14.8.1 Temperature optimization To limit heat losses from the pipes, many DH systems are now introducing temperature optimization. The principle is to supply only the necessary temperature during summer and winter load most customers can operate their heating system with a flow temperature of 60 °C, but the temperature in the pipes depends on the flow rate and the insulation of the pipes. Therefore most systems have been operated on the safe side with too high temperatures resulting in unnecessary heat loss from the pipes. Computer programs can simulate the temperatures from the load situation and with control measurement the program can be balanced according to the actual conditions and afterwards the flow temperature and pressure from the plant optimized to the load situation.

14.8.2 Balancing of the electric grid As a result of the introduction of wind farms and the unpredictable electricity generation, the heating systems can be used as load dumps when there is overflow in the electricity market. Electric boilers are easy to operate and can react quickly. Although they only generate, e.g., 1 MW of heat when using 1 MW of electricity, heat pumps could improve the power factor considerably but the regulating capability is not yet as good as the boiler, but a combination of the two systems could be a possibility.

14.8.3 Pipe dimensioning Pipe dimensioning has mostly been relatively conservative, based on flow rates and velocity but branch pipes close to the boiler station could be made with smaller dimension because they have a high differential pressure available. This could also be used in the pipes instead of in a regulating valve.

14.8.4 Conversion from gas to district heating Conversion of natural gas areas to district heating is one of the new trends in Denmark as the natural gas resources are running out and the government is now supporting these conversions. Heat pump solutions are probably the new heat source for rural consumers and those who are not close to a district heating system as they can be made to primarily use electricity at off-peak periods or even at electricity overflow from wind turbines.



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14.9


Sources for further information and advice

∑ ∑ ∑

Danish Board of District heating, http://www.dbdh.dk/ Danish District Heating Association, http://www.danskfjernvarme.dk/ SHEAP Shetland Heat Energy and Power, District Heating Manager Neville Martin, http://www.sheap-ltd.co.uk/ ∑ COWI, http://www.cowi.com ∑ Aars District Heating, Director Jan Clement, homepage (only in Danish) www.aarsfjv.dk, or email [email protected], phone +45 9998 8070.



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15

Small combined heat and power (CHP) systems for commercial buildings and institutions

R. B o u k h a n o u f, University of Nottingham, UK

Abstract: Small-scale CHP has a huge potential to deliver energy savings and be an effective carbon mitigation strategy in commercial buildings and institutions. This chapter starts with a brief discussion about energy requirements, trends, and the regulatory frameworks driving energy efficiency in these types of buildings. Then details on technical and operational characteristics of small-scale CHP technology are given with emphasis on implementation in different types of buildings. Finally, future prospects and ways to support the technology are discussed. Key words: small-scale CHP, energy consumption, commercial buildings, institution buildings, energy efficiency, engines.

15.1

Introduction

The UK’s long-term manifesto on reducing carbon emissions is supported by the Climate Change Act 2008 that sets out a target of cutting greenhouse gas emission by at least 34% and 80% by the years 2020 and 2050, respectively, against the 1990 baseline (UK Parliament, 2008). This means significant emission cuts will have to be realised in each of the three main sectors of the economy responsible for the bulk of greenhouse gas emissions: the power generation sector, the transport sector, and the building sector. The latter consumes about 45% of the total primary energy and contributes to a corresponding amount of pollutants emission. The UK has a stock of about 1.8 million non-domestic buildings, which account for up to 18% of total CO2 emissions. These buildings consume approximately 300 TWh of energy a year, predominantly for the provision of space heating and cooling, hot water, and power for lighting and office equipment, as shown in Fig. 15.1 (Elsadig, 2005). Energy consumption of the existing building stock can vary widely as it is influenced by the design of the building envelope and the efficiency of the heating, ventilation and air conditioning (HVAC) equipment (Baird et al., 1984). The UK Building Regulation Part L2, conservation of fuel and power in non-domestic buildings, and the EU’s Energy Performance of Buildings Directive (EPBD), are the main tools for change towards sustainability in 365 © Woodhead Publishing Limited, 2011


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Small and micro combined heat and power (CHP) systems Other 7%

O ffi tio

7%

%

3%

t6

n

en

ng

ra

pm

oli

ge

ui

fri

eq

Co

ce

Re

Space heating 32%

Ventilation 3%

Cooking

4%

Water heating 15%

Lighting 23%

15.1 Energy use in non-domestic buildings.

the building sector. The EPBD requires display energy certificates (DECs) in public and commercial buildings and energy performance certificates (EPCs) to be made available at point of sale or rent. The EPCs rating of a building carries, among other benefits, help to identify poorly operated buildings and a list of remedies that can be taken to improve the overall energy performance of the building (EU Parliament, 2002). The UK building regulations are continually evolving for tighter building construction and operation standards. For instance, Part L of the proposed 2011 building regulations will include 20% improvements in building energy performance. Eventually, it is intended to have building regulations enforcing a target of zero carbon emissions for domestic and non-domestic buildings in 2016 and 2019, respectively.

15.2

Basic issues and energy requirements

In the UK, information regarding energy consumption in non-domestic buildings is generally not easily available and not explicitly compiled compared to the industrial and domestic sectors. This is due in part to the diverse nature of buildings with different physical forms and sizes that fall in this category and which are used in a wide range of activities including industrial, commercial, public service, transport and agricultural sector. Figure 15.2 shows a sample of non-domestic buildings with different economic



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Small CHP systems for commercial buildings and institutions

Others 23%

367

Retail 22%

Leisure 6% Offices 17%

Hospitals 6% Schools 10%

Hotels and restaurants 16%

15.2 Energy use in the commercial sector by building type.

activities and the proportional energy consumption (Pérez-Lombard et al., 2008). Furthermore, these types of buildings would often be serviced by plant and equipment with varied power capacities, presenting a major difficulty for collecting accurate and reliable statistical data and producing standardised energy consumption patterns. The implementation of the DECs scheme may offer an opportunity to improve the national database and establish an accurate benchmark of energy consumption in this sector of the economy. Recent energy consumption statistics in the UK non-domestic building stock normalised by floor area (i.e., kWh/m2) show an increase of about 5% between 1990 and 2008. This upward trend is mainly a reflection in increased electrical energy consumption that follows from the overall increase in the commercial sector floor space. The improvement in efficiency of building services equipment slowed down the increase in energy use for air conditioning, refrigeration, lighting, IT, and long opening hours in large retail stores. It is increasingly recognised that investment in the energy efficiency of buildings has, in addition to cutting the cost of energy used and supporting efforts for climate change mitigation, the benefit of improving occupants’ productivity and health (Scrase, 2000). The deployment of commercially available renewable energy and low carbon technologies to provide space heating, air conditioning and lighting could contribute to substantial carbon savings in non-domestic buildings. However, the high cost of deployment of renewable energy technologies (PV, heat pumps, etc.) makes returns on investment unattractive to potential investors. Combined heat and power



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(CHP) is, however, a proven and reliable technology that can reduce carbon emission and be cost effective.

15.3

Small combined heat and power (CHP) use in commercial buildings and institutions

The adoption of CHP systems as an energy supply option in industry and district heating schemes is well established in the UK and the developed countries. CHP systems can be found in all sectors of the UK economy, from individual dwellings to heavy industries and processes and large district heating schemes. In 2008, the UK total CHP electricity generation capacity stood at around 5.5 GWe with a heat-to-power ratio of 1.87 and an overall thermal efficiency of 67.2% (DUKES, 2008). Most of the power is generated from large-scale CHP plants installed in the industrial sector (oil, gas, chemicals and paper industries). Electrical power generated from CHP plants installed in the building sector, however, accounts for only around 344 MWe, representing just over 7 per cent of the UK’s total CHP capacity (DUKES, 2008). Because of the small-scale nature of the CHP plants installed in buildings, these constitute over 90% of the total number of CHP installations. To reduce carbon emissions and help deliver the Climate Change Programme, the UK has a target of achieving at least 10 GW of Good Quality CHP electrical power capacity by the end of 2010. However, this seems unlikely to be met on current trends as growth in installed CHP capacity has stagnated in the last few years. The use of small-scale CHP plants to provide heat and power in the building sector was first introduced in buildings where there is year round demand for both heat and power such as sport centres, hospitals and hotels. Current applications for small CHP in buildings has been extended to encompass universities, schools, tower buildings, sheltered housing schemes, military bases and even farms. Most small-scale CHP plant are built as complete units on a common frame with enclosure with electrical power rating ranging from as low as 30 kW to up to 2 MW. Table 15.1 gives a summary of the total number of small-scale CHP schemes and power generation capacity in different types of commercial buildings and institutions (DUKES, 2008). It can be seen that the largest proportion of the CHP capacity is installed mainly in hospitals, whereas leisure centres and hotels have the largest number of installations. Generally, the basic common requirement for a small-scale CHP is to satisfy the electricity and heat demand in a building with operation in excess of 4500 hours per year or about 14–16 hours/day to be economic (CIBSE, 2007). The traditional intermittency operation of a boiler, to provide heat in a building only when required, is not compatible with the mode of operation of a CHP system. A small-scale CHP should operate continuously and be



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Table 15.1 Number and capacity of CHP installations in the building sector (DUKES, 2008) Building type

Number of schemes

Electricity Heat capacity capacity (MWe) (MWth)

Leisure Hotels Health Residential group heating Universities Offices Education Government estate Retail Other (agriculture, airports, domestic buildings)

394 254 187 40 41 17 17 17 17 3

50 36 124.2 27.7 50 15 10 15.9 4.6 10.5

54.8 45.4 190.4 61 83.8 12 17.7 18.6 3.4 18.7

Total

987

344

505.7

sized to have a heat-to-power ratio comparable to that of the building it intends to service. A departure from full-load operating conditions impacts negatively on the thermal efficiency of a CHP system and hence results in longer payback period. Correspondingly, the outlet temperature level should be suitable for the heating application. For instance, the minimum required temperatures in building applications vary from 40 °C, where underfloor heating is used, to 80 °C for conventional radiators. Thus, a temperature of approximately 100 °C can be regarded as the sufficient output temperature of a CHP system. Therefore, while the overriding aim of installing and sizing a CHP system will be to supply all normal electricity and heat load, in practice this is not always realistic and supplementary grid power and heat from a standby boiler will be considered as part of an overall design strategy.

15.4

Small-scale combined heat and power (CHP) technology

CHP technologies are traditional power generation equipment where the attendant heat from fuel energy conversion into mechanical or electrical energy is recovered for heating or cooling purposes. In this way, smallscale CHP systems can convert up to 80% of the energy in the fuel (GCV) into electrical power and useful heat. This compares favourably with the conventional method of supplying heat and power to buildings from a heatonly boiler and grid. Most small-scale CHP units used in buildings come as packaged plant built around an engine with all components assembled and ready for connection to



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a building’s heating and hot water circuit and electrical distribution panels. Approximately 30% of engine fuel energy input is converted to mechanical power to drive the electric generator, where the conversion into electricity occurs with little loss. Of the remaining energy released in the engine, over 50% can be recovered as useful heat using a heat recovery system. The heat recovered for small-scale CHP is in the form of low temperature hot water (LTHW) at between 70 and 90 °C. A further 10% of available heat can also be recovered at low temperatures of 30 to 50 °C. Figure 15.3 shows a Sankey diagram of energy balance for a small-scale packaged CHP system. Other associated equipment with a small-scale CHP system include a control and monitoring panel that operate the engine start-up and shut-down sequences to ensure safe functioning, an exhaust system with compatible materials, and an acoustic enclosure to attenuate noise emanating from the plant.

15.4.1 Heat engine types The heat engine, also known as the prime mover and the term ‘engine’ will be used throughout this chapter, is the main component of a CHP system. The heat engine, which is referred to here as simply engine, is used to drive an electric generator to convert fuel energy into electricity. Commonly, there are three types of engines used in small-scale CHP for buildings. Reciprocating internal combustion There are two well-known types of reciprocating engine used in small-scale stationary power generation and CHP applications: the spark ignition (Otto cycle) engine and the compression ignition (Diesel cycle) engine. The main difference between the two types is the method of igniting the fuel. Spark Power 30% Useful heat 50%

er

ed

heat

Fuel energy 100%

Heat losses 20%

Reco

v

15.3 Energy balance of a small-scale CHP.



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ignition engines use a spark plug to ignite a pre-mixed air/fuel mixture introduced into the cylinder. In Diesel engines, the fuel is injected into the cylinder at high pressure after the introduced air has been compressed to a high pressure, raising its temperature to the auto-ignition temperature of the fuel. The thermal efficiency of internal combustion engines depends primarily on the compression ratio of the fuel–air mixture in the cylinder with a typical range of 12–24 for diesel engines and 9–12 for spark ignition engines. This makes diesel engines achieve thermal efficiencies of up to 45% whereas that of its spark ignition counterpart is limited to about 35%. The spark ignition engines are based on automotive or marine (industrial) engine derivatives converted to run on gaseous fuel such as natural gas. These engines are available in sizes from down to 20 kW and up to 5 MW electrical power output. The automotive derived engines are usually rated below 200 kW electrical power output rating whereas the industrial counterparts have a higher power output rating. In addition to CHP applications, diesel engines are widely used to provide standby power in sites such as hospitals and data servers that require uninterruptible power supply to protect critical services. Converted diesel engine standby generators for small-scale CHP are often limited to sites where the electrical power demand is in excess of 500 kW and run on diesel fuel or diesel/gas dual fuel. The reciprocating engines have proven reliability, low maintenance requirements and good service life. Depending on the engine size, a full engine overhaul is only required after achieving between 20 000 and 50 000 running hours. The economic benefit of a small-scale CHP is enhanced by effective recovery and use of the thermal energy rejected from the engine. Approximately 60–70% of the inlet fuel energy appears as heat energy, a proportion of which can be recovered from the engine exhaust gas, jacket cooling water, lubrication oil and turbocharger cooling water, and electric generator coolant. The exhaust gas leaves the engine at a typical temperature range of 450–650 °C, contains about 10–30% of the fuel energy while heat in the engine jacket coolant accounts for about 30% of fuel energy input. The heat recovered from the engine is generally in the form of low temperature hot water (90 °C) or low steam at a pressure lower than 2 barg. Figure 15.4 shows the main components and heat flow paths in a gas-fired internal combustion engine. Reciprocating engines for small-scale CHP are a well developed and proven technology. They offer low initial cost, easy to start up, good reliability and availability with a proper maintenance schedule. Better control of the combustion process and use of exhaust catalysts have led to a significant improvement in greenhouse gas (GHG) emissions. However, because a large proportion of the heat energy rejected is of low grade, the ability of the engine



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Fuel input

3-phase Control power panel supply

Exhaust gases

Low temperature hot water supply Exhaust heat exchanger

Internal combustion engine

Hot water return

Lubrication oil cooler

Water jacket cooler

15.4 A simple layout diagram of an internal combustion gas engine for small-scale CHP.

to produce steam is limited. However, this is less critical in commercial and institutional buildings. Gas turbines Gas turbines are an established technology that is widely used by utility and industrial power generators. These are often modified aero-engines where part of fuel (e.g., natural gas or gas-oil) energy released in the combustion chamber is converted to electrical power at an efficiency ranging from 20 to 35%. Combustion gases exiting the turbine at a temperature over 450 °C are a source of high grade thermal energy. The rejected heat from the exhaust gases can be recovered as steam or hot water in an unfired or fired heat recovery boiler. Depending on size and operating properties of the gas turbine, the recoverable heat-to-power generation ratio can vary between 1.5 and 3. The heat-to-power ratio can be increased to over 6 by further fuel combustion in the waste heat recovery boiler to take advantage of excess oxygen content of the exhaust gases from the gas turbine. Hence this is very useful for sites with variable heat loads. The available high quality waste heat, high reliability, and low maintenance costs per unit of power generation make gas turbines the favourite candidates for industrial and commercial CHP applications. Gas turbines can be used in small-scale CHP systems with power output ranging from just under 1 MW to a few MWs. However, the number of sites suitable for gas turbine-powered CHP systems in commercial buildings and institutions is usually limited to those with high pressure steam demand and electricity loads above 1 MW. In practice, gas turbines form a very small percentage of all CHP systems



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installed in buildings and are mainly confined to large hospitals where a small proportion of heat demand is in the form of steam used for medical equipment sterilisation. Micro-gas turbines Micro-gas turbines are small combustion gas turbines with power output ranging from 30 kW to over 200 kW. The scaling down of gas turbine technology impacts negatively the heat and combustion processes which reduces the turbine power output and efficiency. Hence micro-gas turbines often operate at very high shaft speed (up to 100 000 rpm) and use electronic power inverters for power conditioning to generate a.c. voltage and at grid frequency. Equally, a heat recuperator is usually fitted in the exhaust hot gases to pre-heat compressed combustion air to reduce fuel consumption and achieve efficiencies of up 30%. Micro-gas turbines also offer the advantages of compact size, low weight per unit power, multi-fuel capability and ease of emissions control. Figure 15.5 shows a schematic diagram of a microgas turbine. The introduction recently of packaged micro-gas turbines has offered comparable capital costs to reciprocating internal combustion engines with the benefit of lower maintenance costs and high availability, offsetting the lower electrical efficiency. The main application for micro-gas turbines is in packaged small-scale CHP which can be installed as single or multiple units, achieving an overall efficiency higher than 80%. Micro-gas turbines can also be used for emergency or standby power generation as well as a mechanical drive for pumps and compressors. Typical performance characteristics Combustion air

Turbine

Compressor

Generator

Exhaust gas

Heat exchanger

Fuel

CC Electricity supply

Recuperator

Hot water/ steam supply

15.5 A simplified diagram of a gas-fired micro-gas turbine CHP system.



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of the main engines used in small-scale CHP plants are summarised in Table 15.2.

15.4.2 Integration of small-scale CHP into building services Heating and hot water services Heat supply in buildings is mostly required for space heating and hot water, and heat is recovered from small-scale CHP systems at about 80 °C when reciprocating internal combustion engines are used. Where steam is required, this can be generated directly from the exhaust gas heat recovery heat exchange of the engine or a micro-gas turbine. A working fluid (e.g., water) is circulated in a closed loop pipe work that includes backup boilers to transfer heat to the site heat loads. A plate heat exchanger, located on the return feed of the heating system of the building, offers a practical method of interface between the CHP header pipe and the heating circuit, as shown in Fig. 15.6. This series connection arrangement in particular offers an easy method of incorporating packaged CHP units into existing boiler-only heating systems in buildings. In new CHP installations where the CHP system is sized to provide a substantial amount of heat demand, then the CHP unit can be installed in parallel with the backup boilers. Regardless of the adopted installation arrangement, the CHP unit should operate as lead boiler to maximise the number of running hours and the boilers provide a spare heating capacity to be used at times of peak load. Packaged CHP units using internal combustion engines are usually designed to operate within a range of water supply and return temperatures (e.g., 80/70 °C ± 3 °C) and any deviation from this range will cause the engine controls to shut down the unit. Hence the building heating system must be correctly sized in terms of heat dissipation, water flow rates, water supply and return temperature to eliminate frequent start and stop cycles. Table 15.2 Type and properties of heat engines used in packaged CHP for buildings Engine

Electrical Electrical Overall Heat grade power range efficiency efficiency (kW) (%) (%)

Gas turbine

>900

30–40

65–90

High temperature (steam)

Internal combustion 20–15 000 engine

30–45

65–90

Low and medium temperature

Micro-gas turbine

20–25

75–85

Low, medium temperature and capable of raising steam

30–200



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Small CHP systems for commercial buildings and institutions Main circulating pump

Isolating Header valve pump

375

Hot water return

Plate heat exchanger Header pipe

CHP unit 1

Hot water supply

CHP unit 2

Back up boiler Fuel supply

Circuit breaker

Building electrical distribution panel To building electricity loads

Connection to grid

15.6 Small-scale CHP heating circuit interface with building services.

Electric services The selection of a small-scale CHP unit for buildings is usually based on supplying the building with as much heat and electrical power as economically viable to satisfy onsite energy loads. In most cases small-scale CHP systems in buildings will be operated in parallel with the public electricity supply network to export or import power as the electricity load profile of the site dictates. Connecting the CHP unit to a distribution network introduces a new source of energy which may increase the ‘fault level’ in the distribution network (i.e., the fault current that may flow when a fault occurs) and render its detection and isolation difficult. The power generated by a small-scale packaged CHP would commonly be three-phase voltage at 415 V or 11 kV and frequency of 50 Hz. Alternatively, a step-up transformer could be used to increase a generator voltage from 415 V and 11 kV to supply electricity to site. Figure 15.7 shows a simplified single line diagram of a CHP electrical connection. Prior to connecting a CHP plant to a low voltage grid, it is the building operator’s responsibility to inform the distribution network operator (DNO) and approval must be obtained before the connection can take place. The power generation at low voltage in a small-scale CHP in commercial and institution buildings means that connection to the grid will be mostly covered



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CHP unit

Building distribution panel (415 V)

Circuit breaker

Building loads

Voltage transformer Connection to grid (11 kV) Circuit breaker Grid

15.7 A simplified single line diagram of a small-scale CHP electrical connection.

under Electricity Association Engineering Recommendation G59/1. The engineering recommendations set out the conditions for the generator to maintain fault duration, voltage and frequency variations within statutory limits. When run in parallel mode, the CHP must be equipped with adequate protection equipment so that the plant is automatically disconnected in the event of an electrical failure or fault. In building sites where backup power is required to maintain critical service operation during an outage of local area power distribution systems, smallscale packaged CHP can operate in island mode by shedding non-critical loads. However, for an islanding mode of operation, the electric generator must be of synchronous type and the CHP plant must also be fitted with grid synchronisation equipment which would increase the cost of the system. Management of exhaust gases Small-scale CHP plant rooms are often located in the basement or rooftop of buildings with strong mounting platform. In common with boilers, adequate volumetric flow rates of ambient air is drawn in from an outdoor intake to the plant room for combustion and ventilation of the plant room. The exhaust system is then used to discharge the combustion products away and at an outlet point from which it cannot be re-circulated into the building ventilation system. Hence often exhaust duct outlets are extended to building



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roof level with due consideration for compatible duct material, insulation and vibration isolation.

15.5

Application of small-scale combined heat and power (CHP) technology in buildings

Commercial and institution buildings are complex structures with challenging operational requirements. Energy performance of a building depends on adequate use of passive energy strategies such as improved building envelope, maximising use of day time lighting, passive cooling and ventilation as well as its interface with the heating and power services. The UK and EU have made strong commitments to reducing GHG emissions from buildings through tougher building construction standards and integration of renewables and energy efficient systems (UK Parliament, 2008). This carrot-and-stick approach rewards building operators by earning higher display energy certificate (DEC) rating, avoiding climate change levy on consumed fuel and generated power, and attracting renewables obligation certificates (ROCs) when biomass fuel is used. Hence, small-scale CHP is currently the technology of choice for the provision of heat and power in new and refurbished commercial buildings and institutions, as it is a more cost effective technology than renewables.

15.5.1 CHP systems in large office buildings The increase in energy consumption in UK commercial buildings is partly due to rapid growth in floor space with offices, for instance, occupying almost twice as much floor space as in 1970 (Scrase, 2000). Despite improvement in energy efficiency of engineering services, this has led to a rapid growth in energy consumption particularly for space air conditioning, IT equipment and light. The good practice energy consumption in offices in the UK ranges from 112 kWh/m2 per year for naturally ventilated buildings, to 348 kWh/m2 per year for prestigious air conditioned buildings (BRE, 1998). The energy consumed in prestigious office buildings is heavily skewed towards the use of electricity to run traditional vapour compression chillers for space air condition. Hence the proportion of energy used as heat compared to electricity varies widely in commercial office buildings. On average the heat-to-electricity demand ratio ranges from 0.54 for prestigious office buildings to 2.4 for naturally ventilated buildings. Hence CHP systems become attractive in office buildings with high heatto-power ratio as demand for space heating is important. Existing packaged CHP using internal combustion gas engines have a heat-to-power ratio in the range of 1 to 2 which can service this type of building adequately. Equally, in prestigious office buildings where substantial demand for electricity



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for space air conditioning, thermally activated absorption chillers using waste heat from the CHP system can practically replace traditional vapour compression chillers to reduce overall energy consumption. It is estimated that deployment of small-scale CHP in commercial office buildings could reduce overall CO2 emissions in this sector by 5–22% (BRE, 1996).

15.5.2 CHP systems in higher education institutions The higher education sector has been at the forefront of innovation in building sustainability as capital allocations by the higher education funding authorities are increasingly tied to the achievement of sustainability targets. The UK university estate is large and diverse which has a built floor area approaching 25.4 million m2 of floor space (Building, 2009). In 2006, the total energy consumption of the higher education institutions (HEI) was about 8.2 GWh which represents roughly 3.5% of the total energy consumption for the UK service sector. The average energy consumption intensity across all the institutions stands approximately at 287 kWh/m2. This average value is, however, above the 162 kWh/m2 recommended in the best practice benchmark of Higher Education Environmental Performance Improvement (HEEPI) (Ward et al., 2008). Energy rating of all new and refurbished buildings in this sector is expected to achieve a BRE Environmental Assessment Method (BREEAM) rating of ‘good’ or ‘excellent’, whereas the long-term target is to work towards zero net carbon emissions which is planned to be introduced in 2019. Electricity and gas are the main forms of energy used in HEI buildings, accounting for 37.6% and 53.5%, respectively. Assuming that gas is used mainly for space heating and hot water, then the ratio of heat to power demand is about 1.4. Therefore, HEI buildings present a favourable electrical-to-total thermal ratio for integration of small CHP systems. Small CHP use in the education sector has had a successful track record in many institutions. Table 15.3 shows a sample of current small-scale CHP schemes in university campuses in the UK (DUKES, 2008). It is shown that gas-fired reciprocating engines are overwhelmingly the technology of choice for this type of building. The following describes two typical gas-fired small-scale CHP schemes used in higher education institutions. Small-scale CHP at the University of Edinburgh Since 2003, the University of Edinburgh has installed three small-scale CHP systems on its campuses. One of the CHP systems was installed in 2005 on George Square campus to provide heat, power and cooling. The £7m CHP system investment comprises one 1.6 MW power output gas-fired



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379

Table 15.3 Current CHP schemes in university campuses (DUKES, 2008) University site

Engine

Generating Town/city capacity (kWe)

Coventry University, Charles Ward Building (A Block)

IC engine

306

Coventry

Coventry University, Graham Sutherland Building (M Block)

IC engine

211

Coventry

Coventry University, William Morris Building

IC engine

211

Coventry

Coventry University, Armstrong Siddeley Building

IC engine

206

Coventry

Coventry University, Ellen Terry Building

IC engine

306

Coventry

Lancaster University

Gas turbine 1400

Lancaster

University of East Anglia (Plain Campus)

IC engine

3054

Norwich

University of Bath, Scheme 2, Stv

IC engine

189

Bath

University of Bristol, CHP 2

IC engine

1160

Bristol

University of Bristol, CHP 1

IC engine

501

Bristol

University of Dundee, Main CHP Boilerhouse

IC engine

3000

Dundee

University of Edinburgh, King’s Buildings

IC engine

2700

Edinburgh

University of Edinburgh, Pollock Halls of Residence

IC engine

526

Edinburgh

University of Edinburgh, George Square campus

IC engine

1644

Edinburgh

University of Southampton

IC engine

2826

Southampton

University of Surrey

IC engine

1040

Guildford

University of Ulster, Jordanstown Campus

IC engine

1000

Newtownabbey

University of Ulster, Gibbet Hill Energy Centre

IC engine

400

Coventry

University of Warwick, CHP Boilerhouse (CHP 2)

IC engine

4197

Coventry

University of York

IC engine

979

York

University college London, Gower Street Heat & Power Ltd

IC engine

2944

London

GE Jenbacher 612 internal combustion engine; two 6 MW and one 3 MW low-temperature hot water backup boilers; a 600 kW absorption chiller exploiting byproduct heat to cool specialist laboratories in summer; and a 75 m3 thermal store (Somervell, 2006). The CHP engine thermal output is



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1.7 MW, a fuel to electrical energy conversion efficiency of 42% and an overall efficiency of 86%. Although the CHP runs in parallel with the grid, the building energy controls have been set up so that the CHP operates on no-exporting mode by supplying all site power loads while retaining a small inflow from the grid. The current feed-in tariff makes exporting surplus electricity to grid unattractive. In its first full year, the combined CHP and cooling system saved £220 000 in energy costs and 1250 tonnes of CO2 emissions. It is projected that by further optimisation of electricity generation, annual savings of nearer £500 000 could be realised. A simplified schematic layout of the CHP system is shown in Figure 15.8. Small-scale CHP at the University of Dundee Steady growth in electricity consumption at Dundee University has led to identifying that small-scale CHP represented the most realistic mechanism for controlling electrical energy costs and an initial feasibility study was undertaken in 1988. However, it was not until 1995 when an improvement in heat-to-power ratio demand profile, coupled with lower gas prices and rising electricity costs, allowed the CHP project to be launched. The small-scale CHP plant consists of three Jenbacher J320G5-BO5, 4 stroke 20 cylinder spark ignition gas-fired engines rated at 1002 kW power output each. Each engine drives a 3.3 kV alternator at 1500 rpm (DUUSCo, 2009). Heat recovery from exhaust gas, first stage turbo intercooler and jacket water is passed by plate heat exchangers into the returning of existing district heating system water before it enters the boiler plant. When water conditions permit, all the available heat is utilised in the pre-heating function, otherwise some of the jacket heat is used to heat nearby buildings, and any surplus is dissipated to atmosphere by heat damping coolers. Electrical power from the CHP plant is then fed into the university’s 11 kV distribution network via a 4 MVA voltage step up transformer. The CHP plant is fully computerised and is set to operate in load-following mode with output level set to minimise the electricity importation rate. Each engine generator unit is fitted with a comprehensive monitoring system which is connected via modem link with the system suppliers who are contracted for a long-term maintenance agreement. As the boiler plant forms part of an academic teaching building, noise and vibration generated by the engines become an important issue to be resolved. Hence an acoustic enclosure and vibration isolation equipment were fitted to prevent transmission through the building structure. The noise level emanating from air fans of the outside heat damping units also needed to be kept below 37 dB(A) as these were in proximity to adjacent residential property. Hence the cooling units were fitted with multiple slow running



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CHP engine

Glycol circuit

85 °C

Building loads

415 V

Heat dump heat exchanger

75 °C

95 °C

Plate Heat exchanger

60 °C

Thermal store 75 m3

Circulating pumps

Backup boiler 3 3 MW



60 °C

Hot water 80 °C supply

15.8 A simplified schematic layout of the CHP and cooling (trigeneration) system at Edinburgh University.

Grid connection

11 kV local grid

Gas supply

Absorption chiller

80 °C

Chilled water supply

382


fans each having two silencers, and electronic speed control ensures that the fans start and speed up progressively to avoid any sudden changes in the perceived sound level.

