RP-1592
Complete Guide to Combined Heat and Power
This guide provides up-to-date application and operational information about prime
movers, heat recovery devices, and thermally activated technologies; technical and
economic guidance regarding CHP systems design, site screening, and assessment
guidance and tools; and installation, operation, and maintenance advice. As well as a
glossary of terms, the book features extensive, detailed case studies on implementations
in university, industrial, and hotel settings. Information is presented in both Inch-Pound
(I-P) and International System (SI) units.
Also included with the book is access to the newly developed ASHRAE CHP Analysis
Tool, a Microsoft® Excel® spreadsheet (in I-P units only) for use in assessing sites for
CHP applicability.
Combined Heat and Power Design Guide is an essential resource for consulting
engineers, architects, building owners, and contractors who are involved in evaluating,
selecting, designing, installing, operating, and maintaining these systems.
COMBINED HEAT AND POWER DESIGN GUIDE
Combined Heat and Power Design Guide was written by industry experts to give
system designers a current, authoritative guide on implementing combined heat and
power (CHP) systems. CHP systems provide electricity and useful thermal energy
in a single, integrated system. Heat that is normally wasted in conventional power
generation is recovered as useful energy, avoiding the losses that would otherwise be
incurred from separate generation of heat and power. Recent advances in electricityefficient, cost-effective generation technologies—in particular, advanced combustion
turbines and reciprocating engines—have allowed for new configurations of systems
that combine heat and power production, expanding opportunities for these systems
and increasing the amount of electricity they can produce. Combined Heat and Power
Design Guide provides a consistent and reliable approach to assessing any site’s
potential to economically use CHP systems.
COMBINED
HEAT AND POWER
DESIGN GUIDE
ISBN 978-1-936504-87-9
1791 Tullie Circle
Atlanta, GA 30329-2305
404-636-8400 (worldwide)
www.ashrae.org
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COMBINED
HEAT AND POWER
DESIGN GUIDE
ASHRAE_CHP Design Guide_Book.indb 1
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This publication was developed as a result of ASHRAE Research Project RP-1592
under the auspices of ASHRAE Technical Committee 1.10, Cogeneration Systems.
CONTRIBUTORS
The following individuals significantly contributed or provided material
that was substantive with respect to the development of this publication.
PROJECT TEAM
Richard Sweetser
(Principal Investigator)
Exergy Partners Corp.
Herndon, VA
www.exergypartners.com
Gearoid Foley
Integrated CHP Systems Inc.
Princeton, NJ
www.ichps.com
Dr. James Freihaut
The Pennsylvania State University
Department of Architectural
Engineering
University Park, PA
www.psu.edu
ADDITIONAL CONTRIBUTORS
Dr. Bruce Hedman
Institute for Industrial Productivity
Washington, DC
www.iipnetwork.org
PROJECT MONITORING SUBCOMMITTEE (PMS)
Lucas Hyman (PMS Chair)
Goss Engineering, Inc.
Corona, CA
www.gossengineering.com
Dragos Paraschiv
Humber College Institute of Technology
Toronto, ON
www.humber.ca
Geoffrey Bares
CB&I
Plainfield, IL
www.cbi.com
Dr. Timothy Wagner
United Technologies Research Center
East Hartford, CT
www.utrc.utc.com
Updates/errata for this publication will be posted on the
ASHRAE website at www.ashrae.org/publicationupdates.
ASHRAE_CHP Design Guide_Book.indb 2
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RP-1592
COMBINED
HEAT AND POWER
DESIGN GUIDE
Atlanta
ASHRAE_CHP Design Guide_Book.indb 3
4/20/2015 4:32:03 PM
ISBN 978-1-936504-87-9
© 2015 ASHRAE
1791 Tullie Circle, NE
Atlanta, GA 30329
www.ashrae.org
All rights reserved.
Cover design by Laura Haass
ASHRAE is a registered trademark in the U.S. Patent and Trademark Office, owned by the American Society of Heating,
Refrigerating and Air-Conditioning Engineers, Inc.
ASHRAE has compiled this publication with care, but ASHRAE has not investigated, and ASHRAE expressly disclaims any duty
to investigate, any product, service, process, procedure, design, or the like that may be described herein. The appearance of any
technical data or editorial material in this publication does not constitute endorsement, warranty, or guaranty by ASHRAE of any
product, service, process, procedure, design, or the like. ASHRAE does not warrant that the information in the publication is free of
errors, and ASHRAE does not necessarily agree with any statement or opinion in this publication. The entire risk of the use of any
information in this publication is assumed by the user.
No part of this publication may be reproduced without permission in writing from ASHRAE, except by a reviewer who may quote
brief passages or reproduce illustrations in a review with appropriate credit, nor may any part of this publication be reproduced, stored
in a retrieval system, or transmitted in any way or by any means—electronic, photocopying, recording, or other—without permission
in writing from ASHRAE. Requests for permission should be submitted at www.ashrae.org/permissions.
Library of Congress Cataloging-in-Publication Data
Combined heat and power design guide.
pages cm
Includes bibliographical references.
Summary: “Current, authoritative guide on implementing combined heat and power (CHP) systems that provide electricity and useful
thermal energy in a single, integrated system. Covers available technologies, site assessment, system design, installation, operation, and
maintenance, with detailed case studies and a glossary. In dual units, Inch-Pound (I-P) and International System (SI)”-- Provided by publisher.
ISBN 978-1-936504-87-9 (softcover)
1. Cogeneration of electric power and heat. I. American Society of Heating, Refrigerating and Air-Conditioning Engineers.
TK1041.C6425 2014
697--dc23
2014047007
ASHRAE Staff
Special Publications
Mark S. Owen, Editor/Group Manager of Handbook and Special Publications
Cindy Sheffield Michaels, Managing Editor
James Madison Walker, Managing Editor (Standards)
Sarah Boyle, Assistant Editor
Lauren Ramsdell, Editorial Assistant
Michshell Phillips, Editorial Coordinator
Publishing Services
David Soltis, Group Manager of Publishing Services and Electronic Communications
Jayne Jackson, Publication Traffic Administrator
Tracy Becker, Graphic Applications Specialist
Publisher
ASHRAE_CHP Design Guide_Book.indb 4
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TABLE OF CONTENTS
CHAPTER 1 – CHP FUNDAMENTALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.3 History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1.4 CHP Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1.5 CHP Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
1.6 CHP Design Basics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
1.7 Energy Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
CHAPTER 2 – APPLICATION LOAD ASSESSMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
2.1 Load Types and Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
2.2 Efficiency versus Load Factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
2.3 Base, Average and Peak Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
2.4 Thermal/Electric Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
2.5 Load Electric and Thermal Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
2.6 Prime Mover Electric and Thermal Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
2.7 Load Consolidation & Thermal Storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
2.8 Load Measurement and Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
2.9 Prime Mover Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
2.10 Typical Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
CHAPTER 3 – CHP SYSTEM DESIGN CONSIDERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
3.1 Electric Load Profiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
3.2 Thermal Load Profiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
3.3 CHP System Configuration Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
CHAPTER 4 – CHP APPLICATION ASSESSMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
4.1 Types and Scope of CHP Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
4.2 Tools and Software for Feasibility Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
CHAPTER 5 – CHP ECONOMIC ANALYSIS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
5.1 Understanding CHP Output Value & Load Factor Impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
5.2 Utility Rates and Tariffs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
5.3 Energy Supply Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
5.4 Operating and Maintenance Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
5.5 Other Costs and Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
5.6 Capital Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
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CHAPTER 6 – POWER GENERATION EQUIPMENT AND SYSTEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99
6.1 Prime Movers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99
6.2 Internal-Combustion Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
6.3 Combustion Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
6.4 Microturbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124
6.5 Fuel Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
6.6 Heat-to-Power Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134
6.7 Other Heat-to-Power Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144
6.8 Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148
CHAPTER 7 – HEAT RECOVERY AND THERMALLY ACTIVATED TECHNOLOGIES . . . . . . . . . . . . . . . 157
7.1 Heat Recovery Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157
7.2 Reciprocating-Engine Heat Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158
7.3 Combustion Turbine Heat Recovery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163
7.4 Microturbine Heat Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170
7.5 Fuel Cell Heat Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171
7.6 Thermally Activated Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174
7.7 Integration with Building Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185
CHAPTER 8 – CHP REGULATORY AND POLICY ISSUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189
8.1 Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189
8.2 U.S. Federal CHP Energy Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192
8.3 Federal CHP Tax Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193
8.4 State CHP Energy Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195
8.5 Grant Assistance Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196
8.6 M&V Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197
CHAPTER 9 – CARBON REDUCTION, ENVIRONMENTAL BENEFITS, AND EMISSION CONTROLS . . 199
9.1 CHP Fuel Use and CO2 Emissions Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200
9.2 Environmental Emissions from CHP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 210
9.3 Environmental Benefits of CHP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212
9.4 Emission Control Technologies for CHP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215
CHAPTER 10 – CONSTRUCTION CONTRACTING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227
10.1 Traditional Contracting: Design/Bid/Build . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227
10.2 Construction Management Contracting: Design/Bid/Build . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228
10.3 Engineering/Procurement/Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229
10.4 Permitting Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 233
10.5 Project Development Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238
10.6 Project Schedule and Implementation
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 241
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CHAPTER 11 – CASE STUDIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 245
11.1 University Campus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 245
11.2 Pharmaceutical Research/Manufacturing Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 265
11.3 Luxury Full-Service Hotel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 274
CHAPTER 12 – CHP ANALYSIS TOOL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295
12.1 Site Data Input Worksheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295
12.2 CHP System Input Worksheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302
12.3 Print Page Worksheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311
APPENDIX A – GLOSSARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317
APPENDIX B – EXERGY ANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323
B.1 The Meaning of the Second Law: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323
B.2 Definitions and Concepts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 324
B.3 Exergy Analysis Examples. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 335
B.4 Fuel Gas Compressor Load Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 342
SELECTED BIBLIOGRAPHY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 343
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FIGURES
Figure 1-1. Installed and Operating CHP Systems in the United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4
Figure 1-2. Henry Hub Spot Prices for Natural Gas 1996–2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5
Figure 1-3. Capacity (MW) of CHP by Fuel Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8
Figure 1-4. Base Case Estimate: Cost of Power Interruptions by Region/Class . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Figure 1-5. Emissions from CHP Plant versus the National Grid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Figure 1-6. Energy Savings of Typical Packaged CHP Compared to Conventional Sources of Heat and Power Generation. . . . . . . . 12
Figure 1-7. Conventional Boiler for Example 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Figure 1-8. Power-Only Generator for Example 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Figure 1-9. Separate Power and Heating Energy Boundary Diagram for Example 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Figure 1-10. Performance Parameters for Combined System for Example 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Figure 1-11. CHP Power and Heating Energy Boundary Diagram for Example 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Figure 1-12. Performance Parameters for Example 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Figure 1-13. CHP Power and Direct Heating Energy Boundary Diagram for Example 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Figure 1-14. Performance Parameters for Example 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Figure 1-15. CHP Power and HRSG Heating Without Duct Burner Energy Boundary Diagram for Example 4 . . . . . . . . . . . . . . . . . 24
Figure 1-16. Cofiring Performance Parameters for Example 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Figure 1-17. CHP Power and HRSG Heating with Duct Burner Energy Boundary Diagram for Example 5 . . . . . . . . . . . . . . . . . . . . 25
Figure 1-18. Electric Effectiveness ηE versus Overall Efficiency ηO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Figure 2-1. Monthly Steam Demand Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Figure 2-2. Monthly Chilled-Water Demand Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Figure 2-3. Engine Jacket Temperature Balance 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Figure 2-4. Engine Jacket Temperature Balance 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Figure 2-5. Engine Jacket Temperature Balance 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
Figure 2-6. Mall Summer Day Electric Demand Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Figure 2-7. August Chilling Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Figure 3-1. Annual Electric Load Profile for Example Production Facility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Figure 3-2. Two-Week Electric Demand Profile for Example Production Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Figure 3-4. Summer Workday Electric Demand Profile for Example Production Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
Figure 3-3. Winter Workday Electric Demand Profile for Example Production Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
Figure 3-5. Daily Electric Demand Profile for Example Production Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Figure 3-6. Daily Electric Demand Profile for Example Production Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
Figure 3-7. Electric Load Factor Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Figure 3-8. Monthly Thermal Use Profile. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
Figure 6-1. Otto Cycle P-V and T-S Diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
Figure 6-2. Typical High-Speed Engine Generator at 1800 rpm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
Figure 6-3. Typical 75 kW Autoderivative Engine Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
Figure 6-4. 18.8 MW Lean-Burn Natural Gas Engine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
Figure 6-5. Typical Efficiency (HHV) of Stoichiometric Spark Ignition Engine Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104
Figure 6-6. Heat Rate (HHV) of Stoichiometric Spark Ignition Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105
Figure 6-7. Part-Load Heat Rate (HHV) of 1430, 425, and 85 kW Gas Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106
Figure 6-8. 4600 kW ISO-Rated Recuperated Combustion Turbine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110
Figure 6-9. 7.9 MW Simple-Cycle Combustion Turbine/Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111
Figure 6-10. Pressure-Volume and Temperature-Entropy Diagrams for Brayton Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112
Figure 6-11. Simple-Cycle, Single-Shaft Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113
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Figure 6-12. Simple-Cycle, Dual-Shaft Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113
Figure 6-13. Effect of Ambient Temperature on CT Output . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115
Figure 6-14. Effect of Ambient Temperature on CT Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
Figure 6-15. Turbine Engine Performance Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117
Figure 6-16. Combustion Turbine Regenerative Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118
Figure 6-17. Mass Flow, Exhaust Temperature, and Power Output as Function of Capacity and Ambient Temperature . . . . . . . . . . 120
Figure 6-18. 250 kW Packaged CHP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125
Figure 6-19. Five Modularized 200 kW Microturbine CHP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126
Figure 6-20. Single-Shaft Microturbine with Heat Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
Figure 6-21. Microturbine Efficiency Curve with Respect to ISO Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128
Figure 6-22. Single-Shaft Microturbine Part Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129
Figure 6-23. PAFC Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
Figure 6-24. SOFC Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
Figure 6-25. MCFC Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133
Figure 6-26. PEMFC Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133
Figure 6-27. Simple Condensing Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134
Figure 6-28. Basic Types of Axial Flow Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136
Figure 6-29. Noncondensing (Back-Pressure) Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137
Figure 6-30. Effect of Exhaust Pressure on Noncondensing Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140
Figure 6-31. Efficiency of Typical Multistage Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141
Figure 6-32. Combined-Cycle System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142
Figure 6-33. Ideal ORC Temperature-Entropy Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145
Figure 6-34. Schematic of 5.5 MW Exhaust Gas ORC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146
Figure 6-35. Basic Configuration of Ammonia/Water Kalina Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147
Figure 6-36. Cutaway of Free-Piston Stirling Engine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148
Figure 6-37. Pure Resistive Electrical System: Voltage, Current. and Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
Figure 6-38a. Current-Voltage Phase Relationship (Out of Phase) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150
Figure 6-38b. Simple Inductive System with Lag of 30° . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150
Figure 6-39. Real/Reactive/Apparent Electric Power Vectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151
Figure 6-40. Harmonic Distortion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
Figure 6-41. Transient Distortion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
Figure 7-1. Closed-Loop Heat Recovery System Recovering Jacket, Oil, and Exhaust Heat Supplying Two Thermal Loads . . . . . . . 159
Figure 7-2. Closed-Loop Heat Recovery System Recovering Jacket and Exhaust Heat Supplying One Thermal Load . . . . . . . . . . . 159
Figure 7-3. Effect of Lowering Exhaust Temperature below 300°F (149°C) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162
Figure 7-4 Natural Gas Duct Burner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165
Figure 7-5. Impact of Exhaust Temperature on Furnace Fuel Savings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166
Figure 7-6. Combustion Turbine CHP Plant with Duct-Fired HRSG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167
Figure 7-7. Typical HRSG Temperature Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168
Figure 7-8. Hot-Water Heat Recovery with 250 kW Microturbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 172
Figure 7-9. Single-Stage LiBr/Water Absorption Refrigeration Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174
Figure 7-10. Typical Single-Stage LiBr/Water Absorption Chiller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175
Figure 7-11. Typical Single-Stage LiBr/Water Absorption Chiller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176
(Figure 2, Chapter 18, 2014 ASHRAE Handbook—Refrigeration) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176
Figure 7-12. Two-Stage Water/LiBr Absorption Refrigeration Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 177
Figure 7-13. Absorption Chiller Capacity versus Thermal Supply Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180
Figure 7-14. Water/Silica Gel Dual-Bed Adsorption Refrigeration Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181
Figure 7-15. Water/Silica Gel Dual-Bed Adsorption Chiller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182
Figure 7-16. Steam-Turbine-Driven Chiller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183
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Figure 7-17. Steam-Turbine-Driven Chiller Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185
Figure 9-1. eGRID Subregional Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203
Figure 9-2. Load Duration Curve. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204
Figure 9-3. Basic Dispatch Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 205
Figure 9-4. Dispatch Effect of Base-Load CHP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206
Figure 9-5. Results Screen from EPA CHP Emissions Calculator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207
Figure 9-6. Logic Diagram from Clean Air Cool Planet Campus Carbon Calculator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 209
Figure 9-7 Allocation of GHG Emissions from CHP Plant Data Output Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 210
Figure 9-8. EPA Model Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214
Figure 9-9. NOx, SO2, and CO2 Emissions from Grid and CHP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216
Figure 9-10. Percent of Emissions Reduction Using Case Study CHP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217
Figure 9-11. Annual Percentage Emissions and Fuel Reduction, NERC WECC region and Associated eGRID Subregions . . . . . . . 218
Figure 10-1. Typical Design/Bid/Build Project Structure (Single Prime Contractor) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228
Figure 10-2. Typical Design/Bid/Build Project Structure (Multiple Prime Contractors) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 229
Figure 10-3. Construction Manager Including Construction (Left) and Agent (Right) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 230
Figure 10-4. Engineering/Procurement/Construction (EPC) Contract Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231
Figure 10-5. Engineering/Procurement/Construction (EPC) versus Design/Bid Schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232
Figure 11-1. Campus Buildings Central Utility Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246
Figure 11-2. Actual Bundled Electric Prices $/kWh . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 247
Figure 11-3. Actual Bundled Natural Gas Prices $/therm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 248
Figure 11-4. ASHRAE CHP Analysis Tool Site Data Input Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249
Figure 11-5. Campus Estimated Future Electric Load Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250
Figure 11-6. Estimated Existing Peak-Day Heating/Domestic Water Load Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 251
Figure 11-7. CES Estimated Future Peak Heating Water Load Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 252
Figure 11-8. CES Estimated Existing Peak-Day Chilled Water Load Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 253
Figure 11-9. CES Estimated Future Peak Heating Water Load Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254
Figure 11-10. ASHRAE CHP Analysis Tool Addressable & Nonaddressable Loads (million Btu/h per month) . . . . . . . . . . . . . . . . . 256
Figure 11-11. CHP System Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 260
Figure 11-12. ASHRAE CHP Analysis Tool Site Data Input Screen for the CHP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 261
Figure 11-13. 16-Cylinder, 1500 rpm Natural Gas Compressor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262
Figure 11-14. Exhaust Heat Recovery Heat Exchanger (left), Exhaust SCR (right) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262
Figure 11-15. ASHRAE CHP Analysis Tool Average Electric and Thermal Demand versus CHP System Capacity. . . . . . . . . . . . . . 263
Figure 11-16. ASHRAE CHP Analysis Tool Average Electric and Thermal Demand versus CHP System Load Factor . . . . . . . . . . . 263
Figure 11-17. Emissions Results from EPA’s CHP Emissions Calculator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 264
Figure 11-18. ASHRAE CHP Analysis Tool CHP System Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 265
Figure 11-19. ASHRAE CHP Analysis Tool Capital Cost Estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 265
Figure 11-20. ASHRAE CHP Analysis Tool Economic Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 266
Figure 11-21. ASHRAE CHP Analysis Tool Payback and Utility Cost Sensitivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 266
Figure 11-22. Aerial View of the Pharmaceutical Research/Manufacturing Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 268
Figure 11-23. Breakout of Addressable Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 269
Figure 11-24. CHP System Input Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 269
Figure 11-25. Low-NOx Combustor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 270
Figure 11-26. ASHRAE CHP Analysis Tool Load Demand and CHP Load Factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271
Figure 11-27. Combustion Turbine Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 272
Figure 11-28. ASHRAE CHP Analysis Tool System Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273
Figure 11-29. Modeled CHP System Budget Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273
Figure 11-30. ASHRAE CHP Analysis Tool Economic Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273
Figure 11-31. Four Seasons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275
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Figure 11-32. 2008 Monthly Electricity Usage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276
Figure 11-33. 2008 Average Hourly Electricity Usage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276
Figure 11-34. 2008 Average Hourly Electricity Usage with Microturbine Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278
Figure 11-35. EPA Full Service Hotel Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278
Figure 11-36. 2008 Thermal Energy Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279
Figure 11-37. EPA Full-Service Hotel Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280
Figure 11-38. 2008 Thermal Usage by End Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 281
Figure 11-39. 2008 Average Hourly Thermal Usage by End Use with CHP Recovered Heat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 282
Figure 11-40. 2008 Minimum Hourly Thermal Usage by End Use with CHP Recovered Heat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 283
Figure 11-41. Three Microturbines with Integrated Hot-Water Heat Recovery Heat Exchangers . . . . . . . . . . . . . . . . . . . . . . . . . . . 284
Figure 11-42. Hotel Thermal Loop. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288
Figure 11-43. Actual Hot-Water Usage July 13 to July 19, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 290
Figure 11-44. Actual Hot-Water Usage October 24 to October 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291
Figure 11-45. Single-Line Electrical Schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292
Figure 12-1. Site Data Input Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296
Figure 12-2. Operating Hours Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297
Figure 12-3. Addressable Thermal Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299
Figure 12-4. Annual Energy Use/Cost through June . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 300
Figure 12-5. Annual Energy Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 300
Figure 12-6. Site Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 301
Figure 12-7. Existing Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302
Figure 12-8. Energy Costs and Fuel Use Readout . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302
Figure 12-9. Monthly Addressable Loads versus Fuel Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 303
Figure 12-10. CHP System Input Worksheet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304
Figure 12-11. Nominal CHP System Perforance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304
Figure 12-12. Demand, Base Load, CHP Output, and CHP Load Factor Table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 306
Figure 12-13. Site Demand versus CHP Output . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307
Figure 12-14. Demand, Base Load, CHP Output, and CHP Load Factor. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307
Figure 12-15. CHP Overall System Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308
Figure 12-16. Economic Input Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308
Figure 12-17. Grant Calculator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309
Figure 12-18. Operating Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309
Figure 12-19. Economic Output Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311
Figure 12-20. Economic Output Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311
Figure 12-21. Addressable Thermal Loads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312
Figure 12-22. Report Cover Sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312
Figure 12-23. Site and CHP Systems Performance Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313
Figure 12-24. CHP Costs, Savings, and Simple ROI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313
Figure 12-25. Cash Flow and Utility Cost Sensitivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 314
Figure 12-26. Summary Energy Costs and Fuel Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 314
Figure 12-27. Model Input Data and Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 315
Figure B-1. Adiabatic Expansion Of A Gas Tthat Does Work On A Piston . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 326
Figure B-2. Simplified Diagram of CHP District Energy System Proposed by Edmonton Power. (Rosen et al. 2004) . . . . . . . . . . . . 336
Figure B-3. Modified Version of Production Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 337
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TABLES
Table 1-1. CHP Energy and CO2 Savings Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Table 1-2. Values of α for Conventional Thermal Generation Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Table 1-3. Summary of Results from Examples 1 to 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Table 1-4. Summary of Results Assuming 33% Efficient Combustion Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Table 1-5. Typical ψ Values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Table 1-6. Summary of Fuel Energy Savings for 25% Power Generator in Examples 1 to 5 . . . . . . . . . . . . . . . . . . 29
Table 1-7. Summary of Fuel Energy Savings for 33% Power Generator in Examples 1 to 5 (SI) . . . . . . . . . . . . . . . 29
Table 2-1. CHP Output Streams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Table 2-2. Typical Hotel Heating-Water Temperature Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Table 2-3 T/E Ratios of Common CHP Configurations at Nominal Rating Conditions. . . . . . . . . . . . . . . . . . . . . . . 40
Table 2-4. Building Load versus Heat Dump 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Table 2-5 Building Load versus Heat Dump 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
Table 5-1. Offset Value of CHP Output Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Table 5-2. Comparison of Energy Costs and Payback . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
Table 5-3. Thermal Savings versus Net Cost Savings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
Table 5-4. Comparison of Thermal Load Factor and Payback . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
Table 5-5. Non-CHP System Equipment Efficiency and Offset Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
Table 6-1. Representative Overhaul Intervals for Natural Gas Engines in Baseload Service . . . . . . . . . . . . . . . . . 107
Table 6-2. Overview of Fuel Cell Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
Table 7-1. Hot-Water Heat Recovery with 65 kW Microturbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171
Table 7-2. Hot-Water Heat Recovery with 200 kW Microturbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171
Table 7-3. Fuel Cell Characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173
Table 7-4. Typical LiBr Absorption Chiller Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179
Table 9-1. Fuel-Specific Energy and CO2 Emission Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200
Table 9-2. CHP Plant Performance Characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211
Table 9-3. Engine Performance and Emissions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212
Table 9-4. US EPA CHP Emissions Calculator Data Entry Questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213
Table 9-5. Emissions Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215
Table 9-6. Gas Engine Emissions Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219
Table 9-7. Natural Gas Combustion Turbine Emissions Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221
Table 9-8. Natural Gas Microturbine Emissions Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225
Table 9-9. Natural Gas Fuel Cell Emissions Characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226
Table 10-1. Lower Thresholds for Nonattainment Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236
Table 11-1. ASHRAE CHP Analysis Tool Operating Hours Input Screen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250
Table 11-2. ASHRAE CHP Analysis Tool Site Data Input Screen for Addressable Thermal Loads . . . . . . . . . . . . 255
Table 11-3. Actual Electric Cost (Year 2000) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 256
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Table 11-4. Projected Electric Use and Cost for CHP Plant Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 257
Table 11-5. Monthly Electric Billing Data ASHRAE CHP Analysis Tool Site Input. . . . . . . . . . . . . . . . . . . . . . . . . 257
Table 11-6. Actual Natural Gas Cost (Year 2000) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 258
Table 11-7. Projected Natural Gas Use for the CHP Plant Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 259
Table 11-8. Monthly Natural Gas Billing Data ASHRAE CHP Analysis Tool Site Input . . . . . . . . . . . . . . . . . . . . . 261
Table 11-9. 2008 Energy Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 285
Table 11-10. Initial Project Return on Investment without Initial Capital Expenditure . . . . . . . . . . . . . . . . . . . . . 286
Table 11-11. Initial Project Return on Investment without Initial Capital Expenditure . . . . . . . . . . . . . . . . . . . . . 287
Table 11-12. Annual Site Energy Used by the Hotel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293
Table 11-13. Site-to-Source Energy Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293
Table 11-14. CHP Source Energy Savings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 294
Table 11-15. CHP Energy Cost Savings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 294
Table B-1. Overall and Subsystem Efficiencies for CHP-based District Energy System . . . . . . . . . . . . . . . . . . . . . 338
xiv
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ACKNOWLEDGEMENTS
The authors would like to thank the U.S. Department of Energy’s Advanced
Manufacturing Office Industrial Distributed Energy Program and the U.S. Environmental
Protection Administration CHP Partnership for providing key material and review of this
design guide. Additional thanks to the companies who supported the case studies
developed in Chapter 12 of this guide.
This publication is accompanied by the ASHRAE CHP Analysis Tool, which can be
found at www.ashrae.org/CHPDG. These files take a unique approach to solving the
issue of obsolescence of equipment databases by allowing the user to input the parameters
for the CHP system characteristics independently of the technology selection and
providing reliable, transparent cost savings results from the application of CHP. If the
files or information at the link are not accessible, please contact the publisher.
xv
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CHAPTER 1
CHP FUNDAMENTALS
1.1 INTRODUCTION
Historically, combined heat and power (CHP) design guides have focused on
design and development features of major system components, including reciprocating
engine internal structural and wearing surface design, combustion turbine aerodynamics,
microturbine recuperator flexural modulus, and heat exchanger design fouling factors.
Although these elements are critical to develop high-performing and reliable
components, they are not of particular interest to an engineering practitioner seeking to
understand and apply a CHP system to a specific application. This design guide provides
application and operational information about prime movers, heat recovery devices,
thermally activated technologies; technical and economic guidance regarding CHP
systems design, site screening and assessment guidance and tools; and installation,
operation, and maintenance advice.
It is the authors’ intention to furnish a design guide that provides a consistent and
reliable approach to assessing any site’s potential to economically use commercially
available CHP systems.
This book is accompanied by a new ASHRAE CHP Analysis Tool and a chapter on
an exergy approach to CHP, which can be found at www.ashrae.org/CHPDG. These
files may be used for assessing sites for CHP applicability. If the files or information at
the link are not accessible, please contact the publisher.
1.2 OVERVIEW
Combined heat and power (CHP), also known as cogeneration, is the sequential
generation of usable heat and power (usually electricity) in a single process. The
electricity is generated at or close to the end-use, allowing the capture and use of the
resulting waste heat for site applications. CHP systems generate electricity and useful
thermal energy in a single, integrated system. CHP is not a technology, but an approach
to applying technologies. Heat that is normally wasted in conventional power generation
is recovered as useful energy, avoiding the losses that would otherwise be incurred
from separate generation of heat and power.
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Central station generation is inherently inefficient, only converting on average about
a third of the input fuel’s potential energy into usable energy. Engineers have long
appreciated the tremendous efficiency opportunity of combining electricity generation
with thermal loads in buildings and factories, capturing much of the energy that would
otherwise be wasted. When the term “CHP” was coined in the 1970s to describe this
practice, the dominant configuration of systems was a boiler that generated steam, some
of which was used to turn a steam turbine that generated electricity. Because of the cost
and complexity of these systems, they were largely confined to systems of over 50 MW,
thus precluding their installation at most manufacturing facilities. Recent advances in
electricity-efficient, cost-effective generation technologies—in particular, advanced
combustion turbines and reciprocating engines—have allowed for new configurations of
systems that combine heat and power production, expanding opportunities for these
systems and increasing the amount of electricity they can produce.
Two powerful policy drivers will likely increase demand for CHP systems and
assessments over the next decade: the increased availability of cheap natural gas
supplies from shale deposits, and increased attention by energy users on the need to
reduce operating costs.
CHP’s unique place between energy suppliers and consumers, its provision of two
types of useful energy, and its interaction with electricity networks mean that its
prospects necessarily remain tied to local regulation and the quality of public policies
that remove barriers and promote its uses.
1.3 HISTORY
Dating from the 1880s, when steam was still the primary source of motive power
in industry and electricity was just emerging as a product for both power and lighting,
industrial plants led in the application of CHP concepts. The use of such technology
became commonplace as engineers replaced steam-driven belt-and-pulley systems
with electric power and motors, moving from mechanically powered systems to
electrically powered systems. In the 1890s, before the development of the electric grid
and almost of necessity, industrial applications cogenerated. Power was used in motors
and steam for thermal purposes. There were no regulated utilities, and CHP was simply
a power technology. In the 1900s, most of the power used by industry was cogenerated.
With the evolution of the electric utility industry, purchased power costs dropped
while power reliability and quality increased. As technology developed, leading to
larger central plants and their resulting economies of scale, utilities were able to deliver
more capacity for each dollar invested. Moreover, the higher efficiencies achieved at
these plants resulted in lower fuel costs as natural gas demand decreased.
The development of the integrated grid provided several additional benefits to end
users. First, the grid resulted in increased reliability, as power was made available from
a number of sources and not just a single generating plant. Second, the average cost of
power dropped as the available capacity was operated on an economic dispatch basis.
That is, the lowest cost plant available to satisfy a requirement was loaded first, thus
lowering the average cost of power production. Third, low-cost oil and gas and increases
in coal productivity resulted in still lower generation costs.
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CHP FUNDAMENTALS
In general, industrial users found that the most effective way to satisfy power
requirements was to purchase it from the local utility. The perception that electric
power generation was a natural monopoly requiring exclusive service areas and cost
regulation also gave some end users a sense that power was being made available at the
lowest price. Additionally, the low fuel costs caused industrial energy users to ignore
conservation opportunities, typically resulting in the installation of less costly and less
efficient boilers, because the incremental costs of high-efficiency boilers were not
judged to be cost effective. Ultimately, the typical energy end user chose to purchase
power, decreasing the amount of cogenerated power.
While the overall trend in the amount of cogenerated power was downward, there
were several cases, as in the oil and gas industry, refineries, chemical plants, or the
pulp and paper industry, where CHP was both technically and economically compatible
with process requirements; industrial sites continued to cogenerate, but at a much
lower capacity. At these sites, several factors, including the availability of process
by-products as fuel, the need for large quantities of steam at different pressures and
temperatures, long operating hours, and the availability of qualified maintenance and
operating personnel, facilitated the development and operation of CHP systems. In
general, these systems took two forms: larger systems that typically sold the
cogenerated power to the local utility or smaller systems (characteristically less than
5 MW) that used the power internally, reducing power purchases. These CHP systems
were primarily based on either a backpressure or an extraction steam turbine. In
addition, many electric utilities with power plants located in urban areas developed
steam district-heating systems, with the source of the steam being large CHP systems
at these central plants.
Utility rate and franchise regulation, which began in the early twentieth century
and which became increasingly pervasive, acted to further discourage nonutility
generators, as did the public utilities themselves, which sought to deter alternative
suppliers in their own service areas. In fact, state and federal regulations sometimes
resulted in CHP system financial structures that were unique partnerships of industrial
and utility parties. With an exclusive franchise for power sales in its service area,
electric utilities were sometimes able to impose restrictions that further reduced the
cost-effectiveness of CHP. The overall impact was that the amount of CHP power
produced in the US decreased steadily through the 1970s.
There was a short revival of interest in CHP in the late 1960s and early 1970s as
the natural gas industry attempted to expand its market, particularly nonseasonal use,
by encouraging on-site generating systems. Resistance from the electric utility industry,
which was frequently evidenced as a refusal to interconnect the utility grid to sites that
operated CHP systems or, if the site was interconnected, through high-cost supplemental
and standby service, resulted in these sites operating totally independent of the electric
utility grid. Referred to as “total energy systems” (TES), they consisted of on-site
engine generator sets that served all of the site’s electrical requirements, with the end
user’s thermal requirements being satisfied with heat produced by a prime mover, a
supplemental boiler, or both. TES enjoyed some initial successes and began to enjoy
greater acceptance in the early 1970s; however, the gas shortages and price increases of
the 1970s and competitive marketing and rates from electric utilities resulted in a
failure to develop the market further.
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The history of CHP in the United States has been marked by important federal
legislation. CHP received an important policy boost with the Public Utilities Regulatory
Policy Act (PURPA) of 1978, which gave certain CHP facilities a guaranteed market
for their power. This bill helped build a robust fleet of CHP systems across the country
and marked the first time that federal legislation actively sought to encourage distributed
generation and CHP. Figure 1-1 shows the significant increase in CHP installations in
operation as a result of PURPA, beginning in the early 1980s and ending in the early/
mid 2000s.
While PURPA promoted CHP development, it also had unforeseen consequences.
PURPA was enacted at the same time that larger, more efficient, lower-cost combustion
turbines and combined cycle systems became widely available. These technologies
were capable of producing greater amounts of power in proportion to useful thermal
output compared to traditional boiler/steam turbine CHP systems. Therefore, the
power purchase provisions of PURPA, combined with the availability of these new
technologies, resulted in the development of very large merchant CHP plants designed
for high electricity production.
For the first time since the inception of the power industry, nonutility participation
was allowed in the U.S. power market, triggering the development of third-party CHP
Figure 1-1. Installed and Operating CHP Systems in the United States1
1
Source: ICF Combined Heat and Power Installation Database.
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CHP FUNDAMENTALS
developers who had greater interest in electric markets than thermal markets. As a
result, the development of large CHP facilities (greater than 100 MW) paired with
industrial facilities increased dramatically; today almost 65% of existing U.S. CHP
capacity—55,000 MW—is concentrated in plants over 100 MW in size2.
By the turn of the century, natural gas deregulation was complete, and natural gas
commodity markets were affecting the price of natural gas. Figure 1-2 shows a period
of relatively stable natural gas prices in the late 1990s, followed by several periods of
large price spikes after 2000. During 2008, natural gas spot prices traded as high as
$13.32 per million cubic feet ($0.38 per million cubic metres) and as low as $5.63 per
million cubic feet ($0.16 per million cubic metres). The large price fluctuations in 2008
increased the focus on price volatility and its impacts on natural gas market participants.
Price volatility increased the uncertainty of natural gas pricing and dramatically
impacted CHP adoption for much of the decade.
On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005) was signed into
law. Section 1253(a) of EPAct 2005 added a new section 210(m) to the Public Utility
Regulatory Policies Act of 1978 (PURPA) that provided for termination of an electric
Figure 1-2. Henry Hub3 Spot Prices for Natural Gas 1996–20084
Advancing Near-Term Low Carbon Technologies, The International CHP/DHC Collaborative,
International Energy Agency. 2009.
2
The Henry Hub is a distribution hub on the natural gas pipeline system in Erath, Louisiana,
owned by Sabine Pipe Line LLC. Because of its importance, it lends its name to the pricing
point for natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX).
3
Natural Gas Price Volatility. Randy Roesser, California Energy Commission. 2009.
4
5
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COMBINED HEAT AND POWER DESIGN GUIDE
utility’s obligation to purchase energy and capacity from qualifying CHP facilities and
qualifying small power production facilities (QFs), including CHP facilities, if the
Federal Energy Regulatory Commission finds that certain conditions are met. This act
removed federal feed-in tariffs for CHP plants and essentially put a significant drag on
the expansion of CHP systems nationwide.
Utilities interested in retaining their electric customer bases are generally not
incentivized to support greater CHP, because new CHP projects would reduce customer
demand. If they are to actively support the increased development of CHP in their
service territories, electric utilities will require some external incentive or mechanism
to recover the lost revenue associated with greater CHP deployment. Few utilities have
these incentives or mechanisms in place.
The North American shale gas revolution is entering a new phase of activity, with
gas production in the “Big 7” U.S. shale gas plays (Antrim, Barnett, Devonian,
Fayetteville, Woodford, Haynesville, and Marcellus) now estimated to be on track to
rise to between 27 and 39 Bcf/d5 (0.76 and 1.1 Bcm/d6) over the next decade. The
Marcellus field is now the world’s second largest natural gas field. Although some
uncertainty exists with respect to the actual amount of economically recoverable shale
gas reserves, the impact of shale gas production over the next decade, according to the
EIA reference case, projects the Henry Hub spot market price remaining within $1.00
per million Btu ($0.29/MW) of its current price, $4.03 (May 2013). This new level of
stability is an important factor in assessing opportunities for CHP moving forward.
1.4 CHP TRENDS
1.4.1 Policy
Energy policy today is a function of many issues, including assumptions about
energy supply and demand, corporate interest, economics, market interest or disinterest,
pollution fears, climate change, and politics. CHP is generally recognized as a positive
approach to energy policy moving forward.
At the end of the 1990s, policymakers began to explore the efficiency and emission
reduction benefits of thermally based CHP. They realized that a new generation of locally
deployed CHP systems could play a more important role in meeting future U.S. energy
needs in a less carbon-emissions-intensive manner. As a result, the federal government
and several states began to take actions to promote further deployment of CHP. CHP has
been specifically singled out for promotion by the U.S. Department of Energy (DOE)
and U.S. Environmental Protection Agency (EPA).
The DOE in 2001 established the first of eight regional Clean Energy Application
Centers to provide local technical assistance and educational support for CHP development.
In 2001, the EPA established the CHP Partnership to encourage cost-effective CHP
projects and expand CHP development in underutilized markets and applications.
Billion (109) cubic feet per day.
5
Billion (109) cubic metres per day.
6
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CHP FUNDAMENTALS
Several important federal programs have made significant contributions toward
strengthening the CHP market. Most notable are the U.S. DOE Regional Clean Energy
Application Centers and the federal CHP investment tax credit.
On August 30, 2012, a Presidential Executive Order was issued to accelerate
investment in industrial energy efficiency. This Executive Order directs the Departments
of Energy, Commerce, and Agriculture, and the Environmental Protection Agency, in
coordination with the National Economic Council, the Domestic Policy Council, the
Council on Environmental Quality, and the Office of Science and Technology Policy,
to coordinate policies to encourage investment in industrial efficiency focusing on
CHP. Specifically, these agencies are directed to, as appropriate and consistent with
applicable law,
(a) coordinate and strongly encourage efforts to achieve a national goal of
deploying 40 gigawatts of new, cost effective industrial CHP in the United
States by the end of 2020;
(b) convene stakeholders, through a series of public workshops, to develop and
encourage the use of best practice state policies and investment models that
address the multiple barriers to investment in industrial energy efficiency and
CHP; and
(c) utilize their respective relevant authorities and resources to encourage
investment in industrial energy efficiency and CHP.
Federal focus and support encompassed within this Executive Order targeting
increasing industrial CHP use will undoubtedly impact market adoption throughout the
Federal sector, and influence state policy as well as the private sector.
Individual states also began to realize that a variety of policy measures were needed
to remove the barriers to CHP development, and developed a series of policies and
incentives, including streamlining grid interconnection requirements, simplifying
environmental permitting procedures, and establishing rate-payer financed incentive
programs for CHP deployment. Moving CHP into the energy policy mainstream and
maximizing its potential benefits to society requires the continued development of
these kinds of policies at the state level.
Evidence of short-timescale climate change is molding national and international
policies to regulate greenhouse gases (GHGs) from sectors such as power generation,
transport, industrial processes, waste disposal, and remediation. Criteria air pollutants,
such as oxides of nitrogen (NOx), carbon monoxide (CO), unburned hydrocarbons
(HC), and particulate matter (PM) all have aftertreatment technologies that can reduce
them into more benign compounds. Catalysts or combustion techniques can also reduce
or eliminate GHGs, such as methane (CH4) and nitrous oxide (N2O). But, unfortunately,
no catalyst is currently available for the most common and abundant GHG: carbon
dioxide (CO2). The industrial practice of carbon sequestration and storage, except
through biomass, is neither mature nor widespread and also carries risks.
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U.S. GHG emissions associated with fossil fuel electricity generation can vary
from as low as 727 lb (330 kg) CO2eq/MWh of generated electricity to almost 2000 lb
(900 kg) of CO2eq/MWh. There is potential for significant GHG reductions with CHP,
depending on the installation location, yielding 314 lb (143 kg) of CO2eq/MWh from a
4.6 MW recuperative combustion turbine, 419 lb (191 kg) of CO2eq/MWh from a
2 MW lean-burn engine, and 649 lb (295 kg) of CO2eq/MWh from a 2 MW a simple
cycle combustion turbine and local GHG regulation policy. Future GHG regulations
could be a strong driver for increased efficiency, and technologies such as CHP will be
well positioned to meet the challenge.
1.4.2 Fuels
Historically, natural gas has proven to be the preferred fuel for CHP systems both
large and small (Figure 1-3), and this trend is expected to continue largely because of
the continuing development of shale gas in the United States.
Natural gas provides nearly one-fourth of the energy consumed in the United States
and is expected to increase in the future. About 85% of the natural gas consumed in the
United States is produced within U.S. borders; much of the rest comes from Canada,
which also has a large natural gas supply base. Domestic natural gas production is
expected to account for 80% or more of the total annual U.S. natural gas supply through
the year 2030. Gas supplies are frequently described in two different ways: proved
reserves, which are the estimated quantities of natural gas that current geologic and
engineering data demonstrate to be recoverable under existing economic and operating
conditions, and the total natural gas resource base, which is proved reserves plus
Figure 1-3. Capacity (MW) of CHP by Fuel Type7
7
Combined Heat and Power Installation Database, http://www.eea-inc.com/chpdata/
8
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CHP FUNDAMENTALS
undiscovered resources. The total U.S. natural gas resource base, including proved
reserves, is more than 1500 trillion cubic feet (Tcf) (42.5 × 1012 cubic metres), providing
a 75-year supply of natural gas at current production levels8. Natural gas pricing should
remain stable and relatively low for a significant period of time as proven reserves
increase. The important issue is the “spark spread”9 over the operating or economic life
of the CHP plant. Retiring central station power plants, tightening emissions regulations
(e.g. the Utility MACT10), grid congestion, Smart Grid and other transmission and
distribution upgrades all point to higher electricity costs. The one pressure on the natural
gas price would come from increased use of natural gas for vehicles (likely but limited
demand) and exporting liquid natural gas (LNG) from the United States.
Solid fuels, including refuse-derived fuel “waste,” also make up a significant share
of the market, although fuel- and ash-handling costs generally limit the use of solid
fuels to systems of 10 MW or more.
1.5 CHP BENEFITS
To better understand CHP from a macroeconomic perspective, it is important to
understand the benefits CHP can offer to two distinct groups: the owner of the system
systems.
1.5.1 Benefits Realized by Owners of CHP Systems
Site owners generally value operating savings and sometimes value electricity
reliability and power quality when assessing the economics of installing a CHP system.
Rarely can they value other benefits that often accrue to society. CHP owner benefits
are generally recognized as follows:
• Reduced Operating Costs: The principle owner’s benefit from a CHP system
is economic. Simply put, the total operating cost of the CHP plant, including fuel,
maintenance and cost of capital, is less than the cost of purchased fuel and power,
and these savings are significant enough to invest the capital to build the plant.
• Increased Power Reliability: Power reliability can directly impact the economic
evaluation of a CHP plant. EPRI estimated the national cost of power interruptions,
including power quality events, at $79 billion per year11 (Figure 1-4).
8
Potential Gas Agency of the Colorado School of Mines, http://potentialgas.org/about .
Spark spread is the relative difference between the price of fuel and the price of power. Spark
spread is highly dependent on the efficiency of conversion. For a CHP system, spark spread is
the difference between the cost of fuel for the CHP system to produce power and heat on site
and the offset cost of purchased grid power.
9
The emission standard for sources of air pollution requiring the maximum reduction of hazardous
emissions, taking cost and feasibility into account. Under the Clean Air Act Amendments of 1990,
the MACT must not be less than the average emission level achieved by controls on the best
performing 12% of existing sources, by category of industrial and utility sources.
10
The cost of power disturbances to industrial and digital economy companies. Report TR-1006274
(Available through EPRI). Madison, Wisconsin. Primen. 2001.
11
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Figure 1-4. Base Case Estimate: Cost of Power Interruptions by Region/Class12
• Reduced Peak Electricity Demand: CHP can permanently reduce peak
electric demand. Permanent reductions in electric demand can result in a one-time
economic benefit to a CHP project. CHP generally does not qualify for demand
response programs, unless the system is electrically oversized for the site load.
• Offset Capital Cost: CHP systems can offset capital costs that would otherwise
be needed to purchase and install certain facility components, such as boiler and
chiller systems in new construction. In addition, installing CHP systems with
backup capability can enable a local government to avoid having to purchase a
conventional backup electricity generator. Note that certain applications, such as
hospitals, cannot use natural gas in the United States as a backup fuel source.
1.5.2 CHP Societal Benefits
• Reduced Emissions: CHP systems generally result in a reduction of pollutant
emissions, including CO2, NOX, and SO2, when compared to separately generated
heat and power. The example below (Figure 1-5) shows results of a lean-burn
engine/absorption chiller CHP system applied as base load power and cooling
to a data center.
Cost of Power Interruptions to Electricity Consumers in the United States (U.S.). Kristina
Hamachi LaCommare and Joseph H. Eto. Lawrence Berkeley National Laboratory, U.S.
Department of Energy. 2006.
12
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CHP FUNDAMENTALS
Figure 1-5. Emissions from CHP Plant versus the National Grid13
• Energy Efficiency: Energy efficiency (Figure 1-6) can be both a societal and
an owner benefit. From an owners’ viewpoint, properly designed and applied
CHP systems save energy which means it should save energy cost. CHP makes
more efficient use of primary fuel for producing heat and power than separate
conventional methods, such as on-site boilers and power stations. Therefore, it
can deliver significant environmental benefits and cost savings, given the right
balance of technical and financial conditions.
• Carbon Reduction Choices: Table 1-1 compares the annual energy and CO2
savings of a 10 MW natural-gas-fired CHP system, separate heat and power with
utility-scale renewable technologies, and natural gas combined cycle (NGCC)
systems producing power only. This shows that CHP can provide overall energy
and CO2 savings on par with comparably sized solar photovoltaics (PV), wind,
and NGCC, and at a capital cost lower than solar and wind and on par with NGCC.
Applying a Fuel and CO2 Emissions Savings Calculation Protocol to a Combined Heat and
Power (CHP) Project Design. ASHRAE Winter Conference, February 2011.
13
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Figure 1-6. Energy Savings of Typical Packaged CHP Compared to Conventional Sources of
Heat and Power Generation (Shown in Units of Energy)
Table 1-1. CHP Energy and CO2 Savings Potential14
10 MW PV
10 MW
Wind
NGCC
(10 MW
Portion)
85
22
34
70
Annual electricity, MWhe
74,460
19,284
29,784
61,320
Annual useful heat, MWhTH
103,417
None
None
None
6000
(557)
1,740,000
(161 651)
76,000
(7061)
N/A
20,000,000
48,000,000
24,000,000
10,000,000
Annual energy savings versus
today’s grid, 106 Btu (MJ)
308,100
(325)
196,462
(207)
303,623
(320)
154,649
(163)
Annual CO2 savings, tons (Mg)
42,751
(38 783)
17,887
(16 227)
27,644
(25 078)
28,172
(25 557)
Annual NOx savings, tons (Mg)
59.8 (54.2)
16.2 (14.7)
24.9 (22.6)
39.3 (35.7)
10 MW
CHP
Annual capacity factor, %
Category
Footprint required, ft2 (m2)
Capital cost, $
A Clean Energy Solution Combined Heat and Power. U.S. Department of Energy and U.S.
Environmental Protection Agency. August 2012.
14
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Assumptions:
1. 10 MW Gas Turbine CHP: 28% electric efficiency, 68% total overall
efficiency, 15 ppm NOx emissions
2. Capacity factors and capital costs for PV and wind based on utility
systems in DOE’s Advanced Energy Outlook 2011
3. Capital cost and efficiency for natural gas combined-cycle (NGCC)
system based on Advanced Energy Outlook 2011 540 MW combinedcycle power plant
4. Combined cycle system proportioned to 10 MW of output, NGCC 48%
electric efficiency, NOx emissions 9 ppm
5. CHP, PV, wind, and NGCC electricity displaces National All Fossil
Average Generation resources (eGRID 2012 ): 9572 Btu/kWh, 1743 lb
CO2/MWh, 1.5708 lb NOx/MWh, 6.5% T&D losses; CHP thermal output
displaces 80% efficient on-site natural gas boiler with 0.1 lb per million
Btu NOx emissions
• Reduces Grid Congestion: Industrial sites and urban centers are often capacity
constrained. On-site CHP systems can deliver electric power, reducing peak power
requirements.
• Avoids Transmission and Distribution Costs: On-site CHP systems can
permanently avoid transmission, distribution, and central power generation
upgrades, providing saving for all ratepayers.
• Avoids New Generation Costs: Each grid kilowatt saved generally saves the
need for 1.09 kW of power to be generated factoring in line losses. Nuclear plant
relicensing and increasing coal power plant emission regulations are already
impacting America’s generating base. Factoring in economic growth, CHP can
provide a significant source of new power generation for the future.
• Increased Grid Reliability: On-site power generation has proven to provide
improved power reliability by operating when the grid is down. On-site power also
provides power quality support for the owner and neighboring sites as well. Electric
Power Research Institute (EPRI) reported the first ever power-quality cost estimate
of $26 billion per year for the U.S.15
• National Security: Resource conservation is viewed as a national security
issue. The U.S. economy depends on the expectation that energy will be plentiful,
available, and affordable. Historically, oil and gas have been used as political and
economic weapons by nations to manipulate the marketplace. CHP is among the
most efficient means of combusting a fuel to deliver energy.
• Health Benefits: Specifically reducing particulate NOX and SO2 emissions
are important environmental benefits of using CHP systems. Numerous studies
concerning these pollutants have determined these are indeed health hazards, and
they are regulated as such.
15
Estimating the cost of power quality. IEEE Spectrum. 30(6): 40-41.
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1.6 CHP DESIGN BASICS
The following CHP design basics outline provides key insights into a methodological
thought process to lead toward site analytics for successful CHP applications.
1.6.1 CHP Design Goals
The fundamental design goal for any CHP system installation is to provide the site
owner/operator with an appropriate return on their investment (ROI). Make no mistake,
the fundamental reason to install a CHP system is economic. There are influencers,
particularly for public sector sites and large multinational corporations, such as
efficiency and/or carbon goals, that extend acceptable payback periods and reduce
ROI, but economics matter.
A second and equally important design goal is to reduce risk or conversely increase
the certainty of results. This can best be accomplished by a thorough understanding of
CHP system application considerations, which is the goal of this guide.
1.6.2 General CHP System Configurations and Capabilities
CHP systems consist of three primary components: the unit in which the source
fuel is combusted, the electric generator, and the heat recovery unit. CHP systems are
differentiated by a “prime mover,” the device used to convert fuel (e.g., natural gas,
biomass, biogas, coal, waste heat, and oil) into electricity. The most common CHP
system configurations use combustion turbine, reciprocating engine, microturbine, or
steam turbine prime movers.
A CHP system with a gas turbine generates electricity by combusting a fuel (often
natural gas, oil or biogas) and using a heat recovery unit to capture the by-product heat.
Gas turbine configurations are most compatible with large industrial or commercial
CHP applications that require large quantities of heat and power, typically sized
between 4 and 50 MW in electric capacity.
A CHP system with a reciprocating engine generally recovers heat from the jacket
water cooling system and the engine exhaust, providing low pressure steam or hot
water under 250°F (121°C). Engine configurations are most compatible with industrial
or commercial CHP applications that require quantities of heat and power typically
sized between 100 kW and 5 MW in electric capacity.
Microturbine CHP systems are emerging to serve a number of applications with
unit sizes between 65 to 250 kW and modular system capacities of 1 MW.
Unlike the gas turbine configuration, which produces heat as a by-product of
electricity generation, CHP systems with steam turbines generate electricity as a
by-product of steam production. Steam turbine configurations are most compatible
with industrial facilities where solid fuels (e.g., biomass) feed the boiler.
Finally, organic Rankine cycle (ORC) systems, which use an organic working
fluid instead of water/steam, are being applied, especially where low-temperature waste
heat is available for recovery.
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1.6.3 Thermal and Electric Load Requirements
The key driver for CHP economics is operating the CHP system over long hours at
high electric and thermal load factors. Simply put, the only way to overcome the capital
cost of the CHP system is to operate the system efficiently for as long as possible each
year. This typically requires applications with a high degree of coincident electric and
thermal loads. Thermal storage can be used to balance coincident electric and thermal
loads where it is cost effective.
The most fundamental, and perhaps most difficult, element of a CHP application is
understanding a site’s thermal and electric loads. In fact, most CHP design failures
occur because the systems were incorrectly sized to serve the site’s thermal loads. The
first step in understanding electric and thermal load is to differentiate between which
loads are addressable and which are not. Multiple on-site electric meters generally
mean that only one meter set can be considered. This is generally because it is too
costly to rewire the facility to be served by a single meter, which would be necessary
for the CHP system to provide power to all the loads.
For facilities with rooftop air conditioners, space cooling and likely space heating
are not addressable thermal loads, because rooftop air conditioners (not rooftop air
handlers) use direct-expansion systems for cooling (versus water coils) and generally
use a furnace or heat pump cycle for heating. Even multiple rooftop air-handling units
with chilled- and hot-water coils are not likely candidates, because they require
extensive piping runs, which generally lead to costly retrofits. Fundamentally, highthermal-load-factor CHP systems are economical, and low-thermal-load-factor systems
are not economically viable. Generally, sizing the CHP system to the addressable
thermal load and using the electricity on-site16 is considered best practice.
A significant portion of this guide is focused on understanding addressable electric
and thermal loads.
1.6.4 Power Generation Equipment
Selecting the right prime mover is a function of the site requirements, which drive
the capacity of the CHP system to deliver thermal energy and electric power. Energy
economics (cost of fuel versus cost of electricity), N and N+1 considerations (i.e.,
providing equipment backup), equipment capital cost, installation cost, and permitting
play significant roles in prime mover selection. Reciprocating engines, combustion
turbines, microturbines, and fuel cells have all been successfully applied.
1.6.5 Electrical Distribution Systems
CHP systems can be designed to operate in parallel with the electric grid, in island
mode (separated from the electric grid), or in grid parallel with automatic transfer to
island mode when the grid fails. The simplest electric grid interconnection is parallel
operation providing no electric power to the grid, because a CHP system generally
cannot backfeed electricity to the grid unless permitted by the local utility for specific
purposes. CHP generators can provide output at 480 to 13,000 volts.
Current feed-in tariffs for most CHP applications to the electric grid are less than retail electric
prices and are often wholesale prices, making exporting electricity uneconomical. Therefore,
limiting electricity production to on-site use is current best practice.
16
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1.6.6 Heat Recovery Boilers and Thermally Activated Technologies
The simplest means of heat recovery is the direct use of prime mover exhaust for
heating or drying proposes, which often is associated with combustion-turbine- and
microturbine-based systems. Far more often, CHP system thermal loads require waste
heat be used as hot water, steam, and/or chilled water. Heat recovery steam generators
(HRSGs) and heat recovery heat exchangers are used to deliver low- or mediumtemperature steam or hot water. The advent of advanced absorption and adsorption chiller
technologies further extend CHP system capabilities (at a cost) to satisfy chilled-water
and low-temperature refrigeration loads. Thermally activated desiccant dehumidification
has also been applied using CHP waste heat streams.
1.6.7 Thermal Distribution System
CHP system designers must understand the type and quality of all addressable
thermal loads, determine the tie-in point(s), and obtain the highest degree of thermal
load information possible with a minimum of 12 months of data.
1.6.8 Regulations
Electric grid interconnection is the most common regulation connected with CHP
systems. However, CHP installations must comply with a host of local zoning,
environmental, health, and safety requirements at the site. These include rules on air
and water quality, fire prevention, fuel storage, hazardous waste disposal, worker safety,
and building construction standards. This requires interaction with various local
agencies, including fire districts, air districts, water districts, and planning commissions,
many of which may have no previous experience with a CHP project and are unfamiliar
with the technologies and systems.
1.7 ENERGY EFFICIENCY
CHP energy efficiency is an important concept to understand and involves
knowledge of the CHP system being analyzed and where the energy boundary is drawn.
The following sections present the three most common means of measuring overall
efficiency: net electric efficiency, overall system efficiency, and electric effectiveness.
1.7.1 Heating Value
Natural gas is often selected as the fuel for CHP systems, although the same
considerations discussed here apply to biofuels and other fossil fuels. There are two
common ways to define the energy content of fuel: higher heating value and lower
heating value.
Turbine, microturbine, engine, and fuel cell manufacturers typically rate their
equipment using lower heating value (LHV), which accurately measures combustion
efficiency; however, LHV neglects the energy in water vapor formed by combustion of
hydrogen in the fuel. This water vapor typically represents about 10% of the energy
content. LHVs for natural gas are typically 900 to 950 Btu/ft3 (33.5 to 35.5 MJ/m3).
Higher heating value (HHV) for a fuel includes the full energy content as defined
by bringing all products of combustion to 77°F (25°C). Natural gas typically is delivered
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CHP FUNDAMENTALS
by the local distribution company with values of 1000 to 1050 Btu/ft3 (37 to 39 MJ/m3)
on this HHV basis. Because the actual value may vary from month to month, some
gas companies convert to therms (1 therm = 100,000 Btu). These measures all
represent HHV. Consumers purchase natural gas in terms of its HHV; therefore,
performances of CHP systems as well as the electric grid for comparison are calculated
in HHV.
The net electric efficiency ηE of a generator can be defined by the first law of
thermodynamics as net electrical output WE divided by fuel consumed Qfuel in terms of
kilowatt-hours of thermal energy content:
ηE = WE/Qfuel
1-1
A CHP system, by definition, produces useful thermal energy (heat) as well as
electricity. If the first law is applied, adding the useful thermal energy QTH (converted
from megajoules to kWh,) to the net electrical output and dividing by the fuel consumed
(which is how virtually all CHP system efficiencies are reported), the resulting overall
system efficiency ηCHP does not account for the relative value of the two different
energy streams:
1-2
ηo = (WE + SQTH)/Qfuel
According to the second law of thermodynamics, the two different energy streams
have different relative values; heat and electricity are not interchangeable. The first law
describes the quantity of the two energy streams, whereas the second law describes
their quality or value (exergy). Electrical energy is generally of higher value because it
can do many types of work, and, in theory, 100% of it can be converted into thermal
energy. Thermal energy is more limited in use and is converted to work at rates usually
much lower than 100% conversion. The theoretical maximum efficiency at which
thermal energy can be converted to work is the Carnot efficiency, which is a function
of the quality, or temperature, of the thermal energy and is defined as
(Thigh – Tlow)/Thigh
1-3
1.7.2 Electric Effectiveness
The current methodology of using net electric efficiency ηE and overall efficiency
ηO, either separately or in combination, does not adequately describe CHP performance
because ηE gives no value to thermal output. Overall efficiency ηO is an accurate
measure of fuel use but does not differentiate the relative values of the energy outputs
and is not directly comparable to any performance metric representing separate power
and thermal generation.
CHP electric effectiveness ηEE is a single metric that recognizes and adequately
values the multiple outputs of CHP systems and allows direct comparison of system
performance to the conventional electric grid and competing technologies. This more
closely balances the output values of CHP systems and allows CHP system development
to be evaluated over time. CHP electric effectiveness views the CHP system as primarily
providing thermal energy, with electricity as a by-product. It is then defined as net
electrical output divided by incremental fuel consumption of the CHP system above the
fuel that would have been required to produce the system’s useful thermal output by
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conventional means. This approach credits the system’s fuel consumption to account
for the value of the thermal energy output, and measures how effective the CHP system
is at generating power (or mechanical energy) once the thermal needs of a site have
been met. This metric is most effective when used on a consistent and standardized
basis, meaning:
The ηEE metric measures a single point of performance (design point). The design
point for power generation is measured at ISO conditions (for combustion turbines,
microturbines, and fuel cells, 59 F (15 C), 60% RH, sea level, per ISO Standard 3977-2;
for reciprocating engines, 77 °F (25 °C), 30% RH, and 14.5 psia (100 kPa) per ISO
Standard 3046-1). The performance evaluates fuel input and CHP outputs at the design
point only. HHV is used because it measures the true value of performance in relation
to fuel use and fuel cost (HHV is more commonly used to compare energy systems, is
the basis of fuel purchases, and is the basis of emissions regulation).
1.7.3 Power and Heating Systems
For CHP systems delivering power and heating (steam and/or hot water, or direct
heating), the CHP electric effectiveness is defined as
η �EE =
Qfuel
WE
Q 
− � ∑  TH 
 α 
1-4
where α is the efficiency of the conventional technology that otherwise would be used
to provide the useful thermal energy output of the system (for steam or hot water, a
conventional boiler); see Table 1-2.
Examples 1 to 5 demonstrate how to apply this metric. The basis for comparison is
a 25% HHV efficient electric power source. Performance values for larger combustion
turbines, reciprocating engines, and fuel cells vary significantly.
Example 1. Separate Power and Conventional Thermal Generation. A facility
supplies its power and thermal requirements by two separate systems: a conventional
boiler for its thermal needs and a power-only generator for electricity.
Conventional Boiler: 100 units of fuel are converted into 80 units of heat and 20
units of exhaust energy as shown in Figure 1-7.
Power-Only Generator: A 25% HHV efficient electric generator consumes 160 units
of fuel and produces 40 units of electricity and 120 units of exhaust energy (Figure 1-8).
Table 1-2. Values of α for Conventional Thermal Generation Technologies
Fuel
α
Natural gas boiler
0.80
Biomass boiler
0.65
Direct burner exhaust
1.0
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CHP FUNDAMENTALS
The performance metrics for these separate approaches to energy supply are as
follows:
W
40
1-5
= 0.25
ηE = E =
Qfuel 160
ηO =
ηEE =
Qfuel
WE + ∑ QTH
40 + 80
=
= 0 46
Qfuel
160 + 100
1-6
WE
40
=
= 0.25
 80 
 QTH 
− ∑
 260 − 

 ∝ 
 0.80 
1-7
Figure 1-7. Conventional Boiler for Example 1
Figure 1-8. Power-Only Generator for Example 1
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WE
40
=
= 0.25
Qfuel 160
1-8
WE + ∑ QTH
40 + 80
=
= 0.75
Qfuel
160
1-9
ηE =
ηO =
ηEE =
Qfuel
WE
40
= 0.67
=
 80 
Q 
− ∑  TH  160 − 

 0.80 
 ∝ 
1-10
Example 2. Combined Power and Thermal Generation (Hot Water/Steam).
A CHP system is used to meet the same power and thermal requirements as in Example
1, with a 25% HHV efficient generator and a 67% efficient heat recovery heat exchanger
(e.g., a 600°F [315°C] airstream reduced to 240°F [115°C] exhaust and yielding 200°F
[93°C] hot water). The performance parameters for this combined system are shown in
Figure 1-10.
Figure 1-9. Separate Power and Heating Energy Boundary Diagram for Example 1
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CHP FUNDAMENTALS
Note that ηE for both systems (Example 1’s separate generation and Example 2’s
CHP) is the same, but the combined system uses less fuel to produce the same outputs,
as shown by the differences in overall efficiency (ηO = 75% for CHP versus ηO = 46%
for separate systems) (Figure 1-10). However, this metric does not adequately account
for the relative values of the thermal and electric outputs. The electric effectiveness
metric, on the other hand, nets out the thermal energy, leaving a ηEE of 67% for the CHP
system versus 25% for separate systems (Figure 1-11).
Figure 1-10. Performance Parameters for Combined System for Example 2
Figure 1-11. CHP Power and Heating Energy Boundary Diagram for Example 2
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Example 3. Combined Power and Thermal Generation (Direct Exhaust Heat).
In some cases, exhaust gases are clean enough to be used for heating directly (e.g.,
greenhouses and drying where microturbine and gas turbine exhaust is used). For these
cases, the thermal recovery efficiency is the difference between exhaust gas temperature
and ambient temperature, where delivered exhaust gas temperature is divided by the
difference between exhaust gas temperature and outdoor ambient temperature. Direct
exhaust gas delivery is a direct-contact form of heating; thus, heat transfer losses are
minimal. For a 25% efficient electric generator exhausting into a greenhouse with an
internal temperature of 100°F (38°C), thermal recovery efficiency = (600°F – 100°F
[315°C – 38°C])/(600°F – 59°F [315°C – 15°C]) = 92% (note that 59°F [15°C] is the
ISO rating condition for microturbines per ISO Standard 3977-2).
ηthermal recovery =
( 600 F − 100 F [315 C − 38 C ])
( 600 F − 59 F [315 C − 15 C ])
1-11
ηthermal recovery = 92%
Performance parameters for this combined system are shown in Figure 1-12, and
system boundaries are shown in Figure 1-13.
WE
40
=
= 0.25
Qfuel 160
1-12
WE + ∑ QTH 40 + 110
=
= 0.94
Qfuel
160
1-13
ηE =
ηO =
ηEE =
Qfuel
WE
40
= 0.80
=
 110 
 QTH 
− ∑

 160 − 
 1.00 
 ∝ 
1-14
Figure 1-12. Performance Parameters for Example 3
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CHP FUNDAMENTALS
WE
40
=
= 0.25
Qfuel 160
1-15
WE + ∑ QTH 40 + 69
=
= 0.68
Qfuel
160
1-16
WE
40
= 0.54
=
 69 
 QTH 
Qfuel − ∑ 

 160 − 
 0.80 
 ∝ 
1-17
ηE =
ηO =
ηEE =
Example 4. Combined Power and Thermal Generation (Combustion Turbine
[CT] Without Cofired Duct Burner). In this example, exhaust gas from the 25%
efficient electrical combustion turbine generator setup is assessed, first without any
exhaust enhancement, and then in Example 5 the same system is assessed with
temperature and energy content enhancement using cofiring of additional fuel in a duct
burner placed in the exhaust and using a heat recovery steam generator (HRSG). The
basis for this example is using fuel input and steam output data from a simple cycle gas
turbine, as shown in Figures 1-14 and 1-15.
Figure 1-13. CHP Power and Direct Heating Energy Boundary Diagram for Example 3
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Figure 1-14. Performance Parameters for Example 4
Figure 1-15. CHP Power and HRSG Heating Without Duct Burner Energy Boundary Diagram
for Example 4
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CHP FUNDAMENTALS
Example 5. Combined Power and Thermal Generation (CT with Cofired Duct
Burner) (Figure 1-16). Note that, based on this system approach, cofiring has no effect
on ηE, because no fuel flows to the duct burner in power-only mode. However, ηEE
increases from 0.54 to 0.71 (Figure 1-17).
WE
40
=
= 0.25
Qfuel 160
1-18
WE + ∑ QTH
40 + 182
=
= 0.78
Qfuel
284
1-19
ηE =
ηO =
ηEE =
Qfuel
WE
40
= 0.71
=
 182 
 QTH 
− ∑

 284 − 
 0.80 
 ∝ 
1-20
Figure 1-16. Cofiring Performance Parameters for Example 4
Figure 1-17. CHP Power and HRSG Heating with Duct Burner Energy Boundary Diagram
for Example 5
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Table 1-3 shows a summary of the performance metric results of Examples 1 to 5.
Demonstrating the effect of increasing efficiency, Table 1-4 presents the results from
using a combustion turbine (CT) that delivers 33% efficiency. Notice that ηEE is, as
expected, higher in all examples, and ηO is higher in all but the cofired duct burner case.
Cofiring uses exhaust gas heat very effectively, with a 75% recovery rate, accounting
for the dominance of thermal recovery from a primary-energy basis and consequently
lower ηO associated with the higher ηE system. ηEE, like coefficient of performance
(COP), can exceed 1.00, which demonstrates the primary-energy power CHP systems
delivered in Examples 3 and 4. ηEE, like ηO, exhibits the same pattern in Table 1-3 as in
Table 1-2.
Table 1-3. Summary of Results from Examples 1 to 5
Example
System
ηE
ηO
ηEE
1
Separate boiler and generator
0.25
0.46
0.25
2
Combined heat (hot water)
and power
0.25
0.75
0.67
3
Combined heat (direct) and
power
0.25
0.94
0.80
4
Heating (CT without cofired
duct burner)
0.25
0.68
0.54
5
Heating (CT with cofired
duct burner)
0.25
0.78
0.71
Table 1-4. Summary of Results Assuming 33% Efficient Combustion Turbine
Example
System
ηE
ηO
ηEE
1
Separate boiler and generator
0.33
0.51
0.33
2
Combined heat (hot water)
and power
0.33
0.87
1.00
3
Combined heat (direct) and
power
0.33
0.95
1.40
4
Heating (CT without cofired
duct burner)
0.33
0.72
0.64
5
Heating (CT with cofired
duct burner)
0.33
0.67
0.47
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CHP FUNDAMENTALS
The implication is that greater use of the thermal energy results in a higher electric
effectiveness (Figure 1-18). All of the example systems, except a low electrically efficient
generator with separate boiler, are superior in electrical effectiveness as compared to the
delivered efficiency of the electric grid.
1.7.4 Fuel Energy Savings
Electrical effectiveness provides a reasonable metric for CHP system comparison;
however, it alone cannot provide a measure of fuel savings or emissions effects compared
to separate, conventional generation of electric and thermal energy requirements.
Understanding fuel savings or emissions effects requires further assumptions about the
conventional, or reference, systems. Reference baselines for separate thermal heating
are as previously developed. The reference baseline for separate electric generation is a
conventional power plant’s electric generation efficiency ψ. Typical values for ψ are
listed in Table 1-5.
Figure 1-18. Electric Effectiveness ηE versus Overall Efficiency ηO
Table 1-5. Typical ψ Values
Generator η
LHV
Generator
η HHV
T&D
Losses*
ψ
—
—
—
0.32*
High-efficiency combined cycle
combustion turbine (CT)
0.600
0.540
0.050
0.49
Simple-cycle CT
0.380
0.340
0.068
0.27
Electric Generation Source
EIA average national grid
*Calculated from DOE/EIA (2005).
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Fuel energy savings qsavings then reflects fuel savings associated with generating the
CHP system power and thermal output through CHP (Qfuel) compared to using separate
heating and electric power sources (FUELreference):
Separate
electricity
{}
=
 ∑ QTH 

 HEATα 
WE
FUELreference =
θ SAVINGS
Separate
thermal heating
+ 
ψ
1-21
FUELreference − Qfuel
FUELreference
Calculations using the system in Example 2 show a projected fuel savings of 29%,
based on operation at the system design point:
Thermal
heating
Electricity
{ }
40
FUELreference =
θ SAVINGS
=
0.32
225 − 160
225
 80 

