Power Plant Life Management and Performance Improvement (Woodhead Publishing Series in Energy)

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Power plant life management and performance improvement

© Woodhead Publishing Limited, 2011

Related titles: Modern gas turbine systems (ISBN 978-1-84569-728-0) This book provides a comprehensive review of gas turbine science and engineering. Coverage includes large-scale power generation as well as industrial and small-scale gas turbine applications. This coverage is extended with an examination of operational and maintenance issues, including performance monitoring and control, and modelling and optimisation techniques. Finally, advanced operating conditions and concepts are reviewed, including the pursuit of near-zero emissions power plants incorporating carbon capture technology. Oxy-fuel combustion for power generation and carbon dioxide (CO2) capture (ISBN 978-1-84569-671-9) Oxy-fuel combustion is currently considered to be one of the major technologies for carbon dioxide (CO2) capture in power plants. The advantages of using oxygen (O2) instead of air for combustion include a CO2-enriched flue gas that is ready for sequestration following purification and low NOx emissions. This book critically reviews the fundamental principles, processes and technology of oxy-fuel combustion, including advanced concepts for its implementation. Advanced power plant materials, design and technology (ISBN 978-1-84569-515-6) Fossil-fuel power plants generate the majority of the world’s power, but many plants are ageing and cannot meet rising global energy demands and increasingly stringent emissions criteria. To ensure security and economy of supply, utilities are building a new generation of advanced power plants with increased output and environmental performance. This book initially reviews improved plant designs for efficiency and fuel flexibility, including combined-cycle technology and utilisation of lower-grade feedstocks. Coverage extends to advanced material and component use, and the incorporation of alternative energy conversion technology, such as hydrogen production. Environmental and emissions performance issues round off the book. Details of these and other Woodhead Publishing materials books can be obtained by: . . .

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Woodhead Publishing Series in Energy: Number 23

Power plant life management and performance improvement Edited by John E. Oakey

Oxford

Cambridge

Philadelphia

New Delhi


Published by Woodhead Publishing Limited, 80 High Street, Sawston Cambridge CB22 3HJ, UK www.woodheadpublishing.com Woodhead Publishing, 1518 Walnut Street, Suite 1100, Philadelphia, PA 19102–3406, USA Woodhead Publishing India Private Limited, G-2, Vardaan House, 7/28 Ansari Road, Daryaganj, New Delhi – 110002, India www.woodheadpublishingindia.com First published 2011, Woodhead Publishing Limited # Woodhead Publishing Limited, 2011; Chapter 14 # Alstom Power Limited, 2011 (which owns all intellectual property rights in Chapter 14, including but not limited to copyright) The authors have asserted their moral rights. This book contains information obtained from authentic and highly regarded sources. Reprinted material is quoted with permission, and sources are indicated. Reasonable efforts have been made to publish reliable data and information, but the authors and the publishers cannot assume responsibility for the validity of all materials. Neither the authors nor the publishers, nor anyone else associated with this publication, shall be liable for any loss, damage or liability directly or indirectly caused or alleged to be caused by this book. Neither this book nor any part may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, microfilming and recording, or by any information storage or retrieval system, without permission in writing from Woodhead Publishing Limited. The consent of Woodhead Publishing Limited does not extend to copying for general distribution, for promotion, for creating new works, or for resale. Specific permission must be obtained in writing from Woodhead Publishing Limited for such copying. Trademark notice: Product or corporate names may be trademarks or registered trademarks, and are used only for identification and explanation, without intent to infringe. British Library Cataloguing in Publication Data A catalogue record for this book is available from the British Library. Library of Congress Control Number: 2011935505 ISBN 978-1-84569-726-6 (print) ISBN 978-0-85709-380-6 (online) ISSN 2044-9364 Woodhead Publishing Series in Energy (print) ISSN 2044-9372 Woodhead Publishing Series in Energy (online) The publisher’s policy is to use permanent paper from mills that operate a sustainable forestry policy, and which has been manufactured from pulp which is processed using acid-free and elemental chlorine-free practices. Furthermore, the publisher ensures that the text paper and cover board used have met acceptable environmental accreditation standards. Typeset by Data Standards Ltd, Frome, Somerset, UK Printed by TJI Digital, Padstow, Cornwall, UK


Contents

Contributor contact details Woodhead Publishing Series in Energy Foreword Part I

1

xii xv xix

Power plant fuel flexibility, condition monitoring and performance assessment

1

Solid fuel composition and power plant fuel-flexibility

3

N. J. SIMMS, Cranfield University, UK 1.1 1.2 1.3 1.4 1.5 1.6 2

Introduction Fuel chemistry and characterisation Use of alternative fuels in combustion power plants and application of technology to improve fuel flexibility Future trends Sources of further information and advice References

3 5 30 33 34 35

Condition monitoring and assessment of power plant components

38

C. DE MICHELIS, Independent Consultant, previously CESI, Italy, C. RINALDI, RSE, Italy, C. SAMPIETRI, EXOVA, Italy and R. VARIO, CESI, Italy 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

Introduction Monitoring boiler and heat recovery steam generator Steam turbines and generators Condition monitoring of gas turbines In situ assessment of gas turbine hot parts by non-destructive techniques Remote monitoring solutions Future trends Sources of further information and advice


38 41 61 74 84 95 98 101

vi

Contents

2.9

References

3

Availability analysis of integrated gasification combined cycle (IGCC) power plants 110

103

A. LAUGWITZ, M. GRA¨BNER and B. MEYER, TU Bergakademie Freiberg, Germany 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10

Introduction Basic structure of integrated gasification Availability issues of the ASU Availability issues of the gasification unit Availability issues of acid gas removal (AGR) and sulfur recovery Availability issues of the combined cycle Summary of existing plants Forecast based on RAM modeling Future trends References

110 111 116 120 125 127 129 132 135 138

Part II Coal boiler plant: materials degradation, plant life management and performance improvement

143

4

145

Environmental degradation of boiler components N. J. SIMMS, Cranfield University, UK

4.1 4.2 4.3 4.4 4.5 4.6 4.7

Introduction Component operating environments Degradation mechanisms and modelling Quantification of damage and protective measures Future trends Sources of further information and advice References

145 147 152 169 172 175 176

5

Creep in boiler materials: mechanisms, measurement and modelling

180

V. SKLENICˇKA and L. KLOC, Institute of Physics of Materials, Academy of Sciences of the Czech Republic, Czech Republic 5.1 5.2 5.3 5.4 5.5 5.6

Introduction Creep deformation and damage mechanisms in boiler materials Measurement methods Effect of operating environment Predictive modelling Sources of further information and advice


180 181 191 197 211 216

Contents

vii

5.7

References

216

6

Microstructural degradation in boiler steels: materials developments, properties and assessment

222

J. DOBRZAN´SKI, Institute for Ferrous Metallurgy, Poland and A. HERNAS and G. MOSKAL, Silesian University of Technology, Poland 6.1 6.2 6.3

6.4 6.5 6.6 6.7 6.8 7

Introduction The development of steel for power engineering Methodology for assessing the state of a material and determining the residual durability of the operational elements under creep conditions Characteristics of microstructure and property degradation processes Preparation of a classification system for material after operation Modeling degradation processes and their use Conclusion References Boiler steels, damage mechanisms, inspection and life assessment

222 223

230 248 260 261 266 266 272

A. SHIBLI, European Technology Development, UK 7.1 7.2 7.3 7.4 7.5 7.6

Introduction Boiler materials, metallurgy and microstructure Damage mechanisms and component failure Inspection and monitoring of damage and integrity/life assessment issues in high chromium martensitic steels Sources of further information and advice References

Part III Gas turbine plant: materials degradation, plant life management and performance improvement 8

Creep, fatigue and microstructural degradation in gas turbine superalloys

272 274 283 291 301 302 305

307

P. AUERKARI, VTT Technical Research Centre of Finland, Finland 8.1 8.2 8.3 8.4

Introduction Creep Fatigue Combined creep and fatigue


307 308 314 319

viii

Contents

8.5 8.6 8.7 8.8

Microstructural degradation Future trends Conclusion References

322 327 328 328

9

Gas turbine materials selection, life management and performance improvement T. A´LVAREZ TEJEDOR, Endesa Generacioń, Spain

330

9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 9.10 9.11

Introduction Superalloys Protective coatings Material applications Advanced materials and coatings Life management and diagnostic Future trends Sources of further information and advice References Appendix 1: nomenclature Appendix 2: key definitions

330 332 368 377 399 403 409 411 414 417 418

10

Gas turbine maintenance, refurbishment and repair

420

A. D. WILLIAMS, Wood Group GTS, UK 10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 10.10 10.11

Introduction Field service overhaul and maintenance Parts refurbishment: incoming inspection Parts repair Coating and finishing technology Final repair operations Quality control and first article inspection Part life extension and optimisation Future trends Conclusion Further reading

Part IV Steam boiler and turbine plant: materials degradation, plant life management and performance improvement 11

Steam oxidation in steam boiler and turbine environments

420 421 426 429 436 445 445 446 448 449 449 451

453

G. R. HOLCOMB, National Energy Technology Laboratory, U.S. Department of Energy, USA 11.1

Introduction

453


Contents

ix

11.2 11.3 11.4 11.5 11.6 11.7 11.8 11.9 11.10

Steam boiler and turbine environments Oxidation thermodynamics and kinetics Scale morphology and spallation Steam oxidation management Future trends Conclusion Sources of further information and advice References Appendix: nominal alloy composition for alloys of interest

454 460 467 476 478 481 481 482 487

12

Steam boiler component loading, monitoring and life assessment

490

J. TALER and P. DUDA, Cracow University of Technology, Poland 12.1 12.2

12.3 12.4 12.5 13

Introduction Analysis of different ways of conducting start-up and shut-down operations and their influence on thermal and total stress loads in critical pressure components Monitoring of remnant lifetime of pressure components Conclusions References

490

491 498 514 516

Steam turbine materials selection, life management and performance improvement

518

R. W. VANSTONE and S. OSGERBY, Alstom Power, UK 13.1 13.2 13.3 13.4 13.5

Introduction High temperature cylinders Low temperature cylinders Conclusion References

518 519 524 533 533

14

Steam turbine upgrades for power plant life management and performance improvement

535

F. C. MUND, Alstom Power, UK 14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8

Introduction Drivers Product selection and specification Performance improvement Mechanical design Installation Conclusion References


535 537 539 547 557 563 569 571

x

Contents

14.9

Appendix: glossary

Part V Heat exchangers and power plant welds: materials management and performance improvement 15

572 573

High-temperature heat exchangers in indirectly fired combined cycle (IFCC) systems: materials management and performance improvement 575 J. P. HURLEY, University of North Dakota Energy & Environmental Research Center, USA

15.1 15.2 15.3 15.4 15.5 15.6

Introduction High-temperature heat exchanger (HTHX) construction Pilot-scale HTHX testing Conclusions Acknowledgments References

575 582 597 602 603 603

16

Heat recovery steam generators: performance management and improvement

606

V. GANAPATHY, Boiler & HRSG Consultant, India 16.1 16.2 16.3 16.4 16.5 16.6 16.7 16.8 16.9 17

Introduction Gas turbine heat recovery steam generators (HRSGs) How pinch and approach points affect HRSG size and steam generation HRSG simulation Improving HRSG efficiency Conclusion Further reading References Appendix: nomenclature Power plant welds and joints: materials management and performance improvement

606 611 618 621 628 633 633 633 633 635

D. J. ABSON, TWI, UK 17.1 17.2 17.3 17.4 17.5 17.6 17.7 17.8

Introduction Materials selection and development Weld/joint degradation Application of degradation-protection technologies Impact on power plant performance/life management Dissimilar joints Inspection and hardness testing Repair


635 636 639 646 647 648 651 653

Contents 17.9 17.10 17.11 17.12

xi

Future trends Sources of further information and advice Acknowledgements References

655 658 658 658

Index

666


Contributor contact details

(* = main contact)

Chapter 2

Editor

C. Rinaldi RSE via Rubattino 54 20134 Milan Italy E-mail: [email protected]

J. E. Oakey Energy Technology Centre Sustainable Systems Department Cranfield University Bedfordshire MK43 0AL UK E-mail: [email protected]

Chapters 1 and 4 N. J. Simms Centre for Energy and Resource Technology Department of Environmental Science and Technology School of Applied Sciences Cranfield University Cranfield Bedfordshire MK43 0AL UK E-mail: [email protected]

Chapter 3 A. Laugwitz IEC – Department of Energy Process Engineering and Chemical Engineering TU Bergakademie Freiberg Fuchsmu¨hlenweg 9 09596 Freiberg Germany E-mail: Alexander.Laugwitz@iec. tu-freiberg.de

Chapter 5 V. Sklenicˇka* and L. Kloc Institute of Physics of Materials Academy of Sciences of the Czech Republic Zˇizˇkova 22 CZ-616 62 Brno Czech Republic E-mail: [email protected]; [email protected]



xiii

Chapter 6

Chapter 9

J. Dobrzan´ski Institute for Ferrous Metallurgy 44-100, K. Miarki str. 12-14 Gliwice Poland E-mail: [email protected]

T. A´lvarez Tejedor Endesa Generacioń C) Ribera del Loira 28042 Madrid Spain E-mail: [email protected]

A. Hernas and G. Moskal* Silesian University of Technology Department of Materials Science 40-019, Krasin´skiego str. Katowice Poland E-mail: [email protected]; [email protected]

Chapter 10

Chapter 7 A. Shibli European Technology Development Ltd 6 Axis Centre Cleeve Road Leatherhead KT22 7RD Surrey UK E-mail: [email protected]

Chapter 8 P. Auerkari VTT Technical Research Centre of Finland POB 1000 FI-02044 VTT Finland E-mail: [email protected]

A. D. Williams Wood Group GTS Site 4 Piper Street Baldovie Industrial Estate Dundee Scotland DD4 0NT UK E-mail: andy.williams@woodgroup. com

Chapter 11 G. R. Holcomb U.S. Department of Energy National Energy Technology Laboratory 1450 Queen Ave SW Albany OR 97321 USA E-mail: [email protected]. gov

Chapter 12 J. Taler* and P. Duda Cracow University of Technology Al. Jana Pawøa II 37 31-864 Krako´w Poland E-mail: [email protected]; [email protected]


xiv


Chapter 13

Chapter 16

R. W. Vanstone and S. Osgerby* Alstom Power Newbold Road Rugby CV21 2NH UK E-mail: rod.vanstone@power. alstom.com; steve.osgerby@ power.alstom.com

V. Ganapathy Boiler & HRSG Consultant Flat B4 8-9 Nana Street T. Nagar Chennai 600017 India E-mail: [email protected]

Chapter 17 Chapter 14 F. C. Mund Alstom Power Newbold Road Rugby CV21 2NH UK E-mail: friederike.mund@power. alstom.com

Chapter 15 J. P. Hurley University of North Dakota Energy & Environmental Research Center 15 North 23rd Street Stop 9018 Grand Forks ND 58202-9018 USA E-mail: [email protected]

D. J. Abson TWI Granta Park Great Abington Cambridgeshire CB21 6AL UK E-mail: [email protected]

Woodhead Publishing Series in Energy

1

Generating power at high efficiency: Combined cycle technology for sustainable energy production Eric Jeffs

2

Advanced separation techniques for nuclear fuel reprocessing and radioactive waste treatment Edited by Kenneth L. Nash and Gregg J. Lumetta

3

Bioalcohol production: Biochemical conversion of lignocellulosic biomass Edited by K.W. Waldron

4

Understanding and mitigating ageing in nuclear power plants: Materials and operational aspects of plant life management (PLiM) Edited by Philip G. Tipping

5

Advanced power plant materials, design and technology Edited by Dermot Roddy

6

Stand-alone and hybrid wind energy systems: Technology, energy storage and applications Edited by J.K. Kaldellis

7

Biodiesel science and technology: From soil to oil Jan C.J. Bart, Natale Palmeri and Stefano Cavallaro

8

Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 1: Carbon dioxide (CO2) capture, transport and industrial applications Edited by M. Mercedes Maroto-Valer

9

Geological repository systems for safe disposal of spent nuclear fuels and radioactive waste Edited by Joonhong Ahn and Michael J. Apted

10 Wind energy systems: Optimising design and construction for safe and reliable operation Edited by John D. Sørensen and Jens N. Sørensen


xvi


11 Solid oxide fuel cell technology: Principles, performance and operations Kevin Huang and John Bannister Goodenough 12 Handbook of advanced radioactive waste conditioning technologies Edited by Michael I. Ojovan 13 Nuclear safety systems Edited by Dan Gabriel Cacuci 14 Materials for energy efficiency and thermal comfort in buildings Edited by Matthew R. Hall 15 Handbook of biofuels production: Processes and technologies Edited by Rafael Luque, Juan Campelo and James Clark 16 Developments and innovation in carbon dioxide (CO2) capture and storage technology Volume 2: Carbon dioxide (CO2) storage and utilisation Edited by M. Mercedes Maroto-Valer 17 Oxy-fuel combustion for power generation and carbon dioxide (CO2) capture Edited by Ligang Zheng 18 Small and micro combined heat and power (CHP) systems: Advanced design, performance, materials and applications Edited by Robert Beith 19 Advances in clean hydrocarbon fuel processing: Science and technology Edited by M. Rashid Khan 20 Modern gas turbine systems: High efficiency, low emission, fuel flexible power generation Edited by Peter Jansohn 21 Concentrating solar power (CSP) technology: Developments and applications Edited by Keith Lovegrove and Wes Stein 22 Nuclear corrosion science and engineering Edited by Damien Fe´ron 23 Power plant life management and performance improvement Edited by John E. Oakey 24 Direct-drive renewable energy systems Edited by Markus Mueller and Henk Polinder 25 Advanced membrane science and technology for sustainable energy and environmental applications Edited by Angelo Basile and Suzana Pereira Nunes



xvii

26 Irradiation embrittlement of reactor pressure vessels (RPVs) in nuclear power plants Edited by Naoki Soneda 27 High temperature superconductors (HTS) for energy applications Edited by Ziad Melhem 28 Infrastructure and methodologies for the justification of nuclear power programmes Edited by Agustıń Alonso Santos 29 Waste to energy (WtE) conversion technology Edited by Marco Castaldi 30 Polymer electrolyte membrane and direct methanol fuel cell technology Volume 1: Fundamentals and performance Edited by Christoph Hartnig and Christina Roth 31 Polymer electrolyte membrane and direct methanol fuel cell technology Volume 2: In situ characterisation techniques Edited by Christoph Hartnig and Christina Roth 32 Combined cycle systems for near-zero emission power generation Edited by Ashok Rao 33 Modern earth buildings: Materials, engineering, construction and applications Edited by Matthew R. Hall, Rick Lindsay and Meror Krayenhoff 34 Handbook of metropolitan sustainability: Understanding and improving the urban environment Edited by Frank Zeman 35 Functional materials for energy applications Edited by John Kilner, Stephen Skinner, Stuart Irvine and Peter Edwards 36 Nuclear decommissioning: Planning, execution and international experience Edited by Michele Laraia 37 Nuclear fuel cycle science and engineering Edited by Ian Crossland 38 Electricity transmission, distribution and storage systems Edited by Ziad Melhem 39 Advances in biodiesel preparation: Second generation processes and technologies Edited by Rafael Luque and Juan Antonio Melero


xviii


40 Biomass combustion science, technology and engineering Edited by Lasse Rosendahl 41 Ultra-supercritical coal power plant: Materials, technologies and optimisation Edited by Dongke Zhang 42 Radionuclide behaviour in the natural environment: Science, impacts and lessons for the nuclear industry Edited by Horst Geckeis and Christophe Poinssot 43 Calcium and chemical looping technology for power generation and carbon dioxide (CO2) capture: Solid oxygen- and CO2-carriers P. Fennell and E.J. Anthony 44 Materials ageing and degradation in light water reactors: Mechanisms, modelling and mitigation Edited by K.L. Murty 45 Structural alloys for power plants: Operational challenges and hightemperature materials Edited by Amir Shirzadi, Rob Wallach and Susan Jackson 46 Biolubricants: Science and technology Jan C.J. Bart, Emanuele Gucciardi and Stefano Cavallaro 47 Wind turbine blade design and materials: Improving reliability, cost and performance Edited by Povl Brøndsted and Rogier Nijssen 48 Radioactive waste management and contaminated site clean-up: Processes, technologies and international experience Edited by William E. Lee, Michael I. Ojovan and Carol M. Jantzen 49 Probabilistic methods of strength reliability and their application for optimum nuclear power plant life management (PLiM) Gennadij V. Arkadov, Alexander F. Getman and Anderi N. Rodionov 50 Coal utilization in industry: Towards cleaner production Edited by D.G. Osborne 51 Coal power plant materials and life assessment: Developments and applications Edited by Ahmed Shibli