15.5.3 CHP systems in health care buildings Health care buildings are the most energy intensive buildings in the commercial and institution sector as they are usually occupied 24 hours per day, all year round and they require a careful control of the internal climate. In the UK, existing health care buildings are often old and operating outside the energy performance indicator of 55–65 GJ/1003 of heated volume. In 2008, energy consumption in National Health Service (NHS) England buildings amounted to about 9465 GWh, of which 45% was electricity and causing around four million tonnes of CO2 to be discharged to the atmosphere (NHS, 2009a,b). The health care buildings’ typical energy demand for thermal energy for space heating, hot water and electrical power is often required simultaneously most of the time with an average load factor above 80%. Therefore, hospitals buildings represent an ideal case for the application of CHP technologies. Table 15.4 shows a sample of existing small-scale CHP scheme installations of less than 2 MW power output in hospitals across the UK (DUKES, 2008). All the listed CHP installations are gas-fired internal combustion engines. An example of a typical gas-fired small-scale CHP scheme has been installed in Royal Shrewsbury hospital. In 2004, an energy audit of the hospital commissioned by Shrewsbury and Telford NHS Trust showed the primary energy consumption stood at around 100 GJ /100m3, nearly double the NHS target indicator. The study identified small-scale CHP as the best way of improving the hospital’s energy efficiency (EnerG, 2007). In 2007, a small-scale CHP system using a gas-fired Caterpillar internal combustion engine with a rated power output of 1150 kW was installed. The CHP system provides nearly 1.7 MW of thermal energy in the form of both medium temperature hot water and steam at 120 °C. This is supplemented by a dual-fired backup boiler. The unit is also connected to a 700 kW absorption chiller, installed as part of the CHP scheme. The scheme was delivered through a fully funded performance contract with annual savings of £780k guaranteed for 15 years (EnerG, 2007). Similarly, a small-scale CHP has been installed in a purpose-built energy centre at Birmingham Heartlands, a major general hospital managed by Heart of England NHS Foundation Trust, to provide heat, power and cooling. The CHP project cost was £5 million and financed by EnerG Combined Power Ltd through Public Private Partnership agreement with a £403 000 grant from the Carbon Trust under the Community Energy Programme. The project is estimated to save £688 000 a year and cut emissions of CO2 by



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383

Table 15.4 Small-scale CHP installations in hospitals (DUKES, 2008) CHP Site name

Engine

Generating Town/City capacity (kWe)

Cannock Chase Hospital

IC engine 303

Cannock

Royal Devon and Exeter Hospital

IC engine 1016

Exeter

Stoke Mandeville Hospital

IC engine 979

Aylesbury

Leighton Hospital

IC engine 225

Crewe

Leighton Hospital

IC engine 600

Crewe

Dewsbury District Hospital

IC engine 480

Dewsbury

Pontefract General Infirmary

IC engine 409

Pontefract

Milton Keynes General Hospital (Phase 2)

IC engine 152

Milton Keynes

Milton Keynes General Hospital (Phase 1)

IC engine 185

Milton Keynes

Biggart Hospital

IC engine 54

Prestwick

Guildford Nuffield Hospital

IC engine 165

Guildford

Sussex Nuffield Hospital

IC engine 165

Brighton

Southmead Hospital

IC engine 979

Bristol

University Hospital of North Tees

IC engine 1550

Stockton on Tees

Gwynedd Hospital

IC engine 330

Bangor

Northampton General Hospital (CHP 2)

IC engine 211

Northampton


IC engine 409

Northampton


Gas turbine

Northampton

105

Causeway Hospital

IC engine 900

Coleraine

Rochdale Infirmary

IC engine 300

Rochdale

Poole Hospital (CHP 2)

IC engine 210

Poole

Poole Hospital (CHP 1)

IC engine 400

Poole

Royal Manchester Children’s Hospital

IC engine 145

Manchester

Salisbury District Hospital

IC engine 400

Salisbury

Western General Hospital, Lothian Universities NHS Trust

IC engine 1003

Edinburgh

The Princess Royal University Hospital

IC engine 995

Orpington

St Anthonys Hospital

IC engine 168

North Cheam

Norfolk and Norwich University Hospital

IC engine 979

Norwich

United Bristol Healthcare Trust

IC engine 979

Bristol

Glenfield Hospital

IC engine 570

Leicester

Dorchester County Hospital

IC engine 370

Dorchester

Lincoln County Hospital

IC engine 1413

Lincoln



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Table 15.4 Continued CHP Site name

Engine

Generating Town/City capacity (kWe)

Bedford Hospital

IC engine 300

Bedford

Montagu Hospital Mexborough

IC engine 110

Mexborough

Lagan Valley Hospital,

IC engine 306

Lisburn

Forth Park Maternity Hospital

IC engine 95

Kirkcaldy

Royal Infirmary of Edinburgh

IC engine 1029

Edinburgh

1627 tonnes per year (EnerG, 2007). The CHP systems has a 1165 kW power output capacity MTU gas-fired engine with a heat output of 1272 kW and is also equipped with steam raising capability, backup boilers and a 300 kW absorption cooling system which operates off the gas engine waste heat and serving to meet the air conditioning demand during warmer months of the year.

15.5.4 CHP systems in leisure and recreation buildings Leisure, recreation and accommodation buildings have a steady demand for heat for space heating, catering and showering for up to 24 hours a day, making CHP very cost effective. Where swimming pool facilities are installed, the heat and electricity demand increase substantially specifically for heating water and ventilating the pool hall, and the case for CHP becomes even more compelling (Carbon Trust, 2008). Actual energy consumption in leisure and recreation buildings with pool facilities could be as high as 237 kWh/m2 and 1336 kWh/m2 per year for heat and electricity, respectively, compared to good practice of 152 kWh/m2 and 573 kWh/m2, respectively (ETSU, 2001). The leisure and recreation industry has been an excellent example for application of CHP to lower energy costs. Current small-scale CHP systems in the UK’s leisure and recreation buildings contribute more than 20 MW to the total of UK electricity generation capacity. With a few exceptions, most of the plants use gas-fired internal combustion engines with power output ranging from as low as 40 kW to over 500 kW (DUKEs, 2008). For instance, David Lloyd Leisure has more than 46 small-scale CHP plants with another dozen units planned for the next few years in new buildings or as retrofit to existing building services. It is projected that electrical and heat output of 73 GWh and 115 GWh a year, respectively, will be supplied with energy bill savings of £0.9 million and reduction in carbon emissions of 16 000 tonnes a year (EnerG, 2008).



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385

15.5.5 CHP systems in supermarkets and hypermarkets A typical supermarket in the UK uses about 1200 kWh of electricity and 260 kWh of gas per square meter of floor sales area per year compared to the industry benchmark of 915 kWh/m2 for electricity and 200 kWh/m2 for fossil fuels (CIBSE, 2004). Figure 15.9 presents a breakdown of a typical UK supermarket energy consumption. It is shown that approximately 75% of the energy is used for powering vapour compression refrigerators/freezers and HVAC equipment, whereas energy consumption for hot water is very modest. Hence, implementation of CHP in the classical way would result in underutilisation and limited primary energy savings. To increase the utilisation time, excess heat generated by the CHP plant would be used to drive an absorption chiller to displace grid-electricity operated food cooling equipments. The application of an integrated CHP/absorption scheme (trigeneration) in the supermarket can increase the attractiveness of small-scale CHP by utilising available waste heat to shift cooling from an electricity load to a thermal load in a very cost effective way (Zogg and Brodrick, 2005). The use of integrated small-scale CHP with heat driven absorption chiller is also an environmentally benign way that would provide heat, power and cooling/refrigeration at a substantial reduction in CO2 emissions. This could be realised in addition to reducing overall energy consumption, by using alternative refrigerants to hydrofluorcarbons (HFCs) with zero or low global warming potential, such as water and ammonia, with further benefit Others

tw

at

er

3%

Ho

Bakery 11% 3%

Lighting 11%

Refrigeration 49%

hvac 23%

15.9 Breakdown of energy consumption in UK supermarkets.



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of gaining additional BREEAM points. Table 15.5 shows an example of current small-scale CHP installation in supermarkets in the UK (DUKES, 2008).

15.6

Performance analysis and optimisation

Energy consumption patterns in commercial and institution buildings are complex and depend on type, size and activity carried out in the building. Hence a successful implementation of a small-scale CHP scheme requires conducting a detailed feasibility study of the building’s energy consumption patterns. This usually identifies accurately the building’s demand for all heat energy grades, electrical power and cooling. Then a daily and seasonal load profile for each form of energy demand must be established to inform selection of type and energy capacity of the CHP engine. One of the fundamental requirements in considering CHP for buildings is to have a steady and concurrent demand for electrical power and heat/ cooling all year round. This usually consists in running the CHP plant as ‘lead boiler’ to maximise the number of running hours. As a rough guide, a viable small-scale CHP scheme using internal combustion engines requires to run for about 14–16 hours a day and 4500 hours a year (CIBSE, 2007). This is usually achieved by selecting a CHP plant engine with a heat-to-power ratio that matches as closely as practical that of the building. While CHP systems have a higher capital and maintenance cost than using heat-only boilers and grid, it is more efficient than the separate supply of heat and power and savings in energy cost would usually suffice to realise payback periods of 3–5 years. The financial attractiveness of a CHP installation is further enhanced when a complete replacement of existing boilers is considered as its cost is partly offset against the displaced equipments. Most small-scale CHP systems used in buildings are gas-fired plants and purchased fuel constitutes the main running cost of the plant. Small-scale Table 15.5 Small-scale CHP installations in supermarkets (DUKES, 2008) CHP Site name

Engine

Generating capacity (kWe)

Town/City

Sainsbury’s – Cromwell Road CHP 1 Sainsbury’s – Richmond Sainsbury’s – Greenwich Sainsbury’s – Brighton Sainsbury’s – Romford Sainsbury’s – Burnley Tesco – Carmarthen Tesco – Gloucester Tesco – Swansea

IC IC IC IC IC IC IC IC IC

422 211 211 321 211 211 238 238 237

London Richmond Greenwich Brighton Romford Burnley Carmarthen Brockworth Swansea

engine engine engine engine engine engine engine engine engine



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387

CHP in buildings could use between 700 MWh and 25 GWh a year of gas for a 30 kW micro-gas turbine of 20% efficiency and a 2 MW internal combustion gas engine of 35% efficiency, respectively. The unit price of gas fuel and maybe of electricity import/export will be determined by individually negotiated contracts with an energy supply utility and will be greatly influenced by the pattern and volume of gas and power consumed (ETSU, 1983). The economic benefit of CHP is hence very sensitive to variation in displaced electricity and purchased fuel prices, the difference of which is referred to as ‘spark spread’. A high ‘spark spread’ encourages market uptake and installation of new plants as better investment yields can be achieved. Small-scale packaged CHP systems for buildings are designed to operate continuously and supply as high a proportion of the building’s energy demand as possible. In general, three main strategies could be considered.

15.6.1 Base heat load supply operation mode In this mode of operation, the CHP is sized to supply base heat demand and a backup boiler to meet heat demand peaks. This allows the engine to run continuously and at full-rated power output without the need for heat damping or thermal storage facilities. However, unless a site has a flat thermal load profile (i.e., a small peak-trough difference), adopting such a strategy will not yield the full economic and environmental benefits of using CHP. It is also most likely that only a small fraction of the site’s electricity demand will be met by the CHP and the grid will be used to supply the deficit in power demand. This strategy is, however, susceptible to increases or decreases in base load demand, making CHP uneconomical.

15.6.2 Base electricity load supply operation mode Generally, it is desirable that a CHP plant is sized to supply the building’s base load electricity demand. In this way, all electricity generated is used onsite and peaks in power demand will be provided from the grid. This, however, requires a careful assessment as the CHP plant thermal output will be higher than that of the building’s base heat load demand. Hence to be economically feasible, the CHP engine should be selected with as high a thermal efficiency as possible and means heat damping to atmosphere becomes necessary.

15.6.3 Cost-led operation strategy In this strategy various types of CHP plants will be considered. The economic evaluation centres on maximum accrued savings on hourly operation basis



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and taking into account the amortisation of the plant investment capital and running cost. one of the most probable ChP selection scenarios in this case is to size the ChP plant above the building’s heat base load demand and operating at full load for a maximum number of hours per day. This, however, will require provision of short-time thermal storage, backup boilers, heat damping, engine modulation and import and export of power to the grid to smooth out as much as practically possible the heat and power demand profiles. It is important the extra costs resulting from this additional equipment are accounted for at the evaluation stage. other operating possibilities in this cost driven strategy could also include running the ChP plant for coverage of peak load power demands. This is because the cost of imported electricity varies through the day and can be substantially higher during winter months’ peak hours. on the other hand, the cost of electricity generated by the ChP plant would remain unchanged as gas tariffs remain constant through the day (CIBSE, 1999). hence the marginal cost saving of ChP generated electricity during peak times may justify such a strategy.

15.6.4 CHP system performance indicators The high energy performance of a ChP system over traditional heat-only boiler and power from the grid is derived from the ability of the ChP plant to recover a large part of the attendant heat from the conversion of fuel to electrical energy that is wasted in centralised power station. hence the energy performance of a CHP plant is characterised by a thermal efficiency, he, which indicates the amount of fuel converted to electricity, and the overall efficiency, hChP, which is a measure of the primary energy savings that can be obtained compared to separate generation of heat and power. These can be expressed as follows:

he =

Pe Qf

hChP =

15.1 Pe + Qu Qf

15.2

where, Pe is the electrical output, Qu is the useable heat energy recovered and Qf is the total fuel energy input based on gross calorific value of the fuel. A further performance indicator that is specific to CHP systems is the heat-to-power ratio which is a useful property when selecting a ChP plant to match a specific building heat and power load. This is given as: hPR =

Qu Pe

15.3



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389

Therefore the amount of primary energy that can be saved using a ChP plant compared to supplying heat and power separately from a boiler and grid, can be evaluated as (Bruno 2005): Ê ˆ Es = Pe Á 1 + hPR – 1 ˜ hB he ¯ ËhG

15.4

where hG and hB are the average thermal efficiency of a centralised power station and boiler efficiency, respectively. finally, a simple estimate of the energy cost savings per unit of electrical power supplied by ChP plant and assuming that all heat recovered is used onsite, may be given as follows: Ê ˆ Cs = Cp + Cm + Á hPR – 1 ˜ Cg he ¯ Ë hB

15.5

where Cp, Cm and Cg are the unit cost of purchased electricity from grid, maintenance cost per unit of power generated from the ChP and unit cost of fuel, respectively. It is assumed, however, that the same type of fuel is used in the boiler and ChP.

15.7

Merits and limitations of small-scale combined heat and power (CHP)

Small-scale ChP has the potential to impact positively on the main pillars of the uk’s energy policy: security of supplies, diversity of energy sources, sustainability and affordability. It is a proven technology that can cut primary energy consumption and Co2 emissions from the building sector by as much as 30% compared to providing heat and power from a heat-only plant and grid electricity, respectively (Carbon Trust, 2004). Since the introduction of DEC, uk organisations are increasingly looking to improve their carbon footprint and on-site small-scale ChP is being promoted as the most cost effective available technology that can help achieve better EPC ratings. Small-scale ChP in buildings is a form of distributed generation that is often configured to operate in parallel with the electricity grid to allow power flow to and from the building. In the event of grid failure, it can thus operate as an emergency backup generator to maintain efficient operation of the building’s critical services. Equally important, small-scale ChP can improve stability of the local electricity network and benefit in the process large electricity utilities to reduce standby electric power generation capacity necessary to meet peak load demands. Good quality CHP receives further government financial support through Climate Change Levy (CCL) exemption on fuels and generated electricity, business rates exemption for ChP equipment, and earning renewable energy



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certificates (ROCs) when used in conjunction with renewable fuels. It can also impact positively on an organisation’s public relations and marketing profile for being perceived as technologically innovative and environmentally friendly. Despite all the technical and environmental credentials of small-scale CHP, market penetration is still limited. One of the main factors is high initial capital outlay compared to heat-only plants, making it difficult for commercial or public organisations to allocate funds for non-core business. Until recently, commercial and public organisations have made little commitment to consider long-term coordinated energy management strategies which impacted negatively on the small-scale CHP market. Furthermore, because suitability of small-scale CHP is site-specific, it makes the economic viability of a scheme directly linked to the site having a consistent base load demand for power and heat/cooling. This often presents a problem in the summer months when the need for heating is reduced, whilst the electricity demand remains fairly constant. Hence a detailed energy audit for any site will have to be carried to size the CHP for optimum performance, a process requiring a long lead time. Adding to this, the risk generated by unpredictable variation in prices of fuel, electricity, and high maintenance costs mean that initial estimates of a payback period cannot be guaranteed. This is exacerbated further by the competitive nature of the UK electricity market as small-scale CHP generators cannot compete on electricity prices. This has had the effect that small-scale systems being undersized so as to limit exporting electricity to the grid which may undermine the scheme’s viability. Small-scale CHP are usually installed in building basements or roof tops and have to comply with existing noise, vibration and air pollution regulations which entails installing acoustic enclosures, silencers and vibration absorbers to avoid transmission of vibrations through the building structure. Those plants located close or inside urban areas can impact negatively on local air quality. Internal combustion engines are the most common for CHP in buildings and can have high emissions of nitrogen oxides and unburned hydrocarbons which may be perceived as an additional risk about the technology and its benefits.

15.8

Future trends

Favourable energy prices (large spark spread) during the 1990s allowed growth in electricity generating capacity of CHP to increase by over 90% by 2001 (DUKES, 2008). Since then energy market conditions have changed markedly and with the reforms of the UK energy sector, through the introduction of the New Electricity Trading Arrangements (NETA), and the increase in gas prices led to a deterioration in ‘spark spread’. Thus, there has been a decline



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391

in investment in new CHP plants in general. As investment opportunities, small-scale CHP projects in buildings are also considered small business ventures with associated high initial costs and high risk, rendering them not very attractive for long-term investors. Furthermore, the competitive UK electricity market meant small-scale CHP operators (under 1 MW) have only been offered very low prices to export surplus electricity. This has had the effect of undersizing CHP plant designs to supply the building electricity demand instead of meeting all the building heat load and exporting excess power, undermining the full economic and environmental potential of smallscale CHP (Hinnells, 2008). The upward trend in energy consumption in commercial buildings and institutions is set to continue in the future because of expansion of built area and associated energy needs. The energy policies of the UK and other EU countries have put in place mechanisms for promoting energy efficiency in buildings, developing new technologies for energy generation, managing energy demand, and raising social awareness for a sustainable long-term economic growth (Pérez-Lombard et al., 2008). Small-scale CHP forms part of this energy policy with a huge potential to deliver energy savings and thus cost and emission reductions through to 2050 targets. This is reflected in a number of studies with a wide range of projection estimates. For instance, it has been estimated that with favourable energy market conditions, power output capacity of small-scale CHP in the commercial buildings and institutions sector could increase at a rate of 700 MW a year by 2020, even with no further government support. An additional financial incentive of £10/MWh could, however, stimulate this growth to 1.76 GW a year (BEER, 2005, Defra, 2004). It is intended that introduction of further framework policies such as the European EPBD, UK Climate Change Act, Building regulations of 2011, Carbon Reduction Commitment (CRC) should impact positively over time on market uptake of small-scale CHP and other renewable technologies. The CRC will require, for example, organisations that consume more than 6000 MWh of electricity a year to participate in the scheme from April 2010. It is estimated that around 5000 public and private sector organisations ranging from retail, leisure and manufacturing companies through to local authorities, universities and NHS Trusts will have to buy and surrender carbon allowances to cover their annual emissions from 2011. The UK has one of the most competitive markets for electricity generation and supply but at the same time no effective mechanisms have yet been put in place to develop a heat supply market (Toke and Fragaki, 2008). Recently, there has been some positive signs that suggest that the situation may change. This mainly stems from the acknowledgement that implementation of the Climate Change Act would require a new vision towards provision of heat for space heating and hot water in buildings, which accounts for approximately



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50% of all energy used in buildings. This is led by the publication of the UK government of a consultation document on the introduction of a Renewable Heat Incentive (RHI) scheme with the aim to be implemented in 2011. Under the proposed scheme, financial support will be offered to a range of technologies including CHP of all scales that is fuelled by renewable fuels such as biomass and biogas (DECC, 2010). Such a scheme should give necessary financial impetus to advance market penetration of existing gasfired internal combustion engine CHP and develop new technologies such as organic Rankine cycles that run on biomass fuels. The steady growth in energy consumption and the pressing need to cut the amount of CO2 discharges to atmosphere from commercial buildings and institutions have underpinned the energy efficiency strategy for this sector, with energy efficient technologies forming one of the pillars of this strategy. Among the proposed solutions, good quality small-scale CHP is the tried and tested technology which is readily available as packaged units of a wide range of heat and power ratings. Finally, installation of small-scale CHP in buildings can enhance energy certification, CRC, achieve building regulations standards and with the introduction of further support such as RHI, small-scale CHP will achieve the shortest payback period, making it the first consideration for investors and owners of new and refurbished buildings in the future.

15.9


15.9.1 Institutions ∑ ∑ ∑ ∑ ∑ ∑ ∑

The Carbon Trust: www.carbontrust.co.uk CIBSE CHP group: www.cibse.org Energy Saving Trust: www.est.co.uk Combined Heat and Power Association: www.chpa.co.uk EU Energy Performance for Buildings Directive: http://europa.eu Cogen Europe: http://www.cogeneurope.eu Department of Energy and Climate Change (DECC), http://www.decc. gov.uk/ ∑ World Alliance for Decentralised Energy (WADE) ∑ US Clean Heat & Power Association (USCHPA): http://www.uschpa. org/ ∑ US Department of Energy: http://www.energy.gov

15.9.2 Small-scale CHP installer/manufacturers ∑

GE Jenbacher: www.jenbacher.com – Internal combustion engines manufacture



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∑ ∑ ∑ ∑ ∑ ∑ ∑

Capstone: www.capstoneturbine.com – Micro-gas turbine manufacture Cogenco: www.cogenco.co.uk – CHP specialist Ener.G Combined Power Ltd: www.enerG.co.uk – CHP specialist ec Power: www.ecpower.co.uk – CHP specialist Caterpillar: www.cat.com – Internal combustion engines manufacture Dalkia: www.dalkia.co.uk – Internal combustion engines manufacture Wärtsilä Corporation: www.wartsila.com – Internal combustion engines manufacture ∑ Baxi-SenerTec UK: www.baxi-senertec.co.uk – Mini and micro-CHP provider

15.10 References Baird G, Donn M R, Pool F, Brander W, Seong Aun C (1984), Energy Performance of Buildings. Boca Raton FL: CRC Press, pp. 25–51. BERR (2005), Future Energy Solution – Renewable Heat and Heat from CHP plants – study and analysis report, ED02137 Published version. Available from: www.berr. gov.uk/files/file21141.pdf (accessed March 2010). Bruno J C (2005), Technical Module on Combined Heat and Power, The European Green Building Programme. Available from: www.eu-greenbuilding.org (accessed, March 2009). Building (2009), Cost model: Universities. Available from: www.building.co.uk, June 2009 edition (accessed March 2010). Building Research Establishment (BRE) (1996), Potential carbon emission savings from Combined Heat and Power in buildings. IP4/96, London. Building Research Establishment (BRE) (1998), Non-Domestic Building Energy Fact File, Global Atmosphere Division (GAD) of the Department of the Environment, Transport and the Regions, London. Carbon Trust, Action Energy Programme (2004), Good Practice Guide 388: Combined Heat and Power for Buildings, London. Carbon Trust (2008), Swimming pools: a deeper look at energy efficiency: In depth technology, Guide CTG009. Available from: www.carbontrust.co.uk (accessed February 2010). Chartered Institution of Building Services Engineers (CIBSE) (1999), Small scale CHP for buildings, CIBSE Application Manual: AM12, London. Chartered Institution of Building Services Engineers (CIBSE) (2004), Guide F: Energy efficiency in buildings, London. Chartered Institution of Building Services Engineers (CIBSE) (2007), Carbon saving with CHP, CPD supplement magazine, June. DECC (2010), Renewable Heat Incentive (RHI) – Consultation on the proposed RHI financial support scheme. Available from: www.decc.gov.uk (accessed March 2010). Defra (2004), Cambridge Econometrics Modelling Good Quality Combined Heat and Power Capacity to 2010: Revised Projections, A final report submitted to Department of Environment, Food and Rural Affairs (DEFRA), London. Digest of United Kingdom Energy Statistics (DUKES) (2008), Department for Business, Enterprise and Regulatory Reform (BERR), London. Dundee University Utility Supply Co (DUUSCo) (2009), University of Dundee CHP,



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available from: http://www.dundee.ac.uk/duusco/duusco~1.htm (accessed March 2010). Elsadig A K (2005), Energy Efficiency in Commercial Buildings, Master of Science dissertation, Department of Mechanical Engineering, University of Strathclyde, UK. EnerG Combined Power Ltd (2007), Case study: Hospitals. Available from: www.enerG. co.uk (accessed November 2009). EnerG Combined Power Ltd (2008), Next Generation looks to CHP for cost and carbon savings. Available from: www.enerG.co.uk (accessed, January 2010). Energy Technology Support Unit (ETSU) – Energy Efficiency Office (1983), Good Practice Guide 1: Guidance notes fro the implementation of small scale packaged CHP, Department of the Environment, London. Energy Technology Support Unit (ETSU) – Energy Efficiency Office (2001), Good Practice Guide 78: Energy use in sports and recreation buildings, Energy Consumption. Department of the Environment, London. European Parliament and the Council of the EU Union (2002), Directive 2002/91/EC, Energy Performance of Buildings. Hinnells M (2008), Combined heat and power in industry and buildings, Energy Policy Journal, 36, 4522–4526. NHS Sustainable Development Unit (2009a), NHS Carbon Reduction Strategy for England. Available from: Www.Sdu.Nhs.Uk (accessed January 2010). NHS Sustainable Development Unit (2009b), NHS England Carbon Emissions: Carbon Footprint Modelling to 2020, Available from: www.Sdu.Nhs.Uk (accessed January 2010). Pérez-Lombard L, Ortiz J, Pout C (2008), A review on buildings energy consumption information, Energy and Buildings, 40, 394–398. Scrase I (2000), White Collar CO2: Energy consumption in the service sector, The Association for the Conservation of Energy, London. Somervell D (2006), University of Edinburgh’s sustainable future: CHP key to low-carbon strategy. Available from: www.ed.ac.uk (accessed 14 July 2009). Toke D, Fragaki A (2008), Do liberalised electricity markets help or hinder CHP and district heating? The case of the UK, Energy Policy Journal, 36, 1448–1456. UK Parliament (2008), Climate Change Bill. Available from: www.parliament.uk (accessed 20 September 2009). Ward I, Ogbonna A, Altan H (2008), Sector review of UK higher education energy consumption, Energy Policy Journal, 36, 2939–2949. Zogg R, Brodrick J (2005), Using CHP systems in commercial buildings, American Society of Heating, Refrigerating and Air-Conditioning Engineers Journal, 33–34.