 0.80α 
+ 
1-22
= 0.289
\Note the rated design point, to show the utility of the approach in comparing
equipment performance on a consistent basis (i.e., for program management and
performance metrics). The same methodology could be applied to different design
points (e.g., part load, different ambient temperatures) as long as system outputs and
fuel inputs are all determined on a consistent basis (e.g., power output, fuel input,
thermal output, and recovery all estimated based on 100°F [38°C] ambient temperature
and 1000 ft [300 m] altitude). Reference system performance should also be considered
on the same basis (e.g., it would not be fair to compare CHP electric effectiveness or
fuel savings as calculated on a 100°F [38°C] day to combined cycle efficiencies
calculated at ISO conditions). Similarly, the methodology could be applied to actual
application performance if system outputs and utilization are considered on a consistent
basis (e.g., evaluating actual system power output, fuel input, and thermal energy used
over some specified time period). Fuel savings from the same direct heating and power
CHP system as in Example 3 show a projected fuel savings of 32%, based on operation
at the system design point:
Thermal
heating
Electricity
FUELreference =
θ SAVINGS
=
{ } { } = 235
235 − 160
235
40
0.32
+
110
1.0
1-23
= 0.32
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CHP FUNDAMENTALS
Applying the same process for the 25% power generator CHP systems (Examples
1 to 5) and using each of the three referenced electric comparisons gives the results
presented in Table 1-6. Table 1-7 presents results obtained if a 33% generator is assumed.
Table 1-6. Summary of Fuel Energy Savings for 25% Power Generator
in Examples 1 to 5
Example
CHP System
Simple Cycle
Grid Average
Peaker17
Adv.
Combined
Cycle
1
Separate boiler and
generator
0.00
0.00
0.00
2
Combined heat (hot
water) and power
0.35
0.29
0.12
3
Combined heat
(direct) and power
0.38
0.32
0.17
4
Heating (CT without
cofired duct burner)
0.32
0.24
0.05
5
Heating (CT with
cofired duct burner)
0.24
0.19
0.08
Table 1-7. Summary of Fuel Energy Savings for 33% Power Generator
in Examples 1 to 5 (SI)
Example
CHP System
Simple Cycle
Grid Average
Peaker
Adv.
Combined
Cycle
1
Separate boiler and
generator
0.00
0.00
0.00
2
Combined heat (hot
water) and power
0.47
0.41
0.26
3
Combined heat
(direct) and power
0.50
0.44
0.31
4
Heating (CT without
cofired duct burner)
0.41
0.33
0.13
5
Heating (CT with
cofired duct burner)
0.23
0.16
(0.01)
Peaking power plants, also known as peaker plants, and occasionally just “peakers,” are power
plants that generally run only when there is a high demand (peak demand) for electricity.
17
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CHAPTER 2
APPLICATION LOAD ASSESSMENT
The results of the load assessment provide the starting point for sizing and
configuring the CHP system, whether from a solely economic perspective or from the
perspective of providing standby power, emissions reductions, etc. The load assessment
should not only include as high a definition as possible of energy use and demand data
but also the load characteristics and the physical attributes of the facility, including
thermal connection points, power interconnection, power distribution grid layout,
space availability, and existing equipment. An important aspect of the load assessment
is to determine if the available loads are addressable by the CHP system. To this end,
each facility load should be profiled in terms of the type and quality of energy required
to satisfy facility needs. Furthermore, loads must be properly profiled to obtain a
detailed understanding of load variations on a seasonal, monthly, weekly, daily, and
hourly basis.
CHP plants are typically sized to meet base loads, and generally have a constant
electric and thermal output, with limited variation. CHP systems that include duct
burners or are designed to provide variable electric output can provide higher variation
on thermal output but will still have a base load thermal output that should be used to
the fullest extent. On the other hand, facility loads can have wide variations throughout
the day as well as significant changes from season to season or from workday to
weekend day. Undoubtedly, a facility must have some level of consistency in loads as
well as concurrency in thermal and electric loads for it to be amenable to the application
of CHP. An accurate profile of each addressable load must still be developed to
understand the functioning and interaction of the facility and the CHP plant. Although
actual load data on an hourly, daily or weekly basis may not be available, some
estimation of how the loads vary must be made.
If the load information is properly tabulated, it can be used to run various CHP
configuration scenarios with little additional effort. Because this information will be
used to calculate the performance of perhaps multiple CHP configurations, the load
data should be presented in a way that it can easily be compared to various CHP outputs.
This is an essential step in developing the optimum configuration for the particular
facility and contrasts with the often-used approach of developing the CHP output
streams and comparing them to the available loads.
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To achieve some ease of comparing load analysis results with potential CHP
configurations, the addressable loads should be categorized into groups that are
compatible with CHP output streams. These CHP output streams can be characterized
in a limited number of forms (Table 2-1).
Categorizing all the addressable loads into these forms enables consolidation of
similar load forms and easy comparison to multiple CHP configurations. Properly
defining the characteristics of each load form is also required to ensure that loads of
similar form can in fact be consolidated and met by the CHP system output. For
example, a hotel may have multiple hot-water loads, such as domestic hot water for
general use, domestic hot water for kitchen use, and hot water for laundry, pool heating,
and space heating. Typical temperatures for these loads are shown in Table 2-2.
In general, all loads can be consolidated if the CHP configuration has the ability to
supply heat at a temperature no less than the highest supply requirement plus the
temperature loss for any heat exchanger between the loads and the CHP system. Using
the temperatures outlined in Table 2-2 and using a heat exchanger on each loop with a
5°F (2.8°C) approach, a CHP system that generates 170°F (77°C) degree hot water will
not be able to supply the space heating requirements, whereas a CHP system that
generates 190°F (88°C) will be able to address all the loads, including space heating.
In the load analysis and profile development, all the hot-water loads can be consolidated
as long as the temperature requirement of not less than 185°F (85°C) is identified. If a
CHP system with a hot-water output of less than 185°F (85°C) is selected, then the
loads must be reassessed for addressability on the basis of temperature requirement.
Table 2-1. CHP Output Streams
Power
Heat
Cooling
Electric
Steam
Chilled Water
Mechanical
Hot Fluid
Refrigeration
Hot Exhaust Air
Dehumidification
Table 2-2. Typical Hotel Heating-Water Temperature Requirements
Load Type
Supply Temp
(°F)
Supply Temp
(°C)
Return Temp
(°F)
Return Temp
(°C)
General DHW
120
49
-
-
Kitchen DHW
140
60
-
-
Laundry HW
170
77
-
-
Pool Heat
140
60
130
54
Space Heat19
180
83
160
71
18
The supply and return temperatures considered here are those temperatures required by the heat
exchanger used to heat the pool water. Pool water temperature typically varies from 80 to 82°F
(26.7 to 27.8°C) for most recreational pools; however, the design of the pool heating system may
require significantly different temperatures, as illustrated here.
18
Space-heating supply and return temperatures for existing buildings are determined by the
requirements for the existing or new air-side devices, such as radiators, air handling units, etc.
Outdoor temperature reset may vary these requirements according to ambient conditions. The
assessment of such loads should recognize temperature requirements through all seasons and
particularly for peak heating load.
19
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APPLICATION LOAD ASSESSMENT
2.1 LOAD TYPES AND CONSIDERATIONS
CHP systems by definition provide both thermal energy and electric or mechanical
power to serve a variety of loads at one or more facilities. Loads that can be served by
the CHP system are called addressable loads and must be properly defined before
consideration can be given to the size and type of CHP configuration that will meet the
needs of the owner or developer. Properly characterizing the various loads and
understanding their addressability relative to the output of the CHP system is of vital
importance to a CHP load assessment.
In many applications, a variety of thermal loads are available, whereas the available
electric loads in the United States are generally homogeneous at 60 Hz alternating
current (ac) at a specified voltage. The power factor and power quality at the point of
connection are only of concern when they are not in line with normal utility parameters
and can significantly impact a CHP system’s ability to deliver power or even connect to
the facility grid. Correction measures may be required if these issues are present,
although, many utilities will now require facility power grids to meet certain power
factor and quality criteria to protect their own distribution grids. The local utility grid’s
fault protection system also must be considered when applying CHP, because some
distribution systems, particularly grid networks, may require additional protection
equipment to prevent widespread damage in the event of a fault on the grid. Note that
some applications, such as data centers, are beginning to consider use of direct current
(dc) in their applications, but this still remains a very small percentage of applications.
CHP systems can also be configured to provide thermal energy and mechanical power
rather than electric power. Mechanical loads are defined in terms of horsepower
(kilowatts) and shaft rotation speed, which can be matched to prime mover rotatingshaft speeds using gearing mechanisms.
Thermal load types and forms can vary widely, from high-pressure steam to
refrigeration. Although the primary thermal output of a CHP plant is heat—either hot
water (as in the case of a reciprocating engine jacket heat rejection loop) or hot exhaust
gases—this output can be converted using thermal conversion technologies to produce
a variety of thermal outputs from the CHP system. As discussed in Chapter 1, exhaust
gases can be used (1) directly in some heating processes, (2) in a heat exchanger to heat
air or a fluid, or (3) in a heat recovery steam generator (HRSG) to produce steam.
Furthermore, the exhaust, hot water, or steam can be used in thermally activated chillers
to convert this thermal energy to cooling or refrigeration or to remove moisture from
an airstream in desiccant dehumidifiers. Therefore, the thermal loads relevant to CHP
can include domestic hot water, steam heating for process or space conditioning, hot air
drying, space cooling, refrigeration, hot water heating, desiccant regeneration, process
cooling, steam drying, etc. The main consideration for a thermal load is its addressability
by the CHP plant; this incorporates both the physical nature of load access as well as
load characteristics.
To maintain a high load factor20 on the CHP system during all operating hours, it
may be necessary to address multiple thermal loads either at the same time or at
different times, as would be the case for a multifamily residential application where the
Load factor is a statement of the amount of energy consumed for useful purposes versus capacity
of the system or the amount of energy that could be produced by the system if it operated all hours
at its full capacity.
20
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CHP system may address domestic hot water with space heating in winter and
domestic hot water with space cooling in summer. CHP prime movers define the
quality and forms of heat available and must be selected to meet the thermal needs of
the facility as much as the power needs of the facility. For example, in applications
where steam is the only addressable load, selection of a non-ebulliently (non-vaporphase) cooled reciprocating engine that provides approximately half its thermal output
in the form of hot water will potentially have a lower load factor than a combustion
turbine whose entire thermal output is hot exhaust that can be converted to steam.
Mitigating factors such as equipment availability and cost, design needs, and utility
tariff structure may result in selection of the lower-load-factor solution, although, the
higher-load-factor solution will generally provide better operating economics and
lower overall facility emissions.
2.2 EFFICIENCY VERSUS LOAD FACTOR
As discussed in Chapter 1, overall efficiency is defined as the relationship between
the total usable energy output from a CHP system and the input fuel energy normally
expressed in higher heating value (HHV) of the fuel. To calculate nominal overall
efficiency, all the system usable output streams are converted to Btu (kW) and summed
before being divided by the fuel’s higher heating value in Btu (kW). The individual
components of overall efficiency are electric, thermal, and mechanical efficiency and
describe the amount of input fuel that is converted to electric, thermal, or mechanical
energy, respectively. Nominal CHP efficiencies reflect standard equipment-rating
conditions and do not take into account the usefulness of the output energy stream.
Nominal or design efficiencies are single-point ratings and are useful in comparing
different systems from a theoretical perspective but do not in any way reflect the actual
”as used” efficiency of the system for a given application.
Although nominal efficiency is an important statement of the capability of the
system to convert fuel to energy, it is the ability of the facility to use the CHP system’s
power and thermal capacity, expressed in terms of the load factor, that is of real
importance when considering economic and environmental performance. A CHP
system that operates only a minimal number of hours per year can have a high efficiency
when operating, but it will have a low annual load factor, which may be a more true
reflection of the actual economic potential for the application in terms of return on
investment. Similarly, a CHP system that produces electricity at a high annual load
factor but wastes significant thermal energy (poor thermal load factor) may also exhibit
a poor economic return. The thermal load factor is a statement of the amount of thermal
energy consumed for useful purposes versus the system’s thermal capacity (the amount
of thermal energy that could be produced by the system). Where the primary goal of
the project is to optimize return on investment, load factor is a direct indication of how
hard the purchased equipment is working to pay down the capital cost, assuming that
the system is operating at some cost advantage.
In many applications that are electric load driven and designed to operate at an
85% or above electric load factor throughout the year, the thermal output is relatively
constant at 85% to 100% of rated output, whereas the thermal load is independent and
can vary considerably throughout various time periods such that all the CHP output
may not be consumed for useful purposes at all times.
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APPLICATION LOAD ASSESSMENT
For example, a 1 MW generator has the capacity to produce 8760 MWh of electric
energy in a year. If the system actually produces 6000 MWh of power in a specific year,
then the electric load factor for the system that year is 6000/8760 = 68.5%. Thermal
load factor is calculated in the same way, dividing useful Btu (kW) in a given period by
the thermal capacity of the system in Btu (kW). The thermal capacity should be
calculated after the CHP system operation has been adjusted for the actual electric load
factor. In this example, if the nominal thermal capacity of the 1 MW system is 4 million
Btu/h (1172 kW/h) at full output, then the nominal thermal capacity of the system is
4 million Btu/h × 8760 hours = 35,040 million Btu (10.3 million kW). However, given
that the prime mover only runs at a 68.5% load factor, this means that the actual
thermal capacity of the system is the nominal capacity times the electric load factor,
or 35,040 million Btu × 68.5% electric load factor = 24,000 million Btu (7 million kW)
for the specified year.
To further illustrate the meaning of load factor, consider the above example of a
1 MW engine with 4 million Btu/h (1172 kW) of thermal output. When applied to
a facility that has a 1 MW constant load 24 h/day, 7 days/week, and 3 million Btu/h
(879 kW) constant addressable thermal load, the annual electric load factor will be the
full engine output times the engine availability21, which is assumed to be 90%.
Therefore, the electric load factor will be 90% and the thermal capacity will be
4 million Btu/h × 8760 h × 90% = 31,536 million Btu (9.2 million kW). Thermal load
availability is 3 million Btu/h while the CHP system is running or 3 million Btu/h ×
8760 h x 90% = 23,652 million Btu (96.0 million kW). The calculated thermal load
factor for this system is the thermal energy used divided by the capacity of the system
as operated or 23,652/31,536 = 75%. In an effort to increase the thermal load factor,
apply an engine of 750 kW capacity with the same electric and thermal characteristics
such that the engine will have a thermal capacity of 3 million Btu/h (879 kW). In this
scenario, the electric load factor will remain the same at the full engine output times
the engine availability or 90%. However, because the thermal capacity of the system
has been reduced to match the addressable load, the thermal load factor will now be
the useful thermal energy of 3 million Btu/h (879 kW) × 8760 h x 90% divided by the
thermal capacity of 3 million Btu/h (879 kW) × 8760 x 90%, resulting in a thermal
load factor of 100%.
In many cases, the loads are not available 8760 h/yr, and CHP systems are run
during facility operating hours, which may be in line with a process, occupancy, or
other schedule. In such cases, the annual electric load factor should reflect the reduction
in operating hours as an indication of lower revenue generation. Using the above
example, if the facility only operates 5000 h/yr, then the electric load factor can only
be a maximum of the CHP system’s useful electricity capacity times the operating
hours times the availability during operating hours. If the system is sized at or less than
the facility’s base load, as with a 750 kW generator, the maximum electric load factor
will be (750 kW × 5000 h × 95%)/(750 kW × 8760 h) = 54.2%. Given sufficient
addressable thermal load as described above, this system will still have a thermal load
factor of 100%, because all the thermal energy that is produced when the system
operates is consumed for useful purposes.
Reciprocating engines require shutdowns for maintenance and service, which in this example
amounts to 10% of the year.
21
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It is most useful to understand both the electric and thermal load factors
independently when applying CHP configurations to a particular application. In
addition, because the CHP system may address several different thermal loads in the
facility, an understanding of the individual thermal load factors will allow for easy
sizing of the system to get optimum performance. CHP systems must be sized and
configured to provide the maximum electric and thermal load factor through a 12-month
operating period.
Site utilization efficiency combines efficiency and operating hour load factor and
is based on the amount of energy produced by the CHP system that is actually used at
the site versus fuel input during a specified period, typically one year. Because site
utilization efficiency is an expression of the amount of generated output energy that is
actually used in an application, it is directly related to ”as used” energy efficiency when
the system operates, and can be a critical factor for economic performance as well as a
threshold to obtain grant assistance and meet efficiency criteria. This is independent of
load factor and should be considered as a separate characteristic of the CHP system as
applied to a site.
2.3 BASE, AVERAGE AND PEAK LOADS
As previously stated, most applications have varying loads throughout the year,
month, week, and day, while a CHP system typically has a constant output of electric
and thermal energy when it operates. The CHP system’s outputs can be varied somewhat
according to load, but normal design goals target running the system at or close to full
capacity during all operating hours. If the load requirements vary significantly below
the CHP system’s design output, system efficiency can be reduced and maintenance
costs per unit of output increased. In addition, capital cost recovery is slower when a
system runs at lower load factors such that the economic advantage offered by a CHP
plant is lessened. Other factors, including thermal output quality and thermal equipment
performance, may also be compromised.
The peak load represents the maximum instantaneous demand during the period
(typically one month) and can be of short duration but does require that the facility
infrastructure is capable of providing the required amount of power or thermal energy.
Electric peaks are often set in summer and are influenced by the need of electricity to
power air conditioners. Thermal peaks are often set in winter when low ambient
temperatures require additional process or space heating energy. Note that many
electric utility companies derive billing peak load from two consecutive peak readings,
so instantaneous peak as metered may not be the same as the peak load recorded for
billing purposes.
The average load is the total period load divided by the number of time intervals in
the period. Average load provides some indication of the size of the facility loads and,
when compared to the peak load, can also provide information on how the facility
operates as well as on facility electric and thermal load factors. Average loads by
themselves are useful to determine some characteristics of a facility but do not provide
any indication of how that facility operates and should only be used in the most
rudimentary assessments of facilities when considering the application of CHP.
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The minimum load is the demand below which the facility load does not fall and
should be determined based only on the expected operating hours of a proposed CHP
plant. For example, the minimum load at a production facility during working hours
may be significantly higher than the minimum load on a holiday weekend so that if a
CHP plant were to be implemented it may only operate during production hours. In this
case, the minimum load would be the load as applied to the CHP plant and would not
include the holiday weekend minimum.
By sizing the CHP system to provide only enough energy to meet the minimum
loads, the system will attain the highest load factor possible. However, this also results
in the smallest CHP system for the application, and many application minimum loads
may vary considerably from month to month such that restricting the size to the annual
operating hour minimum load may disallow use of a larger, more efficient system with
better economies of scale. In many cases, the system may be sized between the
minimum load and average load such that it can attain a high load factor and still have
economies of scale to justify the less than 100% load factor. To provide a more practical
approach to sizing, a base load is calculated that reflects the minimum load for an
acceptable amount of operating hours. The base load is the minimum load adjusted to
reflect a target load factor such that, for example, at a target load factor of 85%, the
base load is considered to be the minimum load for 85% of the operating hours. In
other words, the base load is the highest minimum load during 85% of the operating
hours while the minimum load can be less than the base load for 15% of the time. If a
load demands 1250 kW for 10% of the CHP system operating hours, 1000 kW for 30%
of the operating hours, 750 kW for 30% of the operating hours and 500 kW for 30% of
the operating hours, then the base load at an 85% load factor is 833 kW. The CHP plant
operates at 100% for 40% of the operating hours, 90% for 30% of the hours and at 60%
for 30% of the operating hours. This leads to an overall operating hour load factor of
85% and allows use of an 833 kW plant in lieu of a 500 kW plant that would have been
determined using only the operating hour minimum load.
Peak, average and base loads are normally expressed as kilowatts per hour for
electricity, thousands or millions Btu per hour (kilowatts) for heating and tons
(kilowatts) for cooling. Though other mitigating circumstances may influence CHP
system size and configuration, it is necessary to recognize the importance of properly
understanding the peak, average and base loads of a facility when reviewing an
application and/or sizing a CHP system. Whereas peak loads generally exceed the CHP
system capacity with little consequence to the design of a CHP system, the base load
more often than not determines the CHP system design. In addition, whatever the size
and configuration of the selected CHP system, the economic and environmental
performance of the system will be directly subject to the addressable load profiles.
Figure 2-1 graphs the monthly load profile showing maximum (peak), average, and
minimum steam demand in pounds per hour (kilograms per second) for a facility that
uses steam for space heating in winter and for process loads and domestic hot-water
production year round. The space-heating component can be approximated by
subtracting the midsummer loads from each month assuming there is no other use for
steam. Note that there is a significant deviation in steam demand during the highdemand winter period when space heating is the major load and a low deviation during
summer when process requirements are the major load. This is typical for applications
that have a large space conditioning component to their loads and needs to be taken into
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Figure 2-1. Monthly Steam Demand Profile
consideration when sizing a CHP system. In this scenario, if a CHP system is sized at
the annual average load of approximately 4000 lb/h (0.504 kg/s), it will have a thermal
load factor of between 25% to 50% for six months of the year, resulting in poor
economic and emission reduction performance.
Figure 2-2 shows the monthly space cooling load profile for a facility that uses
chillers for space conditioning in summer and data center cooling all year round.
Assuming there is no other use for chilled water, the space conditioning load can be
approximated by subtracting the midwinter loads from the cooling month loads. As
with the steam load, there is a higher deviation in demand during the summer when
space conditioning has a major influence on load.
2.4 THERMAL/ELECTRIC RATIO
The thermal/electric (T/E) ratio, in its simplest form, is an expression of the ratio
of thermal energy to electric energy and can describe either the facility load profile or
a CHP system output profile. When considering the facility loads, the T/E ratio should
be restricted to the addressable loads. The T/E ratio is the inverse of the power heat ratio
often provided by engine manufacturers. By contrast to the power heat ratio, which is
expressed in Btu (J) of power output per Btu (J) of heat output, the T/E ratio, as used
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Figure 2-2. Monthly Chilled-Water Demand Profile
for CHP design purposes, is expressed in terms of thousand Btu per hour per kilowatt
of electric or mechanical output (kWH/kW) or refrigeration tons22 per kilowatt (kWC/
kW) with an assumed operating period of one hour. This definition is more compatible
with site loads and allows for characterization of a CHP system’s output in a way that
is compatible with a facility’s addressable power and thermal load characteristics.
Both the host site and the CHP system T/E ratios are very useful in providing a
common methodology for not only comparing addressable loads with CHP configurations
but also in comparing different CHP system configurations. Other factors and elements,
including a comprehensive economic evaluation, should ultimately determine the
optimal configuration, but the T/E ratio can provide an easy method to quickly assess the
suitability of a given CHP configuration for a particular facility’s addressable loads.
Table 2-3 provides typical heating and cooling T/E ratios for a number of common
CHP configurations at nominal rating conditions.
22
1 ton = 12,000 Btu/h
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Table 2-3 T/E Ratios of Common CHP Configurations
at Nominal Rating Conditions
Power
Output,
kW
Heat
Output,
1000
Btu/h
Cooling
Output,
tons
Heating
T/E Ratio,
1000 Btu/h
per kW
Cooling T/E
Ratio, tons
per kW
1 MW reciprocating engine
with hot water
and single-effect absorber
1000
3500
210
3.5
0.210
1 MW reciprocating
engine with hot water
and hybrid23 absorber
1000
3500
275
3.5
0.275
5 MW combustion turbine
with steam and steam
turbine chiller
5000
23,000
2300
5.4
0.460
5 MW combustion turbine
with steam and singleeffect absorber
5000
23,000
1350
5.4
0.270
Power
Output,
kW
Heat
Output,
kW
Cooling
Output,
kW
1 MW reciprocating
engine with hot water
and single-effect absorber
1000
1026
739
1.026
0.739
1 MW reciprocating
engine with hot water
and hybrid23 absorber
1000
1026
967
1.026
0.967
5 MW combustion turbine
with steam and steam
turbine chiller
5000
6741
8089
1.35
1.618
5 MW combustion turbine
with steam and singleeffect absorber
5000
6741
4748
1.35
0.950
Configuration
Configuration
Heating T/E Cooling T/E
Ratio, kWH Ratio, kWC
per kW
per kW
As can be seen from Table 2-3, by selecting different thermally activated chillers,
the cooling T/E ratio can be increased or decreased for the same prime mover. Once
the facility addressable base loads have been determined, the T/E ratios for the facility
in summer and winter can be calculated and compared to multiple CHP configurations.
Matching the T/E ratios of the CHP system to the facility will yield the highest
load factor.
2.5 LOAD ELECTRIC AND THERMAL CHARACTERISTICS
A given host site or facility typically has a number of electric and thermal loads,
each of which should be characterized independently. It is important that not only the
size and frequency of the loads are identified, but also the characteristics of each load.
These characteristics include voltage for electric power, and supply temperature,
A hybrid absorber converts exhaust energy using a double-effect cycle and converts jacket heat
rejection using a single-effect cycle.
23
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temperature range, pressure, etc. for thermal loads, and are important in first qualifying
and then quantifying the portion of a facility load that can be addressed or offset by a
CHP system.
Electric characteristics for the load being reviewed include the frequency or cycles
of the alternating current supply (60 cycles or hertz for the United States); the voltage
at the point of CHP system interconnection; the power factor; the maximum, average,
and minimum demands; and the power usage in kilowatt-hours. Demand and usage can
vary significantly throughout the day and week during any given billing period, and
seasonal conditions can also have significant impact on load characteristics; at least a
year’s data should be reviewed. Other characteristics, such as harmonics and phase
balance, may need to be reviewed if the facility exhibits poor power quality or has a
poor load factor. Facilities with low power factor can affect the performance of the
CHP system’s prime mover, and voltage irregularities can prevent the generator from
connecting to the system.
Thermal loads can be defined by the flow, specific heat, and specific gravity of the
transfer media times the temperature differential across the load. Using this definition
as a guide, the characteristics required to describe a thermal load are transfer media,
mass transfer, and inlet and outlet temperature. The transfer media are generally water,
steam, thermal oil, or air. Mass transfer is the product of media volumetric flow times
the specific gravity of the media times the density of water. The total thermal energy
delivered to the load is the product of the mass transfer times the specific heat of the
media times the temperature differential between the inlet and outlet temperatures at
the point of measurement.
The point of measurement is normally taken at the energy generation device and
includes line losses as well as load requirements. For hot-water or thermal-oil heaters,
the calculation is be based on the inlet and outlet temperatures at the unit, whereas for
steam boilers the outlet temperature is the steam temperature and the inlet temperature
is the boiler feedwater temperature. In the case of steam boilers, the heat of vaporization
in converting the feedwater to steam must also be considered. For hot-air delivery
systems, the outlet temperature is the temperature of the air produced by the unit and
the inlet temperature is the feed air temperature to the unit, which can be made up of
return hot air as well as outdoor air at ambient conditions. For hot-air systems, the
quality of the air must also be considered if the CHP system is to supply exhaust
directly to the process.
2.6 PRIME MOVER ELECTRIC AND THERMAL CHARACTERISTICS
The electric characteristics are defined by the electric generator coupled to the
prime mover and in almost all cases will provide alternating current at 60 Hz (for U.S.
applications) at a voltage selected to match the site’s electric distribution system at the
point of interconnection. Generators are also rated at a specific power factor, which
typically varies from 1.0 to 0.8. If necessary, the load’s power factor can often be
improved using various power factor correction techniques, including the application
of variable-speed drives or capacitors on large inductive loads. In addition, most prime
movers used in CHP systems are gas fueled, and loads generally must be applied in
increments (step loaded), because the engines will fail if large loads are placed on the
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system too quickly. This is of particular concern when the CHP system is to be used as
a source of standby power in the event of a utility grid failure. Step loading appropriate
to the engine capability to accept load can be achieved by using switchgear that will
add cost to the system if not already available. The prime mover’s control system will
normally incorporate a voltage variance measurement and will not allow the plant to
connect to the grid if the variance exceeds set point. The allowable variance should be
checked against grid measurements if there are concerns regarding power quality at the
interconnection point.
Small CHP system generators for residential use may be configured to provide
208/230 V, but more typically, CHP system prime movers generate power at between
460/480 V and 13,200 V. Step-up or step-down transformers can be used to change the
output voltage to match the facility needs. CHP prime movers that generate alternating
current (ac) are restricted to speeds that allow the generator to match the frequency
of the load, whereas direct current (dc) generating systems using inverters to generate
60 Hz ac and mechanical drives may use variable speeds. As with an electric system, a
mechanical system must load the engine appropriate to its step-loading capacity.
Electric systems that generate alternating current must match the frequency requirements
of the load and therefore are normally fixed speed. Direct current generating systems
and mechanical systems may use variable speed engines if, in the case of electric
generators, the output is run through an inverter that allows shaft operation at variable
speeds while maintaining output at a fixed frequency.
Although the prime mover in a CHP system clearly defines the power characteristics
of the system, the prime mover also defines the thermal characteristics of the CHP
system. All the thermal energy delivered by the system is derived from heat recovered
from the prime mover. There are three forms of heat produced by a prime mover:
(1) exhaust heat, (2) cooling fluid loop heat rejection, and (3) radiant heat from the
engine itself. Exhaust heat is defined in terms of mass flow and temperature, and
though specific heat can vary slightly depending on the chemical composition of the
exhaust, it is generally taken as being the equivalent of dry air, which is 0.24 Btu/lb·°F
(1.005 kJ/kg·K). If the exhaust energy is to be used directly in a process such as drying
or curing, the chemical composition should be reviewed for its potential impact on
product quality, because it does contain constituents that differ from furnace air.
Fluid-cooling loops are used to cool reciprocating engine jackets, lubricating oil, and
airflow through various components of the system. These loops can have significant
differences in fluid inlet and outlet temperatures and should be reviewed against load
requirements for compatibility. Radiant heat is rarely recovered but can be used to
preheat outdoor air by moving the air through the housing containing the engine
before it enters the building, assuming that building codes allow such applications.
Filtration is typically required before and after the engine enclosure to prevent dirt
from entering or leaving the enclosure.
When using reciprocating engines, the return temperature requirement to the prime
mover’s various fluid coolers is of primary importance. Though many cooling loops
may have an outlet temperature that appears compatible with load requirements, the
ability of the load to reduce the cooling fluid to the temperature required by the engine
may be an issue. The total energy volume of the load may be consistent with the output
of the CHP system, but a portion of the output may have to be dumped to meet the
return temperature requirement. A simple example is when a load designed for 180°F
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(82°C) inlet and 170°F (77°C) outlet temperature is matched to an engine that has a
jacket loop output temperature of 180°F (82°C) and a return temperature requirement
of 165°F (74°C). In this scenario, assuming that the jacket loop can be used directly to
meet the load, a continuous heat dump of 5°F (2.8°C) is required to maintain the engine
online. Although the load and heat recovery may appear to be compatible based on
supply temperature, in fact only 67% of the heat recovered can be used, and 33% must
be dumped, because the load is not able to reduce the loop temperature sufficiently to
meet the return temperature needs of the engine. This is particularly acute when facility
loads are less than design. Equally, the design must protect against reducing the engine
coolant temperature below the allowable limits. Loads such as boiler feedwater
preheating, freshwater heating or any load that operates below jacket water temperature
requirements have the potential to reduce the coolant temperature below jacket
requirements and cause the system to shut down or damage the engine. Controls must
be included to ensure that the return temperature to the engine jacket loop is not allowed
to fall below acceptable levels.
A second example, closer to real life conditions, provides a more dynamic illustration
of the issue. An engine jacket cooling loop with a total heat rejection of 1 million Btu/h
(293 kW) has an outlet temperature of 190°F (88°C) and a maximum return temperature
of 165°F (74°C) that is applied to a facility load of 2 million Btu/h (586 kW) with
constant flow, a supply temperature of 180°F (82°C) and a return temperature of 160°F
(71°C). The system includes a heat exchanger to separate the two loops with an approach
of 5°F (2.8°C). With the load at 100%, the engine output and load are properly matched,
and the thermal load factor is 100%. Figure 2-3 describes the temperature balance for
this scenario, which is based on peak design conditions.
However, as the load is reduced, the return temperature from the load increases and
can no longer reduce the engine jacket loop to the required temperature, and heat must
be dumped. At 75% load, the load return temperature increases to 165°F (74°C) and the
primary side leaving temperature of the heat exchanger increases to 170°F (77°C). Even
with a load 150% the size of the CHP system output, the thermal load factor is reduced
to 80%, and heat must be dumped. As the load drops, the hot-water loop temperature
increases, and more heat must be dumped, even though the load is apparently still larger
that the CHP system output. At 50% load, when the facility energy requirement equals
the CHP system output, 40% of the heat recovered must be dumped to meet engine
jacket return temperature requirements as depicted in Figure 2-4.
Figure 2-3. Engine Jacket Temperature Balance 1
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Table 2-4 provides the system conditions for loads at 25% increments. Based on a
weighted analysis according to the percentage of time at each load increment, the
annual thermal load factor for this configuration is 68%.
Applying a higher temperature engine to the same load, the results are significantly
different. While the load conditions remain the same, the new engine has a supply
temperature of 210°F (99°C) and a maximum return temperature of 185°F (85°C). In
this scenario, the engine loop return temperature is sufficiently high to allow the load
return temperature to drift up without having to dump any heat until the load is actually
less than the CHP system output. Figure 2-5 shows the same facility at 50% load,
demonstrating that the higher-temperature engine can apply all the available heat
recovery to the load with zero energy being dumped.
Figure 2-4. Engine Jacket Temperature Balance 2
Table 2-4. Building Load versus Heat Dump 1
Building Load
Design
Load
Time
at Load
Load,
1000
Btu/h
100%
15%
75%
CHP System
Hot Water Loop
Load HEX
Load
Factor
Dump,
1000
Btu/h
165
100%
0
190
165
80%
200
1000
190
165
60%
400
1000
190
165
40%
600
Load
Factor
Dump,
kW
Off
Supply
°F
Return
°F
190
165
1000
190
165
190
170
1000
180
170
190
175
180
175
190
180
gpm
Return
°F
On
2000
200
180
160
30%
1500
200
180
50%
35%
1000
200
25%
20%
500
200
Building Load
CHP System
Hot Water Loop
Load HEX
L/s
Supply
°C
Return
°C
On
Off
Output,
kW
586
12.6
82
71
88
74
440
12.6
82
74
88
77
35%
293
12.6
82
77
88
20%
147
12.6
82
79
88
Design
Load
Time
at Load
Load,
kW
100%
15%
75%
30%
50%
25%
Engine Jacket
Output,
1000
Btu/h
Supply
°F
Engine Jacket
Supply
°C
Return
°C
293
88
74
100%
0
293
88
74
80%
59
79
293
88
74
60%
117
82
293
88
74
40%
176
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Table 2-5 provides the system conditions at various loads, which results in an
annual thermal load factor of 90%.
As stated previously, the prime mover determines the thermal characteristics of the
system, but the useful heat recovered is also defined by the load characteristics. Heat
recovered is a product of the transfer media flow, specific gravity, and specific heat
multiplied by the temperature differential between the inlet and outlet temperatures to
the heat recovery device. The inlet temperature to the heat recovery device is a function
of the prime mover, whereas the outlet temperature from the device is defined by the
load. In cases where the return temperature required by the prime mover is lower than
that returned by the load, heat will need to be dumped and the thermal load factor will
be reduced. Operating conditions should be assessed for all load scenarios, including
lower-than-design loads, which are generally more frequent than design conditions.
Figure 2-5. Engine Jacket Temperature Balance 3
Table 2-5 Building Load versus Heat Dump 2
Building Load
CHP System
Hot Water Loop
Load HEX
Engine Jacket
Load
Factor
Dump,
1000
Btu/h
185
100%
0
185
100%
0
210
185
100%
0
210
185
50%
500
Load
Factor
Dump,
kW
gpm
Supply
°F
Return
°F
On
Off
Output,
1000
Btu/h
2000
200
180
160
210
185
1000
210
1500
200
180
165
210
185
1000
210
35%
1000
200
180
170
210
185
1000
20%
500
200
180
175
210
197
1000
Design
Load
Time
at
Load
Load,
1000
Btu/h
100%
15%
75%
30%
50%
25%
Building Load
Supply
°F
Return
°F
CHP System
Hot Water Loop
Load HEX
Design
Load
Time
at
Load
Load,
kW
L/s
Supply
°C
Return
°C
On
Off
Output,
kW
100%
15%
586
12.6
82
71
99
85
75%
30%
440
12.6
82
74
99
85
50%
35%
293
12.6
82
77
99
25%
20%
147
12.6
82
79
99
Engine Jacket
Supply
°C
Return
°C
293
99
85
100%
0
293
99
85
100%
0
85
293
99
85
100%
0
92
293
99
85
50%
147
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2.7 LOAD CONSOLIDATION & THERMAL STORAGE
As described previously, a CHP system can be configured to meet more than one
electric and thermal load. All addressable loads must be physically connected to the
CHP system and must be converted to a form that matches the CHP system output if
they are not already compatible with the output. For example, if a CHP plant is to
address steam space heating and domestic hot water (DHW), these two loads may both
be fed from a steam supply with a heat exchanger connecting the domestic hot-water
portion to the steam loop. The CHP system will feed steam from its heat recovery and
thermal conversion devices into the steam header that serves the heating load and
DHW heat exchanger. If this facility does not have a process heat need and therefore
would have a low thermal load factor in summer, a thermally activated chiller may be
added to the steam loop that would produce chilled water from the waste heat recovered
in summer. This chiller must be connected to the steam loop and the chilled-water loop
to fulfill this need. In this scenario, the space-heating, DHW, and space-cooling loads
are all merged and converted to steam and can all be addressed by the CHP plant. When
applying a reciprocating engine that has the potential to provide both steam from the
exhaust heat recovery system and hot water from the fluid cooling loops, the loads may
be brought to the CHP plant in more than one form. In this example, the space-heating
steam load can be addressed through the steam loop, while the DHW portion can be
addressed by the fluid cooling loop and does not need to be connected to the steam
loop. In summer, the exhaust energy can be used to boost the temperature of the engine’s
fluid cooling loop and used to both feed the DHW load and a hot-water-fired absorber
to meet the cooling load. The space heating load, when available, is addressable by the
exhaust heat recovery steam generator, and the DHW and cooling loads are merged and
converted to hot water that can be connected to the fluid cooling loop in winter and
fluid-cooling loop and exhaust heat recovery in summer.
A significant issue in trying to maintain high thermal load factor through all system
operating hours is the diurnal variations of some thermal loads. Assuming a CHP system
is matched to the base electric load, it will operate at or close to full load and will
provide a constant thermal output during all operating hours. Loads such as domestic
hot water in almost all applications, or space cooling in office building applications
where the chillers can be shut down during nonworking hours, will exhibit significant
variations in demand from hour to hour. Electric loads may likewise exhibit high diurnal
variations with relatively consistent high loads throughout the day and low loads at
night. Figure 2-6 depicts the projected typical summer day hourly electric demand for a
large, enclosed shopping mall based on a non-CHP design that used electric chillers for
space conditioning. The electric chillers are ramped up at 8 a.m. to bring the facility to
temperature by 10 a.m. opening time and then load follow through the day until midnight
when the chiller system is shut off. The electric chillers represent approximately one
third of the total electric load, which also follows the same operating pattern.
To facilitate the availability of power at the site, a CHP system was proposed, but
the operating pattern suggests providing a large system that only operates 16 h/day,
based on the usage profile. However, by adding thermal storage (in this case, chilledwater storage), the load profiles can be shifted and the system peak requirements
reduced. In this way, the capital cost of the CHP system is less, while the operating
hours are increased, resulting in considerably improved return on investment. Much of
the cost of the chilled-water storage system can be offset by the reduction in power and
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chiller capacity requirements. Figure 2-7 shows the chiller production profile for August,
when a chilled-water storage system is incorporated into the project.
The CHP system is sized to drive electric chillers that charge the chilled-water
storage tank during non-operating hours, which is then used to supplement the
noncooling power requirements during operating hours. The chilled-water storage
system is fully charged before the main cooling load is applied and provides a large
portion of the facility cooling needs during the day. Thermally activated chillers use the
waste heat of the CHP plant to supplement the chilled-water storage system during
operating hours, and the electric chillers are available to meet peak needs when
necessary. By using chilled-water storage, the CHP system can operate 24 h/day, the
peak electric demand of the facility is significantly reduced ,and the electric chiller
capacity is significantly lower than that of the non-CHP design.
A more common use for thermal storage is found when applying CHP to a
domestic hot-water load. Although average DHW loads can be very consistent from
month to month, the daily variations can be extreme and, as noted previously, CHP
system output is typically consistent for all hours. For applications such as hotels,
there is high DHW demand in the mornings associated with showering and breakfast
preparation, low demand in late morning, medium demand through the afternoon and
early evening associated with meals and kitchen clean up, and low to no demand
through late evening and night. Hot-water storage allows the CHP system to store the
thermal output until it is needed and, as demonstrated in the cooling application above,
it also allows a system whose output is lower than peak demand requirements to
potentially serve the full load. As peak demand hits in the early morning, the thermal
storage system is at full capacity and works in conjunction with the continued output
Figure 2-6. Mall Summer Day Electric Demand Profile
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from the CHP plant to meet the peak needs even though the continuous CHP output
may be less than half of the peak demand.
Thermal storage in the form of hot water or chilled water can require substantial
space to be effective. Increasing the temperature range of the storage media versus the
needs of the facility will increase the energy density per unit volume and minimize
storage space requirements. For example, when implementing a tank to store domestic
hot water that is delivered to the point of use at 120°F (49°C), the tank can simply be
added to the primary loop. The hot water is raised from a feedwater temperature of 60°F
(15.5°C) to the required temperature of 120°F (49°C) using a heat exchanger, and each
gallon of stored water holds 60°F (15.5°C) of temperature rise. However, if a second
heat exchanger is added between the storage tank and the delivery loop, we can raise the
temperature of the stored water close to the limits of the CHP plant hot-water temperature
and increase the energy density per unit volume. If the stored hot water is increased to
180°F (82°C), then the storage capacity per unit volume can be doubled by comparison
to the inline storage tank. This method also allows for multiple temperatures to be
provided from the same storage system. By the same methods, ice can be used to increase
the storage energy density per unit volume for cooling systems. Care must taken to
maintain temperatures within an acceptable range, and it should be noted that ice storage
systems typically require separate chillers designed for low evaporator temperatures.
New thermal storage media including sensible, latent, and thermochemical heat
storage that increase the energy density and, therefore, reduce space requirements are a
subject of continuing study with added impetus when considering the ability to store
solar thermal energy. Phase change materials offer some advantages over traditional
Figure 2-7. August Chilling Profile
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sensible-heat storage methods and could offer higher energy density as well as high
temperature storage. Hot-water, chilled-water, and ice storage are commonly used in a
large variety of applications, with ice storage being a very cost-effective phase change
medium with characteristics suitable for space conditioning and turbine inlet air cooling.
2.8 LOAD MEASUREMENT AND LOGGING
Most electric utilities collect what is typically called ’interval data,” which is a
measure of the demand at specific time intervals, typically 15 or 30 min. These interval
data can be requested from the utility and provide a resolution on electric load that is
sufficient to understand the majority of electric load applications. Where variations
fluctuate more rapidly than interval data can capture, there are often power quality
issues that must be addressed. Measurement of current and voltage in intervals of
1 min or less should not show significant differences against utility interval data unless
there is an issue with power factor or power quality. In applications where there are
concerns regarding power quality, measurement of voltage and current across each
phase should be taken at least every minute.
Thermal energy is more typically not measured in sufficient detail to provide the
resolution required for reasonable development of thermal load profiles. Where
feasible, thermal loads should be measured in 3 to 15 min intervals at the point of
interconnection with the CHP system. Thermal measurement should include flow,
pressure, and temperature. For steam systems, the output steam flow pressure and
temperature and the inlet feedwater temperature to the boiler should be measured. For
thermal loops, the flow and supply and return temperatures should be measured. The
media specific heat and density also should be identified for thermal loops. For hot-air
systems, the supply temperature and return temperature should be measured for systems
that return all or a portion of the hot air to the supply side. Thermal loops are normally
subject to ambient conditions, and measurement of the various parameters should
ideally be recorded over a 1-year period.
2.9 PRIME MOVER SELECTION
The selection and sizing of prime movers is an iterative procedure in which the
electric and thermal characteristics must be contrasted with load requirements. The
selection of prime mover not only defines the electric characteristics but also determines
the volume, type, and quality of thermal output available. Once the electric base load is
understood, the selection process can begin. Some of the more significant considerations
are as follows:
• Equipment Sizes: Reciprocating engines are readily available in a broad range
of sizes from tens of kilowatts to 3000 kW. Larger, slower-speed reciprocating
engines approaching 10 MW are available on a more limited basis, often requiring
more extended delivery periods. Steam turbines are available in a broad range of
sizes from hundreds of kilowatts to hundreds of megawatts and are usually designed
to meet specific steam quality and load requirements. Simple-cycle combustion
turbines are available in a wide range of models, typically starting at 1 MW.
Recuperative turbines and microturbines are available in smaller sizes under 1 MW,
with some limited availability of recuperated turbines in larger sizes. Fuel cells are
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available in a variety of sizes depending on the technology chosen and can be used in
multiples to address loads of 1 MW or higher.
• Thermal/Electric Ratio: The thermal versus electric efficiency of the CHP
system in heating and cooling modes determines the thermal/electric ratio, which
can be adjusted with different equipment selections to meet the needs of the facility.
• Required Steam Pressure or Water Temperature: CHP system thermal
capacity and efficiency are derived from both the prime mover setting the input
temperature and the load setting the outlet temperature. Temperature, pressure, and
quality requirements of the loads to be addressed will determine the feasibility of
the many options.
• System Availability: Reciprocating engines typically have annual availabilities
of 7800 to 8300 h compared to 8200 to 8600 h for turbines. Reciprocating engines
require more frequent maintenance with shorter maintenance intervals compared to
combustion turbines, which may be an important design consideration for critical
and emergency loads, areas with high transmission and distribution demand charges,
or areas with difficult service access. Availability may not be a major technical
concern, because utility-supplied power and conventionally supplied heat may be
readily available, but it can have significant impact on cost savings related to demand
charges in some areas.
• Maintenance Requirements: Base-loaded turbine maintenance costs, on a cost
per kilowatt hour or horsepower-hour of output, tend to be lower than similar costs
for reciprocating engines. Scale also influences maintenance costs, with smaller
systems generally costing more per unit of output.
• Start-Up Requirements: Natural-gas-fired reciprocating engines are capable of
assuming full load within 1 to 3 min of a signal to start up. Gas turbines require
longer start-up periods, ranging from a few minutes for small turbines to significantly
longer for larger turbines. Start-up of steam-turbine-based systems typically requires
several hours. Start-up characteristics, together with the ability of the prime mover
to accept load and maintain frequency and voltage (block loading capacity), are
important when considering CHP as a source of standby and/or emergency power.
• Utility Costs: Gas costs generally vary little from region to region, whereas
electricity costs can vary widely from region to region. In regions with high electric
costs, CHP systems with high electric efficiency versus thermal efficiency generally
provide a greater advantage in operating cost.
2.10 TYPICAL APPLICATIONS
The following narrative discusses some of the issues related to CHP system design
for a variety of applications. This is not intended to cover all issues but to highlight
those that should be taken into consideration when reviewing these applications.
2.10.1 Hospitals
Hospitals and residential health care facilities are regarded as prime applications
for CHP because they operate 24 h/day, 7 days/week, and have coincident electric and
thermal loads. Hospitals also are generally designed with central thermal distribution
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systems for heating and cooling as well as domestic hot water. In addition, health care
facilities can benefit from the increased reliability offered by CHP, which, in the event
of a utility power outage, can allow more of the facility to operate in grid isolated mode
than would be possible under existing backup power systems mandated by law.
Though relatively few hospitals have implemented CHP, this is generally regarded
as a hospital management and administration issue rather than a reflection of actual
technical or economic potential. As a measure for reducing operating cost in highspark-spread areas, increasing power reliability, and reducing emissions, CHP is
perhaps the single most efficient method to achieve these ends.
Because of the constant requirements for power and space conditioning as well as
domestic hot water, food service, and, in some cases, laundry, hospitals have a suitable
thermal/electric ratio for CHP. Space conditioning is regarded as a critical element of
many hospital tasks, with high-income process centers such as operating theaters and
magnetic resonance imaging requiring precise temperature control to stay online. Many
hospitals in today’s environment not only require operation of the air-conditioning
system to maintain income, but also may require operation of the ventilation system to
prevent the spread of disease. Because of the diverse requirements for temperature and
humidity levels in different sections of the hospital, many hospitals’ cooling systems
are designed to meet the maximum humidity control requirements and then use reheat
to adjust temperature for each space. This method offers stable operation and precise
control of individual spaces but also uses significant amounts of energy. Though
cooling is required as part of a CHP plant in most circumstances, the reheat needs,
combined with domestic hot-water requirements, can provide substantial heating loads
all year round.
One of the major issues that may affect the design of a CHP plant in a hospital
application is the utility power supply and the facility’s electric grid infrastructure.
Hospitals are required to have two separate power feeds to the facility and may normally
operate with each feed powering separate load buses. In this scenario, the entire load
can typically be operated as a single bus from either of the utility feeds by closing and
opening various bus-ties. To obtain the maximum advantage from a CHP system, it
most likely will be desirable to operate the load as a single bus so that all of the power
loads can be addressed. Inverters can be used to allow a single CHP system to address
two load buses, but this does add to the CHP system expense and space requirements.
2.10.2 Food Production
Generally, food production facilities are a good target for the application of CHP
because of their coincident thermal and electric loads. Depending on the type of
processing taking place, the thermal needs may be either heating or refrigeration or
both and may also include process cooling. When heat processes are used, care must be
taken to ensure that the specific temperature and quality requirements are met. In
applications where there is direct injection of steam or hot water, the portion of the
CHP system that generates the heat may have to comply with FDA requirements.
When considering food production facilities that require large amounts of food
storage, refrigeration is normally a significant load. Depending on temperature and the
design of the specific system, it may not be easy to integrate CHP refrigeration systems.
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Many existing refrigeration systems at food processing facilities are ammonia-based,
direct-expansion (DX) systems using central two-step, electric-motor-driven
compressors. In this scenario, it is difficult to integrate a thermally activated ammonia/
water absorber into the refrigeration system. Subcooling of the DX system refrigerant
vapor is a common target for applying CHP cooling, but this does require “cutting
into” the existing system, and there are often limitations on the ability of the compressors
to receive cooled or condensed vapor.
Though domestic hot water for cleaning purposes can be a large load, it is often an
intermittent load with very high use for a few hours at the end of a production run and
little to no use during production. These loads should be carefully examined for needs
and duration, and the CHP plant will need to be designed to meet the rapid temperature
rise required for very large volumes. Hot-water storage is an option to facilitate the
application of CHP to such a load.
2.10.3 Supermarkets
Although supermarkets do have coincident electric and thermal loads and long
operating hours, much of the space cooling is provided by the refrigeration systems such
that there may be little space conditioning required, particularly for stores with a large
component of open refrigerated cases. Heat can also be recovered from the refrigeration
compressors to provide domestic hot water, reheat, or space heating in winter. Large and
continuous refrigeration loads do exist but can present a problem for the application of
CHP, because integration of the CHP output with the refrigeration system is difficult.
Typically, multiple banks of compressors are used to provide different temperature
conditions to various sections of the store. Refrigeration vapor subcooling can be
implemented to relieve compressor motor power use, but this requires integration of the
CHP chiller output with the refrigerant lines using heat exchangers because the
refrigerants are not compatible. This is costly when multiple refrigeration loops must be
addressed and the CHP unit is not close by; the impact of this on compressor system
operation should be studied carefully. In humid environments, the thermal output from
a CHP system can be used to regenerate a desiccant for an easier and less costly approach
that can provide substantial benefits with less risk to facility operation. Domestic hot
water needs are typically small and fed from desuperheater thermal recovery units.
Space heating is a valuable load in colder climate regions.
2.10.4 Multifamily Residential
Large, multifamily residential buildings with significant common areas that are
conditioned by a central plant or with submetered central heating and cooling systems
are good applications for CHP. Larger buildings not only provide the economies of
scale but also have core thermal loads that benefit the application of CHP. Though
multifamily residences have significant space-conditioning loads, they can exhibit low
loads during shoulder seasons in many climate regions, and sizing should be sensitive
to development of an acceptable thermal load factor throughout the entire year. Space
cooling as well as space heating is typically required to enable selection of a larger
system while maintaining a high annual thermal load factor. Where domestic hot water
is provided by a CHP system, the high variation in demand must be taken into account,
and storage should be considered.
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2.10.5 Data Centers
These applications provide steady-state electric and thermal loads and are highly
amenable to CHP. For every unit of power put into a server, a unit of heat is produced
and must be removed. In terms of thermal/electric ratio, for every kilowatt of power
provided to the computer servers, 1 kW (0.28 tons) of cooling must be provided. Many
engines integrated with a single-stage absorber can provide a T/E ratio close to 0.28
tons per kW (0.98 kWC/kWe), which allows for a one-to-one matching of electric and
thermal loads with the CHP system at 100% load factor.
Although the T/E ratios of the load and CHP system are well matched, there
remains a considerable issue of concern relating to power system fault protection as
well as issues relating to space availability and location of equipment. In addition, the
lack of publicly available performance data specifically for CHP at data centers has
hindered the industry’s ability to understand the technology’s risk profile. These issues
have generally prevented the wide adoption of CHP for data center applications,
because data center design engineers are very reluctant to compromise power system
integrity and need a high level of performance predictability before introducing new
technology. It is anticipated that the wider use of inverters will help mitigate fault
issues, and development of modular CHP systems as well as the continuing deployment
of CHP will address the predictability issue.
2.10.6 New Buildings
CHP systems can be cost effective in new construction, where CHP system installation
costs are usually lower than would be the case for a retrofit application. In addition, if the
CHP system eliminates the need for a conventional piece of equipment, such as a second
or third boiler or an emergency generator, the cost of that equipment could be credited to
the CHP system budget, improving the return on the CHP system investment.
The evaluation of a CHP system for a new building faces several problems not
encountered in retrofit applications. The first of these is the uncertainty of the final
“conventional system” design. With the increasing use of fast-track techniques,
construction work is frequently started before finalization of the mechanical and HVAC
systems design. CHP system components have longer lead times than many more
conventional systems; therefore, a decision to develop a CHP system may be required
prior to ordering conventional equipment. Moreover, while the number and size of major
pieces of equipment may have been determined early in the fast-track process, there may
have been only limited modeling of energy requirements and costs. Because there may
be little information on projected conventional loads and costs, the CHP system analysis
may be required to also include the detailed analysis of conventional energy systems.
One useful source of information on energy loads in new buildings is data for
existing similar buildings; however, changing design practices and increased energy
and environmental concerns may introduce significant changes in the energy
requirements of new buildings. Technology and process changes, differing occupancy
patterns, and a number of other factors can also result in significant changes in loads.
One common technique for quantifying loads and evaluating the performance of
alternative building systems is a computer simulation. There are a number of commercially
available programs that have varying input requirements. Simpler techniques use nothing
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more than monthly data, whereas more comprehensive programs can accept building
design, use, occupancy, and weather data as a basis for computing projected hourly
energy requirements; these loads are then used as a basis for modeling the performance
and costs of alternative on-site systems. At one extreme, these programs are based on the
computation of loads for every hour of the year. Other, less comprehensive programs
model the performance of the building for a limited number of days per month or months
per year to approximate the results obtained by modeling all 8760 h in the year. The cost
of modeling is usually in direct proportion to the comprehensiveness of the model, and
the approach to modeling should be consistent with the level of decision making. Monthly
data and modeling may be more than adequate at initial stages of evaluation, while
detailed hour-by-hour modeling for 8760 h may be more appropriate for final design
choices and investment decisions.
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CHAPTER 3
CHP SYSTEM DESIGN CONSIDERATIONS
Many considerations are involved in designing the optimal CHP plant that meets
the project goals. Load use and demand are clearly major considerations but may not
provide the whole input required in the decision on CHP system design. However, load
use and demand data will provide the required information to properly assess how the
CHP system will perform once it has been selected. Therefore, these data must be
properly understood as a first step. Load profiles are developed both to properly
understand the loads throughout the year and to provide a baseline against which the
output of the CHP system can be examined. Simple visual inspection of the load profile
graphs can help to quickly understand the appropriate size of the optimal CHP system
as well as discover load trends and load anomalies.
3.1 ELECTRIC LOAD PROFILES
Electric demand data, generally available in 15-minute, 30-minute or 1-hour
intervals, provide a very precise baseline for facility electric load profiling. The
precision of these data may be somewhat diluted in situations where the data provided
are actually the aggregated values from two or more meters. In these scenarios, some
effort is required to understand the actual load characteristics for each meter, becauses
only a single meter may be served by a CHP system unless inverters and additional
controls are added between the power output of the CHP system and the loads. The
interval data are usually obtained upon request by the facility owner from the local
utility, which continually monitors and records this information for its own billing
purposes. In some cases, this information may also be downloadable from the utility
web site when access to the account is granted by the owner. Interval data for the full
year is a minimum requirement to properly understand the seasonal variations, and
data for more than one year can be obtained and should be reviewed to properly
understand ambient temperature impact when contrasted against degree-day
information as well as identifying any trends in energy use. The data are normally
provided as a CSV (comma separated value) file that can easily be read by programs
that allow columnar manipulation of data, such as spreadsheet or database programs.
The data are typically provided in terms of kW demand by date, separated into time
values for each day. In some cases, the data may be provided as kWh readings, in
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which case the actual kW demand can be derived by dividing the kWh value by the
ratio of the period to one hour. For example, if the data were provided as kWh readings
in 15-minute intervals, then the actual demand is the reading value divided by 0.25.
If the readings were in 30-minute intervals, then the actual demand is the reading
divided by 0.5.
Figure 3-1 shows an electric profile for an example production facility based on
utility-provided 30-minute interval demand data. Each interval demand value is
graphed against a time scale covering an entire year. This allows for a review of the
facility electric demand through all seasonal variations, providing an indication of the
impacts of ambient conditions on power demand. In this case, it can be determined
that the facility has a base load of approximately 600 kW with an increase of
approximately 200 kW during summer that is presumably related to space cooling. It
is also obvious from this view that there is a trend of high demand during working
days followed by low demand for weekends throughout the year. There are also some
anomalies where readings appear to go to zero for short periods five times during the
year and a single event when the demand increased to approximately double the
normal demand for a short period.
Figure 3-1. Annual Electric Load Profile for Example Production Facility
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A more detailed analysis of the data is required to properly understand what is
happening. Figure 3-2 provides the interval demand data for the two week period
beginning on Monday, January 11, and ending on Sunday, January 24. The profile now
reveals in some detail how the facility operates throughout the week, including weekdays
and weekends. Workdays follow a regular pattern of morning startup, production during
the day, and evening shutdown. Saturday also has some production activity, although less
than normal workdays, and Sunday has no production and represents the minimum load
points. The period selected for this review of a ”typical” two week period does not contain
anomalies or extreme high or low readings. These events will be reviewed separately.
Hourly detail (Figure 3-3) for Monday, January 11, provides a typical winter workday
demand profile, which demonstrates that demand begins to ramp up at 5 a.m., peaks at
around 8 a.m., continues high through 3 p.m., and then starts to diminish until it reaches
base load at around 6 p.m.. Peak load is approximately 25% higher than the base load of
600 kW. Figure 3-4 provides the demand profile for a typical summer workday, Tuesday,
July 28. In summer, load begins to build at 6 a.m. and follows a similar pattern to the
winter workday scenario. Summer workday peak is also approximately 25% higher than
the summer base load of 800 kW.
Figure 3-2. Two-Week Electric Demand Profile for Example Production Facility
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Figure 3-3. Winter Workday Electric Demand Profile for Example Production Facility
Figure 3-4. Summer Workday Electric Demand Profile for Example Production Facility
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As mentioned previously, there are also some anomalies that should be investigated.
The first anomaly was a zero reading that occurred on February 17, a Wednesday.
Figure 3-5 shows the daily demand profile for February 17, and it shows that the
anomaly is related to a single zero reading at 2:00 a.m. The readings before and after
this reading were typical for the period at approximately 550 kW. Generally, there are
three possibilities for such a short duration event: this was either (1) a grid failure, (2)
testing of standby generators, or (3) a meter malfunction. In all events, this does not
affect the design of the CHP system other than possibly enhancing the value of CHP as
a backup system if this and the other similar anomalies were in fact grid failures.
The high demand anomaly is shown in Figure 3-6 and occurred on Sunday,
November 1. For two interval readings at 1:30 a.m. and 2:00 a.m., the electric power
demand surged to almost twice the demand in the previous and subsequent intervals.
The demand recorded of 1386 kW was also significantly higher than the midsummer
peak demand reading of 1084 kW. It is highly unlikely that the facility actually required
this level of power to operate, especially at 1:30 a.m. on a Sunday, which normally is
the lowest load time. The causes for such a surge could either be (1) a fault in some of
the facility equipment causing an inrush of power or (2) a meter malfunction. In either
case, this should be investigated with facility personnel, and, if no fault is recorded, this
should be taken up with the local utility and an adjustment sought on demand charges
for the affected period.
Figure 3-5. Daily Electric Demand Profile for Example Production Facility
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Figure 3-6. Daily Electric Demand Profile for Example Production Facility
The interval data also provide the basis for a load duration curve that will
determine the electric load factor for a given CHP system size and typically establish
the starting point for equipment selection. Using the annual demand profile in Figure
3-1, the base load appears to be around 600 kW. Figure 3-7 provides a graphical
interpretation of the percentage of intervals that are greater than a defined value as
represented on the x-axis. From this graph, it can be determined that approximately
100% of the recorded demands are above 500 kW, approximately 98% are above
550 kW, approximately 85% are above 600 kW, and for loads greater than 600 kW,
the percentage of time that the facility demand exceeds these higher loads drops off
quickly. Only 63% of the intervals exceed 650 kW and only 46% exceed 700 kW. As
discussed previously, 85% is generally an acceptable load factor, and so, based on
load duration and an 85% load factor, 600 kW is the base load for the facility. Also
note that, for parallel interconnection, some import of power is typically required to
meet utility interconnection requirements so that, from the electric load perspective
only, the CHP system would potentially be sized at around 550 kW for this example
production facility.
3.2 THERMAL LOAD PROFILES
If at least 12 months of hourly or higher-definition demand data are available for
the thermal loads, a detailed 8760 h model can be developed against which an hourly
CHP output model can be run for high definition on design parameters including
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Figure 3-7. Electric Load Factor Profile
load factors, efficiencies, and standby or supplemental energy requirements. Although
this type of detailed modeling does provide accurate analysis of CHP performance
against historic data and perhaps can be adjusted for parameters such as ambient
conditions, production levels, and occupancy, it will still have some limitations in
accuracy for future projections. However, this level of data is rarely available for
loads other than the electric loads, and estimates must be drawn from the available
data on how the loads function.
Thermal loads must generally be extrapolated from bulk energy use data, such as
gas usage (therms or gigajoules of natural gas billed to the facility by the gas utility).
In the case of oil and coal, data on delivery quantities are usually available, but these
can range from one delivery per year, as may be the case for a small boiler plant
firing coal, to deliveries that occur every week. In such cases, an assessment must be
made on the monthly use of the fuel, which may best be determined through
discussions with facility personnel. The total fuel throughput must also be adjusted
using the existing thermal conversion devices to calculate the total monthly thermal
loads. This must be further refined to apportion the correct volume of fuel to each
addressable load. In the absence of individual data for each load, estimates should be
made for the portion of energy use associated with each load. Figure 3-8 shows the
breakout of addressable loads developed from monthly energy use, review of existing
heating and cooling equipment, and discussions with facility personnel.
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Figure 3-8. Monthly Thermal Use Profile
Note that most utilities read meters on a regular basis; however, they are not usually
read on an exact calendar basis. In addition, the number of days in a billing month may
not be the same as the calendar month, and it is frequently necessary to adjust utility
billing data for the number of days in the billing cycle. In general, it is useful to review
three to five years of historic billings or monthly fuel use data to identify long-term
trends and to assess whether the most recent 12-month data, which are generally the
basis of CHP system modeling, are typical.
It is necessary to use any available data to develop profiles, often augmented by
short-term data collection or supplementary submetering. Metering of boiler feedwater
may provide a reasonably accurate and inexpensive measure of steam production,
although it is necessary to quantify steam system losses. In other cases, it may be
necessary to monitor raw water use. Periodic readings of the gas meter, when used with
an inventory of gas-fired equipment and with more generic data such as water use
patterns, can serve as a basis for constructing thermal profiles. Previously conducted
energy audits may provide a useful source of energy data, if they included any primary
data collection. Audits will frequently include short-term metering or other data
collection efforts that can be the basis of information required for the CHP system.
They can also identify existing site problems, anticipated changes, and other factors
that should be considered in any CHP system analysis. To the extent that these audits
may have been funded by an energy supplier, equipment vendor, or third party seeking
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to enter into some form of externally financed or shared savings venture, the objectivity
and usefulness of the audit should be independently assessed.
Plant logs are another useful source of data; however, it is important to fully
understand the basis of such logs. When during the day or shift are data entered? Are
data taken at the same time each day or during successive shifts? Are the terms used on
the log consistent with generally accepted practice? Are the data available from the logs
consistent with metered, utility-supplied data?
Once these estimates have been developed and monthly use profiles developed, the
data must be further refined to calculate the load usage during operating hours for a
facility that does not support 8760 h operation of a CHP plant. The resulting addressable
loads during operating hours must then be analyzed to determine base, average, and peak
demands so that the true load factor for the CHP system can be developed. The resulting
loads should be compared to actual energy use to verify the accuracy of the profiles.
3.3 CHP SYSTEM CONFIGURATION OPTIONS
CHP systems sequentially provide electric or mechanical power and heat from the
same fuel source. The first energy stream produced by a topping-cycle CHP system is
power, and the waste heat created in the generation process is then recovered through a
variety of devices and converted to useful energy that can be applied to facility loads.
In topping cycles, the prime mover that generates the power can take a number of
forms, such as reciprocating internal combustion engines, combustion turbines, or fuel
cells. Each prime mover has different characteristics, both in terms of the amount of
input energy that is converted to power and heat as well as the form that the heat or
thermal output takes. In bottoming-cycle CHP systems, fuel is burned to first create
thermal energy that is then used to drive a power generation device such as a steam
turbine or organic Rankine cycle generator.Residual thermal energy is then typically
used to serve a thermal load.
The basic elements of a CHP systems’ primary function of providing power and
thermal energy can be fully described in terms of power and thermal efficiency. Among
many other characteristics to be considered, the first CHP configuration option to be
reviewed is the thermal/electric (T/E) ratio, which is a function of the power and
thermal efficiencies of the system. Described in Section 2.4, T/E ratio is a primary
criterion in matching the facility loads with the appropriate CHP configuration.
Typically, all topping-cycle CHP systems have a nominal overall efficiency of
approximately 70% higher heating value when taking into account electric or mechanical
power plus recoverable thermal energy at useful conditions. Bottoming-cycle systems
have CHP efficiencies of approximately 80%. CHP system efficiency can be increased
if the system is applied to a thermal load that requires low-quality heat, but for most
applications the load temperature requirements keep the overall efficiency at these
levels. Different CHP configurations will provide an option on the level of power
efficiency versus thermal efficiency such that, for example, a topping-cycle system may
have 30% electric and 40% thermal efficiency or 40% electric and 30% thermal
efficiency. Bottoming-cycle systems generally have lower electric efficiencies, ranging
from 15% to 25%, with thermal efficiencies of 65% to 55%. The selection of an
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appropriate T/E ratio to match the load will help to define possible CHP configurations.
Although the specific level of thermal load required may be contingent on which and
how many of the addressable loads can be brought to the CHP system, review of the T/E
ratio for the facility should help in refining the number of CHP configuration options.
Because prime movers are often described in terms of their nominal electric
efficiency, there may be a natural inclination to believe that the 40% efficient engine is
“better” than the 30% efficient engine. However, generally the “better” engine is the
one that best matches the load. A 40% electrically efficient engine will convert more of
the fuel to electricity and less to thermal output. If the application is limited by the
electric base load and has a higher thermal load than the CHP system’s output, then a
better option may be to select an engine with a lower electric efficiency so that more of
the fuel is converted to thermal energy, and more of the thermal load can be provided
by the CHP plant. Applications such as district heating systems that use bottomingcycle configurations require very high T/E ratios, because the system addresses large
thermal loads, with relatively small electric loads available in the plant. In cases where
the limiting factor is thermal load availability, the higher electrically efficient engine
will be able to provide more power while still maintaining a high thermal load factor.
From an economic perspective, the better option should be reviewed against energy
costs to determine how to optimize fuel conversion efficiencies. A CHP system’s T/E
ratio is a function of the cycle, prime mover type and design, heat recovery system,
thermal conversion technology design, and the load quality requirements.
A second CHP system characteristic is equally important in determining the CHP
configuration that best meets facility needs. Systems that provide high-temperature
energy streams are more easily applied to various loads, whereas lower-temperature
systems have some restrictions on the type of loads they can serve. For example,
non-recuperated combustion turbines that have an exhaust temperature of 850°F
(454°C) can generate high-pressure steam without losing much of their heat recovery
potential, whereas a recuperated combustion turbine with an exhaust temperature of
600°F (316° C) will lose a considerable amount of its heat recovery potential if highpressure steam is required. However, both systems will retain high heat recovery
potential if they are designed to produce hot water at 160°F (71°C), for example.
When designing a CHP plant for a specific application, there are numerous issues
beyond load data and project goals that affect the outcome. A facility may meet all the
general requirements for the application of a specific CHP plant size and configuration,
but fuel availability or emissions limitations may prove an overriding concern that
either changes the design or eliminates the use of CHP altogether. The main issues are
discussed in brief in the following sections.
3.3.1 Power Quality
Power quality is not only an important issue from the facility owner’s perspective
but is also important in determining the suitability of the site for the application of
on-site generation. Poor power quality can negatively impact the performance and life
of a CHP system and can prevent the application of on-site generation. Power quality
issues such as voltage fluctuations, high reactive currents, high levels of harmonics, or
phase imbalance will cause the system to underperform, may cause damage to system
components, and may prevent the CHP generator’s ability to connect to the load.
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3.3.2 Fuel Characteristics
The characteristics of the fuel supply to a CHP unit will affect the project in many
ways. The first determination that should be made when investigating a site is fuel
availability. The fuel throughput of the CHP system can easily be calculated and must be
provided to the local gas utility or other fuel source to verify that the supply is in fact
available. In many instances, the application of CHP will increase the peak fuel
throughput in a facility that has an existing supply, and so availability must also be
verified for such cases. Fuel pressure is also an issue, because many prime movers
require high-pressure fuel to operate. In particular, combustion turbines require from
60 psig (414 kPa [gage]) for the smallest units to 300 psig (2069 kPa [gage]) and above
for larger units. Reciprocating engines and fuel cells generally require from under 5 psig
(35 kPa [gage]) for smaller units to over 15 psig (103 kPa [gage]) for larger units. Fuel
pressure can be augmented with gas pressure boosters/compressors, but these systems
can use a significant amount of the power generated by the system, typically ranging
from under 3% for smaller combustion turbines to over 5% for larger units with lowpressure supply. When a CHP system is being supplied with biogas, the parasitic booster
requirement can be higher, because the pressure at the supply point can be close to zero.
Fuel quality also must be checked and, whereas natural gas “pipeline quality” fuel
is typically acceptable for many engines, higher-performance engines and fuel cells may
have fuel quality requirements that exceed that provided by the local utility. It is
important to recognize that not all gas supplies are of equal quality, with many gas grids
accepting synthetic gas or other forms of gas that may have a deleterious effect on the
gas quality, particularly just downstream from the point of injection. A fuel quality
statement should be obtained from the gas utility and provided to the engine supplier to
confirm compatibility.
When considering CHP systems that are fueled by biogas or synthetic gas, a higher
level of investigation regarding fuel energy content and impurities is required. Gas
pretreatment equipment will most likely be required to remove moisture, sulfur, particulate
matter, siloxanes, and other impurities. In addition, the operation and performance ratings
of the engine must be characterized for the specific energy content of the fuel. Low energy
gases, such as municipal wastewater treatment plant anaerobic digester gas, are compatible
with many engines, but these engines must be configured for the application and will not
perform at the same capacity or efficiency as if that engine were configured for typical
pipeline quality natural gas. Gas cleanup requirements can be relaxed if higher maintenance
costs and more frequent maintenance intervals are allowed, but there may be little option
to implementing high level gas pretreatment equipment if engine exhaust aftertreatment
is required, because fouling of catalysts can occur very quickly if fuel quality is low.
Solid fueled biomass, such as woody biomass, can be directly combusted in a boiler
to produce steam that turns a backpressure steam turbine to generate power, with the
exhaust steam going to process or heating. Alternatively, the biomass can be pyrolyzed to
produce syngas, which can be combusted in an engine to produce power and heat. In
these CHP systems, the fuel quality and energy content is a function of the type and
moisture content of the biomass as well as the combustion or pyrolysis process used.
Such systems are generally designed around the specific feedstock and must be
appropriately sized to the throughput of fuel necessary to provide the energy output
required by the facility.
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Although natural gas is the predominant fuel for CHP systems in the continental
United States, CHP systems can also be operated with a variety of fuels, including diesel
or propane. In all cases, the fuel specifications should be reviewed with the prime mover
supplier to ensure that the available fuel quality is in line with the manufacturer’s
requirements as well as its impact on warranty, maintenance, and emissions.
3.3.3 Electric Interconnection
Interconnection with the electric utility grid provides a number of benefits to CHP
systems, including the availability of supplemental and standby power, increased
reliability, and operating flexibility. See section 8.1.2 for further information on utility
interconnection categorization. Most CHP systems are interconnected to the electric
utility grid, and interconnection issues are a critical concern in the design and operation
of a CHP system. Though utility interconnection issues typically deal with protection
of the utility from the effects of the CHP system, it is also necessary to consider
protection of the on-site generator from problems caused by the utility grid. Utility
interconnection concerns include the following:
• Power Quality: One utility concern is that an interconnected on-site generator
should not degrade the quality of power supplied by the utility as measured by
voltage and frequency stability, power factor, and harmonic content. In general,
with the exception of induction generators and inverters, the quality of power
available from an on-site generator will exceed the quality of power that is available
from the grid. From the owner’s perspective, poor grid power quality, whether
caused by facility loads or the utility, are of equal concern. Short-term metering
to document power variations of a few seconds or less may be required where the
end-user processes are characterized by short, significant changes in load. In this
case, it is necessary to establish that the selected prime mover can respond to
short-term variations in load.
• Power Safety: Utilities are concerned that an interconnected generator has the
potential to energize a utility circuit that is not being powered by the utility. This
condition can result in a safety hazard to utility personnel working on that circuit.
Most utilities will require the CHP system to install a reverse power relay and an
external disconnect switch that is accessible by utility personnel and that can be
used to disconnect and lock out the CHP system. For systems that are designed to
export power onto the grid during normal operation, additional protective devices
will be required to ensure the utility that the generator can be disconnected when
required. These devices generally must be reviewed by and meet the approval of
the electric utility before an interconnection will be allowed.
• Grid Fault Protection: Utility operation of the grid can be quite complex and
include the coordination of relays, switches, and fault control. The interconnection
of a CHP system or any other active source of power within the grid generally must
be reviewed by the utility to avoid jeopardizing the ability of the utility to manage
grid operations.
3.3.4 Ancillary and Other Equipment
Power-house ancillary subsystems such as water treatment, power supply, condensate
return, deaeration, cooling towers, and controls are used to support the CHP system. If
existing subsystems are to be used, then they must be adequately maintained, have
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sufficient capacity, and be able to provide the quality required for the CHP system. If the
existing subsystems are not adequate, then the cost of new subsystems and equipment
should be included in the CHP project budget.
Major existing energy components such as boilers, hot water generators, emergency
power generators, and chillers will often still provide for the needs of the facility
beyond the capacity of the CHP system. When CHP plants are designed to meet baseload requirements, the additional load is typically met using the existing equipment in
parallel with the CHP plant. In some situations, the installation of a CHP system may
defer or eliminate the need to replace a major component, thus providing a capital cost
credit toward the project. For new construction or major renovations, the installation of
a CHP system can be integrated with the installation of other major components,
including boilers and chillers, thus minimizing total project cost. In all scenarios and
particularly where existing equipment is used to support a new CHP plant, it is
important to review the equipment loads when the CHP system is fully operational
in order to ensure that the existing ancillary equipment has the turndown necessary
to accommodate the CHP plant. For example, where a CHP plant that generates
9 million Btu (9.5 GJ) or steam is added to an existing facility with a 300 hp steam
boiler (10 million Btu/h) (2943 kW) that is at times fully loaded, it will be necessary
to either adjust the existing boiler to provide for stable operation at 1 million Btu/h
(294 kW) or add a new small boiler to provide the supplementary steam. It is not
unusual that existing facilities have boilers that cannot operate efficiently below 30%
of their nominal capacity such that, if the CHP thermal output is slightly less than the
load, a new boiler may need to be incorporated as part of the CHP plant.
It is also important to recognize that, while CHP may provide a less costly source
of power and thermal energy, it will not solve preexisting problems with the site steam
and hot- or chilled-water systems or inadequacies in the power distribution system or
automated control systems. Any CHP review or audit should attempt to identify any
such inadequacies in the facility thermal and electric distribution systems which should
be fixed before installation of a CHP plant. Equally, any potential energy efficiency
measures that would impact the loads intended to be addressed by the CHP plant should
be implemented before installation of CHP equipment. Addressing such issues after
installation of CHP may not only result in wasted resources, but also lead to poor
performance of the CHP plant, resulting in lower efficiencies and higher-thananticipated maintenance costs.
3.3.5 Emissions
Local air quality emissions requirements for stationary engines, fuel cells, or boilers,
in the case of biomass CHP systems, are an important consideration for CHP system
design. Most projects, as a minimum, are required to ensure that project emissions
comply with local air quality requirements as defined by the local jurisdictional authority.
(See Chapter 10 for further information on emissions considerations.) This may require
the addition of exhaust aftertreatment devices, which must be included in the project
capital cost as well as operation and maintenance costs, because most of these devices
do consume chemicals and require replacement of components. Lower restrictions may
be placed on renewable fuels, such as landfill gas or digester gas, but if these systems
require exhaust aftertreatment, then a high level of gas pretreatment will most likely be
required to prevent fouling of any catalysts used for exhaust aftertreatment. Consideration
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must also be given to the location of the point of emissions or the stack. The location
must comply with local regulations that normally prescribe distances from air intakes,
open windows, etc., as well as sensitive receptors (people).
3.3.6 Noise and Vibration
Rotating machinery, such as reciprocating engines, combustion turbines, and
compressors, generate noise (unwanted sound) and vibration that can not only impact
facility equipment and personnel but also neighboring facilities and residents. Excessive
vibration without proper control can cause damage to equipment as well as adjacent
equipment and structures. Occupational Safety and Health Administration (OSHA)
regulations and community zoning laws in the United States generally specify
permissible noise levels for on-site personnel and at the neighboring property line,
respectively. Permissible levels are normally denominated in decibels (dB) and can
vary according to time of day. In some areas, more recently developed zoning laws
specify permissible noise levels in terms of octave band frequency levels. The noise
produced by the CHP system must be added to existing noise levels before the system
was installed to calculate the post-CHP noise level. CHP systems can generate
significant levels of noise from multiple components, including engines, engine
exhaust, compressors, and cooling fans. Noise generated by these components can be
reduced or attenuated using acoustic insulation, acoustic barriers, air attenuation
baffles, and exhaust silencers. Vibration reduction will not only contribute to noise
reduction but is also necessary between rotating machinery and connected structures,
piping, ductwork, and equipment. Vibration reduction is normally accomplished by
mounting the equipment on spring vibration isolators and using flexible couplings
between the rotating machinery and other equipment, piping, and ductwork.
In almost all cases, CHP equipment requires noise attenuation and vibration
isolation. This should be considered in the beginning phase of design and may require
input from an acoustic specialist in sensitive areas, such as locations close to residential
developments, libraries, theaters, and health care facilities. Consideration also should
be given to other sources of vibration and their potential to interfere with CHP
equipment operation. Locations should also be checked for existing sources of vibration
that might impact the operation of the CHP plant components, which are typically
comprised of high-speed rotating machinery that is also sensitive to high levels of
vibration. In some cases, the location of the CHP plant may need to change to mitigate
noise and vibration issues if other methods cannot provide sufficient attenuation.
3.3.7 Maintenance Requirements
CHP plants depend on continual operation of all components, including the prime
mover, thermal recovery and conversion equipment, and accessories such as gas
pressure boosters, controls, pumps, and exhaust aftertreatment. Continual maintenance
is required to sustain the performance and reliability of the plant as well as maximize
the life of the equipment. Compliance with emissions standards on a long-term basis
also requires that the plant and accessory equipment including fuel treatment and
emissions aftertreatment be properly maintained. Maintenance costs can be a significant
part of the total operating costs, typically representing up to 30% of operating costs
when including engine rebuilds or core changeouts. Maintenance requirements for
various types of prime movers vary considerably, but to maintain a plant in good
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working condition through its full life cycle, the requirements should include full
overhauls or changeout of major components. The main variable in terms of maintenance
requirements is the frequency of maintenance intervals, which can be a design
consideration, particularly for critical or remote applications. For more detail on
maintenance requirements for each type of prime mover, see Chapter 6.