Foreword

A sustainable energy future will depend on making appropriate use of all possible resources while ensuring a stable and affordable supply that complies with current and future regulations for protecting the environment. Our future energy portfolio will aim to maximize the use of so-called renewable energy sources such as wind, solar (photovoltaic and solarthermal), geothermal, hydro, wave-power, and biomass, but it must involve realistic expectations for these sources. Further, transitioning to the maximized use of renewable energy must be coordinated with an orderly reduction of reliance on traditional energy sources currently used for baseline production of electric power, chiefly coal, natural gas, and nuclear fission. Some scenarios envisage continued reliance on nuclear power to maintain a baseline capacity. However, the ability to adjust the output of nuclear plants to cope with a need for large amounts of generating capacity at short notice, when renewable sources are unable to generate, for instance, is rather limited. Further, the size of this required ‘reserve’ capacity is considerable, as recent experience in the UK during the exceptionally cold and becalmed month of December 2010 attests, when many old and semiretired fossil power plants had to be brought on line to deputize for the absence of wind power. The only viable options for this reserve capacity at present are natural gas-fired gas turbines and coal-fired steam boilers, so that for the foreseeable future it appears that some degree of the overall generating capacity must continue to involve the traditional, non-renewable sources. In such duty, fossil-fired plants not only will be required to operate at maximum efficiency to be compatible with reduced emission of environmental pollutants (including carbon dioxide), but also must be capable of rapid load cycling. Maximizing efficiency of fossil-fueled systems based on the Brayton and Rankin cycles typically involves operation at the highest possible temperatures, pushing critical structural components to operate at their maximum temperature limits. In addition, normal commercial operation of these plants increasingly will require them to accept a range of fuels, such as


xx

Foreword

gaseous fuels with varying H/C ratios or derived from coal or biomass, and coal from different sources worldwide. The imposition of severe thermal cycling on the requirements for extreme high-temperature strength and improved environmental resistance further complicate the task of maintaining the desired reliable, long-term operating characteristics of these plants. Successful developments will require a detailed knowledge of how such changes in the operating environment influence the degradation and failure modes of key structural components, and the development of mechanistically-based predictive methods to allow the most appropriate scheduling of maintenance and avoidance of unexpected failures. The content of this volume provides excellent insight into the issues that need to be addressed if fossil-fueled power plants are to attain the desired higher levels of operating efficiency while maintaining the necessary levels of reliability. In particular, discussion of approaches being developed for life prediction of key components and the research to provide the underpinning base of understanding emphasize the importance of the linkages among these activities, and their importance to the reliable operation of these power systems. These issues also emphasize that once the mix of generating sources in our future energy portfolio is decided, appropriate investment will be needed to ensure that all approaches, renewable and traditional, can perform as intended and are ready in the desired timeframe. This goal requires not only establishing the infrastructure and maintenance procedures for the new, renewable, systems but also committing sufficient R&D resources to ensure that fossil- and biomass-based generation are as reliable and efficient as possible. Ian G. Wright Denver, Colorado, USA


1 Solid fuel composition and power plant fuel flexibility N . J . S I M M S , Cranfield University, UK

Abstract: A fundamental part of any power plant system is the fuel that it uses. For solid-fuel-fired systems, the composition of the fuels affects every aspect of the plants, from fuel handling and storage, through the fuel conversion process (e.g. combustion or gasification) and heat recovery/energy generation to the gas cleaning systems and environmental emissions (by gas, liquid or solid streams). Traditionally, coals have been used in large scale power plants, but now biomass and waste fuels are being introduced to reduce net CO2 emissions and to increase the consumption of more sustainable fuels. This chapter outlines the main types of solid fuels, analysis methods and their compositions, before highlighting the composition related issues that need to be considered in assessing their role in fuel switching and co-firing. Key words: coal, biomass, waste, fuel composition, fuel analyses, cofiring.

1.1

Introduction

One of the fundamental parts of any power generation system is the fuel that it uses. Many factors depend directly on the fuel used, for example: . . .

the type of power generation system, e.g. pulverised fuel, fluidised bed, moving grate; the scale of the system; for coal-fired boilers typically in the range 500– 800 MWe and for biomass-fired boilers usually less than 30 MWe; system efficiency; with coal-fired power stations having much higher

3 © Woodhead Publishing Limited, 2011

4


. .

efficiencies (typically ~35–47 %) than waste-fired systems (up to ~25 % efficiency); gas cleaning requirements and emissions; ash and other waste disposal, including solid and liquid products from the gas cleaning systems; economic viability.

.

Many of these topics are dealt with in detail in other chapters of this book, with this chapter focusing on solid fuel compositions. Potential solid fuels for generating power include: .

.

.

Coals. Traditionally large scale solid-fuel-fired power generation systems have been based on the use of pulverised coal, with the coal being sourced from local mines to minimise transport costs. However, variations in mining costs around the world, combined with national energy policies and national/international environmental regulations, have prompted an increase in world-traded coal. For example, UK government statistics show that in 2008, 48.3 m tonnes of coal were used for power generation (out of a total coal consumption of 58.2 million tonnes), with ~70 % of the coal used in the UK being imported (UK DECC, 2009). Biomass. Biomass, such as wood or crop residues, has traditionally been used to generate heat on a small scale but now biomass is being used in increasing quantities for the generation of both heat and electrical power. The growth of specific crops for use in energy generation systems is being actively encouraged and biomass fuel supply chains developed (EUBIONET2, 2007). A notable development in the use of biomass in recent years has been co-firing it with coal in traditionally pulverised coal-fired power stations; this has been actively encouraged as one route of minimising net CO2 emissions (UK DTI, 2007). Waste products. Within Europe, one route for the disposal of solid wastes has been via combustion processes to generate heat (e.g. in cement kilns) or to generate heat and/or power in waste to energy plants. Changes in the approach to dealing with waste, with increased emphasis on recycling and a reduction in the quantities going to landfill (Council of the European Union, 1999), have encouraged the consideration of wastes as potential fuels for power generation. In addition, significant fractions of some waste streams can be regarded as being biomass derived and so viewed as sustainable and renewable fuels (IEA Bioenergy, 2003).


Solid fuel composition and power plant fuel flexibility

5

In the drive towards reducing the impact of coal used for power generation in terms of CO2 emissions, approaches include: . . .

.

the use of more sustainable fuels, for example: ○ replacing coal with another fuel (biomass or waste products), and ○ co-firing coal with biomass or waste products; using natural gas as an alternative fuel; increasing the efficiency of electricity generation from coal, e.g. by building new more efficient advanced power stations, or using alternative generation processes such as fuel gasification, or by using the waste heat generated during these processes; using carbon capture and storage systems on existing and new solidfuel-fired power systems (post-combustion, pre-combustion and oxyfiring options).

This chapter focuses on the solid fuels (coals, biomass and wastes) that are currently available, the compositions of these fuels, methods of assessing them and issues that need to be considered for fuel flexibility.

1.2

Fuel chemistry and characterisation

1.2.1 Fuel specifications and analysis methods The analysis of fuels has developed in parallel to their use, and numerous standards have been developed for specific fuels in different countries and by different standards organisations (e.g. ASTM International, British Standards Institute (BSI), European Committee for Standardisation (CEN), International Organisation for Standardisation (ISO)). These various analytical standards have been developed to cover the requirements of different fuel users (e.g. coke production and iron ore smelting, as well as for power generation) in addition to the needs of regulatory bodies for use in applying environmental regulations, determining fuel subsidies, etc. From the point of view of using a fuel for power generation purposes, the key types of analyses can be grouped into those related to: . . .

chemical analyses, to show the chemical make-up of the fuel in different ways; physical analyses, to determine the properties that influence fuel preparation; other general properties needed for fuels, such as energy content, ash fusion temperatures, etc.


6


Chemical analyses During the last century various types of analyses have been developed to show the chemical make-up of coals, with many being aligned to meet the needs of specific industrial uses (Francis and Peters, 1980; Raask, 1985; Speight, 1994, 2005). Some of these analytical methods are now used to characterise coals for use in power generation systems and variations on them have been developed to enable biomass and waste fuels to be analysed to produce equivalent data (sections 1.2.2 to 1.2.4). .

Proximate analysis. This produces an analysis of the fuels in terms of four specific parameters (BS 1016, 2010): ○ ‘Moisture’ is a measure of the amount of water present in the fuel. It is measured by drying a fuel under standard conditions. Due to the different ways in which water can be present in a fuel (e.g. on the fuel surface, hydroscopically, associated with organic and inorganic compounds and/or in cell structures) a number of different methods have been developed to determine it, but they all measure the change in weight of the fuel as a result of a drying process. It is important to note that fuel moisture content can change between sampling and analysis, as well as during storage. Fuel moisture content is expressed as a percentage of the weight of water compared to the original fuel (i.e. on an as-received or wet basis). ○ ‘Ash’ is a measure of the non-combustible residue left after a fuel is burnt. This property is determined by thoroughly burning the fuel and then weighing the residue and expressing this as a percentage of the original as-received (i.e. wet) fuel, or the fuel after drying. These two measures of the ash content are related as follows: ashwt%dry ¼ ashwt%ar 6100=ð100 water contentðwt%ÞÞ

○

○

where ashwt% dry is the weight % of ash in the dry fuel and ashwt%ar is the weight % of ash in the as-received fuel. ‘Volatile matter’ is a measure of the components within a fuel (but excluding moisture) that are vapourised in the absence of air at high temperature. These components typically include a mixture of hydrocarbons (short and long chained, and aromatic compounds) as well as some sulphur and chlorine compounds. Due to the variable nature of the volatile components in fuels, this fuel parameter has to be determined under strictly controlled standard conditions. Volatile matter can be expressed in terms of the % by weight in a dry fuel, as-received fuel, dry and ash free (daf) fuel, or dry and mineral matter free (dmmf) fuel. ‘Fixed carbon’ is the carbon content of the fuel left after the volatile


Solid fuel composition and power plant fuel flexibility Table 1.1 basis

7

Relationship between proximate analysis parameters and analysis

Analysis basis

Method of calculation of fixed carbon in fuel

Dry Dry ash free (daf) As-received (ar)

Fixed C = 100 ash (dry) volatiles (dry) Fixed C = 100 volatiles (daf) Fixed C = 100 ash (ar) water content volatiles (ar)

Table 1.2 basis

Relationship between ultimate analyses parameters and analysis

Analysis basis

Definition

Dry Dry ash free (daf) As-received (ar)

C + H + O + N + S + Cl + ash = 100 C + H + O + N + S + Cl = 100 C + H + O + N + S + Cl + ash + water content = 100

.

.

.

matter is driven off. (It does not correspond to the carbon content of the fuel as carbon can be a significant part of the volatile matter content of the fuel.) This parameter was originally intended to give an indication of the suitability of a coal for coking purposes. It can be calculated in terms of % by weight on the basis of dry, dry ash free or as-received analysis, as indicated in Table 1.1. Ultimate analysis. This group of analyses produces measurements of the quantities of specific elements in fuels. The content of carbon (C), hydrogen (H), oxygen (O), nitrogen (N), sulphur (S) and chlorine (Cl) in fuels is commonly measured, with each being determined using different specific standard analysis techniques. The results of these analyses are expressed in terms of the % by weight of the element in the fuel on the basis of dry, dry ash free or as-received analysis, as indicated in Table 1.2. The oxygen content is often not measured but calculated as the difference between 100 and the % values of the measured components. When the oxygen content is measured the total sum may not equal 100 due to experimental errors in the various analyses. Ash analysis. Following the convention established in coal analysis standards (Stringer, 1995; ASTM-D3174-11, 2011), the results of ash analyses are often expressed in terms of the % by weight of the elements in the dry ash in terms of their highest oxides. These oxides are not representative of the actual chemical compounds in the ashes that contain these elements (section 1.2.2), and so care is required in interpreting such data (Stringer, 1995). Minor and trace metal analysis. The content of the metal elements present in fuels can also be determined by a wide range of analytical techniques, including emission spectroscopy, flame photometry, ICP-


8


.

MS, etc., according to specific standards for the different fuels (sections 1.2.2 to 1.2.4) (Francis and Peters, 1980; Raask, 1985; Clarke and Sloss, 1992; Carpenter and Skorupska, 1993; Speight, 1994, 2005; van Loo and Koppeian, 2007). In these cases, the results are usually expressed in terms of the mg of element per kg of dry fuel (i.e. ppm). Biochemical composition. For some fuels it is appropriate to determine their biochemical composition (van Loo and Koppeian, 2007). This is usually expressed in terms of the % by weight in the dry material: e.g. for cellulose, hemi-cellulose, lignin, fats, protein, pectin, starch, extractives, C5 and C6 sugars, total non-structural matter, carbohydrates, etc.

Physical analyses . .

.

.

‘Bulk density’ of a fuel, in terms of kg/m3; this can vary widely between different types of fuel. ‘Grindability’ is an important parameter for coals that need to be processed by grinding before being used in a pulverised-fuel fired power station. One empirical method of measuring this is the Hardgrove grindability index (BS 1016 – Part 20, 1981). ‘Abrasion’ is a process by which one material is worn away by another material passing over it. This is important for fuel handling systems in which fuels may contain a wide variety of constituents of varying hardnesses, some of which may cause damage to the handling systems. For coals this includes abrasion by quartz and pyrites. One simple test for abrasion involves putting the fuel into a rapidly rotating mill (1500 revolutions per minute) with four steel blades of known mass and then measuring the mass loss of the blades after 8 minutes of operation (Foster et al., 2004); the data generated give an abrasion index. Particle size distributions: these measurements are needed to ensure that the appropriate fuel preparation and handling equipment is used for the different fuels; e.g. to assess the performance of coal grinding mills on a specific coal, or coal–biomass mixture, or the effectiveness of biomass hammer mills in the preparation of biomass. Oversized fuel particles do not burn out completely and so reduce the efficiency of a combustion system, as well as increase the carbon content of ash residues. (For coalfired systems, this leads on to problems with the sale and use of pulverised fuel ash residues as cement replacement materials or in lightweight aggregates.) Particle sizes can be measured by standardised sieving, photometry and optical techniques.



9

Other general fuel properties .

Energy content. A critical property for any potential fuel is its energy content; this is often referred to as the calorific value of a fuel. Analytically, the energy content of a material can be measured using a bomb calorimeter and specific standard methods (sections 1.2.2 to 1.2.4). The values determined are usually the higher heating values, but following established conventions these results can be expressed in terms of either higher or lower heating values, with the difference being the heat of evaporation of the water formed from the hydrogen in the fuel as well as the moisture present in the fuel. Higher heating values (HHVs) are also referred to as gross heating values, calorific values and heats of combustion. Lower heating values (LHVs) are also referred to as net heating values (Phyllis, 2010).

As a large quantity of data on fuel energy contents and compositions has been generated over a long period of time, it has been found that it is possible to calculate HHVs from the fuel elemental composition. One example of this is the Milne formula (Phyllis, 2010): HHVMilne ¼ 0:341 C þ 1:322 H 0:12 O 0:12 N þ 0:0686S 0:0153 ash where C, H, etc., are the mass and the ash fractions in wt% of dry material and HHV the heating value in MJ/kg. By using the hydrogen and ash fractions (wt% dry) and moisture fraction w (wt% ar) the different HHVs and LHVs can be calculated, for example: HHVar ¼ HHVdry ð1 w=100Þ HHVdry ¼ HHVdaf ð1 ash=100Þ LHVar ¼ HHVar 2:442fð8:936H=100Þð1 w=100Þ þ w=100g .

Ash fusion. One of the frequently encountered challenges with fuels is that, under some operating conditions, the combustion residue (ash) can form a hard glassy slag on some heat exchanger surfaces. Most fuel conversion systems perform better with the ash in a powdery form (though systems do exist that handle ashes in molten form). Ash fusion tests are carried out by viewing moulded samples of fuel ashes (in the form of cones, pyramids or cubes) through windows in high temperature furnaces. A series of ash fusion temperatures have been defined (Raask, 1985): ○ initial deformation temperature, when the corners of the mould first become rounded;


10

Power plant life management and performance improvement ○ ○ ○

softening (sphere) temperature, when the top of the mould takes on a spherical shape; hemisphere temperature, when the entire mould takes on a hemisphere shape; flow (fluid) temperature, when the molten ash collapses to a flattened pool.

The ash fusion temperatures can be measured in both oxidising and reducing conditions, and are highly dependent on the detailed test methods used. Therefore, standards exist for specific fuels to enable comparable results to be obtained (sections 1.2.2 to 1.2.4). .

Coal petrology. This is a method of characterising coal by examining polished cross-sections by optical microscopy and determining the reflectance of three phases (liptinite, vitrinite and inertinite) within the coal structures. The vitrinite phase in particular can be used in the classification of coals (Speight, 2005).

1.2.2 Coal fuels Coals are fossil fuels derived from plant matter that has been saved by water and/or mud from oxidation and biodegradation and then subjected to high pressures and temperatures for prolonged periods; this process is described in detail elsewhere (e.g. Raask, 1985; Speight, 1994). Thus coals can be classed as sedimentary organic rocks. There are many variables that influence this process, including initial plant matter, pressure history, temperature history and time. As a result of differences in such variables during their formation, a wide range of coals have developed, but these can

1.1 Breakdown of coal constituents (adapted from Jones, 2005).



11

be thought of as being built up from a number of different types of materials. As illustrated in Fig. 1.1, the primary split is between coal matter (C, H, O, N, etc.) and inert material (moisture and various minerals). The inert material can be further broken down into its location within the coal structure. It should be noted that several elements can occur by more than one route in this view of the make-up of coal. As coal is a well established fuel around the world, numerous analytical methods have been developed and adopted by the various standard bodies (e.g. ASTM International, 2010; BSI, 2010; European Committee for Standardisation (CEN), 2010; ISO, 2010). Table 1.3 lists some of the coal related standards available from ASTM (2010), but similar standards exist from the other standard bodies (e.g. the multi-part BS 1016 from BSI (2010) contains another selection of standards relating to coal analysis). During the study of peats and coals, a number of different methods of classifying them have been developed. One commonly used method divides peats and coals up by into five broad types: . . . . .

‘peat’, material at an early stage in coal formation; ‘lignite’ (or ‘brown coal’), with a high moisture content; ‘sub-bituminous coal’; ‘bituminous coal’, a dense, usually black coal, frequently with a banded structure; ‘anthracite’, a glossy, hard, black coal with a high carbon content and low in volatile matter.

Figure 1.2 provides an illustration of this, together with the relative abundances of these types of coals and their common usages. In addition, Fig. 1.2 illustrates that there are clear trends in composition in passing along this series of fuels; the moisture content decreases, but the carbon and energy contents both increase. Table 1.4 gives a more detailed breakdown of this approach to coal classification and illustrates some of the differences between the standards used in different countries. In this case the trend from peat towards anthracite is characterised by the progressively lower water and volatile matter and higher energy contents. An alternative coal classification system is shown in Table 1.5. This coal ranking system defines a coal class based on the volatile matter content of a coal and its dilation on heating. Other methods can use coal petrology to determine the vitrinite reflection and so assist in the ranking of coals (Table 1.4).