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16

Small and micro combined heat and power (CHP) systems for the food and beverage processing industries

P. S. V a r b a n o v and J. J. K l e m e š, University of Pannonia, Hungary

Abstract: This chapter provides an overview of CHP energy technologies for the food and beverage processing industries on the small and micro scale. The chapter starts by providing the right context in terms of key energy demand properties of food processing sites as well as with techniques of energy integration. Next it proceeds to describe the key small- and microCHP technologies, starting from the established ones and continuing further with experimental and developing technologies represented by fuel cells. The chapter concludes with a summary of the future trends and information for further reading. Key words: small- and micro-CHP systems, food and beverage processing industry, energy efficiency and minimisation.

16.1

Introduction

The world population is growing fast and this imposes a number of global challenges, mainly the simultaneous increase in the demands for food, water, and waste management. Resource demands are not only rising, but also feature strong interactions competing for energy. Food processing refers to the activities converting raw food materials to final consumable products. Foods are processed for the purpose of enhancing quality, taste, nutritional value, as well as shelf life. Processing methods include cooking, preserving, packaging, storage and distribution. One of the main features of the food industry is that, besides the target products, certain amounts of waste are released, most of them of organic composition. Therefore, the food industry has the unique property to simultaneously impose energy demands and potentially offer a number of streams from which energy can be generated. Therefore efficient supply and use of energy in the food industry, including efficient combinations of waste management and energy generation, are of paramount importance to give the food industry a competitive edge. A very important aspect of energy supply for the food industry is the need for local generation, especially for smaller-scale plants, thus avoiding potentially costly energy 395 © Woodhead Publishing Limited, 2011


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carrier transport operations, and resulting in a ‘distributed generation’ architecture. The objectives of this chapter are to first address the basic concepts and issues concerning CHP systems in the food industry, followed by a more in-depth coverage of the issues of energy supply and integration of smallerscale CHP technologies.

16.2

Food processing and energy requirements – examples for specific food and drink industries

Many food companies are significant energy users due to the need for heating and cooling of their products during manufacture and storage. The energy for heating is normally consumed as thermal energy from the combustion of fossil fuels to generate steam and hot water. Cooling and refrigeration generally consume electricity, which also powers other equipment, lighting, ventilation, etc. Within the dairy industry, the split of thermal energy consumption is typically around 80% for heating and 20% for cooling (Elkin and Stevens, 2008). There are various processes needed for food and beverage production. The following sections present a brief overview of some of them from the point of view of energy demand and supply. The food sector, including slaughterhouses, contributes to the energy consumption by industry. For example, in Flanders, the food sector consumes about 2% of the total industrial energy (Genné and Derden, 2008). In the UK the food industry uses about 126 TWh/y which is equivalent to 14% of the energy consumed by UK businesses (Elkin and Stevens, 2008; DEFRA, 2006).

16.2.1 Sugar production An extended discussion of energy and water management in the sugar industry was provided by Urbaniec and Klemeš (2008). The authors point out that in recent decades, the world output of sugar has tended to exceed the demand, causing a decrease in investments in new sugar factories. For economic and environmental reasons, however, there is a constant need for reconstruction of sugar factories – mostly to increase the production rate and reduce energy waste and emissions. In order to obtain the main product, that is, crystalline sugar with a negligible water content, water must be separated thermally with minimum energy expenditure determined by its specific heat of evaporation of 2258 kJ or 627 kWh per 1 kg water at atmospheric pressure. A factory example has been provided with processing capacity of 4800 t beet per day. The specific fuel consumption is about 3.40 kg oil equivalent (at 41 MJ/kg) per 100 kg beet, resulting in a total energy consumption of 2278 MW for the total site.



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16.2.2 Meat processing At most slaughterhouses, the largest part of electricity demand (50–65%) comes from refrigeration operations. The consumption of energy in slaughterhouses is also closely connected to the use of hot water, whose temperature is usually activity dependent. Various process steps require the availability of water at lower or elevated temperatures (4–7 °C, 40 °C, 55 °C and 90 °C) (Genné and Derden, 2008). Refrigerated areas include chills, freezers and cold stores, which entail electricity consumption even during non-production periods. The slaughtering industry can be subcategorised on the basis of the type of animals that are slaughtered: large animals (e.g., pigs, cattle, horses and sheep) and small livestock (e.g., poultry). Most slaughterhouses are smalland medium-sized enterprises (SMEs) and have a labour-intensive character. The electricity consumption varies widely and is very plant specific, e.g. 7–60 kWh/pig, 20–310 kWh/cattle, 0.4–1.2 kWh/piece of poultry. The varying use of external energy (fuel) to heat water (20–90%) and pig scalding and singeing (50–75%) are other key issues.

16.2.3 Processing of agricultural crops Small-to medium-scale plants for production of refined sunflower oil (Klemeš et al., 1998) feature two types of heating utilities, steam/dowtherm and steam/water totalling about 1 MW of use, and two cooling utilities, cooling water and ice water totalling about 0.8 MW. The same source reports similar utility demands also for sites extracting raw sunflower oil, where the added complication is the operation using a volatile and flammable extraction agent. An example from crystalline glucose production (Klemeš et al., 1998) indicates utility demands after heat integration of about 2.5–3 MW for steam and 0.7 MW for cooling water. Operating plants in this process widely use vapours bleeding from a multiple-stage evaporation system for concentrating the water–glucose solution. A further example is given by a case study of a Whisky Distillery (Kemp, 2007; CADDET, 1994). This reports a set of energy demands split among power (12 MW), heating (40–50 MW) and cooling (15–20 MW).

16.3

Heat and power integration of food total sites

Energy recovery is not only an energy supply or CHP issue, it is also important for two reasons. First, applying energy recovery improves the performance of the concerned processes, reducing the utility requirements and thus making the task of energy resource supply easier. Second, advanced CHP



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technologies for supplying utilities make extensive use of energy recovery and heat integration (Klemeš et al., 2010). As a whole, food processing is characterised by relatively low temperatures of process streams (rarely above 120–140 °C), by small numbers of hot streams (some with varying final temperatures, for example secondary condensate of multiple-stage evaporation systems), by low boiling point elevation of food solutions, by intensive deposition of scale in evaporator and recovery systems, and by seasonal performance. The application of heat integration is hindered by some specific technological and design requirements, for example direct steam heating, difficulties in cleaning heat exchanger surfaces and high utility temperatures.

16.3.1 Basic heat integration In the late 1970s the push for better industrial energy efficiency led to the development by Linnhoff et al. (1982) of the basis of pinch technology – now considered the cornerstone of heat integration. The discovery of the heat recovery pinch was a critical step in the development of heat exchanger network (HEN) synthesis. The methodology has been further developed and the most recent state-of-the-art has been presented elsewhere (Klemeš et al., 2010). The main idea behind the formulated HEN design procedure was to obtain, prior to the core design steps, guidelines and targets for HEN performance. This procedure is based on established thermodynamic theory. The hot and cold streams for the process under consideration are combined to yield a hot composite curve representing, collectively, the process heat sources (the hot streams); and a cold composite curve representing the process heat sinks (the cold streams). For a specified minimum allowed temperature difference DTmin, the two curves are combined in one plot (Fig. 16.1) providing a clear thermodynamic view of the heat recovery problem. The overlap between the two composite curves represents the heat recovery target. The overlap projection on the heat exchange axis represents the maximum amount of process heat being internally recovered. The vertical projection of the overlap indicates the temperature range where the maximum heat recovery should take place. The targets for external (utility) heating and cooling are represented by the non-overlapping segments of the cold and hot composite curves. The heat recovery targets are further supplemented by targets for heat transfer area, capital cost and total cost. As a further step, the pinch design method (Linnhoff and Hindmarsh, 1983) for synthesising HENs has been developed featuring algorithmic simplicity and efficient management of problem complexity. The method has evolved into a complete suite of tools for heat recovery and design techniques for energy efficiency, including guidelines for modifying and integrating a number of energy-intensive processes. © Woodhead Publishing Limited, 2011


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399

200

T (°C)

150

Pinch

100

50

DTMIN = 10 °C

0 QC,MIN = 328

QREC = 5912

QH,MIN = 1168

DH (kW)

16.1 Composite curves for heat recovery targeting.

16.3.2 Total site energy integration Besides the heat integration of individual processes, it is also possible to obtain heat recovery and power cogeneration targets for entire sites consisting of more than one production process. The procedure is based on thermal profiles of heat sources and heat sinks for the entire site that are called total site profiles (TSPs) (Dhole and Linnhoff, 1993; Klemeš et al., 1997). An example of TSPs together with the total site composite curves is shown in Fig. 16.2. As sugar plants are mostly not isolated, but interconnected with power plants and in many cases ethanol distilleries, as well as may provide heating for surrounding civic settlements, the total site methodology has been successfully applied. It typically considers a total site comprising sugar beet or cane delivery, storage, pre-processing and processing, packaging and serving the nearby villages or towns. An example of this setup is shown in Fig. 16.3. Additionally, locally installed boilers, consuming traditional fossil-based fuels, biomass or waste, can also help to meet the process energy requirements, when demand is high or other sources are unavailable. Heating/cooling and power not required by one unit can be fed to a local grid system, and then passed to another unit that is unable to meet its demands locally. The grid system can distribute power (electricity) as well as heating agents such as hot water or steam. In geographic locations where air conditioning is required, a cooling distribution main could also be provided.



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Small and micro combined heat and power (CHP) systems From boilers 4

250

3

200 Temperature (°C)

VHP

HP

1 2

MP

2 150 3

1

LP

100

50 –25

CW 4 –20

–15

–10

–5 0 5 Enthalpy (MW)

10

15

20

25

16.2 Total site profiles and total site composite curves.

16.4

Types of small and micro combined heat and power (chp) suitable for the food industry

Decentralised power generation combined with heat supply (CHP) is an important technology for improving energy efficiency, security of energy supply and reduction of CO2 emissions. This section provides an overview of advanced energy technologies which can contribute to the more efficient energy supply of food industries via in-house generation. Many governments encourage micro-CHP system deployment in order to enable meeting international and domestic targets on carbon emissions. Recognising the importance of the issue, the UK government has adopted a policy of incentives to support the development of the technology. As recently as February 2010 (CHPA, 2010) a feed-in tariff of 10 pence per kWh has been adopted in the United Kingdom. This scheme concerns all micro-CHP units with capacity below 2 kW, regardless of whether or not renewables are used. Micro-CHPs are already being developed for applications in SFH (small family houses) and MFH (medium family houses) and SMEs due to their technical and performance features, including high overall efficiency above 90%, low maintenance requirements as well as very low noise levels and low emissions of NOx, COx, SOx and particulates. An assessment has been done of the performance enhancement when applying micro-CHP in residential applications, which compares the new technologies with a base case employing a condensing boiler of 90% efficiency and network electricity (from the grid), which costs approximately 680 £/y (Peacock and Newborough, 2005). The study showed sizable theoretical savings in both cost



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Bio-fuels

Bio-fuels

UNIT 2

UNIT 3

GT

Fossil fuels

UNIT 4

Nuclear

16.3 Locally integrated energy sector (LIES) CHP (after Perry et al., 2008).

Fossil fuels

UNIT 1

Fossil fuels

Bio-fuels

Fossil fuels

Renewables

Electricity

UNIT 5

UNIT 6

Electricity Steam Hot water Cooling utility

402


and carbon foot print (CFP). The CO2 emissions saving was evaluated as up to 9% for Stirling engines and 16% for fuel cells (FCs), while the energy cost savings reached up to 14.6% for Stirling engines and up to 40% for operating an FC at excess electricity generation and selling it to the grid. It should be pointed out that FCs still need further development to achieve longer service availability and lower investment costs, at sufficient levels to be applied in the food industry. However, the possible savings in fuel and emissions from a separate source (Slowe, 2006) look very promising (Fig. 16.4). A market analysis and field tests in Germany and the UK (Berger et al., 2006; Forster, 2006; Carbon Trust, 2005) were evaluated focusing on energy producers and conversion techniques with a high development status. These products are either close to market introduction, undergoing EC certification or have already been matured. The following technology types are discussed in relation to possible application in the food industry: ∑ reciprocating engines ∑ microturbines (electric power below 250 kW) ∑ Stirling engines ∑ fuel cells.

16.4.1 Internal combustion – reciprocating engines Reciprocating engines are prime movers very extensively used in the food industries. These engines are suitable for smaller food processing sites Gas engine, 5 kWe

Gas engine, 1 kWe PEMFC, 1 kWe Low efficiency stirling-rankine engine, 1 kWe High efficiency Stirling engine, 1 kWe SOFC 1 kWe 0

0.2

0.4 0.6 CO2 savings (t/y)

0.8

1

16.4 Annual microCHP CO2 savings compared to grid electricity and boiler alternatives (after Slowe, 2006).



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with relatively lower power-to-heat ratios (PHR). A US market evaluation estimates the share of the food industry as almost 10% of all applications of reciprocating engines on the market for the year 2000 (Energy Solutions Center, 2004). A typical reciprocating engine (diesel, gas, multiple fuel) and a generator linked to the engine can efficiently produce electricity, over wide power ranges. Gas engines are most suitable for back-up applications. Diesel engines are recommended for continuous base load use. One of their main drawbacks is their relatively noisy operation, which for industrial applications can be compensated using proper noise insulation. The moving parts require regular maintenance, which results in certain costs – up to 0.01–0.015 (US$/y 2000) US$/kWh (Onsite Sycom Energy Corp., 2000) and CFP (Perry et al., 2008). CHP based on reciprocating engines are more applicable to stable energy demands with fewer peaks in the electricity and heat consumption profiles (Alanne and Saari, 2004). The most efficient performance can be achieved by the proper selection of the size of the internal combustion engine, the capacity of thermal and electrical storage systems and the operation scenario on the energy performance of the entire micro-CHP system (Onovwiona et al., 2007).

16.4.2 CHP using microturbines Gas turbines with electrical power generation from 25 to 250 kW, usually referred to as microturbines, can be also used for cogeneration. Such a facility generally consists of a generator, a compressor, a combustion chamber, and a turbine connected by a shaft, with a heat recovery module linked to the turbine exhaust. The high temperature of the turbine exhaust gas (450–550 °C) enables considerable heat cogeneration. Among other advantages, they feature low noise levels, small size and lower emission levels (especially NOx) compared with reciprocating engines (Soares, 2007). Gas and liquid fuels are suitable for microturbines. However, microturbines have low electrical efficiency, especially on part load, while capital and maintenance costs are rather high. Therefore CHPs with microturbines are most applicable for high steam production, with fixed output volume and similar applications.

16.4.3 External combustion – Stirling engines The Stirling engine is a reciprocating engine with its cylinder closed and combustion taking place outside the cylinder. Stirling engines are characterised by rather low emissions (especially NOx) and lower noise levels. External combustion also requires less maintenance which favourably influences the carbon footprint of the technology. The Stirling engine is usually quiet because the combustion is not explosive and it can use almost any combustible fuel



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and any source of heat, including biomass. This type of CHP has rather low electrical efficiency, about 25–30% when natural gas is used as a fuel. When solid fuels (e.g., biomass) are used, the efficiency can even be as low as 15%, making them suitable for serving energy demands with low power-to-heat ratios. Their low efficiency supports their use as back-up power supplies rather than for continuous use (Peacock and Newborough, 2005).

16.4.4 Fuel cells (FC) A FC produces electricity electrochemically, by combining fuel and atmospheric oxygen. Lower-temperature FCs need pure hydrogen (e.g., proton exchange membrane fuel cell (PEMFC), phosphoric acid fuel cell (PAFC) while higher temperature fuel cells (solid oxide fuel cells (SOFC) and molten-carbonate fuel cells (MCFC)) can also process gases containing carbon monoxide. Hydrogen can be obtained from various fuels by means of a reforming process. The electrical efficiency of these systems can be as high as 45–55% (Alanne and Saari, 2004; Varbanov et al., 2006). If pure hydrogen is used, the only direct emission is water. If reforming is used, CO2 and a minimal amount of oxides of sulphur and nitrogen are formed, depending on the fuel. Other benefits are noiselessness, reliability, modularity, and rapid adaptability to load changes. Modularity brings substantial scalability and may substantially reduce the economy of scale effect (Yamamoto, 2000; Varbanov and Klemeš, 2008).

16.5

Established combined heat and power (chp) technologies for the food industry

This section discusses specific established CHP technologies already having application in the food industry or having the potential to be applied.

16.5.1 Rankine cycle technologies Siddhartha Bhatt and Rajkumar (2001) and several other authors presented combined heat and power studies relating to cane sugar factories. Part of the fuel energy supplied to the boiler is transferred to steam turbines through high-pressure steam that in turn powers the turbine and generator. This separation of the combustion from the working fluid enables steam turbines to operate with a variety of fuels including natural gas, solid waste, coal, wood, wood waste and agricultural byproducts. The capacity of commercially available steam turbines typically ranges from 50 kW to over 250 MW. The lower end of this range is suitable for smaller-scale CHP. Although steam turbines are competitively priced compared to other prime movers, the costs of a complete boiler/steam turbine CHP



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system are relatively high on a per kW basis. This is because steam turbines are typically sized with low power-to-heat ratios, and have high capital costs associated with the fuel and steam handling systems and the custom built nature of most installations.

16.5.2 Gas turbine-based CHP Gas turbines (GT) for industrial use are generally available in a wide interval of capacities ranging from 500 kW to 250 MW and can operate on a variety of fuels such as natural gas, synthesis gas, landfill gas and fuel oils (US EPA, 2010). In recent years US and European companies have started also offering micro gas turbines (see Section 16.4.2). These include Turbec SpA (TURBEC, 2010), as well as Capstone Turbine Corporation (CAPSTONE, 2010) and Calnetix Power Solutions (CALNETIX, 2010) in the United States. Most gas turbines typically operate on gaseous fuel with liquid fuel as a backup. Gas turbines can be used in a variety of configurations including simple cycle generating only power, CHP – where its exhaust heat is used for generating process steam or direct process heating, and combined cycle operation in which the GT exhaust is used to power steam turbines for generating additional power. The steam cycle placed below the gas turbine in the combined cycle arrangement is often referred to as the ‘bottoming cycle’, while the GT is the ‘topping cycle’. Another variation is to extract process steam at intermediate levels from the combined cycle arrangement. The capabilities of this technology are very broad and flexible, allowing serving food processing sites from different sectors and of different scales. Most GT exhausts allow generating high pressure (HP) steam at 40 bar and higher. By allowing the bottoming Rankine cycle to extract steam at intermediate pressures and to eventually employ condensing steam turbines, a very wide range of demands with different power-to-heat ratios can be served. Much of the gas turbine-based CHP capacity currently existing in the United States and the European Union consists of large combined-cycle CHP systems that maximise power production for sale to the grid. Simple-cycle CHP applications are common in smaller installations, typically less than 40 MW. The suitability of employing GT-based CHP at food processing sites depends on the demand parameters and the nature of the raw materials used. For instance, for cane-based sugar plants one of the primary objectives is to maximise the utilisation of the bagasse. In such case the preferred method in Brazil is by simple Rankine cycle-based CHP. However, it is possible to utilise the bagasse in a GT-based system, first deriving synthesis gas via gasification. While examples of established use of bagasse gasification in sugar industries are difficult to find, theoretical works and small-scale experiments are already under development (Pellegrini and de Oliveira Jr, 2007; Rodrigues et al., 2003).



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16.5.3 Reciprocating engines Reciprocating engines, discussed previously, are also used for energy applications in the food industry. An EU-FP6 project report (POLYSMART, 2009) describes the use of a diesel engine in a trigeneration application, using the lower-temperature recovered heat in an absorption chiller and the higher-grade heat is used for generating process steam. Spark ignition (SI) engines use spark plugs with a high-intensity spark of timed duration to ignite a compressed fuel–air mixture within the cylinder. They are available in sizes up to 5 MW, running mostly on natural gas, but propane, gasoline and landfill gas can also be used. Diesel engines (compression ignition, or CI engines), are very efficient power generation options. They operate on diesel fuel, heavy oil, or recently biodiesel has become an option. Dual fuel engines, using predominantly natural gas with a small amount of diesel pilot fuel, are also installed. Higher-speed diesel engines (1200 rpm) are available in capacities up to 4 MW, while lower-speed diesel engines (60–275 rpm) can be larger – up to 65 MW. Reciprocating engines start quickly, follow load well, have good part-load efficiencies and are generally highly reliable. The overall energy generation availability can be enhanced by deploying multiple reciprocating engines. Reciprocating engines are well suited for applications that require hot water or low-pressure steam.

16.6

High-efficiency technologies in theoretical and demonstration stages

As discussed in Section 16.2, certain food industry sectors, e.g. meat processing, have energy demands with high PHR. In order to use the fuels efficiently, there are two principal ways of satisfying the demands of such sites: to use CHP technologies with high overall efficiency but lower PHR, utilising somehow the extra heat generated, or to employ technologies with high PHR and high electrical efficiency. This section addresses situations in the food industry where higher electrical efficiencies are required for processes. Fuel cell (FC) systems are one of the most promising emerging technologies for power generation, which have the potential to replace conventional methods by offering higher energy conversion efficiencies and significantly lower greenhouse gas emissions (Varbanov and Friedler, 2008). They have not yet been widely commercialised due to high capital costs and the need to improve their reliability and lifespan. The achievable electrical efficiency for FCs ranges from 40% up to 60% and above. There are several classes of FCs with small variations for each type. The most researched types include proton-exchange FC (PEFC), phosphoric acid FC (PAFC), molten-carbonate FC (MCFC), and solid-oxide FC (SOFC).



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There are many factors influencing the FC efficiency, of which the operating temperature is the most important. Based on an analysis by Yamamoto (2000), it can be seen that the correlation between the efficiency and the operating temperature is very pronounced, differing by more than 20% between the PEFC and SOFC (Fig. 16.5). Another important feature is that the exhausts of hotter FCs are available at temperatures above 500 °C, making them suitable for integration with bottoming cycles and cogeneration. Higher temperatures favour higher potential for further power generation or cogeneration from the FC exhausts. Any drop in the temperature drastically decreases this potential. The principle and main parameters of a MCFC are discussed next as an example FC technology.

16.6.1 Molten-carbonate fuel cells (MCFC) The MCFC is one of the fuel cell types operating at high temperatures (550– 700 °C). It is considered suitable mainly for stationary power generation. In an MCFC, natural gas or a gaseous low molecular weight hydrocarbon-containing fuel is fed to the anode. To the cathode, a mixture of oxygen (from the air) and carbon dioxide (from the anode) is introduced. This is a continuous process. The electrolyte is a mixture of molten alkali metal carbonates, usually a binary mixture of potassium and lithium, or lithium and sodium carbonates. The molten carbonates are kept in a ceramic matrix of LiAlO2 (Larminie and Dicks, 2000). At operating temperatures of 550–700 °C, the carbonates are highly conductive to carbonate ions (CO32–) providing ionic conduction. The moving ions inside the electrolyte, along with the electrons in the outer circuit, complete the electric circuit for power production. The high operating temperature of the MCFC gives an opportunity for greater fuel flexibility, use of less expensive electro-catalysts and high overall system operating efficiencies. 60

hMax (%)

50 40 30 20 10 0

80 °C (PEFC)

200 °C (PAFC)

700 °C (MCFC)

1000 °C (SOFC)

16.5 Variation of FC efficiency with operating temperature (after Yamamoto, 2000).



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The basic configuration of a MCFC system consists of a fuel cell stack, an internal reforming chamber, a catalytic combustor and inlet/outlet pipes for the various process streams. The process flow diagram of the system is shown in Fig. 16.6, Natural gas and water from the supply system enter the fuel cell reformer where they get reformed internally (indirect reforming) by the heat content of the exothermic fuel cell reaction. The endothermic reforming reaction taking place in the fuel reformer produces carbon monoxide (CO) and hydrogen (H2). The anode exhaust is sent to a catalytic combustor where the unused fuel is burned in the presence of air taken from the ambient for going through the cathode. The amount of air provided must be more than the stoichiometric air requirement for the fuel combustion. The flue gases are then introduced in the cathode after cooling them to a suitable temperature. Otherwise, at high temperatures, electrolyte evaporation and material corrosion would occur. Carbon dioxide, oxygen and electrons, returning from the external electric circuit, react together in the cathode to produce carbonate ions (CO32–). These migrate from the cathode to the anode via the electrolyte matrix, where they react with the hydrogen from the anode stream to produce water, carbon dioxide and electrons. The electrons pass from the fuel electrode (anode) to the oxidant electrode (cathode) via the electric circuit, external to the electrolyte matrix. The reactions occurring at the anode and the cathode oxidise the hydrogen and reduce CO2 to carbonate ions. In addition, a water gas shift reaction also occurs at the anode resulting in additional production of hydrogen. An example MCFC of the described type has been analysed (Varbanov et al., 2006), generating 2.32 MW of electricity. It needed 0.1 kg/s of

408 °C Reformer

Methane

551 °C

25 °C 25 °C

Water

650 °C Anode Air 25 °C

Catalytic combustor 873 °C

630 °C

Electrolyte matrix

670 °C Cathode exhaust 1

Cathode



16.6 Simple MCFC process flow diagram (after Varbanov et al., 2006).



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methane, equivalent to 5.002 MW energy input, resulting in 46.38% electrical efficiency.

16.6.2 Fuel cell combined cycles (FCCC) using MCFC and solid oxide fuel cells (SOFC) MCFCs feature an important thermodynamic limitation. Operation at temperatures higher than 700 °C leads to falling gains in the fuel cell performance. This happens because of increased electrolyte loss from evaporation and corrosion of materials at high temperatures. Similarly, SOFCs also have certain limitations on their operating temperature and efficiency, mainly in terms of suitable materials and their durability. Therefore, any further increases in fuel utilisation efficiency should be sought in a different direction. One especially interesting option is to consider the formation of a fuel cell combined cycle (FCCC) for power generation, which can be eventually employed for stand-alone power generation, as well as for cogeneration. The main reason for considering this option is the significant amounts of high-grade waste heat released by MCFC and SOFC systems. The literature sources on combining fuel cells with gas and steam turbines clearly illustrate the potential to achieve high power and cogeneration efficiencies as well as economic viability (Massardo and Bosio, 2002; Karvountzi et al., 2004; Kurz, 2005; Varbanov et al., 2006). The potential to use the high-temperature exhaust for process heat cogeneration from SOFC or MCFC can be evaluated in two steps following the hierarchy common for process design: 1. Appropriate heat integration within the FC. This would maximise its fuel efficiency without altering the design and give an estimate of the further heat flows available for steam generation. 2. Steam generation and utilisation in a steam network for process heating or more power generation. Analysing the MCFC system shown in Fig. 16.6 reveals significant potential for cogeneration. Using pinch analysis (Linnhoff et al., 1982; Klemeš et al., 2010), it is shown that the MCFC heating and cooling demands define a threshold problem with net utility demands only for cooling (Fig. 16.7). A similar and more thorough analysis of a SOFC (Varbanov and Klemeš, 2008) has also been performed. The SOFC flowsheet is shown in Fig. 16.8. The pinch analysis of the SOFC system produced the composite curves shown in Fig. 16.9. A more complete analysis of the heat-integrated SOFC, combined with generation of hot water or steam, showed remarkable CHP efficiency of over 70% (Fig. 16.10). This value could be eventually increased further if



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Small and micro combined heat and power (CHP) systems 1027

No heating required

827 DT = 50 °C = DTmin

T (°C)

627

Hot composite curve

427

227

27

Cold composite curve

0

1000

2000

DH (kW)

3000

Qcooling = 1718.09 kW

16.7 Composite curves for the MCFC from Fig. 16.4 (DTmin = 50 °C).

3055.0 kW Power

1664.6 kW

Air 25.0 °C 2.28 kg/s

AP

700.0 °C

0.12 kg/s CH4 25 °C

SOFC

Heat loss 1639.6 kW 985.0 °C 2.77 kg/s

Reformate 900.0 °C

Fuel heat 6001.7 kW

Afterburner 850.0 °C 0.49 kg/s Reformer FP 100.0 °C 1000.4 kW 1227.9 kW reaction 403.4 kW heating

Water/steam P = 1 atm

173.6 kW Loss 2677.0 kW Cooling

932.2 °C

V EC 3119.1 kW

303.6 kW

130.0 °C

0.36 kg/s 25 °C

SG

Cogenerated heat (water or steam) – varied in the analysis Water (demineralised) Key: AP: Air preheat SG: Steam generation

FP: Fuel preheat EC: Exhaust cooling

Exhaust

V: Vaporiser (water)

16.8 SOFC flowsheet (after Varbanov and Klemeš, 2008).



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1000

T (°C)

800 600 400 Hot CC

200

Cold CC 0 0

2000

Q (kW)

4000

6000

16.9 Composite curves for the SOFC integration (after Varbanov and Klemeš, 2008).

Efficiency (%)

70

CHP efficiency hot water

65 60

SOFC 51% stand-alone efficiency

Power generation CHP

55 50 0

5

10 Steam pressure (bar)

15

20

16.10 Overall efficiencies of the combined SOFC and steam system arrangement (after Varbanov and Klemeš, 2008).

the SOFC design is optimised and the high temperature exhausts could be cooled to lower temperatures than 130 °C.