3.3.8 Operating Requirements
Most CHP prime movers are designed to operate automatically, with load control
typically a function of either power or thermal load requirements. Electric utility grid
interconnection normally requires automation of the prime mover to ensure compliance
with interconnection agreement rules. Remote monitoring has typically supplanted
on-site monitoring so that, in many cases, there is little to no interaction between on-site
personnel and the prime mover. In contrast to the prime mover, which requires
specialized operation skills, operation requirements for heat recovery and thermal
conversion equipment are typically the same as those for standard boilers, heat
exchangers, absorbers, or other such equipment. Generally, CHP plant thermal
equipment is subject to existing equipment labor regulations such that, if the CHP plant
were generating high-pressure steam, and regulations require a specific boiler licensed
personnel to operate such equipment, then the CHP plant thermal equipment will be
subject to the same requirements. In many scenarios, it may be most cost-effective to
have the existing boiler/chiller plant personnel operate and maintain the CHP plant
thermal equipment, while specialized companies provide operation, monitoring, and
maintenance of the prime-mover equipment.
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CHAPTER 4
CHP APPLICATION ASSESSMENT
A CHP application assessment is a multistep process. To develop the appropriate
level of information as well as control costs through the decision-making process, these
steps provide higher levels of detail as the process proceeds, with each step providing
sufficient guidance to make a decision that allows the process to move to the next step.
In some situations, the first steps may be skipped if sufficient knowledge of site loads
and CHP technology exists. The ultimate goal in CHP assessment is to provide an
investment grade engineering study that delivers sufficient detail to all parties concerned
to make a decision to proceed with the project. The results are engineering-based and
should provide statements of pre- and post-CHP facility energy use and energy cost,
existing systems operation impact and utility rate impact, as well as a capital and
operating cost estimate for the project, including maintenance.
A number of issues should be addressed early in the process to identify
considerations that would either prevent further action or enhance the value of a CHP
plant. Early involvement of the senior decision makers should also be incorporated
where possible, so that all issues can be understood and the goals of the project clearly
identified. In many circumstances, matters such as environmental considerations,
power availability and quality issues, standby power requirements, plans for future
expansion or contraction, pending equipment replacement, and financial standing can
have significant impact on feasibility, performance, design, and benefit. It is necessary
to develop economic and technical measures of CHP system performance that are
useful and meaningful within the decision-making framework of the end user.
Technical feasibility is based on multiple factors, including
• the existence of adequate concurrent electric and thermal loads and the
availability of natural gas or other acceptable fuels,
• the compatibility of the existing processes or mechanical systems with the
recoverable heat available from a prime mover,
• the availability of space for the siting of the CHP system and the ability to
interconnect with facility thermal and electrical systems, and
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• the adequacy of existing systems, including load management, standby/peak
boilers and chillers, electric grid, switchgear, etc.
Economic feasibility is critical to most projects and can be added to the technical
study and load analysis to determine the costs of operating with or without CHP. For
economic feasibility, the cost saving with CHP must overcome the net capital costs
associated with the project within a time period acceptable to the owner, or the project
must provide an acceptable rate of return on the investment over a specified period. The
first test is called payback, which provides an easily understood metric but does not
fully describe the project economics. The second ”return on investment” test typically
incorporates allowances for inflation, taxes, and the cost of money, and is a truer
definition of the project from an economic perspective, albeit a more complex
assessment. Although the earliest efforts should uncover any potential roadblocks or
“fatal flaws,” the size and complexity of the facility as well as the desired level of detail
will determine which level of investigation is required. If grant application forms
require submission of engineering documents or studies, then the technical data supply
scope of the grant requirement should be included as a study requirement.
4.1 TYPES AND SCOPE OF CHP STUDIES
CHP studies fall into three general categories that vary from a basic screening
study to the investment grade audit that is used to make investment decisions. The basic
breakout in depth and complexity of analysis for an engineering review of a CHP
application are prescribed in the ASHRAE Level 1, 2, and 3 audits (ASHRAE 2011).
Level 1 screening studies are typically based on site energy use data and do not include
a comprehensive review of the facility. These are often provided free of charge by
equipment vendors, CHP developers, or support agencies and should be viewed as a
go/no go decision point for the next phase of engineering review. The next phase of
study is a Level 2 feasibility analysis that provides a more thorough review of energy
use data as well as some level of site suitability for the application of CHP, including a
general assessment of load addressability. If the Level 2 study suggests that CHP is
appropriate for the application, then the next phase of study is a Level 3 assessment
(also called investment grade audit) that requires a higher level of engineering expertise
and effort and is designed to provide a detailed analysis of how a proposed CHP
configuration would perform. Level 2 and 3 CHP analyses are generally provided by
consulting engineering companies (nonaligned with any equipment vendor or project
developer) with experience in the application of CHP as well as energy systems
operation and will also typically require some funds to be allocated to the project.
The U.S. EPA has developed a slightly different approach that is focused on a
single project. This process has two levels that include a Level 1 analysis with a goal to
determine if CHP is a proper technical fit for your facility and if CHP might offer
economic benefits. A Level 2 CHP feasibility analysis is a detailed analysis of the
economic and technical viability of installing a CHP system. A Level 2 study may
consider the return on investment for multiple CHP system sizes, configurations, and
thermal technology options. The Level 2 study normally follows a Level 1 CHP
feasibility analysis and is based on more detailed engineering and operational data
from the site. In essence, the EPA’s Level 2 approach combines the ASHRAE Level 2
and 3 together around a single technical approach such as economic on-site generation,
renewables, or facility resiliency.
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In all cases, the underlying assumptions and valuation made in the development of
load factor and worth of utility offsets and/or capital cost offsets should be transparent
and should be checked for validity. The analysis of CHP should be based on a comparison
between a CHP system and the conventional system that best meets the requirements of
the site and the owner. Thus, if an absorption chiller is not the optimum choice for a site,
it should not be considered as part of the conventional system even if it is included in the
proposed CHP configuration. In this case, the conventional system budget and operating
costs should be based on the operation of an electric chiller, assuming it is the conventional
choice for such an application or existing equipment. CHP energy cost savings would
then be based on the purchased power and maintenance costs of the electric-chillerbased conventional system versus the absorption-based CHP system. Similar concerns
exist with regard to standby engines, conservation, load management, and the overall
design of the site’s processes and HVAC systems. The evaluation of CHP or other
nonconventional options must be conducted within the context of existing equipment or
the alternative conventional system for the site. If that existing system does not currently
operate at reasonable efficiency, it is necessary to determine whether it can be costeffectively restored to efficient operation. For example, CHP may be economical by
comparison to an inefficient boiler plant (e.g., an old and oversized unit operating at an
overall efficiency of 55%). In this situation, the recovered heat would be divided by 0.55
to determine the amount of fuel displaced, and it would be highly valued. However, it
may be more cost effective to improve the efficiency of the existing boiler and increase
its efficiency to 75%. In this case, the value of recovered heat would be decreased by
approximately 36% and the CHP system may no longer be viable.
The selection of the optimum CHP system should be based on the criteria developed
with the project end-user or owner, whether those criteria consider economics, risk,
emissions impact, energy efficiency, reliability, or some other performance measures.
An important decision that should be made early in the process is project ownership.
This can affect several key factors, including capital cost, term of project, operating
cost, and tax treatment. Ownership is based on a number of issues, including risk/reward
acceptance and the availability of cash or alternative funding. If the end-user seeks thirdparty ownership and operation, it may be prudent to limit the detailed design activities
to those necessary to select a third-party concept and to negotiate a third-party contract.
The third-party will most likely want to conduct its own investment grade audit.
In general, the output of the ASHRAE Level 1 or EPA Level 1 study should include
a projected capital budget, CHP-related energy cost savings, projected operating costs
for the CHP plan,t and utility cost sensitivity. As a result of the Level 1 study, the owner
or developer should be able to make a decision as to the general technical approach and
how the project is to be developed.
The output of the ASHRAE Level 3 or EPA Level 2 study should include capital
cost estimates and decisions as to the manufacturer of prime mover, total installed
capacity, the number of prime movers, anticipated operating mode, the approach to
permitting, a project schedule, a strategy for supplemental and standby power, an
approach to fuel supply and purchasing, utility cost sensitivity, and an approach to
maintenance and staffing. The ASHRAE Level 2 or EPA Level 2 study should also
identify the source of data used and any data collection activities that are required
for detailed design, including recommendations for collection of profile data and
measurement of selected power and thermal loads.
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When third party financing or loans are used, there is an additional layer of financial
modeling required. This financial model is normally site specific and incorporates
confidential decisions on the internal rate of return (IRR), tax implications, financing
methods, discount rate, amortization schedule, end of life value, and ownership
structure. The Level ASHRAE 3 or EPA Level 2 study results should provide capital
cost and operating data in a form that can be used by others in the development of the
financial model.
Many grant programs, where available, typically have a well-documented list of
informational requirements for some level of performance and economic analysis, as
well as a technical description of the proposed CHP configuration, including operating
strategy, annualized useful output, and annualized efficiency. Much of the information
required for grant applications can typically be derived from the information reported
through the investment grade audit. If considering a financial support mechanism, the
analysis should report the technical information input in the format required by the
program application.
4.1.1 Initial Screening Study
The initial screening stage of CHP development typically includes a site
walkthrough or its equivalent but is somewhat limited, requiring a few hours to a day
of effort. The objectives of the screening study are to first determine whether the facility
is technically compatible with on-site generation and heat recovery, and then, whether
there is the opportunity for economic viability. Annual energy use numbers can be used
to generate a simple payback statement based on typical or equipment specific
efficiencies and estimated load factors, which should target no less than a 75% load
factor for both thermal and electric loads during operating hours for most applications.
At the core of such a study will be a comparison of the cost to generate power with
a CHP plant including the thermal credit versus the cost to buy power from the utility
(i.e., the CHP spark spread). The differential should be able to overcome the capital
cost within an acceptable amount of time for the project to have economic feasibility.
These types of screening studies can be instructive for stakeholders who have little or
no experience with CHP or in support of the corporate decision-making process to
fund a more detailed study.
The screening study should incorporate a high-level review of site energy
consumption and can quickly identify if the site has the technical potential to benefit
from CHP. This type of screening should require little information and little if any cost
to complete and should generally be more useful to determine if a site should not
proceed with further investigation rather than provide any specifics on CHP system
size, configuration, or economic advantage.
Such screening studies can often be completed by the site itself with minimal
guidance other than general informational support or free web-based tools that allow
the user to enter total energy use and costs as well as some basic energy use details and
a basic load characterization. The results should include annual costs and revenues
with a statement of simple payback based on a gross estimated budget for the installed
plant and are often presented in terms of “go” or “no go” in answer to the requirement
for further study.
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While the screening study is often a low-/no-cost effort, it can set the design
direction for the project and should be handled by adequately knowledgeable personnel.
Because of a number of issues, including budget allocation cycles and project reporting,
many of the criteria used for prime-mover selection during the walkthrough are applied
throughout the development process. Decisions as to the total on-site capacity and the
number and type of prime movers should be reevaluated and refined as more detailed
or comprehensive information becomes available in later review stages.
4.1.2 CHP Feasibility Study
The next level of study is a technical and economic feasibility analysis that should
determine if CHP is in fact feasible and incorporate a review of potentially addressable
loads against a representative CHP configuration. This feasibility level of study is
termed a Level 1 analysis by both ASHRAE and the U.S. EPA. At this level, the electric
and thermal loads should be evaluated and reviewed so that base and average loads are
understood together with their characteristics. In addition, the basic internal electric
grid layout and thermal energy delivery and distribution systems should be reviewed
with interconnection points and operating strategies defined and assumptions and
qualifications listed. Typically, the feasibility analysis requires at least one engineering
site visit to review existing equipment, load distribution systems, and facility operation.
A Level 1 study includes significantly more data analysis than is possible within
the scope of a screening analysis, particularly with regard to the use of more detailed
load profile data. Data collection is generally limited to readily available energy use
information, observations taken during a walkthrough of the site, and records from
computerized load management systems, which may prove a useful source of profile
data even if only for short periods during different load cycles.
Energy-use data typically include the following:
• Utility Billings: Total monthly electricity and fuel use, electric demand, and
total energy cost. Copies of actual utility bills for a recent summer and winter
month should be reviewed to verify utility cost assumptions as well as understand
seasonal energy cost variations. Historical information for bulk fuels such as oil
and coal may be based on deliveries that are decoupled from actual use patterns.
In this scenario, monthly energy use should be estimated based on application and
discussions with facility personnel.
• Utility Rates: Electric and gas rate sheets are generally readily available directly
from the utilities’ websites.
• Energy Profile Data: Both electric and natural gas utilities may be able to
provide energy profile data. Typically, electric utilities do record this data on a
15 or 30 min interval basis and will make interval data available to the owner or
their assignee. In addition, on-site data management systems, steam charts, and
equipment logs may be a source of such profile data. Production or occupancy logs
may also provide data that are useful in interpreting energy requirements.
• Energy Studies: Previous studies of energy use, conservation, demand-side
management, and on-site generation may provide useful information on energy
requirements as well as useful insights on the condition of the existing equipment.
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• Site Inspection: A physical inspection of the site, including the proposed
location of the CHP plant, electric switchgear, mechanical systems, and facility
processes may be the most valuable source of input. In the absence of detailed
load data, existing equipment, machine room configuration, operating strategy, and
operating personnel can provide a fairly accurate estimate of how the loads operate
throughout the year.
During this stage of analysis, it is important to develop an understanding of the
various functions for which thermal energy may be used. Energy may be used in
processes, for feedstock, or for functions that cannot be displaced by recovered heat. In
this case, it is necessary to categorize energy use as either addressable or nonaddressable.
In addition, it is also necessary to examine the end-use thermal applications to determine
if the existing pressures and temperatures are required or if the thermal load can be
satisfied with lower pressures and/or temperatures. For example, 195°F (90°C) hot
water may be substituted for 15 psig (103 kPa) steam with little consequence if the
steam is used in a typical steam-to-hot-water heat exchanger to satisfy a 160°F (71°C)
heating coil loop. Thermal-load-side systems are often sized to function at lower
pressures or temperatures than the main distribution loop. In contrast, decreasing steam
pressure to an absorption chiller may require a derating of the chiller’s capacity. Where
exhaust gases are to be used directly for drying functions, it is also necessary to develop
a model of the process, including mass flows and temperature differences, as a basis for
estimating the amount of recoverable exhaust heat that can be used. Any direct use of
exhaust gases must be thoroughly analyzed for its potential impact on product quality
and human health.
Estimated costs are provided based on rules of thumb for equipment, engineering,
and installation as well as any other alterations, buildings, or effort that is required to
make the CHP plant work. Utility costs can be based on the average “all-in” cost per
unit on a monthly basis, including commodity, transmission, distribution, taxes, and
surcharges. However, in regions where there are significant variations in time-of-day
rates or the demand portion of the utility charge is large, the evaluation should breakout
demand and energy costs and provide separate CHP system energy production and cost
categories for each time-of-day period according to the local utility tariff.
An economic evaluation based on the output of the CHP system, its operating and
maintenance requirements, electric and thermal offsets, as well as any other operating
financial consideration should be provided for each month of a one-year period. A
simple payback analysis based on operating cost savings and the estimated installed
cost should be provided with a utility cost sensitivity analysis for higher and lower
electric and thermal energy costs. Other considerations, such as funding sources, grant
programs, methods of project delivery, as well as impacts the project may have on the
facility operation and existing equipment should be discussed.
4.1.3 CHP Assessment Study
ASHRAE Level 2 and 3 audits and the EPA Level 2 assessment require a more
detailed level of study, where actual equipment specifications are used to develop the
performance of the proposed CHP system and the loads are properly qualified in terms
of addressability and their impact on CHP system load factor. The ASHRAE Level 2
audit is an engineering effort that fully describes the operation of the host facility from
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an electric and thermal perspective as well as highlighting any major issues that may
cause concern. The ASHRAE Level 3 audit develops the proposed CHP technical
approach and provides a review of the proposed investment in economic terms and
should be sufficient to allow accounting and financing personnel to develop a financial
model, including interest, capital repayment, tax strategy, and ownership. The EPA
Level 2 analysis combines both facility and CHP reviews into a single effort.
An engineering site visit or visits are required to develop existing load profiles and
base lines as well as to provide a preliminary siting analysis, configuration selection,
and installation budget. The preliminary siting analysis should include site plans for
the proposed CHP location and nearby buildings. These drawings should identify the
location of existing utility lines including power, fuel, steam, water, sewer, and
telecommunications, as well as interconnection points and disconnects. The location of
any existing access ways, nearby property lines, fuel storage tanks, or other relevant
areas should also be noted. The identification of such lines is the responsibility of the
host site. Separate geotechnical or environmental impact assessments may need to be
carried out to validate existing information and are generally not included in the scope
of a CHP feasibility assessment.
Capital costs should be based on major equipment vendor cost proposals and sitespecific estimates for major equipment, including switchgear and heat recovery
equipment, as well as an installation cost estimate based on site requirements. All
development costs, including engineering, project management, environmental
permitting, utility interconnection, insurance, carrying costs, contingencies, etc. should
be included, and any costs outside of the CHP plant that are necessary to make the
system work should be identified. Maintenance costs and scopes should be obtained for
major equipment, and care should be taken to include the appropriate level of
maintenance and operating cost to maintain the unit through at least the payback period.
For most continuous duty applications, a comprehensive 10-year service contract that
would fully maintain the unit and leave it in good working condition should be used
where possible. Some of these costs can be internalized and reduced through selfperformance, but only properly trained and authorized personnel should work on the
major equipment. In addition, an agreement must be reached with major equipment
vendors to ensure warranty terms are not violated by internalizing routine maintenance
functions. Any accessory equipment, such as emissions treatment, fuel treatment,
thermally activated technologies, vibration isolation, noise mitigation, water treatment,
and weather protection should be fully identified and costs estimated.
Any capital cost offsets or avoided costs should be included as a separate line item
in the installation cost development with a full explanation of how they were derived.
Any additional costs required to facilitate installation of the CHP plant but not necessarily
included in the CHP installation cost should also be identified and fully explained.
The economic analysis provided with the Level 3 assessment should define all
relevant energy uses, offsets, and costs on a monthly basis for one year with an annual
cash flow analysis for at least 10 years and a simple payback calculation. Energy costs
and offset values should be calculated according to the existing utility tariff and most
recent bills with all energy and demand, commodity, and delivery as well as fixed and
variable costs separately accounted for each month. Gas, steam, or other thermal energy
used at site should include demand charges separately where applicable. Standby
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charges and any non-bypassable charges must also be included as a cost against the
CHP system in this level of analysis. Utility costs should account for any changes in
tariff that may result from the implementation of the proposed CHP plant. The economic
analysis should be run separately for a scenario with no grants or incentives as well as
for a scenario where potential grants or incentives are figured in.
The Level 3 study should also include an energy balance diagram of the proposed
CHP system for each operating mode or at least for summer and winter showing fuel
input, electric output, parasitics, thermal output, and thermal use and incorporate a fuel
use efficiency calculation in higher heating value of fuel for each mode of operation
and for a one-year period.
The averaging techniques that may have been the basis for the Level 1 feasibility
study should be replaced by more comprehensive modeling of the facility’s electrical
and thermal requirements and the CHP system performance. The load data should be
used to develop load-duration curves and capacity-load curves, which can be used to
estimate the extent to which CHP power and thermal energy can be used on-site to
displace purchased power and thermal energy from conventional boilers and burners.
Using a “bin” technique, the load duration curves can be used to develop an assessment
of the duration of loads in certain size bins during a specific period for each energy
form. Expressing electric and thermal loads as load durations according to size and
form allows for the development of load factors for a given size and configuration of
CHP plant. If the CHP system is to be operated at part load for significant amounts of
time, it is possible to determine the extent to which a specific engine will be operated
at part load and to use those heat rates and heat recovery data specific to part-load
operation for each engine. Engine efficiency and thermal energy quality and volume
vary with different output levels, because fuel input and thermal output are not linear
with electric output. For most reciprocating engines and combustion turbines, it is
generally recommended to operate systems at 75% to 95% of rated capacity to maintain
high efficiencies.
In some cases, where the coincidence of thermal and electrical requirements is of
concern, or where diurnal variations in either power or thermal requirements are
significant, an hour-by-hour analysis may be required. This analysis need not explicitly
consider all 8760 h in the year, but may be limited to typical weekday and weekend days,
or occupied and non-occupied days, or production and nonproduction days, with the
results extrapolated based on the relative number of days. The seasonal impacts can be
approximated by using an analysis of heating and cooling degree days to develop
weather trends. In those instances, where individual load profile data are not available,
it may be advisable to conduct a limited monitoring program or install temporary
metering or submetering of specific loads to develop a better understanding of the
various uses of energy and demand variations. In cases where a site is served by two or
more electrical services, it is necessary to consider the total load, the load served by each
service, the electrical compatibility of the two services, and the capability for transferring
load from one service to the other. As previously discussed, it is generally not possible
to serve two electric services with a single generator without the addition of inverters.
Occupancy and production data are also important for analyzing historic energy
requirements and for projecting future requirements. Plans for future additions,
demolitions, or modifications to the facility and its processes discussed as a basis for
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projecting future loads. Though the CHP feasibility analysis may not include a detailed
analysis of conservation and load management opportunities, it should include
consideration of their potential impact on energy requirements.
Monthly fuel use should not be less than the addressable and nonaddressable loads
combined. This is an important check to verify load assumptions and should include
the appropriate load-to-fuel conversion equipment (boilers, chillers, etc.) efficiency in
the calculation. Allowances can be made for single billing period mismatch, but in
general the assumed load cannot be greater than fuel use, unless there had been, or is
to be, a significant change in operation since the data were collected.
The CHP assessment study should incorporate calculations on emissions impact of
the CHP system and identify any potential impacts on air permitting as well as greenhouse
gas emissions savings. The recommended method of calculating grid emission offsets is
EPA’s CHP Emissions Calculator, which provides a comprehensive review of CHP
emissions as well as grid emissions. See Chapter 9 for a detailed assessment of CHPrelated emissions issues as well as the EPA’s CHP Emissions Calculator.
The utility costs in the assessment study are generally based on the most recent 12
months of purchased power and fuel costs. Where changes in future rates or tariff are
anticipated, the projected values should be used. The local electric and gas utility rate
tariffs include all the terms and conditions that govern the provision of regulated utility
service, including specific rates when interconnecting to the local distribution system.
The electric tariff is also useful in identifying other purchased power rates that may be
available for supplemental and possibly standby power, standby service charges, or for
specifying the prerequisites that must be met to obtain interconnection or other
conditions or restrictions that may have an economic impact on CHP viability. In some
cases, it may be useful to confirm the interpretation of a standby rate in correspondence
with the local utility. CHP plants that will be connected to the wholesale market will
have different economic metrics and may be dispatched for short operating periods to
avoid import of power during periods of high grid demand (high wholesale energy
cost), whereas they can be turned down or off during periods when grid power costs are
low. In this scenario, an 8760 h analysis of historic wholesale load node costs is required
to determine hours of operation, which depends on the hourly cost of wholesale power
as well as the minimum dispatch period.
In cases where new or upgraded natural gas service is required, the gas tariff may
be helpful in determining the investment that the gas utility or local distribution
company (LDC) can make to bring gas service to a CHP facility or to upgrade existing
service. The gas tariff also provides information on alternative rate structures that may
be available for CHP fuel gas. Once preliminary sizing has been completed, even if
only to the level of the walkthrough analysis, it is often helpful to contact the LDC to
determine if natural gas is available at required pressures; if nonfirm service is being
considered, the historic and projected level of interruptions should be established.
4.1.4 Other Issues
Most electric utilities will provide the technical interconnection requirements
between the utility and the CHP system. The utility may need to conduct an interconnection
study whose cost depends on the size and type of project and the location of the project
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within the utility’s transmission and distribution system. Because the cost of such studies
is usually passed back to the developer, as is any other cost incurred by the utility in
interconnecting the CHP plant, the cost of the study and the utility interconnect should
be negotiated and formalized to the extent possible during the early phases of project
development.
For natural gas supply costs, lower rates than historic data may suggest may be
obtained for interruptible service, and some utilities have special rates for natural gas
supplying a CHP system. A review of rate tariffs or discussion with local utility personnel
should occur early in the development process to identify any special rates that may
apply as well as to confirm gas availability and pressures through all seasons. If natural
gas service is interruptible, deliveries may be interrupted at the convenience of the LDC.
These interruptions may result from a lack of adequate system capacity, an inability to
deliver to specific locations, or because the cost of gas exceeds a specified rate. In
addition, if the commodity supplier and/or transmission contracts are also interruptible,
either or both may also interrupt. Discussions with the LDC should include some
estimate of interruptions, and this should be figured into the operating model.
If air permitting is complex, requiring more than two or three months, or if the
required control technology is uncertain, it may be necessary to develop initial designs
and process diagrams to the point necessary for permitting. If a design/build contract
format is to be used, it may also be prudent to delay any contract until the permit has
been obtained and control technologies, operating constraints, and emission-monitoring
requirements have all been specified.
The use of design/build contracting also imposes a need for the development of
geotechnical information as may be required for construction of new CHP system
foundations. If site conditions are not adequately specified, it may not be possible to
obtain meaningful fixed price proposals.
4.1.5 CHP System Modeling Techniques
Load-duration- or typical-day-based analyses can be acceptable analytical
techniques for simpler and smaller CHP systems or during the initial stages of design
development of larger systems. They may even be acceptable for system performance
modeling of larger wholesale power projects that are operated independent of sitespecific thermal and/or electrical requirements. However, they are generally inadequate
for non-export CHP systems serving multiple and independently varying facility loads,
particularly if these loads and the CHP system performance are functions of ambient
weather conditions.
Hour-by-hour modeling of the facility’s HVAC, energy, and power requirements
for an entire year is generally preferred for larger, more complex systems serving
buildings. This is particularly important if the CHP system capacity is higher than the
base load and it is designed to track either a thermal or electrical load or both and
where those loads vary as a function of both occupancy and weather. Because building
heating, cooling, power, and process loads vary continuously over a broad range of
values, a non-export CHP system with a capacity higher than the base loads will also
be required to vary continuously over a broad range, significantly complicating the
analysis of part-load operation. Because power requirements, and therefore heat rate
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and heat recovery, are functions of both building loads and ambient temperatures,
hour-by-hour modeling may be necessary for the performance analysis of any tracking
system. An hour-by-hour model may also be needed for the following cases:
• Sites where cogenerated power is used both internally to displace power purchases
and sold to the wholesale market. In this case, and particularly so if the value of
power used internally is significantly different than the value of wholesale power, it
is necessary to quantify power exports on an hourly basis.
• Sites where utility rates for supplemental and standby service require more
detailed modeling of the hourly output of the CHP system, either as a basis
for determining the total cost of power or, if standby rates are significant, for
determining the cost for the use of standby power.
• Configurations where the CHP system performance is dependent on ambient
weather conditions, such as is the case with combustion turbines, or where cooling
towers are required for heat rejection, or where absorption or evaporative chillers
are used to precool turbine inlet air.
• Sites equipped with, or considering the implementation of, demand-side
management or load-shifting techniques, such as thermal storage.
Industrial facilities or some institutional facilities, such as hospitals with significant
process type loads, typically exhibit less variation in day-to-day requirements, and their
energy requirements are less sensitive to hourly weather changes. These systems
generally operate at a limited number of discrete output levels, and the modeling of
part-load performance is considerably simpler than is the case for CHP systems that
must serve continuously varying loads. Hour-by-hour analyses based on a limited
number of typical days that are defined by production levels, season, or some other
parameter are a primary determinant of energy requirements. The use of an hour-byhour analysis on a typical-day basis can significantly reduce computational requirements
as compared to the 8760 h of analysis required for an entire year.
Thermal profile data for sites that use oil, coal, or other bulk delivery fuels may be
difficult to develop. These fuels are typically limited to boiler use and can be entirely
displaced with recovered heat. However, fuel deliveries are on an as-needed basis and
may not be analytically linked to thermal profiles. In these cases, it may be necessary
to rely on discussions with facility operations personnel, together with any available
energy production data, such as steam charts (or condensate return readings as an
alternative to steam production). Where thermal use profiles are highly variable and no
historical data exist, it may be necessary to install metering and logging equipment to
obtain a reference point for current conditions.
4.1.6 CHP Feasibility Study for New Facilities
The analysis of CHP at new buildings may present particular problems because
there are no existing baseline energy data; moreover, the specific mechanical systems
may not have been finalized, resulting in even less certainty. One source of useful
information is similar facilities for which data are available. Where energy models have
already been developed for the facility, the output of such models can be used as the
basis for CHP system performance.
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4.2 TOOLS AND SOFTWARE FOR FEASIBILITY STUDY
There are a number of publicly available free tools, as well as privately developed
tools available at a cost, that can be used to assist in the assessment of a CHP application.
Generally, the tools provide a level of output accuracy commensurate with input detail.
Simpler tools that provide the user with few input options and require only annual data
should be considered as screening tools whose output is intended to provide a “go/
no-go” answer to the requirement for further study. These types of tools typically do
not address the difference between fuel use and addressability of thermal loads and are
designed to provide some concept of theoretical potential for CHP at the site. The
advantage with such tools is that they require little time to produce results and are
generally available free of charge.
More sophisticated tools that provide significantly more detail and accurate results
can require significant time to input data appropriately to generate these results. Many
of these programs contain databases of equipment performance and cost characteristics
that are very useful in running various CHP configurations but that can become dated
over time unless they are continually updated. Many also contain template energy load
profiles for typical applications and allow the user to adjust these profiles to match
specific site conditions. Generally, these more sophisticated programs all contain
localized weather data that will adjust load profiles based on location and, combined
with the application templates, can provide a high degree of accuracy in determining
total facility loads. Although these programs are very useful and essentially combine
building modeling and CHP performance, they generally cannot account for physical
constraints, addressability of loads, or other overarching issues that can only be revealed
with a proper engineering site visit. However, they can be particularly useful for new
buildings where load information is not available.
A new ASHRAE CHP Analysis Tool has been developed as a companion to this
guide using a Microsoft® Excel®-based spreadsheet that provides reliable and
transparent cost savings resulting from the application of CHP with a minimum of user
effort. The new tool requires technical input from the user, who is assumed to have
some technical understanding of a prime mover’s energy balance and who will acquire
an understanding of the host site thermal systems. The key to this new tool is reliance
on the user to make some quantitative decisions to overcome complex issues; this
greatly enhances the tool’s ability to provide accurate results with minimum input. The
tool allows users to profile existing or new facilities in terms of monthly electric and
thermal energy use.
The new tool takes a somewhat unique approach to solving the issue of obsolescence
of equipment databases by allowing the user to input the parameters for the CHP
system characteristics independently of the technology selection. This basically
recognizes the practical fact that, no matter which technology you are using, all outputs
can be expressed as a percentage of the fuel input. This does require the user to calculate
appropriate electric and thermal efficiencies based on fuel input; this can easily be
determined from manufacturer data.
Although CHP performance and energy costs are the most important factors to
consider from a theoretical perspective, the real issue when trying to calculate the
economic performance of a CHP plant is accurately assessing the addressable thermal
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loads. This is the most common failure in CHP application design. The new tool and
this design guide are significantly focused on resolving this issue. The new tool requires
input to a series of questions on thermal loads and existing equipment to determine the
possible applications for waste heat from a chosen CHP configuration. This requires
some level of site investigation and knowledge of energy equipment by the user that the
authors believe is necessary to provide a reasonably accurate result.
The new model provides an operation and maintenance cost evaluation, together
with energy cost offsets for the CHP plant, that provide monthly savings and costs and
result in a current-dollar annual savings statement for the proposed system together
with the annualized system efficiency. Based on the technology and size chosen, the
tool provides suggested inputs for capital cost that can be used or altered by the user.
Non-CHP costs, incentives that might apply, as well as other monthly costs and/or
savings can be input by the user to develop a simple payback statement. The average
energy cost is determined by the tool, and a sensitivity analysis for higher and lower
electric and gas prices is provided, including simple payback for each scenario. A
complete guide to the ASHRAE CHP Analysis Tool is provided in Chapter 12.
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CHAPTER 5
CHP ECONOMIC ANALYSIS
The purpose of a CHP economic analysis is to provide sufficient data to allow
stakeholders to understand if the potential financial gain through cost savings is
adequate to justify the investment required. The economic analysis is generally the
most important piece of reporting in the CHP evaluation process, but it is entirely
dependent on the development of accurate data relating to key factors including loads,
utility tariffs, system performance, and installation costs.
5.1 UNDERSTANDING CHP OUTPUT VALUE & LOAD FACTOR IMPACT
The value of the power and thermal energy produced by a CHP plant is a function
of the use of the output energy as well as the costs of energy that would otherwise have
been required. In its simplest form, 1 kWh of power produced by a CHP plant is worth
the value of 1 kWh from the utility as long as there is a 1 kWh load to be served. One
therm (105 MJ) of hot water produced by the CHP plant is worth the cost of gas divided
by the efficiency of the existing hot water boiler as long as 1 therm (105 MJ) of load is
available and addressable by the CHP plant.
The value of cogenerated energy depends on the ultimate disposition of that energy.
If the power is used to reduce purchases of electric power from an electric utility, then
the value of the cogenerated power depends on retail rates and the specific rate structure
applicable to that facility. Alternatively, if the CHP-produced power is exported from
the site and sold to an electric utility, then the value of the cogenerated power is based
on the utility’s costs for an alternative source of that same power. When power is used
on-site, thus reducing retail power purchases, the project is referred to as a selfgeneration, internal-use, or displacement-type project. When the power solely is
exported and sold to a utility or to the wholesale market, the project is referred to as an
avoided-cost, wholesale-power, or utility generation project. Both concepts can be
considered in the evaluation of CHP system economics; however, in many open power
markets, offsetting power purchases typically provides higher savings and price stability
than selling power into a volatile wholesale market. Subsidies are sometimes provided
in performance-type payments, such as a rate per kilowatt-hour or therm, and should be
considered in the operating proforma.
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For projects that are primarily driven by operating economics (which is the case
with most applications), an understanding of the relative value of the various outputs
will help in selecting the optimal configuration. Where electric costs are high and fuel
costs are low, the electric output of the system is most valuable, whereas for applications
with a high cost of thermal energy, the thermal output may be the key component. Table
5-1 shows the value of various forms of energy generated by a CHP plant for a fixed
grid electric cost and at varying natural gas input values. This table assumes that the
CHP plant output is used to offset grid electric and natural gas fuel to a boiler. In
regions with high energy costs, CHP provides higher value output and, as capital costs
are generally not related to energy costs, plants in areas with high energy costs show
the highest rate of return.
Table 5-1. Offset Value of CHP Output Energy
Scenario A:
Input Values
Offset Values
Natural Gas (NG)
$0.60
/therm
Electricity
$29.31
/106 Btu/h
Grid Electricity
$0.100
/kWh
Heating
$7.50
/106 Btu/h
NG Boiler Efficiency
80
%
Cooling
$5.00
/106 Btu/h
Elec Chiller Efficiency 0.60
kW/ton
Scenario B:
Input Values
Offset Values
Natural Gas (NG)
$1.00
/therm
Electricity
$29.31
/106 Btu/h
Grid Electricity
$0.100
/kWh
Heating
$12.50
/106 Btu/h
NG Boiler Efficiency
80
%
Cooling
$5.00
/106 Btu/h
Elec Chiller Efficiency 0.60
kW/ton
Scenario A:
Input Values
Offset Values
Natural Gas (NG)
$5.69
/GJ
Electricity
$27.78
/GJ
Grid Electricity
$0.100
/kWh
Heating
$7.11
/GJ
NG Boiler Efficiency
80
%
Cooling
$4.74
/GJ
Elec Chiller Efficiency 0.17
kW/kWC
Scenario B:
Input Values
Offset Values
Natural Gas (NG)
$9.48
/GJ
Electricity
$27.78
/GJ
Grid Electricity
$0.100
/kWh
Heating
$11.86
/GJ
NG Boiler Efficiency
80
%
Cooling
$4.74
/GJ
Elec Chiller Efficiency 0.17
kW/kWC
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CHP ECONOMIC ANALYSIS
Table 5-2 shows the basic cost of on-site generation, value of thermal output, net
cost of CHP power output, and the simple payback in years for three different energy
cost scenarios. The net cost of CHP power output is calculated by applying the value of
the thermal output as a credit against the cost of power production and provides a
statement of overall CHP savings when compared to the grid electric power cost. The
net cost of CHP power also includes fuel and maintenance costs. The table is based on
a typical prime mover with 35% HHV electric and 35% HHV thermal efficiency, and
the capital cost is assumed to be $2500 per kW. The CHP plant is applied at a facility
that can use all the power and thermal output to offset grid power imports and natural
gas fuel to boilers and has a 95% electric load factor and a 100% thermal load factor.
As electric costs increase, the value of offset electricity increases, while a higher fuel
cost will be somewhat offset by the higher value of thermal offsets, so increases in
thermal energy costs are less impactful that increases in grid electric costs. As discussed
previously, higher energy costs in general lead to reduced payback periods, given that
the capital cost and maintenance cost are independent of energy cost.
Table 5-2. Comparison of Energy Costs and Payback
CHP Costs
Electric Power Cost
$0.080
$0.100
$0.120
/kWh
Natural Gas Cost
$0.50
$0.60
$0.70
$/therm
Maintenance Cost
$0.0200
$0.0200
$0.0200
$kWh
Electric Efficiency (LHV)
38.5%
38.5%
38.5%
Electric Efficiency (HHV)
35.0%
35.0%
35.0%
Thermal Efficiency (HHV)
35.0%
35.0%
35.0%
Fuel Input (HHV) per kWh
9754
9754
9754
Btu
Fuel Cost per kWh
$0.049
$0.059
$0.068
@ 1000 Btu/ft3
Maintenance per kWh
$0.0175
$0.0175
$0.0175
Excludes HR equipment
Total Cost per kWh
$0.066
$0.076
$0.086
Thermal Load Factor
100%
100%
100%
Boiler Efficiency
80%
80%
80%
Natural Gas Offset per kWh
4268
4268
4268
Btu
Offset Value per kWh
$0.021
$0.026
$0.030
@ 1000 Btu/ft3
Net Cost per kWh
$0.047
$0.053
$0.058
Includes HR equipment
Annual Savings per MW
$271,015
$391,794
$512,573
CapX per MW
$2,500,000 $2,500,000 $2,500,000
Simple Payback
9.2
Engine Performance
Cost to Generate Power Only
Gas Offset
CHP Economics
6.4
4.9
Years
Note: Cost to maintain heat recovery (HR) equipment is excluded for power-only scenario.
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It is interesting to note that, whereas power offset generally has the highest financial
value, the value of the thermal output typically represents a significant portion of the
CHP system net cost savings. Given that CHP is based on the sequential generation of
power and thermal energy, it is necessary to first generate the power to produce the
thermal energy. The prime mover often generates at a similar cost to the grid, with the
offset thermal energy value providing the bulk of the savings required to pay down the
capital investment and provide energy cost reductions to incentivize the development
of the project. Table 5-3 indicates that, based on the data provided in Table 5-2, the
thermal output value is equivalent to between two thirds and one half of the total net
CHP system cost savings.
From this perspective, the importance of utilization of the thermal output to offset
fuel costs is vital to the economic success of the project. In all cases, high load factors
on thermal output should be encouraged, although the load factor has less impact in
regions where fuel costs are low. Using the same basic equipment and load parameters
as described above, Table 5-4 provides the cost of generation, thermal offset value, and
payback for varying thermal load factors while holding energy costs steady. As can be
seen from this table, the impact of thermal load factor is highly significant and as
impactful as energy costs in terms of economic performance.
It is also interesting to note the relative value of heating and cooling output. These
values are dependent on both the cost of energy (electricity for most chillers and natural
gas or other fuel for heating) and the efficiency of existing or proposed new non-CHP
chillers and boilers. Table 5-1 provided offset values of CHP system output based on
traditional assumptions 80% efficiency for natural gas boilers and 0.55 kW/ton (0.16
kW/kWC) for water-cooled electric chillers. Because of the high efficiency of watercooled electric chillers, the value of offsetting one million Btu (1055 MJ) of cooling
generally has a lower value than offsetting one million Btu (1055 MJ) of heating.
Therefore, when a CHP plant is configured to convert a significant portion of its thermal
output to cooling to offset chillers rather than offsetting heating, the return on investment
(ROI) period is generally increased for two reasons. First, the expense of adding cooling
conversion equipment such as absorption chillers increases the capital cost of the
project, and secondly, the offset value of the CHP system output is not as high. Using
the traditional efficiency assumptions outlined above, it can be stated that CHP systems
that require cooling output to maintain high load factor require higher spark spreads
than heating-only systems to provide the same ROI. However, offset values are a
function of the offset boiler or chiller efficiency. Table 5-5 provides a comparison of
offset values based on traditional equipment efficiencies and those for equipment of
lower efficiency. From this comparison, it can be seen that if the CHP system is
Table 5-3. Thermal Savings versus Net Cost Savings
Electric Power Cost
$0.080
$0.100
$0.120
/kWh
Natural Gas Cost
$0.50
$0.60
$0.70
/therm
Natural Gas Cost
$4.74
$5.69
$6.64
/GJ
CHP Net Savings
$0.033
$0.047
$0.062
/kWh
Offset Value per kWh
$0.021
$0.026
$0.030
/kWh
Thermal Value/Net Savings
66%
54%
49%
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offsetting an electric chiller with an efficiency of 1.0 kW/ton (0.28 kW/kWC), such as
an older air-cooled chiller, the value of cooling is higher than offsetting an 80%
efficiency boiler at the stated energy values.
When calculating the offset values for CHP output based on existing equipment
efficiencies, care must be taken to ensure that, where low efficiency is claimed, the
existing equipment cannot be adjusted to improve efficiency. In all cases where poor
performance of existing equipment creates a high offset value for CHP output, the
option of improving efficiency or replacing the equipment with new systems should be
considered as an option before calculating the offset values for CHP with a capital
credit to CHP if it allowed the measure to be offset.
Table 5-4. Comparison of Thermal Load Factor and Payback
CHP Costs
Electric Power Cost
$0.100
$0.100
$0.100
/kWh
Natural Gas Cost
$0.60
$0.60
$0.60
$/therm
Maintenance Cost
$0.0200
$0.0200
$0.0200
$kWh
Electric Efficiency (LHV)
38.5%
38.5%
38.5%
Electric Efficiency (HHV)
35.0%
35.0%
35.0%
Thermal Efficiency (HHV)
35.0%
35.0%
35.0%
Fuel Input (HHV) per kWh
9,754
9,754
9,754
Btu
Fuel Cost per kWh
$0.059
$0.059
$0.059
@ 1000 Btu/ft3
Maintenance per kWh
$0.0175
$0.0175
$0.0175
Exclude HR
equipment
Total Cost per kWh
$0.076
$0.076
$0.076
Thermal Load Factor
100%
75%
50%
Boiler Efficiency
80%
80%
80%
Natural Gas Offset per kWh 4268
3201
2134
Btu
Offset Value per kWh
$0.026
$0.019
$0.013
@ 1000 Btu/ft3
Net Cost per kWh
$0.053
$0.059
$0.066
Include HR
equipment
Annual Savings per MW
$391,794
$338,523
$285,251
CapX per MW
$2,500,000 $2,500,000 $2,500,000
Simple Payback
6.4
Engine Performance
Cost to Generate Power Only
Gas Offset
CHP Economics
7.4
8.8
Years
Note: Cost to maintain heat recovery (HR) equipment is excluded for power-only scenario.
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5.2 UTILITY RATES AND TARIFFS
Typical electric and natural gas utility rate tariffs consist of several components,
including one or more of the following:
• Customer Charge: This component consists of a fixed monthly charge applicable
to all customers in the rate class, and is applicable regardless of whether any energy
is actually used. It is generally based on the fixed costs of servicing an account.
• Demand Charge: This component is the monthly charge based on the maximum
facility demand on the utility system. Although it is usually based on the peak
demand that occurs during the month, it may be restricted to the peak demand
Table 5-5. Non-CHP System Equipment Efficiency and Offset Value
Scenario A:
Input Values
Offset Values
Natural Gas (NG)
$0.60
/therm
Electricity
$29.31
/106 Btu/h
Grid Electricity
$0.100
/kWh
Heating
$7.50
/106 Btu/h
NG Boiler Efficiency
80
%
Cooling
$4.58
/106 Btu/h
Elec Chiller Efficiency 0.55
kW/ton
Scenario B:
Input Values
Offset Values
Natural Gas (NG)
$0.60
/therm
Electricity
$29.31
/106 Btu/h
Grid Electricity
$0.100
/kWh
Heating
$9.23
/106 Btu/h
NG Boiler Efficiency
65
%
Cooling
$8.33
/106 Btu/h
Elec Chiller Efficiency 1.00
kW/ton
Scenario A:
Input Values
Offset Values
Natural Gas (NG)
$5.69
/GJ
Electricity
$27.78
/GJ
Grid Electricity
$0.100
/kWh
Heating
$7.11
/GJ
NG Boiler Efficiency
80
%
Cooling
$4.34
/GJ
Elec Chiller Efficiency 0.16
kW/kWC
Scenario B:
Input Values
Offset Values
Natural Gas (NG)
$5.69
/GJ
Electricity
$27.78
/GJ
Grid Electricity
$0.100
/kWh
Heating
$8.75
/GJ
NG Boiler Efficiency
65
%
Cooling
$7.90
/GJ
Elec Chiller Efficiency 0.28
kW/kWC
90
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that occurs during the on-peak period. The demand charge is generally based on
the utility’s fixed costs for delivering energy. A ratcheted demand charge may be
based on the actual peak demand experienced during the month or some percentage
of a previous peak demand. The ratchet period may extend back to the previous
peak cooling or heating season, 11 months, or to the inception of service. Ratchet
percentages may range from as low as 33% to a high of 100%. Two-part demand
structures are also becoming more common for electric utilities that operate in open
wholesale power markets: one demand charge is intended to recover the utility or
regional grid system generation capacity obligation costs, with the second charge
intended to recover the transmission and distribution (T&D) system costs. Two-part
demand structures may use different ratchets, with T&D and capacity obligations
often ratcheted at 100% for 11 months.
Demand charges may be changed in block increments, with the rate either
increasing or decreasing as the billed demand increases. In an inverted rate
structure, demand charges increase with increasing demand as the utility attempts
to discourage incremental use; decreasing block rate structures are characterized by
decreasing rates with increasing use. Demand charges may also vary as a function
of service voltage or gas pressure and from season to season.
• Energy Charge: This component is the charge for the energy that is actually
delivered by the utility. It may be billed in different energy blocks, with the rate
usually decreasing as the amount of energy used increases. Energy blocks may
be defined as fixed, specific quantities of energy or, in the case of electric utility
supplied electricity, they may be variable and based on the time of day at which
energy is used. Typical “time-of-use” blocks include on-peak, off-peak, and
shoulder or intermediate hours.
• Surcharges: Most rates include various surcharges that are intended to recover
specific costs. One of the most common is a fuel cost adjustment, which is intended
to adjust for fuel costs that may vary significantly from month to month. Where
electricity is purchased from the electric utility, this charge is sometimes referred to
as a purchased power adjustment. Other surcharges may be based on the cost of a
utility’s conservation and demand-side management programs, the need to fund the
decommissioning of nuclear power plants, tax adjustments, and, sometimes, various
societal benefits are funded through utility surcharges. These charges are usually
applied on the basis of kilowatt-hour use, although some may be computed on the
basis of a percentage of the total bill or energy cost.
• Power Factor Charges: Many electric utilities require a facility to maintain a
minimum power factor as a condition of service. Some impose additional charges
based on the site power factor. In general, power factors of less than 85% or 90%
result in added costs, whereas power factors in excess of 90% may result in credits.
In some cases, the utility may base billings on apparent power, thus imposing a
penalty for any power factor of less than 100%.
• Taxes: Most utilities include some tax imposed on behalf of a government body,
typically the state and the local municipality. State taxes take the form of a sales
tax; local taxes may be referred to as franchise fees, gross receipts taxes, use taxes,
or sales taxes. Government-owned buildings or nonprofit entities may be exempt
from some taxes.
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The output of a CHP plant reduces both energy use and energy demand of the host
facility. These components should be separated and accounted for separately when
providing a detailed economic analysis. Although using the average cost of electricity
based on total cost divided by total usage may be sufficient to provide an indication of
potential energy savings, it does not properly reflect the impact of load following or
system shutdowns and therefore tends to overstate energy cost savings. This is particularly
true when rate tariffs have high demand components or include ratchets.
Standby charges are generally imposed by the local electric distribution company
on a facility with CHP to address the cost of making service available as well as
providing power when the CHP unit is not operating. Standby charges are generally
based on the capacity of the CHP system (nameplate rating of the prime mover), and
must be taken into account when doing any level of economic analysis. These charges
are a direct cost to the project and can have significant impact on the net financial
savings. They typically include a monthly demand component as well as an energy cost
component. The load factor of the CHP generator and frequency of outages during
operating hours will have significant impact on the cost of standby service. Where CHP
generators are frequently down for either scheduled or unscheduled maintenance, the
cost of standby service will increase. In situations where the load factor is less than
50%, CHP systems will often not qualify for standby service, resulting in significantly
higher demand charges. Electric utility normal rate and standby tariffs often include
ratchet components which can cause a high demand payment for 12 months, even
though the high demand only occurred for a short period during one month. As rate
tariffs evolve to incorporate distributed generation such as CHP, there may be an
emphasis on facilitating on-site power generation that can maintain output during peak
grid demand periods and penalizing systems that cannot provide reliable output during
these times.
Utility rate structure considerations include existing tariff structures, standby rate
tariffs, and rate tariffs that may be applied after a CHP system has been installed. These
should be evaluated for their impact on the economics of implementing CHP. Once a
CHP system has been installed, the reduction in demand or energy usage may cause the
facility’s rate tariff to change, potentially resulting in a higher cost per unit of energy.
Some utilities have special supplementary power tariffs that would be used once a
facility has some form of on-site generation. When determining the cost of supplemental
power, it is also prudent to determine whether the end-user would be better served
remaining on the same full-service rate for supplemental energy, or if some other
partial service rate would be less costly.
Many utility rate tariffs for nonresidential customers have varying rates depending
on the time of day that the power is consumed. Depending on the differential between
on-peak and off-peak hourly energy charges as well as demand charges, the economic
advantage of operating on-site generation can vary widely. This differential depends to
some degree on the grid power generator mix, and it can cause a large variance in plant
economics versus using the average cost of power. This is particularly true for facilities
that wish to operate the CHP plant 24 h/day and may require the plant to be shut down
during off-peak hours. Though the value of offsetting power during peak hours is high,
the inability to run all hours because of low off-peak power costs can extend the
payback of the facility.
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Many utility tariffs also contain what are typically called ‘non-bypassable’ charges.
These are generally relatively small charges per kilowatt-hour that are imposed on
energy usage by the facility rather than on energy supplied to the facility by the grid.
Therefore, these charges are imposed on energy generated on-site as well as imported
energy and must be added to the cost of operation of the CHP plant.
Gas utilities often provide special tariffs that reflect the high load factor associated
with CHP plants. These tariffs recognize the higher throughput associated with CHP
and typically offer reduced distribution charges per unit of throughput. Typically, these
tariffs are published on the gas utility’s web site and should be reviewed and applied to
the economic model. When applying such special CHP tariff rates, it is important to
apply them only to the CHP gas use, because the remaining facility gas throughput will
generally still come under the existing rate structure.
Where CHP plants are designed to offset internal power imports as well as export
power to the grid, the value of the power generated by such a plant is a combination of
the offset value of imported power as well as the sale value of exported power, together
with any standby service, non-bypassable charges, and other service charges that may be
imposed to allow export of power, which can include local distribution utility charges to
get the power from the facility to another facility or the wholesale power market.
5.3 ENERGY SUPPLY COSTS
In valuing on-site generated power and thermal energy, it is important to determine
whether the end-user facility is purchasing both power and thermal energy on the
lowest cost rate available. If the end-user’s costs are unnecessarily high, then the
projected CHP savings will be artificially high. Where facilities purchase energy from
their party suppliers under fixed price, multiyear contracts, it is necessary to understand
the future cost of energy when the current contract expires. In situations where energy
prices have recently declined or increased, the current contract may be based on a cost
of energy that does not properly reflect the cost of energy when the proposed CHP
system will come on line. In these scenarios, projected energy costs should be based on
input from the third-party energy suppliers and should be agreed to by all parties. In
addition, the application of CHP can significantly impact the volumes and load factors
for the purchased energy. In general, electric purchases will decrease, while boiler/
CHP fuel volumes will not only increase, but the load factor for distribution systems
will be improved. Revised energy purchase volumes and demand profiles should be
developed to obtain the most accurate projection on energy costs.
5.4 OPERATING AND MAINTENANCE COSTS
Maintenance costs are typically based on third-party contracts with specialized
service companies or equipment vendors. Some of the routine maintenance on prime
movers and all of the maintenance for thermal equipment can be carried out by the
CHP system owner. In this case, the cost of third-party maintenance can be reduced,
but the cost of the incremental work carried out by the owner should be included in the
project economics.
Because of development of controls and remote monitoring, many CHP prime
movers can remain unattended. However, thermal equipment, particularly steamproducing systems with pressures in excess of 15 psig (103 kPa [gage]), may require
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full-time licensed operators to be present. Many regions require a licensed operator to
be within sight and sound of a high-pressure steam generator during all operating
hours. This can add a very significant cost to the operation of the CHP plant and must
be fully investigated and included in the economic proforma where appropriate. In
some situations, where the thermal equipment portion of the project can be located in
the same area as existing thermal equipment, the existing operators may be able to
incorporate operating duties for the CHP thermal recovery plant into their existing
routine at little or no additional cost to the project.
5.5 OTHER COSTS AND TAXES
Water and wastewater fees for larger CHP systems may become significant within
the context of the project’s operating cost structure. Water may be required for cooling
towers and boiler makeup; wastewater charges may result from boiler blowdown and
sanitary wastes.
Insurance is available, either directly or indirectly, for a number of CHP system
risks. Equipment or boiler insurance is available to protect against the cost of a
catastrophic failure of the prime mover or any key component. In addition, insurance
against loss of income, loss of savings, or business interruption insurance can provide
protection against the erosion of economic viability caused by a catastrophic failure. It
may also be prudent to provide for payment of debt service during a major failure.
CHP systems, even small ones, may be required to obtain offsets or allowances for
various emissions including both NOx and SOx. These charges may be a one-time cost
incurred as a condition for start-up or may be ongoing.
Administrative and management fees depend on the organizational and financial
structure of the project. CHP systems that are owned and operated by a third party may
charge as much as 5 or 10% of the total operating budget as a management fee; the fee
for a larger project may be as low as 1 to 2%. In addition, larger CHP projects with
more complex fuel acquisition strategies may require a fuel manager with fees of 1 to
3% of the cost of the system fuel. Other fees that should be considered are legal and
accounting fees.
CHP systems are typically subject to both ad valorem or property taxes and income
taxes. The ad valorem tax rate is usually established by the local municipality and
school district and is assessed based on the value of the CHP system. These taxes are
often differentially applied to equipment, investment in buildings, and infrastructure,
and can have a significant effect on project viability. In some cases, where either the
state or the local government wishes to increase local investment, tax abatement may
be available.
CHP systems producing a reduction in operating costs are subject to federal and
possibly state income taxes. In those cases where the CHP system is owned by the
energy end-user, any resulting operating cost reductions will contribute to the enduser’s overall profits, and to the extent that the end-user has taxable profits, the CHP
system will incur income taxes. In those cases where the CHP system is owned and
operated by a third party, the third party will be liable for income taxes on any resulting
margins. Any income tax exemption available to the end-user, such as a hospital,
nursing home, or governmental facility, is not directly transferable to the third party.
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Depreciation or capital recovery is a noncash charge taken against operating profits.
Depreciation schedules for larger CHP projects can be quite complex, with various
components depreciated at rates ranging from a few years to 30 years. It may be
necessary to establish a separate depreciation schedule for each type of equipment.
Depreciation of smaller systems is generally based on a single schedule, although in
some cases costs incurred for modification of the host site may be considered as a part
of the building and, therefore, subject to significantly longer depreciation schedules.
While straight-line depreciation schedules are commonly used, other more accelerated
approaches are allowed by the Internal Revenue Service in the United States, and these
alternatives should be considered in the final analysis of a project’s economics.
While not common, some third-party transactions for the sale of power and/or
thermal energy to an end-user may be subject to local sales taxes or, alternatively, to
gross receipts taxes.
5.6 CAPITAL COSTS
Even at the most elementary stages of CHP assessment, capital cost budget
estimates are required for the purpose of deciding whether to proceed with the
development of a CHP system. The accuracy of budget estimates will be directly
affected by the amount of engineering and analysis that is the basis for such estimates.
Budgets developed at the earliest stages of analysis are typically based on generic data
and rules of thumb. Any decisions based on those estimates must allow for significant
uncertainty and are only of value in determining whether a more detailed engineering
analysis is justified. As one proceeds through the development process, capital cost
estimates are refined based on more detailed design information and vendor quotations.
In general, budget elements can be categorized as relating to equipment costs and
non-equipment costs with additional financing cost considerations for projects that
intend to use bond or third-party financing. The following sections provide a list of
considerations that will assist in developing a complete budget estimate.
5.6.1 Equipment Costs
Equipment cost estimates for CHP systems are driven by five major components:
the prime mover/generator including exhaust after treatment, the heat recovery system,
thermal conversion equipment, physical structure and the electrical interconnection.
The following are various cost components included in the equipment scope of work
together with the factors that will influence their cost:
• Engine Generator Set: Design, speed, alternative fuel capability, generator
voltage, duty cycle, and internal emission control techniques.
• Heat Recovery/Rejection System: Required media (steam, hot or chilled water);
thermal energy quality (steam pressure or temperature); number of different
temperatures or steam pressure levels required; the approach for rejection of excess
thermal energy, including heat dump radiators and diverter valves; raw water supply
for emergency cooling; and the need for additional pumps to either supplement or
replace existing powerhouse pumps.
• Emission Control Technologies: For example, selective catalytic reduction
(SCR), filters and catalysts.
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• Supplemental Exhaust Gas Duct Burners: As exhaust temperatures after the
duct burner exceed 1,600 F (871 C), more complex designs may be required for
the heat recovery equipment thereby increasing cost.
• Exhaust System and Stack: Ability to use the existing breeching and stack,
ability to use a single stack for multiple engines or for both diverter valve bypass
and HRSG exhausts, exhaust gas temperature, and emission control technology.
• Fuel Supply: Interconnection with existing fuel supply systems; cost of
upgrading the natural gas delivery system if necessary for higher pressure and
volumes, separate fuel metering and fuel processing as required; fuel cleanup and
treatment as necessary to meet the prime mover specifications.
• Natural Gas Compressors: Pressure differential and the availability of varying
pressures from the natural gas supplier and the approach to redundancy.
• Controls: Requirements for unattended operation, extent of automated
monitoring and reporting.
• Electric Utility Interconnection: Number of services or utility drops to the
site and the need to upgrade or modify the utility distribution and/or transmission
system to accommodate the interconnection and/or power exports from the site.
• Site Electrical Interconnection: Ability to operate in parallel with the grid,
or independent of the utility grid during a blackout, interface with any on-site
emergency generation, and interface with on-site switchgear, energy management
or load-shedding systems. If the CHP system displaces the need to install an
emergency generator, then a credit for the value of the emergency generator should
be considered.
• Mechanical System Interconnection: Interconnection with thermal energy
supply line and modifications for condensate or water return from the site,
interconnection with compressed-air system, if an existing powerhouse system is to
be used or replaced, raw water supply system interconnection for makeup, etc.
• Water Supply and Treatment: Condition of existing water treatment system and
the use of water for thermal loops or injection into engine combustion chamber.
• Wastewater Interconnection: Quantity of blowdown, local wastewater discharge
requirements, and sanitary wastewater discharges, if applicable.
• Architectural/Structural: Acoustic requirements, the extent to which the
existing structure can be used, the need to remove existing boilers, modifications
to allow for equipment egress, modifications to allow for maintenance procedures,
special foundations, installation of additional permanent cranes, and site rigging.
• Ventilation and Combustion Air Systems: Need to prechill combustion air,
deicing of inlet filters, ambient environmental conditions, and need for combustion
air special filtering.
CHP equipment may be subject to local sales taxes, although some systems that
meet state program requirements may be exempt. In addition, equipment purchased for
installation at a tax-exempt institution may be exempt from such taxes. In any case, it
is important to determine specific tax liability for each project.
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5.6.2 Other Costs
Installation costs may be included in the capital budget or separately itemized.
General trade costs and general conditions are typically considered installation costs, as
are site-handling and rigging charges. Other costs that vendors include in a construction
contract include the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Architectural and engineering design fees
Installation labor
Equipment rental and rigging
Construction management fees
Environmental studies and permitting costs
Special consultants (acoustical, soils, water treatment, water runoff,
construction monitoring, and inspection)
Preoperational project management
Legal fees (bid document terms and conditions, contract review)
Land acquisition, easements, and rights of way
Insurance
Building permits
Performance testing, including start-up and testing fuel and expendables
and initial fills of all fuels and expendables
Training
Documentation and as-built drawings
Shipping charges
Sales and services tax
Spare parts and special tools
5.6.3 Financing Costs
Where CHP project are financed with bonds or third-party debt, financing costs
can add to the project capital budget. Typical cost elements include the following:
• Bond or financing consultant
• Legal consultants
• Lender’s independent engineer fees
• Government fees and taxes
• Rating agency fees
• Debt insurance
• Interest paid during construction (include consideration of interest earned during
construction if appropriate)
• Bank fees
• Working capital
Most budgets also include a contingency or an allowance for unforeseen costs and
requirements. Early in the design process, the contingency may be in the range of 15 to
20% of the estimated project cost. As the design uncertainty is reduced, the contingency
decreases accordingly. A 5% contingency is not atypical at the completion of design.
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CHAPTER 6
POWER GENERATION EQUIPMENT AND SYSTEMS
This chapter provides a detailed overview of characteristics of major power equipment
(reciprocating engines, combustion turbines, microturbines, and steam turbines), including
•
basic concepts,
•
operating characteristics,
•
efficiency,
•
heat recovery characteristics,
•
part-load operation,
•
start-up considerations,
•
maintenance,
•
availability,
•
fuel capabilities,
•
emission characteristics and controls, and
•
noise and vibration.
A general overview is also presented of emerging prime-mover technologies, such
as fuel cells, Rankine cycle systems, and Stirling engines. Finally, a detailed overview
of synchronous and induction generators is presented. Additional information on the
application of these prime movers and generators is covered in other chapters of this guide.
6.1 PRIME MOVERS
The prime mover that converts a fuel’s chemical energy or available thermal energy
into power is the heart of any CHP system. Commercially available fuel-based energy
conversion devices include internal-combustion reciprocating engines, combustion
turbines, microturbines, and fuel cells. Commercially available thermal energy systems
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include steam-driven turbines and Rankine and Stirling cycle systems. This chapter
reviews the characteristics of these commonly used CHP prime movers and aids in
understanding how best to apply each prime mover. Prime-mover design and
construction characteristics can be found in the 2012 ASHRAE Handbook—Systems
and Equipment, Chapter 7, and other references listed in this guide.
6.2 INTERNAL-COMBUSTION ENGINES
Reciprocating internal-combustion engines have been successfully applied to
direct-drive and power-generation applications. Direct-drive applications include
compressors, pumps, vapor-compression-cycle chillers, heat pumps, and other
mechanical shaft horsepower applications. Electric power applications include standby
and emergency service, peak shaving, uninterruptible power supplies, and prime power
systems. When equipped with heat recovery to produce both power and useful thermal
energy, the reciprocating engine provides CHP service. Reciprocating engines are very
efficient in small sizes, are available over a broad range of sizes from 5 kW to more
than 18 MW, can be fired on a broad variety of fuels, and are very reliable. As a result,
they have been used in numerous CHP systems serving residential, commercial,
institutional, and industrial loads.
Automotive-derivative engines (generally less than 100 kW), off-road equipment
(generally ranging in size from 100 to 1500 kW), stationary power engines (ranging in
size from a few hundred to 1600 kW), and marine engines (sizes ranging up to 18,000
kW or more) have all been successfully applied to on-site power applications, either
with or without heat recovery.
6.2.1 Reciprocating-Engine Concepts
Two primary reciprocating-engine designs are relevant to stationary power
generation applications: the spark ignition (SI) Otto cycle engine and the compression
ignition diesel cycle engine. The essential mechanical components of Otto cycle and
diesel cycle engines are the same. Both have cylindrical combustion chambers in which
closely fitting pistons travel the length of the cylinders. The pistons are connected to a
crankshaft by connecting rods that transform the linear motion of the pistons into the
rotary motion of the crankshaft. Most engines have multiple cylinders that power a
single crankshaft.
The primary difference between the Otto and diesel cycles is the method of igniting
the fuel. Otto cycle or SI engines use a spark plug to ignite the premixed air-fuel
mixture after it is introduced into the cylinder. Diesel cycle engines compress the air
introduced into the cylinder, raising its temperature above the autoignition temperature
of the fuel, which is then injected into the cylinder at high pressure. Increased focus on
reducing engine exhaust emissions has largely contributed to the rise of natural gas and
renewable fuels versus liquid fuels in spark ignition engines as the design of choice for
CHP applications. Diesel cycle engines still remain the design of choice for emergency
and standby generators that operate limited run hours.
The Otto cycle is also called a constant-volume or explosion cycle. This is the
equivalent air cycle for reciprocating piston engines using spark ignition. Figure 6-1
shows the P-V and T-S diagrams, respectively. At the start of the cycle, the cylinder
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contains a mass of air at the pressure and volume indicated at point 1. The piston is at
its lowest position. It moves upward, and the gas is compressed isentropically to point
2. At this point, heat is added (combustion) at constant volume which raises the pressure
to point 3. The high-pressure charge now expands isentropically, pushing the piston
down on its expansion stroke to point 4, where the charge rejects heat at constant
volume to the initial state, point 1.
6.2.2 Performance Characteristics
Important performance characteristics of an engine include its power rating, fuel
consumption, and thermal output. Manufacturers base their engine ratings on the
engine duty: prime power, standby operations, and peak shaving. Because a CHP
system is most cost-effective when operating at its base load, the rating at continuous
duty or prime power (i.e., when the engine is a primary source of power) is usually of
greatest interest. This rating is based on providing extended operating life with
minimum maintenance. Standby duty is typically based on maximum power output for
a limited number of run hours and normally exceeds the continuous duty rating. Peak
power implies an operation level for only a few hours per day to meet peak demand and
is more in line with standby duty ratings.
Many manufacturers rate engine capacities according to ISO Standard 3046-1,
which specifies that continuous net brake power under standard reference conditions
(total barometric pressure 14.5 psia [100 kPa], corresponding to approximately 330 ft
[100 m] above sea level, air temperature 77°F [25°C], and relative humidity 30%) can
be exceeded by 10% for 1 h, with or without interruptions, within a period of 12 h of
operation. ISO Standard 3046-1 defines prime power as power available for continuous
operation under varying load factors, including 10% overload. The standard defines
standby power as power available for operation under normal varying load factors, not
overloadable (for applications normally designed to require a maximum of 300 h of
service per year).
To determine the site-specific engine rating, the basis of the manufacturer’s ratings
(ambient temperature, altitude, and atmospheric pressure of the test conditions) must
be known. Various derating factors are then used to adjust the manufacturer’s nominal
Figure 6-1. Otto Cycle P-V and T-S Diagrams
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rating to site-specific values. Naturally aspirated engine output typically decreases 3%
for each 1000 ft (300 m) increase in altitude, whereas turbocharged engines lose 2%
per 1000 ft (300 m). Engine output decreases about 1% per 10°F increase in ambient
temperature, so it is important to avoid using heated air for combustion. In addition, an
engine must be derated for fuels with a heating value significantly less than or greater
than the base specified by the manufacturer. For CHP applications, natural gas is the
baseline fuel, although use of landfill gas, digester gas, and biomass is increasing, and
propane and liquid fuels can be used for locations not served by natural gas.
Reciprocating internal-combustion engines are classified according to operating
conditions as stoichiometric, rich-burn, or lean-burn, based on their inlet air-to-fuel
ratio and exhaust oxygen content. Stoichiometric engine operation is defined as having
the chemically correct amount of air in the combustion chamber during combustion. A
rich-burn engine is characterized by having excess fuel in the combustion chamber
during combustion and alsohaving lower exhaust oxygen concentrations. A lean-burn
engine, on the other hand, is characterized by excess air in the combustion chamber
during combustion, which results in higher exhaust oxygen concentration.
Rich-burn engines operate near the stoichiometric air-to-fuel ratio (16:1), with
exhaust excess oxygen levels less than 4% (typically closer to 1%). Additionally, it is
likely that the emissions profile will be considerably different for a rich-burn engine at
4% oxygen than when operated closer to stoichiometric conditions.
Lean-burn engines may operate up to the lean flame extinction limit, with exhaust
oxygen levels of 12% or greater. The air to fuel ratios of lean-burn engines range from
20:1 to 50:1 and are typically higher than 24:1. The exhaust excess oxygen levels of
lean-burn engines are typically around 8%, ranging from 4 to 17%. Using high-energy
ignition technology, very lean fuel-air mixtures can be burned in natural gas engines,
lowering peak temperatures within the cylinders and resulting in reduced NOx emissions.
Natural gas engine efficiencies range from about 28% (LHV) for small stoichiometric
engines (<50 kW) to 47% (LHV) for large (5 MW or greater) lean-burn engines.
Power rating is determined by a number of engine design characteristics, the most
important of which is displacement; other factors include rotational speed, method of
ignition, compression ratio, aspiration, cooling system, jacket water temperature, and
intercooler temperature. Most engine designs are offered in a range of displacements
achieved by different bore and stroke, but with the same number of cylinders in each
case. Many larger engine designs retain the same basic configuration, and displacement
increases are achieved by simply lengthening the block and adding more cylinders.
High engine speeds like 1800 rpm engine shown in Figure 6-2 result in a high
power density and lower installed cost.
As noted, engines also are categorized by their original design purpose: automotive,
truck, industrial, locomotive, or marine. Engines intended for industrial use are fourstroke Otto cycle engines and are designed for durability and for a wide range of
mechanical drive and electric power applications. Stationary engine sizes delivering
generator outputs ranging from 5 kW to more than 18 MW, including industrialized
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auto and truck engines in the 60 to 600 kWe (see Figure 6-3) output range, and
industrially applied marine and locomotive engines to more than 18 MW. The largest
natural gas engine currently available for stationary CHP application is rated at 18.8
MW and is shown in Figure 6-4.
Finally, most modern engines are turbocharged to achieve higher power densities. A
turbocharger is a turbine-driven intake air compressor. The hot, high-velocity exhaust
gases leaving the engine cylinders power the turbine. Very large engines typically are
equipped with two turbochargers. On a carbureted engine, turbocharging forces more air
and fuel into the cylinders increasing the engine’s output. On a fuel-injected engine, the
mass of fuel injected must be increased in proportion to the increased air input. Cylinder
pressure and temperature normally increase as a result of turbocharging, increasing the
tendency for detonation for both spark ignition and dual fuel engines and requiring a
careful balance between compression ratio and turbocharger boost level. Turbochargers
normally boost inlet air pressure on a 3:1 to 4:1 ratio. A wide range of turbocharger
designs and models are used. Heat exchangers (called aftercoolers or intercoolers) are
Figure 6-2. Typical High-Speed Engine Generator at 1800 rpm
(Courtesy of Caterpillar Corporation)
Figure 6-3. Typical 75 kW Autoderivative
Engine Generator
(Courtesy of Tecogen Corporation)
Figure 6-4. 18.8 MW Lean-Burn Natural Gas Engine
(Courtesy of Wärtsilä)
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often used on the discharge air from the turbocharger to keep the temperature of the air
to the engine under a specified limit. Intercooling on forced-induction engines improves
volumetric efficiency by increasing the density of intake air to the engine (i.e., colder air
charge from intercooling provides denser air for combustion, thus allowing more fuel
and air to be combusted per engine stroke, increasing the output of the engine).
6.2.3 Reciprocating-Engine Efficiency
Figure 6-5 illustrates the efficiency of typical SI natural gas engine/shaft power
operating at the continuous-duty or prime power rating (HHV).
Fuel consumption is the greatest contributor to operating cost and should be
carefully considered during planning and design of a CHP system. It is influenced by
combustion cycle, engine speed, compression ratio, and type of aspiration. It is often
expressed in terms of fuel input per unit of electric power output for natural gas engine
generators, or in some cases, it may be expressed as a ratio of fuel input per unit of
mechanical power output at the engine shaft, such as Btu/h per brake horsepower. The
former is known as the heat rate and equals 3412 divided by efficiency [or W/W, J/J, or
kJ/kWh.]. The heat rate can be based on either the LHV or HHV of the fuel but must
be so noted. Most engine manufacturers express the heat rate in terms of LHV to
measure combustion efficiency, but LHV must be converted to HHV for proper
economic evaluation.
Heat rates of several SI engine generators are shown in Figure 6-6. The heat rate
for an engine of a given size is also affected by design and operating factors other than
displacement.
Figure 6-5. Typical Efficiency (HHV) of Stoichiometric Spark Ignition Engine Generators
(Figure 14, Chapter 7, 2012 ASHRAE Handbook—HVAC Systems and Equipment)
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6.2.4 Reciprocating-Engine Heat Recovery Characteristics
The primary function of a heat recovery system is the recovery of the heat produced
during the power generation process, and any system design must also allow for
effective heat rejection if the thermal loads addressed by the system are lower than the
heat produced by the engine. The second function of the heat recovery system is the
application of the recoverable heat to an economically useful function. Failure to
adequately reject heat can result in catastrophic engine failure; failure to recover and
use heat to the fullest extent possible can result in significant diminished economic
return of the CHP system.
A reciprocating engine rejects heat from the following sources: radiation from the
engine block and other hot surfaces, exhaust gases, lubricating oil, jacket water, and,
for turbocharged and aftercooled engines, the engine aftercooler or intercooler. Heat
recovery characteristics vary as a function of engine speed, engine output, combustion
type (rich burn versus lean burn), engine design, and heat rejection strategy.
Manufacturer specifications should be carefully reviewed to determine the heat
rejection characteristics for a specific installation. Because there are no universally
accepted standards for quantifying heat recovery, it is important to note heat rejection
reference temperatures. In particular, the maximum allowable cooling-water circuit
return temperature defines the ability of a specific engine design and configuration to
meet the thermal load needs.
The most commonly used sources of heat recovery for reciprocating engines are
the engine exhaust gases, which typically exceed 1200°F (649°C), and the jacket
coolant, which is typically less than 240°F (116°C). Almost all the jacket heat can be
recovered as hot water.
Figure 6-6. Heat Rate (HHV) of Stoichiometric Spark Ignition Engines
(Figure 15, Chapter 7, 2012 ASHRAE Handbook—HVAC Systems and Equipment)
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Heat can also be recovered from the exhaust gases, which can reach temperatures
in excess of 1200°F (649°C), and from the lubricating and turbocharger aftercooler
heat exchangers. Engine exhaust gases are lower in oxygen content (typically 4% to
8%) than combustion turbine exhaust gases, and, therefore, supplemental combustion
in the exhaust is generally not possible. Lube oil and aftercooler heat recovery is
generally at low temperatures (usually less than 160°F [71.1°C]) with return temperature
requirements of less than 120°F (49°C) and is of limited use unless low-temperature
heat loads are available, such as swimming pool heating, parking lot defrosting, etc.
As previously discussed, the thermal-to-electric ratio (T/E) is a measure of the
useful thermal output per unit of electrical power being generated. For most reciprocating
engines, the recoverable thermal energy is that of the exhaust, the oil cooler, and jacket.
Note that more electrically efficient engines will have a lower thermal-to-electric ratio
and vice versa. The thermal electric ratio may be expressed as the ratio of kilowatts
thermal (kWth) to kilowatts electric (kWe) output or as a ratio of thermal output in
thousands of Btu per kilowatt of electric output. This is an important factor in selecting
an appropriate engine for a given site with a given heat load. The T/E ratio of the site
loads should be matched as closely as possible to the T/E ratio of the prime mover for
maximum load factor.
6.2.5 Reciprocating-Engine Part-Load Operation
Ideally, a CHP plant should operate at full output all the time to achieve maximum
cost effectiveness. In plants that must operate at part load some of the time, part-load
fuel consumption and thermal output are important factors that must be considered in
the overall operation and economics of the plant. Figure 6-7 shows the part-load heat
rate as a function of load for three engine sizes.
Figure 6-7. Part-Load Heat Rate (HHV) of 1430, 425, and 85 kW Gas Engines
(Figure 17, Chapter 7, 2012 ASHRAE Handbook—HVAC Systems and Equipment)
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6.2.6 Reciprocating-Engine Start-Up
Liquid-fueled reciprocating engines have excellent block loading capabilities.
They are frequently used as emergency generators in health care institutions, where
there is a requirement for the generator to pick up and carry load within 10 seconds of
an outage of the primary source of power. Natural-gas-fueled engines require block
loading in 25% of full power increments which means achieving full-load capabilities
within several minutes of a outage primary outage.
6.2.7 Reciprocating-Engine Maintenance and Availability
Maintenance costs vary with type, speed, size, and numbers of cylinders of an
engine and typically include the following:
• Maintenance labor
• Engine parts and materials, such as oil filters, air filters, spark plugs, gaskets,
valves, piston rings, electronic components, etc., and consumables such as oil.
• Minor and major overhauls
Maintenance can either be done by in-house personnel or contracted out to
manufacturers, distributors, or dealers under service contracts. Full maintenance
contracts (covering all recommended service) generally cost $0.01 to $0.02/kWh24
depending on engine size, speed, and service. Many service contracts now include
remote monitoring of engine performance and condition and allow for predictive
maintenance. Service contract rates typically are all-inclusive, including the travel time
of technicians on service calls.
Recommended service is comprised of routine short interval inspections/
adjustments including periodic replacement of engine oil and filter, coolant, and spark
plugs (typically at 500 to 2000 h of operation). An oil analysis is part of most preventive
maintenance programs to monitor engine wear. A top-end overhaul is generally
recommended between 8000 and 30,000 h of operation (see Table 6-1) that entails a
cylinder head and turbocharger rebuild. A major overhaul is performed after 30,000 to
72,000 h of operation and involves piston/liner replacement, crankshaft inspection,
bearings and seals (Table 6-1).
Estimated availability of reciprocating engines operating on clean gaseous fuels,
such as natural gas, is 85 to 92%.
Table 6-1. Representative Overhaul Intervals for Natural Gas Engines
in Baseload Service
Time Between Overhauls, 1000 operating h
Engine Speed
720 rpm
900 rpm
1200 rpm
1500 rpm
1800 rpm
Minor Overhaul
> 30
15 to 36
24 to 36
10 to 20
8 to 15
Major Overhaul
> 60
40 to 72
48 to 60
30 to 50
30 to 36
Source: EPA (EPA 2002)
Engine maintenance cost per kWh has remained relatively stable over the past decade; all
economic considerations should be updated when costing out any CHP project.
24
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6.2.8 Reciprocating-Engine Fuel Capabilities
Reciprocating engines are capable of firing a number of different gaseous and liquid
fuels. Gaseous fuel engines can fire natural gas, sour gas, methane, propane, propane
mixtures (butane or air), manufactured gas, digester gas, and landfill gas. Some gases,
such as manufactured gas, have calorific values as low as 200 BtuBtu/ft3 (7460 kJ/m3)
on an LHV basis, whereas other gases, such as propane and butane, have calorific values
as high as 4000 Btu/ft3 (149,000 kJ/m3) LHV. Low-calorific-value gases often require
oversizing of some components, such as the carburetor, and significant derating of the
engine capacity. Nonconventional gas sources, such as landfill gas and manufactured
gas, require preprocessing, including filtration, to remove impurities including water
vapor, abrasive particles such as siloxanes, and corrosive substances. Particular attention
must be given to removal of sulfur compounds such as H2S, which will attack bushings,
bearings, carburetors, regulators, valves, and spark plugs, causing early failure. As an
alternative, the use of bearings and bushings made from materials that are not susceptible
to attack by sulfur and sulfuric acids may be cost effective. If an engine is to be operated
on fuels derived from landfills or digesters, the maintenance program should include
frequent gas analyses to identify any changes in the fuel’s chemical composition. Some
dirtier fuels may require more frequent changes of the lubricating oil. Finally, it may be
prudent to operate the engine at higher temperatures, if allowable, to reduce the amount
of water that might combine with sulfides, creating acids.
Also, reciprocating engines are capable of operating on several different gaseous
fuels. For example, systems designed to burn wastewater treatment plant digester gas may
be equipped to burn propane and/or pipeline-quality natural gas. These systems use
microprocessor-controlled carburetion systems to adjust the fuel/air mixture as the fuel
and the fuel’s calorific value varies. In some cases, where the calorific value of the fuel
cannot be controlled, as may be the case with landfill gas, the gas with varying heat content
is mixed with a pipeline-quality gas to produce a constant-quality gas fuel for the engine(s).
Additionally, the mixing results in a higher calorific value and a higher engine rating.
Liquid fuel engines can operate on a number of fuels, including distillate oil,
medium-weight and heavier residual fuels, and biodiesel. The heavier fuels are much
less costly than lighter oils; however, they generally result in higher engine maintenance
costs and more extensive maintenance procedures as well as increased emissions,
which may preclude their use in many regions. In addition, the heavier fuels can result
in fuel-handling problems, including the need for removal of contaminants and trace
materials and steam tracing in cold climates.
6.2.9 Reciprocating-Engine Emission Characteristics and Controls
Exhaust emissions are the major environmental concern with reciprocating engines.
The main pollutants are oxides of nitrogen (NOx), carbon monoxide (CO), and volatile
organic compounds (VOCs; unburned or partially burned nonmethane hydrocarbons).
Other pollutants, such as oxides of sulfur (SOx) and particulate matter (PM), depend on
the fuel used. Emissions of sulfur compounds (particularly SO2) are directly related to
the fuel’s sulfur content. Engines operating on natural gas or distillate oil, which has
been desulfurized in the refinery, emit insignificant levels of SOx. NOx emissions, usually
the major concern with natural gas engines, are mostly a mixture of NO and NO2.
Measurements of NOx are reported as parts per million by volume, in which both
molecules count equally (e.g., ppmv at 15% O2, dry). Other common units for reporting
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NOx in reciprocating engines are specific output-based emission factors, such as grams
per horsepower-hour (g/hp·h) and grams per kilowatt-hour (g/kWh), or as total output
rates, such as pounds per hour (lb/h) or kilograms per hour (kg/h). Among the engine
options without exhaust aftertreatment, lean-burn natural gas engines produce the lowest
NOx emissions. In many localities, emissions pollutant reduction is mandatory. Threeway catalytic reduction is the general method for stoichiometric and rich-burn engines,
and selective catalytic reduction (SCR) for lean-burn engines.
6.2.10 Reciprocating-Engine Noise and Vibration
Both airborne and structurally carried noise emanating from a reciprocating engine
