Advances in Power Boilers 0128203609, 9780128203606

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Advances in Power Boilers

JSME Series in Thermal and Nuclear Power Generation

Advances in Power Boilers Edited by

Mamoru Ozawa Faculty of Societal Safety Sciences, Kansai University, Osaka, Japan

Hitoshi Asano Kobe University, Kobe, Japan Series Editor

Yasuo Koizumi The University of Electro-Communications, Chofu, Tokyo, Japan

Elsevier Radarweg 29, PO Box 211, 1000 AE Amsterdam, Netherlands The Boulevard, Langford Lane, Kidlington, Oxford OX5 1GB, United Kingdom 50 Hampshire Street, 5th Floor, Cambridge, MA 02139, United States Copyright © 2021 Elsevier Inc. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the publisher. Details on how to seek permission, further information about the Publisher’s permissions policies and our arrangements with organizations such as the Copyright Clearance Center and the Copyright Licensing Agency, can be found at our website: www.elsevier.com/permissions. This book and the individual contributions contained in it are protected under copyright by the Publisher (other than as may be noted herein). Notices Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary. Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility. To the fullest extent of the law, neither the Publisher nor the authors, contributors, or editors, assume any liability for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions, or ideas contained in the material herein. British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress ISBN: 978-0-12-820360-6 For Information on all Elsevier publications visit our website at https://www.elsevier.com/books-and-journals

Publisher: Candice Janco Acquisitions Editor: Maria Convey Editorial Project Manager: Sara Valentino Production Project Manager: Prasanna Kalyanaraman Cover Designer: Alan Studholme Typeset by MPS Limited, Chennai, India

Contents

List of contributors About the editors Preface of JSME Series in Thermal and Nuclear Power Generation Preface to Volume 2: Advances in Power Boilers

1

2

3

Fossil fuels combustion and environmental issues Jun Inumaru, Takeharu Hasegawa, Hiromi Shirai, Hiroyuki Nishida, Naoki Noda and Seiichi Ohyama 1.1 Introduction 1.2 Overview and properties of coal, oil, and gas 1.3 Combustion of fuels 1.4 Emission-induced environmental issues and protection 1.5 Remarks Nomenclature References Introduction to boilers Mamoru Ozawa 2.1 Start of steam application to pumping water 2.2 Dawn of steam power 2.3 Classification of boilers 2.4 History of boiler development 2.5 Historical development of power generation boilers in Japan 2.6 Similarity law in boiler furnace and other various important issues References General planning of thermal power plant Atsuhiro Hanatani and Mamoru Ozawa 3.1 Overview of steam power plant 3.2 Concept of general planning and factors to be considered 3.3 Principal concept for high-performance plant 3.4 Reheat cycle and regenerative cycle 3.5 Enthalpy pressure diagram along steam generating tube 3.6 Legal regulations in Japan References

ix xi xiii xvii

1

1 4 16 36 49 50 51 57 57 59 61 61 99 99 103 107 107 109 110 113 116 117 118

vi

4

5

6

7

8

Contents

Power boiler design Masashi Hishida, Kenjiro Yamamoto, Kenichiro Kosaka, Wakako Shimohira, Kazuaki Miyake, Senichi Tsubakizaki, Sachiko Shigemasa and Hitoshi Asano 4.1 Heat transfer in boiler 4.2 Boiler gas side performance for furnace design 4.3 Water circulation design 4.4 Deposition, erosion and corrosion, and water treatment References

119

120 125 194 240 252

Construction, operation, and control of power boiler Michio Sasaki, Shingo Naito and Akira Yamada 5.1 Construction of coal-fired boiler 5.2 Operation and control of power boiler Nomenclature References

257

Gas turbine combined cycle Shigehiro Shiozaki, Takashi Fujii, Kazuhiro Takenaga, Mamoru Ozawa and Akira Yamada 6.1 Gas turbine combined cycle power generation 6.2 Pressurized fluidized-bed combustion boiler 6.3 Integrated coal-gasification combined cycle References

305

257 262 302 302

305 325 326 343

Ultrasupercritical and advanced ultrasupercritical power plants Kenjiro Yamamoto, Masafumi Fukuda and Atsuhiro Hanatani 7.1 Introduction 7.2 Efficiency improvement 7.3 History of elevating steam condition in the world 7.4 Development programs for ultrasupercritical and advanced ultrasupercritical power plants in the world 7.5 Aspects of metallurgy and stress analysis 7.6 Concluding remarks References

345

Examples of thermal power station Takatoshi Yamashita, Shigehiro Shiozaki, Shingo Naito, Takashi Fujii, Mamoru Ozawa and Akira Yamada 8.1 Tachibana-Wan Thermal Power Station Unit No. 2 (ultrasupercritical, sliding pressure, once-through boiler) 8.2 Himeji No. 2 Power Plant (gas turbine combined-cycle plant) 8.3 Karita PFBC plant 8.4 Nakoso and Osaki Integrated Coal Gasification Combined Cycle (IGCC) Plants