16.7

Integration of renewables and waste with food industry energy demands

The comparatively low temperatures make food processing very attractive for utilising various renewables, including ground heat via heat pumps as well as solar thermal energy. There are a number of waste and renewable energy sources which are available to provide local heating and cooling, and in doing so can reduce the costs and the greenhouse gas emissions of industrial sites. The focus of this section is on those sources suitable for application to the food industry. The technologies and sources considered include heat pumps, biomass and solar energy.



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16.7.1 Heat pumps Heat pumps are used to upgrade low temperature heat from sources such as ambient air, exhaust air, ground soil, ground rock, groundwater and surface water, to higher temperature heat outputs which can be used for space or process heating. In the food and beverages industry heat pumps are widely used for cooling and refrigeration, mainly utilising their heat sink side. The two principal technologies used in heat pumps are compression and absorption (Laue, 2006). A compression heat pump consists of an evaporator, compressor, condenser and an expansion valve. They are driven mainly by electricity, but can also be powered by direct drive prime movers – gas or diesel engines, gas or steam turbines. Each heat pump is characterised by its coefficient of performance (COP), which depends on the input temperature of the heat source, and the output temperature required. Under the most usual conditions the COP varies between 4 and 5 for temperature lift about 20–30 °C, but may slip below 4 for higher temperature lift values. In the food and drink industry, besides for refrigeration as mentioned, heat pumps can also be applied for process heating. An ideal match would be between a low-temperature heat source or cooling demand below the pinch and a moderate-temperature heating demand above the pinch. However, low-grade geothermal energy can also be used.

16.7.2 Biomass Biomass is another renewable energy source that can provide heat and can reduce the production of greenhouse gases. In many cases it can be readily stored and used when needed. In other cases biomass is a side product or waste from the main production processes, e.g. bagasse and molasses in sugar processing. Depending on the form in which biomass is available, different methods can be applied for utilising it. First, and by far the most common, is direct firing of biomass when it is available in a sufficiently dry condition. However, if higher moisture and/or potentially dangerous components are present, it may be preferable to apply anaerobic digestion of the biomass material, obtaining biogas, which can be further utilised in gas-fired boilers, gas turbine variants (including microturbines) as well as in fuel cells. The biomass renewable energy source can also be used in gasification processes for the production of heat and power. A gasification system thermally converts biomass to synthesis gas, which can then be used to produce fuels, products, power and hydrogen (US DOE, 2008). Currently most large-scale gasification systems research is pursued, but smaller modular gasification systems are also planned. These systems would operate in the range of 5 kW to 5 MW (CIWM, 2008), and would provide heat and power from localised



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sources of biomass. The gasification product, composed primarily of carbon monoxide and hydrogen, is cleaned and then used in gas turbines or internal combustion engines. In addition to the power produced, waste heat can be directed to district heating based systems.

16.7.3 Using solar energy Solar energy is another renewable source that can be used for both heating and cooling. Solar heating is a mature technology that has proven to be reliable and cost-competitive since solar water heaters were introduced over 30 years ago. Although these systems have been centred mainly on producing heat and power for individual or large residential/commercial buildings, there has also been widespread interest in using concentrated solar heat systems for industrial applications (Rantil, 2006). In active solar heating systems, water, or another heat transfer fluid, is circulated through a duct and heated by transfer from direct solar radiation on the collector panel. Various designs of collectors are utilised in order to concentrate the solar radiation on the fluid duct and to maximise solar gains. The amount of heat energy captured per square metre of collector surface area varies with design and location but typically can range from 300 to 800 kWh/(m2y). Some designs use a heat transfer fluid that, when warmed, flows to a storage tank or a heat pump where the heat is further upgraded and used by consumers. An interesting study illustrating the integration of solar captured heat is presented by Atkins et al. (2010). The described example presents a New Zealand dairy milk powder plant located in the central North Island. The case study has been conducted to explore the possible retrofit with the integration of an industrial solar thermal system to the milk powder plant. A 1000 m2 evacuated tube solar collector field is assumed. Evacuated tubes have been considered the most appropriate collector design in this case to fit the required temperature levels and flow rates. However, the overall findings can be generalised to other collector types as well. The plant operates from the beginning of August through to the end of April, when there is a three month shut down due to low milk production in the winter months. This period of no production also coincides with the lowest ambient temperatures and solar radiation levels. The plant data have been analysed using pinch analysis using minimum temperature difference DTmin = 5 °C. The hot and cold utility targets obtained are 1674 and 2927 kW, respectively, with the pinch located at 45 °C for the hot streams and 40 °C for the cold streams. They consider several options for placing the captured solar heat, where the main challenges are how to ensure appropriate placement of the solar heat utility above the pinch and at the same time to maximise the solar collector efficiency. The most beneficial



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scenarios found were: (i) solar heat integration at constant capture flow and varying temperature resulting in reduction of the hot utility by 14% and of the cold utility by 4%; and (ii) solar integration alone – above the pinch at constant capture flow resulting in 7% hot utility reduction.

16.8 Potential applications There is an enormous potential to apply small-scale CHP in the food industry. In this section two case studies are presented. First, an application of a high-temperature fuel cell to powering a Japanese brewery is presented to outline the practical potential of this new technology. Second, a novel idea for integrating smaller-scale industrial plants and other energy consumers/ providers is covered to underscore the importance of taking advantage of local context and potential energy partnerships for successfully implementing distributed generation.

16.8.1 MCFC applied to a Japanese brewery A Brewery in Japan owned by Kirin Beer operates a 250 kWe molten carbonate fuel cell developed by US-based FuelCell Energy together with Marubeni Corporation in Tokyo. It is reported as the world’s first fuel cell to run on digester gas from a waste treatment plant (Kirin Brewery, 2003). The MCFC has been supplying roughly 4% of the electric power and about 1% of the steam for the brewery Toride Plant in Tochigi Prefecture since early April 2003. Marubeni has been responsible for the entire package of investment and for installation, maintenance and operational management of the fuel cell, with the support of the New Energy & Industrial Technology Development Organization (NEDO). The fuel used consists of digester gas (mainly methane) generated by anaerobic treatment at the brewery’s waste treatment plant. All the power generated by the fuel cell and the steam generated from waste heat recovery is supplied for process heating to the brewing plant. Using the fuel cell in cogeneration mode gives a dramatic improvement in overall efficiency to 72% or better (i.e. power generating efficiency of >47% and waste heat recovery efficiency of over 25%).

16.8.2 Locally integrated energy sectors Total site targeting has provided a method for analysing the heat sources and sinks from more than one process, as discussed in Section 16.3.2 (Klemeš et al., 1997). This methodology can be adopted for the analysis of heating and cooling requirements in an enlarged geographical area, which is referred to as a locally integrated energy sector (LIES) (Perry et al., 2008). The LIES



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concept can be very useful for application to the food industry, especially taking into account the relatively smaller scale of many food production plants in Europe. The following example illustrates the concept. Consider two small-scale industrial processing plants, coupled with a hospital complex and a group of residential dwellings and office complexes. The process streams of the industrial processes are shown in Tables 16.1 and 16.2. The grand composite curves, built for DTmin = 20 °C from the data for plants A and B, are shown in Figs 16.11 and 16.12. Table 16.1 Process plant A stream data Stream

Name

Tsupply (°C)

Ttarget (°C)

DH (MW)

CP (kW/°C)

1 2 3 4 5

A2 A1 A5 A6 A7

170 150 25 70 30

80 55 100 100 65

5.000 6.477 1.500 0.750 5.250

55.5556 68.1818 20.0000 35.0000 150.0000

Hot Hot Cold Cold Cold

Table 16.2 Process plant B stream data Stream

Name

Tsupply (°C)

Ttarget (°C)

DH (MW)

CP (kW/°C)

1 2 3 4 5 6

B1 B2 B3 B4 B5 B6

200 20 100 150 60 75

80 100 120 40 110 150

10.000 4.000 10.000 8.000 1.000 7.000

83.3333 50.0000 500.0000 72.7273 20.0000 93.3333

Hot Cold Cold Hot Cold Cold

165 145 125 T (°C)

105 85 65 45 25

0

1

2

3 4 5 Enthalpy (MW)

6

7

8

16.11 Process grand composite curve–process plant A (DTmin = 20 °C).



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Small and micro combined heat and power (CHP) systems 225 205 185

T (°C)

165 145 125 105 85 65 45 25

0

1

2

3

4 5 6 Enthalpy (MW)

7

8

9

10

16.12 Process grand composite curve–process plant B (DTmin = 20 °C). Table 16.3 Process Stream data of hospital complex (Plant C) Stream

Name

Tsupply (°C)

Ttarget (°C)

DH (kW) CP (kW/°C)

1 2 3 4 5 6 7 8 9 10 11

Soapy water Condensed steam Laundry sanitary water Laundry Boiler feed water Sanitary water Sterilisation Swimming pool water Cooking Heating Bedpan washers

85 80 25 55 33 25 30 25 30 18 21

40 40 55 85 60 60 121 28 100 25 121

23.85 96.4 17.7 77.4 7.2 77 12.74 151.68 59.5 100.8 5

Hot Hot Cold Cold Cold Cold Cold Cold Cold Cold Cold

0.53 2.41 0.59 2.58 0.24 2.2 0.14 50.56 0.85 14.4 0.05

Plant A has no net heating requirements, indicated by the lack of abovethe-pinch area, but has a large net cooling requirement below the pinch – excess heat that has to be removed. Consequently there is approximately 4 MW of heat which is available at temperatures of around 120 °C. This heat is available at a temperature sufficient for the production of steam. Plant B requires an external heating source above the pinch, again at a temperature of around 120 °C, and also has a small amount of excess heat which has to be removed by cooling below the pinch. This excess heat, of approximately 1.5 MW, could be used to produce hot water at temperatures of around 70 °C – sufficient to use in the residential and office areas of the LIES, provided the transportation distances are not too long. The LIES under consideration also includes a hospital complex – Plant C (Herrera et al., 2003). The process stream data for this unit is shown in Table 16.3 and the process grand composite curve with a DTmin = 20 °C, derived



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from this original data, is shown in Fig. 16.13. In this particular unit, there is a heat sink of around 400 kW above the pinch which requires supply of external heating. The final unit in the energy sector is composed of a group of residential dwellings and office complexes (Plant D). The heating requirements in this mixed unit are aggregated hot water requirements and space heating. The process stream data are given in Table 16.4 and the process grand composite curve, again at DTmin = 20 °C, in Fig. 16.14. The total site profiles diagram of the LIES is given in Fig. 16.15. The heat sources and heat sinks of the involved processes have been combined to produce the overall total site sink profile and total site source profile. Without integration, the LIES would need to dispose of 6.2 MW of heat, and 17.5 MW of heat would have to be supplied from external heating sources (e.g. fossil fuels). A possible scenario (Scenario 1) for integration in the LIES is shown in Fig. 16.16. In this scenario, a hot water main at a temperature of 60 °C to 40 °C is provided for extracting heat from the total site source profile and supplying heat to the total site sink profile. The amount of generated heat for the hot water supply is 5.5 MW, and the amount of heat that has to be supplied by the hot water is also 5.5 MW. The remaining heat required by the LIES is 12.0 MW, giving a heat reduction of 5.5 MW due to heat 145 125

T (°C)

105 85 65 45 25

0

0.05

0.10

0.15 0.20 0.25 Enthalpy (MW)

0.30

0.35

0.40

16.13 Process grand composite curve of hospital complex (Plant C, DTmin = 20 °C). Table 16.4 Process Stream data of residential and office complex (Plant D) Stream

Name

Tsupply (°C) Ttarget (°C) DH (MW)

CP (kW/°C)

1 Hot 2 Hot

District heating Hot water

15 15

133.333 76.9232

60 80

6.000 5.000



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85 75 T (°C)

65 55 45 35 25 0

2

4

6 Enthalpy (MW)

8

10

12

16.14 Grand composite curve of residential and office complex (Plant D, DTmin = 20 °C). 160 140

Sinks

Sources

T (°C)

120 100 80 60 40 20 10

5

0

5 10 Enthalpy (MW)

15

20

16.15 Site profiles for the LIES.

integration in the LIES. The external heat required could be provided by a boiler using a carbon neutral fuel such as biomass or waste combustion unit. In this particular case the heat for the hot water system is supplied by the small-scale food processing plants, and the recipients of the heat are the hospital and residential and office complexes. If this heat (the 5.5 MW) was no longer available, then it would need to be supplied from another source. A second scenario, Scenario 2, is shown in Fig. 16.17. In this case a steam main at 125 °C has been added to the system. The heat source from the LIES has now been split between steam (3.1 MW) and hot water (2.4 MW). On the sink side, 8.4 MW of steam is supplied to the hospital and residential and office complexes, and 5.5 MW of hot water. The amount of heat to be supplied by the boiler or waste combustion system remains at 12.0



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200 180 160

Sources

140 T (°C)

120 100 80

Sinks

60 40 20 0 10

5

0

5 10 Enthalpy (MW)

15

20

16.16 Scenario 1 – Total site profiles. 200 180

Sources

160

T (°C)

140 120 100 80 Sinks

60 40 20 0 10

5

0

5 10 Enthalpy (MW)

15

20

16.17 Scenario 2 – Total site profiles.

MW. Economics is a significant factor in the final design potential. Installing both a hot water main and a steam main over the geographical area of the LIES may be an economical option. This needs to be further evaluated in relation to changing energy/capital cost ratios. The recent developments in coping with fluctuating sources (typical for most renewables) and demands have been presented by Varbanov and Klemeš (2010).

16.9

Future trends

A number of possible future configurations for smaller-scale CHP technologies and their users are possible and have good probability for development in the



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future. Here several possible future directions of development are outlined from the viewpoint of their potential for improving the security of energy supply as well as the overall performance of the industrial processes and the local energy sectors.

16.9.1 Technology development trends Regarding technology development, the current state of the art for microCHP is the Stirling engine, which is very useful and provides security and availability due to its maturity. However, due to its lower power-to-heat ratio (about 0.5) it is not very suitable for industrial applications, which necessitates further developments and a paradigm shift. Particularly fuel cell technology should be more aggressively pursued. It may have significant positive implications on the CHP market as long as sufficient durability, availability and maintainability of the fuel cells can be ensured. Switching to different technologies will also lead to a different power-to-heat ratio, which is quite high (about 1 to 2 for fuel cells). An overview has been presented by Kuhn et al. (2008).

16.9.2 Strategic issues Recently, attention has shifted towards security of supply (van Soest et al., 2006). It has become clear that having energy resources brings influence, and many countries are not hesitating to use that influence when they have it. The energy exporting countries on the one hand realise that because of the ever growing energy demand world-wide, the energy markets are sellers markets these days. They are in a position to sell to the highest bidder and to those users who are willing to accept long-term contracts. The energy importing countries realise that energy is key for economic development, and that short-term scarcities may hamper economic growth for longer periods. Decentralisation This is becoming more and more popular as an idea, especially with the development of new energy conversion technologies making available high efficiency at lower and lower costs. An example of such a technology with a great potential is fuel cells. The generation of the heat and power at the premises of the consumer or close nearby has two fundamental advantages: minimisation of energy transportation losses and minimisation of infrastructure failures or disturbances.



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The further integration of renewables and maximum waste utilisation This is another matter of strategic importance. It is closely related to the issues of energy security, environmental protection and sustainable development. In particular, maximising waste utilisation according to an appropriately formulated waste management hierarchy has the potential to provide a win-win development by simultaneously reducing waste disposal and the consumption of external energy resources. A good example of waste utilisation has been provided in Section 16.8.1. Locally integrated energy sectors The locally integrated energy sectors discussed in this chapter provide another opportunity – to extend process energy efficiency, waste management and renewables integration to the scope of local communities and towns, thus enabling more efficient utilisation of company resources and symbiosis with other companies and residential areas.

16.10 Sources of further information and advice The material provided in this chapter highlights the major CHP technologies with an emphasis on smaller-scale ones. However, it is by no means exhaustive. Therefore, this section supplies additional references to provide guidelines for more detailed and comprehensive studies.

16.10.1 Institutional resources A large number of institutional resources are available over the world. The ones found most useful by the authors are listed next. The US EPA has compiled a ‘Catalogue of CHP Technologies’ available over the Internet (US EPA, 2010). It contains a number of sections starting with an introductory overview of CHP technologies and accompanied with more detailed analyses of each technology in terms of main characteristics and the potential for their application, also including various CHP efficiency definitions used in industry, research and various standards and regulations. Another useful US information resource is the ‘California Distributed Energy Resources Guide’ (CDERG, 2010). This is a public benefit website providing information regarding technologies for distributed energy generation, to which the small- and micro-CHP technologies inherently belong. The website contains various sections – e.g. ones dedicated to background and overview, equipment analysis (including prominent suppliers), information on ongoing research, an extensive library of real-life case studies, costing, policy incentives, market analysis, and others.



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From the European resources, the Irish Combined Heat and Power Association has compiled a set of resources on CHP technologies including overviews and examples of installed running plants (ICHPA, 2010). The UK Carbon Trust (Carbon Trust, 2010a) also offers an extensive website dedicated to CHP technologies with a special section on micro-CHP (Carbon Trust, 2010b). The section offers an extensive report and guide in PDF format for companies and organisations on the issues of understanding and choosing the right combination of micro-CHP technologies. The guide puts a special emphasis on CO2 emissions minimisation. The Carbon Trust website does require free-of-charge user registration before allowing downloads.

16.10.2 Books An interesting textbook on microturbines is provided by Soares (2007). It describes the various microturbine types, their applications, and their requirements for installation, maintenance and repair. It also discusses the combination of microturbines with fuel cells for forming combined cycles as well as other integration options. Knowles et al. (2004) present another useful resource. The book provides an in-context overview of small-scale energy technologies in terms of renewable energy utilisation, technology options such as wind turbines, hydro, microCHP (Stirling engines, microturbines, fuel cells and their hybrids), biomass gasification, and electricity distribution issues. Pehnt et al. (2005) describe CHP and micro cogeneration from a different perspective, emphasising societal and social issues, emissions reduction, economic viability and market analysis.

16.10.3 Journals There are a variety of peer-reviewed journals available. Those regularly publishing on CHP and micro-CHP issues include: ∑

Applied Thermal Engineering <www.elsevier.com/wps/find/journaldescription.cws_home/630/ description#description> ∑ Energy – the International Journal <www.elsevier.com/wps/find/journaldescription.cws_home/483/ description#description> ∑ Chemical Engineering Transactions <www.aidic.it/CET> ∑ Renewable and Sustainable Energy Reviews <www.elsevier.com/wps/find/journaldescription.cws_home/600126/ description#description> ∑ Clean Technologies and Environmental Policy <www.springer.com/environment/sustainable+development/ journal/10098> © Woodhead Publishing Limited, 2011


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∑

Journal of Cleaner Production <www.elsevier.com/wps/find/journaldescription.cws_home/30440/ description#description> ∑ Journal of Clean Technologies and Environmental Policy <www.springer.com/environment/sustainable+development/ journal/10098> ∑ Resources, Conservation and Recycling <www.elsevier.com/wps/find/journaldescription.cws_home/503358/ description#description>

16.10.4 Conferences There are also a number of conference options to choose from that cover CHP in the food industry and also smaller-scale cogeneration. However, these issues are not always completely coherently covered by a specific conference. A small selection of high-profile conferences is provided next. The Total Food series of biennial, international conferences was initiated in 2004 by the Royal Society of Chemistry Food Group and the Institute of Food Research, Norwich. The aim of Total Food is to debate global research and development relevant to exploiting the whole food crop rather than the limited proportion that is consumed at present. The conference considers the topics of energy supply and efficiency in food processing. The series of conferences Process Integration, Modelling and Optimisation for Energy Saving and Pollution Reduction (PRES), organised annually since 1999, <www.conferencepres.com>, provides a forum for exchanging information and views on energy technologies and emissions minimisation from a wide spectrum of industries, including increasing participation of food processing engineers and researchers. The other prominent forums include: ∑ European Symposium on Computer Aided Process Engineering (ESCAPE), organised annually since 1992, <www.cape-wp.eu> ∑ AIChE International Congress on Sustainability Science and Engineering (ICOSSE) organised since 2009, <www.aiche.org/IFS/Conferences/index. aspx> ∑ Dubrovnik Conference on Sustainable Development of Energy, Water and Environment Systems (SDEWES), organised biennially since 2002, <www.sdewes.fsb.hr>

16.11 References Alanne, K., Saari, A., 2004. Sustainable small-scale CHP technologies for buildings: the basis for multi-perspective decision-making. Renewable and Sustainable Energy Reviews, 8(5), 401–431.



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17

Biomass-based small and micro combined heat and power (CHP) systems: application and status in the United Kingdom

A. V. B r i d g w a t e r, A. A l c a l a and M. E. G y f t o p o u l o u, Aston University, UK

Abstract: This chapter discusses the current state of biomass-based combined heat and power (CHP) production in the UK. It presents an overview of the UK’s energy policy and targets which are relevant to the deployment of biomass-based CHP and summarises the current state for renewable, biomass and CHP. A number of small-scale biomass-based CHP projects are described while providing some indicative capital costs for combustion, pyrolysis and gasification technologies. For comparison purposes, it presents an overview of the respective situation in Europe and particularly in Sweden, Finland and Denmark. There is also a brief comment about novel CHP technologies in Austria. Finally it draws some conclusions on the potential of small-scale biomass CHP in the UK. Key words: biomass, small-scale combined heat and power (CHP), renewable energy, bioenergy.

17.1

UK energy policy and targets

In February 2003 the Government published the Energy White Paper (1) setting a target of 20% of electricity produced from renewables by 2020, and biomass is categorised in Government energy policy as part of renewables. Onshore and offshore wind and biomass could be the largest contributors to the renewables generation mix in 2020. The Government accepted the recommendation of the Royal Commission on Environmental Pollution to reduce carbon emissions by 60% by 2050 and stated their commitment to a target of 10 GWe of ‘good quality’ combined heat and power (CHP) capacity being installed by 2010. CHP is defined as simultaneous generation of usable heat and power in a single process, with the advantage of offering much higher overall energy efficiency (up to 85%) compared to electricity production only (rarely exceeds 35%). CHP that is certified as ‘good quality’ is exempt from the Climate Change Levy imposed on electricity and gas sales for non-residential energy users. Biomass is defined as ‘the biodegradable fraction of products, waste and 427 © Woodhead Publishing Limited, 2011


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residues from agriculture (including vegetal and animal substances), forestry and related industries, as well as the biodegradable fraction of industrial and municipal waste’ (2).The Biomass Task Force Report by Sir Ben Gill published in October 2005 stressed that ‘Biomass is unique as the only widespread source of high-grade renewable heat’ (3).The report challenged the Government to recognise that biomass heat can save carbon and help deliver the climate change agenda at a cost favourable to other options. The Government’s stated their agreement with the Biomass Task Force Report, specifically with the conclusion that renewable heat provides important opportunities and is a particularly efficient way of cutting carbon emissions, provided that there is a secure market for the heat generated (4). At the same time the Government acknowledged the contribution that biomass can make to renewable electricity targets through co-firing or dedicated electricity generation. A working group, the Biomass Implementation Advisory Group, has been formed by the UK Department for Environment, Food and Rural Affairs (Defra) to oversee progress in implementing the recommendations. In the framework of these recommendations a five-year new Bio-energy Capital Grant Scheme targeted at biomass heat and CHP was launched on 29 December 2006. This supported the installation of biomass-fuelled heat and CHP projects in the industrial, commercial and community sectors, worth £10–15m in England over the first two financial years to March 2008. The first two rounds of the Bio-energy Capital Grant Scheme allocated grants to project developers and organisations investing in heat and/or electricity generating projects fuelled by energy crops and other biomass feedstocks creating new bio-energy markets. Round six was announced in December 2009 and was open for applications until 31 March 2010. Microgeneration is defined as the small-scale production of heat and/or electricity from a low carbon source (5). Solar, micro-wind, micro-hydro, heat pumps, biomass, micro combined heat and power (micro-CHP) and small-scale fuel cells are all considered microgeneration technologies. MicroCHP is defined as CHP with an electrical capacity of less than 50 kW (6). A number of programmes and actions have been adopted by the Government to support microgeneration: ∑ The Low Carbon Buildings Programme launched by the DTI in April 2006 superseding the previous Clear Skies Initiative and Solar PV programmes (7). The programme provides grants for a number of microgeneration technologies for householders, community organisations, schools, the public sector and businesses. An accredited installer and product are prerequisites for grant eligibility. A list is available from Clear-Skies (http://www.clear-skies.org/). ∑ A field trial of micro-CHP units run by the Carbon Trust (funded by the Government), monitoring the energy and financial savings. The Carbon Trust provides finance for carbon-reduction projects. © Woodhead Publishing Limited, 2011


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Biomass-based small and micro CHP systems

429

∑

A Value Added Tax (VAT) rate reduction on micro-CHP units from 17.5% to 5% since April 2005. ∑ The introduction of new Building Regulations in April 2006, with changes to the regulations on energy conservation encouraging the use of low or zero carbon (LZC) systems to combat climate change. ∑ The UK-wide Community Energy Programme (now closed) provided funding to promote public sector community heating through capital grants to install new schemes and refurbish outdated infrastructure and equipment, primarily using CHP technology.

In July 2006 the Government published its energy review (8), in which it was concluded that on present policies, the UK is on course to exceed its target under the first commitment period of the Kyoto Protocol, this is, to cut overall greenhouse gas emissions by 12.5% on 1990 levels throughout the period 2008–12. However, the growing energy consumption combined with higher levels of electricity generation from coal has led to higher carbon emissions. As a result further action has to be taken in order to achieve the goal of cutting carbon emissions by 60% by 2050 following the recommendation of the Royal Commission on Environmental Pollution. Renewable energy is an integral part of the Government’s strategy for tackling climate change. The key support mechanism for the expansion of renewable electricity is the Renewables Obligation (RO) on all electricity suppliers in the UK to supply a specific proportion of electricity from eligible renewables. This has succeeded in bringing forward major and minor developments of the most economic forms of renewable energy, in particular onshore wind, landfill gas, and co-firing of biomass in coal-fired power stations. The level of the RO is due to rise from 10% by 2010 to about 15% in 2015–16. Although not given special focus in the energy review, biomass is seen as a key component of the general mix of renewables and will make an important contribution, particularly as a source of distributed energy. At the same time the introduction of the EU Emissions Trading Scheme (ETS) creates a strong economic incentive for biomass technologies by putting a price on carbon. Ignoring climate change will eventually damage economic growth and risk irreversible disruption to economic and social activity. Strong, early action is needed to tackle climate change with initiatives such as investment in higher energy efficiency and low or zero carbon emission technologies of which biomass and biomass-fuelled CHP are key contributors.

17.2

Renewables and combined heat and power (CHP) in the UK

In these sections we look first at the broad picture of electricity produced from renewables, then in Section 17.2.2 we review heat from renewable © Woodhead Publishing Limited, 2011


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biomass-based heat production. In Section 17.2.3 we comment on CHP in the UK, then in Section 17.2.4 we focus on the renewable-based CHP.