12


Table 1.3

Examples of coal analysis standards

Designation

Title

D388-05 D1412-07

Standard Classification of Coals by Rank Standard Test Method for Equilibrium Moisture of Coal at 96 to 97 Percent Relative Humidity and 30 8C Standard Test Method for Determination as Carbon Dioxide of Carbonate Carbon in Coal Standard Test Method for Fusibility of Coal and Coke Ash Standard Test Method for Forms of Sulfur in Coal

D1756-02(2007) D1857-04 D2492-02(2007) D2961-02(2007)

Standard Test Method for Single-Stage Total Moisture Less than 15 % in Coal Reduced to 2.36-mm (No. 8 Sieve) Topsize

D3172-07a

Standard Practice for Proximate Analysis of Coal and Coke

D3173-03(2008)

Standard Test Method for Moisture in the Analysis Sample of Coal and Coke

D3174-04

Standard Test Method for Ash in the Analysis Sample of Coal and Coke from Coal

D3175-07

Standard Test Method for Volatile Matter in the Analysis Sample of Coal and Coke

D3176-09

Standard Practice for Ultimate Analysis of Coal and Coke

D3177-02(2007)

Standard Test Methods for Total Sulfur in the Analysis Sample of Coal and Coke

D3180-07

Standard Practice for Calculating Coal and Coke Analyses from As-Determined to Different Bases

D3302/D3302M-09 Standard Test Method for Total Moisture in Coal D4208-02(2007)

Standard Test Method for Total Chlorine in Coal by the Oxygen Bomb Combustion/Ion Selective Electrode Method

D4239-08

Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High-Temperature Tube Furnace Combustion Methods

D5142-09

Standard Test Methods for Proximate Analysis of the Analysis Sample of Coal and Coke by Instrumental Procedures

D5373-08

Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal

D5865-07a

Standard Test Method for Gross Calorific Value of Coal and Coke

D7582-09

Standard Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis

D3682-01(2006)

Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes

D3683–04

Standard Test Method for Trace Elements in Coal and Coke Ash by Atomic Absorption



13

Table 1.3 (cont.)

Designation

Title

D3684-01(2006)

Standard Test Method for Total Mercury in Coal by the Oxygen Bomb Combustion/Atomic Absorption Method

D3761-96(2002)

Standard Test Method for Total Fluorine in Coal by the Oxygen Bomb Combustion/Ion Selective Electrode Method

D4326–04

Standard Test Method for Major and Minor Elements in Coal and Coke Ash by X-Ray Fluorescence

D4606-03(2007)

Standard Test Method for Determination of Arsenic and Selenium in Coal by the Hydride Generation/Atomic Absorption Method

D5016-08e1

Standard Test Method for Total Sulfur in Coal and Coke Combustion Residues Using a High-Temperature Tube Furnace Combustion Method with Infrared Absorption

D5987-96(2007)

Standard Test Method for Total Fluorine in Coal and Coke by Pyrohydrolytic Extraction and Ion Selective Electrode or Ion Chromatograph Methods

D6316-09b

Standard Test Method for Determination of Total, Combustible and Carbonate Carbon in Solid Residues from Coal and Coke

D6349–09

Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma – Atomic Emission Spectrometry

D6357-04

Test Methods for Determination of Trace Elements in Coal, Coke, and Combustion Residues from Coal Utilization Processes by Inductively Coupled Plasma Atomic Emission, Inductively Coupled Plasma Mass, and Graphite Furnace Atomic Absorption Spectrometry

D6414-01(2006)

Standard Test Methods for Total Mercury in Coal and Coal Combustion Residues by Acid Extraction or Wet Oxidation/ Cold Vapor Atomic Absorption

D6721-01(2006)

Standard Test Method for Determination of Chlorine in Coal by Oxidative Hydrolysis Microcoulometry

D6722-01(2006)

Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by Direct Combustion Analysis

D7348-08

Standard Test Methods for Loss on Ignition (LOI) of Solid Combustion Residues

Source: compiled from ASTM (2010).


1.2

Relationship between coal types and coal carbon and moisture contents (adapted from World Coal, 2010).

14 Power plant life management and performance improvement



15

Table 1.4 Coal classification UN-ECE

Peat Ortho-lignite

Coal types and peat USA Germany (DIN) (ASTM) Peat

Total water content (%)

Torf

Energy content Volatiles Vitrinite af * maf ** reflection in oil (%) (MJ/kg)

75

6.7

35

16.5

0.3

25

19

0.45

10

25

Weichbraunkohle

Lignite

Meta-lignite

Mattbraunkohle

SubSub-bituminous bituminous Glanzbraunkohle coal coal

45

0.65

40

0.75

35

1.0

28

1.2

19

1.6

14

1.9

10

2.2

Bituminous coal

High volatile Gasflammkohle bituminous coal Gaskohle Med. vol. bitum. coal Fettkohle

Steinkohle Hartkohle

Flammkohle

36

Low volatile bitum. coal Esskohle

Anthracite

Semianthracite

Magerkohle

Anthracite

Anthrazit

3

36

*

Ash-free. Moisture and ash-free. Source: adapted from Euracoal (2010). **

From the point of view of using coals in power generating systems, the properties of the coals progressively change through the classification systems, with the anthracite coals having the highest calorific values and the lowest H/C ratios, in contrast to the lignites having the lowest calorific values and the highest H/C ratios. One way of showing this progression in terms of fuel composition is using a van Krevelen diagram in which the H/C ratios of fuels are plotted as a function of their O/C ratios (van Krevelen, 1950). Figure 1.3 includes the various coal types in such a diagram and also shows the position of biomass and peats (the data points on this diagram represent coals and biomass used in power generating systems). This type of diagram is useful in showing some of the trends in bulk composition from biomass through peat and the different coal types through to anthracite. More detailed coal compositions are produced using the analytical methods outlined in section 1.2.1 above. Examples of coal analyses are given in Table 1.6 to indicate typical values for three power station coals sourced


16


Table 1.5 Class

Coal rank

Volatile matter* General description (weight %)

101 102 201 202 203 204 206

< 6.1 3.1–9.0 9.1–13.5 13.6–15.0 15.1–17.0 17.1–19.5 19.1–19.5

301 305 306 401 402 501 502 601 602 701 702 801 802 901 902

19.6–32.0 19.6–32.0 19.6–32.0 32.1–36.0 > 36.0 32.1–36.0 > 36.0 32.1–36.0 > 36.0 32.1 > 36.0 32.1–36.0 > 36.0 32.1–36.0 > 36.0

Anthracites Dry steam coals Coking steam coals Heat altered low volatile steam coals Prime cooking coals

Low volatile steam coals

Medium volatile coals

Mainly heat altered coals Very strongly coking coals Strongly coking coals Medium coking coals High volatile coals Weakly coking coals Very weakly coking coals Non-coking coals

*

Volatile matter–dry mineral matter free basis. In coal, those products, exclusive of moisture, are given off as gas and vapour determined analytically.

1.3 Relationship between H/C and O/C ratios for coals and biomass.


Solid fuel composition and power plant fuel flexibility Table 1.6

Typical coal analyses

Parameter

Unit

Moisture

wt% ar

UK (Thorseby) 4.8

South American (El Cerrejon) 7.0

South African (Koornfontein) 3.8

Ash

wt% dry

11.8

9.0

13.9

CV (gross)

MJ/kg daf

34.1

33.1

34.1

32.9

31.8

32.9

wt% daf

84.3

79.9

84.5

CV (net) C

17

H

4.6

5.3

5.2

O

7.9

12.21

8.8

N

1.8

1.7

2.1

S

2.13

0.73

0.6

Cl

0.67

0.03

0.1

Ash analysis (% on ash) SiO2

54.4

58.72

43.7

Al2O3

24.5

21.30

34.0

Fe2O3

10.7

7.19

3.0 7.2

CaO

2.36

2.20

MgO

1.62

2.81

2.2

K2O

3.13

2.24

10 ppm; more comprehensive lists are available elsewhere (e.g. Clarke and Sloss, 1992). In practice these trace elements can behave in a wide range of different ways during combustion processes (and differently during gasification and pyrolysis), with the result that they can be distributed (or partitioned) between bottom ash, fly ash, various deposits and the gas phase. For simplicity, this behaviour of elements can be grouped so that they are classed as having different volatilities during combustion and in combusted fuel gas streams (Fig. 1.5). Hg species are notable for being particularly volatile and are of concern in terms of atmospheric emissions, even though Hg is generally present at levels of 10 ppm Coal

Element Arsenic Barium Boron Bromine Cerium Chromium Copper Fluorine Lanthanum Lead Lithium Manganese Neodymium Nickel Phosphorous Rubidium Strontium Titanium Vanadium Yttrium Zinc Zirconium

Typical (ppm)

Range (ppm)

10 200 50 20 20 20 15 150 10 40 20 70 10 20 150 15 200 600 40 15 50 50

0.5–80 20–1000 5–400 0.5–90 2–70 0.5–60 0.5–50 20–500 1–40 2–80 1–80 5–300 3–30 0.5–50 10–3000 2–50 15–500 10–2000 2–100 2–50 5–300 5–200

Note. Emissions from some other race elements are also of concern, but their occurrence is typically at levels of 600 8C, new materials) and/or with major process changes (e.g. co-combustion). Design and/or process modifications have to be thoroughly tested in these boilers and running conditions consolidated. Operational experience can later point out other problems that may arise in individual power units during normal operation and that may require and justify the implementation of targeted temperature/heat flow monitoring within the boiler at any time. Infrared methods for temperature monitoring Thermal imaging cameras, working in the infrared (IR) range and specifically adapted to the harsh (because of temperature and environment) and complex (because of the need to exclude or separate — among others – the influence of the hot combustion gases on the thermal image) operating conditions of a running boiler, provide a quick, efficient and reliable means of detecting thermal anomalies in different areas of a boiler. Uneven thermal exchange due, for example to sootblower malfunction, hot spots, fluid flow blockages or overheated areas can be promptly identified and then monitored to check the effectiveness of corrective action (Lyon, 2000). Being a non-local (wide-area), remote monitoring method, thermal imaging is effectively used to compare temperature distributions in different areas or temperature differences within a given area. Use of permanently inserted thermocouples to monitor temperature and heat exchange in waterwall tubes If attention focuses on quantitative, long-term temperature and temperature profile measurement across the tube wall, several solutions based either on externally fixed thermocouples (TCs) or on TCs embedded in the tube wall are also commercially available. A proven embodiment of solutions based on embedded TCs is described in the following. Two grooves are spark-eroded inside a radial section of a waterwall tube portion; each groove hosts one TC (Fig. 2.6). The tip of each


52


2.6 Monitoring temperature profile inside a boiler tube wall: (a) schematic diagram for the positioning of the thermocouples inside the tube wall; (b) section of a boiler tube showing the actual position of the thermocouples (courtesy of CESI).

TC lies at a known depth inside the tube wall. Both TCs lie in the same radial plane, their tips aligned along the same radius, normal to the fireside surface; embedded TCs are not exposed to the aggressive hot gas environment, thereby ensuring long-term survival and performance. The grooves are machined starting from the fire-shielded fin area, so that the TCs can be safely routed to data conditioning and acquisition modules outside the boiler and can be easily replaced, if required. A third TC in the unexposed portion of the tube wall measures the temperature of the process



53

2.6 (continued)

fluid. In this way a fairly accurate temperature profile across the wall thickness, where the heat flow is maximum, is reconstructed and made available online. In particular the average wall temperature and the temperature at the outer fireside surface of the tube can be obtained, together with a qualitative appreciation of heat flow across the tube. In the actual implementation a tube section (~ 70 cm) was cut out of spare tubes, processed as above, equipped with TCs and extension cables and inserted by welding in a waterwall panel in place of an equivalent length of tube. Laboratory tests showed that the mechanical strength of the tube inserts was not impaired. Typically, from 10 to 20 instrumented tube inserts are installed in critical areas of the boiler to provide an overall picture of the ongoing heat transfer process: this is a necessary compromise between cost and coverage and usually proves to be adequate for diagnostic purposes, if the positioning of the tube inserts is judiciously selected according to engineering analysis and previous operating experience. Manufacturing and installation of these instrumented inserts is relatively expensive, if compared to externally applied thermocouples. On the other hand, this solution provides the temperature profile across the tube wall and has a useful operating life similar to that of the average tube life. Several boilers in different power units have been equipped with these instrumented inserts in the last three decades.


54


Use of permanently inserted thermocouples to monitor temperature and heat exchange in SH and RH tubes Similar considerations hold true for SH and RH tubes. The average wall temperature of the hottest tube sections is in most cases the life-determining factor of SH and RH tubes: they mainly undergo high-temperature creep damage and overheating. Continuous monitoring of the temperature of SH and RH tube walls enables direct and accurate evaluation of creep life consumption and a true condition-based life management of these equipments. Unpredicted severe damage to SH and RH coils is more likely to require more lengthy shutdowns for replacement and considerably more cost penalties than incurred from damage to waterwall tubes. Due to the position and configuration of SH and RH coils, thermal imaging is not an easy exercise. Since surface-mounted TCs are generally short-lived and work as short-term solutions, embedded TCs can be used. In this case the average wall temperature at different radial sections along the tube length is of interest. As only one TC per radial section is required, two to four TCs are embedded in a longitudinal groove (typically 1 mm deep), machined on the outer surface of a straight portion of an SH or RH tube. The groove containing the TCs is sealed by welding a longitudinal metal strip to the underlying tube. TCs are thus completely shielded from contact with hot flue gases. Each TC measures the temperature at a different length along the tube, so that an accurate, reliable, long-term temperature profile of the tube is provided. This technology is applicable only to the terminal (inlet or outlet) portion of an SH or RH coil. At their exit from the upper end of the tube the TC cables are routed through the penthouse to the conditioning and data acquisition unit. One instrumented tube for each SH or RH coil is usually sufficient to obtain the required information, taking due consideration of the relative complexity of installation and relevant cost of each instrumented tube. Advanced fibre optic methods for temperature monitoring inside the boiler Thermocouples have well-known limitations in maximum measurable temperature, response, accuracy, stability and service life in harsh environments. If only surface temperature measurements are required, optical fibre thermometers (OFTs) (Yu and Chow, 2009) can be used instead, with the advantages of long-term stability, high sensitivity and quick response. Moreover, they are unaffected by electromagnetic interference, and can survive harsh environmental conditions. In the family of OFTs, blackbody and fluoroscopic sensors are widely used. Blackbody sensors consist of a high-temperature optical fibre with an opaque cavity



55

attached to the sensing tip. The radiation flux spectrum detected at the end of the fibre is related to the temperature of the cavity via Planck’s law, which permits the temperature to be obtained from the measured spectral intensity or intensity distribution. This technique is particularly suitable at high temperatures (500–1900 8C), while at low temperatures fluorescent OFTs have better capabilities. Both types of OFT have high accuracy ( 50 μm). Frequency analysis of raw or envelope charge signal. It can provide hints on the possible origin of the particulate (e.g. moving or static machine components).

The system can be made rugged enough to operate indefinitely in a heavyduty gas turbine environment. It is important to note that not all processes causing a particulate increase are necessarily correlated to ongoing damage (a typical example is periodic compressor washing). Data processing and evaluation software must be tailored automatically to recognize and filter situations belonging to normal operation (e.g. compressor washing), which give rise to abnormal charge signal behaviour without diagnostic significance, so as to avoid unacceptable false alarms. A preliminary automatic screening and reduction of the large flux of incoming data is also highly desirable. The method is attractive because it is simple, robust and cheap. It was first considered in the 1970s for application to aeronautical engines and turbines, mainly out of safety concerns. Only later, in the 1990s, was the effort also directed to the development of the potential of using the method as a ‘condition monitoring’ method for power generation gas turbines (Lapini et al., 2001; Lapini and Zippo, 2003), specifically for giving early warning of those damages that cannot be detected with a satisfactory lead time through conventional methods of machine performance monitoring. Recently this method was also presented at the ASME Turbo EXPO Conference by the SWRI (Wilcox et al., 2010).



79

2.14 EDMS sensor and cable (courtesy of CESI).

An example of results obtained on a 40 MW aero-derivative gas turbine during a monitoring campaign that lasted over 2 years (Lapini and Zippo, 2003) is shown in Figs 2.14 to 2.16. A single charge sensor (Fig. 2.14) was mounted on the exhaust diffuser (Fig. 2.15), in the upper part of the duct, free of obstacles inside. The electrostatic charge, as well as rotation speed and load level, were monitored for over 5 months, to identify an average baseline activity level (see Fig. 2.16). At a certain time (November 12th in the diagram) a sharp increase is observed and continues for a while, with observed peak amplitudes 3 times the baseline. An endoscopic inspection carried out as a follow-up of the charge monitoring data showed a loss of coating on about 20 % of the first-stage turbine blades. The turbine was judged to be fit for further service and operated for an additional 4 months, until it was shut down for refurbishment. This was done while the charge monitoring system provided further damage indications (right-hand end of the diagram). No other monitoring system installed on the machine was able to detect any structural or functional anomaly during such an operating period. The counterpart for the simplicity, ruggedness and low cost of the method is a lack of selectivity and precision in the diagnostic indication and, consequently, the risk of false alarms. Many causes can contribute to an increase of the electrostatic charge level, not all of them diagnostically


80


2.15 EDMS sensor installed in the exhaust duct of a gas turbine (courtesy of CESI).

2.16 Example of EDMS results over a monitoring period of six months (courtesy of CESI) .



81

significant; moreover, it is not easy to discriminate between the different potential causes of deviation from normal charge signal behaviour. This method should be used as a first alarm of potential onset of structural damage and a good reason to start, as soon as possible, more precise and targeted investigations. Preliminary collection and analysis of data on a significant number and variety of gas turbines for an equally significant time duration is the best way to consolidate its diagnostic potential and reliability.

2.4.3 Gas temperature and integrity of hot parts The temperature of hot gas at the turbine inlet (TIT) is a crucial parameter for the energy efficiency and the operation life of gas turbines. At present temperature and pressure of the gases in the hot section of the turbine are estimated by calculations and indirect measurements (typically exhaust gas temperature, measured by groups of two thermocouples for each burner). Such temperature values are introduced into analytical models of the turbine CMS, which indirectly estimates the TIT and the temperature of hot parts. Such an indirect approach has an intrinsic uncertainty of about 10– 15 8C. As a consequence the turbine has to be operated below its optimum efficiency, by about 1 %. Both in design validation and during normal operation a direct measurement of the temperature of gases entering the turbine would be very desirable, for the reasons stated above. Moreover, a direct, accurate measurement of the temperature of hot parts would be very useful in optimizing maintenance intervals, as a variation of ±10 8C in component temperature can induce a +30 %/–20 % variation in the lifetime due to oxidation and a +100 %/–50 % variation in creep life prediction. Currently available instrumentation cannot survive for very long in the turbine hot gas path due to the hostile environment – very high temperatures and pressures, high dynamical stresses, corrosive atmosphere – presenting unique challenges. An interesting summary of the technology gap in this area was worked out at the European level by evi-gti.com in 2006 (Lab Gap Matrix is available from www.evi-gti.com). A similar analysis was performed in the United States by the Propulsion Instrumentation Working Group (PIWG, www.piwg.org), which issued specifications for the missing instrumentation capabilities required ‘to fill the gaps’. Recent summaries of the state-of-the art in sensor needs and measurement requirements in the hot gas path of gas turbines can be found in Roberts (2004) and Niska (2009). The recently completed European project HEATTOP should also be mentioned among the efforts in this field. The project was finalized to reduce hot gas path measurement uncertainties, by developing new sensors and technologies for GT monitoring and by validating their use in test facilities


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reproducing the conditions of actual turbines (Mersinligil et al., 2010; see the website: http://ec.europa.eu/research/transport/news/article_8780_en. html). Optical techniques are the most promising to measure very high temperatures, being non-intrusive (Yu and Chow, 2009). On-line infrared (IR) pyrometry, aimed at a direct on-line measurement of the temperature of hot blades, is the most mature optical technique available nowadays. IR pyrometry is a line-of-sight non-contact optical technique, which requires a suitable fixture to enter the GT at a position that enables a direct view on the rotating blades. The mounting system (Fig. 2.17) provides the right view through a pressure-proof sight glass assembly; the viewing window can remain clean due to a purging air flow derived from the air compressor discharge. The optical signal collected by the pyrometer is transmitted through a rugged, flexible, fibre optic light guide to a remote electronic signal conditioner. If temperature is continuously recorded, a sequence of peaks is observed; each peak corresponds to an individual rotating blade passing in front of the pyrometer. This method can detect significant bladeto-blade temperature differences, possibly due to manufacturing variations or to obstructions of cooling passages. An overheated blade would show an associated peak amplitude higher than the measured mean amplitude (Fig. 2.18). A defective cooling would expose, for example, the first-stage blades to temperatures beyond 1500 8C, above their material limit, so that in many instances on-line pyrometry can be useful to check cooling efficiency and, consequently, to assure coating and blade integrity. The first trials with on-line pyrometry started in the 1970s (Mossey patent 1972) supported by the manufacturers’ interest. Several plant applications have been implemented since the 1980s (e.g. Beynon, 1981). The efforts for

2.17 Schematic of pyrometer installation into the GT (adapted from Amory and Hovan, 2000, LAND web site).



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2.18 Example of pyrometers installed in a GT (right) and results indicating an overheated blade (left).

the application of pyrometry on operating gas turbines were continued by R&D centres in the 1990s (e.g. EPRI in USA, Kema and CESI in Europe), in support of utilities confronted by new generations of GTs coming to the market. Examples of applications of pyrometry at the development level can be found in a recent GT handbook (Soares, 2007). When blades coated with zirconia–ittria ceramics were introduced, pyrometers using IR wavelengths of around 10 μm were also tested (Markham et al., 2002), due to the optical properties of this ceramic material. However, the near-IR wavelengths (around 1 μm) have noticeable advantages from a technological point of view for the following reasons: . . .