must be evaluated, and manufacturers generally can provide data on both airborne
exhaust and mechanical or structural noise emissions. Airborne noise consists of noise
radiated by the engine itself, from the engine exhaust and intake, and possibly from aircooled radiators and heat recovery boilers. Various methods for the control of structural
or mechanical noise include simply directing air intake and exhaust openings away from
potential receptors, vibration isolators, baffles, noise-absorbing materials, simple
enclosures, sound-absorbing enclosures, and various combinations of the these
techniques. Airborne exhaust noises can be reduced using silencers that can also function
as a heat recovery device. Vibration can be a challenge within an engine generator set
and can be transmitted to the facility through the engine base. Vibration can be minimized
through the use of isolators, which consist of springs mounted between the engine base
and the concrete foundation. Steel-spring isolators are capable of isolating more than
95% of engine vibrations; other materials can be used as isolators with less efficiency.
Another approach to vibration control is using isolating materials between the engine
foundation and the facility’s structure. Gravel and sand are typical materials and can
reduce vibrations by as much as 50%. The supporting bed should extend beyond the
dimensions of the foundation. Glass-fiber blocks are effective as isolation material for
concrete bases, which should be thick enough to prevent deflection.
Piping that connects the engine to coolant, exhaust, and fuel systems and electrical
conduits can also transmit engine vibrations and must be isolated. Pipe hangers that
include springs for vibration control are generally used; pipe hanger spacing is varied
to eliminate resonance.
6.3 COMBUSTION TURBINES
Combustion turbines (CTs) have been developed for stationary use as prime
movers. CTs are available in sizes delivering 1.3 to 480 MW and can burn a wide range
of liquid and gaseous fuels. Turbines, when available as dual-fuel engines, can shift
from one fuel to another without loss of service. Microturbine systems (covered in the
next section) typically range between delivered electric capacities of 30 to 250 kW.
CTs consist of an air compressor section to boost combustion air pressure, a
combination fuel/air mixing and combustion chamber (combustor), and an expansion
power turbine section that extracts energy from the combustion gases. Simple-cycle
combustion gas turbines have delivered electric efficiency levels of 28 to 40% LHV.
Recuperated combustion gas turbines (Figure 6-8) preheat combustion air from the
compressor exhaust with heat from the turbine discharge gas, thereby significantly
increasing the engine’s mechanical or electric efficiency.
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Figure 6-8. 4600 kW ISO-Rated Recuperated Combustion Turbine
(Courtesy of Solar Turbines)
Unrecuperated or simple-cycle combustion turbines have lower electric efficiencies
but higher exhaust temperatures, which may make them better suited for some CHP
applications depending on site electric and thermal requirements. Most turbines are the
single-shaft type, (i.e., the air compressor, and turbine are on a common shaft) as shown in
Figure 6-9. However, dual-shaft machines, which use one turbine stage on the same shaft
as the compressor and a separate power turbine driving the output shaft, are also available.
Combustion turbines have the following advantages and disadvantages compared to
internal combustion engine drivers:
•
•
•
•
•
•
•
•
•
•
•
25
Advantages
High power density (high power-to-size and power-to-weight ratios)
Lower emissions
High reliability
Longer maintenance intervals
No cooling water required
Vibration-free operation
Clean, dry exhaust
Disadvantages
More complex devices
Generally lower electrical output efficiency compared to internal
combustion engines25
More sensitive to fuel contaminants
Higher equipment capital costs
Simple-cycle (non-recuperative) CTs, when compared to the same size reciprocating engine.
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Figure 6-9. 7.9 MW Simple-Cycle Combustion Turbine/Generator
(Courtesy of Solar Turbines)
CT concepts are simple, compared to other technologies. The simplest open-cycle
system operation consists of three major components, as shown in Figure 6-10, and
operates through a Brayton cycle. The Brayton cycle consists of adiabatic compression,
constant-pressure heating, and adiabatic expansion. Figure 6-10 shows that the thermal
efficiency of a gas turbine falls below the ideal value because of inefficiencies in the
compressor and turbine and because of duct losses. Entropy increases during the
compression and expansion processes, and the area enclosed by points 1, 2, 3, and 4 is
reduced. This loss of area is a direct measure of the loss in efficiency of the cycle.
Nearly all turbine manufacturers present gas turbine engine performance in terms
of power output and specific fuel consumption26. A comparison of fuel consumption in
specific terms is the quickest way to compare overall thermal efficiencies of gas turbines
(ASME 2005).
The first major component is a compressor, which takes air in at atmospheric
pressure and increases air pressure to the level required in the combustor and power
turbine. Although no heat is added during compression, the work of compression does
increase the air temperature. Older and typically smaller turbines operate at air pressures
of up to 300 psig (2067 kPa [gage]) (a pressure ratio in the range of 15:1), whereas
newer and larger turbines operate at pressures approaching 600 psig (4137 kPa [gage])
(pressure ratio of 30:1). In some cases, where the turbine operates at high pressures, the
compressor may be split into several stages and the partially compressed combustion air
cooled during successive stages. This compressor intercooling reduces the work required
of the compressor. Because the compressor can require 50% or more of the power
developed in the turbine, intercooling can have a significant effect on turbine output.
26
Specific fuel consumption is the rate of fuel consumption divided by the power produced.
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The compressed, high-temperature air is then delivered through a diffuser to a
constant-pressure combustion chamber where fuel is injected and burned, further
increasing the temperature of the turbine gases. The diffuser reduces the air velocity
to values acceptable in the combustor; in practice, the pressure drop across the
combustor is in the range of 1to 2%. Combustion takes place with a considerable
amount of excess air that dilutes and lowers the temperature of the turbine exhaust
gases. Combustor exhaust gases can exceed 2300°F (1260°C) and have oxygen
concentrations of up to 15 or 16%.
The high-temperature combustor exhaust gases are then delivered to the turbine.
In the turbine, the exhaust gas energy is converted to kinetic energy and then to
mechanical work. The turbine itself is divided into two portions: the gas generator,
which consists of the turbine stages required to drive the compressor plus the
compressor, and the power turbine, which consists of the turbine stages required to
drive the externally driven equipment. Much of the work developed in the turbine,
sometimes as much as two-thirds of the turbine’s output, is required by the gas
generator. The turbine exhaust gases are considerably cooler than the combustor
exhaust gases, generally in the range of 850 to 1100°F (454 to 593°C).
Figure 6-10. Pressure-Volume and Temperature-Entropy Diagrams for Brayton Cycle
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In some cases, the compressor and turbine are mounted on a single shaft, and the
entire power train operates at the same speed. These turbines are typically used in
constant-speed operations. Smaller turbines will rotate at high speeds (sometimes as
high as 20,000 rpm), and, therefore, a gear box is required to link the power turbine to
the load, particularly when the turbine is driving a generator. Larger turbines, typically
15 MW or greater, operate at 3000 or 3600 rpm, thus avoiding the need for a gear box.
Some turbines operate with multiple shafts where the higher pressure turbines are
connected to the axial compressor, and the lower pressure or power portion of the
turbine is connected to the load. Multishaft turbines, when combined with multistage
compressors, are referred to as two-spool machines, and they can be operated at
extremely high mechanical efficiency. Larger turbines operate at lower speeds or with
multiple shafts, sometimes allowing a direct-drive application.
Figure 6-11 and Figure 6-12 show the major components of a simple-cycle single
shaft and dual-shaft turbine generators, respectively.
Figure 6-11. Simple-Cycle, Single-Shaft Turbine
Figure 6-12. Simple-Cycle, Dual-Shaft Turbines
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The turbine used depends on job requirements. Single-shaft turbines are usually
selected when a constant-speed drive is required, as in generator drives, and when
starting torque requirements are low. A single-shaft turbine can be used to drive
centrifugal compressors, but the starting system and the compressor match point must
be considered. Dual-shaft turbines allow for variable speed at full load and can easily
be started with a high-torque load connected to the power output shaft, and the power
turbine can be more optimally configured to match load requirements.
6.3.1 Combustion Turbine Performance Characteristics
Air enters the CT at ambient conditions, and the amount of work required of the
compressor and the fuel required to achieve specified turbine inlet pressure and
temperature varies as a function of ambient conditions. Manufacturers specify turbine
capacity and performance at the standardized conditions specified by the International
Standards Organization (ISO), which are defined as 59°F (15°C), 60% relative humidity,
and at sea level elevation (a pressure of 14.7 psia [101 kPa]). In addition, CT performance
(power output and efficiency) is typically specified without pressure drops/losses in the
combustion turbine inlet or exhaust systems.
The power output e capacity of a CT decreases as altitude or ambient temperature
increases. Turbine capacity may decrease by approximately 2 to 4%, depending on the
turbine design, for each 1000 foot (305 m) increase in altitude.
Increases in ambient temperature above the ISO rating of 59°F (15°C) can have
significant impact on a CT’s output capacity and efficiency. Increase in temperature
decrease air density and results in lower air mass flow and lower power output capacity.
One or more of the several technologies (discussed in section 6.3.9) may be used to
cool the turbine inlet air and offset capacity losses during high-ambient-temperature
conditions. The economics of using turbine inlet air cooling and the type of system
used to provide cooling depend on ambient weather conditions and the value of power
output among other issues. Although the degree of capacity and efficiency losses
caused by increasing inlet air temperature are a function of the turbine design, capacity
losses can be as much as 5% per 10°F (~5.6°C) increase in inlet air temperature. For
further discussion on this topic, see the 2012 ASHRAE Handbook—Systems and
Equipment, Chapter 8. Figure 6-13 and Figure 6-14 show typical effects of ambient air
temperature on power output and heat rate, respectively, for the two types of turbines.
The actual performance of a specific CT at different inlet air temperatures depends on
its design. Figure 6-13 and Figure 6-14 show that aeroderivative CTs are more sensitive
to ambient air temperature than are industrial-frame27 CTs. Figure 6-13 (Punwani and
Hurlbert 2006) shows that, for a typical aeroderivative CT, an increase in inlet air
Industrial-frame gas turbines are built specifically for continuous duty over long periods of
time. Because these machines are not designed to minimize weight as a jet engine is, they select
materials for long life, without compromise between weight and endurance. Industrial or frame
gas turbines are exclusively for stationary power generation and are available in the 1 to 250
MW capacity range. They are generally less expensive, more rugged, can operate longer between
overhauls, and are more suited for continuous base-load operation with longer inspection and
maintenance intervals than aeroderivative turbines. However, they are less efficient and much
heavier. Industrial gas turbines generally have more modest compression ratios (up to 16:1) and
often do not require an external fuel gas compressor.
27
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Figure 6-13. Effect of Ambient Temperature on CT Output
(Punwani and Hurlbert 2005)
temperature from 59°F to 100°F (15°C to 38°C) on a hot summer day decreases power
output to about 81% of its rated capacity, a loss of 19% of the rated capacity. Figure
6-14 (Punwani 2003) shows that, for the same change in ambient air temperature, the
heat rate of a typical aeroderivative28 CT increases (i.e., fuel efficiency decreases) by
about 4% of the rated heat rate at ISO conditions. Increasingly, industrial-frame CTs
are using aeroderivative technology to improve performance; thus, their performance
curves are moving toward those of the classic aeroderivative CT.
CT capacity also decreases with increasing pressure losses in the inlet air or exhaust
sections of the turbine. Most applications require inlet air filters, silencers, and perhaps
inlet air cooling systems; most CHP applications require exhaust silencers and exhaust
heat recovery systems. Inlet pressure losses in filter, silencer, and ducting decrease
power output by approximately 0.5% for each inch of water column (2% per kPa)
pressure loss. Discharge pressure losses in waste heat recovery units, silencer, and
ducting decrease power output by approximately 0.3% for each inch of water column
(1.2% per kPa) pressure loss. Increase in pressure losses in the inlet and exhaust
sections also increases the CT heat rate.
Aeroderivative gas turbines for stationary power are adapted from their jet and turboshaft
aircraft engine counterparts. Although these turbines are lightweight and thermally efficient,
they are usually more expensive than products designed and built exclusively for stationary
applications. The largest aeroderivative generation turbines available are 40 to 50 MW in
capacity. Many aeroderivative gas turbines for stationary use operate with compression ratios in
the range of 30:1, requiring a high-pressure external fuel gas compressor.
28
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Both turbine capacity and efficiency also decrease over time as mechanical
clearances between both the compressor and the turbine blade tips and the stationary
casing increase. As hot-gas bypass through the clearances increases, blade erosion and
corrosion occurs, and the compressor is contaminated by dirt, resulting in decreased
capacity and efficiency. Typically, capacity can decrease by 2 to 6% over a three-year
period; however, a major overhaul of the turbine can restore performance to initial
values. Periodic compressor cleaning is also important in restoring the turbine’s original
performance.
Figure 6-14. Effect of Ambient Temperature on CT Heat Rate
(Punwani 2003)
Figure 6-14 (SI). Effect of Ambient Temperature on CT Heat Rate
(Punwani 2003)
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The Brayton or open-cycle turbine results in the exhausting of the working fluid,
which consists of air and combustion products, to the atmosphere. To minimize blade
corrosion, hot oxidation, and the resulting maintenance costs, the open-cycle turbine is
generally limited to the combustion of gaseous or light liquid fuels.
Figure 6-15 shows a typical performance curve for a 10,000 hp (7.5 MW) combustion
turbine engine. For example, at an air inlet temperature of 86°F (30°C), the turbine
develops its maximum power at about 82% of maximum speed. The shaft thermal
Figure 6-15. Turbine Engine Performance Characteristics
Figure 6-15 (SI). Turbine Engine Performance Characteristics
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efficiency of the prime mover is 18 to 35% with exhaust gases from the turbine ranging
from 806 to 986°F (430 to 530°C). If the exhaust heat can be used, overall thermal
utilization efficiency can increase.
Turbine inlet temperature and performance are also a function of design, and, in
general, efficiency increases with increasing turbine capacity. The turbine’s mechanical
efficiency is a function of the ratio of the turbine inlet and exhaust temperatures.
Efficiency can be increased by raising the temperature in the combustor, and
manufacturers are offering turbines with inlet temperatures approaching 2400°F
(1316°C). Lowering the turbine exhaust temperature can further improve efficiency; a
regenerative cycle, as shown in Figure 6-16, illustrates how this can be achieved. In
this case, the turbine exhaust gases are used to preheat combustion air prior to the
combustor, reducing the amount of fuel that is required to reach a specified turbine
inlet temperature and improving the heat rate of the turbine. Regeneration increases
the mechanical efficiency and the amount of power produced but increases the
complexity and system capital cost. It also decreases the availability of recoverable
heat in CHP systems, reducing the potential to displace fuel required by conventional
boilers. The increased cost of the regenerated turbine and the decreased value of
recovered heat must be evaluated against the increased power production to determine
if the regenerative cycle is cost effective.
6.3.2 Combustion Turbine Heat Recovery Characteristics
CT mechanical efficiency typically increases with increasing turbine size and,
therefore, the amount of recoverable heat decreases relative to the power or mechanical
output. As a result, the ratio of turbine thermal to electric output also varies as a
function of turbine size. Smaller simple-cycle turbines (ranging from 1000 to 4000
kW) produce as much as 40 to 45 lb (18 to 20 kg) of high-temperature exhaust gases
per kilowatt-hour, while larger turbines in excess of 50,000 kilowatts produce only
25 to 28 lb (11 to 13 kg) of exhaust gases per kilowatt-hour.
Figure 6-16. Combustion Turbine Regenerative Cycle
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Turbine exhaust temperatures vary in a range from 850 to 1100°F (454 to 593°C),
and the amount of heat that can be recovered depends on the application of the recovered
heat. If a heat recovery steam generator (HRSG) is used to produce steam or an exhaustfired absorption chiller is used, the need to avoid temperatures below the exhaust gas
acid dew points will limit heat recovery to exhaust gas exit temperatures of no less than
275 to 325°F (135 to 163°C). If exhaust heat recovery is required below the exhaust gas
acid dew points, it will be necessary to use corrosion resistant materials, such as
stainless steel, in the exhaust system. In addition, an acid collection and neutralization
system is required to prepare the acid for disposal. If the exhaust is used directly in a
process, the recoverable heat can be computed relative to the reference temperature of
the air that would be used in that process (frequently ambient air). Turbine exhaust
gases can be very clean, and when the turbine is operated on clean fuels, such as natural
gas or propane, the direct-process use of the exhaust can be practical.
6.3.3 Combustion Turbine Part-Load Operation
More than 50% of the work performed by the turbine can be required by the air
compressor. Single-shaft, simple-cycle turbines operate at constant speed and, therefore,
are devices of constant mass flow; compressor work does not change significantly as a
function of load. Because the compressor parasitic load is constant as the work output
of the turbine decreases, overall turbine efficiency decreases significantly. Larger
turbines use variable vanes on the first few compressor stages, thus reducing mass flow
and maintaining speed.
In comparison, some multispool turbines are able to adjust airflow and compressor
work as a function of output. However, because the work required by the compressor
does not usually decrease as a linear function of the net turbine output, these compressor
losses also become an increasing fraction of the work performed by the turbine.
Although efficiency does not fall off as quickly as for the single-shaft turbine, efficiency
is still reduced at part-load operation.
As with other prime movers, it is possible to operate a CT at increased power
levels, exceeding the nominal rating. This operating mode results in higher temperatures
in the hot-gas path and, as a result, the time between repairs or an overhaul of the hotgas section is decreased. Prolonged operation of the turbine at maximum levels typically
results in increased maintenance costs.
Exhaust heat recovery from simple-cycle CTs also varies as a function of output,
because both the turbine airflow and the exhaust gas temperature vary as a direct
function of output. Because CTs are mass-flow-dependent devices, power output is a
function of mass flow, which is affected by ambient temperature or inlet air temperature
if turbine inlet cooling is used. Figure 6-17 shows the typical relationship between
mass flow, exhaust temperature, and power output as a function of capacity and ambient
temperature for a simple-cycle CT.
Though exhaust gas temperatures from a regenerative CT may actually increase as
load drops from 100% to 75%, the reduced airflow results in a decrease in the total
amount of recoverable heat.
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Figure 6-17. Mass Flow, Exhaust Temperature, and Power Output as Function of Capacity
and Ambient Temperature
(Taniguchi and Miyamae 2000)
Figure 6-17 (SI). Mass Flow, Exhaust Temperature, and Power Output as Function of
Capacity and Ambient Temperature
(Taniguchi and Miyamae 2000)
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6.3.4 Combustion Turbine Maintenance and Availability
Routine maintenance practices include on-line running maintenance, predictive
maintenance, plotting trends, performance testing, fuel consumption, heat rate,
vibration analysis, and preventive maintenance procedures.
Daily maintenance includes visual inspection by site personnel of filters and
general site conditions. Routine inspections are required every 4000 h to ensure that
the turbine is free of excessive vibration caused by worn bearings, rotors, and damaged
blade tips. Inspections generally include on-site hot-gas-path boroscope inspections
and nondestructive component testing using dye penetrant and magnetic particle
techniques to ensure the integrity of components. The combustion path is inspected
for fuel nozzle cleanliness and wear, along with the integrity of other hot-gas-path
components.
A gas turbine overhaul is needed every 25,000 to 50,000 h depending on service.
Service typically includes a complete inspection and rebuild of components to restore
the gas turbine to nearly original or current (upgraded) performance standards.
A typical overhaul consists of dimensional inspections, product upgrades and testing
of the turbine and compressor, rotor removal, inspection of thrust and journal bearings,
blade inspection and clearances, and setting packing seals.
Gas turbine maintenance costs can vary significantly depending on the quality and
diligence of the preventive maintenance program and operating conditions. Although
gas turbines can be cycled, cycling significantly increases maintenance costs versus a
turbine that operates for intervals of 1000 h or more. In addition, operating the turbine
over the rated capacity for significant periods of time dramatically increases the
number of hot-path inspections and overhauls. Gas turbines that operate for extended
periods on liquid fuels experience higher than average overhaul intervals.
Two factors contribute to the high scheduled availability of combustion turbines:
modular design and simple operating cycles. Smaller industrial turbines of up to 20 MW
and aeroderivative turbines of up to 35 MW are modular and allow for removal and
replacement of the compressor and/or turbine. Thus, the interval required to perform
either a scheduled or unscheduled replacement of most components is relatively short
(ranging from one to four days). Larger turbines require more extensive fieldwork and
have longer outages. In addition, when operated in a constant-output, base-loaded mode,
the turbine is not subject to thermal and mechanical transients, further extending the
scheduled life.
Many operational conditions affect the failure rate of gas turbines. Frequent starts
and stops incur damage from thermal cycling, which accelerates mechanical failure.
Use of liquid fuels, especially heavy fuels and fuels with impurities (alkalis, sulfur,
and ash), radiates heat to the combustor walls significantly more intensely than occurs
with, clean, gaseous fuels, thereby overheating the combustor and transition piece
walls. On the other hand, steady operation on clean fuels can allow gas turbines to
operate for a year without need for shutdown. Estimated availability of gas turbines
operating on clean gaseous fuels, as for natural gas, is in excess of 95%.
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6.3.5 Combustion Turbine Start-Up
Combustion turbines can be relatively easy to start, requiring an external hydraulic
or electric motor, a small reciprocating engine, or compressed air. Depending on site
and design requirements, turbines can be equipped for a black start; that is, CTs can be
equipped to allow start-up with no external power sources available, or turbines may
require utility-supplied power during start-up. While CTs can carry load relatively
quickly, unless equipped for more rapid start-up, CTs cannot carry load as quickly as a
reciprocating engine. Heat recovery considerations, such as the need to bring an HRSG
to acceptable temperatures, may prove a more severe constraint on start-up time.
6.3.6 Combustion Turbine Fuel Capabilities
Combustion turbines require light fuels and typically operate on either gaseous
fuels or light distillate oil such as No. 2 fuel oil.
As noted previously, combustion takes place external to the power turbine itself
and typically in a combustor. Because combustion is external to the power section, it is
possible to change from a gaseous to a liquid fuel without shutting down the turbine
and without any significant change in the turbine’s mechanical output. It is this
characteristic that makes combustion turbines attractive when low-cost, interruptible
sources of natural gas are available.
Turbines operate at elevated pressures, and if a fuel is to be injected into the
combustor, it is necessary for the fuel pressure to be slightly higher than the turbine
working pressure. In some cases, high-pressure natural gas may be available from the
supplier, particularly if the CHP facility is located near a natural gas transmission
pipeline or a high-pressure distribution main. The more typical case is one where
natural gas is not available at the required pressures. If only low-pressure gas is
available, it is necessary to install fuel gas compressors as part of the CHP system. The
energy to drive these fuel compressors is a parasitic load to the CHP system and, in
many cases, where only low-pressure natural gas is available, the compressor load can
be as much as 4 or 5% of the turbine output. In some cases, the available gas pressure
may vary with season, although the local utility will usually provide regulations to
ensure a constant-pressure supply. In those cases, where seasonal pressure variations
and the compressor parasitic loads are significant, it may be cost effective to accept
varying pressures from the utility. A variable input pressure produces increased system
output during those periods when higher pressure gas is available from the local gas
distribution system. This option requires that the fuel compressors be capable of
accepting varying suction pressures. Finally, note that fuel compressors can be highmaintenance items subject to frequent unscheduled outages. Larger systems or
applications requiring high availability and reliability are often designed with three
compressors, each sized at 50% of the load, thus providing a redundant compressor.
6.3.7 Combustion Turbine Emission Characteristics and Controls
The primary pollutants from gas turbines are oxides of nitrogen (NOx), carbon
monoxide (CO), and volatile organic compounds (VOCs). Other pollutants, such as
oxides of sulfur (SOx) and particulate matter (PM), are primarily dependent on the fuel
used. The sulfur content of the fuel determines emissions of sulfur compounds,
primarily SO2. Gas turbines operating on desulfized natural gas or distillate oil emit
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relatively insignificant levels of SOx. In general, SOx emissions are greater when heavy
oils are fired in the combustion turbine. SOx control is thus a fuel issue rather than a gas
turbine technology issue. Particulate matter is a pollutant for gas turbines using liquid
fuels that, while not generally deemed significant, should be understood and evaluated.
Ash and metallic additives in the fuel may contribute to PM in the exhaust.
It is important to note that the CT operating load has a significant effect on the
emissions levels of the primary pollutants of NOx, CO, and VOCs. Gas turbines typically
operate at high loads. Consequently, gas turbines are designed to achieve maximum
efficiency and optimum combustion conditions at high loads. Controlling all pollutants
simultaneously at all load conditions is difficult. At higher loads, higher NOx emissions
occur because of peak flame temperatures. At lower loads, lower thermal efficiencies
and more incomplete combustion occurs, resulting in higher emissions of CO and VOCs.
The pollutant referred to as NOx is a mixture of mostly NO and NO2 in variable
composition. In emissions measurement, it is reported as parts per million by volume in
which both species count equally.
6.3.8 Combustion Turbine Noise and Vibration
CTs are rotary devices whose major source of direct noise is the turbulent heat
release process in the combustor. They generally produce high-frequency noise that
can be easily and inexpensively controlled. Care is required for the design of inlet
filters and exhaust stack sizing to eliminate air movement sounds. Noise levels within
a few feet (1 m) of the turbine enclosure are typically limited to a maximum of 85 dBa,
while levels of no more than 55 dBa to 65 dBa are typical outside the powerhouse.
Lower noise levels can be achieved through additional silencing.
Because of their light weight, low vibration signature, and smaller size, CT
foundations are not as large as those for other types of prime movers.
6.3.9 Combustion Turbine Inlet Cooling (CTIC)
As discussed previously, power output capacity of all CTs varies with ambient air
temperature and site elevation. For all CTs, increased ambient air temperature or site
elevation decreases power output; increased ambient air temperature also reduces fuel
efficiency (i.e., increases the heat rate, defined as fuel energy required per unit of
electric energy produced). However, the extent of the effect of these changes on output
and efficiency varies with CT design.
Many technologies are commercially available for CTIC, but the overall approaches
can be divided into three major groups:
• Evaporative cooling
• Chilled-fluid system
• Liquified natural gas (LNG) vaporization
Evaporative cooling systems rely on cooling produced by evaporation of water
added into the inlet air. An ideal evaporative cooling process occurs at a constant wetbulb temperature and cools the air to a higher relative humidity (i.e., water vapor content
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increases). When the warm ambient inlet air comes in contact with the added water, it
transfers some of its heat to the liquid water and evaporates some of the water. Studies
show that evaporative cooling also reduces NOx emissions, because the increase in
moisture added to the air cools the combustion temperature.
Evaporative systems can cool the inlet air up to 98% of the difference between the
ambient dry-bulb and wet-bulb temperatures. Therefore, the most cooling can be
achieved during hot and dry weather. Evaporative systems have the lowest capital costs
among CTIC systems, and are the most common in use. Their primary disadvantage is
that the extent of cooling produced is limited by the wet-bulb temperature (and thus,
the extent of cooling is weather dependent). There are two types of evaporative systems:
direct and indirect. Two primary direct evaporative system types are commercially
used for evaporative cooling: wetted media and fogging. An indirect evaporative
cooling (IEC) CTIC system cools the inlet air by an indirect exchange of heat with an
air or a water stream that has been cooled by direct evaporative cooling.
Chiller systems cool inlet air by exchange of heat through indirect or direct contact
between warm ambient inlet air and a cold fluid produced by chillers. In indirect heat
exchange systems, chilled fluid flows inside a coil while the inlet air flows across the
coil face. Typical inlet-air-side pressure drop across the heat exchange coil is about 1
in. of water (250 Pa). The water vapor content (humidity ratio) of the inlet air remains
constant as its dry-bulb temperature decreases. Ammonia is the most commonly used
chilled fluid in direct refrigerant applications; for indirect-contact heat exchange
systems, the preferred chilled fluid is often water, though water/glycol, HFCs, HCFCs,
and other aqueous fluids are also used. Chiller systems can use vapor compression and/
or absorption chillers, with or without thermal energy storage (TES). Vapor compression
chillers used in CTIC systems could be centrifugal, screw, or reciprocating, and could
be driven by electric motors, steam turbines, or engines. Absorption chillers require
thermal energy from steam, hot water, hot exhaust gases, or natural gas as the primary
source of energy, and need much less electric energy than vapor compression chillers.
LNG vaporization systems are useful for power plants located near a liquefied
natural gas (LNG) import facility. In supplying natural gas for pipelines, power plants,
or other applications, LNG must be vaporized by some heat source. For applications in
CTIC, the inlet air is used as such a heat source.
Hybrid systems combine at least two technologies, which can be used simultaneously
in a sequential process; in some systems, each technology may also be used individually.
Further discussion on CTIC is available in Chapter 8 of the 2012 ASHRAE Handbook—
HVAC Systems and Equipment.
6.4 MICROTURBINES
6.4.1 Microturbine Concepts
Microturbines are small electricity generators that burn gaseous and liquid fuels
generally operating at high speeds (rotational speed of 80,000 rpm in a 65 kW machine).
There is no single rotational speed-power size rule, because the specific turbine and
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compressor design characteristics strongly influence the physical size of components
and, consequently, rotational speed. Some models generate electrical power at high
frequency, and of variable frequency (alternating current). This power is rectified to
direct current and then inverted to 60 Hz for U.S. commercial use and also at 50 Hz
where required. In a two-shaft microturbine, the power turbine connects via a gearbox
to a generator that produces power at 60 Hz. Today’s microturbine technology is the
result of development work in small stationary and automotive gas turbines, auxiliary
power equipment, and turbochargers, much of which was pursued by the automotive
industry beginning in the 1950s. Microturbines entered field testing around 1997 and
began initial commercial service in 2000.
Microturbine capacity range on the market, in net delivered electricity, is from 30
to 250 kW (see Figure 6-18). Modular systems have been developed to provide up to 1
MW of power in an integrated system (see Figure 6-19).
Most microturbines feature an internal heat exchanger called a recuperator. In a
microturbine, a radial flow (centrifugal) compressor compresses inlet air, which is
then preheated in the recuperator using heat from the turbine exhaust. Next, the heated
air from the recuperator mixes with fuel in the combustor, and hot combustion gas
expands through the expansion and power turbines. The expansion turbine turns the
compressor and, in single-shaft models, also turns the generator. Two-shaft models
use the combustion gas to power a turbine to drive the air compressor (providing air
Figure 6-18. 250 kW Packaged CHP System
(Courtesy of FlexEnergy, Inc.)
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Figure 6-19. Five Modularized 200 kW Microturbine CHP System
(Courtesy of Capstone Turbine Corporation)
to the combustion chamber) and a second turbine downstream of the first to separately
drive the electric generator. Finally, the recuperator uses the exhaust of the power
turbine to preheat the air from the compressor (Figure 6-20).
6.4.2 Microturbine Performance Characteristics
Microturbines, like the larger combustion turbines, operate on the Brayton cycle
principle. In this cycle, atmospheric air is compressed, heated, and then expanded,
with the excess power produced by the expander (over that consumed by the
compressor) used for power generation. The power produced by an expansion turbine
and consumed by a compressor is proportional to the absolute temperature of the gas
passing through those devices. Consequently, it is advantageous to operate the
expansion turbine at the highest practical temperature consistent with economic
materials and to operate the compressor with inlet air at as low a temperature as
possible. As technology advances allow higher turbine inlet temperature, the optimum
pressure ratio also increases. Higher temperature and pressure ratios result in higher
efficiency and specific power.
6.4.3 Microturbine Efficiency
Microturbines are more complex than conventional simple-cycle combustion
turbines because of the addition of the recuperator, which reduces fuel consumption
(thereby, substantially increasing efficiency) and introduces additional internal
pressure losses that moderately lower efficiency and power. Typical microturbine ISO
efficiencies are 28% LHV fuel-to-power efficiency at 65 kW capacity and 33% LHV
fuel-to-power efficiency at 200 kW capacity.
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Figure 6-20. Single-Shaft Microturbine with Heat Recovery
Figure 6-21 represents one example of microturbine power output performance
with ISO 59°F (15°C) efficiency representing the design efficiency point. Peak
efficiency is achieved at 10°F (-12.2°C). Note that 0°F (-17.8°C) has a lower efficiency.
This occurs because this microturbine is limited in power output by other factors;
usually this is a limit within the power electronics.
6.4.4 Microturbine Heat Recovery Characteristics
Effective use of the thermal energy contained in the exhaust gas improves
microturbine system economics. Exhaust heat can be recovered and used in a variety
of ways, including for use in domestic water heating, space heating, steam generation,
and driving thermally activated equipment such as an absorption chiller or a desiccant
dehumidifier.
Microturbine CHP system efficiency is a function of exhaust heat temperature.
Recuperator effectiveness strongly influences the microturbine exhaust temperature.
Consequently, the various microturbine CHP systems have substantially different
overall efficiency and net heat rate to power. These variations in overall efficiency and
net heat rate stem mostly from the mechanical design and manufacturing cost of the
recuperators and their resulting impact on system cost, rather than from differences in
system size.
6.4.5 Microturbine Part-Load Operation
When less than full power is required from a microturbine, the output is reduced by
a combination of mass flow reduction (achieved by decreasing the compressor speed)
and turbine inlet temperature reduction. In addition to reducing power, this change in
operating conditions also reduces efficiency. Figure 6-22 shows a sample part-load
derated curve for a microturbine.
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Figure 6-21. Microturbine Efficiency Curve with Respect to ISO Efficiency
Figure 6-21 (SI). Microturbine Efficiency Curve with Respect to ISO Efficiency
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Figure 6-22. Single-Shaft Microturbine Part Load
6.4.6 Microturbine Maintenance and Availability
Maintenance costs vary with size, fuel type, and technology (air versus oil
bearings). Normal maintenance includes periodic air and fuel filter inspections and
changes, igniter and fuel injector replacement, and major overhauls of the turbine itself.
A typical microturbine maintenance schedule includes the following:
• 8000 h: replace air and fuel filters.
• 16,000 to 20,000 h: inspect/replace fuel injectors, igniters, and thermocouples.
• 20,000 h: battery replacement (standalone units).
• 40,000 h: major overhaul, core turbine replacement.
In addition to the microturbine itself, the fuel compressor also requires periodic
inspection and maintenance. The actual level of compressor maintenance depends on
the inlet pressure and site conditions.
The basic design and low number of moving parts hold the potential for systems
of high availability; manufacturers have targeted availabilities of 98 to 99%. The use
of multiple units or backup units at a site can further increase the availability of the
overall facility.
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6.4.7 Microturbine Start-Up
When startup has been initiated, the generator operates as a motor to bring the
microturbine up to ignition speed, at which point fuel is introduced into the combustion
chamber and ignited. When the turbine exit temperature (TET) sensors detect an
increase in temperature, the system is declared lit, and the microturbine accelerates to
full load. The start-up process from a cold start to full load requires up to two minutes.
6.4.8 Microturbine Fuel Capabilities
Microturbines are able to operate on a variety of fuels, including natural gas, sour
gases (high sulfur, low Btu content), landfill gas, digester gas, and liquid fuels such as
gasoline, biodiesel, kerosene, and diesel fuel/distillate heating oil. In resource recovery
applications, they burn waste gases that would otherwise be flared or released directly
into the atmosphere.
Microturbines are available that use methane-based oilfield flare casing gas or
low-energy (as low as 350 Btu) landfill/digester gas as fuel sources. Versions of these
are available that can accept sour gas with up to 7% hydrogen sulfide (H2S) content.
Microturbine gaseous fuel pressure requirements range between 70 and 115 psig
(0.43 MPa and 0.79 MPa [gage]).
6.4.9 Microturbine Emission Characteristics and Controls
Exhaust of microturbines is oxygen rich (approximately 15% to 18% O2), which
contributes to very low levels of air pollutants. Typical emissions levels for NOx, CO,
and VOCs are less than 5 ppm based on 15% O2 and pipeline quality natural gas.
Some fuels have inherently higher emissions levels. Liquid fuels generally have
higher NO2 and CO levels than natural gas. Landfill and digester gas fuels can have
lower NO2 levels with higher CO levels at full power. Fuels containing significant
amounts of CO and acetylene (C2H2) also result in higher NO2 emissions.
6.4.10 Microturbine Noise and Vibration
Microturbines are high-speed rotary devices and are relatively quiet and vibration
free. They generally produce high-frequency noise that can be easily and inexpensively
controlled. Care is required for the design of inlet filters and exhaust stack sizing to
eliminate air movement sounds. A typical sound rating for microturbines is 65 dBa at
33 ft (10 m). Lower noise levels can be achieved through additional silencing.
Because of their light weight, low vibration signature, and smaller size, microturbine
foundations are not as massive as those for other types of prime movers.
6.4.11 Microturbine Inlet Cooling
Microturbines can benefit from inlet cooling just as combustion turbines. The issue
with respect to microturbines is a matter of scale: the potential increase in output does
not justify the capital cost when considering the inlet cooling system power output.
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6.5 FUEL CELLS
Fuel cells convert chemical energy of a hydrogen-based fuel directly into electricity
without combustion. In the cell, a hydrogen-rich fuel passes over the anode, while an
oxygen-rich gas (air) passes over the cathode. Catalysts help split the hydrogen into
hydrogen ions and electrons. The hydrogen electrons move through an external circuit,
thus providing a direct current at a fixed voltage potential. A typical packaged fuel cell
power plant consists of a fuel reformer (processor), which generates hydrogen-rich gas
from fuel; a power section (stack) where the electrochemical process occurs; and a
power conditioner (inverter), which converts the DC power generated in the fuel cell
into AC power. Most fuel cell applications involve interconnectivity with the electric
grid; thus, the power conditioner must synchronize the electrical output of the fuel cell
with the grid (ASHRAE 2005).
A growing number of fuel cell applications are grid independent to reliably power
remote or critical systems.
Most fuel cells have similar designs, but differ in the type of electrolyte used. The
main types of stationary fuel cells, classified by their electrodes, are (1) phosphoric acid
(PAFC), (2) molten carbonate (MCFC), (3) solid oxide (SOFC), and (4) proton exchange
membrane (PEMFC. PAFCs, MCFCs, SOFCs and PEMFCs are commercially available.
The most significant research and development activities focus on PEMFC for automotive
and home use and SOFC for stationary applications. Efficiencies of several types of fuel
cells are shown in Table 6-2. Emissions from fuel cells are very low; NOx emissions are
less than 20 ppm. Large phosphoric acid fuel cells are commercially available.
6.5.1 Phosphoric Acid Fuel Cells (PAFCs)
PAFCs (Figure 6-23) operate at about 400°F (200°C) and can achieve 40% LHV
efficiencies. PAFCs use liquid phosphoric acid as an electrolyte. Platinum-catalyzed,
porous-carbon electrodes are used for both the cathode and anode. For each type of fuel
cell, the reformer supplies hydrogen gas to the anode through a process in which
hydrocarbons, water, and oxygen react to produce hydrogen, carbon dioxide, and carbon
monoxide. At the anode, hydrogen is split into two hydrogen ions (H+) and two electrons.
The ions pass through the electrolyte to the cathode, and the electrons pass through the
external circuit to the cathode. At the cathode, the hydrogen, electrons, and oxygen
combine to form water.
Table 6-2. Overview of Fuel Cell Characteristics
Commercially available
Phosphoric
Acid
(PAFC)
Yes
Size range
100 to 200 kW 1 kW to 10 MW 250 kW to 10 MW
500 W to 250 kW
Efficiency (LHV)
40%
45 to 60%
45 to 55%
30 to 40%
Efficiency (HHV)
36%
40 to 54%
40 to 50%
27 to 36%
Solid Oxide
(SOFC)
Yes
Molten Carbonate
(MCFC)
Yes
Proton Exchange
Membrane
(PEMFC)
Yes
Average operating temperature 400°F (200°C) 1800°F (980°C) 1200°F (650°C)
200°F (90°C)
Heat recovery characteristics
140°F (60°C) water
Hot water
Hot water/steam Hot water, steam
Source: Adapted from Foley and Sweetser (2002).
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6.5.2 Solid-Oxide Fuel Cells (SOFCs)
SOFCs operate at temperatures up to 1800°F (980°C), offering enhanced heat
recovery performance (Figure 6-24). A solid-oxide system typically uses a hard ceramic
material instead of a liquid electrolyte. The solid-state ceramic construction is a more
stable and reliable design, enabling high temperatures and more flexibility in fuel choice.
SOFCs can reach 54% HHV (60% LHV) efficiencies. Combined-cycle applications
could reach system efficiencies up to 77% HHV (85% LHV).
SOFCs can use carbon monoxide as well as hydrogen as direct fuel. Hydrogen and
carbon monoxide in the fuel stream react with oxide ions from the electrolyte, producing
water and carbon dioxide, and releasing electrons into the anode. The electrons pass
outside the fuel cell, through the load, and back to the cathode. At the cathode, oxygen
molecules from the air receive the electrons and the molecules are converted into oxide
ions. These ions are injected back into the electrolyte.
6.5.3 Molten-Carbonate Fuel Cells (MCFCs)
MCFCs can reach 55% LHV efficiencies (Figure 6-25). MCFCs operate on hydrogen,
carbon monoxide, natural gas, propane, landfill gas, marine diesel, and simulated coal
gasification products. Operating temperatures are around 1200°F (650°C). This high
operating temperature makes direct operation on gaseous hydrocarbon fuels (e.g., natural
gas) possible. Natural gas can be reformed internally in MCFCs to produce hydrogen.
MCFCs use a molten carbonate salt mixture as an electrolyte; the electrolyte
composition varies, but usually consists of lithium carbonate and potassium carbonate.
The salt mixture is liquid and a good ionic conductor at the MCFC’s high operating
temperature. An electrochemical reaction occurs at the anode between the hydrogen
Figure 6-23. PAFC Cell
(DOE 2007)
Figure 6-24. SOFC Cell
(DOE 2007)
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fuel and carbonate ions from the electrolyte. This reaction produces water and carbon
dioxide, and releases electrons to the anode. At the cathode, oxygen and carbon dioxide
from the oxidant stream combine with electrons from the anode to produce carbonate
ions, which enter the electrolyte.
6.5.4 Proton Exchange Membrane Fuel Cells (PEMFCs)
PEMFCs can reach 40% LHV efficiencies. PEMFCs contain a thin plastic polymer
membrane through which hydrogen ions can pass. The membrane is coated on both
sides with highly dispersed metal alloy particles (mostly platinum) that are active
catalysts (Figure 6-26). Because the electrolyte is a solid polymer, electrolyte loss does
not affect stack life. Using a solid electrolyte eliminates the safety concerns and
corrosive effects associated with liquid electrolytes. PEMFCs operate at relatively low
temperatures (approximately 200°F [90°C]).
Electrode reactions in the PEMFC are analogous to those in the PAFC. Hydrogen
ions and electrons are produced from the fuel gas at the anode. At the cathode, oxygen
combines with electrons from the anode and hydrogen ions from the electrolyte to
produce water. The solid electrolyte does not absorb the water, which is rejected from
the back of the cathode into the oxidant gas stream (Hodge and Hardy 2002).
Hydrogen is delivered to the anode side of the membrane-electrode assembly
(MEA), where it is catalytically split into protons and electrons. The protons move
through the polymer electrolyte membrane to the cathode side, and the electrons travel
to the cathode side along an external load circuit, creating output current.
Meanwhile, oxygen is delivered to the cathode side of the MEA. The oxygen molecules
react with protons and electrons coming from the anode side to form water molecules.
Figure 6-25. MCFC Cell
(DOE 2007)
Figure 6-26. PEMFC Cell
(DOE 2007)
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6.6 HEAT-TO-POWER EQUIPMENT
Heat-to-power equipment converts heat energy into shaft power, and in the context
of CHP the shaft power is typically used to drive a generator. Steam turbine generators
are by far the most common form of heat driven engines. This section will cover steam
turbines in some detail and also provide an overview of lower temperature heat to power
equipment emerging in CHP application, including Rankine and Stirling cycle systems.
6.6.1 Steam Turbines
Steam-turbine-based power generation cycles have been the workhorse of the
power generation industry. They are available in a broad range of sizes from 100 kW
to more than 1000 MW. After many decades of focusing primarily on increasing
system size, the turbine industry has recently turned toward increasing system
efficiency and availability. Because of their energy characteristics and the need to
operate the steaming portion of the cycle, steam-turbine-based systems have been
used primarily for baseloaded applications. In addition, because of the ability to
extract steam at various ports throughout the expansion process, they allow for greater
flexibility in matching cycle thermal capabilities with loads.
6.6.2 Steam Turbine Concepts
The typical steam-turbine-based system consists of several major components: a
heat source, a steam power turbine, and a heat sink. The system typically operates in a
Rankine cycle and, when equipped with a condenser as shown in Figure 6-27, has been
the basis of most of the generation capacity brought on-line since the early 1900s.
Figure 6-27. Simple Condensing Turbine
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The heat source, such as a boiler capable of burning gaseous, liquid, or solid fuels
or a combination of fuels, generates high-pressure steam. The heat source need not be
limited to combustion of traditional fuels; nuclear reactors, refuse, and waste
by-products have been successfully used in steam-cycle generation plants. In many
cases, the heat source consists of an HRSG, which is “fired” with turbine exhaust
gases, and the combination of a combustion turbine and steam turbine is referred to as
a combined cycle. Inlet steam conditions can vary over a broad range: pressures can
range from 150 psig (1034 kPa [gage]) to more than 3000 psig (20 670 kPa [gage]);
temperatures can range from a few degrees of superheat at 150 psig (1034 kPa [gage])
to more than 1000°F (538°C). CHP applications are generally limited to steam
pressures of no more than 700 to 800 psig (4823 to 5512 kPa [gage]) with temperatures
of no more than 800°F (427°C).
A second major component is a heat sink. Because the turbine operates by allowing
the steam to expand, giving up energy and doing work, the cycle must include a
mechanism for rejecting the steam and the energy therein, which is exhausted from
the turbine. This heat sink can be a thermal process, as is the case with CHP systems,
or it can be the environment.
Steam turbine technology is quite diverse, operating over a broad range of steam
conditions and design concepts. As described below, steam turbines can be categorized
in a number of ways, including the process by which steam expands and does work,
the manner in which steam exits the turbine, and the manner in which steam is
introduced into the turbine. All turbines operate on the same basic concept: as steam
expands while flowing through a nozzle, it accelerates and forms a high-speed jet. The
kinetic energy of the jet is then transferred to a series of rotating blades that produce
mechanical work.
A primary categorization of turbines is based on the procedure by which steam
expands and impacts on the turbine blades and can be broken into two classes: impulse
and reaction flow. Fixed-impulse nozzles operate to produce well-formed, high-speed
jets that impact on the moving blades or turbine buckets. The buckets absorb the
kinetic energy from the steam jets and transfer it to shaft rotation and mechanical
work. The amount of work that is performed is a function of the blade speed relative
to the velocity of the steam jet. The maximum amount of work is extracted when the
blade speed is equal to 50% of the jet speed. In a reaction process, the steam is routed
to rotating nozzles, where the steam pressure is reduced and the velocity of the steam
is increased relative to the nozzles. The increase in speed exerts a reactive pressure on
the nozzles, causing them to move relative to the steam. Today, most steam turbines
are multistage devices with a combination of reaction and impulse stages, and
individual blades can operate as both impulse and reaction flow devices.
The vast majority of steam turbine generators in use today are axial-flow turbines.
Conventional axial-flow steam turbines direct steam axially through the peripheral
blades of one or more staged turbine wheels (much like a pinwheel) one after another
on the same shaft. Figure 6-28 shows basic types of axial turbines. NEMA Standard
SM 24 defines these steam turbines and further subdivisions of their basic families
as follows:
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• Noncondensing (Back-Pressure) Turbine. A steam turbine designed to operate
with an exhaust steam pressure at any level that may be required by a downstream
process, where all condensing takes place.
• Condensing Turbine. A steam turbine with an exhaust steam pressure below
atmospheric pressure, such that steam is directly and completely condensed.
• Automatic Extraction Turbine. A steam turbine that has opening(s) in the
turbine casing for extracting steam and means for directly regulating the extraction
steam pressure.
• Nonautomatic Extraction Turbine. A steam turbine that has opening(s) in the
turbine casing for extracting steam without a means for controlling its pressure.
• Induction (Mixed-Pressure) Turbine. A steam turbine with separate inlets for
steam at two pressures, with an automatic device for controlling the pressure of the
secondary steam induced into the turbine and means for directly regulating the flow
of steam to the turbine stages below the induction opening.
• Induction-Extraction Turbine. A steam turbine that can either exhaust or admit
a supplemental flow of steam through an intermediate port in the casing, thereby
maintaining a process heat balance. Extraction and induction-extraction turbines
may have several casing openings, each passing steam at a different pressure.
Figure 6-28. Basic Types of Axial Flow Turbines
(Figure 33, Chapter 7, 2012 ASHRAE Handbook—HVAC Systems and Equipment)
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The back-pressure or noncondensing turbine is the simplest, consisting of a turbine
that exhausts the steam at atmospheric pressures or higher. These turbines are generally
used when there is a heating or industrial process need for high-pressure steam and all
steam condensation takes place downstream of the turbine cycle and in the load. Figure
6-29 illustrates the steam path for a noncondensing turbine. The back-pressure steam
turbine operates on the enthalpy difference between steam inlet and exhaust conditions.
The Carnot-cycle efficiency for these turbines tends to be lower than is possible from
other turbines such as condensing units, because the difference between the turbine
inlet and exhaust temperatures tends to be lower than for other types of turbines.
Because much of the steam’s heat, including the latent heat of vaporization, is exhausted
and then used in a process, the back-pressure CHP system process efficiency or total
energy efficiency can be very high. One potential application for a back-pressure
turbine is as a substitute for a pressure-reducing valve; turbines can provide the same
function—pressure regulation—while also producing a useful product—power.
The use of back-pressure turbines in CHP applications does result in some
disadvantages as compared to other types of turbines. Because the process load is the
heat sink for the steam, the amount of steam passed through the turbine is dependent
on the heat load. Thus, the back-pressure turbine provides little flexibility in directly
matching electrical output to electrical requirements; electrical output is controlled by
the thermal load. The direct linkage of the site steam requirements and electrical output
can result in electric utility charges for standby service or increased supplemental
service. As an alternative, it is possible to vent the exhaust steam directly to the
atmosphere; however, this practice is very inefficient, results in the waste of treated
boiler water, and is likely to lead to poor operating economics. A second disadvantage
is that the turbine itself tends to be larger than other types of turbines.
Figure 6-29. Noncondensing (Back-Pressure) Turbine
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The condensing turbine is capable of greater capacity than a back-pressure turbine
for the same inlet conditions. Lower-temperature exhaust steam conditions result in a
greater temperature difference between inlet and exhaust, with higher turbine efficiencies.
The power generation cycle can be optimized by lowering the exhaust temperature and
pressure; however, the effect of this turbine or power cycle optimization is to lower both
the temperature and the quantity of heat that can be recovered for process use. Condensing
temperatures well below 200°F (93.3°C) are possible, but generally limit the usefulness
of recovered heat to those applications that can use hot water (e.g., boiler feedwater
preheating). While the mechanical efficiency of the turbine may be high, the total energy
efficiency of the cycle may be low and the straight condensing turbine may not be cost
effective for those applications where recovered heat can be economically applied.
There are multiple variations of extraction turbine, in which steam is exhausted from
the turbine at different conditions at several points in the steam flow path. The advantage
of this type of turbine is that it allows extraction of the quantity of steam required at each
temperature or pressure as needed by the industrial process. The extraction ports can be
equipped for automatic operation, thus allowing the turbine to track a site thermal load.
Multiple extraction ports are possible and this turbine provides a great deal of flexibility
in matching the CHP cycle to the thermal requirements of the site. Extracted steam can
also be used in the power cycle for feedwater heating or for ancillary drives. Depending
on cycle constraints and process requirements, the final exit conditions from the extraction
turbine can be either backpressure or condensing. Conceptually, the extraction turbine is
a hybrid condensing/noncondensing turbine. When operating in an extraction mode, the
turbine can be efficient, with steam rates approaching those of a back-pressure turbine.
Induction turbines are equipped to accept steam at multiple ports. These turbines
are frequently found in industrial facilities, where steam may be available at pressures
that are lower than the throttle conditions of the turbine. The lower-pressure steam is
induced into the steam path and produces power as it expands to exit conditions.
6.6.3 Steam Turbine Capacity
Steam turbine capacity and efficiency are determined by the inlet and exhaust
steam conditions and, when used in CHP applications, the steam turbine is generally
designed to the specific conditions imposed by the heat source and process steam
requirements. Single-stage, back-pressure turbines suitable for industrial applications
are available in sizes as small as 100 kW; multistage induction/extraction turbines with
reheat and regeneration are generally used in central power plants and have exceeded
1000 MW in capacity.
Unlike the combustion turbine, steam turbine capacity is not a direct function of
ambient temperature, though, for condensing turbines, capacity is affected somewhat
by ambient temperature. Condensing turbines reject heat to the atmosphere or to some
body of water, and high ambient temperatures can reduce the heat rejection capacity of
the condenser, decreasing both turbine capacity and cycle efficiency.
6.6.4 Steam Turbine Efficiency
Steam turbine maximum efficiency is limited to the Carnot efficiency, which is a
function of the temperatures of the cycle’s heat source and heat sink. The Carnot
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efficiency is reduced by mechanical inefficiencies, steam losses, and imperfections in
the flow path. An obvious opportunity for increasing turbine efficiency is to increase
the difference in the energy content of the throttle and exit steam conditions. Increasing
the throttle pressure and/or temperature and decreasing the condensing pressure and/or
temperature increases the Carnot efficiency. Other measures, such as increasing turbine
speed or increasing the number of turbine stages, also increase efficiency. Mechanical
efficiency is typically 50 to 80%. As exit steam quality decreases, the recoverable heat
becomes less useful, and the total energy efficiency of the CHP system may decrease.
Additionally, as condenser temperatures decrease, the moisture content of the steam
can increase, resulting in added maintenance costs.
Steam turbine efficiency is usually measured as a steam rate in pounds of steam
per horsepower-hour (kilograms of steam per kilowatt-hour). Figures 6-30 and 6-31
show typical efficiency data for low-pressure, backpressure and condensing turbines.
Steam turbine efficiency degrades over time, with a significant erosion of heat rate after
20 years of operation.
When used in a combined cycle, as illustrated by Figure 6-32, the inlet steam
conditions are limited to the temperatures available from the combustion turbine
exhaust (typically 1000°F [538°C] or less). If additional heat is required, the exhaust
gas temperature can be increased to more than 1600°F (871°C) through the use of a
supplemental burner. In either case, the characteristics of the combustion turbine will
determine the steam turbine throttle conditions and, ultimately, cycle efficiency.
6.6.5 Steam Turbine Heat Recovery Characteristics
Steam turbines provide the greatest flexibility in meeting site thermal requirements.
Multiple extraction ports allow the turbine to satisfy differing steam requirements;
multiple induction ports allow the use of process by-product steam for power generation.
Combination extraction/condensing turbines provide further flexibility, allowing the
maximum production of power from steam that is not required for process.
Although extraction and noncondensing turbines allow flexibility in matching the
steam conditions to the process requirements, flow limitations result in constraints on
power production, and steam turbines may not be able to follow the facility electrical
loads. In addition, condensing turbines rarely provide heat at temperatures of greater
than 180°F (82.2°C) to 200°F (93.3°C), and, therefore, the available heat is of limited
value. Large condensing turbines are generally used in electric utility central power
plants, and the power cycle is typically optimized for power generation. As a result,
condenser temperatures may be even lower with even less useful recoverable heat.
6.6.6 Steam Turbine Part-Load Operation
Steam turbines are usually rated at the maximum load the turbine can carry, and this
point is frequently greater than the load at which the turbine achieves maximum efficiency.
Optimum performance typically occurs at approximately 95% of the rated load.
Because most turbines considered for CHP applications are multistage devices
designed for a specific application, typically including both condensing and extraction
capabilities, the part-load characteristics are unique to each turbine.
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Figure 6-30. Effect of Exhaust Pressure on Noncondensing Turbine
Figure 6-30 (SI). Effect of Exhaust Pressure on Noncondensing Turbine
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Figure 6-31. Efficiency of Typical Multistage Turbines
Figure 6-31 (SI). Efficiency of Typical Multistage Turbines
6.6.7 Steam Turbine Start-Up
Unlike combustion turbines, steam-turbine-based CHP systems can require a rather
lengthy start-up period, which includes warm-up of the fired boilers. Start-up can require
several hours, and in some cases, where more rapid availability is of importance, it may
be cost effective to keep a boiler warm, to reduce start-up time.
6.6.8 Steam Turbine Maintenance and Availability
Steam turbines are capable of extremely high availabilities with forced outage rates
of less than 1%. Most turbine outages are the result of blade corrosion; therefore, water
quality is the most significant factor impacting availability and maintenance costs.
Because steam is produced in external boilers, the type of fuel has no effect on turbine
maintenance and availability, although fuel-handling and availability problems may
limit overall system availability. Finally, auxiliary equipment, such as pumps and
valves, may limit system availability, and redundant ancillary components are usually
cost effective for critical systems.
The interval between steam turbine overhauls depends primarily on water quality
and turbine duty cycle. A complete internal inspection of a steam turbine can require
150 to 350 h to complete; however, problems encountered during the inspection can
significantly increase the length of the outage. Detailed planning can effectively shorten
the time required for an overhaul. Among the activities that should be conducted before
an overhaul is a review of outage and maintenance records to assess component
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Figure 6-32. Combined-Cycle System
condition and to identify potential problems. Continued performance monitoring, valve
inspections, vibration monitoring, and water quality testing can also aid in minimizing
outage time.
6.6.9 Steam Turbine Fuel Capabilities
The steam turbine cycle provides maximum fuel flexibility, as steam is generated
external to the turbine. Rankine cycle systems have been operated using various
gaseous, liquid, and solid fuels, including renewable energy sources such as refuse,
industrial by-products, geothermal sources, and solar-generated steam. Finally, note
that the heat source can consist of the exhaust of either another prime mover such as a
combustion turbine, or a reciprocating engine, or an industrial process such as a kiln.
Because all steam is generated external to the turbine, fuel switching has no direct
impact on turbine operation.
6.6.10 Steam Turbine Emission Characteristics and Controls
Excluding combustion emission to generate steam, steam turbines produce only
thermal emissions, which result from the condensing operation. Thermal emissions can
be reduced to the extent that recoverable heat is used in process applications.
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6.6.11 Steam Turbine Noise and Vibration
Enclosed turbine sound levels are generally 85 dBa or less; however, noise emanating
from pipes, pumps, valves, fuel-handling systems, and boilers may be of greater concern.
6.6.12 Steam Turbine Water Treatment Requirements
It is generally believed that more than 50% of steam turbine plant outages are
attributable to corrosion; therefore, water and steam chemistry are critical components
of an effective steam turbine maintenance program. As steam pressures and temperatures
increase, water quality must be increased.
Most corrosive effects occur in the later stages of the turbine where the steam
becomes wet and where impurities are deposited on blades and become more
concentrated. Impurities such as iron, manganese, silica, calcium, magnesium, sodium,
chlorides, sulfates, nitrates, and bicarbonates can leave deposits on blades, valves, and
turbine surfaces. These deposits reduce fluid flow, capacity, and efficiency, and,
through their corrosive action, they decrease turbine reliability and availability while
increasing maintenance costs. Oxygen, carbon dioxide, and nitrogen dissolved in
water can be highly corrosive and interactions among these gases can increase their
total corrosive effect.
There are two distinct sources of impurities that must be addressed: the boiler
makeup water and the condensate returned to the boiler. Because impurities tend to
become more concentrated in the steam turbine, it is important to ensure that the
concentrations of these impurities are well below the level that would cause damage.
Makeup water treatment systems generally consist of several stages, including a
pretreatment step in which either additives or mechanical processes are used to remove
soluble gases and solids. Pretreatment may also include an initial filtration step in
which larger, suspended particles are removed. Oxidizing agents are then used to
convert dissolved impurities into insoluble chemicals that can be removed using
mechanical processes. It is important to monitor and control the residual level of the
oxidant to prevent it from attacking downstream equipment.
Pretreatment is followed by a demineralization step consisting of either evaporation,
membrane treatment, or ion exchange. Vaporization is the oldest form of treatment and
has been commonly applied by utilities. The main disadvantages with this approach
are the high cost of energy for vaporization and equipment maintenance. CHP systems
can be a low-cost source of heat for vaporization systems and, in some cases,
desalinated water is the CHP system by-product. Flash distillation processes, where
the water is vaporized at low pressures, allows the use of low-temperature heat for
vaporization of water.
The most commonly applied membrane process consists of reverse osmosis (RO),
in which a pressurized stream of water moves parallel to a semipermeable membrane;
pure water penetrates the membrane, leaving a more concentrated solution of dissolved
impurities behind. RO processes operate at pressures ranging from 150 psig (1034 kPa
[gage]) to more than 400 psig (2758 kPa [gage]). Higher pressures may be required for
water that is high in impurities. Membrane filtration is the use of membranes with pore
sizes ranging from 0.001 to 1.00 µm to filter dissolved and suspended solids. RO pores
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are smaller than the pores of membranes used for either micro- or ultrafiltration and,
therefore, provide the highest quality water.
Steam condensates impose unique water treatment requirements, as impurity
concentrations can be extremely dilute and can originate from anywhere in the steam
path. Because condensate can make up most of the boiler feedwater, condensate
polishing systems tend to handle greater flows than do makeup water treatment systems.
Moreover, operating and maintenance problems anywhere in the steam path can
contribute to polishing load. Treatment of condensate return is commonly referred to
as condensate polishing and consists primarily of ion-exchange technology.
Both treated makeup water and condensate are routed to a deaerator, where the
oxygen content of the water is reduced to less than 10 ppb. The deaerators also provide
feedwater storage capacity. Most deaeration is based on the use of steam to atomize the
feedwater and strip out dissolved oxygen. Chemical deaerators operate by injecting
chemicals that form insoluble compounds in the feedwater. These compounds are then
removed in the boiler blowdown.
6.7 OTHER HEAT-TO-POWER SYSTEMS
6.7.1 Rankine Cycle Systems
In the Rankine cycle, heat is converted into work. The ideal Rankine cycle is a
cyclical sequence of changes of pressure and temperature of a fluid, such as water, used
in an engine, such as a steam engine. Described in 1859 by William Rankine, it is used
as a standard for rating the performance of steam power plants. In the Rankine cycle,
the working substance of the engine undergoes four successive changes: (1) heating at
constant volume (as in a boiler), (2) evaporation and superheating (if any) at constant
pressure, (3) isentropic expansion in the engine, and (4) condensation at constant
pressure with return of the fluid to the boiler through a pump. This cycle generates
about 90% of all electric power used throughout the world29.
6.7.2 Organic Rankine Cycle (ORC)
When relatively low sources of heat are available, usually below 600°F (121 to
315°C), alternative fluids can provide an economic solution where steam is not the best
choice, either because of low temperature or to avoid freezing on shutdown (e.g.
pipeline compressor station energy recovery). These alternative fluid systems are
generally referred to as organic Rankine cycles (ORCs) because of the use of organic
fluids and have been successfully applied in various configurations. When using a
medium such as toluene, an ORC using engine exhaust gases as a heat source can
increase the output of a CHP system by 10 to 15% with no increase in fuel. In other
cases, the working medium can be a mixture of two different fluids, such as water and
ammonia, with a resulting increase in cycle efficiency (see the Kalina Cycle in section
6.7.3). Organic fluids suffer two major disadvantages when compared to water. First,
organic fluids are more costly than water and losses of the turbine’s working medium
can result in significant costs. Second, the ORC cycle efficiency is less efficient than
the steam Rankine cycle.
Wiser, Wendell H. (2000). Energy resources: occurrence, production, conversion, use.
Birkhäuser. p. 190. ISBN 978-0-387-98744-6.
29
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Figure 6-33. Ideal ORC Temperature-Entropy Diagram
The following six processes are found in a typical ORC system (Figure 6-33), each
causing a change in the working fluid state:
• Process 1-2: the working fluid is pumped (ideally an isentropic process) from low
to high pressure.
• Process 2-3: the working fluid is then heated in the recuperator and preheater.
• Process 3-4: the high-pressure liquid enters a vaporizer where it is heated at
constant pressure by an external heat source to become a saturated vapor.
• Process 4-5: the saturated vapor expands through a turbine to generate power
output (ideally an isentropic process), which decreases the temperature and pressure
of the vapor.
• Process 5-6: the vapor leaving the turbine enters a recuperator where it exchanges
heat with the condensed working fluid leaving the pump.
• Process 6-1: the vapor then enters a condenser where it is cooled at constant
pressure to become a saturated liquid. This liquid then reenters the pump, and the
cycle repeats.
ORCs have been successfully applied to geothermal heat applications as well as
exhaust gas recovery from pipeline combustion turbines, as shown in Figure 6-34.
6.7.3 Kalina Cycle
The Kalina cycle (Figure 6-35) is an ORC that uses a solution of two fluids with
different boiling points for its working fluid. Because the solution boils over a range of
temperatures as in distillation, more of the heat can be extracted from the source than
with a pure working fluid. The same condition applies on the exhaust (condensing) end.
By appropriate choice of the ratio between the components of the solution, the boiling
point of the working solution can be adjusted to suit the heat input temperature. Water
and ammonia is the most widely used combination, but other fluid combinations are
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Figure 6-34. Schematic of 5.5 MW Exhaust Gas ORC
Figure 6-34 (SI). Schematic of 5.5 MW Exhaust Gas ORC
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Figure 6-35. Basic Configuration of Ammonia/Water Kalina Cycle
feasible. Because of this ability to take maximum advantage of the temperature
difference between the particular heat source and sink, the Kalina cycle can be
effectively applied in the recovery of industrial process heat, geothermal energy, solar
energy, and use of waste heat from power plants. While still considered developmental,
the Kalina cycle increases the cost of a combined-cycle plant by approximately 15%
with an increase in cycle efficiency up to 5% or more.
6.7.4 Stirling Engine
The Stirling engine has a history of more than 100 years and was widely used
before 1910. It is an external combustion engine, which facilitates the control of
combustion and results in low emission rate (Wu and Wang 2006) and is suitable for
several fuels, such as natural gas and gasoline. The Stirling engine has few moving
parts and thus has little vibration during operation and minimal wear on components.
The heat driving the pistons in a Stirling engine is supplied from outside the engine
and transferred through heat exchangers to the piston volumes. Thus, the creation of
pollutants such as NOx can be avoided. Also, the external combustion aspect enables a
Stirling engine to operate equally well on multiple types of fuel, such as natural gas,
propane, gasoline, diesel, ethanol-85, biodiesel, or even heat from the sun.
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Quiet operation of the Stirling engine is a notable feature. Many Stirling engine
configurations are balanced (by nature of their construction), and because the fuel is
burned slowly and constantly outside the engine, there are no local detonations to muffle.
There are two principal types of Stirling engines, kinematic and free-piston. All
Stirling engines have two functional pistons, one of which shuttles the working gas
between the hot and cold zones and is known as a displacer, while the other is subject to
the resulting pressure changes and does work to drive the engine. In the kinematic
engine, these two pistons are physically connected by a crank mechanism, whereas in
the free-piston engine, there is no physical linkage and the displacer oscillates resonantly.
Stirling engine CHP systems are on the market in Europe and Asia and are largely
thermal following devices, providing 300 We to 12.5 kWe of power (Figure 6-36).
6.8 GENERATORS
Almost all CHP system prime movers produce mechanical or shaft power, which is
then converted into electric power by a generator. Vendors of small and mid-sized CHP
systems frequently supply the engine generator as a single factory-integrated package
that is shipped to the CHP site where it is installed. Factory integration reduces the
need for more costly and perhaps less accurate field alignment of these components.
All generators operate on essentially the same principle: that the difference in the
voltage induced in a wire that is moved through a magnetic field is proportional to the
strength of the magnetic field and the speed with which the wire and the field move
Figure 6-36. Cutaway of Free-Piston Stirling Engine
(Courtesy of Infinia Corporation)
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relative to each other. If the wire and the field move in the same direction relative to one
another, a direct current (DC) voltage will be produced; if the wire and field move in
alternating directions, then an alternating current (AC) will be produced. The frequency
of the AC current varies in proportion to the speed with which the direction of the wire
and the field change. In the typical generator, the field is rotated relative to the wire, and
the frequency of the power varies directly as a function of the rotational speed in
revolutions per minute (rpm). Three-phase power is produced using three sets of stator
windings and six poles (two per winding). The commercial standard frequency for the
United States is 60 Hz, and generator rotational speed is a multiple of 60, typically
1200 or 1800 rpm. Reciprocating engines operate at speeds that are acceptable for
generators, ranging from a few hundred rpm to 3600 rpm. Multishaft combustion
turbines can operate the power turbine at lower speeds that are compatible with the
generator, whereas single-shaft turbines typically operate at much higher speeds.
Single-shaft turbines generally require a gear box to link the turbine and the generator
to efficiently convert the high speed of the turbine to the low speed of the generator.
6.8.1 Definitions
Several concepts are important to a discussion of generators and interconnection.
The first is load types. In an AC electrical system, there are resistive, inductive, and
capacitive components.
Resistive loads include incandescent lamps, resistance heaters, and the cable itself.
If a circuit were purely resistive, the current and the voltage would be in phase. A
representation of the voltage and current waveforms for a resistive system is shown in
Figure 6-37. No real power system is purely resistive, because it will certainly also have
some capacitive characteristics (the ability to store energy briefly).
Figure 6-37. Pure Resistive Electrical System: Voltage, Current. and Power
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Inductive loads typically include induction motors, the ballast coils used with
fluorescent lamps, many low-energy lamps, and any systems that include magnetic
components, such as transformers, welding equipment, and many electrical goods. In
an inductive circuit, the current “lags” the voltage waveform, as shown in Figures
6-38a and 6-38b.
Figure 6-38a. Current-Voltage Phase Relationship (Out of Phase)
Figure 6-38b. Simple Inductive System with Lag of 30°
(Resulting in Power Factor of cos 30 = 0.87)
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Capacitive loads include such components as digital electronic equipment , a load
that is becoming increasingly prevalent in commercial buildings. In a capacitive circuit,
the current “leads” the voltage waveform. Capacitive loads (in the form of capacitors)
are added to systems as a means of counteracting inductive loads.
Real power is a rather straightforward concept and is a measure of the amount of
work that is performed. In a simple resistive circuit such as one supplying resistance
heaters, real power is defined as the product of the current flowing through a circuit and
the voltage across that same circuit. It is a measure of the energy that is used to do
work. Real power is measured in watts, kilowatts, or even megawatts.
Not all energy in a circuit performs real work, as some of it may be stored in
magnetic fields or in electromotive fields in a capacitor. Reactive power is a measure of
the energy that is stored in a circuit, typically in the magnetic fields of transformers and
motors, and is referred to as inductive power. If the reactive load is an inductive load,
then the reactive power is not dissipated as heat or useful work but is continuously
exchanged between the power source and the inductive load. The reactive power is the
product of the inductive current flowing through a load and the voltage drop across the
load and is expressed in reactive kilovolt-amps (RkVA). Reactive and real currents are
vector quantities that are 90 degrees out of phase with each other. Inductive loads have
leading power factors (the reactive current leads the real current), whereas capacitive
loads have lagging power factors. The relationship between real and reactive power is
illustrated by Figure 6-39. Apparent power is typically expressed in kilovolt amps
(kVA) and is the vector sum of reactive and real power. Figure 6-40 illustrates the phase
difference between current and voltage that is caused by a reactive load.
Power factor is the ratio of real power to apparent power and is a measure of the
efficiency with which the total power delivered by a source is used for real work. Some
utilities measure power and bill customers based on average power factor, using the
Figure 6-39. Real/Reactive/Apparent Electric Power Vectors
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ratio of kilowatt hours to kilovolt amps; other utilities measure and bill based on peak
reactive and apparent demand.
Low power factor is caused by inductive loads (such as transformers, electric
motors, and high-intensity discharge lighting), which are a major portion of the power
consumed in industrial complexes. Unlike resistive loads that create heat by consuming
kilowatts, inductive loads require the current to create a magnetic field, and the magnetic
field produces the desired work.
Many utilities attempt to encourage high power factors by billing for demand on
the basis of apparent power or by imposing additional charges for low-power-factor or
excess reactive loads. Some utility tariffs allow the utility to discontinue service if the
power factor drops to unacceptably low levels. It is common to correct power factor
problems caused by motors, transformers, and inductive heaters by adding capacitance
to the electrical circuit.
Many electrical components, including generators, are rated based on apparent
power, and sites with low power factors can incur increased generator and switchgear
costs because of the need for the larger components required by the larger reactive
load. It is common to specify the real power output of a generator in kilowatts at an
80% power factor.
Harmonic content is another parameter of concern in the analysis of on-site
generation capacity and loads. A harmonic is a current or voltage component of a
periodic wave that is at a frequency that is a multiple of the power base frequency.
Harmonics are caused by nonlinear and quickly changing loads such as those produced
by x-ray machines; which produce a distorted wave shape as shown in Figure 6-40.
Harmonics are a continuing distortion that is distinct from short-term spikes and
distortions caused by transient disturbances as shown in Figure 6-41. Harmonic
distortion can have a number of undesirable effects including
• excessive heating in motors, transformers, and switchgear, leading to shortened life;
• faulty operation of solid-state power supplies;
• excessive voltages, causing capacitor failure or false operation of circuit breakers
and relays;
• interference with telephone operation; and
• increased losses in transformers and erroneous meter readings.
A wave can have both voltage and current harmonics, and total harmonic distortion
(THD) is the accepted measure of harmonic content. THD is defined by Equation
6-1 or 6-2.
To understand a system with an input and an output, such as an audio amplifier, the
analysis starts with an ideal system where the transfer function is linear and timeinvariant. When a signal passes through a nonideal, nonlinear device, additional content
is added at the harmonics of the original frequencies. THD is a measurement of the
extent of that distortion.
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Figure 6-40. Harmonic Distortion
Figure 6-41. Transient Distortion
When the input is a pure sine wave, the measurement is most commonly the ratio
of the sum of the powers of all higher harmonic frequencies to the power at the first
harmonic, or fundamental, frequency:
6-1
which can equivalently be written as
6-2
if there is no source of power other than the signal and its harmonics.
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THD should be limited to approximately 5%, with no single harmonic of more
than 2 or 3%.
Generator pitch is another key characteristic. Pitch is defined as the ratio of the
number of winding slots per generator pole to the number of slots enclosed by each
coil. When a generator is wound with a 2/3 pitch, the third-order harmonics, which
tend to be the largest harmonics, cancel each other out and are completely eliminated.
Most generators are not wound at a 2/3 pitch, however, and, if harmonics are excessive,
measures may be required to eliminate them.
Generators can be categorized as either synchronous or induction, based on the
source of the reactive energy required to establish the magnetic field.
6.8.2 Synchronous Generators
The defining characteristic of synchronous generators is that they provide their
own source of reactive power and can operate independent of or isolated from any
external source of power. They are used in most of the CHP systems in service today
and are always found in larger applications. Synchronous generators are also found in
emergency power applications, in those applications where the CHP plant may wish
to operate in isolation from the utility grid, or where the CHP plant wishes to use the
CHP system generator to correct the power factor. The most common form of
synchronous generator is the self-excited or brushless generator, which consists of
two generators. The smaller generator produces an AC current on the rotating shaft of
the generator; this AC current is then rectified to create a DC current in the rotor
windings, thus producing a DC field. The rotating DC field produces an AC voltage in
the stator windings. The rotational speed of the generator is a function of the number
of poles in the generator. A six-pole generator producing three-phase power with a
two-pole rotor operates at 3600 rpm. Doubling the number of stator or rotor poles
reduces the speed by a factor of two, to 1800 rpm. The strength of the magnetic field
and, therefore, the voltage output of the generator, is controlled by varying the voltage
of the AC exciter field.
If a synchronous generator is to be operated in isolation, then it is necessary to
precisely control the generator and therefore the engine speed. Variations in generator
speed can result in inaccuracies in clocks and other equipment whose operation is
dependent on the frequency of the power supply. If multiple generators are operated in
parallel, speed variations can result in voltage differences and resultant current flows
between generators. When operated in parallel with the utility grid, the grid frequency
and voltage have a stabilizing effect on the generator. If the speed of the prime mover
varies while the generator is interconnected to the grid or another source of power, the
amount of power it produces will change, and a device is required to control the power
output and/or generator speed. This device known as a droop governor, causes slight
changes in generator speed as may be required to adjust to changes in load. When the
generator is interconnected to the grid, the electrical frequency and, therefore, the
generator speed is determined by the grid. The droop governor functions to adjust the
amount of power the generator delivers. Should the utility-supplied power fail, the
governor allows the generator to serve the site or facility load, if the generator has
adequate capacity and is designed to operate in island mode.
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As noted previously, a synchronous generator can be used to control the power
factor. When operating in isolation, the voltage of the generator varies as a function
of the excitation current. However, when the generator is interconnected to the grid,
the voltage is determined by the grid and, therefore, variations in excitation cannot
change voltage. If the voltage is fixed, variations in the excitation current affect the
amount of reactive current produced. If the generator is underexcited, the generator
draws needed reactive power from the utility grid or from other generators. Conversely,
if the excitation field is overexcited, the generator delivers reactive power to the utility
grid, increasing the site power factor. A synchronous generator can, therefore, be
used to compensate for a low site power factor, thus avoiding utility-imposed power
factor penalties.
6.8.3 Induction Generators
Induction generators are simple devices; they are induction motors that are driven
above their synchronous speed. However, unlike synchronous generators, they do not
have an internal source of reactive power and, therefore, an induction generator can
only operate when connected to some external reactive source. The reactive source is
usually the utility grid and, if so, induction generators are not capable of sustained
isolated operation should the grid become deenergized. If stand-alone capability is
required of an induction generator, as may be the case for very small systems, it can be
equipped with an external self-exciter.
Induction generators operate at the same voltage and frequency as the reactive
power source that supplies them and induction generators are simple to synchronize
with the utility grid. The amount of work the engine does and the amount of power the
generator delivers are functions of the generator speed relative to its synchronous
speed. When driven at its synchronous speed, an induction generator delivers no real
power. However, as the generator speed is increased above the synchronous speed, the
amount of real power delivered to the load is increased. Maximum power is available
at approximately 105% of synchronous speed. If the generator speed drops below the
synchronous value, it functions as a motor.
Induction generators interconnected to the utility grid and using cogenerated power
on-site to reduce utility purchases will worsen the power factor of the load served by
the utility. First, the induction generator will increase the reactive load imposed on the
utility; second, it will reduce the real power drawn from the utility. In many cases, it is
necessary to install capacitors to correct for power factor. The amount of correction
that is cost effective depends on the specific utility rate structure, and the tariff should
be reviewed to minimize the total or combined cost of power factor correction and
utility charges.
Because the frequency and voltage of the induction generator is determined by the
external source or utility grid, it requires a minimum of protective relaying. A reverse
power relay is required to protect against the generator operating as a motor. In addition,
the combination of an induction generator and power factor correction capacitors can
cause the induction generator to self-excite should the external source of reactive
energy be lost. While this self-excitation or ferroresonance is likely to decay rapidly, it
may be necessary to install a frequency relay to disconnect the generator should it
occur. Ferroresonance can also occur in circuits served by synchronous generators;
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however, these generators have an inherent capability for self-excitation and already
require appropriate protective relaying.
Rated capacity is typically the most important consideration in specifying a
generator; however, other parameters such as voltage, efficiency, harmonics, voltage
and frequency stability, short-term overload capability, phase imbalance, and fault
current contribution are also important. Although most decisions will be made based
on the rated or nominal capacity of the generator, heavy-duty generators may be capable
of operating at 120 to 125% of rated load for short periods. Although generators are
highly efficient, they do produce heat, and the CHP facility must be designed to handle
the heat contribution of both the engine and the generator. Continuous overload
operation may require generator cooling. Balancing of phases is also an important
consideration, and the ability of generators to handle unbalanced loads varies.
Generator voltage is an important consideration, and higher voltages result in lower
generator losses and greater efficiency; however, it is usually not cost effective to specify
high voltages for small capacities. Any trade-off between generator voltage and efficiency
must also consider the cost of ancillary equipment, such as transformers and switchgear,
whose costs are also a function of voltage. In general, smaller systems will use 480 V
generators, whereas mid-sized generator voltage ranges from 4160 V to 13.8 kV. Large
generators of 100 MW or more may be specified at correspondingly higher voltages.
Most generators can regulate voltage to within 0.5% over the full range of operations.
Generator efficiencies of 95 to 98% are typical; however, smaller induction generators
or generators operating at part load may operate at efficiencies of 85% or less. Generator
efficiency drops off nonlinearly as load decreases. Generator manufacturers can usually
provide part-load efficiency data.
6.8.4 Inverters
Most prime movers are rotating devices that produce AC power. There are, however,
some power generation concepts, such as fuel cells or microturbines, that produce
direct current. An inverter is a device that converts DC power to AC power. It is most
commonly used in applications where power is required at frequencies other than
60 Hz. Typically, when alternative frequencies are required, the commercial 60 Hz
power is rectified to produce DC power, which is, in turn, input to an inverter, where
AC power is produced at the desired frequency. Most inverters operate by cutting the
DC power into a series of blocks or square waves at a number of different frequencies.
These blocks are then electrically summed to create a voltage wave form that
approximates the required alternating current. Inductance and/or capacitance can be
added to the inverter to smooth out the wave and to better approximate a sinusoid. The
inverter output, including voltage and frequency, is controlled by the interconnected
voltage and frequency of the utility grid.
Inverters may be included in the power-conditioning and uninterruptible power
system required for computer applications. If inverters are used as part of a battery
back-up system, they could be displaced by fuel cells when that technology achieves
broader commercial acceptance.
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CHAPTER 7
HEAT RECOVERY AND THERMALLY
ACTIVATED TECHNOLOGIES
7.1 HEAT RECOVERY DEVICES
A CHP topping cycle is based on the use of heat rejected from the power generation
process for an economically useful purpose. The use of this heat results in a reduction in
the amount of fuel that would otherwise be required for onsite combustion, thus reducing
total energy use. The economics of CHP applications often depend on effective use of
the thermal energy contained in the prime-mover exhaust gas and cooling systems,
which generally represent 60 to 70% of the inlet fuel energy. The amount of useful heat
that can be recovered per unit of electrical output varies as a function of the type of
prime mover, the particular configuration of the prime mover itself, and the actual
operations of the prime mover. This review of heat recovery systems is organized by
major prime-mover type; reciprocating engines, turbines, microturbines, and fuel cells.
An important factor contributing to the economic viability of CHP at a specific site
is the ability to use that recovered heat in site processes (heating, cooling, drying, and/
or dehumidifying) and/or space conditioning (heating, cooling, and/or humidity control).
In general, the lower the temperature required at the site, the more useful heat that can
be recovered from any prime mover and the greater the operating cost savings. The
following broad guidelines are applicable regardless of prime mover type:
• Direct-drying industrial applications allow the maximum use of heat recoverable
from exhaust gases, because drying is typically performed by heating ambient air.
The resulting reference point for heat recovery is the ambient air temperature,
which is generally less than 100°F (37.8°C). In addition, no heat recovery steam
generator30 (HRSG) (with its associated costs) is required.
• Direct drying of food allows maximum heat recovery; however, codes may
require an air-to-air heat exchanger at added cost. Alternatives include steam heat
exchangers and steam heat recovery from an engine.
A heat recovery steam generator (HRSG) is an energy recovery heat exchanger that recovers
heat from a hot gas stream. It produces steam that can be used in a process (CHP) or used to
drive a steam turbine (combined cycle).
30
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• Service water heating can also be effective, because water temperatures are
generally limited to 140°F (60°C) or less, with supply water temperatures generally
below 70°F (21.1°C). If water is to be used for potable purposes, double-wall heat
exchangers are required.
• Hot-water building heating systems usually require water temperatures as low
as 60°F (15.6°C) for water-source heat pump loops, from 100 to 140°F (37.8 to
60°C) for low-temperature systems, and from 180 to 220°F (82.2 to 104.4°C) for
high-temperature hot water systems. Building heating systems provide the greatest
thermal load and allow the most use of all heat sources available from both turbines
and reciprocating engines. Lower-temperature space-conditioning systems also
provide the opportunity to use the space-conditioning loads to cool some engine
components.
• Low-pressure steam systems with maximum steam pressures of approximately
15 psig (103 kPa [gage]) can also provide space and process cooling using singlestage absorption chillers.
• High-pressure steam systems with steam pressures exceeding 15 psig (103 kPa
[gage]) can be served with heat recovered from turbine and from reciprocating
engine exhaust. Process steam pressures of 125 to 150 psig (861 to 1034 kPa
[gage]) are typically required for steam distribution systems, two-stage absorption
chillers, and some industrial processes. Pressures of more than 150 psig (1034 kPa
[gage]) typically require turbine technology.
CHP is not a remedy for an inadequate thermal distribution system; it is simply
an alternative source of heat. Any analysis of CHP viability may need to include a
review of the adequacy of the existing space conditioning and process systems to
determine if there are additional problems to be dealt with in the course of developing
the CHP system.
7.2 RECIPROCATING-ENGINE HEAT RECOVERY
There are four sources of usable waste heat from a reciprocating engine: the engine
exhaust and jacket coolant are primary sources of waste heat, and smaller amounts can
be recovered from the lube oil cooler and the intercooler and aftercooler of the
turbocharger (if so equipped). Heat can generally be recovered in the form of hot water
or low-pressure steam at <30 psig (207 kPa [gage]). Medium pressure steam at up to
about 150 psig (1034 kPa [gage]) can be generated from the high temperature exhaust
gas, but the hot exhaust gas contains only about one half of the available thermal energy
from a reciprocating engine.
The most common use of this heat is to generate hot water or low-pressure steam
for process use or for space heating, process needs, domestic hot water, or absorption
cooling. However, the engine exhaust gases can also be used as a source of direct
energy for drying or other direct heat processes.
Heat in the engine jacket coolant accounts for up to 30% of the energy input and is
capable of producing 200 to 210°F (93.3 to 99°C) hot water. Exhaust temperatures of
850 to 1200°F (454 to 649°C) are typical. By recovering heat in the engine cooling
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systems and exhaust, approximately 70 to 80% of the input energy can be effectively
used to produce both power and useful thermal energy.
The most common method of recovering engine heat is the closed-loop cooling