17.2.1 Renewables and biomass electricity generation in the UK

Electricity Generation from biomass (GWh)

According to the UK Energy Digest (9), the largest contribution to renewables in input terms for 2008 (over 81%) is from biomass, followed by large-scale hydroelectricity production. Only 12.2% of renewable energy comes from renewable sources other than biomass and large-scale hydro (solar, wind, small-scale hydro and geothermal aquifers). Total electricity generation from renewables, excluding non-biodegradable waste in 2008 equalled 21 597 GWh showing a 10% increase compared to electricity generation in 2007 and accounting for 5.5% of the total electricity generated. With biomass derived fuels such as landfill gas, sewage sludge and municipal solid waste, a substantial proportion of the energy content is lost in the process of conversion to electricity. Therefore, although in input terms the contribution of biomass to renewable electricity generation in 2008 was over 81%, in output terms it was 43.1%; this accounts for 9315 GWh and 2.4% of the total electricity generation in the UK that year. In 2007, some 9270 GWh of electricity were generated from biomass, comprising 47.2% of the renewable electricity generation. Recent years have reached a plateau in the total electricity generated from biomass, as shown in Fig. 17.1, with 10 000 9000 8000 7000 6000 5000 4000 3000 2000 1000 2001

2002

2003

2004

Landfill gas Municipal solid waste combustion Animal biomass

2005

2006

2007

2008

Sewage sludge digestion Co-firing with fossil fuels Plant biomass

17.1 Electricity generation from biomass in the UK (GWh).



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a slight increase from 2007 to 2008 due to the contribution of landfill gas, animal and plant biomass, with a small decrease in co-firing biomass with fossil fuel. A list of currently operational and under development biomass electricity projects is presented in Table 17.1. Sewage gas and landfill gas plants are not included in the list although they make a significant contribution. This Table 17.1 Biomass electricity projects in the UK (9, 10, 11) Generating station name

Capacity Fuel (kW)

Technology

Operator company

Date commissioned

Balcas Timber 2450

Sawdust and woodchips

Bioflame

MSW

Incineration

Bioflame Ltd.

01/11/2007

Chestnut Bio 980 Power Ltd (formally Ecoenergy ltd)

Biomass

Chestnut Bio Power Ltd

01/09/2006

Eccleshall Biomass

Miscanthus Combustion – Eccleshall Microturbines Biomass Ltd

01/08/2007

Elean 40 000 Business Park

Straw

Combustion – Vibrating grate steam cycle

EPR Ely Ltd

01/09/2000

Eye Power Station (Fibropower)

Poultry litter

Combustion – Moving grate steam cycle

EPR Eye Limited (previously Fibropower Ltd)

01/07/1992

Fawley Waste 8600 to Energy Plant

MSW

Combustion – Pyros 01/06/2001 FB Environmental Limited

Glanford 16 700 Power Station (Fibrogen)

Poultry litter


EPR Glanford 01/11/1993 Limited (previously Fibrogen Ltd)

Goosey Lodge 16 000 Power Plant

Biomass – Animal waste

Combustion – FB

Wykes 01/10/2000 Engineering Co.(Rushden) Ltd.

J E Hartley Ltd

594

Biomass

J E Hartley Ltd

01/06/2007

Knypersley Renewable Generator

7200

Biomass

Yorkshire Generation Company Limited

01/08/2007

600

2645

14 316

Balcas Timber 01/04/2005 Ltd



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Table 17.1 Continued Generating station name

Capacity Fuel (kW)

Technology

Longma Thorn

400

Recycled vegetable oil

Reciprocating Longma engine Biofuels Ltd

LPL Hockwold

400

Recycled cooking oil

Reg Bio 01/01/2007 Power UK Ltd

Mossborough 300 Hall Farm

Clean wood

Gasification

Biomass Engineering Limited

01/01/2005

Old Manor House

100

Biomass

J B Adams (Farms) Ltd

01/10/2006

PDM Group Widnes

9500

MBM

Combustion – FB

Granox Ltd

01/09/2000

Peabody 239 Trust, BEDZED

Waste timber slurry and food

Reciprocating Peabody Trust 01/05/2002 engine

UPM Shotton 19 655 Paper Boiler 7

Biomass BFB (Sludge from paper mill)

Slough Electricity Contracts Ltd

Packging and wood waste

Combustion – Slough Heat FB and Power

Thetford 41 500 Power Station

Poultry litter


EPR Thetford 01/10/1998 Limited (Fibrothetford Ltd)

Wilton 10 Biomass Gen station

35 220

Energy crops, sawmills waste, recycled wood

Combustion – Boilers

Sembcorp Utilities (UK) Ltd

01/01/2007

Dowhill Farm

120

Biodiesel?

James Crawford

01/07/2005

Stevens Croft

42 260

Energy crops and wood chips

Combustion – E.ON UK plc. Microturbines

Poultry litter

Combustion – The Westfield 01/10/2000 FB Biomass Plant/EPR Scotland Ltd

35 000

The Westfield 12 500 Biomass Plant

Operator company

UPM Kymmene (UK) Ltd

Date commissioned 01/07/2006

01/10/2006

01/04/1993

01/06/2007



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table does not claim to be exhaustive; however, it does represent the best of our knowledge at this time. This is a dynamic area and new projects are likely to be forthcoming over the next few years.

17.2.2 Biomass heat generation in the UK

Thousand tonnes of oil equivalent heat generation

According to a study conducted by Future Energy Solutions (12), in 2005 the production of heat accounted for approximately 30% of total energy consumed in the UK excluding transport. The main provider of heat is natural gas, only 1% is generated from renewable energy sources. On the other hand, 94% of renewable heat comes from biomass. Figure 17.2 shows that the level of heat generated from biomass has been steadily increasing since 2005 after a short decline due to tighter emissions controls discouraging the burning of waste wood. Domestic use of wood is still the main contributor to renewable heat generation whereas the input of industrial wood waste has decreased from 225.2 thousand tonnes of oil equivalent (ktoe) in 2001 to just 93.1 ktoe in 2005 rising again in 2008 to 107.6 ktoe. Residential wood fuel systems are increasing in popularity under the DTI’s Low Carbon Buildings Programme. They vary from stand-alone stoves of 6–12 kWth fuelled by logs or pellets providing space heating for a room, to boilers larger than 15 kWth connected to central heating and hot water systems fuelled by pellets, logs or chips. 800.0 700.0 600.0 500.0 400.0 300.0 200.0 100.0 –

2001

2002

2003

2004

2005

2006

2007

2008

Landfill gas

Sewage sludge

Wood combus-domestic

Wood combus-industrial

Animal biomass

Plant biomass

Municipal solid waste combustion

17.2 Biomass derived fuels used for heat generation in the UK.



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Capital costs depend on the type and size of the specific system and installation and commissioning costs. For a stand-alone room pellet-fuelled heater the price range is around £1500–£3000 which is just the cost of buying the unit. A typical 20 kWth pellet boiler would cost around £5000 to install including the cost of the flue and commissioning, whereas a 20 kWth manual log feed system would be slightly cheaper (13). Fuel supply is the principal operating cost for a biomass heat system. It includes sourcing the fuel, processing the fuel to required specifications (e.g. chipping, sieving and drying for wood chips) and transporting the fuel. The bulky nature of biomass in combination with its lower energy density compared to that of fossil fuels results in higher transport costs. The Biomass Energy Centre (14) published indicative domestic scale delivered biomass fuel costs (pence per kWh, 2010): ∑ wood chips: 2.3 p/kWh ∑ wood pellets: 3.9 p/kWh ∑ natural gas: 4.1 p/kWh ∑ electricity: 13.3 p/kWh. Small-scale (up to 350 kWth) biomass heat systems are more viable in areas not connected to a natural gas line, where their higher capital cost is offset by the lower cost of biomass fuels compared to the cost of oil and liquid petroleum gas (LPG). However, due to increased oil and gas prices, significant potential has arisen in all areas for larger-scale heating projects of more than 350 kW, e.g. community heating, particularly where there is a high or predictable heat demand.

17.2.3 CHP in the UK Combined heat and power offers higher carbon savings per tonne of fuel than the current centralised scheme for power generation. In CHP the heat generated is recovered and utilised for industrial processes, community heating or space heating. It is noteworthy that heat demand is the driver in CHP, and electricity is a useful by-product. Therefore heat projects have the potential to become CHP projects. The economics of the energy markets may alter this balance in the future. According to the 2008 UK Energy Digest (15) some 1439 CHP schemes were operating in the UK with an installed capacity of 5469 MWe generating 27 911 GWh of electricity (7.24% of the total electricity generated in the UK) and 52 197 GWh of heat. This represents a 72 MWe increase in installed capacity equivalent to a 1% increase in electricity generation between 2004 and 2008. In terms of electrical capacity, schemes larger than 10 MWe represent 83% of the total installed capacity. However, in terms of number of schemes, the largest share is in schemes less than 1 MWe (81%).



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With regard to buildings, the largest proportion (from the capacity point of view) is in the health sector, mainly hospitals, whereas leisure and hotels account for more than half the total number of schemes, as shown in Table 17.2. In fact, these three sectors account for 85% in terms of number of units installed, 61% of all electricity capacity and 57% of heat capacity. The major fuel used in CHP schemes in 2008 was natural gas. It comprised 71.1% of the overall fuel used, whereas renewable fuels comprised only 3.7% including sewage gas, other biogases, municipal waste and refusederived fuels. The breakdown of the fuel input for CHP schemes in the UK is depicted in Fig. 17.3. Table 17.2 Number and capacity of all CHP schemes installed in buildings by sector in 2008 (16) Number of schemes

Electrical Heat capacity capacity (MWe) (MWth)

Leisure 394 Hotels 254 Health 187 Residential group heating 40 Universities 41 Offices 17 Education 17 Government estate 17 Retail 17 Airports 3

50.0 36.0 124.2 27.7 50.0 15.0 10.0 15.9 4.6 10.5

54.8 45.4 190.4 61.0 83.8 12.0 17.7 18.6 3.4 18.7

Total

344.0

505.7

987

3.32% 20.06%

1.75%

3.71%

71.16% Coal

Fuel oil

Natural gas

Renewable fuels

Other fuels

17.3 Fuel input for CHP in the UK in 2008.



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Micro-CHP is defined as CHP units with an electrical capacity of less than 50 kW. Micro-CHP units are typically operated as conventional boilers, providing space heating and warm water in residential or commercial buildings. However, unlike boilers, micro-CHP units generate electricity together with the heat at very high efficiencies. Most units operate in grid-parallel mode, so that the building can either receive electricity from or export to the network. Of the 24 million households in the UK, as many as 14 to 18 million are thought to be suitable for micro-CHP units comprising approximately 20 GW of electrical capacity in total (17).

17.2.4 Renewable CHP generation in the UK As was mentioned in the previous section, only 3.7% of the fuels used for CHP generation in 2008 were renewable, i.e. sewage gas, other biogases, municipal waste and refuse-derived fuels, resulting in the generation of 838 GWh of electricity and 1566 GWh of heat. Figure 17.4 shows that the increase in CHP generation from renewables for the period up to 2007 is slow, with an average of a 2% increase for heat and 7.43% increase for electricity. A list is presented in Table 17.3 showing the current biomass CHP plants in the UK. Sewage gas, landfill gas plants and biomass co-firing in coal-fired power stations are not included in the table. Table 17.3 is not claimed to be exhaustive. It is certain that there are projects in development with undisclosed details and even some of the projects in development included in the list could be facing problems with planning and environmental permissions and

CHP generation from renewables (GWh)

3000.0

2500.0

2000.0

1500.0

1000.0

500.0

–

2001

2002

2003

2004

Electricity

2005

2006

2007

2008

Heat

17.4 CHP generation from renewables in the UK (GWh).



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Deeside – North East Wales

Innogy Cogen Ltd Alstom/Foster (Aylesford) CHP – Wheeler C, D ME20 7DL

Holsworthy Devon Andigestion Ltd (part of the Summerleaze Group)

UPM Shotton Paper Boiler 7

Npower Cogen Ltd (Aylesford) CHP – C, D

Holsworthy (Summerleaze) Biogas Plant

Biomass CHP (Exus Energy or B9 Energy Biomass Ltd)

Kilwaughter Chemical Co., Larne, N. Ireland

CHP Enclosure, 21 Sandmartin Way, BEDZED, Wallington, Surrey

Kilwaughter Chemical Co

Peabody Trust, BEDZED



Blackwater Valley Blackwater Valley Museum Museum, N. Ireland

Aker Solutions

Aker Solutions

Meadowhead Road Irvine KA11 5AT

UPM Caledonia Paper mill

Manufacturer/ Developer

Location

Generating station name

Table 17.3 Biomass based CHP plants in the UK (9, 11) Feedstock

Downdraft fixed air gasification

Downdraft fixed bed air gasification


Anaerobic Digestion

BFB

Waste timber slurry and food

Wood chips

Wood chips

Manure, litter and food waste

Sludge from de-inking process

Bubbling Waste paper Fluidised Bed fibre and sludge

Bubbling Waste paper Fluidised Bed fibre and sludge

Technology

1500

Gas engines 239

Gas engines 300

Gas engines 200

Gas engines 2700

Steam turbines

20 000

400

23 000

Operational

In development (News of grant in 2009)

Installed in 1998 Recommissioning

Installed in 2001 Recomissioned in 2005

Operational

Prime mover Output Output Status (kWe) (kWth)



4/5/11 9:42:38 AM

Jepson Bros, Biomass Culcheth, Cheshire Engineering Ltd.

Little Woolden Hall Farm

Biomass Engineering Ltd.

Biomass Engineering Ltd

Preston

ECOS Millenium Centre, N. Ireland


Cumbria



Ballymena ECOS Centre

Stoke

Old Manor House Banbury

Mossborough Hall Biomass Farm Rainford St Engineering Ltd Helens

Mossborough Hall Farm


Location


Table 17.3 Continued



Downdraft fixed bed air gasification (8250 kWe gasifiers)

Downdraft fixed bed air gasification (4250 kWe gasifiers)

Downdraft fixed bed air gasification (12 250 kWe gasifiers)



Technology

2 ¥ Gas engines

300

Wood chips

Wood chips

Clean wood

Wood chips

Reclaimed wood

IC engine

85

Gas engines 65

Gas engines 2000 X4

Gas engines 1000 ¥2

Gas engines 3000 ¥6

170

250

Installed in 2005 Operational

Installed in 2000 Not operational

In development 2007/08

In development

In development Q3 2007

Operational

Operational


Biomass/Wood Gas engines 100 chips

Clean wood

Feedstock



4/5/11 9:42:38 AM

Longlands Lane, Margam, Port Talbot

Courtauld Road, Burnt Mills Industrial Estate, Basildon

University of East Integrated Energy Gasification Anglia, Norwich, Utilities and NR4 7TJ, UK Refgas

Aberdeen

Courtauld Road

UEA Norwich

Seaton Energy Centre

Integrated Energy Utilities

Integra Developments

Eco2

Sawmills residues, forestry residues

IC engine?

Steam turbine

Steam turbine

Gas turbine

Gas

Gas Turbine

2500

1060

1400

4400

2000

13 800

6000

280

55–75

Microturbine 250

Virgin forestry IC engine woodchips

Mechanical MSW Biological Treatment (MBT) and AD

Combustion

Pyrolysis and RDF from gasification mixed commercial, domestic and civic amenity waste

Western Wood Energy Plant

Compact Power/ HLC Henley Burrowes (both went bust)

London Borough of Livingstone

Wood chips

Waste leather

Pyrolysis and Clinical, gasification municipal waste


London Borough of Livingstone Resource Recovery Facility

Compact Power (site acquired by Ethos Recycling/ Cyclamax)


Newton-leWillows


Avonmouth Refuse Transfer Station, Kings Weston Lane BS11 0YS Bristol


British Leather Corporation

Compact Power Avonmouth

Construction by 2008

Comissioning Nov 2009

Permission granted July 2008

Opened in Sept 2009

Failed

Installed in 2001

Installed in 2002 Test operation

Test in 2004. Plant planned for 2005



4/5/11 9:42:38 AM

Great Thickthorn Purepower Farm, Bedforshire energy

Huntingdon, Cambridgeshire

Kimbolton Road, Ravensdaen, Bedforshire

Great Thickthorn Farm

Huntingdon

Kimbolton Road

Boughton Pumping Station, Nottinghamshire

Boughton Pumping Station

Combustion

Anaerobic Digestion

Pyrolysis

Pyrolysis

Pyrolysis

Rural Generation Downdraft Ltd. fixed bed air gasification

Birds Green REG Bio-Power Rattlesden Bury St UK Ltd Edmunds, Suffolk IP30 0RT

REG Bio-Power/ Agri-gen UK Ltd

Purepower energy

Purepower energy

LPL – Hockwold

Bentwaters Building 89 Power Generation Woodbridge IP12 Facility 2TW

Enterprise House, Loucetios Energy Combustion Unit G, Forge Way, Brown Lees Industrial Estate, Knypersley, Staffordshire ST8 7DN

Pyrolysis

Knypersley Renewable Generator

Intervate

Yorkshire

Technology

Esholt Sewage


Location



IC engine

IC engine

IC engine

IC engines

Forest residues, wood chips

IC engine

Waste cooking IC engines oil

95

400

2000

1000

5000

4500

7200

200

Operational

Commissioned late 2009


Food and farm IC engines waste

Mixed waste wood

Mixed waste wood

Waste wood

Jatropha oil

Sewage

Feedstock



4/5/11 9:42:38 AM

Laragh, Enniskillen, Co Fermanagh

Balcas Timber

Bedfordia Biogas Milton Park Milton Ltd Ernest Bedford MK44 1YU

Granox Ltd, Desoto Road, West Bank Dock Estate, Widnes, Cheshire

PDM Group Widnes

Wykes Engineering

Goosey Lodge Wykes Power Plant NN10 Engineering 9LU

Tallbott’s

Tallbott’s

Goosey Lodge Power Plant – A,C,D

Harpers Adams University College

Eccleshall Raleigh Hall Biomass Farming Industrial Estate, Eccleshall, Stafford Forest residues, SRC

Integrated Anaerobic Digestion

95

95

Steam turbines

Steam turbines

200

200

200

786

2700

5500

Operational

Installed in 2006 Operational

Installed in 1992 Test operation

Installed in 1996 Not operational

10 000 Operational

16 000

Microturbine 100

Microturbine 2000

IC engine

IC engine

Food and farm IC engines waste

Sawdust and woodchips

Bubbling MBM, food Fluidised Bed waste

Bubbling MBM, food Fluidised Bed waste

Combustion

Combustion

SRC

Willow chips

Rural Generation Downdraft Ltd. fixed bed air gasification

Enniskillen College

Enniskillen College, Londonderry, N. Ireland

Willow chips

Brook Hall Estate Brook Hall Estate, Rural Generation Downdraft Londonderry, Ltd. fixed bed air N. Ireland gasification



4/5/11 9:42:38 AM

Location


Bracknell Biomass CHP Berkshire

Somerset

Charlton Energy Ltd. CHP Somerset

Bracknell Town Centre Biomass CHP

Buckland down

Charlton Energy Ltd. CHP Somerset

Ridgeway Grain Membury Hungerford Berkshire RG17 7TJ

Ridgeway Grain

Gasification

Combustion

Unit 5b Thorn Business Park Rotherwas HR2 6JT

Longma Thorn

Combustion

Rotating kiln gasifier

Biomass combustion boiler

Anaerobic Digestion


Technology

Dowhill Farm – D Dowhill Farm Dowhill Girvan Ayrshire KA26 9JP

Turrif, Aberdinshire AB53 8BP

Biogask

Bedfordia Biogas Westwood, Ltd Higham Park, Rushden, Northamptonshire



Recycled industrial and agricultural wood

Recycled vegetable oil

7000

1100

340

Gas turbine

IC engines

3000

400

120

Reciprocating 7000 engines

Steam turbine

Waste cooking IC engines and vegetable oil

SRC and woody biomass

Wood chips

Food and farm waste?

1500

7000

7000

4500

Awaiting planning permission

Ongoing research

Post planning permission 2007

Failed (Nontechnical reasons)


Food and farm IC engines waste?

Feedstock



4/5/11 9:42:38 AM

Energy crops

Steam turbine

Food and farm IC engines waste?


Combustion

South Shropshire The Business Park Biowaste Digester Coder Road –D Ludlow Shropshire SY8 1XE

Fluidised bed/ Packging, Steam Vibrating woodchips and turbines grate boilers wood waste

Roves Farm, Wiltshire, Roves Energy

Slough Electricity 342 Edinburgh Contracts Ltd Avenue Slough

Roves Farm, Wiltshire, Roves Energy

35 000

2500

5000

Operational

Operational

444


therefore may not come to fruition. On the other hand this is a dynamic area and new projects are likely to be forthcoming over the coming years. Table 17.3 can be rearranged in the form of charts for easier interpretation as in Figs 17.5–17.8. Figure 17.5 demonstrates that large projects (over 1 MWe) dominate the UK’s biomass CHP scene followed by schemes smaller than 400 kWe. This is of particular importance for market research of future opportunities in the CHP market because it dictates the current trend of biomass CHP appeal, thus the most likely market in which continued growth could be achieved as well as areas in which help is needed in order to promote future growth. Another 4% 32% 58%

6%

50 000

20–1000

Electrical Thermal Overall Heat Lifetime (h) efficiency efficiency efficiency production (%) (%) (%) (°C)

10–20



4/5/11 9:42:40 AM

454


Energy Sources in the internal electricity market (Directive 2001/77/EC). Both directives encourage the reduction in CO2 emissions through novel and efficient technologies. A number of common barriers for further biomass CHP/DH implementation were identified in surveys: ∑

low electricity prices combined with the fact that customers are not willing to pay extra for green electricity; ∑ lack of standardisation on the definitions and the ways of action; ∑ competitive priced fuels; ∑ immature biomass markets; ∑ informational barriers, i.e. lack of public awareness and information/ dissemination.

17.4.6 Novel biomass CHP technology in Austria Austria is one of the pioneers in developing and implementing novel biomass CHP technologies, including ORC, Stirling engines and both steam and gas engines. The OPET document ‘Micro and small-scale CHP from biomass (85%, respectively. Dimensions of this wood pellet MCHP system are 1160 mm (D) ¥ 760 mm (W) ¥ 1590 mm (H) and its weight is 410 kg. There is also the SOLO V161 Stirling CHP system (see Fig. 18.23) which was commercially available in Europe a few years ago [16]. This unit was produced by Stirling Systems GmbH and had 2–9.5 kWel and 8–26 kWth electrical and thermal power outputs, respectively. The SOLO V161 Stirling CHP was used for small commercial applications. The system was built around an alpha (v-type) Stirling engine which uses helium as a working fluid. The crankcase of the engine was unpressurised and separated from the internal gas circuit using special rod seals.

18.4

Overview of the method for estimation of economical and environmental benefits from deployment of micro combined heat and power (MCHP) technology in buildings

The method used for estimation of benefits from deployment of MCHP is described in detail in [17]. The micro- or small-CHP systems are located within or close to the property which utilises the electricity generated, with the recovered heat used to provide space heating and domestic hot water. A grid connection offers the possibility of frequency synchronisation with electricity import/export, should power demand not match the generation of the unit. The MCHP is usually developed as a drop-in replacement for the conventional hydronic central heating boiler. The potential direct benefits of the system are economy for the consumer, savings in primary energy and reduced emissions. The micro-CHP system generates electricity from the fuel, source (mainly natural gas, but also biofuels and diesel or heating oils can be used) with a high overall efficiency due to the heat recovery system. From the differential in price between electricity and fuel, noticeable savings can be made. Also, with the appropriate metering and trading arrangements in place, excess generation can be exported back to the grid for which the consumer would be compensated. Due to the high operating efficiency of around 90%, compared with the 40% of the national electricity supply, the system results in considerable savings in primary energy and resources. From the savings in primary energy, which currently are fossil



4/5/11 9:43:01 AM

Thermal-engine-based small and micro CHP systems

481

18.23 A 9.5 kWel CHP unit on the basis of an alpha V-type SOLO V-161 Stirling engine (photo courtesy of SOLO Kleinmotoren GmbH, Germany).

fuels, there are reduced greenhouse gas emissions. The magnitude of these benefits depends greatly on the deployment scenario, with the greatest gain achieved when the CHP system provides the maximum feasible amount of the thermal and electrical demands. Therefore, the system must suit the



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482


situation in which it is employed. The numerous factors involved include the following: ∑

electrical and thermal demand profiles which depend on climatic conditions; occupancy size and pattern; dwelling type and house fabric details; equipment used and attitude towards energy use ∑ the design of the MCHP system which can be specified by its capacity, heat/power ratio, efficiency and performance characteristics, thermal storage used (type, size, efficiency), electrical stores (type, size, efficiency); heat delivery system and control system and regime ∑ differential in fuel and grid electricity prices, emission factors of fuel and grid electricity; electricity export tariff ∑ installation and maintenance costs.

Due to the vast number of variables involved, it is very complex to make generalised predictions about the local economic and environmental impact of installing a micro-CHP unit. A number of previous papers have already attempted to model the effects of different micro-CHP units. Thus Newborough assessed the benefits of using a generalised MCHP system without referring to a specific technology [18]. Peacock and Newborough analysed the effect of 1 kWel Stirling engine and 1- and 3 kWel fuel cell MCHP on energy flows in the UK electricity supply industry and their impact on domestic CO2 emissions based on the expected average efficiencies of the systems [19, 20]. Cockroft and Kelly compared the performance of four micro-CHP technologies based on an air-source heat pump, fuel cell, Stirling engine and internal combustion engine using general performance characteristics of the above, such as average efficiencies and heat-to-power ratio [21]. Hawkes and Leach highlighted the importance of temporal precision in describing heat and power demand date when assessing CO2 emission reductions with implementation of MCHP systems [22]. According to their investigations, economic and environmental benefits can be considerably overestimated through use of coarse data. This is due to the averaging effects which ignore the significance of peaks and troughs in demand and their effects on energy import/export. However, the calculations in the above publications were performed using only averaged values of the efficiency of MCHP units. Peackock and Newborough attempted to take into account simplified dynamic characteristics of a Stirling engine MCHP during the start-up and shut-down processes [23]. In this chapter it is proposed to predict economic and ecological benefits using the experimental performance maps of the MCHP in various scenarios in the modelling process. This approach is demonstrated using the Whispergen Mk 3 MCHP as an example. First, in order to assess the various competing MCHP technologies, suitable heat and electricity demand profiles in dwellings must be quantified. As the unit is designed for use within a single dwelling,



4/5/11 9:43:02 AM


483

it will be subject to large fluctuations in both electrical and thermal loads, as well as their concurrency, due to the transient nature of a household’s energy requirements. Then, to evaluate the performance of the unit, a spreadsheet model of the hydronic heating system was constructed with the use of the developed daily heat and electrical loadings for weekdays and weekends for different heat demand bands.

18.5

Heat demand modelling

In the domestic sector, the average annual demand amounts to approximately 17 MWht and 4.6 MWhe of thermal and electrical energy, respectively [18]. This gives an annual heat-to-power ratio of 3.7. However, these are subject to significant variations dependent on a number of factors with little direct correlation to dwelling size. This makes it difficult to define a ‘typical home’ for the investigation from which savings predictions can be applied to the UK’s housing stock as a whole. For the purposes of these investigations, specific scenarios have been defined, based on common UK ‘components’. Due to the seasonal variations in household demand, the performance over a year has been calculated by producing daily profiles typical of each month of the year. The results from each of these profiles have then been weighted accordingly and combined to produce an overall picture. To ensure sufficient precision, the modelling procedure for this study have been event based, building up the demand profile on a 1 min time base from predicted events and operation of equipment. The proposed scenarios are based on the type of house that might be most likely to install a micro-CHP unit. This was perceived to be a reasonably modern, well insulated property where the occupants have an interest in the environment and energy saving measures. From statistics produced by the Office of the Deputy Prime Minister (ODPM) in 2004, the most common type of housing was semi-detached (33% of the total housing stock) and this forms the basis of the scenario investigated for two storey semi-detached dwelling with a footprint of 64 m2. The size of the dwelling is based on national averages in 2003 for housing of that type [24]. Trends in house size show significant downsizing has occurred over the last few decades and this is predicted to continue. It was assumed in modelling that the house is occupied by a medium-sized family, consisting of two middle age adults and two children, with a typical full-time work and schooling occupancy pattern as defined in Table 18.1. The household thermal demand consists of three components [18]: ∑

Space heating – supplied by the central heating system with extreme seasonal variation, dependent on climatic conditions, dwelling design, heat delivery mechanism, occupancy patterns and perception of comfort.



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484

Small and micro combined heat and power (CHP) systems Table 18.1 Occupancy pattern for modelling procedure Day

Active occupancy periods

Weekdays Monday–Friday

07:00–08:00

Weekend Saturday–Sunday

18:00–23:00 09:00–23:00

Total occupied time/week

∑

∑

58 hours

Domestic hot water – mainly supplied by the central heating system, but sometimes by electric auxiliary heaters. Little variation with season, but dependent on household appliances, occupants’ attitude to energy use, occupancy size and occupancy pattern. Cooking – supplied by number of appliances which may be fuelled by different fuels. Slight variation with season but dependent on cooking appliances, occupants’ attitude to energy use, occupancy size and occupancy pattern.