Glass is not transparent at 10 μm, so more expensive and complex optical windows and lenses would be required for this wavelength. At the shorter wavelength the combustion gases are transparent; they do not disturb the measurement and a higher sensitivity can be reached. A thin oxide layer grows on the surface of the hot parts during operation, which results in an emissivity very similar to that of the hot parts with metallic coatings used before the application of TBCs.

Today IR pyrometry is rather well known and applicable to the most important and common gas turbines (see the web sites of LAND and ROTAMAP). For many gas turbines the mounting system is designed and can be installed by the manufacturer. IR pyrometry can contribute to significant cost savings, by helping to prevent equipment damage and unscheduled shutdowns due to failure of overheated blades and by optimizing operating conditions. Furthermore, it could usefully contribute to the optimization of maintenance schedules and to the development of new GTs.


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2.5

In situ assessment of gas turbine hot parts by nondestructive techniques

Gas turbine users usually follow the maintenance schedule suggested by the OEM, which is based on very conservative criteria to increase plant reliability. During periodic inspections a visual check of the surface of hot gas path components can be done by microendoscopic examination, without opening the turbine case, to verify the integrity of the components and ceramic coatings. A small video camera connected to optical fibres allows a visual check to be made of critical positions on hot parts (mainly rotating blades) and to find possible TBC adhesion failures or local damage due to foreign objects (FOD). Very small cameras are nowadays on the market, with a very high number of pixels (30 000) and very high resolution. If the TBC is absent in very large areas a severe overheating of the substrate during further operation could occur and cause component failure. This in situ damage assessment enables sensible decisions to be taken about the possibility to refurbish damaged components and to avoid their premature replacement. Even if visual inspection gives a positive response, coating degradation can nevertheless proceed slowly according to several degradation mechanisms: deterioration of the protective capability of the bond coat (BC) due to interdiffusion with the base alloy; incipient defects and detachments; microcracking of the thermally grown oxide (TGO) and TBC, sintering of the TBC layer with consequent thermal conductivity and stiffness increase; growth of TGO at the metal/ceramic interface, with the development of high compressive stresses at the bottom of the TBC (Fig. 2.19). In practice, the coatings of hot parts of individual gas turbines that have undergone the same operation period could nevertheless have different life fractions, depending on the particular operation history experienced. Life prediction modelling of metallic coatings is nowadays well developed, but the actual reduction of coating durability due to fuel changes and/or higher degradation due to cycling cannot yet be reliably predicted. Moreover, coating assessment (both in the as-delivered and serviced condition) is even more critical for ceramic thermal barriers (TBC), as their premature failure can dramatically reduce component life. For these reasons a noticeable effort has been made to develop nondestructive techniques that make it possible to evaluate both the initial coating quality (coating thickness) and (possibly in situ) the residual protective capability of the coating after a known operation period (Ellingson et al., 2005; Osgerby et al., 2006). Some innovative inspection and NDT methods to assess hot part coating damage are presented in the following. These methods can be used to support cost-effective decisions about refurbishment needs, avoiding, on the



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2.19 Example of TBC coating as-delivered (left) and aged in cyclic oxidation at 970 8C (right).

one hand, the heavy cost penalties of irreversible damage of base material and, on the other hand, an equally penalizing premature scrapping of very expensive components.

2.5.1 Thermography to check blade cooling and coating adhesion As already mentioned for boiler waterwalls, thermographic techniques can be used to map temperature distributions in complex components; a classic example is the check of cooling channels in a gas turbine blade (Fig. 2.20). Thermography can also be used to detect coating delaminations. The area to be inspected is heated through either conduction or radiation; the surface temperature is monitored using a suitable imaging system, such as a scanning infrared camera with mK resolution. Delaminated areas appear as cold or hot spots, respectively. The technique is unable to detect cracks that are normal to the surface (Grice et al., 1983; Bento and Almond, 1995), but can used to determine some characteristics of the coating, like thermal properties. Pulsed thermography (Fig. 2.20), in particular, is effective – and is currently used – in detecting delaminated areas of metallic and ceramic coatings deposited using the most common deposition techniques. One or two flash lamps heat the component surface and an infrared camera records a time sequence of colour digital images during the cooling phase; at each


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2.20 Examples of a pulsed thermography configuration and (b) a thermal image of a blade with evidence of cooling channels (adapted from Ellingson et al., 2005).

time a cooling curve can be obtained from the image processing system. The cooling process is slower where a coating delamination is present, because the air layer between the coating and substrate interrupts the heat flow into the base material. The resolution of pulsed thermography (PT) depends mainly on the characteristics of the IR camera, on the thermal properties of materials, on coating thickness and on defect geometry (e.g. size and depth). Specimens with artificial defects of different sizes (several millimetres) are used for calibration purposes. Typical physical limitations of thermography, such as the influence of the emissivity of the inspected coating surface, can be overcome. If the emissivity of the coating surface is too low, as in the case of ceramic thermal barriers, a thin reversible graphite layer is first sprayed on to the surface. PT can be used as a quality control technique on new components, to detect coating delaminations and to find out local differences in coating thickness. Moreover, the reliability of PT was increased by the introduction of an algorithm based on the apparent effusivity (Marinetti et al., 2007), which permits discrimination between delaminations and variations in coating thickness. Being a fast, non-contact, single-side technique, PT allows the inspection of wide coated surfaces at a time. The PT equipment is transportable and applicable in situ (Rinaldi et al., 2008) if the components can be reached by the flash lamp radiation. Where a heat pulse cannot be artificially induced, natural thermal transients can be exploited by recording a sequence of images by an IR camera; differences in cooling times can indicate local anomalies. An on-line application of IR transient thermography was developed to monitor local overheating of rotating blades due to TBC delamination or blockage of cooling holes (Zombo, 1997; Zombo and Shannon, 2006).



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Transient infrared methods are now so mature that an OEM has developed a quality control system to evaluate turbine airfoil cooling holes during blade manufacturing (Allen et al., 2010). The blades are mounted on a fixture where fast internal heating with hot air is obtained in a few seconds; during the following cooling phase an infrared camera guided by a robotized system takes IR pictures at fixed positions. The images recorded on each blade during cooling are compared with reference images of a sound blade, taken at the same positions. From this comparison hole manufacturing defects can be quickly and automatically detected in a much more reliable way than with the previously used manual methods.

2.5.2 Advanced eddy current method to evaluate coating thickness and depletion In many cases the actual thickness of the metallic coatings applied to hot parts for protection against oxidation, corrosion and high temperatures cannot be reliably controlled after deposition with traditional NDTs, for one or more of the following reasons: very low overall thickness (some hundreds of micrometres), multilayer structure, small difference in conductivity between some of the layers. Indirect methods are normally used during thermal spraying of big parts, but a direct method is desirable. Moreover, the protective power of MCrAlY bond coats is due to the presence of the aluminum-rich β phase; its dissolution is a thermally activated, diffusion controlled phenomenon, which can today be reliably modelled. During operation two β-phase depleted regions form on the two sides of the coating, near the base material and at the upper surface. Knowing the thickness of such depleted layers, the residual life of the bond coat can be estimated using diffusion and oxidation laws together with inverse problem solution techniques (Krubovsky et al., 2001; Rinaldi and Mandelli, 2009). Consequently, a non-destructive method that enables accurate measurements of both the thickness of the as-delivered parts and the residual effective coating thickness after an operation period is highly desirable, in order to check the integrity and to evaluate the residual operation life of the coatings. The frequency scanning eddy current method (F-SECT) (Antonelli et al., 1997, 1998, 2001; Rinaldi and Antonelli, 2005) is able to detect not only the thickness of the BC and TBC but also the ß-phase depletion of the BC. The method is based on the same physical principle as the well-known eddy current NDT method, but the eddy current probe is excited with a variable frequency (typically from 50–100 kHz to 1–10 MHz) to gradually scan higher to lower depths and to detect the layers with different electrical properties. The spatial resolution is determined substantially by the probe


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diameter (about 8–10 mm). The material response (electrical impedance versus frequency) is recorded; the qualitative trend of the curve is already an indication of coating degradation with respect to a new coating (Fig. 2.21). If the results are analysed with suitable multilayer models, quantitative data can be obtained, such as the thickness of a MCrAlY coating on an Ni-based alloy of a hot part. The measurement of the metallic coating thickness is possible notwithstanding the small conductivity difference between the base metal and the MCrAlY coating. The F-SECT method is also applicable in the presence of yttria-stabilized zirconia (YSZ) TBC coatings, because the external ceramic layer is transparent to the probing electromagnetic field; if the probe is in good contact with the TBC surface, the TBC thickness can be estimated by exploiting the lift-off signal. Taking account of some error sources (small variations in the base metal conductivity, surface roughness, geometry effects due to the curvature of the blade surface), the technique can be used during the manufacturing of gas turbine blades and vanes for coating thickness control. An accuracy of 15 % or 30 % was demonstrated in the measurement of the thickness of as-sprayed and smoothened

2.21 Electrical impedance vs frequency plots obtained on a new blade (left) and a blade after service exposure in the plant (right). Anomalous curves on the right correspond to coating areas with service-induced damage (ß-phase depleted areas). The micrograph is taken on the section of the worst situation detected (opposite curvature): A = TBC; B = effective bond coat (BC); C = depleted BC; D = anomalous precipitation at base material interface.



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MCrAlYs, directly or through a thick ceramic thermal barrier coating, respectively (Jungbluth et al., 2008). The qualitative shape of the impedance versus frequency (from 50 kHz to 1 MHz) plots taken at different positions after service exposure in the plant already gives evidence of the degradation level of the coated material Fig. 2.21). The MCrAlY coatings change their electromagnetic properties according to the temperature history and operation time; F-SECT is able to detect the level of metallic coating degradation, in particular the β-phase depletion of the bond coat for γ/β coatings. A quantitative parameter of the degradation level is determined on basis of a multiple (n)–layer model with a task-dependent allocation of unknowns (e.g. the thickness of different layers). A good correspondence is generally found between the degradation levels measured by this NDT and by metallography after sectioning, as shown in the example of a failed component analysed in Rinaldi et al. (2006). The dependency of the impedance (Z) on temperature (T) and the effective coating thickness varies with the chemical composition both in γ/βand in γ/γ´-type coatings (in the latter case differences in volume fraction of the precipitated Cr-rich phases are important). If the Z–T relationships have been previously determined experimentally for each class of metallic coating, e.g. on coated specimens aged in a furnace at known temperatures for increasing times, the F-SECT technique can be used to determine the temperature of the measured area. As a consequence, using this technique and an automated robotic system it is possible to establish accurate and high-resolution maps of the surface temperature distribution over the entire airfoil and platform areas (Schnell et al., 2007). The exact location of hot spots on the airfoil can easily be identified. The F-SECT technique can also be successfully applied in situ after service exposure in the plant of the blades still mounted during maintenance stops in industrial GTs (Rinaldi and Antonelli, 2005, or Rinaldi et al., 2006). The sensor developed for on-site use and an example of results obtained in field applications are shown respectively in Figs 2.22 and 2.23. Finally, in bare regions of ex-service components (coating eroded or delaminated) the technique can determine the depth of a base material layer affected by nitridation, the precipitation of acicular nitrides severely embrittling the alloy (Jungbluth et al., 2008).


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2.22 Example of in situ frequency-scanned eddy current (F-SECT) measurement (adapted from Rinaldi and Antonelli, 2005).

2.23 Results of frequency-scanned eddy current measurements (FSECT) on a blade section after service exposure in the plant.

2.5.3 Photoluminescence piezospectroscopy to detect electron beam physical vapour deposition TBC degradation This technique was invented by Clarke (Tolpigo and Clarke, 2000), and is based on: .

the transparency to the visible light of the zirconia–yttria with columnar



.

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morphology made by electron beam physical vapour deposition (EBPVD) and the fluorescence in the red of the Cr3+ ions present inside the TGO alumina layer. If excited by a green laser light, the outer electrons of the Cr3+ ions can rise to a higher energy level. Falling again to a lower energy level they produce a red fluorescence radiation (photoluminescence). Initially the technique was studied through a typical Raman spectroscopy instrument combined with an optical microscope, as shown in Fig. 2.24.

It is well known that the position and the shape of fluorescence peaks depend on the crystalline structure of the material and on its elastic strain level (and corresponding stress). A spectroscopic analysis of the fluorescence spectrum of TGO highlights the presence of different alumina phases (α, θ, γ), as shown in the example of Fig. 2.25, which concerns a vertically cracked air plasma sprayed YSZ. Here the doublet relative to the α phase (R1 and R2) and the doublet relative to the θ phase (T1 and T2) are clearly visible, together with the broad peak of γ alumina. As a consequence, this technique can be helpful in quality control of columnar TBC coatings, since the presence of the undesired θ phase gives evidence of improper heat treatments during manufacturing. Since the frequency shift Δν of the main peaks (R1 and R2), compared to the corresponding peaks of a stress-free alumina (see Fig. 2.26 top left), is proportional to the residual stress level of the alumina layer, the technique is called photoluminescence piezospectroscopy (PLPS). The following formula permits quantitative TGO stress evaluations to be obtained: σ

TGO

= – Πij Δν

where the tensor Πij was determined once by laboratory measurements on an alumina sheet at increasing levels of controlled bending strain (and corresponding stress). Since the TGO peaks shifted towards lower energy levels, the corresponding residual stress σTGO is compressive (note the minus sign in the formula). At the beginning of the TBC life, the TGO is growing while remaining flat and in-plane, and the order of magnitude of σTGO is usually about 2–4 GPa. High temperatures and thermal cycling during operation cause local irregularities to appear at the TGO/BC or TGO/TBC interfaces. As a consequence, the TGO residual stress is relieved and the PLPS doublet shifts toward a stress-free condition, as shown in the sequence of Fig. 2.26. Several parameters have been proposed to evaluate the evolution of the PLPS spectra during TGO degradation (Selçuk and Atkinson, 2002), but the R2 peak position seems to be the most stable (minimum dependence on temperature) and significant parameter. In order to determine it reliably, a


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2.24 (a) Schematic of the PLPS technique: excitation by means of an incident green laser (e.g. 514 nm) and detection of TGO (thermally grown oxide) photoluminescence (693 nm) through the EB-PVD thermal barrier coating (TBC). (b) Columnar structure of a typical EB-PVD TBC.

deconvolution process of the doublet R1 and R2 has to be performed by using the sum of a Gaussian and a Lorentzian function. If the bond coat is sufficiently rigid, no significant rumpling occurs and the compressive stress is progressively released, so that the spectra do not contain several different doublets to be deconvoluted with complex routines. This can happen with



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2.25 PLPS spectra of the TGO with evidence of different alumina phases (α, θ, γ). The spectrum with the γ-phase peak was detected through the segmented APS TBC (see the bottom micrograph) after reducing the TBC thickness to 120 μm (adapted from Antonelli et al., 2006).

the much softer bond coats used in the aeronautic field and may give problems. For calibration purposes, a measurement on an alumina stressfree sample has to be done just before and after a set of measurements is taken. The capability of this technique to follow the degradation of the EB-PVD TBC system has been demonstrated by several authors (Gell et al., 2004, on aeronautic bond coats and Rinaldi et al., 2008). The required condition is that a monotonic behaviour of σTGO is measured on specimens aged in laboratory tests. In several laboratories aged specimens have been measured and a monotonic trend of σTGO with exposure time and number of thermal cycles has been found. A portable system to perform measurements in situ was developed and applied during a maintenance stop (De Maria et al., 2006; see Fig. 2.27). The


2.26 Left: comparision of PLPS spectra (black) of specimens aged in cyclic oxidation tests at 1100 8C with reference spectra of stress-free alumina (grey); Δλ of resonance peaks decreases with increasing damage due to cycling. Centre: corresponding cumulative frequency distributions of σTGO values mapped over the whole surface of the exposed disc coated by EB-PVD TBC (300 μm thick). Right: morphology of TGO at the TBC/BC interface.




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different values of the TGO residual stress highlight local damage differences between well film-cooled areas and hot areas of the rotating blades. The parameter σTGO has been shown to be an indication of TBC life expenditure on blades with NiCoCrAlY–Re bond coats of land-based GTs (Rinaldi et al., 2010). Moreover a fast PLPS mapping of σTGO on hot parts coated with EBPVD TBCs points out the most critical areas of the component; statistical analyses of hundreds of measured σTGO values give reliable indications of σTGO reduction and corresponding interface degradation, enabling an early detection of damage before dangerous delaminations occur (Del Corno et al., 2010). During laboratory ageing of an EB-PVD TBC (Fig. 2.26), mapping of the specimens was performed at increasing numbers of thermal cycles; the cumulative probability distributions of the hundreds of measured σTGO values change significantly (Fig. 2.26; mean value decreases to < 1 GPa and standard deviation increases as the interface damage increases). This shows that this non-contact optical technique is very robust if used with an automatic system. Finally a case can be made for the advantages of an integrated approach, based on the cooperation of the three different NDT techniques (the capabilities are summarized in Table 2.9). These techniques provide complementary diagnostic information and performances: while the capability of IR imaging as a wide-area non-contact technique can be exploited for quick and effective in-shop screening of coating adhesion, FSECT can provide more detailed information on coating layer structure and on coating functional integrity and fitness for service, both in-shop and infield, even during short-term shutdowns, thus becoming a valuable condition assessment tool. PLPS, in turn, can be useful in the shop both during the process of developing and qualifying new coatings and in giving very early warning of the onset of EB-PVD TBC coating structural and functional degradation after an operation campaign. Such an integrated approach is widely explained in Antonelli et al. (2006), where different coating damage aspects are detected both on thermal-cycled samples and on service-exposed components coated with TBCs: BC depletion is detected by means of an F-SECT eddy current system, TGO/ BC interface degradation by the portable PLPS system and delaminations by pulsed thermography. As an example, compare the results shown in Figs 2.23 and 2.27 on the same component section.

2.6

Remote monitoring solutions

Advanced power plant diagnostics requires the availability of experts, an ever more valued resource in times of hard competition in the power sector. One effective solution to this problem is to centralize the diagnostic service,


2.27 Example of PLPS results on a blade section after service exposure in the plant (compare with Fig. 2.23). PLPS can detect the regions of an ex-service blade exposed to the highest temperatures (lowest TGO stress values).