system as shown in Figures 7-1 and 7-2. These systems are designed to cool the engine
by pumped circulation of a coolant through engine passages and heat rejection through
an external heat exchanger, which transfers engine heat to a cooling tower or radiator
when there is excess heat generated. Closed-loop water cooling systems can operate at
coolant temperatures from 190 to 240°F (88 to 116°C). Depending on the engine and
CHP system requirements, the lube oil cooling and turbocharger aftercooling may be
either separate or part of the jacket cooling system.
Figure 7-1. Closed-Loop Heat Recovery System Recovering Jacket, Oil, and Exhaust Heat
Supplying Two Thermal Loads
Figure 7-2. Closed-Loop Heat Recovery System Recovering Jacket and Exhaust Heat
Supplying One Thermal Load
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Figure 7-1 depicts a closed-loop heat recovery system recovering jacket, oil, and
exhaust heat and supplying two discrete thermal loads. This particular system also has
an intercooler whose heat is rejected to the atmosphere.
Figure 7-2 depicts a closed-loop heat recovery system recovering jacket and exhaust
heat, which are combined to supply a single thermal load. This particular system also has
an intercooler whose heat is combined with the oil system and rejected to the atmosphere.
The heat recovery loop in Figure 7-2 illustrates several important considerations:
• The jacket water can be routed to a heat recovery muffler where additional heat is
added from the exhaust gases.
• The engine coolant loop serves the site heat load through a heat exchanger, thus
creating two loops: primary and secondary. This configuration allows the use of a
supplemental heat source to further increase the heat available to the load and serves
to isolate and protect the engine coolant circuit. It also insulates the engine cooling
system from failures and leaks in the site hot-water distribution system. A primarysecondary system is particularly useful in multiengine installations, as each engine
cooling loop is separately controlled, protected, and interconnected with the site hot
water loop. Multiple loops lead to higher capital costs but increased reliability.
• The engine coolant loop also includes a heat exchanger, which allows external
cooling of the engine coolant. This heat exchanger loop may use either a wet or dry
cooling tower and can include a service water source for use in emergency cooling.
The primary function of the heat recovery system is to remove heat from the engine
to avoid overheating. All heat recovery system design decisions should be made with
the goal of safe operation of the engine set.
7.2.1 Exhaust Gas Heat Recovery
Reciprocating engine exhaust gases are available at temperatures ranging from 700
to 1200°F (371 to 649°C) and can be recovered to produce either hot water or low- or
high-pressure steam. The exhaust gas temperature varies as a function of engine type
and loading. Part-load operation also results in lower exhaust temperatures. Water
cooling of the exhaust manifold also reduces exhaust temperature.
Though the exhaust gases contain approximately one-third of the heat input, the
need to maintain stack gas temperatures in the range of 250°F (121°C) or more results
in an inability to recover as much as 50% of the exhaust heat. Figure 7-3 shows the
effect of lowering exhaust temperature below 300°F (150°C). This curve is based on a
specific heat recovery silencer design with an initial exhaust temperature of 1000°F
(540°C). Lowering the final temperature from 300°F to 200°F (150°C to 94°C)
increases heat recovery 14% but requires a 28% surface increase. Similarly, a reduction
from 300°F to 100°F (150°C to 40°C) increases heat recovery 29% but requires
a 120% surface increase. This reduction in temperature causes condensation in
the exhaust stack, requiring specialized materials (e.g., stainless steel grades that
can withstand acid corrosion). Therefore, the cost of heat transfer surface must be
considered when determining the final temperature.
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Exhaust gases can vary in composition, and heat exchanger and stack manufacturers
should be consulted to determine minimum stack exit temperatures.
If engine exhaust flow and temperature data are available, and maximum recovery to
300°F (150°C) final exhaust temperature is desired, the basic exhaust recovery equation is
q = m ∈ ( C p )∈ ( t∈ − t f )
7-1
where
q = heat recovered, Btu/h (kW)
m∈ = mass flow rate of exhaust, lb/h/(kg/s)
(C )
p ∈
= specific heat of exhaust gas = 0.25 Btu/lb ⋅° F[1.05 kJ/(kg ⋅ K)]
t∈ = exhaust temperature leaving prime mover, °F (°C)
t f = final exhaust temperature, ° F (°C)
Exhaust recovery equation applies to both steam and hot water units. To estimate
the quantity of steam obtainable, the total heat recovered q is divided by the latent heat
of steam at the desired pressure. The latent heat value should include an allowance for
the temperature of the feedwater return to the boiler. The basic equation is
= m s ( hs − hf )
7-2
where
q = heat recovered, Btu/h (kW)
m s = mass flow rate of steam, lb/h/(kg/s)
hs = enthalpy of steam, Btu/lb (kJ/kg)
hf = enthalpy of feedwater, Btu/lb (kJ/kg)
Similarly, the quantity of hot water can be determined by
w ( Cp ) ( o − ti )
=m
w
7-3
where
q = heat recovered, Btu/h (kW)
m w = mass flow rate of water, lb/h/(kg/s)
(C )
p w
= specific heat of water = 1.0 Btu/lb ⋅ °F[4.8 kJ/(kg ⋅ K)]
to = temperature of water out, °F (°C)
ti = temperature of input water, °F (°C)
Exhaust gas heat exchangers are also designed to reduce engine noise transmitted
in the exhaust gases and are generally referred to as heat recovery mufflers. Steam
generators frequently include an integral steam separator. The design of the heat
recovery muffler should minimize engine backpressure to a maximum of 10 to 12 in.
of water (2.49 to 2.99 kPa) for naturally aspirated engines and 25 to 30 in. of water
(6.22 to 7.47 kPa) for turbocharged engines. Higher back pressures reduce engine
capacity and increase the exhaust gas temperature. Reciprocating engines do not
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Figure 7-3. Effect of Lowering Exhaust Temperature below 300°F (149°C)
operate with large quantities of excess air and, therefore, the exhaust gases are not rich
in oxygen and are generally incapable of supporting additional combustion.
7.2.2 Jacket Heat Recovery
Approximately one-third of the energy input to a reciprocating engine is rejected
from the block through the jacket cooling loop, and essentially all of this heat can be
recovered. Thermal energy can be recovered as hot water at temperatures of up to
260°F (127°C).
Hot-water cooling is based on a temperature change in the coolant as it passes
through the engine block. Circulation is maintained by an external pump, as shown in
Figures 71 and 7-2. That pump can be driven by the engine itself or by a separate
electric motor. An externally driven pump is preferable because it can be equipped with
an external heater to preheat the engine block before start-up. The power requirements
of the pump should be included in the parasitic load.
Jacket water flow rates must be selected to maintain the temperature difference
between the engine supply and return at levels specified by the engine manufacturer
without excessive flow rates, which would lead to component erosion, shortened engine
life, and increased maintenance costs. To avoid excessive thermal stress, the temperature
difference should be no more than 15°F (8.3°C). Lower temperature differences result
in reduced thermal stresses but higher flow rates. These higher flow rates require larger
pumps and heat exchangers at increased cost. Azeotropic antifreezes can be added to
the engine coolant for heat rejection during cold weather.
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As noted above, engine coolant heaters can be installed to preheat the coolant and
the engine prior to start-up. Heaters may be thermostatically controlled to maintain a
specified temperature.
7.2.3 Lubricating Oil/Intercooler Heat Recovery
Up to 10% of the energy input to a reciprocating engine is rejected in the lubricating
oil. High-quality lubricating oils are generally able to operate at temperatures between
160°F and 200°F (71°C and 93°C) without deterioration. The lower the operating
temperature, the longer the oil life, but the recoverable heat is less useful. In addition,
water may condense if oil temperatures are too low. Higher-temperature lubricating oil
results in shortened oil life but increases the amount and the quality of the recoverable
heat. The oil temperature is also affected by the jacket coolant temperature, which
determines the temperature of some engine components and surfaces. Manufacturers
should be consulted to determine the specific requirements for each engine in each type
of application. If the jacket water cooling system is configured into a primary-secondary
loop, the cooling water can be used to cool the lubricating oil before it is used in the
jacket water heat exchanger. It is necessary to compute flow rates and temperatures to
determine if this series cooling arrangement is technically feasible.
The lube oil cooling loop can be used for cooling of the turbocharger aftercooler.
The temperature of the cooling water to the aftercooler should be as low as possible (in
the range of 85 to 90°F [29 to 32°C]) and, therefore, the aftercooler is typically the first
heat exchanger in the cooling loop. Higher-temperature cooling water to the engine
aftercooler requires derating the engine’s capacity; temperatures as high as 135°F
(57°C) are routinely used.
7.3 COMBUSTION TURBINE HEAT RECOVERY
Combustion turbines operate at efficiencies ranging from as low as 20% HHV for
small turbines of 2000 kW or less, up through 45% HHV for larger turbines of 100
MW or more. Almost all of the energy not converted into mechanical power is rejected
from the turbine in the exhaust gases. Small quantities of heat are also rejected from the
turbine itself in ventilation air and from the lubricating oil system through separate
radiators. With exhaust gas temperatures ranging from 800°F (427°C) to more than
1000°F (538°C), much of the heat contained in the exhaust gases is recoverable. The
availability of high-temperature exhaust gases allows the recovery of a significant
quantity of steam and/or hot water of higher quality or higher temperature and pressure.
7.3.1 Direct Use of Exhaust Gases
When combustion turbines are fired with natural gas or another clean fuel, the
exhaust gases are also relatively clean and suitable for direct use in various industrial
drying applications. The major constituents of typical turbine exhaust gases include
approximately 1% as inert gases, 2 to 4% as CO2, 6 to 8% as water vapor, 14 to 16% as
oxygen, and the remainder as nitrogen measured by weight. Other pollutants are also
found in varying amounts depending on the local air shed conditions.
Direct drying results in the lowest capital costs because no HRSG is required. In
most retrofit applications, back-up burners are available from the existing process.
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Turbine exhaust gases are available at high temperatures, and the amount of available
heat q in those gases can be readily computed using Equation 7.4:
q = m ( Cp x t ) −( Cp x t )
1
1
2
2
7-4
where
q = heat recovered, Btu/h (kW)
m = exhaust gas mass flow rate, lb/h (kg/h)
C p1 = exhaust gas specific heat at t1 , Btu/lb·°F (kJ/kg·K)
t1 = temperature at which exhaust gases are available, °F (°C)
C p2 = exhaust gas specific heat at t2 , Btu/lb·°F (kJ/kg·K)
t2 = temperature at which gases are exhausted, °F (°C)
Typical values for the exhaust gas specific heat are in the range of 0.25 Btu/lb·°F
(1.04 kJ/kg·K) to 0.27 Btu/lb·°F (1.13 kJ/kg·K) and vary as a function of the amount of
water or steam injection for NOx control. In many cases, it is acceptable to use the
specific heat for the average of the exhaust gas temperatures. The quantity of exhaust
gas mass flow varies as a function of turbine size and ranges from 25 to 30 lb/kWh
(3.15 to 3.78 kg/MJ) for larger turbines of 20 MW or more, from 35 to 40 lb/kWh (4.41
to 5.05 kg/MJ) for mid-sized turbines of 3 MW to 10 MW, and approximately 50 lb/
kWh (6.30 kg/MJ) for smaller turbines. Mass flow and turbine exhaust gas pressure
vary as a function of altitude, inlet and exhaust pressure drops, and ambient temperature.
For direct-drying applications, the exhaust gases may drop to temperatures that are
only slightly above ambient, thus, maximizing the temperature difference and the
amount of available thermal energy. In many cases, as in rotary dryers or in kilns, it is
necessary to reduce the exhaust gas temperature to the range of 350 to 450°F (177 to
232°C) to avoid damage to the product. Dilution with outdoor air may be acceptable if
the mass of exhaust gases is less than the mass required for drying and if the mass and
temperature balances are acceptable. In some cases, it may be necessary to divert and
reject a portion of the exhaust gases if they would result in higher than acceptable
temperatures. In other instances, the exhaust gases may not provide enough heat for the
drying process, making it is necessary to add additional heat to the drying stream. In
this case, supplemental firing in the turbine exhaust gases, as discussed below, may
provide adequate capacity.
An air-to-air heat exchanger may be required to prevent contamination in fooddrying applications. In this case, the heat exchanger inefficiencies and required
temperature differences reduce the amount of available heat.
7.3.2 Supplemental Firing in Exhaust Gases
Combustion turbines operate with a considerable amount of excess air and, therefore,
exhaust gases contain large quantities of oxygen. With an oxygen content of 16% or
more, these gases can support additional combustion and it is possible to install additional
burners directly in the exhaust gas stream. The high temperature of the exhaust gases
results in improved fuel efficiency and the supplemental burner efficiency can exceed
90%. Duct burning (Figure 7-4) is usually limited to natural gas and light liquid fuels.
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Figure 7-4 Natural Gas Duct Burner
(Courtesy of Clever Brooks)
Figure 7-5 shows the relationship between the temperature of the combustion gases
and the amount of fuel saved as a function of furnace exit temperature ranging from
1400 to 2400°F (760 to 1316°C). As shown here, the use of turbine exhaust at 800°F
(427°C) as preheated combustion air in a furnace reduces the amount of gas required
to achieve a specific furnace temperature by approximately 19%.
Duct burners can increase the temperature of the exhaust gas stream to as high as
1600 to 1800°F (871 to 982°C) without excessive burner maintenance or control
problems, and are also capable of operating at low capacities, although the need to
maintain a stable flame in the higher-velocity turbine exhaust gases presents a constraint.
A diverter valve may be required in direct-drying applications to bypass turbine exhaust
gases directly to the atmosphere should the drying process be out of service or when
the drying load is less than the amount of heat available in the exhaust gases. Diverter
valve pressure drop losses are typically about 2%.
Duct burners can be used in direct-drying applications to increase the temperature
of the gases delivered to the process. This condition exists when the heat available from
the turbine is inadequate for complete drying. As discussed in the following section, a
supplemental duct burner provides a number of benefits when installed in combination
with a HRSG.
7.3.3 Heat Recovery Steam Generators (HRSGs)
HRSGs are unfired boilers that use turbine exhaust gases to produce steam
required for process or building requirements (see Figure 7-6). Because turbine exit
temperatures are generally lower than those available in a fired boiler, HRSGs tend to
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Figure 7-5. Impact of Exhaust Temperature on Furnace Fuel Savings
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Figure 7-5 (SI). Impact of Exhaust Temperature on Furnace Fuel Savings
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be larger, with more heat exchanger surface than a fired boiler of the same capacity.
HRSGs can be equipped with economizers, superheaters, reheaters, and duct burners
for increased steam production. The pressure drop of the exhaust duct/HRSG system
should be minimized to reduce turbine capacity losses. Although the amount of heat
available can be computed using Figure 7-7, the amount of steam produced in the
HRSG is determined by the gas-steam temperature profile of the HRSG. The limits
of heat recovery are determined by the allowed HRSG stack exit temperature, which
is generally 300°F (149°C) or more, although 250°F (121°C) may be acceptable
for some applications and fuels. Stack exit temperature is limited by the need to avoid
condensation and the formation of acids in the stack (unless special measures
are taken). Part-load operation of the combustion turbine will result in lower turbine
exit temperatures and lower temperature exhaust gases from the HRSG. Stack
temperature analyses should consider part-load conditions if load tracking is an
operating alternative.
If the HRSG does not include an economizer, the stack temperature is limited by
the steam saturation temperature; however, even when an economizer is used, the
higher temperature and pressure of the steam at the exit conditions can result in stack
exit temperatures as high as 400°F (204°C), thus decreasing the amount of recoverable
heat used. In this case, multiple-pressure boilers may be economical, because they
allow a reduction of stack temperature to 300°F (149°C) with a resulting increase in
heat recovery.
Figure 7-6. Combustion Turbine CHP Plant with Duct-Fired HRSG
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The theoretical energy contained in the CT QE exhaust is
QE = Qfuel × (100 − (ηCT 100 ) )
7-5
where
Q fuel = energy content of CT fuel
η CT = CT efficiency
The theoretical amount of heat available for steam production Qs is a function of
the HRSG efficiency:
Qs =η
� HRSG × QE
7-6
The calculation of steam capacity from a HRSG is an iterative procedure that starts
with the turbine exhaust mass flow rate and temperature and the feedwater temperature
into the economizer. Gas and steam temperatures are profiled across the HRSG
components including the economizer, evaporator, and superheater. The boiler pinch
point is defined as the minimum difference between the exhaust gas temperature and
the saturated steam temperature into the HRSG evaporator and is shown in Figure 7-7.
The pinch point is typically a minimum of 40°F (22.2°C) and is critical to defining that
profile. Low pinch points increase the amount of recoverable heat; however, low pinch
points can significantly increase HRSG cost because the heat transfer surface must be
increased. The output of the calculations is stack temperature and steam flow. If the
stack temperature is too low, it is necessary to revise these calculations with a decreased
Figure 7-7. Typical HRSG Temperature Profile
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steam flow or to include supplemental heat from a duct burner. If the stack temperature
is too high, the steam flow can be increased.
HRSG steam production is also limited by boiler radiation losses lr, which are
typically 2%, and blowdown losses lb, which are on the order of 5%. Diverter valve
losses ld are approximately 2%. The diverter valve will allow continued operation of
the combustion turbine should the site steam load be interrupted or the HRSG be out
of service. Developmental work has been completed on an HRSG capable of operating
dry, thus eliminating the need for the diverter valve. This type of HRSG requires highquality water to avoid scaling problems.
Steam available from the HRSG can be used for preheating boiler feedwater, and
steam used there should be subtracted from the HRSG output to determine the total
amount of steam available for process use. Steam use in powerhouse drives may also be
included in this calculation. In evaluating CHP economics, it is necessary to ensure
consistency between measurements of the steam produced by the conventional system
and steam available from the CHP system.
In those applications where the entire site steam demand can be satisfied by an
HRSG, either with or without a supplemental burner, a conventional boiler may be
used for steam standby. To minimize the time required to bring the conventional boiler
on-line, a heat exchanger may be used to introduce a small amount of heat into the
boiler mud drum31 to keep the boiler warm. If the practice of maintaining a boiler in
warm standby was not followed for the conventional powerhouse, the steam used for
boiler heating must be considered an incremental parasitic load and deducted from the
steam available for process.
The use of a duct burner in combination with the HRSG provides several benefits:
• The duct burner firing in high-temperature combustion air will operate at
extremely high efficiencies, exceeding 90% on an HHV basis.
• The duct burner can be efficiently fired to provide modest amounts of additional
heat, eliminating the need to operate a conventionally fired boiler at low-load
conditions and low part-load efficiencies.
• The duct burner can boost exhaust gas temperatures and mass flow, increasing the
capacity of the HRSG.
• A duct burner, in combination with a forced- or induced-draft fan, can provide
a capability to fire the HRSG during those periods when the turbine is shut down.
The fan provides the capability to continue to raise steam in the HRSG during both
short and long turbine outages and increases the overall reliability of the steam
supply at modest costs. Because high-temperature combustion air is no longer
available, the duct burner efficiency drops and the HRSG efficiency decreases
to that of a conventional, fired boiler. If supplemental fans are used, they should
be sized to maintain approximately the same mass flow through the burners as
would be the case if the turbine were operating. This approach allows the system
to operate at its design level. While induced-draft fans are possible, they are more
costly and are not commonly used.
A mud drum is a water drum, particularly one mounted low on the boiler, whose function is
primarily to trap mud from circulation.
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Some emission control technologies such as selective catalytic reduction (SCR),
which is located within the HRSG and is only effective when operated in a narrow
temperature range, limit the ability to use a supplemental duct burner to track thermal
loads. Varying firing temperatures in the duct burner result in variations in SCR
efficiency, increasing NOx emissions. If it is necessary to operate the duct burner at
different output levels, as may be the case for thermal load tracking or in a combined
cycle, it may be necessary to install multiple catalysts with different temperature
windows to ensure required NOx removal.
7.3.4 Diverter Valves
Diverter valves are located between the turbine exhaust and the HRSG. They
provide the capability to reject exhaust gases during those periods when the site steam
load is less than the thermal output of the turbine or when the HRSG may be out of
service. Diverter valves can be used to bypass a portion of the exhaust flow, thus
modulating steam production. By bypassing the HRSG with its pressure drops and
resulting turbine capacity loss, diverter valves can increase turbine output. They do,
however, result in some leakage of exhaust gases and a loss of steam capacity.
Alternatives to a diverter valve are the dry HRSG concept that is just becoming
commercialized, steam condensers, and the venting of steam from the HRSG, which
reduce the overall installed cost of the system. These options do not provide the ability
to operate the turbine during an HRSG outage and are less effective. Condensers can
be costly both to install and to operate. Venting of steam can be costly, because highquality, chemically treated water is rejected to the atmosphere;this alternative is
generally limited to emergency conditions.
7.4 MICROTURBINE HEAT RECOVERY
Microturbine CHP system efficiency is a function of exhaust heat temperature.
Recuperator effectiveness strongly influences the microturbine exhaust temperature.
Consequently, the various microturbine CHP systems have substantially different
overall efficiency and net heat rate chargeable to power. These variations in overall
efficiency and net heat rate are mostly caused by the mechanical design and
manufacturing cost of the recuperators and their resulting impact on system cost, rather
than stemming from differences in system size.
7.4.1 Hot Water Heat Recovery
Commercially available microturbines presently come in four sizes: 30, 65, 200,
and 250 kW. The primary method of recovered heat is in the form of hot water. The
three larger units have standard internal heat recovery systems, providing a clear
understanding of thermal characteristics. The following information was recorded at
ISO conditions.
The 30 kW microturbine exhaust gas flow is 0.69 lbm/s (0.31 kg/s) at 530°F (275°C).
This microturbine does not have an internal heat recovery heat exchanger.
The 65 kW microturbine exhaust gas flow is 1.08 lbm/s (0.49 kg/s) at 588°F (309°C).
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Table 7-1 presents typical hot water heat recovery capacity using the internal heat
recovery heat exchanger at 40 gpm (150 L/min) water flow.
The 200 kW microturbine exhaust gas flow is 2.93 lbm/s (1.33 kg/s) at 535°F (280°C).
Table 7-2 presents typical hot water heat recovery capacity using the internal heat
recovery heat exchanger at 150 gpm (570 L/min) water flow.
The 250 kW microturbine exhaust gas flow is 4.7 lb/s (2.13 kg/s) at 468 °F (242°C).
Figure 7-8 presents typical hot-water heat recovery capacity using the internal heat
recovery heat exchanger.
7.4.2 Steam Heat Recovery
HRSGs have been successfully applied to microturbine prime movers. Refer to
section 7.3.3 for more information concerning HRSGs.
7.5 FUEL CELL HEAT RECOVERY
The amount and quality of heat available from fuel cells depends on the type of
fuel cell (Table 7-3). Generally, 25% of the inlet fuel energy is recoverable from higherquality heat from the stack and reformer subsystems, and another 25% is contained in
the exhaust gases that include the latent heat of the product water generated in the fuel
cell. The most common use of this heat is to generate hot water or low-pressure steam
for process use or for space heating, process needs, or domestic hot water.
Heat can be recovered in the form of hot water or low-pressure steam (< 30 psig), but
the quality of heat is very dependent on the type of fuel cell and its operating temperature.
The one exception to this case is the PEMFC, which operates at temperatures below
212°F (100°C), and therefore has only low-quality heat.
Table 7-1. Hot-Water Heat Recovery with 65 kW Microturbine
Water Temperature
Heat Recovery, Btu/h (kWth)
Inlet, °F (°C)
Outlet, °F (°C)
85 (30)
108 (42)
450,000 (132)
140 (60)
160 (71)
400,000 Btu/h (118)
185 (85)
203 (95)
360,000 Btu/h (106)
Table 7-2. Hot-Water Heat Recovery with 200 kW Microturbine
Water Temperature
Heat Recovery, Btu/h (kWth)
Inlet, °F (°C)
Outlet, °F (°C)
85 (30)
98 (37)
970,000 (284)
140 (60)
151 (66)
835,000 (245)
185 (85)
195 (90
724,000 (212)
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For example, there are four primary potential sources of usable waste heat from a
fuel cell system: exhaust gas including water condensation, stack cooling, anode-off
gas combustion, and reformer heat. The PAFC system achieves 36% electric efficiency
and 72% overall efficiency, which means that it has a 36% thermal efficiency or power
to heat ratio of one. Of the available heat, 25 to 45% is recovered from the stackcooling loop that operates at approximately 400°F (204°C) and can deliver low- to
medium-pressure steam. The balance of heat is derived from the exhaust gas cooling
Figure 7-8. Hot-Water Heat Recovery with 250 kW Microturbine
Figure 7-8 (SI) . Hot-Water Heat Recovery with 250 kW Microturbine
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loop that serves two functions. The first function is condensation of product water, thus
rendering the system water self-sufficient, and the second function is the recovery of
by-product heat. Because its primary function is water recovery, the balance of the heat
available from the PAFC fuel cell is recoverable with 120°F (49°C) return and 300°F
(149°C) supply temperatures. This tends to limit the application of this heat to domestic
hot water applications. The other aspect to note is that all of the available anode-off gas
heat and internal reformer heat is used internally to maximize system efficiency.
In the case of SOFC and MCFC fuel cells, medium-pressure steam up to about 150
psig (1034 kPa [gage]) can be generated from the high-temperature exhaust gas, but the
primary use of these hot exhaust gases is in recuperative heat exchange with the inlet
process gases. Like engine and turbine systems, the fuel cell exhaust gas can be used
directly for process drying.
Table 7-3. Fuel Cell Characteristics32
Fuel Cell Type
Nominal Electricity Capacity,
kW
Fuel Consumed at Full Load @
ISO MMBtu, GJ
Electric Heat Rate, Btu/kWh
(kJ/kWh)
Electrical Efficiency (% HHV)
PEMFC PEMFC
PAFC
MCFC
SOFC
10
200
400
1200
125
0.1137
(0.12)
1.95
(2.057)
3.61
(3.809)
9.6264
(10.156)
1.003
(1.058)
11,370
(11,996)
9750
(10,287)
9025
(9522)
8022
(8464)
8024
(8466)
30%
35%
38%
43%
43%
Heat Avail. > 160°F (72.1°C),
MMBtu/hr (GJ/hr)
0.69
(0.73)
Heat Avail. > 1160°F (72.1°C),
MMBtu/hr (GJ/hr)
0.04
(0.042)
0.72
(0.76)
0.96
(1.01)
1.9
(2.05)
0.34
(0.36)
Total Heat Output, MMBtu/hr
(GJ/hr)
0.04
(0.042)
0.72
(0.76)
1.65
(1.74)
1.9 (2.0)
0.34
(0.36)
Heat Output, kW equivalent
11.7
211
281.3
556.7
99.6
Thermal Efficiency, fuel bases
in %
35%
37%
46%
20%
34%
Total Overall Efficiency (%),
HHV
65%
72%
84%
62%
76%
Power/Heat Ratio
0.85
0.95
1.42
2.16
1.25
65
72
84
62
76
0.85
0.95
1.42
2.16
1.25
Total Overall Efficiency, %
HHV
Power/Heat Ratio
“Technology Characterization: Fuel Cells”, U.S. Environmental Protection Agency, 2008.
32
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7.6 THERMALLY ACTIVATED EQUIPMENT
7.6.1 Lithium Bromide/Water Absorption Chillers
An absorption cycle is a heat-activated thermal cycle. It exchanges only thermal
energy with its surroundings; no appreciable mechanical energy is exchanged. Furthermore,
no appreciable conversion of heat to work or work to heat occurs in the cycle.
Absorption chillers are generally classified as direct- or indirect-fired, single- or
two-stage and use water as the refrigerant and lithium bromide (LiBr) as the absorbent
or ammonia as the refrigerant and water as the absorbent. In direct-fired units, the heat
source can be a gaseous or liquid fuel, including natural gas, propane bagasse33, diesel,
biodiesel, or some other fuel that is burned in the unit. Indirect-fired units use hot water,
steam, engine/turbine exhaust gases, or some other transfer fluid that brings in heat from
a separate source, such as a boiler, or heat recovered from an industrial process.
The single-stage “cycle” refers to fluid transfer through the four major components
of the refrigeration machine (evaporator, absorber, generator, and condenser) and
one heat recovery heat exchanger, as shown in the pressure-temperature diagram in
Figure 7-9.
The typical single-stage absorption cycle water chiller34 uses LiBr/water as the
fluid pair, whereas the typical refrigeration absorption cycle uses water/ammonia as the
fluid pair.
Figure 7-9. Single-Stage LiBr/Water Absorption Refrigeration Cycle
Bagasse is the fibrous matter that remains after sugarcane or sorghum stalks are crushed to
extract their juice. It is currently used as a biofuel and in the manufacture of pulp and paper
products and building materials.
33
Use of water, with a freezing point of 32°F (0°C), as a refrigerant limits the temperatures that
can be delivered by the absorber to more than 32°F (0°C).
34
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Figure 7-10 shows a typical single-stage LiBr/water absorption chiller and Figure
7-11 is a schematic diagram of a typical LiBr/water absorption cycle, which is described
in detail as follows:
• Heat is added to the cycle at the generator (Qgen), where a strong solution of LiBr
and water is heated, boiling the refrigerant (water). The water vapor leaving the
generator is at a high temperature and pressure and enters the condenser.
• Heat is removed from the cycle in the condenser (Qcond), where the hightemperature, high-pressure refrigerant (water vapor) is liquefied. Both the heat
of vaporization that was added to the refrigerant in the generator and the heat
that was removed from the cooling load are then typically rejected in a cooling
tower. Cooling tower loads for absorption chillers tend to be greater than those
for electric-motor-driven mechanical chillers, because the thermal input to the
generator is greater than the thermal input from compression. Capital and operating
costs must be understood because of these increased heat rejection requirements.
• Heat is removed in the evaporator (Qevap) to satisfy the cooling load, where the
low-temperature refrigerant is sprayed over the load-cooling loop. The refrigerant
vapor pressure in the evaporator is kept quite low, typically at approximately 0.1
psia (0.689 kPa) or less, and the refrigerant vaporizes, taking the required heat
of vaporization from the cooling load. The evaporator pressure determines the
temperature.
• The absorber is used to maintain the low vapor pressure in the evaporator/
absorber section of the cycle and also contains the absorbent. The absorbent, which
in this case is LiBr, is a material chosen because it has a high chemical affinity for
the refrigerant, which is water. The vapor produced in the evaporator quickly goes
into the solution in the absorber, maintaining a low vapor pressure. The absorption
reaction is exothermic, so heat is also removed from the absorber (Qabs).
• The dilute (or weak) solution is then pumped (W) from the absorber through a
heat recovery heat exchanger to the generator where heat is added to boil off the
refrigerant (water) and start the cycle over again.
Figure 7-10. Typical Single-Stage LiBr/Water Absorption Chiller
(Courtesy of Johnson Controls)
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Figure 7-11. Typical Single-Stage LiBr/Water Absorption Chiller
(Figure 2, Chapter 18, 2014 ASHRAE Handbook—Refrigeration)
Two-stage absorbers are formed by coupling the absorbers and evaporators of two
single-effect cycles into an integrated, single cycle. Heat is transferred between the
high-temperature condenser and low-temperature generator. The heat of condensation
of the refrigerant (generated in the high-temperature generator) generates additional
refrigerant in the lower-temperature generator. Thus, the prime energy provided to the
high-temperature generator is cascaded (used twice) in the cycle, making it a two-stage
cycle (Figure 7-12).
Some two-stage absorbers have the capability to accept high-temperature exhaust
gases directly from an engine, microturbine, or combustion turbine. Hybrid two-stage
absorption chillers, when paired with a reciprocating engine, have used engine exhaust
gas to drive the high-temperature generator and the engine jacket water to drive the
low-temperature generator. Exhaust-fired units can also be equipped to provide both
hot and/or chilled water up to the capacity of the burner or the exhaust gas heat
exchanger. The use of a two-stage absorber equipped to use exhaust gases directly
from a gas-fired engine eliminates the need for an HRSG with a reduction in budget.
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Figure 7-12. Two-Stage Water/LiBr Absorption Refrigeration Cycle
Exhaust-firing a chiller is typically used in industrial processes where cooling is the
only significant thermal requirement. Note that, unless the absorption chiller was
equipped with a direct-fired burner, the chiller would not be available if the turbine
were shut down, whereas a steam-fueled system could operate using a conventionally
fired boiler as the steam source.
When choosing between a single- and two-stage, hot-water-driven absorption
chiller, it is important to understand the relationship between COP, generator
temperature requirements, complexity, and capital cost. For example, is it better to use
a single- or two-stage absorption chiller35 with a 5 million Btu/h (1465 kW) source of
hot water at 500°F (260°C) rejecting heat to a cooling tower? From a capacity point of
view the following equation is used:
Qabs = Q
input
×∈
chiller
7-7
where
Qabs = absorption chiller cooling capacity, tons (kW)
∈absorption chiller = absorption chiller thermal efficiency (0.7 single stage, 1.1 two-stage)
This example compares conventional hot-water designs. For example, specially designed
absorption chillers to use microturbine exhaust will have different results.
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Qthermal � input = m hot� water �� × Cp � (Tin � − Tout )
7-8
where
m hot water = hot-water follow rate,(lbs/minute)(kg/h)
C p = specific heat for water at constant pressure = 1.0 Btu/llb·°F (4.19 kJ/kg·°K)
Tin = available input temperature = 500°F (533°K)
Tout = varies depending on the heat sink (e.g.,a cooling tower can provide an
average heat rejecction temperature of 97°F [309°K], a single stage
absorption chiller can provide a heat sink temperature of about 200°F
[366.5°K], and a two-stage absorption chiller about 325°F [436°K])
5, 000, 000 Btu h = m hot water × 1.0 Btu/lb·°F × (500°F − 97°F) = 12,407 lbs/h
5, 275, 280kJ h = m hot water × 4.19 kJ/kg·°K × (533°K − 309°K) = 5,621 kg/h
∈absorption chiller = 0.70 for single-stage and 1.1 for-two stage
Qabs single− stage = 12,407 lbs/h × 1 (500°F − 200°F) x 0.70 = 217 tons cooling
Qabs single− stage = 5,621 kg/h × 4.19 kJ/kg·°K (533°K − 366.5°K) × 0.70 = 2,744,794 kJ
Qabbs two − stage = 12,407 lbs/h × 1 ( 500 °F − 325°F ) × 1.10 = 199 tons cooling
Qabs two − stage = 5,621 kg/h × 4.19 kJ/kg·°K (533°K − 436°K) × 1.10 = 2,512,823 kJ
Using the preceding 5 million Btu/h (1465 kW) example and simply varying the
supply temperature and correcting for flow rate, Figure 7-13 provides the relationship
between supply temperature and chiller capacity. A crossover point around 550°F
(288°C) occurs. However, one caution to consider: the growing interest in applying
absorption chillers to CHP systems has stimulated development of specialty chillers
specifically designed to utilize exhaust gases, which would distinctly alter the
performance depicted in Figure 7-13. Always check with the manufacturer to understand
the best match for a given waste heat stream.
Single-state and two-stage lithium bromide/water absorption chillers have distinctly
different performance (Table 7-4). In waste heat recovery situations, using a two-stage
absorption chiller will provide more capacity, but how much more will depend on the
waste heat supply and return temperatures. Ultimately, the selection will depend on the
site load requirements, the prime mover thermal capacity, and economics.
7.6.2 Ammonia/Water Absorption Chillers
The basic operation of an ammonia/water absorption cycle is the same as the water/
LiBr cycle shown in Figure 7-9. Heat is applied to the generator, which contains a
solution of ammonia water, rich in ammonia. The heat causes high-pressure ammonia
to vaporize out of the solution. The high-pressure ammonia vapor flows to a condenser
where heat is removed. The ammonia vapor condenses into a high-pressure liquid,
releasing heat.
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Table 7-4. Typical LiBr Absorption Chiller Characteristics
Single Stage
Two-Stage
0.65 to 0.7
1.1to 1.2
Steam input pressure
9 to 12 psig (62 to 83 kPa [gage])
115 psig (793 kPa [gage])
Steam consumption
18.3 to 18.7 lb/ton·h
(2.37 to 2.38 kg/kWh)
9.7 to 10 lb/ton·h
(1.25 to 1.29 kg/kWh)
Hot-fluid input temp.
240 to 270°F(115 to 132°C), with as low as
200°F (93°C) for some smaller machines
for waste heat applications
370°F (188°C)
18,100 to 18,500 Btu/ton·h
(1.58 to 1.54 W/Wh), with as low
as 17,100 Btu/ton·h (1.42 W/Wh)
for some smaller machines
10,000 Btu/ton·h
(0.83 W/Wh)
85°F (29.4°F)
85°F (29.4°F)
3.6 gpm/ton (0.065 L/s·kW), with up to
6.4 gpm/ton (0.115 L/s·kW) for some
smaller machines
3.6 to 4.5 gpm/ton
(0.065 to 0.081 L/s·kW)
44°F (6.7°C)
44°F (6.7°C)
2.4 gpm/ton (0.043 L/s·kW), with 2.6 gpm/
ton (0.047 L/s·kW) for some smaller
machines
2.4 gpm/ton
(0.043 L/s·kW)
0.01 to 0.04 kW/ton (0.003 to 0.011 kWe/
kWth) with a minimum of 0.004 kW/ton
(0.0011 kWe/kWth) for some smaller
machines
0.01 to 0.04 kW/ton
(0.003 to 0.011 kWe/kWth)
Single Stage
Two-Stage
Nominal capacities
50 to 1660 tons (176 to 5,838 kW), with
5 to 10 tons (18 to 35 kW) for some
smaller machines
100 to 1700 tons (352 to 5,979 kW)
up to 3,300 tons (11,606 kW) for
some large machines
Length
11 to 33 ft (3.4 to 10.1 m), with as low as
3 ft (0.9 m)for some smaller machines
10 to 31 ft
(3 to 9.4 m)
Width
5 to 10 ft (1.5 to 3 m), with 3 ft (0.9 m)
minimum for some smaller machines
6 to 12 ft
(1.8 to 3.7 m)
Height
7 to 14 ft (2.1 to 4.3 m), with 6 ft
(1.8 m) for some smaller machines
8 to 14 ft
(2.4 to 4.3 m)
11,000 to 115,000 lb (5,000 to 52,273 kg),
with 715 lb (325 kg) for some smaller
machines
15,000 to 132,000 lb
(6,818 to 60,000 kg)
COP indirect-fired
Heat input rate
Cooling water temp. in
Cooling water flow
Chilled-water temp. off
Chilled-water flow
Electric power
Typical Physical
Characteristics
Operating weight
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Figure 7-13. Absorption Chiller Capacity versus Thermal Supply Temperature
Figure 7-13 (SI). Absorption Chiller Capacity versus Thermal Supply Temperature
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The high-pressure ammonia liquid goes through a restriction to the low-pressure
side of the cycle. This liquid ammonia, at low pressures, boils or evaporates in the
evaporator. This provides the cooling or refrigeration product. The low-pressure vapor
flows to the absorber, which contains a water-rich solution obtained from the generator.
This solution absorbs the ammonia while releasing the heat of absorption. The solution
in the absorber, now once again rich in ammonia, is pumped to the generator, where it
is ready to repeat the cycle.
The use of ammonia as the refrigerant means that an ammonia/water absorption
system can reach temperatures as low as -50°F (-45.6°C).
7.6.3 Adsorption Chillers
Adsorption is the term frequently used for solid-vapor sorption systems in which
the sorbent is a solid and the sorbate a gas.
Figure 7-14 depicts a typical dual-bed water/silica gel adsorption cycle, which is
described as follows:
• Heat is added to the cycle at the desorber (Qdes), where a water-vapor-laden silica
gel bed is heated, driving the refrigerant (water) from the silica gel bed (adsorber/
desorber). The water vapor leaving the desorber is at a high temperature and
pressure and enters the condenser.
• Heat is removed from the cycle in the condenser (Qcond), where the hightemperature, high-pressure refrigerant (water vapor) is liquefied. Both the heat
of vaporization that was added to the refrigerant in the generator and the heat
that was removed from the cooling load are then typically rejected in a cooling
tower. Cooling tower loads for adsorption chillers tend to be greater than those
for electric-motor-driven mechanical chillers, because the thermal input to the
generator is greater than the thermal input from compression. Capital and operating
costs must be understood because of these increased heat rejection requirements.
Figure 7-14. Water/Silica Gel Dual-Bed Adsorption Refrigeration Cycle
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• Heat is removed in the evaporator (Qevap) to satisfy the cooling load, where the
low-temperature refrigerant is sprayed over the load-cooling loop. The refrigerant
vapor pressure in the evaporator is kept quite low, typically at approximately
0.1 psia (0.689 kPa) or less, and the refrigerant vaporizes, taking the required
heat of vaporization from the cooling load. The evaporator pressure determines
the temperature.
• The adsorber section is used to maintain the low vapor pressure in the evaporator/
adsorber section of the system. The adsorbent, which in this case is silica gel,
because it is very porous, has a large specific surface area and a high adsorbent
affinity for the refrigerant, which is water. The vapor produced in the evaporator
quickly goes into the porous silica gel, maintaining a low vapor pressure in this
section of the system. The adsorption reaction is exothermic so heat is also removed
from the adsorber (Qads).
• The dilute (or weak) solution is then pumped (W) from the adsorber through a
heat recovery heat exchanger to the generator where heat is added to boil off the
refrigerant (water) and start the cycle over again.
The growing interest in the recovery of thermal energy in the lower temperature
range < 212°F (<100°C) is leading to an increased interest in adsorption chiller
technology (Figure 7-15). A distinct advantage of adsorption chillers is that they can
produce chilled water using low temperature 140 to 176°F (60 to 80°C) waste water.
Figure 7-15. Water/Silica Gel Dual-Bed Adsorption Chiller
(Courtesy of Power Partners)
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However, this capability comes at a cost, in that adsorption chillers have low efficiencies36
and require multiple beds that switch between adsorbing and desorbing. To manage
constant chilled-water flow and temperature requires adsorption chillers to be installed
with thermal storage, and the complete installation including a chiller, thermal storage,
valves, pumps, and controls can be a cost consideration.
7.6.4 Steam Turbine Chillers
Steam turbine chillers (Figure 7-16) use medium-pressure steam as a motive
source. Steam-turbine-powered chillers offer several advantages over other steampowered (double-effect) absorption chillers. Off-design-point efficiency is superior
because of the inherent use of variable-speed operation, and the space required for
turbine installation is less. Although it is possible to design steam-powered systems for
almost any requirement, water chillers are usually offered for larger capacities from
1000 to 8000+ tons (3500 to 28 000+ kW). Steam sources in the range 100 to 200 psig
(690 to 1380 kPa) are most commonly used.
Figure 7-16. Steam-Turbine-Driven Chiller
(Courtesy of Johnson Controls)
With 83.4°F (28°C) cooling tower water, providing 53.6°F (12°C) chilled water: one
adsorption chiller using 149°F (65°C) hot water has a 0.42 COP. The same chiller with 212°F
(100°C) hot water yields a 0.65 COP.
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The principle of operation (Figure 7-17) is that steam is fed to a steam turbine
(Qsteam), which turns a compressor. The compressor provides the motive force for a
traditional refrigerant vapor compression cycle where useful cooling is generated in the
evaporator. Heat is rejected in the refrigerant condenser to cooling water (Qcond). The
same cooling water is then also passed to the steam condenser to absorb the heat
required to condense the steam exiting the turbine (Qsteam cond). The condensed steam
(condensate) is returned to the steam generating source.
7.6.5 Desiccant Dehumidification Systems
Desiccant dehumidification systems remove moisture from the air by forcing the
water vapor directly into a desiccant material. The moisture from the air is attracted to
desiccants, because an area of low vapor pressure is created at the surface of the
desiccant. The pressure exerted by the water in the air is higher, so the water molecules
move from the air to the desiccant, and the air is dehumidified.
The functioning of an adsorbent desiccant can be compared to the action of a
sponge in collecting a liquid. When the sponge is dry, it soaks up the liquid effectively.
Once it becomes saturated, the sponge is taken to a different spot, the liquid is expelled
by squeezing the sponge, and the dry sponge is ready to absorb more liquid.
In a desiccant system, if the desiccant material is cool and dry, its surface vapor
pressure is low, and moisture is attracted and absorbed from the air, which has a higher
vapor pressure. After the desiccant material becomes wet and hot, it is moved to another
airstream and the water vapor is expelled by raising the temperature (this step is called
“regeneration”). After regeneration, the desiccant material is ready to be brought back
to adsorb more water vapor. The entire adsorption process involves only water vapor;
no liquid is ever condensed.
Desiccants can be either solids or liquids. The difference between solid and liquid
desiccants is their reaction to moisture. Some simply collect moisture like a sponge
collects water. These desiccants are called adsorbents and are mostly solid materials.
Silica gel is an example of a solid adsorbent.
Other desiccants undergo a chemical or physiological change as they collect
moisture. These are called absorbents and are usually liquids or solids that become
liquid as they absorb moisture. Lithium chloride collects water vapor by absorption.
Sodium chloride, common table salt, is another example of an absorbent.
7.6.6 Thermal Energy Storage
Thermal energy storage comprises a number of technologies that store thermal
energy in energy storage reservoirs for later use. They can be used to balance energy
demand between day and night. The thermal reservoir may be maintained at a
temperature above or below that of the ambient environment. Applications today
include the production of ice, chilled water, or eutectic solution at night, or hot water
which is then used to cool/heat environments during the day.
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Figure 7-17. Steam-Turbine-Driven Chiller Cycle
7.7 INTEGRATION WITH BUILDING SYSTEMS
7.7.1 Thermal Transport Medium
Thermal energy can be transported as either steam or hot or chilled water. Steam
distribution systems generally operate at lower pressures, although some do operate at
pressures of 150 to 200 psig (1033 to 1378 kPa). Hot-water systems can be designed
over a broad range of temperatures and can be characterized as high-temperature, with
temperatures greater than 400°F (204°C); medium-temperature, with water supply
temperatures between 180 and 400°F (82 and 204°C); and low-temperature, which
operate at temperatures of less than 180°F (82°C). The choice between steam and hot
water depends on a number of factors, discussed in the following paragraphs.
Steam distribution piping can be quite large and, to minimize costs, these systems,
in the past, have been constructed without a condensate return loop, but this is not
currently common practice. Large quantities of heat may be lost when the condensate
is discharged. Construction of a steam distribution system without a condensate return
can result in a number of operating costs that must be included in any life-cycle cost
analysis. These additional costs include the loss of condensate thermal energy with a
negative effect on system distribution efficiency and increased requirements for
treated water at the steam production facility. The requirement to replace the
condensate results in higher costs for both raw water and chemical treatment. In many
cases, the condensate temperature, whether discharged to a sewer system or a surface
body of water, will exceed allowed discharge temperatures, requiring that the end-user
mix the condensate with service water, thus incurring additional water costs. Finally,
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if the condensate is discharged to a sewer system, there may be sewer charges for the
incremental load. Hot-water distribution systems are able to function with smaller
pipe sizes; however, two pipes are required: a supply and a return. Hot-water
distribution systems generally return all water, thus avoiding makeup water supply
and associated chemical treatment costs.
Efficiency, which affects fuel costs, is also a significant factor/consideration, and a
number of parameters result in higher efficiencies for hot-water distribution systems as
compared to steam distribution systems. In general, hot water systems operate at lower
temperatures, thus resulting in lower sensible-temperature-related losses. The
temperature of the hot-water system can be adjusted in response to load, thus providing
the opportunity for even lower temperatures and decreased thermal losses. In general,
hot water systems have a lower leakage rate than steam systems. Steam traps and drains
introduce the opportunity for additional losses not found in hot-water systems.
Condensate must be removed from the steam system to reduce water hammer, further
increasing losses. Because they are more efficient, hot-water transmission systems can
be quite long, extending for up to 20 mi (32 km).
Hot-water systems also have better operational characteristics. Hot-water systems
are normally full during start-up and shutdown, and system start-up and shutdown are
rather simple in comparison to steam systems. In contrast, steam system start-up and
shutdown can be quite complex, lengthy, and costly. Operating a steam distribution
system to maintain the steam supply in balance with the steam load, without excessive
pressures or condensation, also contributes to more complex operating procedures. The
mass of the hot water in the system inherently provides thermal storage. The hot-water
temperature can be increased during periods of low demand to store heat and can then
be allowed to drop during high-use periods, thus drawing on the stored thermal energy.
All thermal distribution systems must be designed to compensate for the
temperature changes that occur during start-up, shutdown, and, for variable-temperature
hot-water systems, temperature changes during actual operation. Expansion loops (or
other acceptable methods) are required to relieve any thermal stresses and to reduce the
potential for line failure and system leakage.
Chilled-water systems are not as common as steam and hot-water distribution
systems. Chilled-water systems operate at lower temperatures and temperature
differences than do hot-water systems; chilled water cannot be economically transported
the same distance as hot water. Chilled-water systems operate through a smaller
temperature difference, resulting in high mass flows and flow rates; the higher flows
result in higher costs for piping and ancillary pumps and valves.
7.7.2 Thermal Distribution System Routing
The location and routing of a thermal distribution system has a significant impact
on construction costs. Aboveground systems are less costly; however, they require that
the developer of the district loop have ownership or rights-of-way for all required
routings. In addition, aboveground systems are more accessible with less costly
maintenance; aboveground systems are more susceptible to accidental damage and,
depending on ambient temperatures, can have greater losses than underground systems.
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Underground installations are generally more costly to construct, with their cost
being a function of the burial technique. System losses tend to be lower, because the
surrounding temperature is higher and constant; however, underground installations
can be quite expensive to maintain. Leaks may be difficult to identify, and repairs can
be quite costly and inconvenient, because it is necessary to dig up the existing lines.
Despite these shortcomings, underground distribution systems are most frequently
specified. When hot- and chilled-water distribution systems are included in the same
tunnel or trench, the distribution systems must be adequately insulated and separated
from each other to avoid a “short-circuiting effect.” Manholes should be designed to
allow water to drain, thus reducing the potential for standing water to break down
pipe insulation.
There are two general choices for burial: tunnels and trenches or direct burial.
Tunnels and trenches may be of varying size and cost. The most costly option consists
of a concrete utility tunnel that may also include electrical cables, telecommunications,
and chilled-water lines. Large tunnels also allow personnel and material transportation
between buildings. Smaller tunnels may be nothing more than shallow trenches
equipped with a removable cover for maintenance and repair. Tunnels and trenches may
be constructed of poured-in-place concrete or of prefabricated concrete or steel
sections. Tunnels and trenches allow pipes to be elevated, thus reducing the potential
for corrosion. Direct burial is becoming more common and requires much more care
during installation. Prefabricated piping is also more commonly specified, both to
reduce installation costs and to ensure quality in pipe construction, including the
welding and joining of pipe sections. Pipe corrosion is a significant problem with
direct-burial systems, and both protective coatings and cathodic protection are
sometimes required to reduce the potential for deterioration.
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CHAPTER 8
CHP REGULATORY AND POLICY ISSUES
8.1 REGULATION
Governmental regulations addressing installation of a CHP system focus on
obtaining the requisite environmental compliance permits, fulfilling utility
interconnection requirements, obtaining construction permits, air permits, and
operating permits. Permit conditions generally impact project design, and construction
cannot begin until all permits are in process or in place. The process of permitting a
CHP system typically takes 3 to 12 months to complete, depending on the location,
technology, and site characteristics.
Government approval procedures are those required by the local planning and
building departments, fire department, and air quality district to ensure that a CHP
project complies with the following:
• Local ordinances (e.g., noise, set-backs, general planning and zoning, land use,
and aesthetics)
• Standards and codes (e.g., fire safety, piping, electrical, and structural)
• Air emissions requirements (e.g., NOx, CO, and particulate standards)
The roles and responsibilities of several authorities having jurisdiction over CHP
siting and permitting are outlined, including the following:
• Local building inspectors (e.g., building permits)
• Local fire marshals (e.g., fuel storage codes)
• Local zoning boards (e.g., noise limitations)
• City/state environmental departments (e.g., air emissions permits)
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8.1.1 Air Permitting
For all but the smallest CHP applications, the principal hurdle is likely to be
the air permit. Air permitting guidance follows a sequential structured pattern of
consideration:
1. Location
2. Technology
3. Size/emissions rates
The New Source Review (NSR) permitting program was established as part of the
1977 Clean Air Act Amendments. Under this program, stationary sources of air pollution
are required to obtain an air permit before commencing construction or making certain
modifications. The permit specifies the air pollution control devices that must be used,
emission limits that must be met, and how the facility must be operated.
There are three types of NSR permitting requirements. A source may have to obtain
one or more of the following:
• Prevention of Significant Deterioration (PSD) permit: PSD permits are
required for new major sources or major modifications to major sources in an
attainment area. PSD permits may be issued by EPA or by state and local permitting
authorities. PSD applies to new major sources or major modifications at existing
sources for pollutants where the area the source is located in is in attainment or
unclassifiable with the National Ambient Air Quality Standards (NAAQS). It
requires the following:
š Installation of the “Best Available Control Technology37 (BACT)”
š Air quality analysis
š Additional impacts analysis
š Public involvement
• Nonattainment NSR permit: Nonattainment NSR permits are required for new
major sources or major modifications to major sources in a nonattainment area.
These permits are generally issued by state and local permitting authorities.
• Minor source permit: Minor NSR is for pollutants from stationary sources
that do not require PSD or nonattainment NSR permits. Minor NSR permits often
contain permit conditions to limit the emissions to avoid PSD or nonattainment
NSR. Minor NSR permits are issued by state and local permitting authorities
according to programs approved by EPA.
BACT is an emissions limitation based on the maximum degree of control that can be achieved.
It is a case-by-case decision that considers energy, environmental, and economic impact. BACT
can be add-on control equipment or modification of the production processes or methods. This
includes fuel cleaning or treatment and innovative fuel combustion techniques. BACT may be a
design, equipment, work practice, or operational standard, if imposition of an emissions standard
is infeasible.
37
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• Title V permits: This permit type is mandatory for major sources, which are
those featuring a Potential to Emit38 (PTE) for one or more regulated pollutants
that is greater than the federal thresholds. It is also required for certain sources that
are subject to the federal New Source Performance Standards. This type of permit
requires submission of much more extensive documentation than the state facilities
permit. A 30-day public comment period on a proposed permit applies, and EPA
has 45 days for review. If EPA objects, the site must satisfy its objections before the
permit can be issued. Facilities must certify each year that they are in compliance
with the permit conditions, and must renew the permit every five years. Significant
modification of a Title V permitted facility (i.e., addition of a new or modification
of an existing emission unit or change in mode of operation) triggers the need to
apply either for a modified Title V permit or a state permit for the new unit. For
example, major NOX source facilities are defined as those with PTE ≥ 25 tons/yr in
severe nonattainment areas and ≥100 tons/yr for nonattainment areas.
8.1.2 Grid Interconnection
Interconnection refers to the technical, contractual, rate, and metering issues that
must be settled between a CHP system owner, utility, and local permitting authorities
before the system can be connected to the electrical grid. Interconnection requirements
vary from state to state and from utility to utility. Interconnection issues tend to revolve
around procedures to obtain interconnection and the uncertainty about the amount and
type of equipment that is necessary to protect utility line workers and the utility system
in general. Key utility interconnection concerns include the following:
• Power quality: Utilities are concerned that an interconnected on-site generator
not degrade the quality of power supplied by the utility as measured by voltage and
frequency stability, power factor, and harmonic content.
• Power safety: Utilities are concerned that an interconnected generator has the
potential to energize a utility circuit that is not being powered by the utility. This
condition can result in a safety hazard to utility personnel working on that circuit.
Most utilities will require installation of an external disconnect switch that is
accessible by utility personnel and that can be used to disconnect and lock out the
CHP system.
• Grid operations: Interconnection of a CHP system or any other active source of
power within the electrical grid should be reviewed to avoid jeopardizing the ability
of the utility to manage grid operations.
• Dispatchability: Utilities require that a CHP system be isolated from the
electrical grid during periods of emergency or for grid safety.
• IEEE 1547: In March 1999, the Institute of Electrical and Electronics Engineers
(IEEE) Standards Association Board voted to undertake the development of
uniform standards for interconnecting distributed resources with electric power
systems. Since then, the IEEE Standards Coordinating Committee 21 has
completed work on the development of the IEEE 1547 Standard for Distributed
The potential to emit is the highest amount of regulated pollutants your business could release
into the air when operating at full capacity for 8760 h/yr (even if you never have or will not
actually emit the highest amount).
38
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Resources Interconnected with Electric Power Systems. This consensus standard
contains specific requirements related to performance, operation, testing, safety,
and maintenance of interconnections between distributed resources and other
electric power systems39.
• UL1741: Standardized requirements for inverters, converters, charge controllers,
and output controllers have been adopted by Underwriters Laboratories, Inc.
(UL) and are provided in UL 1741. Equipment covered by this standard is used
in stand-alone (not grid connected) or utility-interactive (grid-connected) power
systems. The utility-interactive inverters and converters discussed in the standard
are intended to be installed in parallel with an electric supply system or an electric
utility to supply common loads.
• Standard interconnection rules: These rules address the application process and
the technical requirements for interconnecting CHP projects of a specified type and
size with the electric grid. Standardized interconnection rules, which are generally
developed and administered by a public utility commission, establish clear and
uniform processes and technical requirements for connecting CHP systems to the
electric utility grid. These rules are an important mechanism for improving the
market conditions for CHP.
• Application process: Includes some or all parts of the interconnection process,
starting from when a potential customer considers submitting an application up to
the time when the interconnection agreement is finalized. For example, rules might
specify application forms, timelines, fees, dispute resolution processes, insurance
requirements, and interconnection agreements.
• Technical interconnection requirements: Includes technical protocols and
standards that govern how generators must interconnect with the electric grid. Rules
generally specify the type of generation technology that can be interconnected, the
required attributes of the electrical grids where the system will be connected, the
types of equipment and protocols required for the physical interconnection, and the
maximum system size that is eligible for the interconnection process.
These requirements may specify that the CHP system must conform to industry or
national standards (e.g., IEEE 1547, UL 1741), and might include protection systems
designed to minimize degradation of grid reliability and performance, as well as to
maintain worker and public safety.
8.2 U.S. FEDERAL CHP ENERGY POLICY
Energy policy is a function of many issues including assumptions about energy
supply and demand, corporate interest, economics, market interest or disinterest,
pollution fears, climate change, and politics. CHP is generally recognized as a positive
approach to energy policy moving forward.
IEEE 1547, Standard for Interconnecting Distributed Resources with Electric Power Systems,
http://grouper.ieee.org/groups/scc21/1547/1547_index.html.
39
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CHP REGULATORY AND POLICY ISSUES
In 2001, the U.S. Department of Energy established the first of eight regional Clean
Energy Application Centers to provide local technical assistance and educational
support for CHP development. In 2001, the U.S. Environmental Protection Agency
established the CHP Partnership to encourage cost-effective CHP projects and expand
CHP development in underutilized markets and applications.
On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005) was signed into
law. Section 1253(a) of EPAct 2005 adds a new section 210(m) to the Public Utility
Regulatory Policies Act of 1978 (PURPA) that provides for termination of an electric
utility’s obligation to purchase energy and capacity from qualifying CHP facilities and
qualifying small power production facilities (QFs), including CHP facilities, if the
Federal Energy Regulatory Commission (Commission) finds that certain conditions
are met. PURPA removed Federal feed-in tariffs40 for CHP plants and essentially put a
significant drag on the expansion of CHP systems nationwide.
On August 30, 2012, Presidential Executive Order 13626 was issued to accelerate
investment in industrial energy efficiency. This Executive Order directs the Departments
of Energy, Commerce, and Agriculture, and the Environmental Protection Agency, in
coordination with the National Economic Council, the Domestic Policy Council, the
Council on Environmental Quality, and the Office of Science and Technology Policy to
coordinate policies to encourage investment in industrial efficiency focusing on CHP.
Specifically, these agencies were directed, as appropriate and consistent with applicable
law, to
(a) coordinate and strongly encourage efforts to achieve a national goal of
deploying 40 gigawatts of new, cost effective industrial CHP in the United
States by the end of 2020;
(b) convene stakeholders, through a series of public workshops, to develop and
encourage the use of best practice state policies and investment models that
address the multiple barriers to investment in industrial energy efficiency
and CHP; and
(c) utilize their respective relevant authorities and resources to encourage
investment in industrial energy efficiency and CHP.
Federal focus and support encompassed within this Executive Order targeting
increasing industrial CHP use will undoubtedly impact market adoption throughout the
Federal sector, and influence state policy as well as the private sector.
8.3 FEDERAL CHP TAX POLICY
Federal tax policy relating specifically to CHP will remain in effect until 2017 and
should be incorporated in any economic evaluation. The key to applying the Investment
Tax Credit (ITC) is that the CHP plant must be in service before January 1, 2017.
A feed-in tariff (FIT) is a policy mechanism designed to accelerate investment in energy
technologies. It achieves this by offering long-term contracts to energy producers, typically
based on the cost of generation of each technology. Technologies such as CHP are often eligible.
40
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The CHP Investment Tax Credit (ITC) is a tax credit for the costs of the first
15 MW of CHP property. To qualify for the tax credit, the CHP system must meet the
following conditions:
• Produces at least 20% of its useful energy as electricity and 20% in the form of
useful thermal energy
• Smaller than 50 MW
• Constructed by the taxpayer or have the original use of the equipment begin with
the taxpayer
• Placed in service after October 3, 2008, and before January 1, 2017
• Greater than 60% efficient on a lower heating value basis
The 60% efficiency requirement does not apply to CHP systems that use biomass
for at least 90% of its energy source. The ITC may be used to offset the alternative
minimum tax, and the CHP system must be operational in the year in which the credit
is first taken.
The CHP ITC is claimed through IRS Form 3468, available on the IRS website.
Facility owners who claim the ITC cannot claim the production tax credit (PTC) or
receive a grant in lieu of the ITC.
8.3.1 Investment Tax Credits for Microturbines and Fuel Cells
For microturbines, the ITC is equal to 10% of expenditures, with no maximum
credit limit stated (explicitly). The credit for microturbines is capped at $200 per kilowatt
of capacity. Eligible property includes microturbines up to 2 MW that have an electricityonly generation efficiency of 26% or higher.
For fuel cells, the credit is equal to 30% of expenditures, with no maximum credit.
However, the credit for fuel cells is capped at $1500 per 0.5 kilowatt of capacity.
Eligible property includes fuel cells with a minimum capacity of 0.5 kW that have an
electricity-only generation efficiency of 30% or higher. (The credit for property placed
in service before October 4, 2008 is capped at $500 per 0.5 kW.)
Facility owners who claim the ITC cannot claim the production tax credit (PTC) or
receive a grant in lieu of the ITC.
The ITC for both microturbines and fuel cells is available for eligible systems
placed in service on or before December 31, 2016. As with the CHP ITC, facility
owners can choose to receive a one-time grant in lieu of receiving the tax credit as long
as the facility is depreciable or amortizable. The Treasury Department is now accepting
applications for the grant program. A guidance document, terms and conditions, the
application, and answers to frequently asked questions related to taking a grant in lieu
of the tax credit are available on the U.S. Department of Treasury website.
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8.4 STATE CHP ENERGY POLICY
State financial incentives are an important instrument for increasing the use of
technologies that provide benefits to both residents and the state overall. The
incorporation of a financial incentive can make energy efficiency investments more
alluring for private and public entities. Homeowners and businesses not only save
energy but also reduce pollutants, improve electric system reliability, and save
significant amounts of money over the life of their investments. Financial incentives
also help newer technologies, such as micro-CHP, to overcome barriers to market entry.
Financial incentives can take many forms: rebates, grants or loans for energyefficiency improvements, direct income tax deductions for individuals and businesses,
and exemptions from sales tax on eligible products. The majority of financial incentives
for CHP systems, however, are loans and grants; tax exemptions, grants, and bonds are
less commonly used. Eligibility often depends on meeting specific energy savings
goals, such as a 20% reduction in facility energy use over five years.
State programs are too numerous and transitory to list in a design guide, however
understanding all economic incentives available to a CHP project can be critical to a
positive economic outcome. The Database of State Incentives for Renewables &
Efficiency (DSIRE http://dsireusa.org/) is the most comprehensive resource for current
state, local, and utility incentives for energy efficiency and renewable energy. The
following paragraphs provide some examples of different state projects.
Loans. States offer low-interest loans for a wide variety of energy efficiency measures.
Rates and terms vary by program, though a maximum 10-year term is common. For
example, New Jersey’s Clean Energy Solutions Capital Investment Loan/Grant Program
provides interest-free loans and grants to New Jersey-based industrial, commercial, or
institutional entities for end-use efficiency and combined heat and power projects. Loans
are limited to $5 million, of which up to $2.5 million may be taken as a grant. Loans have
a maximum 10-year term, and a minimum of 50% of project costs must be financed by
the project sponsor. The loan program receives revenue from the sale of greenhouse gas
emission allowances under the Regional Greenhouse Gas Initiative (RGGI).
Connecticut’s Low-Interest Loans for Customer-Side Distributed Resources
program, in effect since 2006, provides loans to customers for the installation of
distributed generation systems, including CHP, with a capacities of 50 to 65 MW. Interest
rates are 1% below the customer’s applicable rate, or no more than the prime rate.
Grants. Most grant programs are designed primarily to offset the costs of eligible
technologies, although some promote research and development or support project
commercialization. For example, Massachusetts’ Green Communities Grant Program
provides funding for municipalities to pursue energy efficiency and renewable energy
projects. Among the conditions for eligibility are the requirement to establish an energy
use baseline and the development of a plan to reduce energy use 20% below this baseline
within five years. Ohio’s Advanced Energy Fund Grants program offers grants up to
25% of project cost (with a maximum of $100,000) for, among other things, CHP and
waste heat recovery projects up to 25 MW. Applications are evaluated according to a
number of criteria including overall system efficiency, the balance of financing
committed, and project cost per kilowatt produced.
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Tax Credits and Exemptions. Like most property tax exemptions, Arizona’s
Energy Equipment Property Tax Exemption program, for example, excludes the added
value of eligible renewable and energy efficient systems from the valuation of the
property for tax purposes. As another example, Oregon’s Business Energy Tax Credit
provides tax credits to businesses for a wide variety of renewable and energy efficiency
initiatives. A 50% tax credit is awarded to high-efficiency CHP projects that achieve
20% annual energy savings.
Rebates. As an example of a state rebate program, New York’s Energy $mart New
Construction Program provides technical assistance and cash rebates for the installation
of energy-efficiency measures, including CHP, in new or substantially renovated
buildings owned by businesses, state and local governments, not-for-profits, colleges
and universities, and other facilities. The program awarded $53 million in 2010. The
state also offers a smaller-scale program for existing facilities.
Bonds. The use of bonds to incentivize CHP deployment is rare. However, New
Mexico’s Energy Efficiency and Renewable Energy Bond Act authorizes up to $20
million in bonds to finance energy efficiency and renewable energy improvements in
state government and school buildings. State agencies or school districts may request
an energy assessment from the New Mexico Energy, Minerals and Natural Resources
Department to identify specific energy saving measures. Combined heat and power and
waste heat recovery systems are eligible for funding. Bonds are to be paid back by
realized energy savings.
8.5 GRANT ASSISTANCE REQUIREMENTS
Grant assistance requirements generally assure the grantor that the funds will
actually achieve the intended results. The requirements assure that the host site and the
CHP system complies with certain minimum standards.
A CHP host facility must be located in the appropriate jurisdiction of the grant
making entity. Third party ownerships (or leased CHP equipment), such as those
procured under Power Purchase Agreements, are generally permitted with certain
provisions such as the following: (1) binding agreement (or lease) between the customer
and third party with a term of at least five (5) years, (2) host site has assigned payment
of the CHP incentive to the third party owner and (3) only permanently installed
equipment is eligible for incentives.
CHP systems must achieve annual system efficiency—generally 60 to 65% based
on total energy input (HHV) and total utilized energy output. Mechanically developed
energy and electricity generated from the thermal energy output of the system may be
included in the efficiency evaluation.
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8.6 M&V REPORTING
Measurement and verification reporting requirements generally fall under two
categories: performance and reliability.
Detailed system performance data should be automatically collected at regular
intervals (e.g., every 15 min or hourly) by a data logger or control system. The required
data include generator power output, fuel input, facility power use, and useful heat
recovery rates.
Generally, operational reliability data is collected as it occurs and is required to be
reported monthly. These data include information on any scheduled or unscheduled
equipment outage, including the time and date of the outage, its cause, and the resolution.
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CHAPTER 9
CARBON REDUCTION, ENVIRONMENTAL BENEFITS,
AND EMISSION CONTROLS41
To calculate the fuel use or CO2 emissions avoided by a CHP system, both the
electrical and thermal outputs of the CHP system must be accounted for. The thermal
output displaces the fuel normally consumed and emissions from on-site thermal
generation in a boiler or other combustion equipment, and the power output displaces
the fuel consumed and emissions from grid-connected power plants. To quantify the
fuel or CO2 emissions savings of a CHP system, the fuel use or emissions released from
the CHP system must be subtracted from the fuel use or emissions that would normally
occur without the CHP system (i.e., using conventional separate heat and power). The
following equation shows this relationship for fuel savings:
where
FS = (FT + FG) – FCHP
9-1
FS = Total fuel savings
FT = Fuel use from avoided on-site thermal production
FG = Fuel use from avoided purchased grid electricity
FCHP = Fuel use by the CHP system
CO2 emissions savings are expressed by
CS = (CT + CG) – CCHP
9-2
where
CS = Total CO2 savings
CT = CO2 emissions from avoided on-site thermal production
CG = CO2 emissions from avoided purchased grid electricity
CCHP = CO2 emissions from the CHP system
Fuel and CO2 Emissions Savings Calculation Protocol for Combined Heat and Power (CHP)
Systems, ASHRAE 2009
41
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9.1 CHP FUEL USE AND CO2 EMISSIONS CALCULATIONS
The energy content of the fuel consumed by the CHP system can be measured
directly as the higher heating value of the fuel consumed (typically in million Btu
[gigajoules]) or by the fuel volume or weight, which can then be converted to the
energy value through fuel-specific energy factors or heating values. Fuel consumption
can also be estimated based on the electric or power output of the CHP system and the
net generation efficiency. The CO2 emissions from the CHP system are a function of
the type and amount of fuel consumed. CO2 emissions rates are commonly presented
as pounds of emissions per million Btu (kilograms per gigajoule) of fuel input. Table
9-1 shows energy and CO2 average emissions factors for common fuels.
The fuel use and CO2 emissions avoided at the site result from the displacement by
the CHP system of some or all of the fuel otherwise combusted in boilers or other thermal
equipment to provide required heating or cooling services. The amount of energy and
emissions represented by this avoided fuel can be calculated from the thermal output of
the CHP system and the efficiency characteristics of the avoided thermal equipment.
The amount of avoided fuel use can be estimated by measuring the annual useful
thermal output of the CHP system and applying an efficiency factor representative of the
avoided equipment (e.g., 80% efficiency for a natural gas boiler). Once the fuel used to
produce the equivalent amount of avoided thermal energy is estimated, the avoided
energy and CO2 emissions can be calculated through the fuel-specific factors that are
listed in Table 9-1. The following are relevant equations for calculating avoided thermal
fuel use and CO2 emissions:
FT = CHPT/ŋT
9-3
where
FT = Avoided thermal fuel savings, Btu (J)
CHPT = CHP system useful thermal output, Btu (J)
ŋT = Avoided thermal equipment efficiency, %
and
Table 9-1. Fuel-Specific Energy and CO2 Emission Factors
CO2 Emissions
Fuel Type
Energy Factor
Factor
(lb/106 Btu)
kg/GJ
Natural Gas
1030 Btu/ft3
38.3 MJ/m3
117
50.3
Distillate Oil
138,000 Btu/gal
38.6 MJ/L
160
68.8
Residual Oil
150,000 Btu/gal
42 MJ/L
160
68.8
10,150 Btu/lb
21.75 MJ/kg
205
88.1
7500 Btu/lb
16.1 MJ/kg
0
0.0
Coal
Woody Biomass
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CARBON REDUCTION, ENVIRONMENTAL BENEFITS, AND EMISSION CONTROLS
CT = FT × EFF
9-4
CT = Avoided thermal CO2 emissions savings, lb (kg) CO2
FT = Avoided thermal fuel savings, Btu (GJ)
EFF = Fuel-specific emission factor, lb/106 Btu (kg/GJ) CO2
To estimate the fuel and emissions reduction from avoided electricity purchases,
one must first determine the amount of grid generation avoided by the generation of
power from the CHP system. When power produced from a CHP system is consumed
on site, close to or at the point of generation, the overall grid savings also includes the
avoided delivery losses for power that occur along the transmission and distribution
systems. A portion of the electricity that is transmitted over power lines is lost because
of resistance and other forms of dissipation, commonly referred to as ‘transmission
losses’. The amount of electricity actually delivered to consumers is, therefore, less
than the amount generated at central station power plants, usually by about 7 to 10%.
Consequently, avoiding 1 MWh of purchased electricity on site means that more than
1 MWh of electricity no longer needs to be generated at the central station power plant.
To estimate fuel and emissions savings from displaced central station generation, the
electricity displaced on site must be converted to a corresponding amount of avoided
grid generation. This can be calculated using the following equation:
EG = CHPE / (1-LT&D)
9-5
where
EG = Grid generation avoided, kWh
CHPE = CHP system electricity output, kWh
LT&D = Transmission and Distribution Losses, %
Equation 9-5 determines the amount of electricity generation avoided at central
station plants because of the power produced by the CHP system. To calculate the
displaced fuel and CO2 emissions this avoided generation represents, one must know
the heat rate in Btu (J) per kilowatt-hour (or fuel efficiency in percentage) and the CO2
emissions factor in pounds (kilograms) per megawatt-hour of the displaced central
station generation resources.
Published data on the U.S. grid electricity heat rates and emissions factors are
available from a number of sources. A prime source is the EPA Emission & Generation
Resource Integrated Database (eGRID). Developed by the State and Local Branch of
the EPA Climate Protection Partnership Division, eGRID is considered the preeminent
source of data on the environmental attributes of virtually all of the electric power
generated in the United States, linking air emissions to electricity generated. The most
recent version, eGRID2007, includes operational data from 2005. eGRID provides fuel
use, resource mix, and emissions data for power generation at various levels of
aggregation, including plant, electric generating company (EGC), state, power control
area (PCA), eGRID subregion, NERC region, and the U.S. total. Development of the
aggregate data begins with the plant level data. In aggregating to any one of these
aggregation levels, the values of the emissions, net generation, heat input, and nameplate
capacity of specific plants are attributed to that entity.
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CHP facilities should use geographic factors based on their specific location to
accurately estimate the fuel use and emissions rate of electric generators supplying
power to the grid in their area. It is highly recommended to use the heat rate and
emissions factors corresponding to a facility’s eGRID subregion in the savings
calculations. An EGC may purchase power and/or export its power to other EGCs; state
electricity generation may not serve all of the consumption within the state. The eGRID
subregion emissions and resource mix (based on generation, not consumption)
uniformly attribute power in a specific region of the country and minimize these issues.
Using the eGRID subregion emission factors is the recommended approach by the
EPA Climate Leaders program. The eGRID subregions are identified and defined by
EPA using the NERC regions and PCAs as a guide. An eGRID subregion is often, but
not always, equivalent to an Integrated Planning Model (IPM) subregion. The 26
eGRID sub regions in eGRID2007 are subsets of the NERC regions (see Figure 9-1).
The associated PCA determines the eGRID subregion, which is defined as a subset of
the NERC region and is composed of entire PCAs, with the exception of PJM
Interconnection and New York Independent System Operator PCAs (each is associated
with three eGRID subregions). Each eGRID subregion consists of one or a portion of
a power control area. Subregions generally represent sections of the grid that have
similar emissions and resource mix characteristics. Subregions may also be partially
isolated by transmission constraints.
The total fuel use and CO2 emissions represented by avoided central station power
are calculated through the following equations:
FG = EG * HRG
9-6
where
FG = Fuel use from avoided purchased grid electricity, Btu (J)
EG = Total grid generation avoided, kWh
HRG = Central station heat rate, Btu/kWh (J/kWh)
and
CG = EG * EFG
9-7
where
CG = CO2 emissions from avoided purchased grid electricity, lb (kg)
EG = Total grid generation avoided, kWh
EFG = Central station emission factor, lb/kWh (kg/kWh) CO2
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CARBON REDUCTION, ENVIRONMENTAL BENEFITS, AND EMISSION CONTROLS
Figure 9-1. eGRID Subregional Map
A key factor in estimating the energy and CO2 emissions savings for CHP is
determining the nature of the avoided central station generation. Should the calculation
of the displaced energy and CO2 emissions be based on the all-generation average of the
region the facility is located in, the all-fossil average, the average for some specific fuel
type, an estimate of marginal generation, or a projection of future installed generation?
eGRID and the other data sources typically include a variety of regional heat rate
and emissions data based on fuel type (e.g., coal, oil, and natural gas), all fossil fuels
(a weighted mix of fuels), and all generation sources (including nuclear and renewable
generation). Currently, there is no consensus on the baseline to use for displaced power
calculations, and different entities base their estimates on different comparisons. The
discussion provides several alternatives.
Demand for electricity varies widely over the year, and different kinds of generating
equipment are used to meet the varying load as it occurs. A common way of looking at
this is with a load duration curve. The load duration curve shows the electric demand
in MW for a region for each of the 8760 hours in the year. The hourly values are sorted
from highest to lowest.
Figure 9-2 shows the load duration curve for the central midwestern United States
(the old ECAR NERC region) for a recent year. The shape of the curve is typical of
electric load duration curves. The vertical axis shows demand in megawatts, and the
horizontal axis shows the hours of the year. The chart shows that the highest hourly
electric demand was 93,500 MW, most likely on a hot summer day. The demand for the
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Figure 9-2. Load Duration Curve
next highest hour was about 93,000 MW, possibly on a different day. The minimum
demand was 23,300 MW, perhaps in the middle of a temperate spring night. Every hour
of the year had at least this much demand. The next highest hour had a demand of
35,000 MW. The demand was at least this much for all except one hour of the year.
The area under the curve is the total generation, about 524 million MWh. The total
generation for the 23,300 MW base-demand that exists every hour of the year is 40% of
the total generation (area under the curve). The minimum demand for all but the last two
hours of the year is 40,000 MW, and the generation at that level for all but one hour of
the year comprises 66% of the total generation. Including the units that operate for 5600
h and greater per year account for 90% of the total generation. In contrast, the peak
10,000 MW of capacity operates for 80 h or less per year and accounts for only 0.075%
of generation. The peak 20,000 MW operates less than 700 h per year and accounts for
only 0.7% of generation.
This varying electric load is met with a large number of different types and sizes of
generating units. Figure 9-3 shows a typical generating mix. In a competitive electric
market, the units are dispatched based on their variable cost: the cost of fuel, consumable
items, and operation and maintenance costs directly related to production.
Peaking units may run only tens to hundreds of hours per year, so a high capital
cost is not supportable. On the other hand, high efficiency is not critical, because these
plants only run when there is no other source of capacity and electricity prices are very
high. Simple-cycle gas turbines are the classic peaking generator, though reciprocating
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Figure 9-3. Basic Dispatch Mix
engines and standby oil and gas steam plants are used for peaking in some parts of the
United States.
Between the peak and the base load, various generating assets are used to meet
demand. In most regions, these are cycling coal, oil, and gas steam units. Large hydro
generators can also fit in this regime. Developers of gas combined-cycle plants would
like them to run 5000 h or more per year, in the base- to low-intermediate-load ranges.
Depending on the cost of gas and other factors, large hydro generators may run in the
middle-intermediate range.
The CO2 emissions from power generation are the product of the megawatt-hours
of generation of each part of the mix times the emission rate in lbs (kg) CO2 per
megawatt-hour. Multiplying each unit of generation under the load curve times the
associated emission factor would derive an emissions curve that would look very
similar in shape to the load curve. The nuclear component would drop out. The coal
component would be accentuated because of higher emission rates. Note that, even at
peak hours, the majority of emissions are from the base-load units. Most CHP systems
are baseload. For simplicity, assume that a CHP facility operates for the entire year
except for a two-week maintenance outage; the generator will run for 8400 h at its full
load. This is a “must run” unit. The system will run for these hours independent of what
the rest of the central generating system does.
This case is shown on the load duration curve (Figure 9-4) by inserting the
appropriate amount of capacity at the 8400 h level. The CHP “must-run” generation
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means that some other generation is not needed in each hour that it runs. Compared to
the base case, the addition of the CHP unit displaces an equal amount of generation at
the top of each hour that it runs, essentially taking a “slice” off the top of the load curve
for the hours that the unit runs. The CHP system is displacing power from the last unit
of generation in each of these hours. Depending on the hour, that unit could be a cycling
coal, oil, or gas steam unit, a combined cycle unit, a central station peaking turbine, or
a reciprocating-engine unit.
The displaced fuel consumption and CO2 emissions are the product of the displaced
generation times the specific heat rate and emission rate of each central station unit
avoided. Although the heat rates and emission rates vary for each of these units, the
aggregate rates for the displaced generation is going to be very close to the average
heat rate and CO2 emissions rate for all fossil units in the region.
This graphical analysis suggests that, short of a detailed dispatch analysis, the allfossil average heat rate and CO2 emission rate are reasonable estimates for the calculation
of avoided fuel and emissions.
In summary, to calculate the fuel use and CO2 emissions impacts of a CHP system,
both outputs of the CHP system must be accounted for. The thermal output of the CHP
system displaces the fuel normally consumed in and emissions emitted from on-site
thermal generation in a boiler or other equipment, and the power output displaces the
fuel consumed and emissions from grid-connected power plants. To quantify the fuel
Figure 9-4. Dispatch Effect of Base-Load CHP
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CARBON REDUCTION, ENVIRONMENTAL BENEFITS, AND EMISSION CONTROLS
or CO2 emissions savings of a CHP system, the fuel use of or emissions released from
the CHP system must be subtracted from the fuel use or emissions that would normally
occur without the system (i.e., using conventional separate heat and power).
A key factor in estimating the energy and CO2 emissions savings for CHP is
determining the nature of the avoided central station generation.
9.1.1 U.S. EPA CHP Emissions Calculator
The Combined Heat and Power (CHP) Emissions Calculator is a Microsoft® Excel®
spreadsheet-based tool that compares the anticipated emissions from a CHP system to
the emissions from systems using separate heat and power (SHP).
A user can select from a large number of different separate heat and power system
profiles, compare them to a CHP system (characterized by the user), and estimate the
carbon, CO2, SO2, and NOX emissions from both systems and the corresponding
emissions reductions achieved by the CHP system. The CHP Emissions Calculator is
intended to help CHP end users and other interested parties calculate the emissions
attributable to their CHP projects. In addition to estimating emission reductions, the
CHP Emissions Calculator presents the carbon equivalency of these emissions
reductions in terms of number of cars removed from the road. The results screen from
the calculator is shown in Figure 9-5.
Figure 9-5. Results Screen from EPA CHP Emissions Calculator
(Note: this figure is from the EPA Emissions Calculator and is only available in I-P units)
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The CHP Emissions Calculator is designed for users with at least a moderate
understanding of CHP technology and its terminology; therefore, a glossary of the
terms that appear in the Emissions Calculator is not provided. The calculator can be
found at http://www.epa.go/chp/basic/calculator.html.
Examining publicly available emissions calculators, the U.S. EPA Emissions
Calculator provides the best results when examining the discrete impact of comparing
CHP systems to the grid.
9.1.2 Campus Carbon Calculator/CarbonMAP
The Campus Carbon Calculator (CCC) is an Excel-based tool developed by Clean
Air-Cool Planet and now offered by University of New Hampshire Sustainability
Institute. There is also a web-based version of this tool called CarbonMAP (Carbon
Management and Analysis Platform). Both are designed to facilitate three tasks:
1. Conducting a Greenhouse Gas Emissions Inventory: Collecting, analyzing,
and presenting data on the emissions of greenhouse gases attributable to the
existence and operations of an institution. This first step provides an essential
foundation for focused, effective collaboration on the issue of climate change
at a college or university, and is the basis for institutional action.
2. Projecting Emissions into the Future: Projecting the university’s “business
as usual” and alternate scenario emissions trajectories provides context for
choosing emission reduction goals and the projects needed to meet those goals.
3. Evaluating a Portfolio of Carbon Reduction Projects: Developing a
portfolio of proposed carbon reduction projects to create an effective climate
plan to address the specific emissions identified in the inventory of interest.
The Calculator includes all six greenhouse gases specified by the Kyoto Protocol
(CO2, CH4, N2O, HFC and PFC, and SF6) and enables calculated and projected emissions
for the years 1990-2060, with charts and graphs illustrating changes and trends in an
institution’s emissions over time. The spreadsheets were originally based on the
workbooks provided by the Intergovernmental Panel on Climate Change (IPCC, www.
ipcc.ch) for national-level inventories, and incorporate data from the Fourth Assessment
Report of the IPCC. The CCC has adapted this IPCC data for use at institutions such as
a college or university, but follows virtually the same protocols. The CCC uses standard
methodologies codified by the GHG Protocol Initiative and used by corporations, the
state of California, The Climate Registry, and other entities to account for greenhouse
gas (GHG) emissions. These methodologies are currently the most accurate and widely
accepted among policy makers. Inventories produced by the CCC are compatible with
current standards used to craft forthcoming cap-and-trade policy. The CCC is also a
preferred tool for the ACUPCC (American College and University President’s Climate
Commitment). The CCC assesses campus level emissions and decisions based on actual
annualized energy consumption. The Calculator’s logic diagram is shown in Figure 9-6.
Access to both the Calculator and CarbonMAP is available at www.campuscarbon.com.
9.1.3 World Resources Institute Allocation of GHG Emissions from CHP Plant
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CARBON REDUCTION, ENVIRONMENTAL BENEFITS, AND EMISSION CONTROLS
Figure 9-6. Logic Diagram from Clean Air Cool Planet Campus Carbon Calculator
This tool intends to facilitate the allocation of GHG emissions attributable to the
purchase or sale of energy from a CHP plant (Figure 9-7). This is a cross-sector tool
that should be applied by all companies whose operations involve the purchase or sale
of energy from a CHP plant.
The purpose of this tool is to facilitate this allocation of GHG emissions to the
separate energy streams of the CHP plant by determining the separate GHG emission
factors associated with each stream. To do this, it is first necessary to determine the
total direct emissions emitted by the CHP plant. Note that this tool does not facilitate
this calculation. Total direct emissions of the CHP plant can be determined by using the
revised GHG Protocol® calculation tool for Direct Emissions from Stationary
Combustion, available on the GHG Protocol website, www.ghgprotocol.org, or using
the results from EPA CHP Emissions Calculator.
Once the emission shares from a CHP plant are allocated to each energy stream,
the indirect emissions associated with the purchase or sale of electricity, heat, or steam
from a CHP facility should be accounted for in a GHG inventory the same way as
indirect emissions associated with the purchase or sale of electricity, heat, or steam
from a non-CHP plant:
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• Emissions associated with electricity, heat, or steam purchased for consumption
should be categorized as scope 2 indirect emissions.
• Emissions associated with purchased electricity, heat, or steam for resale to
end-users should be categorized as scope 3 indirect emissions. According to GHG
Protocol standards, it is optional, but strongly encouraged, to account for and report
these emissions.
• Emissions associated with the sale of own-generated electricity, heat, or steam to
another entity are not deducted/netted from scope 1 direct emissions, and may be
reported in optional information.
The calculator can be found at www.ghgprotocol.org/calculation-tools/service-sector.
9.2 ENVIRONMENTAL EMISSIONS FROM CHP
Calculating full-fuel-cycle (FFC) emissions42 from fuel input into a CHP system is
relatively straightforward. Calculating FFC emissions saved by thermal energy recovered
from the CHP generator and used by the building (e.g., for heating, hot water, chilled
water) requires knowledge of the thermal system, the served load,and the technology
that was not needed as a result of the CHP system (i.e., the technology displaced by the
recovered thermal energy).
Using the EPA Model (10.1.1), the following design case study describes a CHP
system using a lean-burn reciprocating engine providing 328 kW of power and thermal
energy to drive an 80 ton (281 kWTH) single-effect absorption chiller. This case study is
a typical screening analysis example where it is necessary to project potential CHP fuel
use and CO2, SO2, and NOx emissions and potential savings when compared to a
conventional approach using electricity supplied by the grid. A data center example was
chosen because it is a high-energy-density facility where electric computing and thermal
cooling loads directly correlate, making this market niche a potential CHP application.
Figure 9-7 Allocation of GHG Emissions from CHP Plant Data Output Screen
(Note: this figure is from the 9.1.3 WRI’s Allocation of GHG Emissions and is only available
in I-P units)
Full-fuel-cycle emissions correspond to resource extraction, fuel production, delivery, and
CHP system exhaust. FFC includes combustion, fugitive, and spillage emissions, as well as
water discharges. Emissions from engine and CHP plant fabrication are not included.
42
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The data center electric load profile is considered constant for this facility, and the
thermal load is internally generated by the data servers. The cooling required by the data
center is also constant at 80 tons based on server cooling requirements. The baseline
electric cooling system consisted of an 80 ton water-cooled screw chiller operating at
0.8 kW/ton (0.227 kWe/kWTH) at the full-load design point. Table 9-2 provides the CHP
system performance characteristics assuming 8333 h of annual operation to allow for
scheduled maintenance. Scheduled maintenance will use the grid as backup.
Table 9-3 provides the performance and emissions characteristics of the lean-burn
reciprocating engine operating on natural gas.
The model consists of 31 questions necessary to define the CHP plant being
assessed (Table 9-4), the on-site production of electricity and thermal energy from the
CHP plant, and the displaced emissions from off-site generation of electricity, including
transmission losses.
Table 9-4 presents the necessary inputs to the CHP-EC model, based on the case
study. The remainder of this example examines the various eGRID blends of generation,
national, state, eGRID region, and subregion results used to estimate the fuel use and
emissions of the displaced electric power generation.
The model provided the following performance results (Figure 9-8) for the case
study CHP plant based on the inputs in Table 9-4 which are compared to the model