In this analysis, in order to characterise the thermal requirements of the proposed scenario, the following factors are included in the modelling process: ∑

The house is sited in the south east of England, where the Whispergen units are being initially installed. The house’s front faces south with a set of double glazed windows installed on the main south and northfacing walls. There are four vinyl windows in each of two main walls with 1 m ¥ 0.91 m and 2 m ¥ 0.91 m dimensions and a 13 mm air gap. The interior wall has a finish made of 100 mm bricks and the house has a gypsum board ceiling and wooden floor. Thermal performance is in line with Part L of the 2000 building regulations [25]. ∑ Internal design temperature is 21 °C. ∑ The house has a conventional hydronic central heating system consisting of a gas-fired central non-condensing boiler (h = 0.8) supplying a network of appropriately sized radiators and 150 litre hot water storage cylinder. ∑ Domestic hot water is supplied entirely from the hot water cylinder with appliances including hot fill washing machine, cold fill automatic dishwasher, standard shower, bath and washbasins. ∑ Cooking is with the use of gas-fired hobs, oven and grill supplemented by an electric microwave, kettle and toaster.

18.5.1 Space heating In order to calculate the space heating requirements of the dwellings throughout the year, a model was constructed in ‘Hot 2XP’, a program developed by the



4/5/11 9:43:02 AM


485

Daily thermal space heating demand (kWh)

CANMET Energy Technology Centre [26] to analyse energy flows within buildings. Taking into account all the appropriate thermal gains (solar, occupants, equipment, cooking), building details and historical weather data, the variations in space heating requirements have been predicted as illustrated in Fig. 18.24. As can be seen, there is a significant variation between the months with no supplementary heating required during the summer months June to September and annual heat demand is 13,172 kWh. The program also calculates the required size of space heating system, based on the maximum rate of heat loss. The result for the semi-detached house model was 5 kWth. This corresponds to the combined thermal output of the radiators when operating, fully open, at their specified supply and return temperatures, i.e. the magnitude of the maximum instantaneous thermal demand from the space heating system. The Whispergen Mk 3 unit has a thermal output of approximately 6 kWth which meets the heat demand in the semi-detached house. The conventional control system of a central heating system consists of a ‘time led’ operation, with defined periods coinciding with the occupancy, between which the system follows the heat demand within the property. The space heating demand is monitored by a simple bi-metallic thermostat positioned within the property. This leads to a profile with a heat-up period and cycling once the design temperature has been reached. The magnitude of the demand is varied depending on the positions of the individual radiator valves. A common energy saving addition to the system is thermostatic radiator valves (TRVs) which automatically modulate the output of individual radiators to match the requirement of the room. The majority use the principal 45 40 35 30

Annual total = 13 172 kWh

25 20 15 10 5 0 Jan

Feb

Mar

Apr May

Jun Jul Month

Aug

Sep

Oct

Nov

Dec

18.24 Daily space heating requirements (averaged on a monthly basis).



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486


of thermal expansion with an appropriate mechanism to steadily close the valve as the room approaches the desired temperature. They save energy by reducing the overheating of individual rooms and, if the boiler is capable of modulating its output, reducing the cycling of the boiler. In terms of the demand profile, TRVs lead to a shape illustrated in Fig. 18.25. The exact proportions and shape depend on a number of factors, such as the initial room temperature, the building’s thermal inertia, performance of the TRVs and current climatic conditions. In particular, the steady state will be subject to fluctuating thermal gains, e.g. solar or occupancy, and this will vary with the control system’s response to these. However, to simplify the modelling, the profile may be split into two stages as shown in Fig. 18.26: the initial heating period where the design temperature is reached followed by the steady state where the temperature is maintained. As the occupancy pattern is based around full-time work, the dwelling will be empty for a significant period in the middle of the day during the week; therefore there will be two timed periods of operation. At the weekend, there is a less prescribed pattern with the likelihood that the property is occupied all day, resulting in a single long period of operation. The occupied periods correspond to the steady state part of the profile (area 2) in Fig. 18.26, when the design temperature is maintained. Therefore the system will come into operation earlier to actually raise the temperature to that required. Taking into account the marked difference between weekdays and the weekend,

1

2

3

Thermal power

Room temperature

On

Off

Time

18.25 Idealised space heating demand profile with TRVs. 1 – The heat up period where the valves are fully open and the system operates at maximum power; 2 – The valves start to close, reducing thermal power, as the temperature approaches the set point; 3 – Steady state reached where thermal power balances heat loss from building.



4/5/11 9:43:02 AM


1

487

2

Thermal power

Room temperature

On

Off

Time

18.26 Space heating demand profile for modelling purposes. 1 – Heat up period where valves are fully open and system operates at maximum power; 2 – Steady state reached where thermal power balances heat loss from building. Table 18.2 Daily space heating demand (kWh) Month

Semi-detached Actual

Banded

January

40

40

February

27

29

March

29

April

15

May

2

June

0

July

0

August

0

September

0

October

1

19 1.5

0

1.5

November

23

19

December

31

29

a representative profile for each type of day is required for each month. However, due to the symmetry of variation throughout the year, months with similar thermal demands can be grouped together so reducing the number of profiles required (see Table 18.2). Appropriate banding is shown in Fig. 18.27, which breaks the year into five different heating categories.



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488


Daily thermal space heating demand (kWh)

45 Actual 40

Banded

35 30 25 20 15 10 5 0 Jan

Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month

18.27 Daily space heating bands used for modelling.

This grouping requires ten separate daily profiles for the dwelling. These are generated using the occupancy pattern in conjunction with the banded daily requirements and output ratings of the systems from the CANMET program. The results demonstrate there is a large variation in the steady state power required from the central heating boiler.

18.5.2 Domestic hot water An average person in the UK uses 49 litres of hot water per day, with little seasonal variation [27]. The actual consumption is linked to the composition of the household, e.g. single or multiple occupiers, over or under 60 years of age, young or dependent children. It also depends on the equipment used and their specification, e.g. automatic washing machine, high flow rate power shower, etc. For the prescribed scenario of a couple with two dependent children utilising an automatic dishwasher, the average daily consumption rises slightly to 50 litres per person, resulting in a household consumption of 200 litres per day. This requires an annual thermal input of 4245 kWhth. As stated, this is supplied from the hot water storage cylinder within the gas-fired central heating system. This thermal storage method uses a heat exchanger within the cylinder to transfer heat from the closed loop boiler circuit to the surrounding water in the cylinder when the central heating system is active. This is regulated by



4/5/11 9:43:03 AM


489

a thermostat on the tank which restricts the maximum temperature to 60 °C. Domestic hot water is drawn off the top of the cylinder, as required, which is then refilled from the cold header tank. This system effectively creates a buffer between demand and generation, providing hot water outside the operation of the central space heating system. The size of the buffer, i.e. storage cylinder, is governed by the overall system design and the demands placed upon it. The capacity specified in the scenario is 150 litres which is around average with a capacity of 8.73 kWhth, assuming an increase of the temperature of water from 10 °C in mains to 60 °C in the cylinder. This part of the thermal demand forms the base load for the system as it demonstrates little seasonal variation, therefore, only two daily profiles are required; weekday and weekend. The same profiles will also be applied to both scenarios. To form the profiles using an event-based method, the uses and their requirements must be identified along with an appropriate schedule. The majority of hot water is required for one of five main activities. These are summarised in Table 18.3 along with their proposed characteristics for the purpose of modelling. There are obviously further miscellaneous uses, e.g. car washing, which are not daily and make them difficult to integrate into the model. However, they are relatively small and can be eliminated without affecting the accuracy of the model. The schedule and frequency of the above events can be calculated by considering the activities of a household throughout the day and the estimated daily usage of 200 litres. The two proposed profiles are shown in Fig. 18.28. As expected, the weekend profile is more distributed throughout the day whilst the weekday profile shows concentrations around the limited occupancy periods.

18.5.3 Cooking Cooking requires high temperature inputs that are not supplied by a central heating system. However, the heat produced does contribute to the thermal gains of the property, slightly reducing the auxiliary space heating required. If Table 18.3 Use of domestic hot water DHW Use

Flow rate Average (l/min) duration/ event (min)

Total volume/ event (l)

Thermal power required (kW)

Energy used (kWh)

Automatic washing machine Showering Bathing Hand washing dishes Hand and face washing

6 5 6 6 4

12 35 54 12 4

20.9 17.4 20.9 20.9 13.9

0.696 2.030 3.135 0.696 0.232

2 7 9 2 1



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490


25 Weekday Weekend Thermal power (kW)

20

15

10

5

0 00.00

03.00

06.00

09.00

12.00 Time

15.00

18.00

21.00

18.28 Domestic hot water thermal power requirements.

the thermal loads due to cooking are met by electricity, the electrical demand profile will demonstrate large fluctuations due to the high power requirements of the thermal devices. As the main cooking appliances in the scenarios are gas-fired, the effects on the electricity profile will be less dramatic.

18.6

Electrical demand

It was assumed in the modelling process that the household electrical demand consists of three types of load: ∑

Base load – a constant load of about 100 We due to the standby power consumption of most electrical goods, plus the cyclic load from refrigeration devices. This is present all day, throughout the year, with little variance. ∑ Biased load – a load that occurs on most days at similar or predictable times, e.g. lighting, television, cooking appliances. These arise through external influences or habitual behaviour. ∑ Elective load – a load operated primarily at the occupier’s discretion, e.g. washing machine, PC. These are harder to predict due to their more irregular nature. The daily electrical profile is made up of a combination of these loads, with the peaks occurring during periods of coincidence. The profile as a whole demonstrates little seasonal variation, except with changes in lighting periods and seasonal equipment. Taking the average annual electricity consumption at 4.6 MWhe [18], the daily usage is approximately 12.6 kWhel.



4/5/11 9:43:03 AM


491

As with the domestic hot water, to form the profiles using an event-based method, the electrical loads and their characteristics must be identified along with an appropriate schedule. Recent years have seen significant improvements in the efficiency of household appliances. With increased public awareness through advertising and literature on the subject, ‘A’ rated appliances are becoming the standard for new and replacement purchases. From previous research on the subject regarding ownership and energy consumption trends [28, 29], the details of the appliances to be included in the model, along with their usage patterns and consumption, were compiled and these are shown in Table 18.4. This table contains only a certain number of the electrical loads present within a household. However, these were thought to be the most influential for the investigation due to either their peak power or usage pattern. In order to create the daily profiles, a suitable schedule for operation must also be created. Due to the slight seasonal variation, it was decided to use the approach adopted for the space heating profiles and generate a pair of profiles, weekday and weekend, for each of the heating categories. This still captures the variation to a suitable degree as it follows a similar symmetric variation through the year. A number of electrical appliances within the household are not used daily, as becomes evident from Table 18.4. This creates problems when generating Table 18.4 Electrical appliances included in profile model Category

Appliance

Category Energy consumption

Usage pattern

Peak power

–

Base load

Base

876 kWh/year

Permanent

100 W

Cold

Fridge-freezer

Base

584 kWh/year

Permanent

270 W

Wet

Washing machine

Elective

1.21 kWh/cycle 274 cycle/year

2.2 kW

Electric tumble dryer

Elective


2.5 kW

Dishwasher

Biased


2.2 kW

Televisions

Biased

190 kWh/year

6.5 hrs/cycle

80 W

PC

Elective

500 kWh/year

3 hrs/cycle

500 W

Vacuum cleaner

Elective

50 kWh/year

1 hr/week

1.5 kW

Lawnmover

Elective

30 kWh/year

1 hr/week (seasonal)

1.5 kW

Iron

Elective

100 kWh/year

0.5 hr/cycle

2 kW

Lighting

Lighting

Biased

440 kWh/year

3–10 hrs/day

1 kW

Cooking

Electric kettle

Elective

250 kWh/year

4–5 cycles/day

2.5 kW

Electric toaster

Elective

70 kWh/year

2–3 cycles/day

1.5 kW

Microwave

Elective

75 kWh/year

300 cycles/year 1.3 kW

Brown



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492


single daily profiles to be applied to extended periods. To overcome this, the operation of these non-daily loads will be evenly spread over 52 weeks to create weekday/weekend profiles to achieve an effect similar to the usage pattern prescribed. As before, the actual daily schedule was created by considering the activities of a household throughout the day and translating this using the acquired appliance information into an electrical demand profile. Examples of those generated are shown in Fig. 18.29. The weekend profile shows a more distributed load with 14.3 kWh of total and 5.35 kW of peak loads against 13.8 kWh and 4.58 kW of total and peak loads, respectively, in weekdays. However, both profiles have similar peaks in the evening due to the high concurrent use of appliances in this period.

18.7

Performance mapping

To produce a comprehensive performance map of the Whispergen Mk 3 MCHP unit, the following key areas were focused on: ∑ response to heat demand (start-up and run-down characteristics); ∑ maximum outputs (electrical and thermal); ∑ modulation capabilities; ∑ full and part load efficiencies; ∑ emission analysis. The Whispergen Mk 3 unit has been installed within a test rig which consists of a small-scale mock-up of a conventional hydronic space heating

6.0 Weekday 5.0 Electrical power (kW)

Weekend 4.0 3.0

2.0

1.0

0.0 00.00

03.00

06.00

09.00

12.00 Time

15.00

18.00

21.00

18.29 Electrical profiles for pairing with 40 kWh heating band.



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493

system (theoretical output of 6 kWth) and the test rig contains a number of meters: Ultrasonic heat meter (Landis Gyr+ 2WR5) – measures the flow rate through the radiators and the heat supplied. ∑ Data logging via RS232 – PC connection to CHP unit itself to log main parameters including electrical output. ∑ Gas meter – monitors gas consumption to calculate overall efficiency. ∑ Gas analyser (RBR Ecom KD) – analyses exhaust composition using heated sample system with probe placed directly in the exhaust flue of the unit.

∑

The heat demand for the system, usually indicated by a combination of a time switch and thermostat, was simplified to a time switch which allows simulation of timed periods of demand. The variables within the rig during experiments were periods of heat demand (duration and pattern), set point temperature of hot water in Whispergen Mk 3 (60–75 °C) and position of radiator valves. A number of experimental configurations were executed whilst monitoring the system. These have been analysed with the relevant information, figures and characteristics extracted for inclusion in the relevant following section. One of the important characteristics that affects the unit’s provision of heat and power is how fast it switches into operation after the heat demand is signalled. This is influenced by a number of factors, such as the control strategy, thermal mass of the cylinder walls and burner output; as with all external combustion engines, it must warm up before it will begin to operate. To evaluate this aspect, the thermal and electrical outputs at the start and finish from a number of cycles were examined and compared.

18.7.1 MCHP performance as a response to heat demand: start-up Start-up characterirics of the MCHP unit were recorded from a number of separate cycles for a 30-minute period following a heat demand signal. In all these cycles the central heating system was starting from room temperature. The results demonstrated significant variation in the time taken to reach a semi-steady state; between 10 and 20 minutes. All of the profiles have very similar shapes and gradients, hence the variation arises from the initial delay in the system before it appears to start. The source of this delay is believed to be internal diagnostics by the control system with dependence on external variables such as the air and current central heating water temperatures. From examining a single pair of electrical and thermal profiles, distinct periods in the start-up procedure can be identified, as shown in Fig. 18.30.



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1500

5

Thermal output

4

Electrical power (W)

1000 Electrical output 500

0

Preheating engine Initial diagnostics

3 2 1

Engine comes to operation

0 Alternator is used as a motor to start the engine

–500

–2 –3

Diagnostic run of the engine –1000

–1

Thermal power (kW)

494

0

5

10 15 20 Time from startup (min)

25

30

–4

18.30 Breakdown of Whispergen Mk 3 start-up characteristic.

18.7.2 MCHP performance as a response to heat demand: run down A similar comparison was made between the profiles recorded after the end of the heat demand. Governed by the control system, the unit operates on a low power level for approximately 30 minutes after the heat demand ceases. Compared with start-up, the profiles are equally consistent in terms of their shape and gradient, but much more so in regards to timing, with two shutdown procedures apparent depending on the power level prior to shutdown. Notable thermal energy is supplied after the shutdown of the engine as the heat stored within the cylinder walls is transferred to the exhaust heat exchanger by the continuing operation of the burner fan. An examination of the run-down characteristic is given in Fig. 18.31.

18.7.3 MCHP performance as a response to heat demand: maximum outputs The maximum outputs were measured by operating the system at 75 °C with the radiators fully open for a three hour heat demand period. This produced the profiles shown in Fig. 18.32. The thermal power reached 80% of its maximum after 20 minutes, plateauing at approximately 6.25 kW after 2 hours while the electrical power reached its steady peak of 850 W after



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495

1500

6 5

Thermal output

4 Engine continues to operate at low power level

Dissipation of internal heat

Burner fan stops

3 Thermal power (kW)


1000

2

500 Electrical output

1 0

0 Engine stopped with gradual withdrawal of heat

–1 –2

–500

–3 –1000

0

10

20 30 40 Time from end of heat demand (min)

50

60

–4

18.31 Breakdown of Whispergen Mk 3 run-down characteristic.

8 6

1000

0

4

Electrical output Thermal output

500

0

50

100

2 150

200

–500 –1000

0 250 –2 –4

Time (min)

Thermal power (kW)


1500

–6

18.32 Maximum outputs of WhisperGen Mk 3 unit.

20 minutes. From examination of the gas consumption, this consisted of a single burner firing rate with the variation due to the system ‘warming up’.

18.7.4 MCHP performance as a response to heat demand: modulation capabilities As the thermal demand within the household will vary and often be less than the unit’s maximum output, it is important to analyse modulation capabilities



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496


of the system. To investigate this, two of the radiators were three-quarters closed, the set point temperature reduced to 65 °C and a two hour heat demand period programmed. This produced the profiles shown in Fig. 18.33. From these results, it becomes apparent that the unit can only operate continuously on two separate power levels. In this run, the unit operated at full power to bring the flow temperature close to that of the set point, after which it switched to a lower level. However, this still provided too much thermal energy causing the flow temperature to continue rising. This resulted in the engine switching off entirely for a 12-minute period while the temperature dropped. The pattern was then repeated when the engine restarted. The unit is capable of little modulation, with only steady state thermal outputs of 5.3 kWth and 6.25 kWth. This will produce a high cycling rate during long periods of low thermal demand which will be detrimental to the performance of the unit.

18.7.5 Efficiency per cycle and power level efficiencies The economic performance of the unit will be governed by both its overall efficiency and heat-to-power ratio (HPR). This is due to the significant difference in gas and electricity prices. The efficiency and HPR can be examined on two levels: ∑

Per cycle basis using the total output energies and gas consumption for the period. This can be used to compare modulated and non-modulated cycles. Power level basis using the recorded trends within a cycle. This can be used to analyse the full and part load efficiencies.

∑

Thermal power (kW)

7

70

Set point temperature

6

60

5

50 40

4 3

Thermal output

2

Flow temp

30

1 0

–1

0

20

40

60

20

Unit switches off for a period 80 100 Time (min)

120

140

10 160

0

Water flow temperature (°C)

For comparison, the profiles from Figs 18.32 and 18.33 were analysed along with their gas consumption data. The results are presented in Table 18.5. The figures show a significant difference in both the efficiencies and ratios for the compared cycles. As anticipated, the modulated cycle with its engine

–10

18.33 Modulated thermal output of Whispergen Mk 3 unit.



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2 hours

Modulated

24.74 kWh 14.99 kWh

2.312 m3 1.401 m3 1.120 kWh

2.564 kWh

Input energy* Total electricity generated

Gas consumed

*Based on a calorific value of 10.7 kWh/m for natural gas

65 °C 3

3 hours

Full power

75 °C

Heat demand Set point duration temperature

Cycle

Table 18.5 Example cycle efficiencies

11.207 kWh

19.984 kWh

Total heat generated

10.00

7.79

82.23%

91.4%

Heat-to-power Overall ratio efficiency

498


shutdown period is nearly 10% less efficient. Also, the proportions of heat generated are greater, further decreasing the comparative economic value. The instantaneous efficiency of the unit was analysed for the two steady state power levels, namely full and intermediate power levels. This was achieved using two 3 hour runs at 65 °C and 75 °C and their gas consumption. The data used to calculate the efficiency were taken once the outputs had stabilised. The results are shown in Table 18.6. Both power levels have high overall efficiencies of over 90% but the major difference lies in the heatto-power ratio. This is almost doubled when the unit switches from full to intermediate power. Hence, the possible economic returns will be severely diminished if the unit operates at the intermediate power level for extended periods due to the reduced proportion of electricity produced.

18.7.6 Emissions analysis As one of the major drivers behind micro-CHP development is the reduction of harmful gas emissions, the composition of the Whispergen’s exhaust is very important. This was investigated using the gas analyser included in the test rig. The combustion process inputs are natural gas and air. Therefore, the components of flue gas are primarily made up of compounds of oxygen, nitrogen, hydrogen and carbon. The efficiency of the combustion process can also be determined from the combustion products. This was achieved using the oxygen and/or CO2 measurement in conjunction with pre- and postcombustion gas temperatures. The calculation was performed automatically by the gas analyser. The exhaust composition and combustion efficiency was logged at two-minute intervals for a number of experimental runs. An example from a three hour run is shown in Fig. 18.34. The gas analyser relies on an electrochemical reaction for its readings and must be purged at regular intervals during continuous measurement, hence the short gaps in readings. The actual amount of carbon dioxide produced depends on the type and amount of fuel burnt, hence this was a function of gas consumption rather than the burner design. For natural gas, this was 0.19 kg/kWh. Carbon monoxide is the product of incomplete fuel combustion from the lack of oxygen. As the Stirling engine design is based on continuous external combustion, which is easily optimised, the combustion process is highly efficient as indicated. This results in little formation of carbon monoxide once the process has stabilised. The principal source of NOx emissions in natural gas appliances is the oxidation of excess atmospheric nitrogen at temperatures above 1100 °C. Modern applications require the minimisation of NOx through advanced burner design. Emissions can be greatly reduced by rapid or complete mixing of the gas/air fuel supplies and encouraging the internal recirculation of combustion



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3 hours

3 hours

Full

Intermediate

850 W (11.1%)

7.640 kW 6.227 kW

0.714 m3/hour 0.582 m3/hour 400 W (6.4%)

Electricity power

Gas Input power* consumption rate

*Based on a calorific value of 10.7 kWh/m3 for natural gas

65 °C

75 °C

Heat demand Set point duration temperature

Power level

Table 18.6 Power level efficiencies

5.3 kW (85.1%)

6.25 kW (81.8%)

Thermal power

13.25

7.35

91.54%

92.88%

Heat-to-power Overall ratio efficiency

500


140

NOx (ppm) CO (ppm) CO2 (%) Combustion efficiency (%)

*Peak 1960 ppm

120 100 80 60 40 20 0

0

50

100 Time (min)

150

200

18.34 Exhaust composition analysis of Whispergen Mk 3 unit.

products. This minimises the peak temperatures in the combustion zone. The Whispergen Mk 3 unit has peak NOx emissions of over 120 ppm. During steady state operation this level is about 80 ppm. Typical NOx emission level in conventional burners is between 110 and 150 ppm. In burners with the fully pre-mixed combustion process, the NOx emission level is reduced to 45–75 ppm whilst advanced burners, such as catalytic stabilised and catalytic, have NOx emissons less than 5–10 ppm [30].

18.8

Economic and environmental analysis

To evaluate the performance of the unit, a spreadsheet model of the hydronic heating system was constructed with the use of the daily developed heat and electrical loadings for weekdays and weekends for different heat demand bands. The mapped characteristics of the unit were applied, and the system performance calculated for each of the pairs of electrical and thermal demand profiles. The time step in the modelling process has been to one minute. This is necessary in order to make it possible to reflect the gradual increase or decrease in the thermal and electrical outputs when the engine is switched on or off. The results were weighted according to the banding strategy to form a picture of the unit’s performance over a typical year in each scenario. These were then analysed for efficiency and the anticipated economic and environmental savings of installing a micro-CHP. In the modelling process the following physical features of the heating system were taken into account: ∑

Thermal inertia – As well as the thermal mass of the house and hot water



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501

cylinder, the water and associated pipe work within the heating circuits have their own mass. This affects the lag present within the system. The heat capacity of the test rig was determined by examining the rate at which the radiators heated during the experimental runs in conjunction with the thermal input and dissipation calculated. This capacity was then scaled to each scenario according to the maximum space heating output of each system. Additional thermal mass was also added to model the 5 kW heating circuit through the hot water cylinder which is not present in the test rig. ∑ Individual space and tank thermostats – Most heating systems contain a distribution valve which directs the hot water from the boiler to where it is needed. If no further space heating is required, all the water from the boiler is directed to the hot water cylinder and vice versa. This was included in the model along with the effects when the valve position changes, mixing standing water from one circuit with the active circuit. ∑ Variable heat loss – As the inside of the house heats up, the heat loss through the fabric will increase in proportion. The heat losses from the house in various seasons, at design temperature, were obtained from the CANMET program results. These were then used to model variable heat loss for each season based on the current internal and appropriate ambient temperatures. ∑ Standby losses from hot water cylinder – While the hot water is stored in the cylinder, an amount of heat is lost through the walls depending on the temperature of the water. This can be reduced through insulation, although not totally removed. An appropriate loss was included in the model in line with current British Standards for hot water cylinders. The effect of thermal stratification within the cylinder was also taken into account for modelling the performance of the heat exchanger. To assess the economic benefits of the Whispergen Mk3 unit, the associated costs must be compared to the base situation of a conventional boiler with all the household electricity imported from the grid. In conjunction with the performance of the Whispergen Mk 3 unit, the most important factor is the differential between gas and electricity prices. For analysis, the standard ‘British Gas’ gas and electricity tariffs for 2005 in the London area were used. In this example, benefits from the new feed-in tariff scheme were not included in the calculations. These, along with most other tariffs, consist of two rates: a higher rate for the first x units each quarter followed by a much lower rate. To ease the costing, these were averaged out on the estimated household usage. The result was a kWh unit cost of 3p and 10.6p for gas and electricity, respectively. This leads to a significant difference which will maximise the value of the micro-CHP generation.