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Table 2.9 Comparison of methods available for in situ non-destructive evaluation of hot part coatings Technique

Detection capabilities Limitations

Pulse . Detachment at thermography TBC/BC or at BC/ substrate Interfaces

F-SECT

PLPS

Applicability in field

Applicable to There must be a components if they discontinuity at an can be reached by interface, typically flash lamps wider than a few mm parallel to the interface Requires preliminary Applicable also on mounted blades, calibration on each with open turbine type of metallic case coating

. MCrAlY or bond coat degradation (quantitative parameters) . TBC thickness . Very early stages Only for EB-PVD of damage at TBC/ TBCs BC interface can be Application to detected on EBvertically cracked PVD TBC (up to APS up to 100 μm 350 μm thick) thick is under . TGO residual study stress level (quantitative)

Portable instrument with optical fibre; applicable on dismounted blades

sharing all the relevant data coming from several plants – or from specific subsystems of these plants – within a common expert centre able to provide the assistance of highly qualified experts to solve the problems of individual plants. The unceasing development of data processing, storage and transmission capabilities makes it relatively easy to share data in real time with a remote centre. Moreover, the relevant parameters describing the current status of a main component can be stored to make possible the reconstruction of its previous operation history. The problem is then to build efficient data processing and screening procedures to extract diagnostically significant information preventing local and remote diagnostic facilities from being submerged by huge amounts of non-significant information. The associated aspect of data security can also be solved efficiently and satisfactorily in response to any well-defined requirement. Different access levels can be provided to data of increasing sensitivity. This approach offers a number of advantages. Personnel of the power production plant can get real-time assistance from top-level experts when required, at drastically reduced costs. The diagnostic centre experts can use their time efficiently, since they mostly avoid time-consuming travel and use their potential at its best, since they have their analysis tools and collected case histories readily to hand. Such centralized acquisition and analysis of diagnostic data is done according to unified criteria. This greatly accelerates


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the growth of diagnostic capabilities within the company, enhancing early malfunction or damage prevention and detection, as well as the possibility of corrective actions. This aspect is of particular relevance for manufacturers (see, for example, Killich, 2006, or www.ge-mcs.com), since they can collect in a relatively short time a large amount of operational experience on the components or machines they supply, and can optimize their service activity to their own benefit as well as to their clients. A variety of such centres has been developed in past years: . .

.

2.7

OEM centres very efficiently assure on-line assistance to their customers, as required in a long-term global assistance contract. Power generation company centres contribute to managing the generation fleet in the most efficient way. They are not limited to diagnostic monitoring, but rather support overall optimization of the power production strategy. Third party service company centres, including specialized university centres.

Future trends

2.7.1 Trends in condition assessment and monitoring policies Strong market competition in a frame of safety and environmental constraints is the main driver for developments in condition assessment and monitoring policies in thermal power plants. Besides assuring the required level of safety inside and outside the plant and compliance with environmental regulations, condition assessment and monitoring activities must be functional to the economic optimization of the entire power unit life cycle and are an integral part thereof. The individual plant itself may undergo different condition assessment and monitoring policies, depending on its specific operation mode within the power generation fleet (base load, intermittent, peak only, backup, etc.). For example, an older combined cycle of comparatively low efficiency, which is deemed to be replaced in a couple of years by a new-generation, high-efficiency counterpart, requires focus on short-term availability and reliability issues. The focus will be quite different for the new plant, although the available condition monitoring tools are essentially the same. Another important point is that utilities increasingly tend to contract the technical task of condition assessment and monitoring, as far as main plant items are concerned (boiler, steam and gas turbine, generator) to the manufacturers in the form of long-term global service contracts. The potentially unpredictable maintenance costs, as well as the related



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unavailability costs, are correctly treated as a risk and transformed into a fixed cost for the utility by means of long-term service contracts, essentially insurance contracts. The risk is thus transferred to the manufacturer, who is in turn stimulated to improve condition assessment and monitoring capabilities, as one way to control risk and to make the service business profitable. As a consequence, the most recent innovations in the field of condition assessment and monitoring for power plants have been introduced or are under development by manufacturers. As far as technical aspects are concerned, besides the above-mentioned thrust towards remote monitoring, the following general trends are observed: . . .

.

.

increasing automation, both in manipulation (ultrasonic probe scanners, etc.) and in data processing, screening and presentation; increasing tendency to present diagnostic results in the form of immediately usable images (ultrasonic, tomographic, etc.); continued interest for non-contact, non-local, wide-area diagnostic tools (a good recent example is the examination of long portions of piping by guided ultrasonic waves to detect corrosion and other types of damage in non-accessible areas); continued interest for improved models of the power unit or main subsystems thereof, to be used in connection with (reliable) monitoring data to enable relatively cheap, quick and precise understanding of the current condition; development of sensors resistant to harsh environments.

Efforts are also ongoing towards the use of neural networks and artificial intelligence (AI) techniques to support decisions about the machine condition (e.g. Adgar et al., 2009).

2.7.2 Some examples of technology innovations Substantial technical innovations in the past decade have widened the range of problems that can be addressed and the range of solutions available for condition monitoring and assessment. The dramatic progress in telecommunications has also had relevant fallouts in the field of industrial diagnostics. A significant example is provided by wireless sensors and local wireless data collection and exchange nets, which have achieved noticeable practical success and industrial penetration in the last decade. Wireless solutions have become available for a variety of monitoring tasks, from vibration monitoring of rotating machinery to environmental sensing. Wireless sensor subsystems can be an integral part of large local and remote monitoring systems for power generation units. The international standard for wireless communication in process automation (IEC 62591Ed. 1.0) was


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approved on 26 March 2010. The availability of wireless sensors and wireless data collection systems allows a substantially lower time, complexity and cost for the installation of monitoring systems and is of special relevance where a condition assessment and monitoring intervention is required at short notice and for a definite time duration (e.g. on a relatively isolated rotating machine). Some examples of efforts to develop new sensors are shortly described in the following. The aim is to obtain sensors and monitoring solutions that withstand harsh environments and are applicable in closed-loop control or can be implemented into an open-loop advisory/diagnostic system. Optical technique to measure gas turbine inlet temperature An innovative optical non-contact system to measure on line the temperature of gases at the gas turbine inlet (turbine inlet temperature, TIT) has been developed and is actually in the testing phase. The technique (Gianinoni et al., 2007) is based on the measurement of the IR emission of hot gases. The IR emission is detected by an optical probe mounted in a through-thickness penetration of the turbine case and positioned in such a way that the line of sight of the probe is perpendicular to the gas flow direction. Within the angle of view of the probe, the system carries out photometric measurements of the IR radiation emitted by the CO2 molecules present in the combustion gases in an appropriate wavelength band. The IR wavelength band is selected to meet the following requirements: it should undergo strong absorption along the test optical path (to avoid contributions from the opposite hot wall) and, at the same time, be transparent enough to allow the emitted radiation to cross a significant portion of the test region. The prototype sensor is mechanically robust and has been tested on a full-scale combustion rig (ENEL – Sesta Testing Facility, Italy). Results have shown that the recorded signal trend is in good agreement with the adiabatic temperature derived from the combustion process parameters. Recently, in the frame of the EU project HEATTOP, a solution based on multiwavelength detection, aimed at obtaining an absolute measurement of the gas temperature, has been investigated Silicon carbide (SiC) high-temperature sensor A novel silicon carbide (SiC) optical ultraviolet (UV) dual-diode flame temperature sensor (FTS) has been developed for an active combustion pattern factor controller (APFC) for gas turbines by General Electric’s



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Global Research Center and GE Energy and applied in harsh environments simulating a real combustion situation (Palmer et al., 2009). Smart components Continuous on-line condition monitoring of life-limiting components in the hot gas path sections of turbines would be highly desirable to optimize maintenance. For some years efforts have been ongoing (Mitchell et al., 2009) to build smart, self-aware engine components that incorporate embedded, harsh-environment-capable sensors and high-temperature-capable wireless telemetry systems. The innovative technology approach involves two aspects. First, sensors are embedded on complex shapes, such as turbine blades, by the MesoScribe’s MesoPlasma™ robotic thermal spray deposition system (Longtin et al., 2004), which can deposit finefeature patterns on flat and conformal surfaces (both thermocouples and strain gauges are under development). Second, wireless telemetry systems are embedded in less hot and harsh regions of the component (e.g. the root of the rotating blade), where temperatures prevent the use of conventional silicon-based devices but high-temperature electronics can be used.

2.8

Sources of further information and advice

A general and systematic description of the basic concepts and techniques of condition monitoring for power plants can be found in Handbook of Condition Monitoring (Rao, 1996, pages 285–324). For more details about boilers, see Boiler Operator’s Guide (Kohan, 1997) and Power Boiler Design, Inspection, and Repair (Malek, 2005) can also be used. An example of a leak monitoring system can be found at www. acousticmonitoring.com. A wide literature exists about vibration monitoring (see, for example, Kelly, 2006, for Advanced Vibration Analysis). For a systematic description of conventional non-destructive testing methods, vol. 17 of ASTM Metals Handbook: NDE and Quality Control is recommended; for a recent update on thermographic techniques, see, for example, chapter 14 of Chen (2007). Regarding the use of Small Inspection Vehicles for Non-destructive Testing Applications, see, for example, Friedrich et al., 2006. A systematic description of the most common techniques used in gas turbine condition monitoring can be found in the recent Gas Turbines: A Handbook of Air, Land, and Sea Applications (Soares, 2007). The applications of pyrometry and thermography are particularly significant. A comprehensive review of the non-destructive techniques developed for hot part coatings and applicable to thermal barrier coatings can be found in


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the dedicated chapter 8 of the book on High Temperature Coatings (Bose, 2007).

Web sites Corrosion monitoring http://www.kema.com/Images/KEMCOP.pdf http://www.lesman.com/unleashd/catalog/analytical/Honeywell-CET5000/ 34-SC-03-02.pdf http://www.lesman.com/unleashd/catalog/analytical/Honeywell-CET5000/ 34-SC-03-01.pdf http://www.osti.gov/bridge/purl.cover.jsp;jsessionid=AC1FD1732C579 B9B2D6326D60C080F49?purl=/895400-wsRNR4/ Boiler temperatures http://www.infra-view.com/whitepaper.htm Gap matrix EVI-GTI, the lab gap matrix, on the WWW, at http://www.evi-gti.com. Excel file PIWG, sensor specifications, on the WWW, at http://www.piwg.org http://gltrs.grc.nasa.gov/reports/2004/TM-2004-213202.pdf Further information on the HEATTOP project http://ec.europa.eu/research/transport/projects/article_6499_en.html http://ec.europa.eu/research/transport/news/article_8780_en.html http://www.evi-gti.com/default.asp?contentid=1227 http://www.msm.cam.ac.uk/UTC/thermocouple/pages/HEATTOP.html Pyrometers http://www.lirkorea.com/Landinstruments.net%20Website/combustion/ downloads/index.htm http://www.rotadata.com/pages/products/optical_pyrometry1.php Ceramic thermocouples http://www.rowantechnologies.co.uk/research_and_development.htm Thermography Grote K H, Antonsson E K (2009) Handbook of Mechanical Engineering, Springer edition, vol. 10, pp. 135–136.



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3 Availability analysis of integrated gasification combined cycle (IGCC) power plants A . L A U G W I T Z , M . G R A¨ B N E R a n d B . M E Y E R , TU Bergakademie Freiberg, Germany

Abstract: In this chapter each of the four main units (air separation, gasification, gas treatment, power block) from 13 integrated gasification combined cycle (IGCC) plants are critically analyzed in terms of planned and unplanned downtimes. It can be seen that these plants cannot compete with conventional coal based power plants in terms of availability, especially due to unplanned production losses. Reasons for unplanned downtimes are many and vary from plant to plant, so a generalization concerning lessons learned is difficult to make. However, one element is that coal based integrated gasification plants need four to five years to achieve their average availability of 50–70%. On the other hand, refinery residue based integrated gasification plants need only two to three years to achieve higher average availabilities of 80–90 %. Key words: IGCC, gasification, combined cycle, power plant, ASU, availability.

3.1

Introduction

From 1994 to 1997, different coal based integrated gasification combined cycle (IGCC) plants of a size between 100 and 400 MWel were realized. The goal was to demonstrate that IGCC technologies were ready for commercial implementation. Moreover, several IGCCs, some of even bigger size, have been erected in the last 13 years, gasifying refinery residues for hydrogen and electricity production. The large-scale operation of this technology has led to the accumulation of a large store of lessons learned in the industry. Verification of low SOx, NOx or dust emissions as well as an acceptable quality of waste water and slag was achieved. Moreover, expectations concerning high thermal efficiency were confirmed. Nonetheless, ongoing improvements in conventional combustion technologies inhibited transla110 © Woodhead Publishing Limited, 2011

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tion of specific IGCC characteristics into a striking competitive advantage over these conventional power generation systems. One reason is that availability of these IGCC demonstration plants could not satisfy the demands of the power industry. Reaching commercial breakthrough will therefore also depend on investigating the reasons for low availability and conducting appropriate remedies. In the following, the main availability issues are pointed out. The objective is to minimize planned and unplanned downtimes by deriving an advantage from the lessons learned, which have been published in open source literature.

3.2

Basic structure of integrated gasification

Each IGCC comprises the same fundamental units shown in Fig. 3.1. Their particular technical realization and configuration, however, depends on specific boundary conditions. The air separation unit (ASU) is responsible for delivery of oxygen (gasification agent) and/or nitrogen (transport agent, purging gas, diluent). The gasification unit comprises fuel preparation (grinding, milling, drying, slurrying), the reactor itself and the raw gas cooling unit. Subsequently, raw gas has to be treated prior to its combustion in the combined cycle unit (CCU).

3.2.1 Air separation unit The overwhelming majority of gasifiers in IGCC applications employ oxygen of at least 85 % purity (usually 95 %) as gasification agent. The Pinõn Pine IGCC was operated using air, but at the moment there is only the MHI gasifier at Nakoso IGCC employing air (slightly enriched) as gasification agent. The targeted oxygen purity of the other investigated IGCCs lies between 85 % and 99.5 %. Another very important and often discussed variable to be considered is the degree of air-side integration between the ASU and gas turbine, defined as the proportion of the air requirement of the ASU that is extracted from the gas turbine. Integration can reach from 0 % (Wabash) to 100 % (Buggenum, Puertollano). Air-side integration of 100 % leads to long start-up periods due to a sequential start sequence (Hannemann, 2002). In these cases the ASU can deliver required oxygen during the start-up process with a time lag only. This could be counteracted by oxygen and nitrogen storage, which would lead to increased investment costs. Additionally, the longer start-up procedure requires excessive amounts of expensive back-up fuel. So far this option seems economically unfavorable, especially in times of higher natural gas prices. On the other hand, there may be a need to extract a certain amount of air from the gas turbine air compressor in order to facilitate optimal performance over a wide range of ambient conditions and in case of


Basic structure IGCC.


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load changes. Moreover, the auxiliary load of the ASU is markedly reduced by decreasing necessary compression effort, giving rise to higher IGCC efficiency. The ideal degree of integration depends on many conditions (e.g. chosen gas turbine, scope of environmental conditions, load changes, CO2 sequestration). However, Gra¨bner et al. (2010) recommend 70 % integration for coal fed IGCCs featuring two gas and one steam turbine.

3.2.2 Gasification unit Different options and entailed issues of the sub-units of the gasification unit strongly depend on the chosen reactor technology. Entrained flow gasifiers (GE, ConocoPhillips, Shell, Siemens, MHI and others) require coal particle sizes of less than 100 μm, whereas fluidized bed gasifiers are fed with particles of 2–5 mm in size and moving bed systems can process particles in an order of magnitude of centimeters. Of course, these differences have an influence on chosen milling technology. Moreover, it should be considered whether a dry feed (Siemens, Prenflo, KBR, MHI) or a slurry feed (GE, ConocoPhillips) is used. Usually dry feed leads to application of roller mills and the necessity of a dryer. Slurry preparation is usually done in rod mills. Besides fuel preparation, the pressurization of fuel can be conducted in different ways. Slurry fed systems employ pumps for transportation and pressurization purposes. A dry feed requires lock hoppers for pressurization and usually pneumatic dense phase conveying (using N2 or CO2 as the transport agent) for transportation purposes. The gasifier itself is typically, though not always, an entrained flow reactor. Moving bed gasifiers (like those in Vresova) are employed as well in some industrial applications, but the targeted product in these cases is chemicals or fuels rather than power. Flow direction of entrained reactors can be downdraft (GE, Siemens) or updraft (ConocoPhillips, Shell, Prenflo). The gasifier can be a refractory lined vessel (GE, ConocoPhillips) or a membrane wall construction (Shell, Siemens, MHI). Most of the reactors are single staged (GE, Shell, Siemens, Prenflo), which means that coal is fed at one level only. In order to establish a chemical quench, some gasifiers feature a second feed level. These are called two staged reactors (ConocoPhillips, MHI gasifier). Generated gases have a temperature between approximately 1000 8C (two staged gasifiers) and 1600 8C (single staged gasifiers). Prior to subsequent gas treatment, a temperature decrease is mandatory. Raw gas cooling can be realized in different ways. Usually, steam is raised while the raw gas is cooled in order to use it for power production via the steam turbine. Employed heat exchangers are radiant heat exchangers (employed only by GE, but Siemens is likely to use it (Hannemann, 2010)) and convective heat exchangers (water tube or fire tube). Another way to reduce raw gas temperature is to apply a recycle gas


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quench as performed by Shell and Prenflo. An additional option is a full water quench (offered by GE and Siemens), which is not used in coal fired IGCC plants at the moment due to a related decrease in thermal efficiency since no additional high pressure steam can be fed to the steam turbine. A full water quench is a reasonable cooling option if a downstream CO shift conversion is desired, which would be the case in chemical applications or if carbon capture and storage (CCS) is planned. Of course different combinations of mentioned cooling options are conceivable. Pre-treatment of raw gas includes separation of solid matter as well as ammonia and chlorides. Employed devices are candle filters (ceramic or sintered metal), water wash or scrubbers. Finally, slag removal devices are part of the gasification unit. Depressurization is, in most cases, done via lock hoppers. Only the ConocoPhillips gasification unit is equipped with a continuous slag depressurization system without lock hoppers (Holt, 2006). Additional information on gasifiers and related sub-units can be found in Schmalfeld (2008) and Higman (2008).