results in Table 9-5.
Table 9-2. CHP Plant Performance Characteristics
Fuel Used
Power Generated
106 Btu
HHV
GJe
HHV
kWh
Jan
2432
2565
232,137
792
Feb
2196
2317
209,672
Mar
2432
2565
Apr
2353
May
Exhaust
Recovered
Efficiency
at 0.70
Power HR
GJ
COP
HHV, HHV,
HHV
106 Btu
%
%
Tons
106
Btu
GJ
836
56,619
679
717
971
1024
32.6
39.9
715
755
51,140
614
647
877
925
32.6
39.9
232,137
792
836
56,619
679
717
971
1024
32.6
39.9
2483
224,649
767
809
54,792
658
694
939
991
32.6
39.9
2432
2565
232,137
792
836
56,619
679
717
971
1024
32.6
39.9
Jun
2353
2483
224,649
767
809
54,792
658
694
939
991
32.6
39.9
Jul
2432
2565
232,137
792
836
56,619
679
717
971
1024
32.6
39.9
Aug
2432
2565
232,137
792
836
56,619
679
717
971
1024
32.6
39.9
Sep
2353
2483
224,649
767
809
54,792
658
694
939
991
32.6
39.9
Oct
2432
2565
232,137
792
836
56,619
679
717
971
1024
32.6
39.9
Nov
2353
2483
224,649
767
809
54,792
658
694
939
991
32.6
39.9
Dec
2432
2565
232,137
792
836
56,619
679
717
971
1024
32.6
39.9
Total
28,630
8410
32.6
39.9
Month
30 206 2,733,224
106 Btu GJ
HHV HHV
Refrigeration
Produced
9326
9839 666,640 8000 8440 11,428
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9.3 ENVIRONMENTAL BENEFITS OF CHP
The environmental benefits are derived from displacing fuel used to create thermal
energy and displacing electricity from the grid. Displacing fuel used to generate and
deliver electricity requires an understanding of the operation of the electric grid, likely
power plant(s) that would provide power to the building site where the proposed CHP
plant is to be located, and the type of power plant whose electricity would be displaced
by the electricity generated by the CHP plant (e.g., nuclear, baseload coal, hydro,
combined-cycle, cycling coal, oil and gas, peaking plants). (See section 9.1)
Continuing with the case study developed in section 9.2, the model allows emission
factors for all generation, fossil, coal, oil, or gas generation as the emission factor for
the displaced generation. The model also includes seven generic generator types,
including various coal boiler and combined-cycle units that cover the range from older
coal boilers with low-NOx burners to the newest natural gas combined-cycle units with
selective catalytic reduction (SCR).
Figure 9-9 presents annual emissions data, including a blend of all generation; all
fossil generation; and coal-, oil-, or gas-fueled generators. Considering this case study’s
CHP plant is designed to run base-loaded, like most profitable CHP systems, it is a
reasonable assumption that base-load electric power would be displaced. Therefore,
nuclear, hydro, and a blend of fossil-fired power plants could be displaced. Nuclear
power plants are designed as large power generators for economic reasons and take
many hours, if not days, to achieve a steady state power output. Existing nuclear and
hydropower plants are high-capital-cost and low-variable-cost producers whose capital
costs have been fully amortized, yielding low-cost electricity with no direct carbon
emissions. Therefore, it is unrealistic to believe that nuclear or hydropower would ever
be displaced, for a multitude of reasons, leaving a fossil blend as the logical choice.
(see Section 9.1 load duration curves for electricity production) Therefore, CHP
displacing base-load power is not a reasonable assumption after all is considered.
Table 9-3. Engine Performance and Emissions
Lean-Burn Natural Gas Engine
Annual Performance
Brake horsepower
458
3,818,355
kW
328
2,733,224
Heat Rate, 10 Btu/h (GJ) LHV
3.12
27,799 (29 330)
Heat Rate, 106 Btu/h HHV
3.47
28,630
Heat Rate, GJ/h HHV
3.66
30 206
6
Emissions
lb
kg
tons
CO2 emissions lb/10 Btu (kg/GJ)
117 (50.3)
3,349,652
7,369,234
1,675
NOx g/bhp·h (g/kWh)
0.6 (0.82)
5040
2291
2.52
CO g/bhp·h (g/kWh)
2.5 (3.4)
15,033
6833
7.52
NMHC g/bhp·h (g/kWh)
0.43 (0.58)
26
12
0.013
NMNEHC g/bhp·h (g/kWh)
0.25 (0.34)
16
7.2
0.008
PM10 g/bhp·h (g/kWh)
0.01 (0.013)
1
0.3
0.0003
6
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Table 9-4. US EPA CHP Emissions Calculator Data Entry Questions
Relevant Question (Note: some
Data Entered in Model
Source of Data and Implications
Reciprocating engine,
lean burn
Driven by size requirement, emissions,
efficiency and thermal to electric (T/E) ratio.
328 kW
Driven by case study load
1
Reliability and cost requirements
4. CHP: How many hours per year
does the CHP system operate?
8333
The design is for fulltime operation.
The case study provides a simplified model.
Note: 427 h annually have been allocated
for planned maintenance.
5. CHP: Does the system provide
heating or cooling or both?
Cooling only
A function of the application
Natural gas
A function of the application
questions are eliminated because
of the particular CHP plant.)
1. CHP: Type of system
2. CHP: Electricity generating
capacity (per unit)
3. CHP: How many identical units
(i.e., engines) does this system have?
6. CHP: Fuel
117 lb/10 Btu
6
8. CHP: What is the CO2 Emission
Rate for this Fuel?
9. CHP: What is the heat content of
this fuel? (Enter a value in only ONE
of the boxes)
(50.3 kg/GJ)
Default value for natural gas; pounds
per million Btu of energy input
1,020 Btu/ft3
(37 978 kJ/m3)
Default; could vary somewhat by natural gas
distribution company and location
12. CHP: Electric efficiency
32.4%
Engine manufacturer
13. CHP: Base power to heat ratio
0.8141
Basis is 1.4 million Btu/h thermal output used
as input to the absorption chiller. 403 kWth
divided by power output 328 kW = 0.814
0.6 g/hp·h
(0.82 g/kWh)
Engine manufacturer
Yes
For comparative
20. Cooling: type of absorption
chiller used?
Typical single-effect
absorption chiller, COP=0.7
The default COP equals the manufacturer’s
rating for this application
21. Cooling: What is the cooling
capacity of the system?
80 tons
Driven by load
22. Typical single-effect absorption
chiller, COP=0.7
0.80 kW/ton
(0.227 kWe/kWTH) (COP=4.4)
Average new rotary screw
compressor, water-cooled,
≥150 tons capacity
Closest fit electric alternative
29. Displaced electricity: generation
profile
eGRID average fossil 2005
See Displaced Power Generation section (9.1)
30. Displaced electricity: select U.S.
average or individual state/NERC
region for eGRID data
RFCW West
See eGRID Subregions section (9.1)
5.82%
Program default value. Actual values could be
higher or lower and impact results up to 5%
14. CHP: NOx emission rate
19. Cooling: Does the CHP provide
cooling?
31. Displaced electricity:
transmission losses
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Figure 9-8. EPA Model Results
(Note: this figure is from the EPA Emissions Calculator and is only available in I-P units)
A second matter of significant importance is to determine the generator supply mix
that actually delivers electricity to the site. Many smaller countries solve this problem
by using national averages. Figure 9-10 demonstrates the problem with using national
averages by showing results comparing the CHP plant in terms of percent of annual
savings of CO2, NOx, and SO2 emissions, as well as fuel consumption to the national
average electric grid and various states. When comparing the CHP plant emissions to
the national average, the result is a reduction in CO2/carbon emissions by 48%, NOx
emissions by 47%, SO2 emissions by 100%, and fuel consumption by 18%. However,
when compared to the State of California averages, the CHP plant increases local NOx
emissions 294%, while reducing SO2 emissions by 98%, CO2/carbon emissions by
11%, and fuel consumption by 6%. Using the State of South Dakota values, the modeled
CHP plant reduces local NOx emissions 85%, SO2 emissions by 100%, CO2/carbon by
emissions 59%, and fuel consumption by 31%.
Figure 9-10 provides a compelling case to use state-based emissions for power
generation versus the national average data. California data shows 76% less CO2
savings versus the national grid, whereas South Dakota shows a 23% increase in carbon
savings. This is due to the widespread use of natural-gas-powered generation in
California versus coal-powered generation in South Dakota. However, the data available
on a state basis generally do not include imported electricity, so state-level data are not
always reflective of the real emissions impact of displaced electricity.
To estimate the environmental attributes of the electricity consumed in a particular
facility, eGRID divided the electric grid into 27 subregions (Figure 9-1). These subregions
represent a portion of the U.S. power grid that is contained within a single NERC region,
and generally represent sections of the power grid that have similar emissions and
resource mix characteristics, and may be partially isolated by transmission constraints.
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Table 9-5. Emissions Results
Calculator
Table 10.3-2
Variance, %
28,792 (30 377)
28,630 (30 206)
0.06
CO2 tons/yr
(Mg/yr)
1683 (1527)
1675 (1520)
0.05
NOx tons/yr
(Mg/yr)
2.42 (2.2)
2.52 (2.29)
0.04
SO2 tons/yr
(Mg/yr)
0.01
0.0
—
Fuel 106 Btu (GJ)
Figure 9-11 presents the CHP system savings versus the grid. It shows agreement
between Colorado power generation data and eGRID subregion, indicating in-state
generation closely follows the eGRID subregions emissions and fuel savings.
Washington state and the NWPP closely track for CO2 and fuel savings, with increasing
NOx deviation likely caused by imported power. The state of California and the CAMX
subregion data results track in the same general direction with only a significant
NOx deviation.
The composition of non-state-level aggregation levels may not be geographically
obvious. The deviation between the state of California and CAMX exists largely because
the Intermountain Power Project plant in the state of Utah is operated by and for the City
of Los Angeles, which is connected to CAMX subregion through the Los Angeles utility.
The bottom line for this example is that the CHP plant conserves energy and reduces
CO2 and SO2 emissions versus the all fossil average grid throughout the country. The
CHP plant also reduces NOx emissions in most states, except for certain states, such as
California and Colorado. In this example, to generate NOx savings, the lean-burn engine
would require emissions aftertreatment.
9.4 EMISSION CONTROL TECHNOLOGIES FOR CHP
9.4.1 Reciprocating Internal Combustion Engines43
The primary pollutants from reciprocating internal combustion engines are oxides
of nitrogen (NOx), carbon monoxide (CO), and volatile organic compounds (VOCs)
(unburned, nonmethane hydrocarbons). Other pollutants, such as oxides of sulfur (SOx)
and particulate matter (PM), are primarily dependent on the fuel used (Table 9-6). The
sulfur content of the fuel determines emissions of sulfur compounds, primarily SO2.
Engines operating on natural gas or desulfurized distillate oil emit insignificant levels
of SOx. In general, SOx emissions are an issue only in large, slow-speed diesels firing
heavy oils. Particulate matter (PM) can be an important pollutant for engines using
liquid fuels. Ash and metallic additives in the fuel contribute to PM in the exhaust.
“Technology Characterization: Reciprocating Engines”, U.S. Environmental Protection Agency,
ICF Company, 2008.
43
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Figure 9-9. NOx, SO2, and CO2 Emissions from Grid and CHP System
Oxides of nitrogen (NOx). NOx emissions are usually the primary concern with
natural gas engines and are a mixture of (mostly) NO and NO2 in variable composition.
In measurement, NOx is reported as parts per million by volume in which both species
count equally (e.g., ppmv at 15% O2, dry). Other common units for reporting NOx in
reciprocating engines are grams per horsepower-hour (g/hp·h) and g/kWh or as an
output rate such as pounds per hour (grams per hour). Among natural gas engine
options, lean-burn natural gas engines produce the lowest NOx emissions directly from
the engine. However, rich burn engines can more effectively make use of three-way
catalysts to produce very low emissions. If lean-burn engines must meet extremely low
emissions levels, selective catalytic reduction (SCR) must be added.
Three mechanisms form NOx: thermal NOx, fuel-bound NOx and prompt NOx. The
predominant NOx formation mechanism associated with reciprocating engines is
thermal NOx. Thermal NOx is the fixation of atmospheric oxygen and nitrogen, which
occurs at high combustion temperatures. Flame temperature and residence time are the
primary variables that affect thermal NOx levels. The rate of thermal NOx formation
increases rapidly with flame temperature. Fuel-bound NOx forms when the fuel contains
nitrogen as part of the hydrocarbon structure. Natural gas has negligible chemically
bound fuel nitrogen. Fuel-bound NOx can be at significant levels with liquid fuels.
Prompt NOx is attributed to the reaction of atmospheric nitrogen, N2, with radicals such
as C, CH, and CH2 fragments derived from fuel. Occurring in the earliest stage of
combustion, this results in the formation of fixed species of nitrogen, such as NH
(nitrogen monohydride), HCN (hydrogen cyanide), H2CN (dihydrogen cyanide), and
CN (cyano radical), which can oxidize to NO.
The control of peak flame temperature through lean-burn conditions has been the
primary combustion approach to limiting NOx formation in gas engines.
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Figure 9-10. Percent of Emissions Reduction Using Case Study CHP System
For any engine, there are generally trade-offs between low NOx emissions and high
efficiency. There are also trade-offs between low NOx emissions and emissions of the
products of incomplete combustion (CO and unburned hydrocarbons). There are three
main approaches to these trade-offs that come into play, depending on regulations and
economics. One approach is to control for lowest NOx, accepting a fuel efficiency
penalty and possibly higher CO and hydrocarbon emissions. A second option is finding
an optimal balance between emissions and efficiency. A third option is to design for
highest efficiency and use postcombustion exhaust treatment.
Carbon Monoxide (CO). CO and VOCs both result from incomplete combustion.
CO emissions result when there is inadequate oxygen or insufficient residence time at
high temperature. Cooling at the combustion chamber walls and reaction quenching in
the exhaust process also contribute to incomplete combustion and increased CO
emissions. Excessively lean conditions can lead to incomplete and unstable combustion
and high CO levels.
Unburned Hydrocarbons. Volatile hydrocarbons, also called volatile organic
compounds (VOCs), can encompass a wide range of compounds, some of which are
hazardous air pollutants. These compounds are discharged into the atmosphere when
some portion of the fuel remains unburned or partially burned. Some organics are
carried over as unreacted trace constituents of the fuel, while others may be pyrolysis
products of the heavier hydrocarbons in the gas. Volatile hydrocarbon emissions from
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Figure 9-11. Annual Percentage Emissions and Fuel Reduction, NERC WECC region and
Associated eGRID Subregions
reciprocating engines are normally reported as nonmethane hydrocarbons (NMHCs).
Methane is not a significant precursor to ozone creation and smog formation and is not
currently regulated, although it is significant with respect to greenhouse gas emissions.
Control of combustion temperature has been the principal focus of combustion
process control in gas engines. Combustion control requires tradeoffs; high temperatures
favor complete burn up of the fuel and low residual hydrocarbons and CO, but promote
NOx formation. Lean combustion dilutes the combustion process, reduces combustion
temperatures and NOx formation, and allows a higher compression ratio or peak firing
pressures, resulting in higher efficiency. However, if the mixture is too lean, misfiring
and incomplete combustion occurs, increasing CO and VOC emissions.
Lean burn engine technology was developed during the 1980s as a direct response
to the need for cleaner-burning gas engines. As discussed previously, thermal NOx
formation is a function of both flame temperature and residence time. The focus of
lean-burn developments was to lower combustion temperature in the cylinder using
lean fuel/air mixtures. Lean combustion decreases the fuel/air ratio in the zones where
NOx is produced so that peak flame temperature is less than the stoichiometric adiabatic
flame temperature, thereby suppressing thermal NOx formation. Most lean-burn
engines use turbocharging to supply excess air to the engine and produce the
homogeneous lean fuel-air mixtures. Lean-burn engines generally use 50 to 100%
excess air (above stoichiometric). The typical emissions rate for lean-burn natural gas
engines is between 0.5 to 2.0 g/bhp·h (0.68 to 2.7 g/kWh).
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CARBON REDUCTION, ENVIRONMENTAL BENEFITS, AND EMISSION CONTROLS
Table 9-6. Gas Engine Emissions Characteristics
Emissions
Characteristics
System 1*
System 2*
System 3
System 4
System 5
100
300
1000
3000
5000
28.4%
31.1%
35%
36%
39%
Rich
Rich
Lean
Lean
Lean
NOx, lb/MWh
0.1
0.5
1.49
1.52
1.24
NOx, kg/MWh
0.05
0.23
0.68
0.69
0.56
CO, lb/MWh
0.32
1.87
0.87
0.78
0.75
CO, kg/MWh
0.15
0.85
0.40
0.35
0.34
VOC, lb/MWh
0.1
0.47
0.38
0.34
0.22
VOC, kg/MWh
0.05
0.21
0.17
0.15
0.10
CO2, lb/MWh
1404
1284
1142
1110
1024
CO2, kg/MWh
638
584
519
505
465
Electricity
Capacity, kW
Electrical
Efficiency (HHV)
Engine
Combustion
* With available exhaust control options.
Figures represent typical engine generators.
Optimized lean-burn operation requires sophisticated engine controls to ensure
that combustion remains stable and NOx reduction is maximized while minimizing
emissions of CO and VOCs.
Combustion temperature can also be controlled to some extent in reciprocating
engines by one or more of the following techniques:
• Delaying combustion by retarding ignition or fuel injection
• Diluting the fuel-air mixture with exhaust gas recirculation (EGR), which
replaces some of the air and contains water vapor that has a relatively high heat
capacity and absorbs some of the heat of combustion
• Introducing liquid water by direct injection or by fuel oil emulsification;
evaporation of the water cools the fuel-air mixture charge
• Reducing the inlet air temperature with a heat exchanger after the turbocharger
or using inlet air humidification
• Modifying valve timing, compression ratio, turbocharging, and the combustion
chamber configuration
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The following catalytic exhaust gas treatment processes are applicable to various
types of reciprocating engines.
Three-Way Catalyst. The catalytic three-way conversion process (TWC) is the
basic automotive catalytic converter process that reduces concentrations of all three
major criteria pollutants: NOx, CO, and VOCs. The TWC is also called nonselective
catalytic reduction (NSCR). NOx and CO reductions are generally greater than 90%,
and VOCs are reduced approximately 80% in a properly controlled TWC system.
Because the conversions of NOx to N2 and CO and hydrocarbons to CO2 and H2O will
not take place in an atmosphere with excess oxygen (exhaust gas must contain less than
0.5% O2), TWCs are only effective with stoichiometric or rich-burning engines. Typical
“engine out” NOx emission rates for a rich burn engine are 10 to 15 g/bhp·h (13.6 to
20.4 g/kWh). NOx emissions with TWC control are as low as 0.15 g/bhp·h (0.20 g/kWh).
Stoichiometric and rich-burn engines have significantly lower efficiency than
lean-burn engines (higher carbon emissions), and only certain rich-burn engine sizes
(<1.5 MW) and high-speed engines are available. The TWC system also increases
maintenance costs by as much as 25% over an engine without aftertreatement. TWCs
are based on noble metal catalysts that are vulnerable to poisoning and masking, limiting
their use to engines operated with clean fuels (e.g., natural gas and unleaded gasoline).
In addition, the engines must use lubricants that do not generate catalyst poisoning
compounds and have low concentrations of heavy and base metal additives. Unburned
fuel, unburned lube oil, and particulate matter can also foul the catalyst.
Selective Catalytic Reduction (SCR). This technology selectively reduces NOx to
N2 in the presence of a reducing agent. NOx reductions of 80 to 90% are achievable
with SCR. Higher reductions are possible with the use of more catalysts or more
reducing agents, or both. The two agents used commercially are ammonia (NH3) in
anhydrous liquid form or aqueous solution and aqueous urea [CO)(NH2)2]. Urea
decomposes in the hot exhaust gas and SCR reactor, releasing ammonia. Approximately
0.9 to 1.0 moles of ammonia is required per mole of NOx at the SCR reactor inlet to
achieve an 80 to 90% NOx reduction.
SCR systems add a significant cost burden to the installation and maintenance
costs of an engine system, and can severely impact the economic feasibility of smaller
engine projects. SCR requires on-site storage of ammonia or urea, a hazardous
chemical. In addition, ammonia can “slip” through the process unreacted, contributing
to environmental health concerns.
Oxidation Catalysts. Oxidation catalysts generally are precious metal compounds
that promote oxidation of CO and hydrocarbons to CO2 and H2O in the presence of
excess O2. CO and nonmethane hydrocarbon analyzer (NMHC) conversion levels of 98
to 99% are achievable. Methane conversion may approach 60 to 70%. Oxidation
catalysts are now widely used with all types of engines, including diesel engines. They
are being used increasingly with lean-burn gas engines to reduce their relatively high
CO and hydrocarbon emissions.
Lean-NOx Catalysts. Lean-NOx catalysts use a hydrocarbon reductant (usually the
engine fuel) injected upstream of the catalyst to reduce NOx. While still under development,
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it appears that NOx reduction of 80% and reduction of both CO and NMHC emissions
by 60% may be possible. Long-term testing, however, has raised issues about sustained
performance of the catalysts. Current lean-NOx catalysts are prone to poisoning by
both lube oil and fuel sulfur. Both precious metal and base metal catalysts are highly
intolerant of sulfur. Fuel use can be significant with this technology; the high NOx
output of diesel engines would require approximately 3% of the engine fuel consumption
for the catalyst system.
9.4.2 Combustion Turbines44
The primary pollutants from combustion turbines are oxides of nitrogen (NOx),
carbon monoxide (CO), and volatile organic compounds (VOCs). Other pollutants,
such as oxides of sulfur (SOx) and particulate matter (PM), are primarily dependent on
the fuel used. The sulfur content of the fuel determines emissions of sulfur compounds,
primarily SO2. Gas turbines operating on desulfized natural gas or distillate oil emit
relatively insignificant levels of SOx. In general, SOx emissions are greater when heavy
oils are fired in the turbine. SOx control is, thus, a fuel-purchasing issue rather than a
gas turbine technology issue. Particulate matter is a marginally significant pollutant for
gas turbines using liquid fuels. Ash and metallic additives in the fuel may contribute to
PM in the exhaust.
Table 9-7 shows emissions characteristics of natural-gas-fueled combustion
turbines as a function of size.
Table 9-7. Natural Gas Combustion Turbine Emissions Characteristics
Emissions
Characteristics
System 1
System 2
System 3
System 4
System5
Electricity Capacity,
kW
1000
5000
10,000
25,000
40,000
Electrical Efficiency
(HHV)
21.90%
27.10%
29.00%
34.30%
37.00%
42
15
15
25
15
NOx, lb/MWh
2.43
0.66
0.65
0.9
0.5
NOx, kg/MWh
1.10
0.30
0.30
0.41
0.23
20
25
25
25
25
CO, lb/MWh
0.71
0.68
0.66
0.55
0.51
CO, kg/MWh
0.32
0.31
0.30
0.25
0.23
CO2, lb/MWh
1877
1440
1404
1163
1079
CO2, kg/MWh
853
655
638
529
490
NOx, ppm
CO, ppmv
Note: Estimates based on typical manufacturers’ guarantees using commercially available, dry,
low-NOx combustion technology.
Technology Characterization: Gas Turbines. U.S. Environmental Protection Agency, ICF
International Company. 2008.
44
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It is important to note that the gas turbine operating load has a significant effect on
the emissions levels of the primary pollutants of NOx, CO, and VOCs. Gas turbines
typically operate at high loads. Consequently, gas turbines are designed to achieve
maximum efficiency and optimum combustion conditions at high loads. Controlling all
pollutants simultaneously at all load conditions is difficult. At higher loads, higher NOx
emissions occur because of peak flame temperatures. At lower loads, lower thermal
efficiencies and more incomplete combustion occurs, resulting in higher emissions of
CO and VOCs.
The control of peak flame temperature through diluent (water or steam) injection or
by maintaining homogenous fuel-to-air ratios that keep local flame temperature below
the stoichiometric adiabatic temperature have been the traditional methods used to limit
NOx formation. In older, diffusion-flame combustion systems, fuel/air mixing and
combustion occurred simultaneously. This resulted in local fuel/air mixture chemical
concentrations that produced high local flame temperatures. These high temperature
“hot spots” are where most of the NOx emissions originate. Many new gas turbines
feature lean, premixed combustion systems. These systems, sometimes referred to as
dry, low-NOx (DLN) or dry, low-emissions (DLE), operate in a tightly controlled, lean,
(lower fuel-to-air ratio), premixed mode that maintains modest peak flame temperatures.
CO and VOCs both result from incomplete combustion. CO emissions result when
there is insufficient residence time at high temperature. In gas turbines, the failure to
achieve CO burnout may result from the quenching effects of dilution and combustor
wall cooling air. CO emissions are also heavily dependent on the operating load of the
turbine. For example, a gas turbine operating under low loads tends to have incomplete
combustion, which increases the formation of CO. CO is usually regulated to levels
below 50 ppm for both health and safety reasons. Achieving such low levels of CO
had not been a problem until manufacturers achieved low levels of NOx, because
the techniques used to engineer DLN combustors had a secondary effect of increasing
CO emissions.
VOCs can encompass a wide range of compounds, some of which are hazardous
air pollutants. These compounds discharge into the atmosphere when some portion of
the fuel remains unburned or partially burned. Some organics are unreacted trace
constituents of the fuel, whereas others may be pyrolysis products of the heavier
hydrocarbons in the gas.
Emissions of CO2 are also of concern because of its contribution to global warming.
Atmospheric warming occurs because solar radiation readily penetrates the earth’s
atmosphere and reaches surface of the planet, but infrared (thermal) radiation from the
surface is absorbed by the CO2 (and other polyatomic gases such as methane, unburned
hydrocarbons, refrigerants, water vapor, and volatile chemicals) in the atmosphere,
with resultant increase in temperature of the atmosphere. The amount of CO2 emitted
is a function of both fuel carbon content and system efficiency. The fuel carbon content
of natural gas is 34 lb/106 Btu, oil is 48 lb/106 Btu, and (ash-free) coal is 66 lb/106 Btu.
NOx control has been the primary focus of emission control research and
development in recent years. The most prominent emission control approaches are
described in the following paragraphs.
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CARBON REDUCTION, ENVIRONMENTAL BENEFITS, AND EMISSION CONTROLS
Water or Steam Injection. The first technique used to reduce NOx emissions was
injection of water or steam into the high-temperature flame zone. Water and steam are
strong diluents and can quench hot spots in the flame, reducing NOx. However, because
positioning of the injection is not precise, some NOx is still created. Depending on
uncontrolled NOx levels, water or steam injection reduces NOx by 60% or more. Water
or steam injection enables gas turbines to operate with untreated exhaust-NOx levels as
low as 25 ppm at 15% O2 on natural gas. NOx is only reduced to between 42 to 75 ppm
when firing with liquid distillate fuel. Both water and steam increase the mass flow
through the turbine and create a small amount of additional power. Use of exhaust heat
to raise the steam temperature also increases overall efficiency slightly. The water used
must be demineralized thoroughly to avoid forming deposits and corrosion in the turbine
expansion section. This adds cost and complexity to the operation of the turbine. Diluent
injection increases CO emissions appreciably, because it lowers the temperature in the
burnout zone, as well as in the NOx formation zone.
Lean Premixed Combustion. Lean premixed combustion (DLN/DLE) premixes the
gaseous fuel and compressed air so that there are no local zones of high temperatures, or
“hot spots,” where high levels of NOx would form. Lean premixed combustion requires
specially designed mixing chambers and mixture inlet zones to avoid flashback of the
flame. Optimized application of DLN combustion requires an integrated approach to
combustor and turbine design. The DLN combustor becomes an intrinsic part of the
turbine design, and specific combustor designs must be developed for each turbine
application. Although guaranteed NOx levels as low as 9 ppm have been achieved with
lean premixed combustion, few DLN-equipped turbines have reached the level of practical
operation at this emissions level necessary for commercialization—the capability of
maintaining 9 ppm across a wide operating range from full power to minimum load. One
problem is that pilot flames, which are small diffusion flames and a source of NOx, are
usually used for continuous internal ignition and stability in DLN combustors and make
it difficult to maintain full net NOx reduction over the complete turndown range.
Noise can also be an issue in lean premixed combustors; acoustic waves form
because of combustion instabilities when the premixed fuel and air ignite. This noise
also manifests itself as pressure waves, which can damage combustor walls and
accelerate the need for combustor replacement, thereby adding to maintenance costs
and lowering unit availability.
All leading gas turbine manufacturers feature DLN combustors in parts of their
product lines. Turbine manufacturers generally guarantee NOx emissions of 15 to 42
ppm using this technology. NOx emissions when firing distillate oil are typically
guaranteed at 42 ppm with DLN and/or combined with water injection. A few models
(primarily those larger than 40 MW) have combustors capable of 9 ppm (natural gas
fired) over the range of expected operation.
The development of market-ready DLN equipped turbine models is an expensive
undertaking because of the operational difficulties in maintaining reliable gas turbine
operation over a broad power range. Therefore, the timing of applying DLN to multiple
turbine product lines is a function of market priorities and resource constraints. Gas
turbine manufacturers initially develop DLN combustors for the gas turbine models for
which they expect the greatest market opportunity. As time goes on and experience is
gained, the technology is extended to additional gas turbine models.
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Selective Catalytic Reduction. The primary postcombustion NOx control method
in use today is selective catalytic reduction (SCR). Ammonia is injected into the flue
gas and reacts with NOx in the presence of a catalyst to produce N2 and H2O. The SCR
system is located in the exhaust path, typically within the HRSG, where the temperature
of the exhaust gas matches the operating temperature of the catalyst. The operating
temperature of conventional SCR systems ranges from 400 to 800°F (200 to 425°C).
The cost of conventional SCR has dropped significantly over time; catalyst innovations
have been a principal driver, resulting in a 20% reduction in catalyst volume and cost
with no change in performance.
Low-temperature SCR, operating in the 300 to 400°F (150 to 200°C) temperature
range, was commercialized in 1995 and is currently in operation on approximately 20
gas turbines. Low-temperature SCR is ideal for retrofit applications where it can be
located downstream of the HRSG, avoiding the potentially expensive retrofit of the
HRSG to locate the catalyst within a hotter zone of the HRSG.
High-temperature SCR installations, operating in the 800 to 1100°F (425 to 600°C)
temperature range, have increased significantly in recent years. The high operating
temperature allows the placement of the catalyst directly downstream of the turbine
exhaust flange. High-temperature SCR is also used on peaking capacity and baseloaded simple-cycle gas turbines where there is no HRSG.
SCR reduces between 80 to 90% of the NOx in the gas turbine exhaust, depending
on the degree to which the chemical conditions in the exhaust are uniform. When used
in series with water/steam injection or DLN combustion, SCR can result in low-singledigit NOx levels (2 to 5 ppm).
SCR systems are expensive and significantly impact the economic feasibility of
smaller gas turbine projects. In addition, ammonia can “slip” through the process
unreacted, contributing to environmental health concerns.
Carbon Monoxide Oxidation Catalysts. Oxidation catalysts control CO in gas
turbine exhaust. Some SCR installations incorporate CO oxidation modules along with
NOx reduction catalysts for simultaneous control of CO and NOx. The CO catalyst
promotes the oxidation of CO and hydrocarbon compounds to carbon dioxide (CO2)
and water (H2O) as the exhaust stream passes through the catalyst bed. The oxidation
process takes place spontaneously, so no reactants are required. The catalyst is usually
made of precious metal, such as platinum, palladium, or rhodium. Other formations,
such as metal oxides for emission streams containing chlorinated compounds, are also
used. CO catalysts also reduce VOCs and organic hazardous air pollutants (HAPs). CO
catalysts on gas turbines result in approximately 90% reduction of CO and 85 to 90%
control of formaldehyde (similar reductions can be expected on other HAPs).
Catalytic Combustion. In catalytic combustion, fuels oxidize at lean conditions in
the presence of a catalyst. Catalytic combustion is a flameless process, allowing fuel
oxidation to occur at temperatures below 1700°F (925°C), where NOx formation is low.
The catalyst is applied to combustor surfaces; this causes the fuel/air mixture to react
with the oxygen and release its initial thermal energy. The combustion reaction in the lean
premixed gas then goes to completion at design temperature. Data from ongoing long-
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term testing indicates that catalytic combustion exhibits low vibration and acoustic noise,
only 1/10 to 1/100 the levels measured in the same turbine equipped with DLN combustors.
Gas turbine catalytic combustion technology is being pursued by developers of
combustion systems and gas turbines and by government agencies, most notably the U.S.
Department of Energy and the California Energy Commission. Past efforts at developing
catalytic combustors for gas turbines achieved low, single-digit NOx ppm levels but failed
to produce combustion systems with suitable operating durability. This was typically
because of cycling damage and the brittle nature of the materials used for catalysts and
catalyst support systems. Catalytic combustor developers and gas turbine manufacturers
are testing durable catalytic and “partial catalytic” systems that are overcoming the
problems of past designs. Catalytic combustors capable of achieving NOx levels below 3
ppm are in full-scale demonstration and are entering early commercial introduction.
Similarly to DLN combustion, optimized catalytic combustion requires an integrated
approach to combustor and turbine design. Catalytic combustors must be tailored to the
specific operating characteristics and physical layout of each turbine design.
9.4.3 Microturbines45
Microturbines have the potential for extremely low emissions (Table 9-8). All
microturbines operating on gaseous fuels feature lean premixed (dry, low-NOx, or
DLN) combustor technology, which was developed relatively recently in the history of
Table 9-8. Natural Gas Microturbine Emissions Characteristics
Emissions Characteristics
System 1
System 2
System 3
System 4
28
65
200
250
23%
25%
31%
29%
9
4
4
5
NOx, lb/MWh
0.54
0.22
0.22
0.29
NOx, kg/MWh
0.25
0.10
0.10
0.13
40
9
9
5
CO, lb/MWh
1.46
0.3
0.3
0.14
CO, kg/MWh
0.66
0.14
0.14
0.06
THC, ppmv
9.00
5.00
5.00
5.00
THC, lb/MWh
0.19
0.09
0.09
0.10
THC, kg/MWh
0.09
0.04
0.04
0.05
CO2, lb/MWh
1736
1597
1288
1377
CO2, kg/MWh
789
726
585
626
Nominal Electricity Capacity, kW
Electrical Efficiency (HHV)
NOx, ppmv
CO, ppmv
Note: Estimates are based on manufacturers’ guarantees for typical systems. Emissions estimates
represent 15% O2 using natural gas fuel. All systems are equipped with gas booster compressors.
“Technology Characterization: Microturbines”, US Environmental Protection Agency, ICF
International Company, 2008
45
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gas turbines and is not universally featured on larger gas turbines. All of the example
commercial units have been certified to meet extremely stringent standards in Southern
California of less than 4 to 5 ppmvd of NOx (15% O2); CO and VOC emissions are at
the same level. “Non-California” versions have NOx emissions of less than 9 ppmvd.
9.4.4 Fuel Cells
Table 9-9 illustrates the emission characteristics of fuel cell systems. Fuel cell
systems do not require any emissions control devices to meet current and projected
regulations.
Table 9-9. Natural Gas Fuel Cell Emissions Characteristics
Emissions
Analysis
System 1
System 2
System 3
System 4
System 5
400
200
300
1200
100
37.80%
35%
43%
43%
43%
Fuel Cell Type
PAFC
PEMFC
MCFC
MCFC
SOFC
NOx, lb/MWh
0.02
0.06
0.02
0.02
0.05
NOx, kg/MWh
0.009
0.027
0.009
0.009
0.023
CO, lb/MWh
0.02
0.07
0.1
0.1
0.04
CO, kg/MWh
0.009
0.032
0.045
0.045
0.018
VOC, lb/MWh
0.02
0.01
0.01
0.01
0.01
VOC, kg/MWh
0.009
0.005
0.005
0.005
0.005
CO2, lb/MWh
1050
1323
900
855
1050
CO2, kg/MWh
477
601
409
389
477
Electricity
Capacity, kW
Electrical
Efficiency
(HHV)
Electric only, for typical systems available. Estimates are based on fuel cell system developers’
goals and prototype characteristics. All estimates are for emissions without after-treatment and
are adjusted to 15% O2.
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CHAPTER 10
CONSTRUCTION CONTRACTING
Contracting for the design and construction of a CHP system is one of the most
critical decisions made throughout the development process. With the growth of
nonutility generation, the basic structure of most power plant construction contracts
has changed.
10.1 TRADITIONAL CONTRACTING: DESIGN/BID/BUILD
The design/bid/build form of contracting is rather simple to understand. The owner
retains an engineer who is responsible for the design of the entire project. Upon
completion of the designand preparation of a set of plans and bidding specifications,
the owner selects a contractor for construction in accordance with those plans and
specifications. The contractor purchases all required equipment and may, in turn, hire
additional subcontractors for specific activities. During construction, the roles of the
owner and design engineer consist of monitoring the construction work to ensure that
it is performed in accordance with the plans and specifications, and dealing with
problems and unforeseen conditions that arise during construction.
This type of organizational structure, as shown in Figures 10-1 and 10-2, provides
a number of benefits, including an opportunity to reduce costs by seeking competitive
bids for the construction phase. Because all bidders are responding to a known specific
requirement, the owner has a basis for comparing price, although it may be difficult to
measure and quantify qualitative differences among bidders. Additionally, it allows for
a more complete development of project costs, including construction costs, based on
actual construction proposals as a basis for a final decision as to whether or not to
proceed with project development.
The design/bid/build approach also has several disadvantages. First, it requires that
the design be essentially completed as a condition of construction bidding. The
separation of design and construction activities results in a lengthier development
period, with greater costs resulting from escalation. This potential for cost increase
may be offset by the increased certainty regarding the construction phase for the design/
bid/build process compared to some alternatives. The most significant source of
difficulty with this form of contracting is that the owner cannot obtain guarantees for
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Figure 10-1. Typical Design/Bid/Build Project Structure (Single Prime Contractor)
the performance of a CHP project. The architect/engineer (A/E) will not be able to
provide meaningful guarantees regarding either the cost or the performance levels of
the resulting CHP system. The contractor cannot provide such guarantees based on a
design from someone else; the contractor can only guarantee to build the project in
accordance with the plans and specifications provided by the design professional. Thus,
the owner must bear the primary risk of project performance, knowing that any resulting
failures or problems may require a lengthy and costly arbitration or litigation process
to determine the cause and the responsibility for the problems.
These problems are exacerbated when the project must be completed on a fast
track, either as a condition for a power sale to a utility, a need to supply power and
thermal energy to an end-user facility, or for new host or end-user sites because the
overall host or end-user facility construction project may be fast-tracked. If contractors
are required to submit bids based on partial plans and specifications, the opportunity
for budget overruns is also increased. The responsibility for any resulting problems is
also less certain.
10.2 CONSTRUCTION MANAGEMENT CONTRACTING: DESIGN/BID/BUILD
The use of separate construction managers provides one mechanism for dealing
with the problems inherent in traditional contracting. Two alternative construction
manager (CM) roles are possible. In both cases, the owner retains an engineer for
evaluation of the design, equipment procurement, and actual construction; however,
two alternative organizational structures are possible, as shown in Figure 10-3. In one,
the CM contract includes the actual construction of the CHP system. In the other, the
CM is retained as an agent or consultant to the owner.
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Figure 10-2. Typical Design/Bid/Build Project Structure (Multiple Prime Contractors)
If the CM is retained as an agent of the owner, the problems of risk and performance
guarantee remain with the owner; the CM provides specialized expertise for dealing
with that risk. If the CM is the prime contractor responsible for construction, it is
possible to shift some of the cost risk to the CM. In either role, as an agent or as a prime,
the CM can reduce the project budget risk through the use of a guaranteed maximum
price form of contract. Under this form of agreement, the CM is paid a fixed fee that is
separately negotiated by the owner and CM and is then reimbursed for actual construction
costs. Because of the expertise of the CM in construction and value engineering, a CM
is sometimes engaged during the design process to help refine and improve designs and
to establish a budget prior to the receipt of contractor and vendor bids.
10.3 ENGINEERING/PROCUREMENT/CONSTRUCTION
More recently, CHP system developers have increasingly relied on engineering/
procurement/construction (EPC) contracts as a response to concerns over budget and
performance risks. This type of structure is also referred to as design/build and is
illustrated in Figure 10-4. It places all the contracts under a single entity—the EPC
contractor—who is responsible for all required design and construction activities. The
EPC contractor may be a single established firm, a joint venture created for purposes
of the specific project, a partnering arrangement, or an affiliate of the developer. In all
cases, it is important that the EPC contractor have adequate financial resources to take
on all the risks associated with a design/build approach. The single most significant
benefit of an EPC contract to the owner is that the contractor, who has responsibility for
all aspects of the project design and construction, is now in a position to guarantee both
budget and performance.
Design/build is an attractive option for CHP system development in that it assigns
most risks before a final decision as to whether the project should be built. In addition,
power generation and CHP projects with well-defined and measurable output are
amenable to performance-based contracts with acceptance tests. The inclusion of an
acceptance test, as a condition of project completion, provides a measure of protection
against performance deficiencies, including either electrical or thermal capacity
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Figure 10-3. Construction Manager Including Construction (Left) and Agent (Right)
deficiencies, low heat rate, and poor availability. Many EPC contracts specify financial
penalties or liquidated damages for failure to achieve required performance levels and
may also include bonuses for above-specification performance. Because the contract
for design and construction rests with a single vendor, it is also possible to shift schedule
risk entirely to that vendor. The erasure of an external interface between design
professionals and construction contractors eliminates one major cause of constructionrelated disputes and cost overruns. Finally, as shown in Figure 10-5, a design/build
approach can reduce the overall time required to develop a project.
Because of the increased risk associated with a fixed-price EPC contract, the
contractor will include additional contingencies, and the price may be greater than
would be the case for alternative, more traditional forms of contracting. Some of this
risk premium may be offset with economies realized by fast-tracking development,
leading to an earlier in-service date, and from reduced administrative costs resulting
from dealing with a single entity. The use of a single EPC contract also results in the
loss of the traditional role of the design professional as a monitor of construction on
behalf of the owner. The design professional is employed by the EPC contractor and it
is prudent for the owner to retain separate and independent design and construction
review services.
The use of an EPC contract imposes additional duties on the owner. First, the
owner must fully specify existing conditions that will have an impact on design and/or
construction costs or run the risk of cost overruns despite the fixed-price EPC. Second,
the owner must develop an understanding of the project that is adequate to develop an
EPC contract, including the specification of all critical performance parameters and
valuing any liquidated damages and bonuses. The owner must be capable of defining
an acceptance test procedure that properly demonstrates performance, including
measures of reliability and availability. Lastly, the owner must be capable of monitoring
the EPC process and evaluating actual performance.
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Figure 10-4. Engineering/Procurement/Construction (EPC) Contract Structure
Because of the unique nature of many CHP systems and the preliminary stage at
which a contract must be awarded, EPC contracting raises special concerns:
• Selection of Key Equipment and Components. In many projects, the owner will
have selected the key equipment, including the type and size of the prime movers,
the size of the HRSGs or the heat recovery system, and fuels. To the extent that the
owner specifies a particular piece of equipment, including a specific manufacturer or
model, that owner is reducing the risk that is shifted to the EPC contract. If the owner
specifies a piece of equipment, and that equipment does not function, the owner’s
claim on the EPC contract may be reduced. It may be possible to obtain performance
guarantees from the vendor and base the EPC contractor’s performance and liabilities
on those vendor guarantees. Owners should limit their direct intervention in the EPC
contract, both to preserve design and cost flexibility and to limit their own liabilities.
• Performance Guarantees. The owner can mitigate system performance
risk through guarantees included in the EPC contract. These guarantees can be
established at the expected performance levels or some fraction of those levels,
and they can be accompanied by penalties and bonuses. However, it is important to
exercise care in establishing guarantee levels and penalties, because most contractors
will include a risk premium or contingency that is based on the contractor’s
perception of potential difficulty and liability. Unnecessary guarantees can be costly.
• Acceptance Testing. The acceptance testing procedures are the key to ensuring
that the CHP system meets required performance levels. The overall testing
procedural approach and the specific testing procedures should be specified in the
design/build contract. The parameters that form the basis of testing will usually be
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Figure 10-5. Engineering/Procurement/Construction (EPC) versus Design/Bid Schedule
determined by the unique aspects of each project. As noted above, testing of heat rate
and capacity can be required, as can short-term performance at rated output (testing
period of one to seven days), reliability (continuous operation for a testing period of
14 to 45 days), and dependability (a minimum of 5 to 10 successive successful startups within a specified time). Other key issues include
š the cost of testing, including fuel, expendables, and maintenance;
š the treatment of revenues or savings resulting from production of
power and thermal energy during testing;
š the schedule requirements for testing, including a date or elapsed
time by which testing must be successfully completed;
š the requirements for repeating the test should it not be successful,
and the number of times the test can be repeated; and
š the procedures for correcting problems identified during testing.
• Transition to Operational Status. The transition from construction and
commissioning to operational status is critical for purposes of ending the
responsibilities and liabilities of the EPC contractor. It should be marked by a
specific event such as successful completion of performance tests or a release from
the owner to the EPC contractor. One potential area of mixed responsibility is the
operation of the CHP facility before turning it over to the owner. For larger CHP
systems, it is typical for the owner to contract for operating services and to bring
that operating contractor onboard well in advance of the facility start-up. In those
cases where the owner’s operating contractor and the EPC contractor both have site
responsibility, it is important that those responsibilities be contractually defined to
minimize the potential for ambiguity and cost.
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Selection of the proper form of contracting requires care and should involve input
from other professionals, including legal counsel.
10.4 PERMITTING REQUIREMENTS
Obtaining the required utility interconnection, environmental compliance, and
construction permits is an essential step in the CHP project development process.
Permit conditions often affect project design. It is critical to understand that construction
cannot begin until all permits are in process or in place.
The process of permitting a CHP system typically takes 3 to 12 months to complete,
depending on the location, technology, and site characteristics. There are also a number
of preconstruction, construction, and operating approvals that must be obtained from a
variety of local government jurisdictions for any CHP project, including the following:
1. Local utility company approvals
a. Electric utility interconnection study and approval
b. Natural gas connection/supply
2. Local jurisdiction preconstruction and construction approvals
a. Planning department land use and environmental assessment/review
b. Building department review and approval of project design and engineering
(based on construction drawings)
c. Air quality agency approval for construction
3. Local jurisdiction postconstruction and operating approvals
a. Planning department and building department confirmation and inspection of
installed CHP source
b. Air quality agency confirmation that CHP emissions meet emissions
requirements
10.4.1 Overall Permitting Process
A typical basic preconstruction/construction phase permitting process for a CHP
project within any given entity (utility company or government agency) involves two
major steps:
1. Project developer completes and submits application forms, accompanied by fee
payment(s), to the relevant entity. The entity reviews the application for
completeness and iterates with the submitter until the application is considered
complete and accurate. The entity completes its review and issues the relevant
approval/permit. The approval process may require one or more meetings between
agencies or utility staff and the project developer or development team. In some
states, public comment periods are required to the completed application. The
comment periods are usually a minimum of 30 days in length. The agency then
addresses the comments received, usually explaining why the project developer
did or did not incorporate or act on specific suggestions. Public review processes
can add months to the approval process.
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2. The postconstruction/operating phase in some state and local governments requires
approvals and for utility interconnection approval whereby the cognizant agency/
organization confirms that the installation is in compliance with the approved
application, often requiring a site inspection. This may be an iterative process, with
a number of rounds of developer corrections and agency reinspections.
The success of the permitting process relies upon a coordinated effort between the
developer of the project and the various entities that must review project plans and
analyze their impacts.
10.4.2 Utility Interconnection Requirements
Interconnection requirements include the technical and contractual requirements
for interconnection to the local electricity grid for those systems that will operate in
parallel with the utility. “Parallel with the utility” means the CHP system is electrically
interconnected with the utility distribution system at a point of common coupling at the
site (common bus-bar), and facility loads are met with a combination of grid and selfgenerated power. Interconnection requires various levels of equipment safeguards and
utility approvals to ensure that power does not feed into the grid during grid outages.
Each utility has had its own specific requirements that, in the past, have sometimes
appeared to be arbitrary, overly complicated, and prohibitively expensive. Recent
regulatory interventions, standardization and equipment certification initiatives at the
federal and state levels have helped to provide better definition and certainty to both the
technical and contractual requirements for interconnection approval.
The approval process typically includes the following steps:
1. Application. A formal application is filed with the servicing electric utility. This
application usually asks for information on the location, technical and design
parameters, and operational and maintenance procedures for the planned CHP
system. The level of detail required and application fees can vary considerably
from one utility to another.
2. Interconnection Studies. A number of technical interconnection studies may
be required, depending on the size and configuration of the CHP system, the
condition and design of the grid at the facility’s interconnection point to the
grid, and the specific requirements of the servicing utility:
a. Minimum engineering review:designed to identify any adverse system
impacts that would result from interconnection of the CHP system. Examples
of potential negative impacts to the grid include exceeding the short circuit
capability of any breakers, violations of thermal overload or voltage limits,
and inadequate grounding requirements and electric system protection.
b. System impact study:required if any adverse impacts are identified in
the minimum engineering review. Designed to identify and detail the
impacts to the electric system operation and reliability of the proposed CHP
system, focusing on the potential adverse system impacts identified in the
engineering review.
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c. Facility study: might be required if the system impact study indicates that
grid system reliability would be adversely affected by interconnection of the
CHP system. This study would identify and design any required facility or
system upgrades that might be necessary to maintain grid integrity.
The costs of the studies are typically paid by the applicant, but can be negotiated
with the utility. It is important to execute specific agreements with the utility if specific
studies are required. These agreements should outline the scope of the study and
requirements and include a good faith estimate of the cost to perform the study.
10.4.3 Interconnection agreement
The interconnection agreement will cover such issues as back-up services, metering
requirements, inspection rights, insurance requirements, and the responsibilities of
each individual party.
10.4.4 Power purchase agreement
If sales of excess power to the grid are contemplated, the terms and conditions of
power purchases would be contained in a separate power purchase agreement (PPA)
between the utility and the site.
10.4.5 Local Zoning/Planning Requirements
Project siting and operation are governed by a number of local jurisdictions. It is
important to work with the appropriate regulatory bodies throughout all stages of
project development to minimize permitting delays that cost both time and money.
Applicable local agencies include the following:
• County and City Planning Bureaus. These govern land use and zoning issues
and may conduct environmental impact assessments, including noise studies,
and are responsible for compliance with local ordinances. For example, many
local zoning ordinances stipulate the allowable decibel levels for noise sources,
and these levels vary, depending on the zoning classification at the site. The local
zoning board or planning bureau determines whether land-use criteria are met by a
particular project and can usually grant variances if conditions warrant.
• State and Local Building and Fire Code Departments. These address CHPrelated safety issues such as exhaust temperatures, venting, natural gas pressure,
fuel storage, space limitations, vibration, gas and steam piping, and building
structural issues. Building departments are often part of a city’s planning division.
Most CHP projects require a building permit.
• Environmental/Public Health Departments. These look out for public health
and safety, focusing on hazardous materials and waste management requirements.
• Water/Sewer and Public Works Authorities. These rule on water supply and
discharge matters. Typically, they ensure that a project is compliant with the federal
Clean Water Act; decide whether local water and wastewater quality standards will
be or are being met; and evaluate waste streams that empty into lakes, rivers, and
other bodies of water.
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10.4.6 EPA Title V
In the 1990 amendments to the Clean Air Act (CAA), Congress established a
program to reduce air pollutants from large facilities. The CAA, contained in Title 5,
enhances the way federal, state, tribal, and local permitting authorities regulate air
pollution by consolidating all air pollution control requirements into a single
comprehensive site “operating permit” that covers all aspects of a source’s year-to-year
air pollution activities. The Title 5 program is designed to make it easier for owners and
operators to understand and comply with the CAA requirements applicable to their
sources. All major sources and other sources as defined in 40 CFR 70.2 and 71.2 are
required to obtain operating permits. Title V triggers a significant application process,
including public review. Facilities where adding a CHP system will trigger a Title 5
application46 are often problematic and will likely not be pursued by the site simply to
avoid the public hearing process.
A major source is defined as having actual or potential emissions that meet or
exceed EPA major source threshold for their location. The major source threshold
for any “air pollutant” is 100 tons/year (the default value) for attainment areas.
Table 10-1 provides lower thresholds that apply in nonattainment area in tons per
year (tpy)(Mg/yr).
Major source thresholds for “hazardous air pollutants” (HAP) are 10 tons/year for
a single HAP or 25 tons/year for any combination of HAP.
10.4.7 Prevention of Significant Deterioration and Title V
Operating Permit Concerning Greenhouse Gas Emissions
The Tailoring Rule focuses on new facilities with greenhouse gas emissions (GHG)
emissions of at least 100,000 tons per year (tpy) (90.7 Mg/yr) carbon dioxide equivalent
(CO2e), and existing facilities with at least 100,000 tpy (90.7 Mg/yr) CO2e making
changes that would increase GHG emissions by at least 75,000 tpy (68.0 Mg/yr) CO2e
are required to obtain Prevention of Significant Deterioration (PSD) permits. Facilities
Table 10-1. Lower Thresholds for Nonattainment Areas
Nonattainment Area Designation
VOC or NOx
tons/yr
Mg/yr
Marginal
100
90.7
Moderate
100
Serious
CO
PM-10
tons/yr
Mg/yr
tons/yr Mg/yr
90.7
100
90.7
100
90.7
50
45.4
50
45.4
70
63.5
Ozone transport region (other than
severe or extreme) (VOC only)
50
45.4
Severe
25
22.7
Extreme
10
9.1
Note that the reason adding an on-site CHP system increases site emissions is that there is no
offset for the displaced electric generation, transmission, or distribution related emissions
credited to the CHP system.
46
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that must obtain a PSD permit anyway, to cover other regulated pollutants, must also
address GHG emissions increases of 75,000 tpy (68.0 Mg/yr) CO2e or more. New and
existing sources with GHG emissions above 100,000 tpy (90.7 Mg/yr) CO2e must also
obtain operating permits. It is incumbent on CHP system developers to keep updated
on this and other developing regulations to be current on the requirements.
10.4.8 Local Air Quality Requirements
Air quality agencies/districts at the state and local levels are responsible for
administering air quality regulations, with a primary focus on air pollution control. The
primary criteria pollutants of concern include NOx, CO, SO2, particulates, and certain
hazardous air toxins. Local air agencies ensure that a project complies with federal and
state Clean Air Act mandates. These authorities issue construction permits based on
their review of project design and performance objectives. After construction and
installation is complete, projects receive operating permits based on emissions
performance relative to applicable emissions thresholds. Issues that air agencies
consider include exemption thresholds (e.g., capacity, emission levels), controlled
emission levels, type of fuel(s) fired, proximity to sensitive receptors (e.g., schools, day
cares, hospitals), siting at a new location or an existing site (e.g., commercial building,
industrial facility), and a demonstration that projected emission levels are met via
source testing.
Major characteristics that typically differentiate projects for air permitting purposes
include the following:
• Does the CHP system trigger permit requirements? If it is not exempt, what
relevant emissions threshold is it below or above?
• Is the site in an attainment area? Nonattainment areas feature more rigorous
guidelines.
• Is the site an existing or new facility? Is the site currently considered a major
emissions source or a minor emissions source? Adding a new source of emissions
to an existing major source can trigger additional permitting requirements; adding
a new source to an existing minor source may move the facility into the major
source category.
• Do emissions of criteria pollutants and air toxics affect surrounding communities?
If it appears that the source’s emissions may affect public health, air quality
modeling or an evaluation study may be necessary.
10.4.9 Permitting Costs
Siting and permitting can require significant investments of time and money in
researching, planning, filing applications, meeting with officials, and paying fees.
Interconnection, environmental, regulatory, and local government agency approval
costs may approach 3 to 5% of project costs for smaller systems and need to be included
in any CHP project economic evaluation.
Equipment needed to ensure compliance, such as air pollution control equipment
or noise abatement equipment, would be in addition to these fees.
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10.5 PROJECT DEVELOPMENT OPTIONS
Project development options generally are reduced to financial decisions that may
be influenced by the nature and focus of the company making the decision. In other
words, CHP decisions are first and foremost financial, but systems development and
ownership decisions might be influenced by the company expertise and focus.
This section primarily focuses on the financial options. CHP systems require an
initial investment to cover the cost of equipment, installation, and regulatory/permitting
costs; these costs are then typically recovered through lower energy costs over the life
of the equipment.
There are a variety of capital providers in the market, and different investors have
different objectives. The terms under which capital is provided vary from source to
source, and depend on factors such as the lender’s appetite for risk, the expected return
on the project, and the time horizon for repayment.
The primary financing options available to CHP projects include the following:
• Company earnings or internal cash flow
• Debt financing
• Equity financing
• Lease financing
• Bonds (for public entities)
• Project or third-party financing
• Build, own, and operate (BOO) options, including energy savings performance
contracting
10.5.1 Company Earnings or Internal Cash Flow
To finance the required capital investment out of cash flow generated from ongoing
company activities, the potential return on investment can make this option economically
attractive. In addition, loan transaction costs can be avoided with self-financed projects.
However, there are many demands on internal resources, and the CHP project may be
competing with other investment options for internal funds, including options tied
more directly to business expansion or productivity improvements.
10.5.2 Debt Financing
Commercial banks and other lenders can provide loans to support CHP projects.
Most lenders look at the credit history and financial assets of the owner or developer,
rather than the cash flow of a project. If the facility has good credit, adequate assets,
and the ability to repay borrowed money, lenders will generally provide debt financing
for up to 80% or more of the installed period of the loan, regardless of the actual project
performance. Debt financing usually provides the option of either a fixed-rate or
floating-rate loan. Floating-rate loans are usually tied to an accepted interest rate index,
such as U.S. treasury bills.
For small businesses, the Small Business Administration (SBA) can guarantee
85% of bank loans up to $150,000 or 75% of bank loans up to $2 million for various
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projects, including CHP. Host or facility owners should ask potential developers and
equipment suppliers if debt financing is a service they can provide. The ability to
provide financing may be a key consideration when selecting a developer, equipment
vendors, and/or other partners.
10.5.3 Equity Financing
Private equity financing has been a widely used method for financing certain types
of CHP projects. To use private equity financing, an investor must be willing to take an
ownership position, often temporarily, in the CHP project. In return for a significant
share of project ownership, the investor must be willing to fund part or all of the project
costs using its own equity or privately placed equity or debt. Some CHP developers are
potential equity investor/partners, as are some equipment vendors and fuel suppliers.
Investment banks are also potential investors. The primary advantage of this method is
its applicability to most projects. The primary disadvantage is its higher cost; the
returns to the host/owner are reduced to cover the off-loading of risk to the investor.
10.5.4 Lease Financing
Leasing can be an attractive financing option for smaller CHP projects. The
operating savings resulting from the installation of CHP—the bottom-line impacts on
facility energy costs—are used to offset the monthly lease payments, creating a positive
cash flow for the company. Lease financing encompasses several strategies in which a
facility owner can lease all or part of the assets from the asset owner(s). Typically, lease
arrangements provide the advantage of transferring tax benefits, such as accelerated
depreciation or energy tax credits, to an entity that can best use them. Lease arrangements
commonly provide the lessee with the option, at predetermined intervals, to purchase
the assets or extend the lease. Several large equipment vendors have subsidiaries that
lease equipment, as do some financing companies.
10.5.5 Project or Third-Party Financing
Project or third-party financing is an approach to obtaining commercial debt
financing for the construction of a project in which the lenders look at the creditworthiness of the project to ensure debt repayment rather than at the assets of the
developer/sponsor. Third-party financing can involve the creation of a legally
independent project company financed with non-recourse debt and equity for the
purpose of financing a single purpose industrial asset. This entails establishing a
company (e.g., a limited liability corporation) solely to accomplish a specific task, in
this case to build and operate a DG/CHP facility. Lenders look primarily to the cash
flows the asset will generate for assurances of repayment. They are explicitly excluded
from recourse to the owners’ underlying balance sheets.
10.5.6 Build/Own/Operate Options
A final third-party financing structure is the BOO option, in which the CHP facility
is built, owned, and operated by an entity other than the host, and the host purchases
heat and power at established or indexed rates from the third party. There are also build/
own/transfer projects, which are similar to BOO projects, except that the facility
involved is transferred to the host after a predetermined timeframe. Such projects may
be implemented by an energy services company (ESCO) or sometimes by equipment
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suppliers and project developers acting as ESCOs. In a BOO project, the ESCO finances
the entire project, owns the system, and incurs all costs associated with its design,
installation, and maintenance. The ESCO sells heat and power to the host at a specified
rate that offers some savings over current energy expenditures, or can enter into an
energy savings performance contract (ESPC) with the host. In an ESPC, the ESCO and
the host agree to share the cost savings generated by the project; in return, the ESCO
guarantees the performance of the CHP system. An ESPC mitigates the risks associated
with new technologies for facility owners, and allows operation and maintenance of the
new system by ESCO specialists.
ESPCs are frequently used for public-sector projects. There are no upfront costs
other than technical and contracting support. Traditional ESPCs have three components:
• Project development agreement
• Energy services agreement
• Financing agreement
10.5.7 Financing Options for Public Entities
Public sector facilities have additional financing options to consider. A government
entity (e.g., municipality, public utility district, county government) can issue either
tax-exempt governmental bonds or private activity bonds, which can be either taxable
or tax-exempt, to raise money for CHP projects. Bonds can either be secured by general
government revenues (revenue bonds), or by specific revenues from a project (project
bonds). The terms for bond financing usually do not exceed the useful life of the facility,
but terms extending up to 30 years are not uncommon. The primary benefit of
governmental bonds is that the resulting debt has an interest rate that is usually lower
(by 1 to 2%) than commercial debt. However, in addition to initial qualification
requirements, many bond issuers find that strict debt coverage and cash reserve
requirements may be imposed on an energy project to ensure the financial stability of
the issuer is preserved. These requirements may even be more rigorous than those
imposed by commercial banks under a project finance approach.
The Federal Energy Management Program (FEMP) of the U.S. Department of
Energy has signed indefinite quantity contracts with ESCOs on a regional basis for
streamlining energy efficiency improvements, including CHP, at federal facilities.
Realizing that awarding a stand-alone ESPC can be very complex and time-consuming,
FEMP created streamlined Super ESPCs. The Energy Independence and Security Act
of 2007 (EISA), Section 514, extended the authority for all federal agencies to use
ESPCs permanently. These “umbrella” contracts allow agencies to undertake multiple
energy projects under the same contract. An agency that uses a Super ESPC can bypass
cumbersome procurement procedures and partner directly with a prequalified ESCO to
develop an energy project. Section 512 of the EISA increases financial flexibility for
agencies by allowing them to use both private and appropriated funds for an ESPC
project. With Super ESPCs, FEMP has already completed the Federal Acquisition
Regulations (FAR) procurement process, in compliance with all necessary requirements,
and awarded contracts to selected ESCOs. Federal facilities can place and implement a
Super ESPC in much less time than it takes to develop a standalone ESPC. As a result,
Super ESPCs are being used more frequently by federal agencies.
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Another way for federal agencies to implement efficiency and CHP projects is
through partnerships with their franchised or serving utilities. Federal agencies can
enter into sole-source utility energy service contracts (UESCs) to implement energy
improvements at their facilities. With a UESC, the utility typically arranges financing
to cover the capital costs of the project. Then the utility is repaid over the contract term
from the cost savings generated by the energy efficiency measures. With this
arrangement, agencies can implement energy improvements with no initial capital
investment. The Energy Policy Act of 1992 authorizes and encourages federal agencies
to participate in utility energy efficiency programs offered by electric and gas utilities
and by other program administrators (e.g., state agencies). These programs range from
equipment rebates (i.e., utility incentives) to delivery of a complete turnkey project.
Federal legislation and numerous legal opinions demonstrate that agencies have full
authority to enter into utility energy service contracts as well as take advantage of
utility incentive programs.
10.6 PROJECT SCHEDULE AND IMPLEMENTATION
After the basic technical and economic elements of the CHP are understood, a
positive feasibility study completed, and the financing structure is obtained, the project
participants enter the project implementation stage, which includes the following steps:
1. Project team selection
2. Detailed engineering design
3. Code and regulatory compliance
4. Contracting: selection of designer/suppliers
5. Construction
6. Commissioning
7. Validation
10.6.1 Project team
The project team is assigned to represent and protect the interest of the CHP plant
owner during the implementation of the project. The team must either comprise or
outsource the legal, technical, and managerial skills required for implementation of the
CHP project. The competencies and responsibilities for individual tasks within the
team have to be clearly defined during the whole process of project implementation, the
steps of which are described in the previous and following sections.
10.6.2 Detailed engineering design
Detailed engineering design can start immediately after positive decision of the
client to implement the solution presented in the ASHRAE Level II assessment. The
detailed engineering design typically proceeds in two stages, although some engineering
processes use more stages. The first, 30% design stage, is connected with obtaining the
permits and licenses for construction; the deliverable of this stage presents the first
level project design for review. The 30% project design is followed by a detailed, 100%
project design.
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10.6.3 Code and regulatory compliance
This phase of the CHP project is the most administratively intensive part, and it
depends on the generally binding regulations related to the specific site. The project
manager must define responsibilities of the individual project team members for the
individual steps to be taken to secure legal compliance.
10.6.4 Contracting: Selection of Designer/Suppliers
Soliciting proposals for equipment and services depends on the types of project
and capabilities of the project team.
If the owner(s) are self-financing and developing their own project, then soliciting
subcontracts and/or equipment purchases will be required. If the CHP project is selffinanced and procured, complete project specifications should be used to solicit bids.
If third-party developers will develop the CHP project, then preliminary designs or
30% designs could be used to solicit bids for these services.
10.6.5 Construction
The project team approves, with the supplier, a schedule of the regular inspection
days to ensure fulfillment of the approved time-schedule physical delivery and quality.
Based on inspection and reporting by site supervision, the project team makes
decisions about potential changes required in the projected status and as proposed by
the supplier.
The designer of the CHP system should be involved to supervise the project
construction to ensure that the equipment is installed correctly, in accordance with the
original design. The main role of the designer is to provide technical and economic
evaluation of the impact of changes that usually appear during construction, in
comparison with the design.
10.6.6 Commissioning
The last phase of CHP project implementation is commissioning, which usually
lasts for several weeks. During this phase, it is important to train the staff that will be
responsible to operate the plant and to perform basic maintenance following
commissioning.
At the end of commissioning, the CHP plant is turned over to the owner for normal
operation. Potential failures usually appear during the first year of operation; therefore,
it is important that the supplier is bound by contractual terms to remove any failures
that result from the equipment or changes in original construction plans.
Commissioning of a CHP system begins well before the actual construction is
complete and includes the training of the plant operators. It may or may not include a
formal acceptance test procedure; however, it should include extensive testing as a
basis for safely bringing the system into service. It also includes the development of a
detailed plan for testing and acceptance of the system.
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Operator training should start during the installation phase of the project. For
smaller projects sited in an existing powerhouse and where the operating responsibility
will rest with the existing powerhouse staff, that staff should be part of the project
design team or, at a minimum, participate in design and construction reviews. It is
important that the operating staff have a complete understanding of the system design
philosophy, all components and their functions, limitations and relationships to other
components, and all operating and maintenance procedures. In retrofit applications
where the CHP system operation will be the responsibility of existing operators, this
training can be accomplished throughout the construction and installation process. For
larger CHP systems, and typically those third-party-owned systems of several hundred
megawatts that are based on power sales to a utility, it may not be practical to have the
complete operating staff available through design and installation. In this case, key
persons should be brought into the project as early as possible during installation.
Commissioning consists of a number of discrete tasks applicable both to the prime
mover/generator and to all ancillary systems. These include the following:
• Development of a Commissioning and Start-Up Plan. The development
of a formal plan for commissioning and start-up is the first task necessary for
successful commissioning with a minimum of delay and cost. The plan should
include a detailed description of the formal acceptance testing procedures, whether
or not performance tests are specified in the construction contract. If a formal
performance test is included in the construction contract, the plan should state
the respective responsibilities and obligations of the construction contractor’s
personnel and the plant operator’s personnel. In addition, it is necessary to delineate
responsibilities for other tasks that may be shared by the construction contractor
and the operator, so as to avoid the possibility of operators negatively affecting the
construction or performance of the CHP system.
• Operator Training. Experienced operators should be trained in the specific
details of the CHP system being installed.
• Inspection. Inspection should be initiated during the construction phase and
continue to completion and inspection of all equipment and systems. These
inspection activities will allow the operators to become familiar with the specific
equipment and its installation as well as provide an opportunity to identify any
problems or deficiencies.
• Cleaning.All equipment should be cleaned and any shipping materials or coatings
removed prior to any attempt to energize the system. Special attention should
be paid to inlet air filters, because any debris not cleared can cause catastrophic
damage to the air supply system and the prime mover.
• Pressure Testing. The heat management system, including the HRSG, radiators,
mufflers, heat exchangers, and other components, should be pressure tested to ensure
system integrity. If the CHP system includes its own water supply and treatment
system, that system should be tested and used as a supply for pressure testing.
• Interconnection Energization. The interconnection between the CHP system
and the local electric utility grid should be energized. For new facilities, a
temporary utility service drop is typically used during construction; the permanent
utility service for supplemental and standby power to the facility should be tested.
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• Electrical Synchronization and Closure. The ability to synchronize the CHP
system to the electric utility grid and to interconnect and parallel the grid should
be tested. Multiple prime-mover or generator installations should also be tested to
ensure that the prime movers are capable of synchronizing with each other.
• Isolated Operation. Those CHP systems capable of operation in isolation from
the grid should be tested both with and without a site load. If the CHP system is
tied to a site load management system, the interface and functioning of the loadshedding system should be verified.
• Instrumentation and Controls. All controls should be manually exercised to
verify their function and should be used until automatic controls can be calibrated
and verified. The function of automated control systems used to monitor and
control the operation of the CHP system prime mover should be manually verified.
• Chemical Cleaning. Final chemical cleaning of all water and coolant systems.
• Checking of Safety Valves. All settings and functions of safety valves should be
verified upon initial operation at pressure and temperature.
• Data-Monitoring and -Reporting System. The operation of the CHP system’s
data-monitoring and -reporting system should be independently verified and
calculations and reports verified.
• Start-Up. Start-up procedures will vary as a function of the type of prime mover
and heat recovery system.
• Alternative Fuel Transfer Capability. The capability of a dual-fuel CHP system
to transfer from one fuel to another should be verified.
Whether or not a performance test is included in the construction contract, the
capacity and efficiency of the CHP system should be tested and documented.
10.6.7 Validation
During this trial period, a verification of the achieved results and the comparison to
projected parameters should take place. This verification should also contain the
emission measurements, which will document the real environmental benefits.
After the end of trial operation and the verification of results, for future reference,
it is recommended that the CHP project developer summarize the project results and
experience gained in a report.
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CHAPTER 11
CASE STUDIES
Case studies are important learning tools for understanding the results of design
choices. The case studies presented in this chapter are based on real installations. The
case study structure follows a standardized format and is designed to walk the reader
through the process that was undertaken in delivering the subject CHP systems and
explain the lessons learned.
11.1 UNIVERSITY CAMPUS
This case study provides a typical example multibuilding campus CHP system
evaluation. The campus covers 140 acres on the west coast of the United States with an
enrollment approaching 2000 students.
11.1.1 Introduction
The main university campus consists of approximately 50 buildings, ranging in
age from only a few years old to over 90 years old (see Figure 11-1). The buildings
range in size from 600 ft2 (56 m2) to over 100,000 ft2 (9 290 m2). Usage includes
academic, laboratory, dormitory, administration, libraries, and various others. Eleven
of the buildings have 12 kV electrical service, with 4160 V electrical service serving
the remainder of the buildings. At present, 10 buildings are connected to the campus
energy center (CES) chilled-water system, and 12 buildings are connected to the hotwater distribution system. The CES building is approximately 19,000 ft2 (1765 m2).
The CES building is divided into two general areas. The west end of the CES houses
the heating hot-water boilers and ancillary equipment, and the east side of the CES
houses the chillers and ancillary equipment. There is also an electrical room located
on the west end of the CES, and three structural cooling tower cells are located on the
east end of the CES. The CES at the university is located near the campus core. The
CES currently provides chilled water and hot water to the buildings as indicated in
Figure 11-1. Significant expansion of the campus thermal and power requirements
prompted the CHP assessment.
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11.1.1.1 Natural Gas Distribution
Natural gas is delivered to the university via a 6 in. supply main. Natural gas is
distributed to the campus via lines that extend north and south from the main natural
gas line. Two natural gas meters are located at the CES. One meter monitors an existing
gas-fired absorption chiller’s natural gas usage, and the other meter monitors the boiler’s
natural gas usage, as well as the natural gas usage of two other buildings.
11.1.1.2 Electrical Distribution
Primary electrical service is 12 kV. From the utility disconnect switch, the electrical
service leads east underground to the main 12 kV electrical service for the campus. The
main electrical service for the university is located at the north side of the CES. The
campus utility consists of two distinct electrical distribution systems:
• 12 kV System. The 12 kV electrical distribution service is identified as the
“East Loop.” The average age of the conductor and equipment on this loop is
relatively new (2 to 3 years old). The loop serves 11 buildings.
Figure 11-1. Campus Buildings Central Utility Use
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• 4160V System. The 4160 V electrical distribution service, identified as the
“West Loop”, is the larger of the two loops. The average age of the conductor
and equipment is 25 to 30 years old. This loop is fed from the main 12 kV
switchgear service to a 2500 kVA 12/4.16 kV transformer. This transformer feeds
4160 V distribution switchgear. The three distribution feeders from this switchgear
serve 31 buildings.
The 12 kV and 4160 V switchgear have the capability of remotely operating the
feeder and main breaker for load shedding and generator(s) or cogeneration feed to
provide standby power. This system is scheduled for automation with paralleling gear
and controls through programmable logic controller (PLC) and LAN to operate two
1500 kW 48/12,000 V standby generators.
11.1.2 Project History
U.S. West Coast residents and businesses had experienced what newspapers and
politicians have called an “Energy Crisis” in the latter part of the 20th century and
entering the 21st century as well. Peak electricity prices escalated from $20 to $30 per
megawatt-hour to more than $300 per megawatt-hour, a ten-fold increase. Subsequently,
spot electricity prices had fallen to levels comparable to those levels prior to the recent
escalation in electricity prices. Escalating electricity prices were expected. Figure 11-2
provided evidence that the site owners were right to conclude that electric prices were
on the rise, because the actual average bundled price of electricity for large commercial
customers has increased 18% since 2000.
Figure 11-2. Actual Bundled Electric Prices $/kWh49
49
Source: U.S. Energy Information Agency.
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At the same time, natural gas prices had seen a price spike from about $0.30 per
therm50 to more than a $1.00 per therm in December of 2000, and then natural gas
prices falling back again over the last year (Figure 11-3).
Figure 11-3. Actual Bundled Natural Gas Prices $/therm51
Figure 11-3 (SI). Actual Bundled Natural Gas Prices $/therm51
50
100,000 Btu (29.3 kWh).
51
Source: U.S. Energy Information Agency.
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Energy price volatility has made for difficult times for those with significant energy
budgets, such as this university. Escalating energy prices are one of the reasons (along
with the need to replace aging, inefficient equipment, and to plan for future campus
expansion) that the site decided to explore energy cost saving options, including CHP.
11.1.3 Initial Project Parameters
This case study will follow the ASHRAE CHP Analysis Tool process. The Analysis
Tool is available as a supplement to this volume at www.ashrae.org/CHPDG. The initial
project parameters are entered on the Site Data Input screen (Figure 11-4). This section
covers site input data for the university case study.
Establishing a site’s hours of operation is driven by a firm understanding of how the
loads function with respect hours of operation. In the case of this university with
heating, ventilation, air conditioning, and domestic hot-water loads, it is logical to
assume 24 h/day, 7 days/week operation. Table 11-1 shows the ASHRAE CHP Analysis
Tool Operating Hours Input screen containing the site schedule information.
Figure 11-4. ASHRAE CHP Analysis Tool Site Data Input Screen
(ASHRAE CHP Analysis Tool [I-P units only])
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11.1.3.1 Electric Load Profiles
The planned campus expansion consisted of a new science center (68,000 ft2) and
miscellaneous campus expansion of approximately additional 38,000 ft2. The science
center will have a peak electric load of approximately 7.5 W/ft2, and the miscellaneous
campus development will have a peak electric load of approximately 5 W/ft2. The
additional peak diversified electric load is therefore 600 kW. When added to the existing
estimated peak campus electrical load of 2400 kW, the resulting estimated future peak
campus electric load is approximately 3000 kW. Science laboratory buildings are often
24 h buildings because of the nature of the research being conducted. Research
equipment and HVAC equipment are therefore usually not shut down at night, resulting
in an electric load profile that is flatter than typical campus building electric load
profiles. Therefore, the additional building base electric load was estimated to be
approximately 70% of the peak load, or 400 kW. (Figure 11-5)
11.1.3.2 Thermal Load Profiles
Developing addressable thermal loads is the first step in assessing a site for CHP.
The university site has four current and future addressable thermal loads: (1) hot water
for space heating, (2) hot water for reheat, (3) hot water for domestic service water, and
(4) chilled water for space cooling.
Table 11-1. ASHRAE CHP Analysis Tool Operating Hours Input Screen
Operating Hours
Operating Hours per Day
24
Days per Week
7.0
% Operating Hours
100%
Figure 11-5. Campus Estimated Future Electric Load Profile
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Figure 11-6 shows an estimated existing peak-day 24 h heating load profile for the
university, based on provided site data. The peak existing heating load is estimated at
7.5 million Btu/h (2200 kW).
Figure 11-6. Estimated Existing Peak-Day Heating/Domestic Water Load Profile
Figure 11-6 (SI). Estimated Existing Peak-Day Heating/Domestic Water Load Profile
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The planned additional heating loads to the CES are therefore approximately 6.5
million Btu/h (1900 kW), increasing the peak estimated heating load without diversity
to approximately 14 million Btu/h (4100 kW). (Figure 11-7).
Figure 11-7. CES Estimated Future Peak Heating Water Load Profile
Figure 11-7 (SI). CES Estimated Future Peak Heating Water Load Profile
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Figure 11-8 shows the ‘smoothed out’ estimated existing CES peak-day 24 h
cooling load profile. The existing peak cooling load is estimated at 500 tons, and occurs
at approximately 3:00 in the afternoon. The estimated total ton-hours for the existing
peak day are approximately 8000 (28 000 kWhTH) .
Figure 11-8. CES Estimated Existing Peak-Day Chilled Water Load Profile
Figure 11-8 (SI). CES Estimated Existing Peak-Day Chilled Water Load Profile
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Figure 11-9 shows the estimated future peak-day cooling load profile. The peak
cooling load is estimated with diversity at 1120 tons (3940 kW). The estimated future
peak-day total ton-hours are 18,000 (63 306 kWh).
Figure 11-9. CES Estimated Future Peak Heating Water Load Profile
Figure 11-9 (SI). CES Estimated Future Peak Heating Water Load Profile
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From the preceding load analysis, planning for four future addressable thermal
loads was determined:
• Hot water for space heating. 14 million Btu/h (4100 kW) maximum
• Hot water for reheat (10% outdoor air fraction for reheat purposes), because this
is the high desert, and humidity control is generally not an issue. However, some
reheat is used in laboratories that are overcooled because of multiple fume hoods.
• Domestic hot water. 250,000 Btu/h (73 kW) is estimated for the limited load
served by the CEC for DHW and swimming pool.
• Chilled water for space cooling. 1120 tons (3940 kW) maximum.
Table 11-2 shows the ASHRAE CHP Analysis Tool Operating Hours Input screen
containing the site schedule information.
Figure 11-10 presents both the addressable and nonaddressable loads versus the site
fuel usage. The addressable thermal loads to displace onsite fuel usage consist of space
heating and domestic hot water. The significant nonaddressable winter thermal load
exists because a noteworthy number of campus buildings are not heated from the campus
loop, and most of the DHW service is distributed and does not use the hot water loop.
(Note that system efficiencies would improve and overall energy costs would be reduced
if additional building and DHW production were connected to the CEC.)
Table 11-2. ASHRAE CHP Analysis Tool Site Data Input Screen
for Addressable Thermal Loads
(Note: this table is from the ASHRAE CHP Analysis Tool and is only available in I-P units)
Addressable Thermal Loads1
Process Heat Type
Hot Water
Average Process Head Load
MBH2
0
Process Heat Load Deviation
%
0%
Space Heating Type
Hot Water
Max Space Heating Load
MBH
14,000
Chilled Water Reheat
MBH
Hot Water
%
10%
MBH
250
OA Fraction
Average Domestic Hot Water
Process Cooling Type
Average Process Cooling Load
Process Cooling Load Deviation
Max Space Cooling Load
Cooling
Tons
0
%
0%
Tons
1,120
Note 1: Input ‘0’ load value for nonaddressable loads
Note 2: MBH = 1000 Btu/h
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11.1.3.3 Energy Economics
Table 11-3 shows the electric load profile and cost available at the time of assessment.
The data in Table 11-4 are then entered into the Monthly Electric Billing Data section
of the ASHRAE CHP Analysis Tool (Table 11-5).
Figure 11-10. ASHRAE CHP Analysis Tool Addressable & Nonaddressable Loads
(million Btu/h per month)
(ASHRAE CHP Analysis Tool [I-P units only])
Table 11-3. Actual Electric Cost (Year 2000)
Month
Usage (kWh)
Demand kW
$/kWh
Total Cost, $
January
939,377
1961
0.0686
64,444
February
953,672
1969
0.0678
64,663
March
953,396
2000
0.0613
58,471
April
764,819
2190
0.0649
49,672
May
909,219
2074
0.0677
61,516
June
961,800
2067
0.0956
91,981
July
914,378
1999
0.1374
125,648
August
1,016,446
2054
0.1049
106,594
September
1,184,391
2367
0.1114
131,962
October
1,081,623
2176
0.0628
67,968
November
1,067,581
2040
0.0975
104,127
December
586,344
1945
0.0703
41,236
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Table 11-6 shows the natural gas load profile and cost available at the time of the
assessment.
The actual data in Table 11-6 must be projected to the future to incorporate known
growth. An additional 6.5 million Btu/h was projected. This is an approximate 87% energy
use increase, which is good enough for an initial feasibility assessment and is incorporated
in increasing both the energy and demand elements. The more difficult element at that
time was to project forward natural gas prices during a particularly volatile time in energy
markets. In this case, a future fixed cost was determined to be $6.23/dekatherm52.
Table 11-4. Projected Electric Use and Cost for CHP Plant Design
Month
Usage (KWh)
Demand kW
$/kWh
Cost, $
January
1,174,221
2451
0.1353
158,911
February
1,192,090
2461
0.1353
161,330
March
1,191,745
2500
0.1353
161,283
April
956,024
2738
0.1353
129,382
May
1,136,524
2593
0.1353
153,810
June
1,202,250
2584
0.1353
162,705
July
1,142,973
2499
0.1353
154,682
August
1,270,558
2568
0.1353
171,949
September
1,480,489
2959
0.1353
200,359
October
1,352,029
2720
0.1353
182,975
November
1,334,476
2550
0.1353
180,599
December
732,930
2431
0.1353
99,190
Table 11-5. Monthly Electric Billing Data ASHRAE CHP Analysis Tool Site Input
(Note: this table is from the ASHRAE CHP Analysis Tool and is only available in I-P units)
Monthly Billing Data
Jan
Feb
Mar
Apr
May
Jun
Billing days per month
31
28
31
30
31
30
Electric Use
Peak Demand
kWh 1,174,221 1,192,090 1,191,745
956,024
1,136,524 1,202,250
kW
1,961
1,969
2,000
2,190
2,074
2,067
$
158,911
161,330
161,283
129,382
153,810
162,705
Monthly Billing Data
Jul
Aug
Sep
Oct
Nov
Dec
Billing days per month
31
31
30
31
30
31
Total Bill
(Commodity, T&D)
Electric Use
Peak Demand
Total Bill
(Commodity, T&D)
52
kWh 1,142,973 1,270,558 1,480,489 1,352,029 1,334,476
732,930
kW
1,999
2,054
2,367
2,176
2,040
1,945
$
154,682
171,949
200,359
182,975
180,599
99,190
Unit of energy equal to 10 therms or one million British thermal units.
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Table 11-6. Actual Natural Gas Cost (Year 2000)
Month
Usage,
Therms
Usage,
DTherms*
Usage,
GJ
$/DT
$/GJ
l Cost, $
January
76,253
7625
8045
4.26
4.04
32,520
February
81,400
8140
8588
4.27
4.05
34,746
March
87,170
8717
9197
4.69
4.45
40,904
April
65,510
6551
6912
4.99
4.73
32,690
May
46,673
4667
4924
4.91
4.66
22,931
June
26,020
2602
2745
6.98
6.62
18,174
July
28,657
2866
3023
7.08
6.71
20,286
August
25,172
2517
2656
7.63
7.24
19,216
September
41,090
4109
4335
7.18
6.81
29,512
October
56,984
5698
6012
6.46
6.12
36,801
November
86,609
8661
9138
12.13
11.50
105,067
December
93,741
9374
9890
16.23
15.38
152,127
*DTherms = dekatherms = 10 therms = 1 million Btu.
The data in Table 11-7 are then entered into the Monthly Natural Gas Billing Data
section of the ASHRAE CHP Analysis Tool (Table 11-5).
11.1.4 CHP System Technical Overview
The nature of the addressable thermal loads at the university is as follows:
• Base loading any domestic hot water load is a starting point to displace natural gas.
• Hot-water heating load will displace natural gas during winter months.
• Hot water to provide absorption generated chilled water is likely essential to deliver
operating hours required for CHP efficiency and pay back the capital investment.
Figure 11-11 presents a logical CHP hot-water system schematic. Note that the
single effect absorption chiller is not shown but would be fed by the hot-water loop.
11.1.4.1 CHP Equipment Selection
Table 11-8 shows the ASHRAE CHP Analysis Tool Site Data Input Screen for the
CHP System. There are relatively few data entry points for the system. Essentially, the
engine generator power, generator fuel efficiency, and thermal recovery capacities (at
appropriate temperature levels) must be entered. In macro terms, enter the generator
ISO power rating at 100% capacity, jacket water heat recovery, and the exhaust heat
recovery as a percentage of the fuel input. The data entered in Table 11-9 are from the
selected engine/generator; however, the default values can provide a good initial
screening if this information is not readily available. To define this particular CHP
plant, select the absorption chiller from the dropdown menu. In this case, a singleeffect lithium bromide machine is selected.
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Table 11-7. Projected Natural Gas Use for the CHP Plant Design
Usage
Therms
Use Dtherms
Usage,
GJ
$/DT
$/GJ
Cost, $
January
116,921
11,692
12,336
6.23
5.90
72,842
February
124,813
12,481
13,168
6.23
5.90
77,758
March
133,661
13,366
14,102
6.23
5.90
83,271
April
100,449
10,045
10,598
6.23
5.90
62,580
May
71,565
7,156
7,550
6.23
5.90
44,585
June
39,898
3,990
4,209
6.23
5.90
24,856
July
43,940
4,394
4,636
6.23
5.90
27,375
August
38,598
3,860
4,072
6.23
5.90
24,046
September
63,004
6,300
6,647
6.23
5.90
39,252
October
87,376
8,738
9,219
6.23
5.90
54,435
November
132,801
13,280
14,011
6.23
5.90
82,735
December
143,737
14,374
15,165
6.23
5.90
89,548
Month
From Figure 11-12, the calculated performance of the single effect chiller is
333 tons, which is within 10% of the actual unit selected. Figure 11-13 shows the
16-cylinder, 1500 kW engine generator set.
Figure 11-14 shows the exhaust heat recovery heat exchanger (left in green) and
SCR/particulate filter exhaust aftertreatment system (right silver box).
11.1.4.2 CHP Performance
There are several ways of expressing CHP performance. This section examines the
CHP system performance by examining the system capacity versus average electric and
thermal load and average demand (Figure 11-15), and average electric and thermal
demand versus CHP system load factor (Figure 11-16). Figure 11-15 provides a clear
picture of a CHP system that is well suited to service the average electric load of the site,
oversized for the average heating demand and slightly oversized for the average cooling
load serviced by the absorption chiller. Figure 11-16 shows a high CHP system electric
supply load factor agreeing with Figure 11-15. The 40% CHP system load factor shows
large heating fluctuation with significant heating load hours and significant overcapacity
for heating heat recovery. The 45% cooling capacity load factor shows significant cooling
overcapacity. Adding heating and/or cooling load to the system will improve performance.
Total CHP efficiency is found in section 11.1.5.1, “Overall Energy Performance”.
11.1.4.3 CHP Interconnection
Interconnection with the electric utility was required. Interconnection is an essential
element in ensuring the reliability of the plant operations. The site utility was bound by
the state’s standard interconnection rule, which follows ANSI/IEEE 1547-2003, Standard
for Interconnecting Distributed Resources with Electric Power Systems (IEEE 1547).
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Figure 11-11. CHP System Schematic
Figure 11-11 (SI). CHP System Schematic
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Table 11-8. Monthly Natural Gas Billing Data ASHRAE CHP Analysis Tool Site Input
(Note: this table is from the ASHRAE CHP Analysis Tool and is only available in I-P units)
Monthly Billing
Data
Jan
Feb
Mar
Apr
May
Jun
Billing days
per month
31
28
31
30
31
30
DTherm
11,692
12,481
13,366
10,045
7,156
3,990
GJ
12,336
13,168
14,102
10,598
7,550
4,210
$
$72,842
$77,758
$83,271
$62,580
$44,585
$24,856