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502


A further value is generated by any rebate for the export of excess electricity through the appropriate network and metering interface. The rebate per exported unit is generally significantly less than the import rate due to the embedded infrastructure costs, etc. A rate of 3p per unit was used for the analysis as an average value. The main environmental benefit comes from reduced CO2 emissions through high efficiency of localised generation. From analysis of the electrical grid and its generation facilities, the amount of CO2 released per unit reaching the consumer can be estimated and the figure used in the calculations was 0.43 kg/kWh. A similar figure was produced for the combustion of natural gas, which was 0.19 kg/kWh. The reduction in CO2 emissions was calculated using these figures and the assumption that the electricity exported from the household was ‘CO2 free’. The performance of the unit is strongly related to how well it can match its thermal output to that required. The band 1 winter days had the highest rate of heat loss from the building and therefore required the most space heating input. In conjunction with the hot water cylinder, this provided a large enough thermal sink to prevent the system flow temperature from rising above that at which the Whispergen Mk 3 unit shuts down. This lead to long run times with little cycling, resulting in a high efficiency with a constant electrical output. However, simulation results demonstrate that the temperature of the water in the hot tank drops below an acceptable level. The various system temperatures for the weekday in this band are shown in Fig. 18.35. The corresponding electricity import/export profile shows mainly concurrency between generation and demand resulting in little export, maximising the value of the electricity generated. The high thermal demand also allowed the unit to operate at full power for significant periods which minimised the heat-to-power ratio. The graph illustrating the electrical distribution is shown in Fig. 18.36. The economic and environmental savings are inherently dependent on duration of operation resulting in days of highest thermal demand having the largest attributable savings. In contrast, as the space heating demand decreases towards the middle of the year due to reduced heat loss through the fabric of the building, the system does not have enough thermal dissipation for the Whispergen Mk 3 to run continuously at even its intermediate power setting. This resulted in the constant cycling shown in Fig. 18.37 by the system temperatures for a mid-season weekend profile. It can be seen that the MCHP does not maintain the hot water temperature in the storage tank. The operating efficiency for this profile showed a marked 5% decrease compared to its band 1 equivalent. The intermediate power operation also increases the heat-to-power ratio which further diminishes the savings. The corresponding electricity profile (Fig. 18.38), showed the expected import/export fluctuations, partly due to



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Thermal-engine-based small and micro CHP systems 90 80

Cylinder temp Radiator flow temp System flow temp House temp

House design temp

Temperature (°C)

70

503

Active occupancy period

60 50 40 30 20 10 0 00:00

03:00

06:00

09:00

12:00 Time

15:00

18:00

21:00

18.35 System temperatures for semi-detached heating band 1 weekday. Cylinder Temp – the average temperature of the water in the hot water tank; Radiator flow temp – the temperature of the water coming out of the radiators; System flow temp – the temperature of the water coming out the MCHP. 6.0


Demand 5.0

Import/export

Electrical power (kW)

4.0 3.0 2.0 1.0 0.0 00:00 –1.0

03:00

06:00

09:00

12:00

15:00

18:00

21:00

Time

18.36 Electricity profile for semi-detached heating band 1 weekday.

cycling but also to the reduced electricity demand during the middle of the day. The Whispergen Mk 3 operates at flow temperatures considerably lower than a conventional boiler to maximise the efficiency of and protect the



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504


90

Cylinder temp Radiator flow temp System flow temp House temp House design temp

80

Temperature (°C)

70 60


50 40 30 20 10 0 00:00

03:00

06:00

09:00

12:00 Time

15:00

18:00

21:00

18.37 System temperatures for semi-detached heating band 3 weekend.

5.0

Active occupancy period Demand

4.0 Electrical power (kW)

Import/export 3.0

2.0

1.0

0.0 00:00 –1.0

03:00

06:00

09:00

12:00

15:00

18:00

21:00

Time

18.38 Electricity profile for semi-detached heating band 3 weekend.

Stirling engine from overheating and therefore it would be desirable to modify the existing heating system by switching to low-temperature radiators. Conventional radiators can still be used though they are designed to operate with a higher temperature difference of ~50–60 °C while the Whsipergen Mk 3 provides the thermal output restricted to a temperature difference of



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505

~40 °C as found in the simulation. Due to this lower temperature of the water coming out of the MCHP system, there is also restricted heat transfer in the hot water cylinder. During the summer months when the need for space heating is practically removed, the unit operates periodically to heat the hot water cylinder. However, without the load sink of the space heating system and the limited transfer to the cylinder itself for the reasons above, the flow temperature quickly rises causing the unit to shut down. Therefore, the summer profiles consist of an excess number of short, intermediate power cycles resulting in relatively low overall efficiency, high heat-to-power ratio and little production of electricity. As in previously considered cases, the MCHP is not capable of maintaining the high temperature level in the storage tank. This kind of operation is shown in Fig. 18.39. As anticipated, the annual variation in daily savings basically mirrors the thermal demand of the household, as is apparent in Fig. 18.40. Due to their origin, the CO2 and financial reductions are directly related. During the four summer months, the savings drop to a lowly 4% meaning little difference is seen between the CHP and conventional system. A similar variation profile is apparent in the unit’s efficiency, although with reduced magnitude. The lack of reasonable thermal demand-following capabilities results in an estimated total of 2078 cycles per year, averaging over five a day. This is acutely detrimental on the service interval of the unit as well as its expected life. 90 80

Temperature (°C)

70 60


Cylinder temp Radiator flow temp System flow temp House temp House design temp

50 40 30 20 10 0 00:00

03:00

06:00

09:00

12:00 Time

15:00

18:00

21:00

18.39 System temperatures for semi-detached heating band 4 weekend.



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18

90

16

80

Daily saving and ratio

20

14

70

12

60

10

50

8

40

6

Heat-to-power ratio

30

4

CO2 saving (%) Economic saving (%)

20

2

Efficiency (%)

506

10

Efficiency

0

0 Jan

Feb Mar Apr May Jun Jul Month

Aug Sep

Oct

Nov Dec

18.40 Annual variation of Whispergen Mk 3 performance for semidetached scenario.

Over the year, the unit satisfied 16.9% of the household’s electrical requirements in response to the thermal demand. This relatively low figure illustrates the mismatch between the annual heat-to-power ratios of 8.85 for the unit and 2.04 for the demand. The ratio for the modelled demand is lower than the average but it is typical for the modelled modern house due to the trends in house design and electrical appliance ownership. Of the electricity generated, 26.5% was exported to the grid. This indicates a reasonable level of concurrency between thermal and suitable electrical demands to absorb the electricity generated. The annual savings amount to 9% and 9.3% in monetary and CO2 terms respectively. The household was modelled using the ten representative heat/ power profiles analysed above, providing simulation results on a per day basis. These are summarised in Table 18.7 along with a weighted annual summation. One of the major problems with this particular MCHP system (the Whispergen Mk 3) was its small range of thermal modulation. Modern high efficiency boilers commonly have continuous modulation capabilities with a ratio of 1:3. This is compared to a ratio of 1:1.2 with only two discrete values available for the Whispergen Mk 3 unit. Excessive cycling occurs as a result. The operation of the Whispergen Mk 3 unit could be improved by adapting the existing heat delivery systems within the household to greater suit the characteristics of the unit. This could be achieved in a number of ways, such as the use of larger conventional radiators, taking into account the lower temperature differential when calculating the output, or forced convection



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1 2 3 4 5 1 2 3 4 5

Annual summary

Weekend

Weekday

6.168 4.660 3.607 1.289 1.149 8.020 7.403 5.212 1.498 0.976 1159

Electricity generated (kWh)

47.860 36.862 32.969 16.605 13.460 75.627 55.120 43.292 15.964 11.207 10254

60.859 47.602 42.464 20.860 17.477 94.411 73.515 57.851 20.962 14.778 13279

Thermal energy Gas generated consumption (kWh) (kW)

Table 18.7 Summary of semi-detached simulation results

Heating band Heating band


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2 6 7 5 4 4 12 12 5 4 2078

On/off cycles 9.606 11.045 11.582 12.574 12.426 8.004 8.990 10.288 11.309 12.914 4187

1.410 1.348 0.885 0.179 0.247 2.197 2.548 1.650 0.397 0.05 307

Electricity Electricity imported exported (kWh) (kWh) 7.759 7.910 9.140 12.879 11.716 9.430 7.445 8.307 10.657 11.488 8.85

Heat-topower ratio 88.776 87.229 86.136 85.785 83.591 88.599 85.049 83.845 83.306 82.433 85.950

15.5 11.9 10.1 5.8 4.4 16.0 12.8 10.2 5.1 4.1 9.3

2.46 1.71 1.31 0.53 0.37 3.47 2.31 1.53 1.45 0.27 411

14.00 11.48 9.39 5.44 4.15 14.52 12.11 9.43 4.96 3.17 9

Efficiency Economic CO2 savings (%) saving (kg) (%) (%)

508


to increase the radiator heat dissipation via fans, although this may produce an undesirable environment in terms of noise and excessive air motion. A thermal storage system for space heating could be used as well for the domestic hot water, so allowing long, highly efficient periods of operation [31]. Most importantly, it should be highlighted that the above relatively conservative results were obtained without taking into about the new feed-in tariff scheme which is currently in place (£0.1 for each kWhel for cogenerated power and an additional £0.03 for each kWhel exported to the grid). If this new scheme is taken into account, then savings produced by a MCHP appliance will increase significantly. Finally, the system’s operation on ‘intermediate power’ level may have reduced the value of the electrical efficiency in these tests on the Mk 3 unit. The intermediate power mode is disabled in the currently available Mk 5 version of the unit and the engine operates at full power and only switches on and off. Further, the Mk 5 version of the MCHP is equipped with an auxiliary burner to meet higher levels of heat demand and utilises a low emission, pre-mix, steel mesh burner with NOx levels in the 20–40 ppm range.

18.9 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17.

18.

References

http://www.otag.de, OTAG Vertriebs GmbH & Co.KG, 17 September 2010. http://www.energetixgroup.com, Energetix Group plc, 12 September 2010. http://www.cogenmicro.com, Cogen Microsystems, 15 September 2010. http://www.hondanews.com, HONDA, 12 December 2008. http://www.freewatt.com, 16 August 2010. www.baxitech.co.uk, Baxi-SenerTec UK, 14 August 2010. www.ecpower.co.uk, EC Power A/S, 15 September 2010. http://www.whispergen.com/, Whisper Tech Ltd, 29 April 2010. http://www.disenco.com, DISENCO ENERGY plc, 12 July 2010. http://www.microgen-engine.com, Microgen Engine Corporation, 12 May 2010. http://www.enatec.com, ENATEC Micro Cogen b.v., 12 September 2010. http://www.sunmachine.com, 16 August 2009. http://www.eonenergy.com/At-Home/Products/Technology-And-Initiatives/ WhisperGen.htm, E.ON, 12 December 2008. http://www.ehe.eu, 16August 2010. http://www.baxi.co.uk/ecogen, 16 August 2010. http://www.stirling-engine.de/engl, Stirling Engine Systems GmbH, 12 December 2008. Veitch, D.C.G. and Mahkamov, K. 2009. Assessment of economical and ecological benefits of using a Stirling domestic CHP unit based on its experimental performance. Proceedings of the Institution of Mechanical Engineers, Part A, Journal of Power and Energy, 223/7: 783–798. Newborough, M. 2004. Assessing the benefits of implementing micro-CHP systems in the UK. Proceedings of Institute of Mechanical Engineers, Part A: Journal of Power and Energy, 218(4): 203–218. © Woodhead Publishing Limited, 2011


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19. Peacock, A.D. and Newborough, M. 2006. Impact of micro-combined heat-and-power systems on energy flows in the UK electricity supply industry. Energy, 31(12): 1804–1818. 20. Newborough, M. and Peacock, A.D. 2005. Impact of micro-CHP systems on domestic CO2 emissions. Applied Thermal Engineering, 25(17–18): 2653–2676. 21. Cockroft, J. and Kelly, N. 2006. A comparative assessment of future heat and power sources for the UK domestic sector. Energy Conversion and Management, 47(15–16): 2349–2360. 22. Hawkes, A. and Leach, M. 2005. Impacts of temporal precision in optimisation modelling of micro-combined heat and power. Energy, 30(10): 1759–1779. 23. Peacock, A.D. and Newborough, M. 2007. Controlling micro-CHP systems to modulate electrical load profiles. Energy, 32(7): 1093–1103. 24. http://www.planningportal.gov.uk, 29 April 2008. 25. http://www.rics.org, 29 April 2008. 26. http://www.sbc.nrcan.gc.ca/software_and_tools/hot2xp_e.asp, 29 April 2008. 27. Estimates of hot water consumption from the 1998 EFUS. Implications for the modelling of fuel poverty in England. A summary report presenting data from the 1998 EFUS produced by the BRE Housing Centre on behalf of DTI and DEFRA. June 2005. 28. Newborough, M. and Augood, P. 1999. Demand-side management opportunities for the UK domestic sector. Generation, Transmission and Distribution, IEE Proceedings, 146(3): 283–293. 29. Fawcett, T., Lane, K. and Boardman, B. et al. 2000. Lower carbon futures for European households, Environmental Change Institute, Oxford University. http:// www.eci.ox.ac.uk/research/energy/lcfpublications.php, 29 April 2008. 30. Joynt, B. and Wu, S. 2000. Nitrogen oxide emissions standards for domestic gas appliances, Chapter 5. February 2000 Environment Australia. http://www.environment. gov.au/atmosphere/airquality/publications/residential/, 9 September 2008. 31. Haeseldonckx, D., Peeters, L., Helsen, L. and D’Haeseleer, W. 2007. The impact of thermal storage on the operational behavior of residential CHP facilities and the overall CO2 emissions. Renewable and Sustainable Energy Reviews, 11(6): 1227–1243.



4/5/11 9:43:06 AM

Index

absorption, 279 absorption heat pumps, 280–2 absorption refrigeration, 9–10 active magnetic bearings, 166 adsorption heat pumps, 282–4 air pre-heater, 188 AMB see active magnetic bearings anaerobic digestion, 104–5 anaerobic digestor, 511 APU see auxiliary power units Aqueous Ammonia cycle, 9 Argent Energy (UK) Limited, 106 ash, 92 auxiliary burner, 244 auxiliary power units, 336 baffles, 49 bagasse, 5 Baxi SenerTec Dachs, 473 bearings, 165–6 active magnetic bearings, 166 gas, 165–6 oil-lubricated, 165 Beddington Zero Energy Development, 448 BedZED see Beddington Zero Energy Development beverage processing see food and beverage processing Bio-energy Capital Grant Scheme, 428 bio-oils, 100, 101, 132, 133 biodiesel production, 105–7 bioenergy, 89 biofuel, 89 biogas, 89, 104, 212, 350 biogas-driven small CHP system in sewage works, 60–8 choice of prime mover, 61–3 CHP system flow diagram, 63 engine performance, 63–4 efficiency and heat rejection, 64 Sankey diagram for a single generation scheme, 65 exhaust heat recovery, 66

economiser performance, 66 heat recovery system, 64–6 compact heat exchanger performance, 66 overall system performance, 66–7 emissions reduction per generator, 67 Sankey diagram for cogeneration scheme, 67 biomass, 212–13, 350, 412, 427–8 categories, 89–91 non-woody biomass, 90 organic waste biomass, 90–1 woody biomass, 89–90 combined heat and power technologies, 108–16 combustion-based, 108–14 gasification-based, 114–15 illustration, 108 other, 116 combustion and prime mover, 109–14 biomass-fired hot air gas turbine process, 114 biomass-fired micro-scale CHP system with ORC, 111 hot air gas turbine, 113–14 ORC-based biomass CHP plant of Lienz, 110 organic Rankine cycle turbine, 109–12 small-scale biomass Stirling engine CHP of BIOS, 113 steam turbine/steam engine, 108–9 Stirling engine, 112–13 conversion technologies, 94–107 anaerobic digestion, 104–5 basic steps in anaerobic digestion process, 105 basic steps of biomass fermentation, 102 biodiesel production, 105–7 biomass thermochemical conversion processes, 99 conversion processes, 95–6 fermentation to produce ethanol, 102–4 gasification, 98–100 pathways of biomass pyrolysis, 101


CHP-Beith-Index.indd 514

4/5/11 9:44:36 AM

Index pyrolysis, 100–2 current development of small and micro CHP, 107–16 fuels for small and micro combined heat and power systems, 88–116 renewable energy resource, 89–91 illustration, 90 solid biomass fuels, 91–4, 95, 96–8 50 kW wood pellet boiler, 97 Arimax Bio Energy boiler, 98 average net calorific value, 94 calculation of analyses to different bases, 93–4, 95 calorific value, 93, 94 characterisation, 91–4, 95 combustion, 96–8 combustion stages, 96 formulae for calculation of results to different bases, 95 moisture content effect on biomass fuel net calorific value, 94 proximate, ultimate analyses and gross calorific values, 95 proximate analysis, 92 ultimate analysis, 92–3 world energy supply, 91 biomass-based small and micro CHP systems application and status in UK, 427–56 technical changes, 450–2 UK energy policy and targets, 427–9 capital costs, 452–5 European policy, 453–4 novel biomass CHP technology in Austria, 454 small-scale biomass CHP in Europe, 453 small-scale biomass CHP in Sweden, Denmark and Finland, 454–5 small-scale biomass combustion CHP, 452 small-scale biomass gasification CHP, 452 small-scale biomass pyrolysis CHP, 452 technological characteristics from small scale CHP production, 453 difficulties associated with biomass fuels, 450–1 biodiversity and land use, 450 energy efficiency, energy balance and carbon neutrality, 450 food shortages, 450 supply and security of supply issues, 451 difficulties associated with prime movers, 451–2 IC engines, 451 turbines, 451–2 past and present small-scale biomass gasification companies, 447–9

515

Beddington Zero Energy Development (BedZED), 448 Biomass CHP, 447–8 Biomass Engineering, 447 Blackwater Valley Museum, Benburb, 448 Boughton Pumping Station, 449 Brook Hall Estate, Londonderry, N. Ireland, 448 ECOS Millennium Centre, Ballymena, N. Ireland, 447 Little Woolden Hall Farm, Culcheth, Cheshire, 447 Mossborouh Hall, Merseyside, 447 Rural Generation Ltd, 448–9 past and present small-scale biomass pyrolysis + gasification examples, 449–50 Compact Power, 449 Harper Adams University College, 449–50 Talbott’s Biomass Energy System, 449–50 renewables and combined heat and power in the UK, 429–50 biomass-based CHP plants in the UK, 437–43 biomass derived fuels used for heat generation, 433 biomass electricity projects, 431–2 biomass heat generation, 433–4 CHP in UK, 434–6 CHP schemes installed in buildings by sector (2008), 435 electricity generation from biomass, 430 fuel input for CHP (2008), 435 increase in CHP generation from renewables, 436 renewable CHP generation, 436–46 renewables and biomass electricity generation, 430–3 UK biomass CHP arranged by feedstock, 445 arranged by prime mover, 444 arranged by size, 444 arranged by technology, 445 Biomass Energy Centre, 434 biomass fermentation, 102–4 biomass gasification, 98–100, 446 thermochemical conversion processes, 99 Biomass Implementation Advisory Group, 428 biomass pyrolysis, 100–2 fast pyrolysis, 101–2 pathways, 101 slow pyrolysis, 100 Biomass Task Force Report, 428 boiler station, 354 bottoming cycle, 405



4/5/11 9:44:36 AM

516

Index

bowl-in-piston combustion chamber designs, 133 Brayton cycle, 152, 153, 449–50 Brazil’s PRO ALCOOL programme, 102 BS EN 14775:2009, 92 BS EN 14918:2009, 93 BS EN 15148:2009, 92 BS EN 14774-1:2009, 92 BS EN 14774-2:2009, 92 BS EN 14774-3:2009, 92 BS EN 14778-1:2005, 92 Building Regulations (2006), 428 CAES see compressed air energy storage Calnetix Power Solutions, 172, 405 capacitors, 309 capacity ratio, 51 Capstone Inc., 172 Capstone Turbine Corporation, 173, 405 carbon dioxide central performance metric, 26 emissions reduction performance, 35–8 CO2 performance of two micro-CHP systems to annual thermal demand in target dwelling, 37, 38 CO2 reductions to prime mover capacity, 36 Carbon Reduction Commitment (CRC), 391 Carbon Trust, 428 Carnot COP, 286–9 Carnot cycle, 465 Carnot efficiency, 187, 189, 199, 230 Carnot’s principle, 186 Casten, T., 4 CCHP see combined cooling, heat and power cellulosic biomass, 102–3, 104 CEN/TS 15104:2005, 93 CEN/TS 15289:2006, 93 CEN/TS 15290:2006, 93 CEN/TS 15296:2006, 94 CEN/TS 15297:2006, 93 Central Electricity Generating Board, 4 CFD see computational fluid dynamics choking, 168 CHP see combined heat and power CHP systems see combined heat and power systems clean wood, 446 Cleanergy AB, 198 CODEGen see Cost Optimisation of Decentralised Energy Generation Coefficient of Performance, 10, 412 Cogen Microsystems, 471, 473 cogeneration see combined heat and power cogeneration plant, 46–7 combined cooling, heat and power, 266 combined heat and power, 427 grid services applications, 317–18

systems applications, 315–17 costs of storage, 317 domestic scale, 316 economic scale, 316–17 establishment scale, 315–16 combined heat and power systems, 3–16, 43, 510–13 applications in fuel cell systems, 233–56 commercial development and future trends, 253–6 fuel cell systems, 239–46 fundamentals of operation, types and properties of fuel cells, 234–8 operating conditions and performance, 246–53 barriers, 15–16 biomass fuels, 88–116 biomass conversion technologies, 94–107 current development, 107–16 solid biomass fuels characterisation, 91–4 cogeneration, 3–5 commercial exploitation pathways, 24–5 community microgrid, 24 company control, 24 plug-and-play, 24 conclusion and outlook, 512–13 cost benefit and emissions reduction, 12–13 district and community heating aspects, 347–63 Aars, Denmark case study, 360–2 control system and consumer installations, 353–9 future trends, 363 heat sources, 349–51 Lerwick, Shetland case study, 359–60 pipework installation issues and design considerations, 351–3 preconditions, 348–9 energy efficiency improvement, 11–12 energy storage, 307–22 applications, 315–17 electrical energy storage application, 309–15 electrical vehicles, 318 energy management applications, 307–8 future trends, 321–2 grid services applications and relationship, 317–18 islanding capability applications, 308 large-scale and small-scale storage – conceptual planning, 318 power trading, 308 thermal storage development and application, 318–21 types of systems, 308–9



4/5/11 9:44:36 AM

Index food and beverage processing industries, 395–421 established CHP technologies for food industry, 404–6 food processing and energy requirements, 396–7 future trends, 419–21 heat and power integration of food total sites, 397–400, 401 high-efficiency technologies, 406–11 integration of renewables and waste, 411–14 potential applications, 414–19 suitable types of small and micro CHP for food industry, 400, 402–4 future trends, 16 grid connection, 13–15 harmonics, 15 inverters, 15 protection, 13–14 synchronisation, 14 system fault level analysis, 14–15 heat-activated cooling technologies, 262–306 advantages and limitations of heatactivated cooling, 296–7 closed sorption cycles, 279–84 component-specific efficiency and effectiveness metrics, 285–90 cooling systems and their applications, 267–9 future trends, 297–9 open sorption cycles, 269–79 small-scale trigeneration, 263–7 steam ejector cycle, 284–5 system-wide performance and efficiency metrics, 290–6 integration into distributed energy systems, 70–86 conditions for profitable decentralised generation, 75–8 distributed energy resources, 70–3 distributed generation value, 73–5 evaluating the ‘full value’ of being network connected, 78–81 recommendations to distribution system operators and regulators, 81–6 internal combustion engine technology and application, 125–45 commercially available units, 140–5 installation and practical aspects, 138–40 operating characteristics and performance, 133–7 types, properties and design, 126–33 review of micro combined heat and power system, 510–11 review of small combined heat and power system, 511–12 Stirling engine applications, 179–205

517

applications and future trends, 203–5 definition, 180–1 development for micro CHP applications, 189–98 micro CHP design and system integration, 199–203 Stirling cycle, 183–8 suited to micro CHP, 181–3 types, 188–9 techno-economic assessment, 17–41 case study: micro CHP, 28–39 economics, 18–21 future trends, 39–41 modelling methodology, 23–8 onsite generation, 21–3 thermal-engine-based, 459–508 deployed prime movers, 460–70 economic and environmental analysis, 500–8 economical and environmental benefits estimation, 480–3 electrical demand, 490–2 heat demand modelling, 483–90 performance mapping, 492–500 product development, 470–80, 481 thermodynamics, performance analysis and computational modelling, 42–68 analysis of computational modelling, 55–60 case study: biogas-driven small CHP system in sewage works, 60–8 cogeneration thermodynamics, 44–7 computational modelling, 54–5 heat exchangers theory, 48–51 performance analysis of cogeneration cycles, 48 temperature-entropy chart, 52 types of systems, 43–4 worked sample, 51–4 types of technology and potential applications, 5–11 base technologies, 6 large-scale CHP, 7–8 micro-CHP, 10–11 small-scale CHP, 8–9 trigeneration, 9–10 see also specific type of CHP system Community Energy Programme, 455 Community Energy Storage, 321–2 community heating, 341–3 Community Power Corporation, 115 competitive locational price, 74 compressed air energy storage plants, 313, 314 system diagram, 315 compression heat pump, 412 compression ignition engines, 132–3 compression ratio, 465



4/5/11 9:44:36 AM

518

Index

compression stroke, 133 computational fluid dynamics, 160 computational modelling CHP, 54–5 analysis, 55–60 extraction ratio efficiency influence on CHP performance, 60 maximum boiler pressure influence on CHP performance, 61 process heat extraction pressure influence on CHP performance, 62 pump efficiency influence on CHP performance, 58 simulation results vs manual calculations, 56 superheat temperature influence on CHP performance, 57 system flow diagram, 63 turbine efficiency influence on CHP performance, 59 variable 1: superheat temperature, 56 variable 2: pump efficiency, 56 variable 3: turbine efficiency, 56–7 variable 4: extraction ratio, 57–8 variable 5: maximum pressure – boiler, 58–9 variable 6: heat extraction pressure – process heat, 59 condensing connections, 230 conventional central plant, 343–4 COP see Coefficient of Performance correction factor, 49 Cost Optimisation of Decentralised Energy Generation, 23–8 inputs, outputs and flow diagram for optimisation, 23 CPC see Community Power Corporation customer billing system, 358–9 Dachs, 139, 140, 143 dead volume, 185 DEC see display energy certificates decentralised/distributed generation concept, 20 characteristics, 20–1 defence plans, 72 DER see distributed energy resources desiccant dehumidification, 269–79 effectiveness, 289–90 desiccant wheel, 271, 275 configuration options, 274 DG see distributed generation Diesel dilemma, 133 diesel engines, 126, 132–3, 403, 406 direct combustion, 96 direct heating, 341–3 direct hot air microturbine, 452 Directive on the Promotion of Cogeneration base on Useful Heat Demand, 453

Disenco kinematic Stirling engine, 194–8 Sigma 3 kWe micro-CHP unit, 197 displacer, 181, 184, 189, 469 display energy certificates, 366 distributed energy resources, 70–3 initial developments in power systems, 70–2 supply reliability, 72–3 distributed energy systems conditions for profitable decentralised generation, 75–8 distributed energy resources, 70–3 initial developments in power systems, 70–2 supply reliability, 72–3 distributed generation value, 73–5 market regulation, 75 technical aspects, 73–4 value for the system, 74 evaluating the ‘full value’ of being network connected, 78–81 generation costs evaluated for islanded sites, 80 evaluated for small customer islanded sites, 81 vs full load working hours, 78 recommendations to distribution system operators and regulators, 81–6 new designs for distribution networks, 82–5 new regulatory frameworks, 85–6 small and micro combined heat and power systems integration, 70–86 distributed generation, 71 value, 73–5 distribution system operators, 73 district heating, 512 Aars, Denmark case study, 360–2 Energy from Waste plant in Aars, 361 transmission pipe between Aars and Hornum, 362 combined heat and power systems, 347–63 Lerwick, Shetland case study, 359–60 preconditions, 348–9 control system and consumer installations, 353–9 boiler station with a CHP unit as the base unit, 354 boiler station with a heat storage tank, 354 customer billing system, 358–9 heat storage in Aars, 357 heat storage tank, 356–7 pressurising and static pressure, 353–6 standard consumer installation, 355 water quality in the network, 357 flow temperature, 358 hot tap water, 358 space heating, 358



4/5/11 9:44:36 AM

Index future trends, 363 balancing of the electric grid, 363 conversion from gas to district heating, 363 pipe dimensioning, 363 temperature optimisation, 363 heat sources, 349–51 biogas, 350 biomass, 350 fossil fuel, 350–1 size considerations, 349–50 waste to energy, 350 pipework installation issues and design considerations, 351–3 consumer education, 352–3 pipe size considerations, 352 DSO see distribution system operators E-ON, 475 economics techno-economic assessment, 18–21 onsite generation, 21–3 UK electricity and gas price plotted vs CHP spark spread, 19 ECOWILL micro-CHP unit, 473 ECU see electronic control unit Efficient Home EnergyS1, 475–6 EFMT see externally-fired microturbines EFW see Energy from Waste plant electric efficiency, 155 electrical vehicles, 318 electricity generation, 327 electricity grid connection, 13–15 electricity-led operation, 139 electrolysers, 309 electronic control unit, 136 Emissions Trading Schemes, 429 ENE-FARM, 251, 254 energy crops, 89 energy efficiency improvement, 11–12 Energy from Waste plant, 360 energy management, 307–8 energy performance certificates, 366 Energy Performance of Buildings Directive, 365–6 energy service company, 25 central performance metric, 25–6 energy storage combined heat and power systems applications, 315–17 costs of storage, 317 domestic scale, 316 economic scale, 316–17 establishment scale, 315–16 electrical energy storage application, 309–15 50 kW demonstration flywheel, 314 Beacon’s 20 MW flywheel under construction, 313

519

CAES Plant, 314 CAES system diagram, 315 mechanical systems, 312–15 technologies for integration with CHP systems, 312 uninterruptible power supply, 309–12 electrical vehicles, 318 vanadium battery, 319 future trends, 321–2 community energy storage, 321 small and micro CHP systems, 307–22 energy management applications, 307–8 energy storage, 307–21 grid services applications and relationship, 317–18 islanding capability applications, 308 large-scale and small-scale storage – conceptual planning, 318 power trading, 308 thermal storage development and application, 318–21 parabolic trough collectors and experimental solid media storage unit, 320 types of systems, 308–9, 310–11 definition and scope, 308 energy storage devices development status, 310–11 Energy White Paper, 427 engine efficiency, 134 engine knock, 130 EPBD see Energy Performance of Buildings Directive EPC, 366 energy performance certificates ESCO see energy service company ETS see Emissions Trading Schemes EU -DEEP project, 79, 84 external combustion engines, 180, 326, 329–30 externally-fired microturbines, 174–5 flow diagram, 174 extraction ratio, 57–8 influence on CHP performance, 60 Faber, O., 4 FCP see fuel chargeable to power fit-and-forget principle, 83 fixed carbon, 92 flameless oxidation, 198 FLOX see flameless oxidation flywheels, 309, 312–13, 314 food and beverage processing, 395 energy requirements, 396–7 agricultural crops processing, 397 meat processing, 397 sugar production, 396 established CHP technologies, 404–6 gas turbine–based CHP, 405 Rankine cycle technologies, 404–5