3.2.3 Acid gas removal and sulfur recovery Sulfur compounds like H2S, COS and mercury are the main impurities that have to be removed. Acid gas removal (AGR) technologies can be categorized into chemical (usually amine gas treatment, e.g. MDEA, ADIP) or physical (e.g. Selexol, Rectisol, Purisol, Genosorb) absorption processes. Additionally, there are mixed approaches like Sulfinol or Amisol combining features of both categories. Each option can be characterized as a mature process since they have been practised for many years in different industrial applications featuring very high availabilities. Rectisol is capable of guaranteeing demanding purity requirements of a possible subsequent synthesis (< 0.1 ppmv total sulfur). Moreover, it can handle a raw gas containing various trace elements. On the other hand, it is an expensive process generating sulfur levels one order of magnitude lower than required for a combined cycle. This is why IGCC plants usually employ alternative approaches like MDEA, Selexol or others, which are much cheaper. Opting for one or the other will be based on a trade-off between very high purity (Rectisol) and low investment costs (MDEA) with Selexol and Sulfinol lying in between. Moreover, COS handling needs to be considered as well. Conversion of COS into H2S via hydrolysis has to be conducted prior to cold gas cleanup, due to the fact that chemical scrubbers are not capable of absorbing COS and Selexol would be uneconomic if designed to do so. Only Rectisol does not need an upstream hydrolysis at all. Once the H2S was separated it is usually treated in a sulfur recovery unit. Typically, a Claus plant is employed for that purpose. The only exceptions in IGCC applications are Tampa and Vresova, where sulfuric acid is produced



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instead of elementary sulfur, and Nakoso IGCC, where a limestone–gypsum unit is employed. Each IGCC Claus plant employs oxygen to operate the Claus furnace in order to reduce capital costs. Oxygen demand is low compared to the oxygen consumption of the gasifier. Differences occur in the handling of tail gas treatment. In a typical refinery Claus plant the tail gas is hydrolyzed and cleaned from sulfur using an amine solution prior to being post-combusted and released into the atmosphere (traditional tail gas treating–TGT). An alternative concept is to recycle hydrogenated tail gas. This results in both elimination of a permanent sulfur emission source and increased mass flow to gas turbine. The point of recycle stream integration differs from plant to plant. Besides H2S, CO2 can be separated from the raw gas as well for capture and sequestration purposes (pre-combustion capture of CO2). The basic principle is to convert the CO of the generated gas in a water gas shift reaction into CO2 and H2 with subsequent separation of the CO2 in the gas cleaning units. Hence, a conditioned fuel gas containing mainly hydrogen can be fed to the combined cycle unit. Respecting economic considerations, suitable CO2 separation processes are selected depending on the required CO2 purity of the separated stream (selectivity), the partial pressure of CO2 in the raw gas stream and the required separation efficiency. Whereas the carbon recovery rate determines the amount of CO2 captured, the properties of the separated CO2 stream are defined by the CO2 transport and storage technology or other utilization approaches. Today, separated CO2 is used for enhanced oil recovery (EOR) in Canada. Potential technologies for CO2 separation are membranes, pressure swing adsorption (PSA) or physical and chemical absorption. Chemical scrubbers usually show a low co-absorption of non-acidic components. Thus these scrubbers show a high selectivity for CO2 if the raw gas was desulfurized in a prior step. Physical scrubbers are especially suitable for IGCC processes because CO2 separation is favorable at higher partial pressure compared to chemical scrubbers. Moreover, these systems are characterized by a higher solvent loading, which is especially advantageous if higher mass flows of CO2 have to be separated, as the amount of scrubbing agent can be reduced, resulting in a reduced auxiliary power demand for pumping. A comprehensive comparison of IGCC applications with and without CO2 separation is given by von Morstein et al. (2009) and Gra¨bner et al. (2010). However, because CO2 capture is not applied in large scale IGCC applications, its influence on the availability of a gas treatment system can be analyzed only from a theoretical point of view. It should be mentioned that the Puertollano IGCC accomplishes tests to separate CO2. Since late 2010, a new 14 MW pilot plant has demonstrated H2 production and CO2 capture (ELCOGAS, 2010).


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3.2.4 Combined cycle The combined cycle unit includes a gas turbine, a heat recovery steam cycle and associated auxiliary devices and is comparable to a natural gas driven combined cycle. One main difference is the application of NOx reduction techniques. Operation with significant quantities of hydrogen is not possible with the pre-mix ‘dry low NOx’ burners used in modern natural gas machines and so diffusion flame burners are used. NOx control is therefore performed by dilution either with N2 or steam or a combination of both. There is little experience with selective catalytic reduction (SCR) in the flue gas stream. Waste water treatment and the flare do not significantly contribute to overall downtime of an IGCC plant and will not be regarded in the following. An overview and detailed information on state-of-the art IGCC plants can be found in Holt (2006), Anon. (2010) and Nykomb-Synergetics (2007). Tables 3.1 to 3.3 summarize the most important characteristics of analyzed IGCC plants.

3.3

Availability issues of the ASU

Industrial gasification plant operators have two different options for oxygen supply: onsite or offsite production. Typically, coal based IGCC plants chose the onsite option. On the other hand, most refinery IGCCs opted for the offsite oxygen generation. In this way a gas company can operate the ASU by employing specially trained staff, which usually leads to better reliability of oxygen supply in these cases. Generally, air separation units in industrial applications have a typical availability of 98.5 % with downtimes of approximately 1 % due to planned outages and 0.5 % due to unplanned outages respectively (EPRI, 2007a). Even though planned downtimes of an IGCC-ASU are scheduled to coincide with other planned maintenance work, the performance of existing units has not matched that of other industrial ASU performances, as shown below.

3.3.1 Reported failures Even though there are no published numbers, it seems quite evident, though surprising, that the electric motor of the air compressor was a main reason for poor availability (< 70 % within the first 2 years) of the Falconara IGCC plant. Subsequently, the unreliable electric motor was replaced. It is believed that lack of reliability was caused by the employed cooling concept. Fresh sea water was used for cooling purposes instead of a closed circuit. This design caused considerable corrosion problems and entailed leakages



Nippon Oil Corp.

Clean Coal Power R&D Co. LtD

Falconara, ITA

Negishi, JAP

Nakoso, JAP

SGC – synthesis gas cooler.

api

Sarlux, ITA

*

ERG Petroli; LUKOIL Saras S.p.A.

ISAB, ITA

2007

2003

2001

2001

2000

1997

Shell

Pernis, NL

1997

1997

Sustec

SVZ, GER

1996

250gross

350

241

550

512

130gross

300

80

26200

100 253

Puertollano, ESP ELCOGAS

Sokolovska Uhelna

Vresova, CZ

250

1998 1994

250

1996

SG Solutions/ 1995 ConocoPhillips

Wabash River, USA

Polk Power Tampa Station, USA Electric Pinõn Pine, USA SPPC Buggenum, NL Nuon (part of Vattenfall)

Operator

Plant

28

22 26

30

29

71 N.A.

MHI; air blown

66

39

GE (oil)

GE (oil)

GE (oil)

68

61

Shell (oil) GE (oil)

26

Prenflo

Coal

Power

Power

Chemical quench; convective SGC

McDaniel, 2002

Dowd, 2000

References (for Tables 3.1, 3.2 and 3.3)

Breakler and Kamka, 2004 Holt, 2006 Siemens V94.3 ELCOGAS, 2001 Penã, 2009 Penã, 2010 GE MS 6541 B de Graaf et al., 1999 EPRI, 2007a 26Siemens Anon. 2009 V94.2K EPRI, 2007a 36GE 9E Sharp et al., 2002 Collodi and Brkic, 2003 Alstom (ABB) Sharp et al., 2002 13E2 Arienti et al., 2005 MHI 701F Ono, 2003 Yamaguchi, 2004 Hatayama, 2006 MHI 701 DA Ishibashi and Shinada, 2008 Ishibashi, 2009 Watanabe, 2010

GE 6 B

GE 6 FA NETL, 2002 Siemens V94.2 Hannemann, 2002 Kanaar, 2002 Holt, 2006 26GE 9E Buryan et al., 2008 Holt, 2006

GE 7 FA

GE 7 FA

Cooling concept Gas turbine

Chemical quench; fire tube SGC* Coal; Power Radiant SGC; petcoke fire tube SGC Coal Power Convective SGC Coal; Power Recycle gas biomass quench; water tube SGC Lignite Power Full water quench for Siemens– gasifier–raw gases Coal; Methanol; Diverse biomass; power waste; plastics Coal Power Recycle gas quench; water tube SGC Refinery H2; power Fire tube SGC residues Refinery H2; power Full water quench residues Refinery H2; power Full water quench residues Refinery H2; power Full water quench residues Refinery Power Full water residues quench

Coal; petcoke

Pressure (bar) Feed-stock Product

76Lurgi fixed bed 25 16BGL 16Siemens

266Lurgi fixed bed 16Siemens

KRW; air blown Shell (coal)

GE (coal)

ConocoPhillips

Size Start-up (MWel,net) Gasifier

Table 3.1 Overview of analyzed IGCC plants

Availability analysis of IGCC power plants 117

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Table 3.2

Overview gas treatment and sulfur recovery in gasification plants

Plant

Gas treatment

Sulfur recovery

Wabash River Polk Power Station Pinõn Pine Buggenum

Claus unit Sulfuric acid CaO + SO2 + 12O2 → CaSO4 Claus unit

Vresova

COS hydrolysis + MDEA COS hydrolysis + MDEA Transport desulfurizer HCN/COS-hydrolysis + Sulfinol M Rectisol

SVZ Puertollano Pernis ISAB Sarlux Falconara Negishi Nakoso

CO shift + Rectisol COS hydrolysis + MDEA CO shift + Rectisol COS hydrolysis + MDEA COS hydrolysis + Selexol COS hydrolysis + Selexol COS/HCN hydrolysis + ADIP COS hydrolysis + MDEA

Table 3.3

Summary IGCC ASU

Plant

LOX Capacity % O2 % Integration O2 production storage ASU–GT (t/d)

Wabash River 2060 Polk Power 1840 Station Pinõn Pine Buggenum Vresova SVZ Puertollano Pernis

1780 N.A. N.A. 2400 3175

95 95

0 Initially 0; 15 since 2005

95 100 96 0 94 50 85 100 99.5 0

ISAB 261850 95 Sarlux 262300 95 api Falconara 95 Negishi 2400 95 Nakoso

Haldor Topsøe (wet sulfuric acid plant) — Claus unit Claus unit Claus unit Claus unit Claus unit Claus unit Limestone–gypsum unit

0 0 0 0

Onsite Onsite

Air blown Onsite Onsite Offsite Onsite Offsite

Offsite Offsite Onsite Onsite

Supplier

No No

Air Liquide Air Products

Yes N.A. N.A. Yes Yes, plus 7 km pipeline Yes Yes No No

Air Products Linde Linde Air Liquide Air Products

Air Liquide Air Liquide Praxair Air Liquide

Enriched air blown gasifier

(Arienti et al., 2005). Likewise problems occurred at Wabash. Windings of the electric motor were exposed to moisture, which caused serious problems but no outages. The root of related troubles is that the motor operated outdoors even though it was not designed for outdoor operation. Tampa and Negishi suffered from production loss of 3 weeks (McDaniel, 2001; Yamaguchi, 2004), which was caused by a damaged air compressor rotor and required repair at the manufacturers’ factories. Neither Tampa nor



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Negishi had a backup rotor, which could have reduced downtime. According to the Final Technical Report from the Wabash River Project (Dowd, 2000), the most important issue concerning reliability of its air compressors is the inlet guide vane. Furthermore, Tampa operators experienced some trouble with that particular device and there were several other gasification plants, which had additional problems with instrumentation and control devices associated with the air compressor. In some cases, molecular sieve heat exchangers suffered from leakage of steam to the gas side, which can lead to intrusion of moisture into the molecular sieve during regeneration. As a consequence, the cold box might be exposed to moisture and subsequently freeze up. One possible reason for leakage was reported to be vibration of the heat exchanger. Furthermore, ductwork leakage within the cold box was experienced at Tampa and Wabash. The 401 hours of unplanned downtime in 2000 were caused by welding failures on an instrument tube at Tampa (McDaniel, 2000). Repair took quite a long time because an inaccessible area was concerned. The Wabash River Final Technical Report (Dowd, 2000) reports 299 hours of unplanned downtime due to inaccurate welding on a de-icing collector as well. During a durability test of the recently erected Nakoso plant (air blown MHI gasifier) leakage of extraction air cooler tubes was observed. This was caused by corrosion due to inadequate and irregular tube materials (Watanabe, 2010). None of these failures can be attributed to design features specific to an IGCC application. However, when designing an ASU for an IGCC, it is clearly necessary that similar criteria are applied to issues of reliabilityrelated design and specification as elsewhere in the industrial gas industry in order to ensure similar reliabilities of 99–99.5 %.

3.3.2 Liquid oxygen storage Short-term outages of ASU can be bridged by buffered oxygen, though this is limited for economic reasons to about half a day. Regarding the above explained failures and root causes, it is evident that LOX storage would not have been capable to avoid all production losses. These considerations caused some owners not to consider oxygen storage in future gasification plants (ELCOGAS, 2001). On the other hand, the presence of a storage system seems reasonable for certain plants, as operators make some effort to improve their systems (Buggenum). Several considerations should be taken into account when opting for or against liquid oxygen storage. First, due to the fact that motors from air compressors are vulnerable to voltage dips, stability of the external grid must be ensured. Second, economical penalties for a gasifier outage (mainly backup fuel for the gas turbine and restart process) need to be considered.


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3.4

Availability issues of the gasification unit

Due to the fact that the gasification unit is the most distinctive part of an IGCC plant, its sub-units are itemized in more detail compared to the other main units.

3.4.1 Feed system Issues for slurry feed and dry feed systems tend to be different. One main issue related to the slurry feed system is settlement of particulate matter in both storage tanks and suction pipes (especially upstream of the slurry pump during downtimes). This can be avoided by ensuring permanent motion of the slurry. Most slurry fed IGCCs employ slurry storage tanks, which can bridge unplanned downtime of the rod mills. Moreover, most plants (except Tampa) have two slurry pumps of 50–100 % capacity each. A similar decision is necessary for dry fed systems. The number and capacity of mills have a decisive influence on the availability of the fuel preparation unit. The 2660 % roller mills from Puertollano have been identified as being insufficiently robust (Penã, 2005) and to be important contributors to outages. The 3650 % mills used in Buggenum ensure increased availability of the fuel preparation unit. Dry fed IGCCs are of course concerned with common issues related to transport and storage of ground coal, e.g. bridging in sluicing devices or clogging of conveyors as experienced at Puertollano. Moreover, it is not trivial to maintain a stable fluidization and adequate pressure control in dense phase transport systems and to establish a vital and reasonable coal dust explosion prevention system. An issue common to both feed systems is the proper blending of raw materials in order to guarantee adequate and predictable characteristics of the gasifier feedstock. This is of decisive importance, since adjustment of gasification conditions, slag removal and raw gas cooling parameters is based on predicted feedstock properties.

3.4.2 Gasifier Feedstock It is absolutely necessary to avoid slag solidification within the reaction chamber of slagging gasifiers. Solid slag lumps would plug the bottom discharge system. Thus it has to be ensured that operation conditions are constantly above the ash melting point. In the case of altered coal feed it is essential to adapt the operation temperature to new ash properties. As an example, Buggenum suffered from formation of slag lumps in the



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lower part of the reaction chamber in the early days. Until 2002 the IGCC operation management was not responsible for delivered coal quality. Coal was supplied by nearby conventional plants. In this way, uncontrolled changes in coal quality caused several outages (Kanaar, 2002). Reactor wall Decisions made on refractory lined vessel or cooling jacket concepts or membrane wall construction have a decisive impact on unplanned and especially planned downtime. Aggressive and corrosive slag stresses different layers of refractory lining, which leads to increased abrasion and wear. Consequently, the lifetime of such vessel linings is usually less than 2 years, even though Wabash achieved 3 years by 2006 (Holt, 2006). In case of replacement of refractory it takes up to 35 days to cool down the gasifier, change the refractory and reheat the system. On the other hand, Payonk (2008) reports that refractory repairs at the Wabash River IGCC can be done in 17 days. If possible, it is reasonable to make these changes during planned maintenance of other devices (e.g. the gas turbine). Moreover, employment of a refractory lining requires slow start-up and shut-down to avoid high temperature gradients in the bricks. Comparatively short lifetimes of these systems make employment of a spare reactor especially desirable even though Payonk (2008) claims that the spare reactor at the Wabash River IGCC is no longer needed. An alternative design is provided by membrane wall construction. The metallic vessel is protected by a water wall with a studded ramming mass. Pressurized water flows through the tubes of the wall, is heated and is used for steam generation. The inner side of the ramming mass is exposed to the hot synthesis gas. Liquid slag reaching the inner wall of the reactor transfers its heat into the membrane wall and thus solidifies. A protective layer of solid slag grows. If this insulating coat is thick enough, the outer slag will no longer solidify and will flow downwards into a slag chamber. The insulating layer regenerates immediately whenever a part of the wall is unprotected. This construction makes it absolutely necessary to operate at temperatures above the ash melting point. When gasifying low ash feedstock (pet coke, low ash coals) about 5 % of the ash or flux must be added to the feed, so as to maintain the solid slag layer. Advantages compared to refractory lined vessels are reduced weight of the gasifier, faster start-up and faster shutdown because temperature gradients are unproblematic. Lifetime of the Buggenum membrane wall is expected to be 25 years with more than 16 years of successful operation so far (Chhoa, 2005). Prenflo and Siemens gasifiers expect comparable lifetimes (Radtke, 2007; Schingnitz, 2008). Thus, the lifetime of membrane walls does not influence the overall availability. However, it should be mentioned that the bottom part of the Buggenum


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reactor was refractory lined and required periodic maintenance. It is expected that Shell will equip future gasifiers with a water cooled bottom region (Chhoa, 2005). On the other hand, there are some issues related to membrane walls at Puertollano, where the wall suffered from local leakage caused by flow blockages and erosion on the water side (Pena˜, 2005). Burner Slurry feed systems are stressed by frequent burner changes because stress corrosion cracking leads to short lifetimes of injector tips (Holt, 2006). Associated downtime is approximately half a day. In the case of single train concepts, downtime may be even longer because downstream gas cleaning units have to be restarted after the maintenance period, which is timeconsuming. Lifetime of burners from dry fed gasifiers (up to more than 16 000 hours) does not affect overall availability at all (Chhoa, 2005). However, for the dry feed gasifier at Nakoso, Watanabe reported an erosion issue at the burner cooling tube caused by inadequate positioning of the burner (Watanabe, 2010). Corrosion Penã (2005) reports of ‘cold ends’ corrosion and downtime corrosion at the Puertollano IGCC. Characteristic locations are fittings for the measurement equipment and nozzles, where wet syngas is cooled below its dewpoint. There are two ways to eliminate such destructive corrosion. Either utilization of sour gas corrosion resistant materials or deployment of trace heating should be considered.

3.4.3 Slag removal Issues connected with the slag removal section have centered around plugging and erosion/corrosion aspects. Usually, plugging emerged if slag properties changed due to an unexpected change in feedstock properties as described above. Polk Power Station experienced how solidified slag lumps plugged the slag discharge line as well. It takes up to 10 days to cool down the system and to mine out the clump (Holt, 2006). An important issue in the slag removal unit is erosion and corrosion in the piping of circulating slag water from the slag bath. This circulating water contains fine, sharp solids, which cause erosion (Holt, 2006). Additionally, the pH value needs to be monitored in order to avoid corrosion. As reported by EPRI (2007a), the Buggenum slag disposal tubes were stressed by erosion and corrosion, leading to approximately 120 hours of downtime in 2002. Meanwhile, these tubes have been replaced by more resistant duplex steel. It



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has also been reported that particle separation from slag bath water caused problems. Thus it was necessary to retrofit a lamella separator. It is well known that Buggenum decided to replace the ceramic heat skirt, which was installed to protect the pressure vessel wall of the slag bath, and retrofitted a membrane wall construction. Puertollano operators observed that erosion will occur if velocities in solids separation units (e.g. slag removal, entrained fly ash) are high. As in Buggenum, stressed devices were replaced by wearresistant materials and design. Also, operation control has been improved (Penã, 2005). A unique pressure let-down system is used in ConocoPhillips systems (Wabash) where lock hoppers are redundant. So far, no problems have been reported, apart from slag plugging, which emerged once.