Monthly Billing
Data
Jul
Aug
Sep
Oct
Nov
Dec
Billing days
per month
31
31
30
31
30
31
DTherm
4,394
3,860
6,300
8,738
13,280
14,374
GJ
4,636
4,073
6,647
9,219
14,011
15,165
$
$27,375
$24,046
$39,252
$54,435
$82,735
$89,548
Fuel Use
Fuel Cost
Fuel Use
Fuel Cost
Nominal CHP System Performance
System Type
ICE > 700 kW
Suggested
Exhaust Use:
Hot Water
Electric Power Output
kW
1,500
Efficiencies
Chiller Use:
Cooling
Electric Efficiency
LHV
36%
38%
Chiller Type:
1 Effect
Exhaust HR Efficiency
LHV
19%
18%
Chiller Output Temp:
> 40 F
Jacket HR Efficiency
LHV
21%
21%
Chiller Capacity (Tons):
333
Fuel Input (LHV)
MBtu
14,225
Chiller Maint. per Year:
$10,200
Exhaust HR
MBtu
2,717
CHP Maint. per kWh:
$0,0175
Jacket Water HR
MBtu
2,987
Parasitics:
2%
CHP System Efficiency
LHV
76%
Heat Rate (Btu/kWh):
9,483
Figure 11-12. ASHRAE CHP Analysis Tool Site Data Input Screen for the CHP System
(Note: this table is from the ASHRAE CHP Analysis Tool and is only available in I-P units)
11.1.4.4 CHP Environmental Impact
To quickly assess the environmental impact, EPA’s Combined Heat and Power
(CHP) Emissions Calculator53 compares the anticipated carbon dioxide (CO2), methane
(CH4), nitrous oxide (N2O), carbon dioxide equivalent (CO2e), sulfur dioxide (SO2), and
nitrogen oxide (NOx) from a CHP system to those of a separate heat and power system.
The calculator uses fuel-specific CO2, CH4, and N2O emissions factors used in the EPA
Greenhouse Gas Reporting Program, region-specific transmission and distribution
(T&D) loss values, and data from Emissions & Generation Resource Integrated
Database (eGRID) 2012. The calculator also presents estimated emissions reductions
as metric tons of carbon equivalent and emissions from passenger vehicles.
Figure 11-17 shows that the CHP system equipped with an SCR substantially
reduces emissions evaluated versus the eGRID all-fossil average for California.
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Figure 11-13. 16-Cylinder, 1500 rpm Natural Gas Compressor
Figure 11-14. Exhaust Heat Recovery Heat Exchanger (left), Exhaust SCR (right)
11.1.4.5 CHP Plant Operations
The university’s 1500 kW CHP plant presently has an availability of 93% per year.
During the summer months, the majority of the engine heat is used to drive the 350 ton,
single-effect absorption chiller. Similarly, during the winter months, the majority of the
engine heat is used to produce heating hot water. Some heating hot water is also used
to heat the campus swimming pool and to provide for domestic hot water to the pool
showers (the only domestic hot water produced with central heating hot water).
As shown in Figure 11-10, engine heat is obtained from both the engine jacket and
from the engine exhaust via a hot water heat recovery generator producing 224°F
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Figure 11-15. ASHRAE CHP Analysis Tool Average Electric and Thermal Demand versus
CHP System Capacity
(ASHRAE CHP Analysis Tool [I-P units only])
Figure 11-16. ASHRAE CHP Analysis Tool Average Electric and Thermal Demand versus
CHP System Load Factor
(ASHRAE CHP Analysis Tool [I-P units only])
(107°C) jacket water (JW). Note that, because a relatively expensive 50% glycol mixture
is used in the JW and the JW system has different temperature requirements from the
campus hot-water system, the JW system is separated from the campus HW system with
a heat exchanger.. The campus hot water is then either pumped out to the campus for
space heating or used directly at the plant to drive the 350 ton absorption chiller.
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Figure 11-17. Emissions Results from EPA’s CHP Emissions Calculator
(Note: this figure is from EPA CHP Emissions Calculator and is only available in I-P units)
While rarely used, in the case where there is insufficient hot-water load, a dump
radiator can reject heat to the atmosphere to ensure “cool” (193°F [89°C] maximum)
JW supply to the engine. During engine startup, a 3-way thermostatic valve allows the
jacket water to recirculate until it reaches the proper temperature.
11.1.5 Measured Performance
11.1.5.1 Overall Energy Performance
The overall CHP system performance is found in the ASHRAE CHP Analysis Tool
System Input worksheet (Figure 11-18). This figure shows an 83% electric load factor
(highlighted), which is below the desired 85 to 100% level and suggests a need to scrutinize
the site, reassess the assumptions, and perhaps downsize the system. Note that this does
not rule out this system, but it suggests that the economics must be positive to proceed.
Because this is an assessment of a system that was installed, these data will not be changed.
11.1.5.2 Overall Economic Performance
Figure 11-19 presents the capital cost calculations. The 3.5% adjustment was an
input to match the engineer’s detailed estimate. The $1,000,000 state grant was available
at the time of the system evaluation and the federal investment tax credit (ITC) was
not available.
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Figure 11-18. ASHRAE CHP Analysis Tool CHP System Performance
(ASHRAE CHP Analysis Tool [I-P units only])
Figure 11-19. ASHRAE CHP Analysis Tool Capital Cost Estimate
Figure 11-20 provides an annual net savings of $635,078, which is in general
agreement with the engineer’s detailed estimate.
Figure 11-21 provides a graphical representation of the cash flow and a brief utility
rate sensitivity assessment.
11.1.6 Case Study Acknowledgements
Material for this case study was provided by Goss Engineering, Inc., Corona, CA.
11.2 PHARMACEUTICAL RESEARCH/MANUFACTURING FACILITY
Industrial applications for CHP are generally straightforward, because of the
availability of large thermal load sinks, which are often in a single form, such as highpressure steam. Although economic performance requirements for many industrial
clients may be more demanding, the scale and availability of large 24/7 loads make
industrial CHP the largest single application from a capacity perspective.
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Figure 11-20. ASHRAE CHP Analysis Tool Economic Performance
(ASHRAE CHP Analysis Tool [I-P units only])
Figure 11-21. ASHRAE CHP Analysis Tool Payback and Utility Cost Sensitivity
(ASHRAE CHP Analysis Tool [I-P units only])
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11.2.1 Introduction
As with all global manufacturing operations, biotechnology companies and
pharmaceutical manufacturers continue to seek ways to reduce energy costs as well as
improve process reliability. In addition, many global manufacturers are trying to move
towards environmentally friendly, more sustainable processes. Energy requirements for
a pharmaceutical manufacturing facility involve thermal, electrical, and pneumatic
loads, which generally apply to the manufacturing process in the following ways:
• Process thermal energy: Input of heat via high-quality fluids in reactors,
fermenters, and mixers. This particular site is a research/manufacturing facility
with thermal loads focusing on sterilization and humidification.
• Process chilling: For product cooling, preservation, cooling production tanks,
and cleaning stations.
• Compressed air: For process controls, pressurization of process tanks, etc.
• Vacuum: For suction intake of materials in the process, or for packaging.
• Electricity: Reliable electricity to supply machines, instrumentation, control
systems, and measurement equipment.
The 24/7 operation and coincidence of thermal, pneumatic, and electric loads
makes such processes amenable to the application of CHP, which can reduce energy
costs, improve reliability, and reduce greenhouse gas footprint.
11.2.2 Project History
In 2004, a pharmaceutical company facility in Cambridge, Massachusetts (see
Figure 11-22), needed a reliable supply of steam for their batch production. This area
of Cambridge also suffered from power quality issues, including power outages, which
had caused serious production problems, with the loss of electricity for 1 h meaning as
much as 24 to 36 days of product loss because of batch production processes.
The original option was to simply supplement the steam supply with on-site boilers,
but initial studies identified the availability of high, coincident electric and thermal loads
that made the facility a good fit for combined heat and power. CHP added significant
economic benefit, both in terms of energy cost savings as well as avoidance of production
loss, because of higher electric reliability. An energy master plan and feasibility study
addressing the most reliable energy solution for the campus suggested the development
of a CHP plant to serve six buildings with electricity and five with high-pressure steam.
Today, with 5 MW of CHP capacity, the operation provides energy for the campus’
entire thermal load and for the majority of its electric load. The electric grid is still used
for a portion of the facility’s power needs, and the electric grid serves as a backup source
of power. In addition, the on-site CHP plant has the ability to obtain steam from the
network, or sell its excess steam into the network for use by other customers.
11.2.3 Initial Project Parameters
The facility campus consists of 750,000 ft2 of space that includes manufacturing
facilities, laboratories, process development, datacenter, and office space, with more
than 2000 employees. Because of the sensitive nature of energy use data for industrial
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facilities, detailed load shapes cannot be made available, other than stating that the
facility had a peak electric demand of approximately 10 MW, a peak steam demand of
approximately 35,000 lb (15 900 kg) per hour, and operates 24 h/day, 7 days/week.
Electric peaks occur in summer coincident with high ambient temperatures, and there
is a consistent base load of approximately 5 MW available year round. Steam demand
peaks in winter, but there are also significant process steam and process and spaceconditioning cooling needs in summer. The ASHRAE CHP Analysis Tool was used to
compare the results with actual performance reports from the site (Figure 11-23).
To develop the load profile, the electric monthly demand, use, and cost, as well as
steam use and cost were input to the model. Because the facility used district steam
purchased from a third party, the total throughput in million Btu per month was entered
together with the total monthly steam cost. To create the proper load profile, the various
heater and boiler efficiencies were set to 98%, which allows for 2% leakage and piping
heat losses to the main loads.
11.2.3.1 Energy Economics
Utility reliability was a key driving issue, but economic advantage and payback of
the initial investment were also important considerations. The facility was purchasing
electricity from the grid at close to $0.08/kWh and was purchasing steam commodity
at close to $15 per 1000 lb plus a capacity payment from the local district steam network
for the period studied. Natural gas used to drive the CHP system was estimated to be
$7.00 per million Btu.
Figure 11-22. Aerial View of the Pharmaceutical Research/Manufacturing Facility
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11.2.4 CHP System Technical Overview
11.2.4.1 CHP Equipment Selection
Based on the site data entered, a 5 MW combustion turbine was selected for
modeling with input parameters as described in Figure 11-24. Anticipated load growth
at the site dictated that the electric and steam base loads would be larger than those
suggested by historic data. However, the model’s historic site energy use data was not
adjusted to reflect this; therefore, electric and thermal load factors for the selected
configuration were allowed to be lower than typically required.
Based on the equipment selection, the 5 MW CHP plant would have a 76% electric
load factor, and 84% of the steam output would be used by space heating and process
Figure 11-23. Breakout of Addressable Loads
(ASHRAE CHP Analysis Tool [I-P units only])
Figure 11-24. CHP System Input Parameters
(ASHRAE CHP Analysis Tool [I-P units only])
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heating needs, with the remainder being diverted to chilled-water production in
summer. The model will only select a chiller based on the excess steam capacity
remaining after all addressable heating uses have been satisfied. Without consideration
of load growth or steam reliability requirements, the model suggests that a small unit
may offer better performance.
However, with consideration of future load growth and steam reliability issues, the
site actually used a dual-fuel (natural gas and ultralow-sulfur diesel) combustion turbine
with a site adjusted 5.3 MW capacity (Figure 11-25). The system included low-NOx
premix combustion and an inlet air cooler.
A heat recovery steam generator (HRSG) was added to convert the exhaust heat
energy to steam. The HRSG was fitted with a supplemental duct burner that increased
the steam output of the system from 25,000 lb/h to 52,000 lb/h. A selective catalytic
reduction (SCR) unit was incorporated to meet the strict emissions requirements for the
area. Two additional independent dual-fuel steam boilers were added for steam reliability.
Although the ASHRAE CHP Analysis Tool does not allow for duct burners or
additional savings from on-site boilers versus purchased steam, it does reflect the
baseload case against a basic CHP plant. The addition of duct burners and supplemental
boilers should only serve to enhance the base-case economics.
11.2.4.2 CHP Performance
Based on the 5 MW model configuration and historic site data, the modeled plant
had a 76% electric load factor and an 84% steam load factor with any excess steam
output being diverted to a double-effect steam-driven absorption chiller (Figure 11-26).
Figure 11-25. Low-NOx Combustor
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The CT generator operates in parallel with the electric utility and is equipped with
load shedding switchgear for island operation during a utility failure. With the two
supplemental boilers providing backup and peak steam capacity, the plant also
maintains an automated connection to the district steam system to provide a third level
of backup for the steam supply (Figure 11-27).
11.2.4.3 CHP Interconnection
The plant is connected in parallel with the local electric utility at 13.8 kV during
normal operation. In the event of a grid outage, the switchgear is designed to disconnect
the generator from the utility and run in island mode. The electric architecture has
accommodation for a second unit in the future. A dedicated 400 psig (2758 kPa [gage])
natural gas supply is provided by the utility so that the turbine does not need a gas
pressure booster. The unit is also capable of operating on ultralow-sulfur diesel, with
approximately 20,000 gal (76 000 L) of on-site storage that could run the system for
24 to 36 h. The plant can also be black-started using an on-site diesel generator.
11.2.4.4 CHP Environmental Impact
The combination of low-NOx combustion technology and SCR allowed the plant to
achieve the lowest permitted emissions levels in the state and reduce greenhouse gas
emissions by approximately 36,000 metric tons per year.
11.2.5 Measured Performance
11.2.5.1 Overall Energy Performance
Based on the modeled site load data and 5 MW CHP configuration, the system
meets the main efficiency criteria by achieving over 60% fuel use efficiency on a higher
heating value basis. Although the electric load factor is not as high as typically desired,
future load growth will boost electric load factor to a higher level (Figure 11-28).
Figure 11-26. ASHRAE CHP Analysis Tool Load Demand and CHP Load Factor
(ASHRAE CHP Analysis Tool [I-P units only])
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Figure 11-27. Combustion Turbine Generator
Installation was completed, and the plant was commissioned in 2007, providing a
reliable and very efficient source of heat and power for the campus. The state-of-the-art
facility is the recipient of the Cambridge GoGreen Award and has been a model for
many subsequent CHP implementations.
11.2.5.2 Overall Economic Performance
The system was installed in the basement level and included low-NOx technology.
The CHP system budget cost was adjusted by 25% to reflect these additional items,
resulting in a cost of $3112/kW (Figure 11-29).
The operation of the system benefited from a New England ISO derived income of
$15,000 per month reflected in the modeled economic evaluation (Figure 11-30).
Since initial start-up, a series of upgrades has improved the ROI of the plant. The
modeled economics are based on 2004 energy costs and demonstrate an acceptable
payback, considering the significant indirect cost savings of improved steam and power
reliability. With escalations in energy costs, in 2010, the plant actually saved the facility
$4 million in energy costs and paid off the initial investment within the first four years
of operation.
11.2.6 Case Study Acknowledgements
Material for this case study was provided by the following:
• Biogen Idec, Cambridge, MA
• Source One, Boston, MA
• Veolia Energy/Dalkia Energy, Boston, MA
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Figure 11-28. ASHRAE CHP Analysis Tool System Performance
(ASHRAE CHP Analysis Tool [I-P units only])
Figure 11-29. Modeled CHP System Budget Cost
Figure 11-30. ASHRAE CHP Analysis Tool Economic Evaluation
(ASHRAE CHP Analysis Tool [I-P units only])
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11.3 LUXURY FULL-SERVICE HOTEL
This case study provides a departure from the conventional CHP systems described
in the previous case studies in that electricity, cooling chilled water, and heating hot
water are supplied to the building from a neighboring office building, and domestic
hot-water heat is supplied from a district steam loop. Therefore, this case study will
not use the ASHRAE CHP Analysis Tool, but instead will walk through the addressable
load analyses using a publically available thermal-load profile for a full-service hotel.
11.3.1 Introduction
A high-rise office building located in the Logan Square neighborhood of
Philadelphia, Pennsylvania, is located just behind a hotel. The building stands at 400 ft
(122 m) with 30 floors, and was completed in 1983 (Figure 11-31). Adjacent to the
office building is a world-renowned 364-room 330,000 ft2 luxury hotel. The hotel also
contains three restaurants, a full-service hotel laundry, and an indoor pool and spa. All
sites posed interesting engineering and economic challenges, and the luxury hotel was
no different. The hotel purchases electricity, hot water for heating, and chilled water for
cooling from the office building. The hotel further purchases steam for domestic hot
water from a district system and natural gas from the local utility54 for cooking. This
present location is an extraordinary, but important, urban case study, because energy
data is multifaceted, complex, and somewhat limited. Nevertheless, this case study
demonstrates the fundamentals of defining addressable thermal loads first, understanding
the cost of reaching these loads, assessing the energy economics, and developing a
sound economic solution.
11.3.2 Project History
Historically, the hotel received hot water from a central plant and used a primary
loop booster pump to circulate its heating water supply through distribution pipes.
A new, dedicated isolation heat exchanger was installed between the hydronic
heating riser and the central plant, with an injection pump feeding circulating hot water
from the riser to the new microturbines. A preheat heat exchanger was also installed to
preheat domestic hot water, and additional heat exchangers were piped into the heating
water loop to serve the kitchen, laundry, pool, and spa. The injection pump ensures that
30 to 40 gal (115 to 150 L) of water get to the microturbines every minute. The
microturbines impart 1.2 million Btu/h (350 kW) to the heating water loop. The
isolation heat exchanger transfers heat from the office building heating-water loop
(supply) to the hotel heating-water loop.
The $1.05 million solution included installing three microturbines, which generate
174 kW, or 30% of the hotel’s overall electricity. Additionally, the new system,
completed in October 2009, supplies all of the building’s day-to-day domestic hot water
and satisfies 15% of its heating needs.
54
Local utility receives delivery charge, and natural gas is purchased as a commodity.
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Figure 11-31. Four Seasons
11.3.3 Initial Project Parameters
11.3.3.1 Electric Load Profiles
Electricity for the hotel is provided through three electrical submeters from the
adjacent office building. These submeters provide commodity readings only, so the first
task is to understand how to parse monthly electric consumption into a rational load
profile. An EPA study of an instrumented CHP system in a full service hotel55 provides
a starting point in developing a load profile for the hotel. According to the study, peak/
average load for a full service hotel is about 210% of the average and the minimum/
average load is about 70% of the average.
In 2008, before the CHP plant was installed in the hotel, the monthly electric usage
was available from invoices and is depicted in Figure 11-32. Electricity is supplied
under contract from the neighboring office building electric submeters to provide
general power and lighting to the hotel.
Note that the minimum hourly average electricity demand was 600 kW per hour
which occurred in January of 2008 (Figure 11-33).
Using the EPA data56 and applying it to the hotel yields a potential daily range from
about 400 to 1200 kW.
55, 56
CHP in the Hotel and Casino Market Sectors. U.S. EPA CHP Partnership. December 2005.
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Figure 11-32. 2008 Monthly Electricity Usage
Figure 11-33. 2008 Average Hourly Electricity Usage
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The CHP plant developer at that time had a single commercial product (a
microturbine rated at 65 kW ISO and 58 kW net) that could be configured in arrays.
From a purely electrical perspective, Figure 11-34 shows that up to six microturbines
could be installed and not exceed the monthly average minimum power requirement
projected using the EPA data.
Figure 11-35 shows a portion of the results of monitoring the EPA studied hotel
electric use for a period of almost two weeks during the summer of 2002. The minimum
nighttime electric load was 304 kW, and the maximum peak electric use occurring at
10:00 p.m., July 17th, (not shown) was 540 kW. The minimum electric loads during the
winter months were 5 to 10% lower.
The problem with following the above daily example is that the electricity is not
cooling dominated, because the space conditioning electricity is borne by the adjacent
hotel. Extrapolating from Figure 11-34, the 400 kW per hour monthly usage is a good
limit at this stage of analysis.
11.3.3.2 Thermal Load Profiles
Thermal energy is provided to the hotel through four energy streams:
• Natural gas is provided to the hotel by the local natural gas utility for cooking only.
• Hot water is supplied under contract from the adjacent office building to provide
space heating to the hotel.
• Chilled water is supplied under contract from the adjacent office building to
provide space cooling to the hotel.
• Steam is supplied under contract from a district steam system and is converted to
hot water for guests, the laundry, the kitchen, the pool, and the spa.
Figure 11-36 shows the steam purchased from the district loop is used for domestic
hot water use, and hot water purchased from the neighboring office building, supplied
for space heating, has the potential to be addressed by a CHP system. However, the
domestic hot water is divided into separately addressed heat exchangers by end use,
which would require access by the CHP thermal loop.
Figure 11-37 presents a typical thermal load profile for a full service hotel based
on measurement and verification data57.
Figure 11-38 takes the data shown in Figure 11-37 and apportions it to the domestic
hot water load.
Figure 11-39 presents the monthly thermal load shown in Figure 11-38 as average
hourly thermal load and superimposes the hourly thermal heat recovery potential of
one to six microturbines producing 175°F (79.4°C) hot water returning at 155°F
(68.3°C). In general terms, given the data available, three microturbines would have a
consistently high thermal capacity factor.
57
CHP in the Hotel and Casino Market Sectors. U.S. EPA CHP Partnership. December 2005.
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Figure 11-34. 2008 Average Hourly Electricity Usage with Microturbine Capacity
Figure 11-35. EPA Full Service Hotel Data58
58
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Comparing the 24 h load curve in Figure 11-37 and the average and minimum
thermal load curves, an estimated 80% thermal load factor can be applied to a CHP
plant using three microturbines and providing thermal energy for space heating, guest
hot water, the laundry, kitchen, pool, and spa (Figure 11-40).
Figure 11-36. 2008 Thermal Energy Supply
Figure 11-36 (SI). 2008 Thermal Energy Supply
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Figure 11-37. EPA Full-Service Hotel Data
Figure 11-37 (SI). EPA Full-Service Hotel Data
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Figure 11-38. 2008 Thermal Usage by End Use
Figure 11-38 (SI). 2008 Thermal Usage by End Use
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Figure 11-39. 2008 Average Hourly Thermal Usage by End Use with CHP Recovered Heat
Figure 11-39 (SI). 2008 Average Hourly Thermal Usage by End Use with CHP Recovered Heat
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Figure 11-40. 2008 Minimum Hourly Thermal Usage by End Use with CHP Recovered Heat
Figure 11-40 (SI). 2008 Minimum Hourly Thermal Usage by End Use with CHP Recovered Heat
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11.3.3.3 Energy Economics
The energy economics for this site particularly support a microturbine-based CHP
plant in that electricity and heating hot water are supplied from the neighboring office
building (Figure 11-41). The economics determining the cost of these services include
the usual energy commodity, capacity, and demand charges, plus a prorated operations
and maintenance charge based on a direct proration of the total utility bills, plus the
operation and maintenance performed by the office building, and a fee for service. The
operations and maintenance proration means that, if the hotel requires heating hot
water in the summer (at night for example) or chilled water for cooling in the winter
and the office building requires no heating or cooling respectively, the hotel bears the
total operation and maintenance cost for that month. Furthermore, the domestic hot
water (DHW) heat is supplied by a district steam system with a dwindling customer
base. This atypical energy purchase arrangement shows that, in 2008, actual energy
costs for heating hot water and steam for DHW heating were greater than electricity on
a $/106 Btu ($/GJ) basis.
Note that 2008 was the year when energy costs peaked. Actual steam cost for 2009
was $28.43/106 Btu ($26.95/GJ), reflecting the economic downturn, and $30.19/106
Btu ($28.62/GJ) in 2010. Of course, the designer in 2008 did not have the certainty of
foresight regarding macro-economic events. However, a prudent designer might hedge
his/her bets and use $32/106 Btu ($30.33/GJ) for calculation purposes. The heating hot
water cost fell to $36.80/106 Btu ($34.88/GJ) in 2009 and then rose to $39.93/106 Btu
($37.85/GJ) in 2010.
The energy costs in Table 11-9 would lead to selecting a CHP plant favoring
thermal energy production over electricity production (a low thermal-to-electric [T/E]
ratio system) ,which favors microturbines over reciprocating engines.
Figure 11-41. Three Microturbines with Integrated Hot-Water Heat Recovery Heat Exchangers
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The project initiation economics include the following:
• Installed capital cost for three microturbines, heating hot water isolation heat
exchanger; DHW heat exchanger; repiping the laundry heat exchanger; repiping
the kitchen heat exchanger; repiping the pool heat exchanger; repiping the spa heat
exchanger; installation of all necessary piping, valves, and pumps; interconnection
and all electrical services: $1,050,000.
• Interest rate—the natural gas utility offered a 0% interest loan to be paid back as
a surcharge of natural gas sales: 0%.
• Natural gas cost in years 1-2 ($/Decatherm): $12.00.
• Natural gas cost in years 1-2 ($/GJ): $11.37.
• Natural gas cost in year 3 ($/Decatherm): $10.00.
• Natural gas cost in years 1-2 ($/GJ): $9.48.
• Natural gas escalation in years 4-10: 5%.
• Electricity cost ($/kWh): $0.10.
• Electricity escalation: 3%.
• Steam cost ($/106 Btu): $37.15.
• Steam cost ($/GJ): $35.21.
• Domestic hot water and space heating cost ($/106 Btu): $37.43.
• Domestic hot water and space heating cost ($/GJ): $35.48.
• Steam (and DHW) escalation: 5%.
• Fixed maintenance costs ($/kW): $0.019.
Based on these assumptions, a simple economic calculation can be performed,
yielding significant economic return for this particular site (Table 11-10).
The exceptional economics (104.84% IRR, shown in Table 11-10) are a direct
function of the source and high cost of the thermal energy streams and are dominated
by the incentive provided by the natural gas utility. This municipal utility provided a
0% interest loan for the project that is being repaid by a fee on the natural gas being
consumed by the CHP plant.
Table 11-11 shows the impact of a conventional 0% interest loan booked at the
beginning of year one, this reduces the IRR to a still respectable 28.9% and also reduces
the net present value (NPV) by half.
Table 11-9. 2008 Energy Costs
$/106 Btu
$/GJ
Electricity
$29.12
$27.60
Steam
$37.15
$35.21
Heating Hot Water
$37.43
$35.48
Natural Gas
$12.00
$11.37
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Table 11-10. Initial Project Return on Investment without Initial Capital Expenditure
Year
0
1
2
3
4
5
Domestic hot water
heating
$244,726
$256,962
$269,810
$283,301
$297,466
Space heating
$91,671
$96,254
$101,067
$106,120
$111,426
Electricity production
$146,562
$147,939
$149,330
$150,734
$152,150
2.00%
2.00%
2.00%
2.00%
$501,155
$520,207
$540,154
$561,042
Electrical generation
degradation per year*
Total utility savings
$482,958
Costs
Capital cost
$0
Natural gas consumption
-$255,320
-$255,320
-$212,767
-$223,405
-$234,576
Maintenance costs
-$27,847
-$27,847
-$27,847
-$27,847
-$27,847
Total costs
-$283,167
-$283,167
-$240,614
-$251,252
-$262,422
Annual net operating
savings
$199,791
$217,988
$279,593
$288,902
$298,620
Capital recovery
-$199,000
-$199,000
-$199,000
-$199,000
-$199,000
$791
$18,988
$80,593
$89,902
$99,620
$791
$19,779
$100,373
$190,275
$289,895
Annual cash flow
Total cash flow
-$30,000
Cumulative cash flow
Year
6
7
8
9
10
Domestic hot water
heating
$312,339
$327,956
$344,354
$361,571
$379,650
Space heating
$116,998
$122,848
$128,990
$135,439
$142,211
Electricity production
$169,905
$171,502
$173,114
$174,741
$176,384
Electrical generation
degradation per year*
0.00%
2.00%
2.00%
2.00%
2.00%
Total utility savings
$599,241
$622,305
$646,458
$671,752
$698,245
Costs
$0
$0
$0
$0
$0
Capital cost
$0
$0
$0
$0
$0
Natural gas consumption
-$246,304
-$258,620
-$271,551
-$285,128
-$299,384
Maintenance costs
-$27,847
-$27,847
-$27,847
-$27,847
-$27,847
Total costs
-$274,151
-$286,466
-$299,397
-$312,975
-$327,231
Annual cash flow
$0
$0
$0
$0
$0
Annual net operating
savings
$325,090
$335,839
$347,061
$358,777
$371,014
Total cash flow
-$55,000
$0
$0
$0
$0
Cumulative cash flow
$270,090
$335,839
$347,061
$358,777
$371,014
IRR
104.84%
NPV
$538,225
* Microturbines will be rebuilt in year 5.
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Table 11-11. Initial Project Return on Investment
without Initial Capital Expenditure
Year
0
1
2
3
4
5
Domestic hot water
heating
$244,726
$256,962
$269,810
$283,301
$297,466
Space heating
$91,671
$96,254
$101,067
$106,120
$111,426
Electricity production
$146,562
$147,939
$149,330
$150,734
$152,150
2.00%
2.00%
2.00%
2.00%
$501,155
$520,207
$540,154
$561,042
Electrical generation
degradation per year*
Total utility savings
$482,958
Costs
Capital cost
-$1,050,000
Natural gas consumption
-$255,320
-$255,320
-$212,767
-$223,405
-$234,576
Maintenance costs
-$27,847
-$27,847
-$27,847
-$27,847
-$27,847
Total costs
-$1,333,167
-$283,167
-$240,614
-$251,252
-$262,422
-$850,209
$217,988
$279,593
$288,902
$298,620
-$850,209
$217,988
$279,593
$288,902
$298,620
-$850,209
-$632,221
-$352,627
-$63,725
$234,895
Annual cash flow
Annual net operating
savings
Total cash flow
-$30,000
Cumulative cash flow
Year
0
1
2
3
4
Domestic hot water
heating
$312,339
$327,956
$344,354
$361,571
$379,650
Space heating
$116,998
$122,848
$128,990
$135,439
$142,211
Electricity production
$169,905
$171,502
$173,114
$174,741
$176,384
Electrical generation
degradation per year*
0.00%
2.00%
2.00%
2.00%
2.00%
Total utility savings
$599,241
$622,305
$646,458
$671,752
$698,245
Costs
$0
$0
$0
$0
$0
Capital cost
$0
$0
$0
$0
$0
Natural gas consumption -$246,304
-$258,620
-$271,551
-$285,128
-$299,384
Maintenance costs
-$27,847
-$27,847
-$27,847
-$27,847
-$27,847
Total costs
-$274,151
-$286,466
-$299,397
-$312,975
-$327,231
Annual cash flow
$0
$0
$0
$0
$0
Annual net operating
savings
$325,090
$335,839
$347,061
$358,777
$371,014
Total cash flow
$325,090
$335,839
$347,061
$358,777
$371,014
Cumulative cash flow
$559,986
$895,825
$1,242,885
$1,601,663
$1,972,677
IRR
28.89%
NPV
$276,776
5
* Microturbines will be rebuilt in year 5.
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11.3.4 CHP System Technical Overview
11.3.4.1 CHP Equipment Selection
Three nominal 65 kW (58 kW net) microturbines were installed on the hotel roof
and were in operation in October of 2009. The thermal integration of the microturbines
consisted of the following (see Figure 11-42):
1. A plate-and-frame isolation heat exchanger is installed between the office building
and the hotel. This avoids the hotel sending back hot water at a higher temperature
than it receives when the hotel thermal load falls below the CHP plant capacity.
Furthermore, the isolation heat exchanger simplifies the thermal system design.
2. The hotel heating thermal loop receives heat (now isolated) from the office
building’s hot water loop. This heated hot water is pumped to the hotel roof. On
each floor, heating hot water supplies heat through a heating coil located in a
floor air-handling unit, which in turn supplies conditioned air to the guest rooms
and hallway of each floor.
Figure 11-42. Hotel Thermal Loop
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3. An injection pump extracts 240 gpm (15 L/s) to be heated by the microturbine
heat recovery systems and reinjects the hot water back into the return line where
it returns to the isolation heat exchanger to pick up more heat from the office
building heating loop.
4. A new domestic hot-water preheating heat exchanger is tied into the hotel
heating loop to extract microturbine heat.
5. The laundry, kitchen, pool, and spa brazed-plate heat exchangers are added to
recover heat for the heating loop and supply these respective end uses.
11.3.4.2 CHP Performance
The performance of the three microturbines generally follows the predicted
performance, except that for four to six weeks during the summertime there is not
enough thermal load to warrant their operation. Figure 11-43 shows the actual hotwater usage for July 13 to July 19 during 2010, indicating enough thermal load to
justify operating the array at about 40% capacity, which was deemed uneconomical
during that time of year. Figure 11-44 shows actual hot-water usage from October 24
to October 31 during 2009, indicating enough thermal load to justify operating the
array at about 87.5% capacity.
The initial assessment accounted for an 80% load factor, including a two week
shutdown that amounts to about 10 weeks of downtime.
11.3.4.3 CHP Interconnection
Figure 11-45 is the single-line electrical schematic for the project. The three
microturbines in the red box were planned for future installation. Note that the three
microturbines are interconnected directly to the load line using their built-in protective
relays. The three microturbines could operate using the manufacturer’s master/slave
control protocol, which regulates required power output of all three microturbines in
synchronization. This means that, if 116 kW output were required from the microturbine
array instead of the 174 kW net array capacity, all three microturbines would operate at
38.8 kW output versus two microturbines operating at 58 kW. However, the array at the
hotel shuts down one turbine, in this case, allowing the two remaining turbines to
operate at full capacity. The microturbine control unit evaluates the number of hours of
runtime and alternates them to balance the hours. Note: the array is designed to operate
only in grid parallel.
11.3.4.4 CHP Environmental Impact
Each microturbine exhaust contains less than 9 ppmvd (19 mg/m3) NOx emissions
at 15% O2, which is equivalent to 0.46 lb/MWhe (0.21 kG/MWhe).
The microturbine-based CHP system annually is calculated to reduce CO2e by 425
tons per year, which is equivalent to removing 70 cars from the road. The reduction in
district steam usage by 44% is also equal to saving 1000 gal (3785 L) of potable water
per year.
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Figure 11-43. Actual Hot-Water Usage July 13 to July 19, 2010
Figure 11-43 (SI). Actual Hot-Water Usage July 13 to July 19, 2010
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Figure 11-44. Actual Hot-Water Usage October 24 to October 31, 2009
Figure 11-44 (SI). Actual Hot-Water Usage October 24 to October 31, 2009
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Figure 11-45. Single-Line Electrical Schematic
11.3.4.5 CHP Plant Operations
To date, the CHP plant has run seamlessly with the existing arrangement and has
allowed the hotel to more closely watch the end use of their energy consumption to the
benefit of the owner and the hotel’s guests. The following significant advantages were
gained by installing the microturbine units outdoors as opposed to an indoor installation:
• Combustion and ventilation air was more easily addressed.
• Venting of exhaust gases was simplified.
• Derating of the electrical output associated with elevated intake temperature was
avoided during winter months.
• Service and maintenance clearances were more easily obtained.
The microturbine array is operating under a 9-year complete maintenance contract.
The microturbine array operates automatically and is monitored via a web interface.
The only repair was to microturbine number 2 during the second month of operation,
when a faulty diverter valve was replaced on the heat recovery heat exchanger.
11.3.5 Measured Performance
11.3.5.1 Overall Energy Performance
Table 11-12 presents the site energy use from 2008 through 2011 for the hotel. The
CHP plant started up during the latter part of 2009. Table 11-13 presents ASHRAE’s
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Table 11-12. Annual Site Energy Used by the Hotel
2008
2009
2010
2011
Electric, 1000 Btu
19,673,275
16,893,443
13,527,283
14,200,157
Electric, kJ
20 756 406
17 823 529
14 272 042
14 981 961
Hot water, 1000 Btu
9,016,508
6,908,196
4,800,750
5,329,744
Hot water, kJ
9 512 921
7 288 534
5 065 060
5 623 178
Steam, 1000 Btu
14,091,810
12,711,985
9,840,858
10,569,852
Steam, kJ
14 867 649
13 411 856
10 382 656
11 151 786
Natural gas (CHP), 1000 Btu
0
5,650,500
21,411,927
20,277,190
Natural gas (CHP), kJ
0
5 961 594
22 590 782
21 393 571
Total site energy, 1000 Btu
87,918,569
80,688,042
79,300,575
82,133,868
Total site energy, kJ
92 759 013
85 130 403
83 666 548
86 655 830
Table 11-13. Site-to-Source Energy Conversion
ASHRAE Standard 105 Site to Source
Natural gas
1.09
Imported steam
1.45
Imported hot water
1.35
Imported electricity
3.15
site-to-source energy conversion factors from Standard 105. Applying Table 11-13
factors to Table 11-12 site energy figures yields the source energy data in Table 11-14.
Comparing the source energy use in 2010 and 2011 versus 2008 presents a 6 to 8%
annual source energy savings.
11.3.5.2 Overall Economic Performance
Applying the energy cost from Table 11-9 to the site energy use in Table 11-12
yields the energy cost information presented in Table 11-15, showing a 22 to 32%
energy cost savings in 2010 and 2011, respectively, versus 2008.
11.3.6 Case Study Acknowledgements
Material for this cases study was provided by the following:
•
•
•
•
Four Seasons Hotel, Philadelphia, PA
Philadelphia Gas Works, Philadelphia, PA
E-Finity, Distributed Generation, Wayne, PA
Wachter Engineering, LLC, Mullica Hill, NJ
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Table 11-14. CHP Source Energy Savings
2008
2009
2010
2011
Electric, 1000 Btu
61,970,815
53,214,346
42,610,943
44,730,495
Electric, kJ
65 382 680
56 144 115
44 956,931
47 193 177
Hot water, 1000 Btu
12,172,286
9,326,065
6,481,012
7,195,154
Hot water, kJ
12 842 443
9 839 520
6 837 830
7 591 291
Steam, 1000 Btu
20,433,125
18,432,378
14,269,244
15,326,285
Steam, kJ
21 558 091
19 447 191
15 054 852
16 170 089
Natural gas (CHP), 1000 Btu
0
6,159,045
23,339,000
22,102,137
Natural gas (CHP), kJ
0
6 498 137
24 623 952
23 318 992
Total site energy, 1000 Btu
194,359,440
172,562,660
153,549,812
160,308,629
Total site energy, kJ
205 060 093
182 063 269
162 003 651
169 134 581
Source EUI Btu/ft gross per year
589
523
465
486
Source EUI kJ/m gross per year
6689
5939
5284
5517
NA
21%
18%
2
2
Percent source energy savings
Table 11-15. CHP Energy Cost Savings
2008
2009
2010
2011
Electric
$572,895
$500,911
$419,493
$396,211
Chilled water
$299,136
$225,948
$243,733
$203,856
Hot water
$337,521
$275,865
$176,652
$139,881
Steam
$523,502
$361,410
$297,144
$272,683
Natural gas (CHP)
$0
$43,198
$198,419
$193,337
Natural gas (Other)
$140,462
$117,647
$125,712
$69,171
Total site cost
$1,873,517
$1,524,979
$1,461,153
$1,275,139
Energy savings
$348,539
$412,364
$598,378
Percent energy savings
19%
22%
32%
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CHAPTER 12
CHP ANALYSIS TOOL
The CHP Analysis Tool supplied as part of this design guide is a Microsoft® Excel®
spreadsheet that builds on an analysis engine model used in assessing sites for CHP
applicability during 10 years of work with the U.S. Department of Energy and the
private sector. The tool is available for download at www.ashrae.org/CHPDG.
The ASHRAE CHP Analysis Tool has been further developed as part of ASHRAE
research project RP-1592 to provide an initial understanding of the CHP potential for
a given site. The results of the analysis are intended to be used for guidance purposes
only. The results of this CHP Analysis Tool should not be used for financial investment
decision making.
The CHP Analysis Tool consists of four worksheets:
• Introduction: provides the design purpose of the model
• Site Data Input: describes the current site and its energy consumption
• CHP System Input: describes the CHP system to be assessed
• Print Page: presents the results in a logical, printable format
The ASHRAE CHP Analysis Tool was developed for U.S. practitioners and is only
available in I-P units.
12.1 SITE DATA INPUT WORKSHEET
The Site Data Input screen (Figure 12-1) is where the existing load profiles and
energy costs for the site are established. The Site Data Input screen also contains the
most important step in developing a successful understanding of a site’s CHP potential—
the addressable thermal loads. Perhaps the most common design flaw in selecting and
configuring a CHP plant is incorrectly estimating the facility’s addressable loads,
which, if not properly itemized and quantified, can lead to a significant reduction in
anticipated thermal cost savings as well as annual fuel utilization efficiency.
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Figure 12-1. Site Data Input Screen
12.1.1 Operating Hours
Following the process flow on the input screen (Figure 12-1); the first information
required impacts the process load calculation as well as general occupancy schedules.
The required input is the number of operating hours per day, which can be any increment
of 1 h. The second input is the number of days per week operating on this basis. Days
of operation per week can be apportioned like the shifts; for example, 5 full days and a
half day on Saturday can be represented by 5.5. The percentage of operating hours
relates to a 52-week schedule divided by 8760 h/yr (Figure 12-2).
12.1.2 Addressable Thermal Loads
Understanding a site’s addressable thermal loads (Figure 12-3.) is one of the most
significant issues with respect to the performance and economic success of a CHP
project. Addressable thermal loads can be understood using the following considerations:
1. Can the thermal loads be physically addressed by a CHP system? This includes
such things as physical location (e.g., thermal loads are too far apart and cannot
be economically addressed) and type of equipment servicing the thermal load
(e.g., direct-expansion (DX) systems serve space heating or cooling and,
therefore, it is too expensive to convert to chilled-water/hot-water coils.).
2. This also includes an understanding of the thermal capacity of the CHP prime
mover that is available to service the load. Examples include the following:
a. The available hot-water supply temperature, return temperature, flow heat
available from a microturbine heat recovery heat exchanger.
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Figure 12-2. Operating Hours Screen
b. The available microturbine exhaust temperature, flow, heat flow, and
allowable back pressure.
c. The available hot-water supply temperature, return temperature, flow, and
heat available from a combustion turbine heat recovery heat exchanger.
d. The available combustion turbine exhaust temperature, flow, heat flow, and
allowable back pressure.
e. The available reciprocating-engine hot-water supply temperature, return
temperature, flow, and heat available from an engine jacket water system.
f. The available reciprocating engine exhaust temperature, flow, heat flow,
and allowable back pressure.
3. Addressable thermal loads should be expressed in the form required at the
point of interconnection to the CHP plant. Where loads such as hot water are
to be incorporated into a steam loop, this hot water load should be added to the
steam load and entered as part of the steam load and not as a separate hot-water
load. If a refrigeration system will use chilled water warmer than 40°F from an
absorber to reduce the temperature of the refrigeration unit’s condenser, the
load should be entered as cooling at the point of connection to the CHP plant.
When loads are not available or not addressable, enter zero into the load
parameter. Total addressable loads are calculated based on the Operating Hours
input screen. The Addressable Thermal Load input screen provides thermal
parameters in three categories:
a. Process dependent thermal loads (heating and cooling) that the user must
define in terms of average load per hour, deviation in terms of a single
percentage term that will calculate the maximum and minimum process
loads. These are non-weather-dependent loads.
b. Weather-dependent loads (space heating, cooling, and reheat) for which
the user must input the maximum load and the model will generate the
load depending on the user-selected climate region/city.
c. Domestic hot water, which requires the user to input the average hourly load.
4. The Addressable Thermal Loads input table (Figure 12-3.) consists of the
following data entry parameters:
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a. Process Heat Type: available choices from the drop down menu are hot
water (MBH = 1000 Btu/h), steam (lb/h) or hot air (MBH).
b. Average Process Heat Load: the average hourly load directly pertains to
the operating hours already selected. It is most important to understand the
direct relationship between the addressable load selected and the
CHP prime mover selected. For example, serving a hot-water load that
requires 190°F is non-addressable with a reciprocating-engine jacket
designed for a coolant temperature range of 160 to 180°F (71 to 82°C).
A microturbine providing hot exhaust gas to a process will have a supply
temperature between 350 and 450°F (177 and 232°C), whereas a
combustion turbine will have a supply temperature of between 800
and1000°F (426 and 538°C).
c. Process Heat Load Deviation: the process heat deviation is used to develop
the initial max/min load estimate. For example, entering 30% with an
average load of 3000 MBH means the maximum process load
will be calculated as 3900 MBH and the minimum will be calculated as
2100 MBH.
d. Space Heating Type: available choices from the dropdown menu are hot
water (MBH), steam (lb/h) or hot air (MBH).
e. Max Space Heating Load: entering the maximum space heating load
drives the installed capacity for the space heating system. The actual
load is calculated using local weather conditions based on the max
space-heating load input. The load should be the operating maximum
of the plant and not the nominal capacity of the plant.
f. Chilled Water Reheat: available choices for the dropdown menu are hot
water (MBH) or steam (lb/h). Chilled-water reheat load is derived from
the cooling load and the outside air fraction.
g. Outside Air Fraction: inputting the outside air fraction allows the model
to estimate the external latent load and, combining with average internal
latent load, to yield an estimated thermal reheat requirement.
h. Average Domestic Hot Water: input the average hourly load (MBH)
directly that pertains to the operating hours already selected. The model
recognizes the volatility of domestic hot-water demand and accounts for
this by using 20% of the average load as the base load. The CHP analysis
tool considers domestic hot water to be a steam load if steam is selected
as the exhaust use in the “CHP System Input” tab, otherwise it is
considered as a hot-water load.
i. Process Cooling Type: choose between process cooling or refrigeration.
j. Average Process Cooling Load: input the average hourly load (refrigeration
tons) directly that pertains to the operating hours already selected.
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Figure 12-3. Addressable Thermal Loads
k. Process Cooling Load Deviation: the process cooling deviation is used
to develop the initial max/min load estimate. For example, entering 20%
with an average refrigeration load of 100 tons means the maximum
process load will be calculated as 120 tons and the minimum will be
calculated as 80 tons.
l. Max Space Cooling Load: entering the maximum space cooling load
drives the installed capacity for the space-cooling system. The actual load
is calculated using localized weather data and the max space-heating load
input. The load should be the operating maximum of the plant and not the
nominal capacity of the plant.
12.1.3 Monthly Billing Data
The user will also input 12 months of utility data, which will provide historical
energy and fuel usage information to correlate with the model load calculations and
develop the historical energy cost information. Twelve months of electric data should
be entered in the table (Figure 12-4), including number of billing days in the cycle,
kWh of electric usage, peak electric demand, and the total electric bill amount. Twelve
months of natural gas data should be entered in the table, including number of billing
days in the cycle, dekatherms of natural gas usage, and the total electric bill amount. If
oil or propane is used, then liquid fuel drops will need to be converted into million Btus
used on a monthly basis and the total cost estimate per month. If monthly bills are not
available, then an estimate must be made on fuel use and cost per month and the data
entered by month.
The pie-chart (Figure 12-5) provides a graphical picture of the site’s annual energy
cost according to the monthly billing data input.
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Figure 12-4. Annual Energy Use/Cost through June
Figure 12-5. Annual Energy Cost
12.1.4 Site Identification
The site information that will be produced on the cover of the report is entered
here, including the facility name, town, state, and electric utility name (Figure 12-6).
Next, a pulldown menu provides a choice of 21 different climate regions in the United
States. The region best emulating the weather pattern for the subject facility should be
chosen. Space-conditioning profiles are developed from the heating and cooling degree
days associated with each region, which are based on the average of 2007–2011 values
for that region. Then input the principal fuel used at the site (natural gas, #2 oil, or
propane). Next, the name and company to be listed as the entity performing the study
should be entered.
The 21 different climate regions used by the model are as follows:
Atlanta, GA
Boise, ID
Boston, MA
Chicago, IL
Denver, CO
Grand Forks, ND
Honolulu, HI
Houston, TX
Kansas City, KS
Knoxville, TN
Los Angeles, CA
Minneapolis, MN
New York, NY
Nome, AK
Oklahoma City, OK
Orlando, FL
Philadelphia, PA
Portland, ME
Riverside, CA
Seattle, WA
Washington, DC
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Figure 12-6. Site Identification
12.1.5 Existing Equipment
Enter the respective efficiency of the existing equipment in percentage format into
the Existing Equipment table (Figure 12-7). These are used to calculate the various
loads as well as the fuel offset for providing thermal energy from a CHP plant.
Efficiencies are for the boilers and chillers only, not to include parasitic loads such as
thermal media flow or cooling towers. If there are multiple pieces of equipment with
different operating efficiencies, then the engineer will need to create an average
efficiency for each category. The best method is to use operating hours of each piece of
equipment to determine the weighting average efficiency.
12.1.6 Energy Costs and Fuel Use Offsets
This section of the Site Data Input tab is a representation of the average electric and
thermal fuel costs by season and a breakdown of the site’s fuel use, indicating both
addressable and nonaddressable loads. The energy costs are based on the total energy
spend and usage each period and, as such, are weighted by volume of use. The ‘Annual
Av” represents the average annual cost of energy at the site. Thermal fuel offset value
and CHP fuel costs are based on the monthly average cost of fuel according to the
historical billing information entered into the model. An option to override the historic
monthly fuel price is provided in the CHP System Input tab, which allows for special
or annual contract prices to be used instead of the monthly average costs.
Fuel use offsets (see Figure 12-8) are provided in terms of fuel input associated
with each addressable load based on the data entered into the Addressable Thermal
Load section. They are compared to the total fuel input based on billing data and
provide a check on the validity of the addressable load data. Assuming that there are no
new loads added to the facility, the nonaddressable fuel use should always be a positive
number. If it is negative, this indicates that the claimed addressable loads may be too
big, because the fuel use associated with these loads should be no greater than the
actual fuel use provided in the billing information.
A more-detailed breakout of thermal loads and fuel use is provided at the end of
the tab to allow the user to review the loads compared to fuel use on a monthly basis.
Although the annual totals should result in an overall minimum of zero nonaddressable
fuel use, the monthly breakout helps to understand the accuracy of the various load
model components. Figure 12-9 presents an example of a typical application where
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Figure 12-7. Existing Equipment
Figure 12-8. Energy Costs and Fuel Use Readout
nonaddressable fuel use is negative in June. This may be due to a misalignment of loads
and billing periods or due to a production shutdown in June and would have little
impact on the overall results as long as addressable load fuel use is lower than actual
fuel use for the rest of the year.
12.2 CHP SYSTEM INPUT WORKSHEET
The ASHRAE CHP Analysis Tool was developed with the intention of having the
user input the CHP efficiencies as they would be with respect to the load type. The CHP
System Input screen (Figure 12-10) requires the user to understand the performance
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Figure 12-9. Monthly Addressable Loads versus Fuel Use
aspects of the CHP prime mover, particularly in relationship to the electricity and
addressable thermal loads that were input on the preceding worksheet. A number of
parameters relating to the performance of the CHP system, as well as the CHP fuel cost,
capital costs, and other costs and savings, are entered in this section to complete the
analysis. Figure 12-10 shows the complete CHP System Input tab along with the results
of matching the proposed CHP system with the loads entered in the Site Data Input tab.
12.2.1 Nominal CHP System Performance
Figure 12-11 allows the user to enter the electric capacity and specific electric and
thermal efficiencies of the prime mover.
The Nominal CHP System Performance (Figure 12-11) screen contains default
characteristics for a generic microturbine, generic reciprocating engines (<100 kW,
>100 kW and <700 kW and >700 kW), and simple-cycle combustion turbines. The
electric efficiency, exhaust heat recovery efficiency, and the jacket water heat recovery
efficiency (if available) are represented as a percentage of the fuel’s lower heating value
(LHV is used in this section because most manufacturer’s data is provided in terms of
LHV and is converted to HHV for load and efficiency calculations as well as economic
evaluation). The CHP performance input data is the second-most important area after
assessing the addressable loads. The user must understand the recoverable thermal
efficiency relative to the load. For example, if the user is inputting data for a microturbine,
and the thermal load is moderate temperature hot water ≤140°F (60°C), the exhaust
heat recovery efficiency may be 48%, whereas if the load is steam, the heat recovery
efficiency could be 30%. This issue highlights a significant deviation from most existing
model approaches; this e-tool requires the user to have some understanding of how
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Figure 12-10. CHP System Input Worksheet
Figure 12-11. Nominal CHP System Perforance
prime-mover heat outputs interact with loads. This approach not only requires some
effort by the user, but, more importantly, once that understanding is obtained, it allows
very quick analysis of complex applications, with reliable results.
Once the appropriate prime mover is selected, suggested default efficiencies
(electric, exhaust heat recovery, and jacket heat recovery) are determined. The next
input is the prime-mover electric power output, which should be an educated estimate
based on the electric and thermal loads already recorded. The next three inputs are the
user-defined prime-mover efficiencies (electric, exhaust heat recovery, and jacket heat
recovery). If the user-defined efficiencies deviate from the suggested efficiencies, then
the cell background will turn to yellow to highlight this fact. This is acceptable and
does not impact results but is a useful reminder to adjust efficiencies if a different
prime-mover technology is selected. Consult with the actual prime-mover supplier for
best available information and specific frame size for more accurate model input.
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Fuel Input (LHV), Exhaust HR, Jacket Water HR, and nominal CHP System
Efficiency are then calculated for the system based on the efficiencies input by the user.
The right-hand column data entries concern the thermal heat recovery uses based
on the Site Input Worksheet.
If process or space cooling is used, the heat recovery use (hot water, steam, or hot
air) is then selected which, in turn, provides a dropdown menu containing the available
equipment. If no addressable cooling is available or desired, then the user selects none,
to remove the cooling option from the analysis.
Exhaust Use. The user defines the heat recovery product from the exhaust stream
by selecting one of the options from the dropdown menu. Depending on the application,
exhaust can be used to generate hot water (MBH [= 1000 Btu/h]), steam (lb/h), or hot
air (MBH). In cases where hot water is produced by the exhaust from a reciprocating
engine, the total exhaust heat recovered as hot water will be added to the jacket heat
recovery to provide a single hot-water stream from the CHP plant.
Chiller Use.The dropdown menu allows the choice of refrigeration, cooling, or
none. If you choose refrigeration, the thermal energy will be used to meet the
refrigeration load indicated on the Site Data Input worksheet. If cooling is selected,
thermal energy will be used to meet the process- and space-cooling loads entered in the
Site Data Input worksheet. Note that by selecting ‘None” in this cell, no cooling will be
used to address the loads.
Chiller Type. A cooling selection (Chiller Use) designates a lithium bromide/water
absorption chiller and allows chiller selection of a single- or double-effect absorber. In
cases where the exhaust use is input as hot water and the chiller use is cooling, the
choice of chiller type is be restricted to a single-effect absorber, because it is assumed
that the hot water will not be hot enough to drive a double-effect absorber. A refrigeration
selection (Chiller Use) allows selecting a water/NH3 absorption chiller only.
Chiller Output Temp.If cooling is chosen, the chiller output temperature is >40°F
(4.4°C). If refrigeration is chosen, the chiller output temperature is either >40°F
(4.4°C), 20 to 40°F (−6.7 to 4.4°C), 0< to 20°F (−17.8< to −6.7°C), −20 to 0°F (−28.9<
to −17.8°C) or < −20°F (< −28.9°C).
Figure 12-12 to 12-13 contain the output of the CHP system performance versus
the previously entered load data. This provides the user with an understanding of the
load availability versus CHP system output for the chosen configuration that allows the
user to iterate solutions focusing on optimizing load factor.
Figure 12-12 provides annual average demand and base-load data calculated from
the Site Data Input Worksheet. The CHP system output to satisfy the load requirements
is presented in the right two columns indicating output and load factor.
Figure 12-13 provides a quick valuation of average site demand (blue bars) versus
the CHP system capacity (red-striped bars). Note that, for the example data shown, the
CHP system produces 980 kW, which represents approximately 32% of the average
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Figure 12-12. Demand, Base Load, CHP Output, and CHP Load Factor Table
power demand; 1.9 million Btu of hot water, which is 67% of the hot-water demand;
over 59% of the steam demand; and 29% of the average cooling demand.
Figure 12-14 presents the same site average annual demand (blue bars) with the
CHP system capacity load factor superimposed in red-striped bars. In this scenario, the
CHP electric output has a 100% load factor, hot-water heat recovery has a 63% load
factor, steam output from the CHP system has a 92% load factor, and cooling output
has a 58% load factor.
The graphs in Figures 12-13 and 12-14 can assist the user in fine-tuning CHP
prime-mover selection and thermal heat recovery and use options that will maximize
load factor. In the model, any thermal energy not used for heating purposes is passed
through to the chiller and converted to cooling. Again, using the example data shown,
this means that the available hot-water heat recovery after the hot-water load has been
satisfied will be available for the chiller.
The overall annual efficiency is calculated as the total fuel use efficiency (see
Figure 12-15) by adding the electric output to the thermal output and dividing the result
by the higher value of the total fuel input. This result is an important design guide on
the suitability of the selected CHP size and configuration for the application. For
economically driven projects, the result should be greater than 60%, which is also a
typical efficiency threshold for grant qualification.
12.2.2 Economic Input Screen
Figure 12-16 contains economic calculation results and allows for user adjustments
to the nominal values generated by the model.
Calculated CHP Installation Cost. This provides the basic CHP system installed
cost based on currently available information for the selected system type. The basis
for equipment cost is the U.S. Bureau of Labor Statistics Table 1 for seasonally
adjusted labor for manufacturing, which in June 2012 was 113.8 (2005 basis 100).
The basis for installation labor is the U.S. Bureau of Labor Statistics Table 1 for
seasonally adjusted labor for installation, maintenance, and repair, which in June 2012
was 116.7 (2005 basis 100).
Adjustment Factor. An Adjustment Factor is an important user input to adjust
capital costs and to appropriately deal with escalation over the next decade as well as
site installation simplicity or complexity. Adjustments of up to ±20% are normal to
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Figure 12-13. Site Demand versus CHP Output
Figure 12-14. Demand, Base Load, CHP Output, and CHP Load Factor
reflect actual site conditions and costs. Where the user has an installation cost developed,
the adjustment factor should be used to bring the model’s cost into line with actual
installation costs. The model’s material and labor costs are based on June 2012
estimates. Therefore, the user should consider changes in labor and manufacturing
costs when making further adjustments to the Calculated CHP Installation Cost.
Chiller Type. The chiller type is displayed to remind the user which thermally
activated cooling system is chosen, performance assessed, and costed.
Adjusted CHP Installed Cost. This is the corrected dollar amount of the
Adjustment Factor for new equipment costs and complexity of the site installation over
and above a straightforward system installation.
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Non-CHP System Costs. This cell provides a place to add any non-CHP-systemrelated costs, such as a significant upgrade to the piping distribution system that may
not be included in rebatable CHP costs.
Fed 10% ITC. The current 10% federal investment tax credit can be selected from
the dropdown menu, which automatically calculates the credit and subtracts it from the
total net installed cost.
Grant/Rebate. Federal, state, and utility-based grants can be entered. Figure 12-17
is a simple grant calculator that quickly calculates a potential grant amount based on $/
kW ($550/kW example). Grant caps are usually expressed as a percentage of project
capital, typically on an installed basis (example = 30%).
Capital Cost Credit. This cell provides a place to enter any additional capital cost
credits that can be applied to the project, such as offsetting purchase of diesel backup
generators if the CHP system will provide emergency power capability, or costs associated
with bringing new power service to the facility if the CHP plant can provide this power
instead. The number entered here is deducted from the net installed cost but does not
impact the CHP system installation costs, which may be the basis for grant caps.
Net Installed Cost Budget. This calculates the adjusted capital amount, including
any additions, complexities, incentives, grants, and cost offsets.
Figure 12-15. CHP Overall System Efficiency
Figure 12-16. Economic Input Screen
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The $/kW provides a rule-of-thumb check to compare this project with prior
experience. This number is based on the net installed cost number and includes all
capital cost adders and offsets.
12.2.3 Operating Cost
Figure 12-18 contains economic calculation results and allows for user adjustments
to the nominal values generated by the model.
Existing Fuel. This displays the existing fuel from the Site Data Input Worksheet.
CHP Fuel. This displays the CHP fuel, which is natural gas, because the CHP
prime movers this model focuses on are microturbines, reciprocating engines, and
combustion turbines. Other gaseous fuels can be used, but this will require primemover efficiency adjustments and fuel cost adjustments.
Projected CHP Fuel Cost. The basic fuel cost is generated from the monthly
fuel bills; however, the user can change this calculated cost, inputting a different
$/MMBtu cost.
Use Projected Cost. To use the project cost versus the historical calculated cost,
select “Yes” from the dropdown box.
Incremental Oper Cost. The user can input additional incremental operating
expense on a cost-per-month basis. Standard CHP system maintenance, including
cooling/refrigeration system maintenance, is included in the basic operating-cost
calculation.
Figure 12-17. Grant Calculator
Figure 12-18. Operating Costs
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Standby Charge. The user can input distributed power standby charges, if they
exist. The value input here is carried through the economic evaluation as a per-month
operating charge.
Other Incremental Cost. This can be used for any additional monthly input charges.
Other Savings. This can be used for any additional monthly savings.
12.2.4 Economic Output Screen
Figure 12-19 is the Economic Output Screen, which contains the following elements:
Total Power Output. Total electric power produced annually by the CHP System
in kWh.
Total Useful Heat. Total useful heat supplied annually to the site in million Btu.
Total Useful Cooling. Total cooling or refrigeration supplied annually to the site
in ton-hours.
Cost of Fuel. Total annual cost of fuel, based on the operating hours, electric load
factor, electric efficiency, and the monthly unit cost of fuel.
Maintenance. The total annual maintenance cost includes the prime mover, heat
recovery, and chiller plant, if selected.
Operation. Annual cost based on user-supplied input for incremental operating cost,
if required. The proposed CHP plant may require additional operating or administrative
personnel, which should be accounted for here.
Standby Cost. The annual charge calculated from the Operating Cost input screen.
Other Costs. The annual charge calculated from the Operating Cost input screen.
Power Offset. The annual value of the net power delivered to the site by the CHP
system displacing retail purchase of electricity. This calculation also includes kWh
offset by a cooling system, if used.
Heat Offset. The net thermal heat (note: thermal cooling displaces electricity)
delivered to the site by the CHP system displacing retail purchase of natural gas.
Other Savings. Could include site-specific emissions credits or state production
credits.
Capital Budget. Calculated installed capital net of all additional cost, offsets, and
capital incentives.
Net Annual Savings. Net annual offsets less net total costs.
Simple Payback. Calculated simple payback.
10-Year Net. The 10-year net value is the total value of the project in present
dollars when a 3% escalation is applied to all costs and offsets and includes interest
charges based on the cost of capital, if financing is selected.
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Figure 12-20 shows the input for calculating interest charges, if financing is desired.
If the project is to be funded by the owner, then a 1-year loan term should be selected
with 0% interest rate.
12.2.5 Monthly Addressable Load Chart
Figure 12-21 shows the addressable loads on a monthly basis as calculated by the
model based on the input provided in the Site Data Input worksheet. This is a useful tool
in understanding the impact of the various addressable load development parameters.
12.3 PRINT PAGE WORKSHEET
Figures 12-22 to 12-27 provide the user with printed results of the analysis, which
is intended to serve as a a comprehensive CHP analysis report and a deliverable that
can be provided to the client.
Figure 12-19. Economic Output Screen
Figure 12-20. Economic Output Screen
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Figure 12-21. Addressable Thermal Loads
Figure 12-22. Report Cover Sheet
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Figure 12-23. Site and CHP Systems Performance Summary
Figure 12-24. CHP Costs, Savings, and Simple ROI
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Figure 12-25. Cash Flow and Utility Cost Sensitivity
Figure 12-26. Summary Energy Costs and Fuel Use
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Figure 12-27. Model Input Data and Assumptions
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APPENDIX A
GLOSSARY
auxiliary firing
addition of extra fuel into the exhaust gases of a turbine to
provide an increase in heat output. This technique uses the preheated excess oxygen in
the exhaust gas from the turbine and provides extra heat at high efficiency. Ideally
suited for meeting peak heat demands.
availability
ratio of the number of hours a piece of equipment is available for
use to the number of hours it is required for use. Provides a measure of how much time
equipment is not available for use (e.g., when undergoing maintenance or repair).
Equipment may also be available for use for more hours in a year than it is actually used
(see load factor or utilization).
avoided cost
incremental cost to an electric power producer to generate or
purchase a unit of electricity or capacity or both but that is instead provided by a third
party or not needed because of energy conservation and efficiency.
back-pressure steam turbine
a turbine that relies on the expansion of steam
within the turbine to drive the alternator without condensing the steam. The exhausted
steam is then used to provide the heat for the hot-water distribution system. A simple
but comparatively inefficient.
backup power
a specific industrial application for on-site power generation
technology. This applies to any equipment that exists solely to provide a redundant
power source in the case of failure of the primary power source. Backup power devices
are characterized by low load factors, rapid start-up, and high reliability. Also called
standby power or standby generation.
base load the level of demand, for heat or electricity, that exists for the majority
of the operating period. The demand will rarely be less than this base load. This load
should be met from the lowest cost sources.
baseload capacity
produce.
amount of power that a generating facility can continuously
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best available control technology (BACT) an emission limitation based on the
maximum degree of reduction of each pollutant subject to regulation and emitted
from or that results from any major emitting facility. The permitting authority, taking
into account energy, environmental, and economic impacts, and other costs, on a caseby-case basis determines what is achievable for each facility through application of
production processes and available methods, systems, and techniques. This includes
fuel cleaning or treatment or innovative fuel combustion techniques for control of
each pollutant.
capacity
the maximum power output or the load for which a generating unit,
generating station, or other electrical apparatus is rated. Common units include kilovoltampere (kVa), kilowatt (kW), and megawatt (MW).
capacity factor
the ratio of the energy that a plant produces to the energy that
would be produced if it were operated at full capacity throughout a given period, usually
a year. Sometimes called the plant factor.
combined cycle
the combination of a number of power generation methods to
extract the most energy from the fuel. Typically, the exhaust from a gas turbine, driving
a steam generator, is used to generate steam that then drives a steam turbine, also
driving a generator. This increases the efficiency of electricity generation to about 50%.
demand
rate at which electricity is delivered, expressed in kilowatts,
kilovoltamperes, or other unit, at a given instant or averaged over a specified time.
demand charge
charge for the maximum rate at which energy is used during
peak hours of a billing period.
demand diversity
measure of the potential connected load experienced as an
actual load at a given time; specifically, the peak demand at the central heat supply
source divided by the sum of the individual heat demands. A value of between 0.85 and
0.95 is normal for space heating systems. A similar concept also exists for the connected
electrical load.
diesel engine
a reciprocating internal-combustion engine that ignites the fuel/
air mixture by compression. The diesel engine has a high mechanical efficiency and
hence a high power/heat ratio in CHP applications.
distributed generation (DG) the integrated or stand-alone use of small, modular
electricity generation resources by utilities, utility customers, and/or third parties in
applications that benefit the electric system, specific end-use customers, or both. From
a practical perspective, it is a facility for the generation of electricity that may be located
at or near end users within an industrial area, a commercial building, or a community.
distributed power
process in which generation facilities, energy storage
facilities (thermal energy storage, batteries), and other strategies, such as district energy
and demand-side management efforts, are located at or near the end-use customer.
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APPENDIX A
exit fee charge levied by a utility when a customer leaves the grid or reduces its
load through distributed generation, to compensate for investments made by the utility
on behalf of that customer.
extraction condensing steam turbine a turbine system that exhausts the steam
to a lower-than-atmospheric pressure. This increases the efficiency of the generation
but increases the cost and complexity of the plant.
heating value (or calorific value)
the number of heat units obtained by the
combustion of a unit mass of a fuel. . (Also see lower heating value (LHV) and higher
heating value (HHV).
higher (or gross) heating value (HHV)
the standard measure of the energy
released during combustion of a fuel, assuming the product water is in the liquid state,
after the products of combustion are cooled to the original fuel temperature. Most
engine suppliers quote engine fuel consumption and efficiencies using the lower
heating value (LHV) of the fuel, but gas is sold by its HHV. It is essential to use the
same definition of HHV throughout CHP system calculations involving fuel costs and
fuel energy inputs. For natural gas fuel, the HHV is approximately 5 to 10% higher
than the LHV.
independent system operator (ISO)
a neutral and independent organization
with no financial interest in generating facilities that administers the operation and use
of the transmission system.
independent power producer (IPP) any entity not regulated by the government
as a public utility that owns or operates an electricity generating facility and offers
electric power for sale to utilities and/or the public (also known as nonutility generator).
installed capacity
maximum load-carrying ability of a generating facility.
interruptible rate
price paid for electricity by commercial or industrial
customers who have agreed to have their power cut off by the supplier in the event of
high demand caused by severe weather or equipment problems.
load factor
ratio of the amount of electricity produced by a piece of power
generation equipment in a given year divided by the amount that it could have produced
if it were operated continuously at full power.
local distribution company (LDC)
traditional utility that distributes natural
gas or electricity or both to local customers.
lower heating value (LHV) the standard measure of the energy released during
combustion of a fuel, assuming the product water is in the gaseous state. The LHV is
the total heat produced in combustion less the energy in the uncooled products of
combustion, including uncondensed water vapor. The LHV of fuel is typically 5% to
10% less than the higher heating value (HHV).
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marginal cost
in the utility context, the cost to the utility of providing the next
(marginal) kilowatthour of electricity, irrespective of sunk costs.
nameplate rating
the full-load continuous rating of a generator or other
electrical equipment under specified conditions as designated by the manufacturer and
written on the nameplate.
net metering practice that allows the electric meters of customers with generating
facilities to turn backwards when the generators are producing energy in excess of the
customers’ demand, enabling customers to use their own generation to offset their
consumption over a billing period.
nominal capacity
approximate energy-producing capacity of a generating
facility or unit under specified conditions during periods of highest load.
open access
ability to send (or “wheel”) electric power to a customer over a
transmission and distribution system not owned by the generator of the power.
peak load
hour in a year.
the maximum demand for heat or electricity that occurs in any one
premium power
a specific industrial application for on-site power generation
technology. This applies to any equipment that exists solely to provide power with a
higher quality than that available from a conventional power source. This power may
have a well-defined waveform, be direct current, or be more reliable than the
conventional source.
Public Utility Regulatory Policy Act (PURPA) of 1978 federal legislation that,
among other things, requires utilities to buy electric power from private “qualifying
facilities,” at an avoided cost rate equivalent to what it would have otherwise cost the
utility to generate or purchase that power. Utilities must further provide customers who
choose to self-generate a reasonably priced backup supply of electricity.
recuperated turbine
a gas turbine that includes a recuperator to recover some
of the residual energy from the hot off-gases exiting the expander, thereby increasing
electrical efficiency.
retail wheeling transmitting electricity over transmission lines not owned by the
supplier of the electricity to a retail customer of a supplier.
self-generation on-site production and use of electricity by an industrial facility
or other energy customer.
spark-ignition gas engine a reciprocating internal-combustion engine that ignites
gas using spark plugs. Most gas engines used for CHP are based on commercial diesel
engine designs, but with lower compression ratios, spark plugs, and other modifications.
spinning reserve on-line generating capacity, ready to carry additional electrical
load in excess of the load on the system.
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APPENDIX A
switching station
an assemblage of equipment used for the sole purpose of
tying together two or more electric circuits. Selectively arranged switches are used to
allow a circuit to be disconnected in case of trouble or to change electric connections
between circuits. A type of substation.
synchronizing the process by which the sinusoidal output voltage waveform of
an AC generator is brought precisely into line with the frequency, time, and voltage of
another generator or with the main system to which it is to be connected.
thermal/electric (T/E) ratio
a ratio describing the energy use of a particular
industry or facility, in which the total energy used as heat is divided by the total energy
used as electric power. This refers to energy used within the plant rather than the energy
purchased at the plant gate. This value is usually used in conjunction with assessments
of CHP options.
thermal energy storage (TES)
system that produces cold water, usually at
night when electrical rates are lowest, and stores the water in insulated tanks for use in
air-conditioning applications when rates are higher.
thermal storage
storage of heat, typically, in an insulated tank as hot water to
provide a buffer against peak demand. The water may be pressurized to allow it to be
kept at a higher temperature.
wheeling
moving electricity from the generating facility to the customer over
one or more separately owned electric transmission and distribution systems.
wholesale wheeling transporting electric power in amounts and at prices covered
in long-term contracts between the generator and a distributor or large power consumer.
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APPENDIX B
EXERGY ANALYSIS
The term “exergy” originated from the Greek words meaning “from” and “work”
(McGovern, 1990a). It means the useful energy or, work, potential of a system at a
specified state that could be realized as the system “relaxes” to the state of the overall
environment, coming to intensive property (e.g., Ttemperature, Ppressure, chemical
composition) equilibrium with that environment. Exergy is a co-property of the state of
the system and the reference environment. In many contexts, the term exergy is thought
of as synonymous with: available work, available energy, availability, available useful
work, maximum work, or reversible work.
The useful work could be defined as the energy that could cause a mass to be lifted
through a distance in a gravitational field, or perfectly elastic spring to be compressed
by a measurable displacement, or frictionless flywheel to be accelerated from one
angular velocity to another (McGovern, 1990a) as the defined system relaxes to the
intensive properties of the overall environment, that is, as it is thermodynamically
driven to intensive property equilibrium with the overall environment, achieving the
so-called “dead- state” conditions. Thermodynamic work includes mechanical work,
electrical work, chemical work, and so on. Definitions, concepts, and exergy related
equations follow primarily from the second law of thermodynamics, and are simply
re-conceptualizations of the first and second laws. . The second law of thermodynamics
expresses the directions of energy transfer in terms of intensive property (T, P, chemical
composition) differences between a defined system within a given boundary and,
ultimately, the overall macro-environment. The Clausius statement of the second law is
this: Nno process is possible whose sole result is the transfer of heat from a body of
lower temperature to a body of higher temperature. This concept gave the definition of
a physical property: the entropy.
B.1 THE MEANING OF THE SECOND LAW:
There is an extensive property of a system called entropy, S. The entropy of an
isolated system can never decrease (Kotas, 1985).
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In an isolated system:
( ∆S )ISOL ≥ 0
B-1
The equality sign corresponds responses to the ideals case of a reversible process.
In a combined system,
( ∆S )SYSTEM + ( ∆S )SURROUNDINGS ≥ 0
B-2
The increase of entropy is the prediction of thewhat processes, chemical reactions,
transformations between various energy forms, or direction of heat transfer (Kotas,
1985) that can occur as a defined system interacts with its surroundings, the macroenvironment. The second law gives the limit of energy conversions between different
forms of energy, and, thereby, leading to the concept of energy quality. On a molecular
level, entropy can be considered as a measurement of randomness and resultant
uncertainty of matter. All practical interactions between a system and the environment
increase the randomness of the system and environment, leading to a smaller portion
of energy available to convert into useful, ordered work. Therefore, the entropy is
considered as the measurement of “unavailability” of the energy in the system relative
to the environment (Reynolds, 1977).
B.2 DEFINITIONS AND CONCEPTS
B.2.1 Reversibility and Irreversibility
Reversibility and irreversibility describe the conditions of a system-environment
interaction and are important concepts in the quantification of available energy that can
be realized in such interactions ( Horlock 1996; Kotas, 1985). and (Horlock, 1996):
A reversible process is an idealization whichthat can never be realized fully but
which is useful conceptually because it is easier to describe in mathematical terms than
an irreversible process. The reversible process can be used conveniently as a standard of
perfection by which real processes can be judged, sincebecause no viable energy
realization from the system-environment interaction is made unavailable from a potential
ability to do work perspective.
An irreversible process is unavoidably accompanied by an increase in entropy in
the combined system and macro-environment. Frorm the microscopic and statistical
point of view, this indicates that there has been a change from a more organized from
of energy to one characterized by a greater degree of randomness.
Two groups of phenomena are found in irreversible process. One involves direct
dissipation of work into internal energy of the system; that is, i.e., fully organized
macroscopic work is converted to the microscopic energy associated with the random
motion of the molecules. This dissipation is caused by solid or fluid friction, mechanical
or electrical hysteresis, ohmic resistance, etc.
The other groups of phenomena are associated with spontaneous non-equilibrium
processes, in which a system tends to move in an unrestrained manner from a state of nonequilibrium to one of equilibrium. Typical phenomena in this group are spontaneous
chemical reactions, free diffusion, unrestrained expansion, and equalization of temperature.
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APPENDIX B
The condition for reversibility of a process is that the system passes through a
series of equilibrium states; that is, the process is allowed to occur in an infinite number
of small state changes, and dissipative phenomena are absent from the system.
Therefore, the interaction between the system and the environment occurs in a quasistatic manner.
In an irreversible process, all its effects on both the system and its environment
cannot be negated without calling on the aid of a perpetual-motion machine of the
second kind, in contravention of the second law of thermodynamics. All practical
processes are, in some measure, irreversible (Haywood 1992).
Internal reversibility implies that all process within the system are reversible (i.e.,
that there is an absence of friction, of diffusive heat transfer, and of diffusive mixing
within the system, so that the system passes through a succession of equilibrium states
in a quasi-static process).
External reversibility implies that all heat exchanges between the system and its
environment are made reversibly. This requires either that the temperature of any part
of the system that exchanges heat with the environment is infinitesimally different from
that of the environment, or that such an equal amount of heat exchange frorm the
environment to the system could occur by immediately reversing the infinitesimal
temperature gradient. Full reversibility implies the existence of both internal and
external reversibility, in the sense defined above.
B.2.2 Different Forms of Work Output
Displacement work output is the work performed by system Z in expansion against
the environment. To achieve internal reversibility, the process must be quasi-static; that
is, the expansion must take place infinitely slowly. When this is the case,
(Wd )REV = p0 (V2 − V1 )
B-3
where
(Wd )REV = reversible displacement work
p0 = ambient pressure
V1 = volume at state 1
V2 = volume at state 2
Internal energy change is the total work output (mechanical and/or electrical)
produced directly by system Z.
External work output is the work produced by such auxiliary cyclic devices as are
needed to ensure external reversibility. This is wholly in the form of useful shaft work
(McGovern, 1990a).
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Normal work:
Consider an adiabatic cylinder with an adiabatic, frictionless, and perfectly sealed
piston as shown in Fig. B-1. Assume that a gas within the cylinder has been compressed
from the pressure of the specified reference environment, p0 to pressure p. The external
face of the piston is in contact with the reference environment. If the gas is now allowed
to expand reversibly until it reaches the environmental pressure p, the work it does on
the piston is given by
p0
B-4
W = ∫ PdV
P
Assuming the diameter of the piston rod is negligible, the work transmitted by it
during the expansion of the gas is given by
p0
Wu = ∫ pdV − p0 ∆V
B-5
P
Combining two equations gives
Wu = W − p0 dV
B-6
Figure B-1. Adiabatic Expansion Of A Gas Tthat Does Work On A Piston
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APPENDIX B
Shear work:
By means of a suitable ideal mechanism, shear work at a boundary can cause the
lifting of a weight and no other effect. Therefore,
Wu, s = Ws
B-7
Important theorems in availability are found in Haywood (1992) and are noted as
follows:
Theorem 1: Gross work output between specified and states
For a system that can exchange heat with a single thermal reservoir (e.g., the
environment at temperature T0 , the gross work output is the same for all fully reversible
processes between the same specified end states 1 and 2. During any irreversible
process between these same specified end states in the presence of the specified
environment at temperature T0 , the gross work output is always less than the state 1 to
state 2 transition difference.
Theorem 2: Loss of gross work output and entropy creation
For a system undergoing an irreversible process between specified end states in the
presence of an environment at temperature T_0, the loss of gross work output due to
irreversibility is equal to T0 ∆Sc , where ∆Sc is the entropy creation due to irreversibility
within the system.
Theorem 3: Entropy conservation in a fully reversible process
In a fully reversible process, there is zero entropy creation in the combined system
+ environment context (i.e., entropy is conserved).
Basic Concepts of Exergy
To account for the variable quality of different energy forms in the analysis of
thermal and chemical plants, systems, a universal standard of quality is needed. The
most natural and convenient standard is the maximum work which can be obtained
from a given form of energy using the macro-environmental parameters as the reference
state. This standard of energy quality of the system in question, relative to the
environment interaction, is called exergy.
Exergy may now be formally defined as the maximum useful work that could be
produced by the interaction of a system with a specified reference environment.
One of the main uses of this concept is in an exergy balance in the analysis of
thermal systems. The exergy balance is similar to an energy balance but has the
fundamental difference that, whilewhereas the energy balance is a statement of the law
of conservation of energy, the exergy balance may be looked upon as a statement of the
law of degradation of energy. Degradation of energy is equivalent to the irretrievable
loss of exergy, (maximum available useful work) due tobecause all real, practical,
processes arebeing irreversible. From (Kotas, 1985).
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B.2.3 Environment
The environment, as conceived in the Exergy Methodin the context of exergy, is a
very large body or medium in the state of perfect thermodynamic equilibrium. Thus,
this conceptual environment has no gradients or difference involving pressure,
temperature, chemical potential, kinetic, or potential energy and, therefore, there is no
possibility of producing work from any form of interaction between parts of the
environment. Any system outside the environment whichthat has one or more
parameters, such as pressure, temperature, or chemical potential, thatwhich differs
from the corresponding environmental parameter, has the potential to produce useful
work as it interacts with the macro-environment and drives toward equilibrium with it
(i.e., transitions to the dead state).
B.2.4 Equilibrium
The Environmental State
Equilibrium can be conceptualized in two forms: :
• Restricted equilibrium, in which conditions of mechanical and thermal
equilibrium between the system and the environment are satisfied, requires the
pressure and the temperature of the system and environment to be equal. The
adjective “restricted” indicates that, under these conditions, the substances of the
system are restrained by a physical barrier that prevents the exchange of matter
between system and environment. Under conditions of restricted equilibrium, there
are no requirements of chemical equilibrium between system and environment.
• In “unrestricted” equilibrium, the conditions of mechanical, thermal, and
chemical equilibrium between the system and the environment are satisfied.
Therefore, in addition to pressure and temperature, the chemical potentials of
the substances of the substance of the system and environment must be equal.
Under these conditions of full thermodynamic equilibrium between system and
environment, the system cannot undergo any changes of state through any form
of interaction with the environment. Unrestricted equilibrium of a system relative
to the macroenvironment is, thus, the dead state.
Exergy Associated Wwith A Work Transfer
Because we have defined the available work equivalent of a given form of energy
as a measure of its exergy, work is clearly equivalent to exergy in every respect. Thus,
exergy transfer can be specified both in magnitude and direction by the work transfer
to both the work transfer rate, or power, and for the associated exergy transfer rate.
B.2.5 Exergy Associated with a Heat Transfer
The exergy of a heat transfer at the control surface is determined from the maximum
work that could be obtained from it using the environment as a reservoir of zero-grade
thermal energy. For a heat transfer rate Qr and a temperature Tr at the control surface
where the heat transfer is taking place, the maximum rate of conversion from the
thermal energy to work is:
WMAX = E Q = Qrτ
where
τ = 1−
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T0
Tr
B-8
B-9
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APPENDIX B
τ is the dimensionless exergetic temperature and is equal to the Carnot efficiency
for the special case when the macroenvironment at temperature T0 is used as a thermal
energy reservoir.
B.2.6 Exergy Associated with a Steady Stream of Matter
Exergy of a steady stream of matter is equal to the maximum amount of work
obtainable when the stream is brought from its initial state to the dead state. Thus, the,
exergy of a stream of matter is a property of two states: the state of the stream and the
state of the environment.
As with energy, exergy E of a stream of matter can be divided into distinct
components:
E = Ek + Ep + Eph + E0
B-10
where Ek is kinetic energy of the system in motion relative to the macroenvironment,
Ep is the potential exergy of the system via its gravitational position in the macroenvironment, Eph is the physical (mechanical) exergy, and E0 is chemical exergy
following from the differences in chemical potential between the system components
and the macroenvironment.
Introducing the mass of the isolated system, specific exergy ε= E⁄m :
ε = εk + ε p + εhk + ε0
B-11
The kinetic and potential energies of a stream of substance are ordered forms of
energy and thus “fully” convertible to work. Therefore, when evaluated in relation to
the environmental reference, they are equal to kinetic and potential exergy respectively.
Thus,
2
B-12
Ek = m C
2
EP = mg E Z 0
B-13
where m becomes is the mass flow rate of the fluid stream, c is the bulk velocity of
the fluid stream relative to the surface of the earth, Z0 is the altitude of the stream above
the sea level, and gE is gravitational acceleration, considered a constant.
Use of environmental reference states for c and Z is only important where there is
direct interaction of the stream with the environment, for example, when evaluating
kinetic exergy of the exhaust gases of an engine. In most other cases, only changes in
kinetic and potential exergies are associated and, therefore, any inertial reference frame
may be used.
B.2.7 Physical and Chemical Components of Exergy
In principle, the total exergy derived from disordered energy forms could be
determined in one idealized device where the stream would undergo physical and
chemical processes while interacting with the environment. It is convenient, however,
to separate physical exergy Eph and chemical exergy E0, enabling calculation of exergy
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values using standard chemical exergy tables. The dividing state in the processes that
are used to determine physical and chemical exergy is the environmental state (T0 , P0 )
(McGovern, 1990; VM, 1973)
The total exergy of a simple system or quantity of substance is
E = U − U * − T0 ( S − S * ) + P0 (V − S * ) + Σ( µi* − µ0,i ) Ni
B-14
The superscript * refers to the thermomechanical dead state of the system, whereas
subscript 0 refers to properties of the specified reference environment. µi* represents the
chemical potential of substance i within the system, whereas µ0,i represents the chemical
potential of the same substance i in the specified reference environment.
This expression represents the total exergy of a system at a specified state as defined
by three independent thermodynamic properties (usually T and P) and its chemical
composition (expressed as the numbers of moles of all substances present) with respect
to a reference environment as specified by the three independent thermodynamic
properties (again usually T and P) and its chemical composition (in terms of the mole
fractions, Ni of all substances present). The chemical potential pi of a component i
within a system is the partial molar Gibbs free energy of that component such that for
the system,
G = ∑ µi Ni
B-15
For a particular chemical species i which is at its partial pressure pi* within a system
at the thermomechanical dead state and that also exists in the specified reference
environment, the chemical exergy is equal to the reversible isothermal work that would
be done if the substance were to expand from its actual partial pressure to its partial
pressure in the specified reference environment. If the chemical species is an ideal gas,
this can be represented as
p
Ech ,i = mi RT
i 0ln p
*
i
B-16
o, i
Thus, for a system consisting of a mixture of ideal gases which all exist in the
specified reference environment,
p
Ech = Σmi RT
i 0ln p
*
i
B-17
o, i
Exergy transfer corresponding to work consists of:
EW = W − p0 ∆V
B-18
Ew,s = Ws
B-19
Ew,n = Wn = p0 ∆V
B-20
where Ew,s is shear work exergy and, Ew,n is normal work exergy.
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APPENDIX B
The energy equation for a steady flow system is
h1 + C2 + gz1 + q = h2 + C2 + gz2 + w
2
1
2
2
B-21
Here the term w represents the shear work done by the steady flow system and
excludes the flow work interactions (normal work) at system boundaries 1 and 2.
Heat transfer energy is:
EQ = T T−T Q
0
B-22
This expression applies for conductive heat transfer.
In a closed sytem, the non-flow exergy function is as follows:
A = U − T0 S + poV
B-23
where A is the Helmholtz free energy and U is the internal energy of the system.
The exergy of a closed system can be written as
E = A − A*
B-24
The exergy between two states is given by
E1−2 = A1 − A2
B-25
For open systems, the thermomechanical flow exergy is defined as follows:
ε = H − H 0 − T0 ( S − S0 )
B-26
where H is the enthalpy (U + PV) , and S is the entropy.
It is also common to define the flow exergy function as
B = H − T0 S
B-27
Thus, the reversible shear work transferred from the system to some useful work
reservoir for a flow process from state 1 to state 2 in which only reversible heat transfer
interaction with the specified reference is allowed is given by
Ws = B1 − B2
B-28
The lost work theorem, states that the exergy destruction is equal to the product of
T0 and the entropy generated within the system:
i = T0 ( s2 − s1 ) − ∫ dqT
B-29
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The rational efficiency is therefore defined as follows. Let E1-2 represent the
decrease in the exergy of the system over the period for which the rational efficiency is
defined. E1 > E2, then the rational efficiency, ψ, is given by
ψ=
∑ Eout, k
∑ Ein ,1 + E1−2
B-30
ψ=
∑ Eout ,k + E2−1
∑ Ein ,1
B-31
If E1< E2 then
If the system undergoes no change, as in the case of a steady-flow system, or
returns to its initial state, as in a cycle, then E2-1 = E1-2 = 0 and
∑ Eout ,k
ψ=
∑ Ein ,1
B-32
The definition of the universal rational efficiency can be summarized in a single
expression as follows:
Σ exergy outputs to all systems
ψ=
B-33
[any exergy increase of thee system] +Σ exergy outputs to all systems
B.2.8 Carbon Dioxide Emissions Equation Based on Exergy
CHP is well developed and studied by different companies and governments
because of its high efficiency and low emission rate relative to conventional gridsupplied electricity and a separate boiler. Nonetheless, the allocation of carbon dioxide
(CO2) is not that well understood. Several traditional energy perspective methods
calculate the allocation of CO2 emissions.
Allocations Based on Energy Content of Products
Allocations proportionate to the energy contents in the products are given as:
fE = E
fQ = Q
(E + Q)
B-34
(E + Q)
B-35
where fE and fQ are the fractions of the emissions from the electrical and thermal
products, respectively.
E and Q stand for the net outputs of electrical energy and thermal energy from the
CHP system, respectively.
Allocations Based on Economic Value of Products
Allocations proportionate to the economic value of the products are given as
c E
fE = E
B-36
(E + Q)
fQ =
cQQ
(E + Q)
B-37
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APPENDIX B
where cE and cQ denote for the unit economic values of electricity and heat,
respectively.
The fraction can also be described as:
fE = E
c
 −1 