4/5/11 9:44:37 AM

520

Index

reciprocating engines, 406 food total sites heat and power integration, 397–400, 401 basic heat integration, 398–9 heat recovery targeting, 399 locally integrated energy sector CHP, 401 total site energy integration, 399–400, 401 total site profiles and composite curves, 400 future trends, 419–21 decentralisation, 420 further integration of renewables and maximum waste utilisation, 421 locally integrated energy sectors, 421 strategic issues, 420–1 technology development trends, 420 high-efficiency technologies in theoretical and demonstration stages, 406–11 fuel cell combined cycles, 409–11 fuel cell efficiency variation with operating temperature, 407 molten-carbonate fuel cells, 407–9 overall efficiencies of combined SOFC and steam system arrangement, 411 simple MCFC process flow diagram, 408 potential applications, 414–19 locally integrated energy sectors, 414–19 MCFC in a Japanese brewery, 414 renewables and waste integration with food industry energy demands, 411–14 biomass, 412–13 heat pumps, 412 using solar energy, 413–14 small and micro CHP systems applications, 395–421 suitable types of small and micro CHP systems, 400, 402–4 annual microCHP CO2 savings, 402 CHP using microturbines, 403 external combustion–Stirling engines, 403–4 fuel cells, 404 internal combustion–reciprocating engines, 402–3 fossil fuels, 91, 350–1 free-piston Stirling engine, 470 Freewatt, 473 fuel cell combined cycles, 409–11 fuel cell systems, 239–46 auxiliary burner, 244 commercial development and future trends, 253–6 current and future costs, 254–6 expectations and targets given by manufacturers and government bodies, 256 known sale prices, 255

major manufacturers, products and demonstrations, 253–4 control system, 245 dynamic operation effects, 247–51 on/off cycling and start-up, 250–1 part load performance, 247, 249–50 utilisation of generated energy, 251 whole system electrical and thermal efficiency, 249 fuel cell stack, 239–40 stationary fuel cell CHP system, 239 fuel cells, 234–8 fundamentals of operation, 234–6 materials of PEFCs and SOFCs, 237–8 operating characteristics, 238 operating range, 235 operation, 234 types of stack, 237 fuel processor, 240–2 fuel processing, 241 heat management, 243 heat storage, 243–4 installed system, 245–6 inverter and power electronics, 244–5 operating conditions and performance, 246–53 conversion efficiency, 246–7 demonstrated stack and system lifetimes, 252 overall efficiency, 248 reliability, availability and lifetime, 251–3 thermal and electrical efficiency, 246 reactant delivery systems, 242–3 small and micro combined heat and power applications, 233–56 water management, 243 fuel cells, 9, 175–6, 233, 234–8, 309, 326, 331, 404, 406–7, 510–11 fuel chargeable to power, 293–4 fuel processor, 240–2 fuel utilisation efficiency, 293 fuel utilisation factor, 292 gas boilers, 201, 204 gas engines, 403 gas turbine/generator, 512 gas turbines, 7–8, 149, 372–3, 405 gasification product, 413 gasification system, 412 GCV see gross calorific value Genlec Energetix Ltd, 471 geothermal heat, 213, 215 global warming potential, 207, 220 Grenoble synchronous machine, 80 Grenoble UPS, 80 gross calorific value, 93 GWP see global warming potential



4/5/11 9:44:37 AM

Index HACD see heat-activated cooling device HACT see heat-activated cooling technologies harmonic distortion, 15 health care buildings, 382–4 heat, 42 heat-activated cooling device, 266 heat-activated cooling technologies closed sorption cycles, 279–84 absorption heat pump cycle, 281 absorption heat pumps, 280–2 adsorption heat pump schematic, 283 adsorption heat pumps, 282–4 Dühring diagram for water on silica gel 3A, 283 component-specific efficiency and effectiveness metrics, 285–90 desiccant dehumidification effectiveness, 289–90 thermal coefficient of performance and Carnot COP, 286–9 thermal COP vs regeneration temperature for various HACT, 287 open sorption cycles, 269–79 airside psychrometric state points for basic desiccant wheel, 271 airside psychrometric state points for dehumidification processes, 270 desiccant wheel schematic, 271 enhanced desiccant wheel, 275 equilibrium isotherm for aqueous LiCl, 278 liquid desiccant dehumidification system, 278 liquid desiccant processes, 277–8 qualitative equilibrium isotherms, 272 representative average air side state points for enhanced desiccant wheel, 275 solid desiccant cycles, 271–6 system integration options, 279 small and micro combined heat and power systems, 262–306 advantages and limitations, 296–7 cooling systems and their applications, 267–9 future trends, 297–9 sorption processes, 269 small-scale trigeneration, 263–7 cooling technologies and applications, 265–7 energy flow schematic of a generic CCHP (trigeneration) system, 267 generic CHP (cogeneration) system, 266 heat recovery circuitry options and trade-offs, 266 matrix connecting cooling cycles with applications, 268 prime movers, 264–5

521

small-scale CHP prime movers, 265 steam ejector cycle, 284–5 ejector cycle schematic, 285 ejector with fluid velocity profiles, 285 system-wide performance and efficiency metrics, 290–6 comparative performance relative to baseline systems, 295–6 energy content of fuel, 291 fuel utilisation rate and fuel-chargeable to power efficiency, 294 system-wide metrics, 292–4 zero-order model baseline non-CHP system with VCC cooling device and fuel-fired water heater, 295 CCHP system with absorption chiller, 296 CCHP system with desiccant wheel and VCC, 295 heat engine types, 370–4 gas turbines, 372–3 micro-gas turbines, 373–4 reciprocating internal combustion, 370–2 heat exchanger network, 398 heat exchangers, 163–4 heat exchangers theory, 48–51 cross-flow heat exchanger and typical temperature profile, 49 logarithmic mean temperature difference, 49 modified logarithmic mean temperature difference, 49–50 number of transfer units-effectiveness method, 50–1 capacity ratio, 51 effectiveness, 50 NTU, 50 heat extraction pressure – process heat, 59 influence on CHP performance, 62 heat-led mode, 139 heat-led operation, 139 heat management, 243 heat pumps, 412 heat recovery pinch, 398 heat sources, 350–1 heat storage, 243–4 heat storage tank, 356–7 heat-to-power ratio, 28, 236, 496 HEN see heat exchanger network HFE see hydrofluoroethers high heating values, 93 higher education institutions, 378–82 homes market, 332–6 micro combined heat and power systems, 332–6 objections, 334, 336 scope, 334



4/5/11 9:44:37 AM

522

Index

Honda CB1000R, 129 Honda Ecowill/Freewatt, 145 hospitals, 383–4 hot tap water, 358 Hot 2XP, 484–5 HPR see heat-to-power ratio HRe boilers, 479–80 hydrofluoroethers, 112 hypermarkets, 385–6 IAPWS-IF97 see IAPWS Industrial Formulation 1997 for the Thermodynamic Properties of Water and Steam IAPWS Industrial Formulation 1997 for the Thermodynamic Properties of Water and Steam, 55 ICE see internal combustion engines IGCC see integrated gasification combined cycle indicated power of machine, 465 industrial cogeneration, 44 Infinia linear free piston Stirling engine, 194, 196 Ariston 1 kWe micro-CHP unit, 196 integrated gasification combined cycle, 115 internal combustion engines, 28, 39, 181, 326, 330–1, 463–4 commercially available units, 140–5 Honda Ecowill/Freewatt, 145 installation and practical aspects, 138–40 electrical connection, 138 maintenance, reliability and availability, 140 operational control, 139 micro combined heat and power, 473–4 operating characteristics and performance, 133–7 common internal combustion engine based CHP system configuration, 135 energy balance, efficiency and heat recovery, 134–6 energy balance in internal combustion engine based CHP system, 136 operational optimisation and load control, 136–7 performance map for a spark ignition engine, 137 PowerPlus Technologies ecopower, 143–4 CHP unit performance data, 144 ecopower micro-CHP unit design and operational data, 143 SenerTec Dachs, 140–3 micro-CHP technical data, 142 micro-CHP unit, 141 specific aspects, 130–3 compression ignition engines, 132–3 spark ignition engines, 130–2

technology and application in small and micro CHP systems, 125–45 types, properties and design, 126–33 basic design considerations, 128–30 common designs, 127 ideal Otto cycle efficiency and typical fuel efficiencies, 129 inverters, 15 isentropic efficiency, 55 islanding capability, 308 landfill gas, 89, 104, 212 large combined heat and power system, 7–8 large office buildings, 377–8 leisure and recreation buildings, 384 LFPSE see linear free piston Stirling engine LHV see low heating value LIES see locally integrated energy sector linear free piston Stirling engine, 189, 193 Lion Powerblock unit, 471 liquid desiccant processes, 277–8 liquid desiccant dehumidification system, 278 liquid desiccant solutions, 277–8 LMTD see logarithmic mean temperature difference locally integrated energy sector, 401, 414–19, 421 hospital complex process grand composite, 417 process stream data, 416 plant A process grand composite, 415 process stream data, 415 plant B process grand composite, 416 process stream data, 415 residential and office complex grand composite curve, 418 process stream data, 417 site profiles, 418 scenario 1, 419 scenario 2, 419 logarithmic mean temperature difference, 49 modified, 49–50 Low Carbon Buildings Programme, 428, 433 low heating value, 93, 155, 291 lubrication, 466 Magic Boiler Company, 190 maximum pressure – boiler, 58–9 influence on CHP performance, 61 MCFC see molten carbonate fuel cell MEC LFPSE see Microgen linear free piston Stirling engine micro combined heat and power system review, 510–11 micro combined heat and power systems, 436



4/5/11 9:44:37 AM

Index basic issues and energy requirements, 326–9 economic rationale, 326–8 electricity generation, 327 fuel availability, 328 regulatory environment, 328 technical requirements for viability, 328–9 case study, 28–39 characteristics of commercially successful micro CHP, 38–9 CO2 emissions reduction performance, 35–8 CO2 performance of two micro-CHP systems to annual thermal demand in target dwelling, 37, 38 CO2 reductions to prime mover capacity, 36 economic results variation of two key micro CHP technologies to annual electricity demand in target dwelling, 30 economic results variation of two key micro CHP technologies to annual thermal demand in target dwelling, 29 sensitivity of economic result to maximum ramp rate for 4 microCHP technologies, 34 sensitivity of economic result to minimum operating point for 4 micro-CHP technologies, 35 sensitivity of micro-CHP system value to prime mover capacity, 32 techno-economic assessment for investors and policy makers, 29–31 techno-economic assessment for technology developers, 31–5 competing technology solutions, 341–4 annual CO2 emissions for micro-CHP and CH/CHP, 342 community heating, 341–3 conventional central plant, 343–4 efficiencies of micro-CHP and conventional options, 343 other microgeneration technologies, 343 deployment modelling, 459–508 domestic applications, 331–6 complementary applications in housing, 332 domestic energy consumption by end use, 333 existing homes market, 332–6 new-build housing market, 336 UK gas consumers by consumption, 335 residential and small commercial systems, 325–45 advantages and limitations, 341–4 future trends, 344–5

523

small commercial buildings and other potential applications, 336–40 emergency service buildings, 339 hotel, 338 laundrettes, hairdressers, and similar premises, 339 multiple EC power 15 kWe ICE units, 340 offices, 339 preferred technologies, 337 residential and nursing homes, 338 restaurants and pubs, 338–9 small schools, 339 UK commercial market, 336, 338–40 types of system for residential and small commercial buildings, 329–31 external combustion engines, 329–30 fuel cells, 331 internal combustion engines, 330–1 other novel technologies, 331 micro-gas turbines, 373–4 Micro Turbine Technology, 176 Microgen linear free piston Stirling engine, 192–4, 195 Baxi Ecogen 1 kWe micro-CHP unit, 195 cross section through the upper cylinder, 193 Microgen MCHP unit, 476 microgeneration, 428 microturbine systems components types and properties, 160–6 axial turbine, 163 bearings, 165–6 centrifugal compressor, 161 combustors, 165 compressors, 160–1 heat exchangers, 163–4 radial turbine, 162 turbines, 161–3 variable frequency drive, 166 cycle performance, 152–9 compressor pressure ratio effect, 157 main input values in the simulation, 157 T-s and flow diagram of Brayton cycle and actual recuperated cycle, 154 future trends, 174–6 externally-fired microturbines, 174–5 flow diagram of externally-fired microturbines, 174 fuel cells and microturbines, 175–6 gas turbine integrated to a fuel cell, 175 gas turbine and recuperative cycle flow diagram, 148 gas turbine development, 149, 150 efficiencies, 149 power and efficiency, 150 general challenges with microturbine scale, 149–52 efficiency, 151–2



4/5/11 9:44:37 AM

524

Index

microturbine power output effect on compressor and turbine efficiency, 152 single stage compressors efficiency values, 151 speed, 150–1 volume, 150 manufacturers and applications, 172–4 Capstone, 173 Capstone microturbine, 173 Turbec, 173–4 operation, 166–72 ambient conditions effect, 168–70 ambient temperature effect on power output and electric efficiency, 169 compressor and turbine characteristics, 167 control methods, 170 electric load effect on electric efficiency and heat output, 171 emissions, 170–1 operating point determination, 166–8 other operational viewpoints, 171–2 single parameter change effect on operating point, 169 small combined heat and power applications, 147–76 microturbines, 403 modelling methodology, 23–8 central performance metric, 23–6 CHP commercial exploitation pathways, 24–5 CO2 performance, 26 inputs, outputs and flow diagram for optimisation, 23 optimisation problem, 26–8 Modular Bioenergy Company, 115 molten carbonate fuel cell, 404, 407–8, 409–11 applied to a Japanese brewery, 414 composite curves for MCFC, 410 simple MCFC process flow diagram, 408 multi-energy chiller, 10 net calorific value, 93 NETA see New Electricity Trading Arrangements new-build housing market, 336 New Electricity Trading Arrangements, 390 non-woody biomass, 90 NTU see number of transfer units number of transfer units, 50–1 ODP see ozone depletion potential open cycle, 153 optimisation, 26–8 constraints, 27 decision variables, 27 optimisation models, 22

ORC see organic Rankine cycle ORC-based biomass CHP plant, 109–12 biomass-fired micro-scale CHP system with ORC, 111 illustration, 110 ORC process efficiency, 230 organic Rankine cycle, 107, 453, 460, 512 commercial development and exploitation, 223–30 current technology provided by present day manufacturers, 223, 226–30 Gesellschaft für Motoren und Kraftanlagen mbH, Germany, 223, 226 GMK ORC plant connected to diesel engine, 226 GMK ORC power conversion module, 226 historical review of early development stages (1960–1984), 223 ORC power conversion module from Tri-O-Gen, 228 Ormat ORC plant producing electricity, 227 Ormat Technologies Inc, 223, 226–7 plants built between 1960 and 1984, 224–5 power conversion module of typical Turboden ORC plant, 229 process diagram, 229 schematic of Turboden power conversion module, 230 Tri-O-Gen B.V., Goor, The Netherlands, 228–9 Turboden S.r.l., Brescia, Italy, 229–30 conventional process generator, gearbox, recuperator and condenser, 209 working principle, 208 efficiency and typical costs for current ORC plants, 230–1 large size plants disadvantages, 219 ORC process vs water-based systems benefits, 213, 217–19 good dielectric properties, 219 low enthalpy drop in turbine, 217–19 low heat of vaporisation, 213, 217, 218 process comparison in temperature– total enthalpy diagram, 218 simplified ORC process in temperature– entropy diagram, 217 power plant (145 kW) run with exhaust gas, 211 (150 kW) run with unclean landfill gas, 212 (500 kWe) heat source are hot gasses collected with pipes, 211 process principle, 206–7, 208, 209



4/5/11 9:44:37 AM

Index process system alternatives, 221–2 small CHP applications, 206–31 typical process heat sources and operating ranges, 207–13 biogas from industrial and municipal waste streams, 212 biomass in agriculture and in forestry, 212–13, 214 electricity production and district heat from biomass, 214 gas turbines and combustion engine exhaust gases, 209, 211–12 geothermal heat, 213, 215 industrial waste heat, 207, 209, 210–11 micro-ORC in distributed energy system, 213, 216 micro-ORC plant principle for special applications, 216 ORC principle using geothermal heat, 215 present-day industrial waste heat sources, and economical feasibility, 210 working fluid selection, 219–21 dry or wet expansion, 221 environmental aspects, 220–1 pressure in condenser, 220 thermal stability, 219–20 volumetric flow, 220 working fluids properties used in present day plants, 221 organic Rankine cycle machines, 460–3 organic waste biomass, 90–1 Otto engines, 126 ozone depletion potential, 206–7, 220 PAFC see phosphoric acid fuel cell PEFC see polymer electrolyte fuel cells PEMFC see proton exchange membrane fuel cell phosphoric acid fuel cell, 404 photovoltaic, 80 PHR see power-to-heat-ratios pipework installation, 351–3 polymer electrolyte fuel cells, 28, 234 power generation, 70–1 power piston, 469, 470 power plant, 71 power stroke, 185 power-to-heat-ratios, 403 power trading, 308 PowerPlus Technologies ecopower, 143–4 CHP unit performance data, 144 ecopower micro-CHP unit design and operational data, 143 pressure-reducing valve, 47 prime movers, 264–5, 461 process heat, 46

525

proton exchange membrane fuel cell, 404 pump efficiency, 56 influence on CHP performance, 58 radial compressor, 160 radial turbines, 162 Rankine cycle, 45, 206, 455, 460 Rankine cycle machines, 460–3 Rankine cycle micro combined heat and power, 471–3 Rankine cycle technologies, 404–5 reciprocating engines, 402–3, 406 reciprocating internal combustion, 370–2 recuperator, 163–4 Remeha, 194, 202 renewable energy, 429 renewable energy certificates, 389–90 renewable energy source and combined heat and power solution, 81 Renewable Heat Incentive scheme, 392 Renewable Obligation, 429 RES -CHP see renewable energy source and combined heat and power solution Reynolds number, 152 RHI see Renewable Heat Incentive scheme rhombic drive, 469 ROC see renewable energy certificates rotary screw engine, 462–3 Rural Generation Ltd, 448–9 Sanevo, 190 Sankey diagram, 64 cogeneration scheme, 67 single generation scheme, 65 scroll engine, 461, 462 Second Law of Thermodynamics, 292 SenerTec Dachs, 140–3 micro-CHP technical data, 142 micro-CHP unit, 141 simulation models, 22 small combined heat and power system review, 511–12 small combined heat and power systems, 8–9 application in buildings, 377–86 breakdown of energy consumption in UK supermarkets, 385 cooling trigeneration system at Edinburgh University, 381 health care buildings, 382–4 higher education institutions, 378–82 hospitals, 383–4 large office buildings, 377–8 leisure and recreation buildings, 384 supermarkets, 386 supermarkets and hypermarkets, 385–6 university campuses, 379 commercial buildings and institutions, 365–92



4/5/11 9:44:37 AM

526

Index

basic issues and energy requirements, 366–8 energy use in commercial sector by building type, 367 energy use in non-domestic buildings, 366 future trends, 390–2 merits and limitations, 389–90 number and capacity of CHP installations in the building sector, 369 microturbine systems, 147–76 components types and properties, 160–6 cycle performance, 152–9 future trends, 174–6 manufacturers and applications, 172–4 operation, 166–72 organic Rankine cycle systems applications, 206–31 benefits and disadvantages vs waterbased systems, 213–19 commercial development and exploitation, 223–30 efficiency and typical costs for current ORC plants, 230–1 process principle, 206–7 process system alternatives, 221–2 typical process heat sources and operating ranges, 207–13 working fluid selection, 219–21 performance analysis and optimisation, 386–9 base electricity load supply operation mode, 387 base heat load supply operation mode, 387 cost-led operation strategy, 387–8 system performance indicators, 388–9 small-scale technology, 369–77 electrical connection, 376 energy balance, 370 gas-fired micro-gas turbine CHP system, 373 heat engine types, 370–4 heat engines types and properties, 374 heating circuit interface with building services, 375 integration into building services, 374–7 internal combustion gas engine, 372 small-scale biomass CHP, 453 small-scale biomass combustion CHP, 452 small-scale biomass gasification CHP, 452 small-scale biomass pyrolysis CHP, 452 SOFC see solid oxide fuel cells solar energy, 413 solid biomass fuels, 91–4, 95, 96–8 characterisation, 91–4, 95 average net calorific value, 94

calculation of analyses to different bases, 93–4, 95 calorific value, 93, 94 formulae for calculation of results to different bases, 95 moisture content effect on biomass fuel net calorific value, 94 proximate, ultimate analyses and gross calorific values, 95 proximate analysis, 92 ultimate analysis, 92–3 combustion, 96–8 50 kW wood pellet boiler, 97 Arimax Bio Energy boiler, 98 stages, 96 solid desiccant cycles, 271–6 basic cycle, 274 cycle enhancements, 274–6 desiccant wheel configuration options, 274 solid desiccant materials and substrates, 272–3 solid oxide fuel cells, 28, 39, 81, 175, 236, 326, 404, 409–11 flowsheet, 410 integration composite curves, 411 overall efficiencies of combined SOFC and steam system arrangement, 411 Solo engine, 190, 191 see also Cleanergy AB SOLO V161 Stirling CHP system, 480 solvent refined coal, 446 space heating, 358 spark gap, 19 spark ignition engine, 130–2, 406, 463–4 spark spread, 18–19, 326, 387 specific steam consumption, 48 squish, 133 SRC see solvent refined coal steam ejector cycle, 284–5 steam engine, 453 steam tables, 52–3 steam-turbine cogeneration plant, 47 Stirling conversion, 76 Stirling cycle, 510 Stirling cycle micro combined heat and power, 474–80, 481 Baxi Cogen MCHP unit, 478 Enatec MCHP unit, 479 free-piston Stirling engine from Microgen, 478 free-piston Stirling engine in Enatec MCHP unit, 479 V-type SOLO V-161 Stirling engine, 481 Whispergen Mk 5 MCHP unit, 474 ‘wobble-yoke’ drive mechanism in Whispergen, 475 Stirling engines, 5, 28, 403–4, 453, 464–70 alpha engine, 467



4/5/11 9:44:37 AM

Index applications and future trends, 203–5 beta-type engine, 467–9 definition, 180–1 design arrangement and pressure-volume diagrams, 465 development for micro CHP applications, 189–98 Ariston 1 kWe micro-CHP unit, 196 Baxi Ecogen 1 kWe micro-CHP unit, 195 Cleanergy AB, 198 Disenco kinematic Stirling engine, 194–8 Infinia linear free piston Stirling engine, 194, 196 Microgen linear free piston Stirling engine, 192–4, 195 Sigma 3 kWe micro-CHP unit, 197 Sunmachine, 198 WhisperGen kinematic Stirling engine, 190–2 double-acting 4-cylinder engine, 468 gamma configuration engine, 469 general scheme beta-type engine, 468 free-piston engine, 470 layouts of modern Stirling engines, 467–70 micro CHP design and system integration, 199–203 design for thermal efficiency, 199–201 interface design, 203 Sigma Stirling engine micro-CHP package, 200 system design, 201–3 schematic illustration, 180 small and micro CHP applications, 179–205 Stirling cycle, 183–8 constraints, 185 efficiency and other performance constraints, 185–8 theoretical Stirling cycle, 184 suited to micro CHP, 181–3 high efficiency, 183 long life and extended service intervals, 182 low emissions, 183 noise and vibration, 182–3 types, 188–9 free-piston Stirling engines, 189 kinematic Stirling engines, 188 V-type, single acting alpha-configuration, 467 Sunmachine, 198 Sunpower engine, 193 superheat temperature, 56 influence on CHP performance, 57 supermarkets, 385–6 surging, 168 system fault level analysis, 14–15

527

T-s chart, 52 Talbott’s Heating, 174–5 techno-economics, 22 assessment for investors and policymakers economic results variation of two key micro CHP technologies to annual electricity demand in target dwelling, 30 economic results variation of two key micro CHP technologies to annual thermal demand in target dwelling, 29 assessment for technology developers sensitivity of economic result to maximum ramp rate for 4 microCHP technologies, 34 sensitivity of economic result to minimum operating point for 4 micro-CHP technologies, 35 sensitivity of micro-CHP system value to prime mover capacity, 32 assessment of combined heat and power systems, 17–41 case study: micro CHP, 28–39 economics, 18–21 future trends, 39–41 modelling methodology, 23–8 onsite generation, 21–3 thermal coefficient of performance, 286–9 thermal-engine-based small and micro CHP systems deployed prime movers, 460–70 four-stroke spark ignition engine operational principles, 463 internal combustion engines, 463–4 Rankine and organic Rankine cycle machines, 460–3 rotary engine schematic, 462 scroll engine, 462 steam/vapour engine schematic, 461 Stirling engines, 464–70 domestic applications, 459–508 economic and environmental analysis, 500–8 economical and environmental benefits estimation, 480–3 electrical demand, 490–2 base load, 490 biased load, 490 elective load, 490 electrical appliances in profile model, 491 electrical profiles for pairing with 40 kWh heating band, 492 heat demand modelling, 483–90 cooking, 484, 489–90 daily space heating bands used for modelling, 488



4/5/11 9:44:37 AM

528

Index

daily space heating demand, 487 daily space heating requirements, 485 domestic hot water, 484, 488–9 domestic hot water thermal power requirements, 490 idealised space heating profile with TRVs, 486 occupancy pattern for modelling procedure, 484 space heating, 483, 484–8 space heating demand profile, 487 use of domestic hot water, 489 performance as response to heat demand efficiency per cycle and power level efficiencies, 496–8, 499 emissions analysis, 498, 500 maximum outputs, 494–5 modulation capabilities, 495–6 run down, 494 start-up, 493–4 performance mapping, 492–500 breakdown of Whispergen Mk 3 rundown characteristic, 495 breakdown of Whispergen Mk 3 start-up characteristic, 494 cycle efficiencies, 497 exhaust composition analysis of Whispergen Mk 3 unit, 500 maximum outputs of Whispergen Mk 3 unit, 495 modulated thermal output of Whispergen Mk 3 unit, 496 power level efficiencies, 499 product development, 470–80, 481 3 kWel MCHP appliance, 476 Cogen Micro MCHP unit, 472 components of 3 kWel MCHP appliance, 477 internal combustion engine MCHP, 473–4 Kingston 1 kWel MCHP unit, 472 Rankine cycle Lion MCHP, 471 Rankine cycle micro combined heat and power, 471–3 Stirling cycle MCHP, 474–80, 481 XRGI 15 Mini CHP system based on Toyota gas engine, 474 semi-detached heating band annual variation of Whispergen Mk 3 performance, 506 electricity profile 1 weekday, 503 electricity profile 3 weekend, 504 summary of simulation results, 507 system temperatures 1 weekday, 503 system temperatures 3 weekend, 504 system temperatures 4 weekend, 505 thermo-insulation, 465 thermochemical gasification, 98

thermodynamics cogeneration, 44–7 combined heat and power, 46–7 heat-only plant, 46 power-only plant, 45–6 ‘process heating only’ plant and its T-s cycle, 46 schematic of typical stream-turbine cogeneration plant, 47 simple ‘power-only’ plant and its T-s cycle, 45 thermostatic radiator valves, 485 topping cycle, 405 total site profiles, 399 total site targeting, 414 transesterification, 106 transmission system operators, 82 TRIAD, 74 trigeneration, 9–10, 263–7 TRV see thermostatic radiator valves TSO see transmission system operators TSP see total site profiles Turbec, 173–4 Turbec SpA, 405 turbine efficiency, 56–7 influence on CHP performance, 59 uninterruptible power supplies, 307 types, 309, 312 United Kingdom Building Regulation Part L2, 365 United Kingdom-wide Community Energy Programme, 429 university campuses, 379 UPS see uninterruptible power supplies utilisation factor, 48 vanadium battery, 318, 319 vapour compression cycle, 286 vertical integration, 72 volatile matter, 92 Volvo TAD1240, 129 VW Golf 1.6 engine, 129 waste, 350 Waste to Energy plant, 361 water management, 243 Whispergen, 474–5, 476, 492–3 WhisperGen kinematic Stirling engine, 182, 185, 186, 190–2, 194, 199, 201, 202 EU1 1 kWe micro-CHP unit, 192 WhisperGen micro-CHP unit, 336 WhisperTech engine, 189 woody biomass, 89–90 working piston, 189 XRGI 15, 473



4/5/11 9:44:37 AM

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