3.4.4 Raw gas cooling Fouling, plugging and leakage are the possible reasons for a significant number of failures. Unplanned maintenance is reported as a regular issue by each IGCC operator, though reasonss vary due to the different cooling approaches taken by the respective technology suppliers. Alteration of the feedstock quality can cause entrained fly ash to plug the entry zone of cooling units in a comparable manner to the plugging of the slag discharge line as described earlier. Adapted operation control is required in these cases, as done by Buggenum operators, which consequently could reduce such fouling issues (Eurlings and Ploeg, 1999). On the other hand, leakage has remained an issue in the last few years. Waste heat boilers in Puertollano were stressed by both sticky and fluffy fly ash (Pena˜, 2005). As a consequence, the recycle gas stream (for gas quench purposes) was increased in order to decrease the gas inlet temperature at the entry zone of the heat exchanger. In this way entrained ash was much less sticky and both plugging and fouling were reduced. Issues contributing to fluffy fly ash were solved by increasing gas velocity. The gasification system at Tampa employs both a radiant syngas cooler (RSG) and convective syngas coolers (CSCs). The RSG is much less stressed by fouling than expected; thus it cools the raw gas even more than designed. Only a few outages of 288 hours in 1999 and 96 hours in 2001 were reported by EPRI (2007a). The inlet region of the CSCs is one main problem and significantly reduces overall availability. Ten outages between 1999 and 2001 caused almost 1500 hours of unavailability. As a consequence, accessibility of the heat exchangers was improved and it was decided to eliminate convective coolers for the future reference plant (Rigdon and Schmoe, 2005). Even after more experience was gained this issue could not be overcome. Up to 5 % lost availability was caused by plugged coolers in 2006


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and 2007 (McDaniel, 2007). Plugging forces a shut-down in order to clean the tubesheets every 30 to 45 days (McDaniel, 2008). Because the ConocoPhillips gasifier features a second stage (chemical quench leads to comparatively low outlet temperatures of approximately 1040 8C), there is only one vertically arranged convective syngas cooler employed at Wabash River. Fouling was also an early problem of this syngas cooler. It was caused by entrained tar matter that survived in the secondary gasification zone. Adapted operation control and feeding of petcoke solved that problem (Dowd, 2000). An additional correction was to improve accessibility of the syngas cooler, as was done at Tampa as well. Another, very specific incident resulted in 607 hours of lost production. Sodium carbonate condensed at cooling pipes, which led to an increased pressure drop and impeded heat exchange. The source of sodium might have been waste water recycled to the rod mills that was neutralized using caustic soda (EPRI, 2007a).

3.4.5 Raw gas pre-cleaning Dry filtration Scheibner and Wolters (2002) report of a successful cooperation between Nuon and Pall Schumacher to improve performance of ceramic candle filters at the Buggenum IGCC. Lifetime could be doubled to two years because plugging and breakage of candles were overcome. One remedy was to fix candles in a grid in order to avoid horizontal movements of the candles. Unfortunately, Puertollano could not extend the lifetime of employed ceramic candle filters above 4000 operating hours (8000 hours were initially expected), because plugging had not yet been overcome. Another issue related to ceramic filters is breakage. This is why Wabash operators switched to sintered metal filters in 1996. These show a reasonable performance and lifetimes of 10 000 hours (Payonk, 2008). Watanabe (2010) also reports inadequate tightening of a package. This resulted in gas leakage from the base of a rotary valve below the filter. The failed IGCC project Pinõn Pine had its main problems with a hot gas filtration system. As reported in a DOE Assessment Paper (NETL, 2002), operators could not overcome problems with the filter-fines removal system (accumulation of fines in the bottom region of the hot gas filter). During a last start-up attempt of the Pinõn Pine IGCC, some material from the desulfurizer (installed just prior to the hot gas filter) was entrained, reached the filter and ignited. The consequential fire and ensuring damage caused the termination of the project in 2001.



125

Wet scrubbing The whole scrubbing unit and recycle system is acidic. Therefore, monitoring and adjustment of the pH value is necessary. If entrained particles are not separated in a dry filter (Tampa), they will be separated in the scrubber and the correct design is required in order to avoid erosion and corrosion issues in the black water piping. Typically fivedimensional radius bends and ensuring a low chloride content in the circulating water are usually sufficient to avoid any concern. Attention should be paid to another potential problem as well. Raw gases could entrain droplets from the scrubbing unit, especially during the startup process. Droplets contain halides and metals, which act as a catalyst poison in the subsequent COS hydrolysis. In order to avoid damaged catalysts, as experienced at Tampa (McDaniel, 2002), the COS hydrolysis should be started only if the prior scrubber has reached stable operation. Although the gasification area has not been the most frequent contributor to unplanned outages, some issues are less amenable to improvement than those in other parts of the plant. Some problems like issues with the convective syngas coolers in Polk can only be resolved in a new plant and the demonstration plant will have to continue with the design it has. Work has been done on extending the life of refractory linings, although it will be a while before the improvements can be quantified. There are inherent issues with any solids handling systems and the gasification unit is no exception. For dry-feed units some solutions are available from conventional power plant technology. Clearly the lessons learned from the demonstration units will benefit new plants, but one must still be cautious about taking too much credit for this at this time.

3.5

Availability issues of acid gas removal (AGR) and sulfur recovery

Even though AGR is a mature technology and only a small amount of unplanned downtime can be attributed to the related units, there are some lessons to be learned.

3.5.1 Acid gas removal COS hydrolysis Several operators reported the formation of formic acid on hydrolysis catalysts. This acid can give rise to corrosion issues (directly or indirectly) for the downstream units. Formation may be due to the following reaction (EPRI, 2007a): HCN þ 2H2 O $ NH3 þ CHOOH;

DH ¼ 76:14 kJ=mol


126


The only plants that seem to be untroubled by that issue are Negishi (they have an ammonia wash prior to their ADIP desulfurization unit) and Buggenum (they explicitly call their hydrolysis a HCN/COS hydrolysis). Moreover, catalyst poisoning and damage caused by condensation must be avoided. For this reason it needs to be ensured that alkali, heavy metals and halides do not reach the COS catalysts and that operation is not close to dewpoint conditions. Tampa operators had to change their start-up procedure to avoid entrainment of catalyst poisons from the scrubber into the COS hydrolysis unit (McDaniel, 2002). There was no water wash prior to the COS hydrolysis unit in the original design for Wabash, so chlorides and metals damaged the COS catalyst. After the first damaged catalyst a water wash was retrofitted (Dowd, 2000). The first catalysts at Puertollano were alumina based and featured a very poor durability leading to 2–3 changes p.a. (Penã, 2005). Later, a new and 8 times more expensive catalyst, based on titanium, was employed. Additionally, inlet temperature was increased and subsequently the point of operation was shifted further away from the dewpoint. Both remedies increased the lifetime of the catalyst, which operated successfully for 4 years. Selexol Operators of Selexol utilizing plants reported the entrainment of formic acid from the COS hydrolysis unit during the start-up process. They discovered that formic acid is absorbed by Selexol solvent and is vaporized in the regenerator. Subsequently, it condenses overhead, is refluxed back into the column and accumulates in the system in this way. Consequently, the pH value is reduced, which leads to considerable corrosion (Sharp et al., 2002). Rectisol There is one issue related to Rectisol that causes significant downtimes: plugging of the methanol–water column, as reported, for example, by Shell for its Pernis IGCC (EPRI, 2007a). MDEA Entrainment of formic acid from COS hydrolysis caused significant degradation of MDEA solution. This caused the formation of corrosive heat stable salts. As a consequence, additional maintenance was necessary to fix corroded and fouled devices. Installation of an ion exchanger solved that issue at Tampa and Wabash by removing heat stable salts from the solution cycle (Dowd, 2000; McDaniel, 2002). Since the new titanium catalyst was



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employed, Puertollano operators had no further trouble with fouling of the AGR solvent.

3.5.2 Sulfur recovery Even though Claus plants in refinery and natural gas environments are extremely reliable, they represent a critical bottleneck as these units are in charge of assuring permitted annual sulfur emission of the whole plant. In the case of a Claus plant outage, these emission values will be reached quickly, forcing a shut-down of the IGCC. As this circumstance is generally recognized, most commercially operated IGCCs employ 2666 % Claus units. Since in general the ICGG will not be operating with the highest sulfur design coal, this still leaves scope for an operation reasonably close to full load in the event that one unit is down. However, there are some reported hours of lost production connected to the Claus unit. Wolters (2003) reports of almost 600 hours of downtime in 2003 due to corroded welds and entailed leakage of the Buggenum Claus unit. The remedy was found by redesigning the tube sheets. Acid gas removal and sulfur recovery units have not been a major contributor to unplanned outages in IGCCs. Nonetheless, their performance in the demonstration units has not been as good as similar equipment has shown in the oil and gas or chemical industries. Many of the problems can be attributed to issues of plant integration, e.g. trace formic acid formation in the COS hydrolysis causing corrosion in the downstream acid gas removal unit. These issues have now been largely identified and a closer approach to the reliability levels of other industries can be expected.

3.6

Availability issues of the combined cycle

During examination of data provided by public reports and databases (ORAP®), in order to judge the availability of syngas fired combined cycles it turns out that these units cannot match the reliability performance of natural gas driven combined cycles. Natural gas driven gas turbines achieve availabilities of 90–95 % whereas CC units in IGCC applications achieve in most cases less than 90 % (Higman, 2005). Analyzing these data, one should be aware of the fact that Tampa, Wabash and Puertollano employed new F-class gas turbines (see Table 3.1). Each represents an early model of the respective series. Even natural gas driven turbines of the same class exhibited availability-reducing problems in the early years and were subject to a major product recall action. The assumption that lower availability is not caused by the syngas application itself is supported by the fact that Italian gasification plants and Buggenum have been equipped with E-class gas turbines, showing a much higher


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availability. However, some published reasons for unplanned downtimes are listed below. Tampa and Wabash operators experienced quite similar problems with their CCUs. An outage lasting 100 days in 1999 due to a damaged blade in the compressor section of the gas turbine is mentioned in the Final Technical Report from the Wabash IGCC (Dowd, 2000). In 2005, a damaged compressor also caused an unplanned outage of 100 days in Tampa. The damage was caused by a creeping compressor casing and accompanied breakage of the compressor’s stationary elements. Moreover, Wabash suffered from an outage of 19 days due to pipe leakages in HRSG (Payonk, 2000). Tampa experienced problems with the backup fuel system, leading to 416 hours of lost production in 2000 (McDaniel, 2000). Additional 24 days of unplanned outage was reported for 2003. The 7FA rotor was replaced and both generators were rewound. Horizontal silo burners caused several problems at the Puertollano gas turbine. Before a burner modification was made in 2003, preventive inspection of the hot gas pass was required every 500–1000 operation hours (a 3 year interval was desired). After improvement the inspection interval could be extended to 4000 hours. Meńdez-Vigo (2002) reports of 617 hours of downtime in 2001 and 105 hours in 2002. These were necessary, among others, to revise and change ceramic tiles in gas turbine combustion chambers. In 2003 a production loss lasting three months was caused by deformation of the generator casing flange. In 2004 and 2005, issues with the gas turbine transformer, DCS and compressor guide vane occurred. Several operators reported difficulties caused by humming and oscillating gas turbine burners. One of the latest incidents attributed to CCU occurred at the ISAB IGCC. It was reported that an explosion damaged one train of the combined cycle, in October 2008. Since December 2008, the plant has run on the left train. The accident happened during maintenance activities of one train. For some reason, syngas reached the non-operating train past the gas turbine and ignited as it contacted with air in the subsequent HRSG. The explosion pushed back into the gas turbine and destroyed the train. It seems that inertization (using nitrogen) of the maintained train was insufficient (Anon., 2009). Another explosion is reported for the SVZ IGCC by Braekler and Kamka (2004). At SVZ, light oil is fed to the gas turbine for start-up purposes. The explosion occurred during test runs while switching from light oil to syngas. As a consequence, the gas skid was retrofitted by a nitrogen buffer. In the demonstration plants the combined cycle unit has statistically been the largest source of unplanned outage. In evaluating this finding, it is necessary to separate issues associated with syngas firing and those due to



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other reasons, which would also impact availability of a natural gas-fired turbine. With the exception of the Puertollano machine (which is no longer offered by the vendor), the syngas firing issues have been resolved and provide a sound basis for implementing the conversion of newer natural gas models to syngas firing. Nonetheless, it may be wise to assume that a syngas fired turbine will not have an above-average availability compared to a natural gas turbine, or at least not initially.

3.7

Summary of existing plants

Four of the plants (Buggenum, Puertollano, Tampa and Wabash) reviewed in the previous sections were built in the mid-1990s as demonstration plants. For the gasification section three of the four plants represented a major upscaling on previous references. For Puertollano the factor was 40, for Buggenum 9 and for Tampa 2. Additionally, the gas turbines from Tampa, Wabash and Puertollano were early examples of their respective technologies (7FA and V94.3), both of which required several years before fleet teething problems in natural gas service had been resolved. Nevertheless, all the plants achieved their targets for high efficiency and low emissions. While they have also made the transition from demonstration to commercial service, the availability has been less than satisfactory. The following figures summarize the contributions of different units to overall downtime (each reflecting the latest data that are available from public domain sources) and development of IGCC availability of these IGCCs over operation years. It is important to note that published data concerning availability are edited in different ways. Some authors, for example, report on reliability instead of availability or it is not mentioned if stated figures are based on syngas operation only or include backup fuel operation as well. Additionally, one has to be aware of the fact that the contribution of specific main units to overall downtime differs from year to year, as shown in Fig. 3.2 for Puertollano. This is caused by several planned maintenance activities, which consume much time but are necessary in certain years only. It would therefore be best practice to take the mean value of all operational years to calculate representative numbers of their contribution to overall downtime. Unfortunately, there is a lack of published data for most IGCC plants and therefore Fig. 3.3 refers to a specific year only, rather than presenting an average of several years. Nevertheless, general trends can be derived. Additionally, Fig. 3.3 includes coal based IGCCs only, due to the fact that this information is not reported for refinery based IGCCs in open source literature. Note that the Wabash River IGCC was not in operation in 2004 and most of 2003 because of contract restructuring and ownership change (Payonk, 2008). Therefore availability from these years is missing in Fig. 3.4.


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3.2 Main units downtime at Puertollano (2006–2009) (Penã, 2007, 2008, 2009, 2010).

3.3 Contribution of different main units to total downtimes (numbers in brackets refer to the year of operation when numbers were recorded) (Wolters, 2003; McDaniel, 2008; Payonk, 2008; Penã, 2010).



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3.4 Development of IGCC availability (data adapted from Zuideveld, 2001, 2002; Kanaar and von Dongen, 2006; EPRI, 2007a; Hornick, 2007; Ishibashi and Shinada, 2008; Payonk, 2008; Ciccotosto et al., 2009; Domenichini, 2009; Ishibashi, 2009; Penã, 2009, 2010).

It is generally found that refinery based IGCCs show higher availabilities compared to coal based plants. One remarkable fact about availability of coal based IGCCs is the low reliability of ASUs and especially of the combined cycle. The gasification unit itself contributes less to overall production loss than the combined cycle. A fair amount of ASU downtimes could have been avoided and are avoided, as a matter of fact, in the industrial gas industry. Nevertheless, the explained reasons for unplanned downtimes show that poor availability of ASU is not a consequence of its application in an IGCC. Analyzing outages related to the gasifier itself, as done in section 3.4, shows that another conclusion has to be drawn. Even though some lessons learned could have been anticipated, like settlement of solid matter in slurry tanks or downtime corrosion, there are some difficulties left. Extending lifetimes of the refractory lining and injector tips (for slurry feed gasifiers) continue to be the subject of research and results will also benefit existing plants. Other issues, especially fouling in the entry zone of the convective syngas cooler in Polk, remain of concern in these plants, but have been addressed in the design of newer plants. Future research activities will continue to address these problems in order to achieve availabilities comparable to those of Italian refinery residue gasification units. In the case


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of refractory lined reactors, planned maintenance (lining replacement) and its timing with inspections of gas turbines is essential to maximize availability as these two tasks are on the critical path. It is useful to address raw gas treatment units as well, even though reported downtimes hardly contribute to overall production loss. One lesson learned is that entrainment of formic acid from COS hydrolysis to Selexol or MDEA units causes degradation. A second valuable consideration is employment of 2660 % Claus plants due to the fact that availability of the Claus unit is critical to overall plant availability. Low availability of the combined cycle is more a question of the gas turbine applied and the reliability of its auxiliary units rather than application of syngas instead of natural gas. Increasing availability of that unit seems probable for future IGCC plants. However, appropriate scheduling and timing of planned maintenance and inspection activities are of great importance concerning availability, as shown below. Finally, activities to establish a maintenance program for IGCC plants are comparable to those of conventional power plants. A detailed development of a maintenance program for an IGCC plant including, besides others, reliability, availability, maintainability (RAM), hazard and operability (HAZOP), safety integrity level (SIL), failure mode effect and critical analysis (FMECA) and critical spare parts analysis can be found in Verwilligen (2010).

3.8

Forecast based on RAM modeling

A reliability, availability and maintainability analysis (RAM) can be carried out if a database for the various components of an IGCC plant is available comprising mean values and statistical deviations for times between failures and time to repair. Since some international studies incorporate this kind of data, which is typically not gained at IGCC plants, a plausibility check with operating plants is required. Simulations were accomplished by different authors (EPRI, 2007b; Higman, 2008; Sutor et al., 2009) yielding theoretical availabilities and reliability factors for different plant configurations on a higher level of detail. Table 3.4 shows five cases comprising two common IGCC plants with Shell (case A) and GE gasification technology (case B) (EPRI, 2007b), with the latter including a spare gasifier. Case C represents a standard IGCC for hard coal with Shell gasification and CO2 capture derived from von Morstein et al. (2009). The last two cases, D and E, were recently published by Sutor et al. (2009), exhibiting a polygeneration IGCC plant that can produce methane as well as electric power, hence including a methanation unit.



98.84%

n Cap. RF.

Case B – GE IGCC with spare gasifier (EPRI, 2007b)

97.85%

Fly ash removal

89.36% 5.11% 84.80%

91.02% 5.38% 86.12%

1 100% 97.28% Methanation

1 100% 99.51% Methanation

2 60% 97.81%

2 100% 99.06%

2 60% 99.52%

2 60% 99.23%

95.53%

91.45% 5.11% 86.77%

1 100% 99.50%

85.49%

1 100% 98.76%

87.89%

2 60% 99.00%

1 100% 99.80% CO2 compression 1 100% 99.80% CO2 compression 2 60% 99.84% and dehumidification and dehumidification 1 100% 97.87% 1 100% 96.66% 1 100% 97.02%

1 100% 98.83% Claus process

1 100% 99.40% Acid gas removal

1 100% 99.04% CO shift conversion

94.46%

1 100% 99.55% Claus process 1 100% 99.28%

1 100% 99.66%

1 100% 99.74% Acid gas removal

1 100% 99.77% 1 100% 99.74% CO shift conversion

97.08%

1 100% 99.28%

n: number of units, Cap.: capacity, RF: reliability factor; AF: availability factor.

Total Reliability Factor Scheduled Outage Factor Equivalent Availability

2 50% 99.16%

2 50% 99.95% Water wash 2 50% 99.90% Gas cooling, 2 50% 99.88% CO shift boiler feed water, conversion and knockout 2 50% 99.95% Mercury removal 2 50% 99.95% Rectisol absorption 2 50% 99.55% COS hydrolysis 2 50% 99.55% Rectisol regeneration 1 100% 99.87% Selexol - acid 2 50% 99.71% gas removal 2 66% 99.36% Claus process 2 66% 99.36% Claus process 1 100% 99.50% Hydrogenation 1 100% 99.50% Hydrogenation reactor and reactor and gas cooler gas cooler 2 50% 99.87% Syngas reheat 2 50% 99.87% Syngas humidification and reheat CO2 compression and dehumidification 1 100% 94.91% 1 100% 94.91%

97.98%

1 100% 99.74%

4 25% 96.16%

3 60% 99.61%

95.78%

n Cap. AF.

Case E – Polygeneration IGCC – Full Redundant (Sutor et al., 2009)

2 50% 98.59% Coal milling and drying 4 25% 96.16% Siemens gasifier full water quench

94.80%

n Cap. AF.

Case D – Polygeneration IGCC – Non redundant (Sutor et al., 2009)

2 100% 99.78% Coal milling and drying 1 100% 97.90% Siemens gasifier full water quench

96.73%

n Cap. RF.

Case C – Shell CCS IGCC (Higman, 2008)

2 100% 100.00% Coal handling, 2 100% 99.99% conveyor 3 50% 99.75% Slurry preparation 2 70% 99.36% Coal milling and drying 2 60% 99.54% Slurry feeding 3 50% 99.91% Shell gasifier, syngas cooling, cyclone, filter 2 50% 98.25% GE gasifier, 3 50% 99.58% Syngas cooling cooler, scrubber

97.55%

n Cap. RF.