 E + Q  E cQ  

 

fQ = Q
 E  cE  + Q 
  cQ 

B-38
B-39
Allocations Based on Incremental Fuel Consumption to Electrical Production
Fuel consumption is described as follows:
FQ = Q
ηB
B-40
where ηB is the energy efficiency of the independent devices for thermal energy.
The fuel consumption by electricity generation is
FE = F − FQ
B-41
Then
fQ =
Q
Fη B
f E = 1 − fQ
B-42
B-43
The problem with traditional CO2 emissions methods is that the results are not
commonly accepted and it is thought that the reasoning is not well established (Rosen
2006). To some degree, the results could be conflicting. In many cases, the use of those
methods is overly complex.
The exergy-based method of CO2 allocation is more rational and meaningful. It
avoids the the difficulties in quantifying the differences in the quality of different forms
of energy irrespective of the quantities of energy, because the electricity and heat values
in CHP have a noticeable difference in quality.
Advantages of Exergy-Based Method
In the application of CHP, some of the electrical production from a primary fuel
could be lost to achieve a greater useful thermal output. From an exergy analysis view, a
small decrease in electricity generation increases a proportional amount of thermal exergy.
The analysis above indicates that exergy efficiency of electricity generation ψE is
similar to the heat exergy generation efficiency ψQ. The energy efficiency of electrical
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generation efficiency is inversely proportional to the heat generation efficiency. The
exergy-based method involves the quality of both power and heat. It avoids the problem
in giving the share of emissions into electricity production, and it gives a lower portion
of emissions to the thermal production.
C is the total CO2 emissions for a multi-product production, expressed as
C = C E + Cq
B-44
CE and CQ are the CO2 emissions with the electrical and thermal energy products.
C could be also defined as
C = Fφ
B-45
where F is the total fuel usage and φ is the CO2 emission coefficient.
The total CO2 emissions C can also be written as
B-46
C = ( FE + FQ )ψ
The fuel exergy consumption, EXFE and generating the electrical exergy EXE
EX =
EX
E
FE
B-47
ψE
where ψE is the exergy efficiency of generating the electrical energy product in the
process.
EXFQ is the thermal production exergy, expressed as:
EX =
EX
Q
FQ
B-48
ψQ
where ψQ is the exergy efficiency of thermal energy.
The fractions for fE and fQ are
 EX



ψ
E
fE = 
E
E
 EX

+ X


ψ
ψ
E
Q

E
 EX



ψ
Q
fQ = 
B-49
Q
Q
E
 EX

+ X


ψ
ψ
E
Q

E
B-50
Q
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APPENDIX B
B.3 EXERGY ANALYSIS EXAMPLES
Strictly speaking, exergy is the portion of energy that could convert into useful
work, but exergy analysis can indicate when such energy might be more effectively used
as heat in a thermal process addressed by the system, rather than attempting to convert
to it to mechanical work or electrical energy. Only during ideal processes would exergy
be conserved; otherwise, it would decrease in direct proportion to the entropy created.
First law energy analysis is widely implemented in all different aspects of industrial
applications. First law energy analysis alone ignores the quality of energy being addressed
and therefore does not address considerations to establish the relative value of converting
the potential energy of a system at question into work or its application as immediately
useful thermal energy. Stated alternatively, high-efficiency equipment may have a very
low efficiency if it is forced to use low-quality energy forms. Thermal-energy-dependent
equipment efficiencies or effectiveness factors may be optimized by careful consideration
of the degradation of changes in the quality of the thermal energy in the utilization
processes. Exergy analysis reveals the energy utilization issues that can be ignored in
first law energy analysis. It offers an insightful view of the characteristics of systems and
helps in design of efficient systems by indicating the nodes at which energy is most
effectively converted to different useful forms to meet the goals of the system.
B.3.1 Example 1: District Energy Systems
District energy systems provide energy to communities to meet the thermal loads.
The system may include boilers and chillers providing . The system provides hot water,
steam, or chilled water systems via underground piping systems. A CHP district energy
system is capable of providing electricity, heating, and cooling to a community.
A proposed district CHP based system in Edmonton, Alberta, Canada was
investigated by Rosen et al. (2004). The system would have an initial capacity of 230
MW for heating and 100 MW for cooling, incorporating central chillers and a cooling
network. The addition of absorption chillers is proposed for the future and the
relationship to the CHP system (see Figures B-2 and B-3).
Efficiency Analysis
Heating
The electricity generation rate W is the function of heat generation rate QH andwith
the use of an electric chiller:
CHP
B-51
W = η elec
Q H
CHP
η elec
( )
For an absorption-based CHP configuration, W is a function of the heat product
generation rate and the heat in the absorption chiller generator:
W =
( ) (Q
η CHP
elec
η CHP
elec
H
+Q gen)
B-52
CHP
where ηCHP
elec and η heat are the electrical and heat efficiencies of the CHP, respectively.
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The overall efficiency is defined as:
η
CHP
tot
=
W + QH
E f
B-53
W + Q H + Q gen
E f
B-54
For absorption-chillers-based CHP,
η
CHP
tot
=
where Ef is the fuel input rate.
Figure B-2. Simplified Diagram of CHP District Energy System Proposed by Edmonton Power.
(Rosen et al. 2004)
Figure B-2 (SI). Simplified Diagram of CHP District Energy System Proposed by Edmonton
Power (SI version) (Rosen et al. 2004)
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APPENDIX B
Figure B-3. Modified Version of Production Process
The total exergy efficiency for electric chillers based CHP is
ψ
W + τ Q + Q H
(RE ) f
B-55
W + τ Q Q H + τ Q Q gen
(RE ) f
B-56
CHP
tot
=
H
For absorption-chillers-based CHP,
ψ
CHP
tot
=
gen
H
where τQH and τQgen , respectively, are the exergetic temperature factors for QH and
Qgen. For heat transfer at a temperature T, τ ≡ 1 – T0⁄T (Kotas 1985), where T0 is the
environmental temperature. R is the energy grade function; for most fossil fuels, it is
between 0.9 and 1.0 (Dincer et al. 2003; Kotas 1985).
Cooling
The exergy efficiency for an electric-chiller-based system is:

ψ ch = −τ Q QC
H
Wch
B-57
For absorption-chillers-based CHP,

ψ ch = −τ Q QC
H
τ Q Q gen
B-58
gen
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Table B-1. Overall and Subsystem Efficiencies for CHP-based District Energy System
Energy efficiency, η(%)
System
One-stage
Centrifugal absorption
chiller
chiller
Exergy efficiency, ψ(%)
Two-stage
absorption
chiller
One-stage
Centrifugal absorption
chiller
chiller
Two-stage
absorption
chiller
Heating side*
85
85
85
30
31
31
Cooling side†
532‡
80‡
143‡
14
9
12
94
83
88
28
29
29
Overall system
*The heating side includes cogeneration, district heating and end-use heating.
†
The cooling side includes chilling, district cooling and end-use cooling.
‡
These are coefficient of performance (COP) values when divided by 100.
Transport for heating and cooling
The pipes are considered perfectly insulated so that there is no heat loss or
infiltration during the transport of fluid.
For heating:
τ Q Q Hu
ψDH = 
τ Q QH
u
H
B-59
H
For cooling:
 Cu
ψ DC = −τ Q Q
u
C
B-60
−τ Q QC
C
End-use heating and cooling
For heating:
ψ UH = τ Q
u,s
H
u,s
 u,w
Q H +τ Q u,w
H QH
τQ u Q Hu
B-61
H
For cooling:
u,r
Q C
τQ u Q Cu
ψ UC = −τ Q
−
u,r
C
B-62
C
The overall system efficiency based on the first law is

fsys =Wnet +
u,s
u,w
u,r
Q H + Q H + Q C
B-63
E f
The overall system exergy efficiency is

ψ sys =Wnet + τ Q
u,s
H
u,s
u,w
u,r
Q H + τ Q Q H − τ Q Q C
u,w
H
( RE )f
u,r
C
B-64
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APPENDIX B
Research results
From a first law analysis point of view, the system seems to achieve high efficiency.
The comparison with exergy analysis demonstrates that the first law energy analysis
cannot provide a meaningful understanding of the system. The exergy efficiency is much
lower than the energy efficiency. The low exergy efficiency of the chillers is the main
reason for the low exergy efficiency for the whole system.
The difference between exergy and energy analysis is mainly because the first law
energy utilizes the energy quantity and ignores the quality of different forms of energy.
The electricity exergy and energy analysis is identical, but the thermal energy analysis
involves the quality. This research improved the understanding of efficiencies of the
district energy and its components. It may help designers and engineers to simulate and
understand the exergy in district CHP systems.
B.3.2 Example 2: Hot Water Boiler
A traditional oil-fired boiler has a water flow output temperature of 95°C and return
temperature of 60°C. The excess air flow rate is 10% of the stoichiometric requirement,
and flue gas temperature is 250°C. The first law energy efficiency is calculated as 84.6%.
Efficiency Analysis
For exergy analysis, the assumptions are the following:
The system provides electric power to the electrical auxiliaries of the boiler. The
system also provides the fuel to burn. The flow of water is the heat transfer medium.
Exergy input for the electricity:
It is assumed that the energy input via electricity is one-half the 100 units of
calorific values at the system boundary.
Exergy input for the fuel:
For 100 units of calorific value of the fuel, the exergy is 106.8 units.
Exergy output to the hot water
From the equation (McGovern, 1990b):
Ξ
Q
 T 1n(T2 / T1 ) 
= Q 1 − 0

T2 − T1 

B-65
where Ξ is the total exergy. Substituting values for this example,
Ξ
C
 298.15 1n{( 95 + 273.15) / (60 + 273.15)} 
= 1 −
 85
95 − 60


= 12.67
B-66
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The rational efficiency of the boiler is
ψ=
ΞC
=
ΞA + ΞB
12.67 = 11.8%
106.8 + 0.5
B-67
This low rational efficiency demonstrates that there is still a huge space for
improvement for the boiler, even though it has a first law efficiency of 85%.
B.3.3 Example 3: Microturbine CHP
A microturbine is similar to a gas turbine that burns natural gas and other liquid fuel to
produce electricity in generators. A recuperator recovers the heat in the flue gas to increase
the electricity generation efficiency. With the high reliability and energy efficiency, the
microturbine is environmentally friendly. It also offers flexibility in connection with the
grid and loads. The research in this example (Makhdoum and Agnew 2011) models a 200
kW microturbine under ISO conditions. The system includes a single-effect absorption
chiller, an organic Rankine cycle with R-245fa as the working fluid, a multieffect distillation
(MED), and a thermal vapor compression MED desalination plant (TVC-MED).
Efficiency Analysis
The thermal efficiency of the microturbine is based on the first law of energy
conservation as the ratio of work obtained to the input of energy:
ηmicroturbine =
Wnet
Qin
=
Wmicroturbine − ∑W pump
B-68
m × LHV
where LHV is the lower heating value of the fuel, W is the work generated, Q is the
unit of heat input, and m is the mass flow rate in kg/s.
Carbon dioxide (CO2) emission rate
CO2 Emission Rate =
m × α
W
∑ net ,output + ∑ Qnet ,output
B-69
where α is the amount of CO2 produced for each ton of fuel.
The exergy of the system is:
E = E KN + E PT + E CH + E PH
E
PH
B-70
where, EKN is kinetic exergy, EPT is potential exergy, ECH is chemical exergy, and
is physical exergy.
The fuel exergy exergy is
E fuel = Θ × ηc.c × m fuel × LHV
B-71
Θ is the molar Gibbs function of formation, which equals 1.04 for natural gas ηc,c
is the efficiency of the combustion chamber.
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APPENDIX B
The physical exergy of a closed system is
E PH = ( h − h0 ) − T0 × ( s − s0 )
B-72
Research results
From the first law analysis showed that the microturbine with an absorption chiller
reduces 41% of the carbon dioxide emissions and has an energy utilization factor of
65%. This is because the exhaust heat was recovered in the absorption chiller. The
second law exergy analysis indicated that the most exergy destruction was in the
entrance of the absorber, this resultinged from the mixing process and heat transfer
between three streams entering the absorber.
B.3.4 Countrywide Exergy Analysis
The exergy method has been used in countrywide energy system analysis for more
than 30 years. The research is generally divided into four groups: domestic, industrial,
service, and transportation. This helps to find the exergy potential in each sector. The
electricity generation has a low exergy efficiency this is primarily due to the way we
produce electricity and utilization: the loss in combustion and heat transfer in the
electricity generation and space heating.
Exergy Analysis Equations in Practice
Exergy is lost and quality is decreased in every real irreversible process. The second
law of thermodynamics can be formulated in an manner similar to the first law:
∑ε
in
min − ∑ ε in min − ∑ ( E Q − E W ) − I = 0
B-73
where EQ and EW are the exergy transfers associated with Q and W, respectively.
I is the loss of exergy because of irreversibility, and ε is the specific exergy.
Exergy efficiency:
ψ=
Eout
= 1 − E1 < 1
Ein
in
B-74
The exergy is an extensive property, and defined by the system and reference
environment: temperature T0, pressure p0 , and chemical potential µi0:
E = ( H − H 0 ) − T0 ( S − S0 ) + ∑ Ni ( µi − µi 0 )
B-75
For the heat transfer and a constant temperature, the thermal exergy is given by
(
)
T
EQ = 1 − T Q
0
p
B-76
Domestic gas-fired and electric heating equipment exergy efficiency are given by
(1 − )
ψ=
T0
Tp
We
Q
( )
T
= 1 − T0 η
B-77
p
where η is the electrical efficiency, equal to Q/We.
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From these equations, we know that reference temperature T0 influences the exergy
efficiency. When the process temperature Tp is low, for example, as in space heating,
the exergy efficiency is reduced by 50%. At high process temperatures, the exergy
efficiency only decreases by 20%.
Conclusions
Exergy analysis is a significant engineering and policy analysis tool. It provides a
different understanding of complex energy systems. For example, Reistad (1975) noted
that, from the first law perspective, the energy loss is in the condenser, and there is little
room for improvement, unless by “the bottoming cycle.” Second law analysis shows
the major exergy losses are in the combustion process and heat exchangers.
Researchers found that the residential/commercial sectors have higher potential for
energy savings, because of the huge difference between the overall energy and exergy
efficiencies. More specifically, the exergy efficiency is generally lower than the energy
efficiency, because it takes the quality of energy into account. In addition, although the
building industry is less energy intensive than other fields of industry, it is more likely
to encounter challenges related to energy use.
B.4 FUEL GAS COMPRESSOR LOAD CALCULATION
The parasitic load resulting from a natural gas compressor can be estimated using
the following equation as found in Gas Engineers Handbook (1965).
Hp = (3.0325 × 10 − 6) × Qs × ( Ps × T1 × Z / Tse ) × K × [C (1 / K ) − 1]
B-78
where
H p = parasitic load,
K = k / ( k − 1)
k = specific heat ratio=1.26
Qs = gas flow, scf/day
Ps = standard pressure = 14.73 psia
Ts = sttandard temperature = 520 R
T1 = gas inlet temperature,  R
Z = compressibility factor (approximately 0.95 to 1.00 over
the range of temperatures and pressures of interest))
e = compressor efficiency
C = pressure ratio
Pressure ratio C is the ratio of the absolute discharge pressure to the absolute inlet pressure.
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SELECTED BIBLIOGRAPHY
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RP-1592
Complete Guide to Combined Heat and Power
This guide provides up-to-date application and operational information about prime
movers, heat recovery devices, and thermally activated technologies; technical and
economic guidance regarding CHP systems design, site screening, and assessment
guidance and tools; and installation, operation, and maintenance advice. As well as a
glossary of terms, the book features extensive, detailed case studies on implementations
in university, industrial, and hotel settings. Information is presented in both Inch-Pound
(I-P) and International System (SI) units.
Also included with the book is access to the newly developed ASHRAE CHP Analysis
Tool, a Microsoft® Excel® spreadsheet (in I-P units only) for use in assessing sites for
CHP applicability.
Combined Heat and Power Design Guide is an essential resource for consulting
engineers, architects, building owners, and contractors who are involved in evaluating,
selecting, designing, installing, operating, and maintaining these systems.
COMBINED HEAT AND POWER DESIGN GUIDE
Combined Heat and Power Design Guide was written by industry experts to give
system designers a current, authoritative guide on implementing combined heat and
power (CHP) systems. CHP systems provide electricity and useful thermal energy
in a single, integrated system. Heat that is normally wasted in conventional power
generation is recovered as useful energy, avoiding the losses that would otherwise be
incurred from separate generation of heat and power. Recent advances in electricityefficient, cost-effective generation technologies—in particular, advanced combustion
turbines and reciprocating engines—have allowed for new configurations of systems
that combine heat and power production, expanding opportunities for these systems
and increasing the amount of electricity they can produce. Combined Heat and Power
Design Guide provides a consistent and reliable approach to assessing any site’s
potential to economically use CHP systems.
COMBINED
HEAT AND POWER
DESIGN GUIDE
ISBN 978-1-936504-87-9
1791 Tullie Circle
Atlanta, GA 30329-2305
404-636-8400 (worldwide)
www.ashrae.org
ASHRAE_CHP-Design-Guide.indd 1
9 781936 50487 9
Product code: 90555
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