Air Separation Unit 1 100% 98.52%

Combined Cycle

Sulfinol – acid gas removal Claus process Hydrogenation reactor and gas cooler Syngas humidification and reheat

COS hydrolysis

Water wash Gas cooling, boiler feed water and knockout Mercury removal

Gas Treatment

Shell gasifier, syngas cooling, cyclone, filter

Coal handling, conveyor Coal milling and drying Coal feeding

Gas Production

Case A – Shell IGCC (EPRI, 2007b)

Table 3.4 Results of RAM studies


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All the derived figures from Table 3.4 are the results of software aided modeling of detailed analyses of each block of the system. The blocks consist typically not only of the main devices but also controls, instrumentation, valves and piping respectively. Hence, reliability factors (RF), scheduled outage factors and equivalent availabilities are computed for each block as defined by the equations below: forced outage time Reliability factorðRFÞ ¼ 1 6100 % ½3:1 unit period time Scheduled outage factor ¼

scheduled outage time 6100 % unit period time

scheduled outage factor Equivalent availability ¼ RF6 1 100 % Availability factor ¼

½3:2

½3:3

forced outage time þ scheduled outage time 1 unit period time 6100 %

½3:4

Detailed maintenance plans allow shortening the total planned downtime to a minimum, which was assessed for cases A to C (EPRI, 2007b; Higman, 2008). As indicated above, coal gasification holds a potential for unplanned outages. For cases A and B, the averaged values for the reliability factor show that a double-train Shell gasification unit achieves 98.25 %. The same configuration for the GE gasifier would result in a lower reliability of 97.70 %, resulting from burner failures due to erosion and problems with the slag let-down system. Moreover, a design is chosen in which heavily fouling convective syngas coolers are replaced by a water quench. In order to enhance reliability a final configuration of three trains with 50 % capacity was selected for case B, exhibiting reliabilities up to 99.58 %. The gas treatment in cases A and B differs in configuration but shows high reliability values of 97.98 % in case A and 97.85 % in case B dominated mainly by the Claus process. The combined cycle is assumed to have an identical reliability of 94.91 % in both cases. Due to the higher oxygen demand of the slurry fed GE gasifier a setup with two air separation units is reasonable, improving reliability from 98.52 to 99.16 %. The total reliability factor accounts for 89.36 % for case A and 91.02 % for case B, which is equivalent to an annual downtime of 39 and 32 days respectively, if there were no scheduled outages. Defining the scheduled downtimes, the studies used optimized maintenance plans, yielding a minimum annual scheduled



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downtime of 19 days in case A and up to 20 days in case B due to burner replacements because of erosion problems. Hence, an equivalent availability can be calculated, being 84.80 % in case A and 86.12 % in case B. Regarding case C, the whole unit has a stringent single train configuration except for the coal mills. Consequently, the gas production unit has a low reliability of 96.73 %, although employing Shell gasification. Due to CO shift conversion and additional CO2 separation and CO2 compression, the gas treatment also shows a slightly decreased reliability of 97.08 %. The air separation unit and the combined cycle deploying an F-class turbine show the best achievable reported values of 99.50 and 97.87 % respectively. Since the scheduled outage factor is the same as in case A, the equivalent availability accounts for 86.77%, which is fairly high in comparison to the experience-based assessment, published in von Morstein et al. (2009) (see Table 3.4). The study carried out by Sutor et al. (2009) investigates the influence of a non-redundant and all-redundant polygeneration IGCC. It is shown that a fully redundant configuration allows an increase of availability from 85.49 % to 87.89 % by only 2.4 % pts. The simulation reveals that an additional 210 hours of operation per year lead to a steep increase of capital costs and are not favorable. This clearly shows the necessity of understanding the performance of the individual components of the system and using such analysis to ensure that redundancy is only applied where it really brings ‘value for money’.

3.9

Future trends

The 1990s generation of IGCCs in the 250–300 MWel range have paved the way for improved designs, which are inherently more reliable than these demonstration units. The lessons learned number in the thousands, covering design as well as operation and maintenance practices; some of these are sufficiently minor as to appear trivial, while others are a matter of applying best practices from other known technologies and some are at a more fundamental level. Examples of the latter include the move away from 100 % air integration by all systems builders, GE’s decision to replace the convection syngas cooler that has given so much trouble at Polk by a proven water quench design as in the Edwardsport 650 MWel unit (Rigdon and Schmoe, 2005) and Shell’s decision to replace the refractory in the slag quench area by a membrane wall in all its post-Buggenum gasifiers (Chhoa, 2005). Complex and highly integrated systems like IGCC power plants need a comparatively long time to be adjusted and to reach high availability. After start-up, refinery residues fed IGCCs have shown that they can achieve maximum availability up to 90 % in the second or third year of operation.


136


In contrast, the demonstration coal fed systems did not reach stable availability until the fourth or fifth year of operation (compare with Fig. 3.4), achieving up to 30 % in the first, up to 50 % in the second and up to 60 % in the third year depending on the duration of the compulsory main revision of the gas turbine. Given the store of lessons learned – in particular the use of best practices in areas such as the ASU, acid gas removal and combined cycle – one can expect a faster ramp-up of availability in the next generation of plants. However, one should not forget that the third year is likely to need a hot gas path inspection of the gas turbine, so that even with much improved performance in years two and three, peak availability is unlikely until the fourth year of operation. Today’s coal based IGCC plants show maximum availabilities of 82.4 % (Hornick, 2007). In contrast, some chemical plants, such as those in Kingsport and Coffeyville, achieve availabilities in the 95–98 % range on a regular basis (EPRI, 2007a). While one cannot expect such figures from an IGCC simply on the basis of necessary gas turbine inspection procedures, it does show that the ASU and acid gas removal (which in both cases include CO shift and CO2 capture) are able to support such availability. In both cases the gasifiers used are refractory lined, so that a spare gasifier is provided to allow on-stream refractory replacement. This in turn does provide a window for some preventative maintenance for a limited portion of the gasification area. Different studies (EPRI, 2007a; von Morstein et al., 2009) have been published indicating the long-term best achievable values for each unit based on manufacturer experiences (see Table 3.5). In order to describe trends towards higher stable availability of a mature IGCC plant, it is instructive to identify the longest foreseeable planned downtime, which is typically the inspection of the hot gas duct of the gas turbine. All other maintenance activities take less than these tasks and should ideally be accomplished in parallel. According to the gas turbine downtime, the advent of the F-class model in IGCC technology results not only in increased efficiency but also lower availability. (This lower availability is due at least in part to longer planned maintenance periods, which are required because of the larger physical size of the machine, number of burners, etc.) Reasonable values can be derived from natural gas fired F-class turbines exhibiting 20 to 25 days planned maintenance (5.5–6.8 %) (von Morstein et al., 2009; ORAP) and 8–11 days unplanned production loss (2.2–2.9 %) (Higman, 2005; von Morstein et al., 2009). Since there is only limited experience in adapting advanced natural gas turbines to syngas, more unplanned downtimes can be expected in the first few years. In the case of an E-class turbine, the planned downtime could be shortened to 15 days (4.3 %), being just sufficient to replace the gasifier’s refractory wall. Since all other units have shorter maintenance periods than



1.2 E-class 7.2

2.2 F-class 15.9

7.9 76.2

Planned maintenance (% p.a.) Availability

6.8 85.0

2.2 F-class 8.2

0.5 n/a Claus No

0.5 5.0 Shell/GE

EPRI prognosis

Sources: McDaniel (2008); EPRI (2007a); von Morstein et al. (2009).

4.3 88.5

0.5 n/a Claus No

1.2 MDEA Sulfuric acid No

0.5 5.0 Shell/GE

EPRI prognosis

Gas treatment AGR Sulfur recovery CO2 separation CO shift Combined cycle GT type Total unplanned downtime

3.4 9.1 GE

Polk IGCC average 2006–2008

5.5 83.7

2.9 F-class 10.8

1.7 MDEA OxyClaus No

1.3 4.9 Shell

von Morstein et al. case 1 prognosis

5.5 84.1

2.9 F-class 10.4

1.2 Flexsorb Clinsulf No

1.3 5.0 HTW


Comparison of availability experiences of Polk Power Station to several studies

Unplanned downtime (% p.a.) ASU Gas production Gasifier

Table 3.5

5.5 83.5

1.3 4.9 Dry feed entrained flow + water quench 1.9 Rectisol OxyClaus Yes Sour 2.9 F-class 11.0


5.5 83.4

1.9 Rectisol OxyClaus Yes Sour 2.9 F-class 11.0

1.3 5.0 HTW



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the gas turbine, ideally only unplanned outages account for additional losses in availability. The unplanned outage of typical ASU in the industrial gas industry is about 2 days (0.5 %) total in a year, which can be mitigated in part by liquid oxygen storage. In a worst case an unplanned de-riming cycle of about 5 days (1.3 %) may be needed. The unplanned outage to be expected from the gasification unit is more difficult to quantify. Despite applying many of the lessons learned, including many of those mentioned earlier, some malfunctions and problems must still be expected, particularly in connection with equipment involved in solids handling. Undetected fluctuations in feedstock quality are another potential source of downtime. A conservative assessment would foresee a potential for about 18 days (5.0 %) unplanned outage. This value would take credit for some small but not dramatic improvement over the performance of the demonstration units. In principle, gas treatment systems are mature technology and have high availabilities. Hence, they do not influence significantly the global availability of an IGCC plant. For the sulfur recovery a double-train strategy (2660 %) is favorable, allowing short-term partial load operation while avoiding cooling down and restarting the gasifier. Despite deployment of completely different washing processes in different studies, Table 3.5 shows expected outages of 2–6 days (0.5–1.7 %), which extends to 7 days (1.9 %) in the case of CO2 separation. Here, a comparison with the performance of the chemical plants mentioned above, which also employ different solvents (Rectisol in Kingsport and Selexol in Coffeyville) for desulfurization and include CO shift and CO2 capture, demonstrates that such values are on the conservative side. Using the above values, an overall availability of 83.7–85.0 % can be expected for a generic IGCC plant deploying an F-class turbine system. Integration of CO2 capture may reduce availabilities to about 83.5 % due to the additional CO shift reactor and CO2 compressor. The most recent demo plant at Nakoso, Japan, already demonstrates the improvements and lessons learned since the mid-1990s. Within the first year a 2000 hour continuous reliability run was achieved. During the following year a 5000 hour durability test has been performed with five minor incidents. The conclusion by the operator, Clean Coal Power R&D Co. Ltd., is that ‘Every incident could be solved, and know-how has been accumulated so that commercial plants will be realized with high reliability.’ (Watanabe, 2010).

3.10

References

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4 Environmental degradation of boiler components N . J . S I M M S , Cranfield University, UK

Abstract: During the operation of a boiler it is anticipated that there will be a range of interactions between the boiler components and their operating environments. These interactions are often classified in terms of deposition, erosion or corrosion, and can all degrade the operation of the boiler, either in terms of restricting heat transfer or reducing the potential lives of the boiler components. Understanding and modelling the mechanisms of such interactions enables their extent and effects to be reduced, e.g. by changing the operating environments or the materials used in the boilers. As a result, the efficiency of boiler operations can be improved and/or the lives of components in the boilers can be extended. This reduces the operating and maintenance costs associated with boilers and reduces the risks of costly unplanned outages. Key words: deposition, fireside corrosion, superheater corrosion, waterwall corrosion, coal, biomass, co-firing.

4.1

Introduction

The operating environments for components within power plants are a result of the fuels used, the power plant design and the component operating conditions. Most current large scale power plants contain a steam generating system that drives a steam turbine, either on its own (a Rankine cycle) or in combination with a gas turbine (as part of a combined cycle). For heat recovery steam generators located downstream from gas turbines in combined cycles, the environments are usually relatively benign as their gas stream inlet temperatures are generally limited by the gas turbine exhaust temperatures and the contaminant levels in these gases are low (to meet the strict limits placed on gas turbine operating conditions). However, power systems that rely entirely on heat exchange from a hot gas stream to a water/steam system can have much more aggressive environments around 145 © Woodhead Publishing Limited, 2011

146


the fireside surfaces in their hot gas paths. In such systems, the hot gas streams can be produced by the combustion of a wide variety of fuels (solid, liquid or gaseous), which can contain a range of different impurities. As these hot combusted gas streams pass through the boilers and the various heat exchange surfaces, as well as transferring heat to the water/steam system they can interact to produce deposition, erosion and/or corrosion on the heat exchanger surfaces. Both corrosion and erosion damage to the fireside surfaces of the heat exchangers cause metal losses and so reduce component lives (though there is often a ‘corrosion allowance’ to enable design lives to be achieved). In order to avoid unexpected tube failures, which can result in costly plant outages, significant effort is devoted to non-destructive examinations of heat exchanger tubes during routine plant outages so that any affected tubing can be identified and replaced. The replacement tubing can be the same (if the component life is acceptable), or a better material may be used (if one exists), or protective measures may be required (such as coatings, coextruded tubes, bandages, etc.). Alternatively, the boiler operating conditions could be changed to reduce the damage rates or the compositions of the fuels used in the boiler restricted. Deposit formation usually has the effect of reducing heat transfer from the hot gas stream to the water/steam system, which in turn reduces boiler efficiency. In addition, such deposits are involved in some of the corrosion damage mechanisms that have been found in boiler environments (section 4.3). As a result, a range of techniques have been developed to try to remove deposits from the surfaces of heat exchangers during operations or periods of maintenance, including: mechanically hitting the tube surfaces; sootblowing using compressed air, steam or water jets; sonic waves; explosive charges; etc. This chapter describes the operating environments that are encountered in selected heat exchangers in solid-fuel-fired boilers. The complex mechanisms that govern the environmentally induced degradation of these components are outlined, together with available models of these processes. These environments and degradation processes can change during the life of a power plant as a result of alterations in the fuels used and/or operating conditions. Monitoring of the degradation of boiler tubes is described, together with preventative measures. Finally, the anticipated challenges in environmental degradation of boiler tubes is considered in terms of likely future developments for solid-fuel-fired power plants.


Environmental degradation of boiler components

4.2

147

Component operating environments

4.2.1 Superheaters/reheaters/waterwalls, etc. The hot gas paths of combustion systems contain a series of heat exchangers to generate high temperature/high pressure steam from water. Figure 4.1 shows a flow diagram for a typical water/steam system, with the series of heat exchangers being an economiser, evaporator and superheater before the steam enters the high pressure steam turbine. In this system, the steam is reheated before entering the intermediate pressure steam turbine. The highest steam temperatures in such a system are achieved in the final stages of the superheater and reheater. Figure 4.2 illustrates the layout of these heat exchangers around a conventional pulverised-fuel fired combustion power plant; this shows that the combustion zone is surrounded by waterwalls and that the hot gases from the combustion process then flow past the various superheater and reheater stages before going through the economiser. In such a system, the waterwalls are relatively cool (up to 400 8C) despite containing the fuel burners and gases of up to 1600 8C, but have high heat fluxes (up to ~0.4 MW/m2). The combustion gases have cooled to 1000–1200 8C by the time they pass through the superheaters and produce heat fluxes of ~0.2 MW/m2; the steam temperatures exiting the superheaters can be ~540– 620 8C depending on the age of the power plant. The combustion gases continue cooling through the superheaters, reheaters and economisers. The

4.1 Schematic flow diagram for a power plant steam/water system showing the main component parts.


148


4.2 Schematic diagram of a pulverised fuel power plant showing the position of the main heat exchangers.

final stage of the reheaters is at similar steam and metal temperatures (but lower pressures) compared to the superheaters. Figure 4.3 shows a different power plant configuration based on a circulating fluidised bed combustion process, with this example being used to generate heat and power from biomass combustion (Henderson et al., 2002b). In this system, the combustion chamber is again surrounded by waterwalls, but superheaters are located in the gas pass after the cyclone. The flue gas temperature approaching the superheaters is ~860–880 8C. The steam system operates with the final superheater output at 480 8C/80 bars. Figure 4.4 shows a power plant configuration based on a grate-fired boiler, with this example based on a waste to energy process (Henderson et al., 2002a). In this system the combustion gases initially pass through a chamber surrounded by waterwalls, but the superheaters are located in the third gas pass to overcome environmental degradation issues associated with such fuels (section 4.3.3). In this system, these issues limit superheated steam temperatures to 360 8C (with pressures of ~ 33 bars) and such low steam conditions restrict the efficiencies of this type of power plant.



149

4.3 Schematic diagram of a circulating fluidised bed (CFBC) biomassfired unit (adapted from Henderson et al., 2002b).

4.4 Schematic diagram of a waste-fired grate unit (adapted from Henderson et al., 2002a).


150


Table 4.1

Example solid fuel compositions

Parameter Unit

UK coal

South South American African Wheat Palm Olive coal coal Willow Miscanthus straw nuts residue

Moisture

11.9

13.0

9.1

15.3

9.0

15.2

2.0

4.0

5.0

7.5

4.5

34.3 32.8 81.6 5.2 8.7 1.8 2.28 0.7

32.7 31.1 79.9 5.3 12.21 1.7 0.8 0.1

33.2 31.9 83.2 4.3 9.6 2.0 0.7 0.1

20.3 18.8 49 6.2 44 0.5 0.05 0.03

19.8 18.4 49 6.4 44 0.7 0.2 0.2

19.8 18.5 49 6.3 43 0.5 0.1 0.4

19.8 18.3 50.2 6.6 40 3.2 0.2 0.2

21.4 18.3 49 6.0 40 2.24 0.1 0.1

wt% ar Ash wt% dry CV (gross) MJ/kg CV (net) daf C wt% H daf O N S Cl

15

25

25

4.6 13.5

Source: Simms et al. (2007a).

4.2.2 Fuel effects A range of solid fuels can be combusted in boilers to provide the heat required, for example: . . .

coals, typically bituminous, sub-bituminous or lignite coals depending on the availability and cost of local and world-traded coals; biomass, traditionally residual agricultural by-products, but increasingly energy crops; waste products, derived from municipal solid wastes, sludges, etc.

These three general classes of solid fuels are described in detail in Chapter 1 of this book, which also describes the appropriate analytical methods for each of the fuels together with the characteristic properties of each type of fuel. Within boilers, the environments around the heat exchangers depend on the chemical compositions of the fuels used, as well as the operating conditions used in the boilers. Table 4.1 provides examples of each of these types of fuels in terms of their chemical composition. During the combustion processes, the fuels react with an oxidising gas stream, which is air in most current combustion plants, to produce a hot combusted gas stream. Figure 4.5 (Tomeczek and Palugniok, 2002) illustrates this process for pulverised coal combustion and shows the breakdown of the fuel in terms of the burnout of the combustible material and generation of ash particles and vapour phase species. As a result of the complex reactions of the inorganic elements present in the fuels in various different forms (Chapter 1), the minor and trace elements are partitioned between the coarse (bottom) ash, fly ash and gas/vapour phase. It is the fate


4.5

Schematic representation of fuel combustion (adapted from Tomeczek and Palugniok, 2002).



151

152


of these elements as they pass through the hot gas path of the power systems that is in a large part responsible for the environmental degradation of the heat exchangers. The particles produced can form deposits (section 4.3.1) or cause erosion damage (section 4.3.4); the vapour phase species can condense under particular conditions to become part of the deposits (section 4.3.1); the gases, deposits and heat exchanger surfaces can react to cause accelerated corrosion damage (section 4.3.3).

4.3

Degradation mechanisms and modelling

4.3.1 Deposition The deposits that form around the fireside surfaces of heat exchanger tubes are created from the particles and vapours that pass through a boiler by the action of a number of different mechanisms that can occur in parallel in the local environments, as shown in Fig. 4.6 (Simms et al., 2007b). For particles, the important potential deposition mechanisms are:

4.6 Schematic representation of interaction between superheater tube and its local environment (Simms et al., 2007b).


Environmental degradation of boiler components . . .

153

direct inertial impaction: for larger particles, typically >10 μm on the upstream tube surfaces; thermophoresis: for smaller particles, typically

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