391

345 346 352 356 370 384 386

391 400 406 410

Contents

9

10

vii

8.5 Incineration firing by circulating fluidized bed References

422 424

Boiler explosion and inspection Mamoru Ozawa, Mikiyasu Urata and Masaki Honda 9.1 Historical trend of boiler explosions 9.2 Legislative framework 9.3 Development in boiler code and inspection organization in the United States and Germany 9.4 Historical development of boiler regulation in Japan 9.5 Outline of current inspection of power boiler References

427

Future perspective and remarks Jun Inumaru, Saburo Hara and Takeharu Hasegawa 10.1 Introduction 10.2 Situation of thermal power generation 10.3 Next-generation thermal power generation technology for a decarbonized society (B2030) 10.4 Future outlook for thermal power generation (2030B) 10.5 Conclusion References

Index

427 433 439 441 443 458 461 461 462 464 472 477 478 479

List of contributors

Hitoshi Asano Kobe University, Kobe, Japan Takashi Fujii Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Masafumi Fukuda Research Institute for Advanced Thermal Power Systems, Tokyo, Japan Atsuhiro Hanatani IHI Corporation, Tokyo, Japan Saburo Hara Central Research Institute of Electric Power Industry, Tokyo, Japan Takeharu Hasegawa Central Research Institute of Electric Power Industry, Tokyo, Japan Masashi Hishida Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Masaki Honda Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Jun Inumaru Central Research Institute of Electric Power Industry, Tokyo, Japan Kenichiro Kosaka Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Kazuaki Miyake Mitsubishi Hitachi Power Systems Environmental Solutions, Ltd., Yokohama, Japan Shingo Naito Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Hiroyuki Nishida Central Research Institute of Electric Power Industry, Tokyo, Japan Naoki Noda Central Research Institute of Electric Power Industry, Tokyo, Japan Seiichi Ohyama Central Research Institute of Electric Power Industry, Tokyo, Japan Mamoru Ozawa Kansai University, Osaka, Japan

x

List of contributors

Michio Sasaki Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Sachiko Shigemasa Hitachi Zosen Corporation, Osaka, Japan Wakako Shimohira Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Shigehiro Shiozaki Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Hiromi Shirai Central Research Institute of Electric Power Industry, Tokyo, Japan Kazuhiro Takenaga Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Senichi Tsubakizaki Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Mikiyasu Urata Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Akira Yamada Mitsubishi Heavy Industries, Ltd., Nagasaki, Japan Kenjiro Yamamoto Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan Takatoshi Yamashita Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan

About the editors

Mamoru Ozawa is a professor emeritus and a senior researcher of Research Center for Societal Safety Sciences, Kansai University, Japan. He received his doctoral degree from Osaka University in 1977. His research interests include boiling heat transfer, two-phase flow dynamics, combustion system, boiler, and safety in industrial systems. He has authored and coauthored more than 150 refereed journals, more than 150 conference papers, several handbooks, and many books related to thermal hydraulics in steam power. Among his edited books the most recently published Science of Societal Safety has been chapter-downloaded more than 70,000 times. He served the Board of Directors and the President of Heat Transfer Society of Japan and the Chairman of the Power and Energy Systems Division of the Japan Society of Mechanical Engineers (JSME). He was awarded several times from the Visualization Society of Japan, the Heat Transfer Society of Japan, and the JSME. Hitoshi Asano is a professor of the Department of Mechanical Engineering, Kobe University, Japan. He received his doctoral degree from the Kobe University in 2000. His research interests include boiling and condensation heat transfer, two-phase flow dynamics in energy conversion systems, compact heat exchangers for HVAC systems, and two-phase flow cooling systems for electric and power equipment. He has authored and coauthored more than 100 refereed journals and more than 130 conference papers. He is a member of the Scientific Council of International Center for Heat and Mass Transfer and is a fellow of the JSME. He received the Asian Academic Award from the Japan Society of Refrigeration and Air-Conditioning Engineers, the Society of Air-Conditioning and Refrigerating Engineers of Korea, and the Chinese Association of Refrigeration in 2018.

Preface of JSME Series in Thermal and Nuclear Power Generation

Electric power supply is a fundamental and principal infrastructure for modern society. Modern society uses power generation through heat. This series of books consists of eight volumes describing thermal and nuclear power generation, taking Japan as the example, and referring the other countries. The Volume 1 discusses how power supply is attained historically, focusing on the thermal and the nuclear power generation along with minimum-required scientific and technological fundamentals to understand this series of books. Then, the present status of the thermal and the nuclear power generation technique is displayed in detail in Volumes 2 through 8. The rehabilitation and reconstruction of Japan after World War II was initiated through the utilization of a large amount of coal for boilers of the thermal power plants. Meanwhile, environmental pollution caused by coal combustion became serious, and then oil was introduced to the boilers. Due to two worldwide oil crises and because of carbon dioxide issues, natural gas has also begun to be used for boilers. Current thermal power generation in Japan is based on coal and gas utilization. As a result of enough power supply, Japan has become one of the leading countries economically and technologically in the world. The thermal power technology that started from introducing technology from abroad has been transfigured Japan into one of the most advanced in the world through the research and development of Japanese industry, government, and academia during this process. Global warming related to excess carbon dioxide emissions has become a worldwide issue in recent years. Reducing carbon dioxide emission in thermal power generation is important to help cope with this issue. One direction is to change the fuel of a boiler from coal to gas that exhausts less carbon dioxide. Another important direction is to endeavor to enhance the thermal efficiency of coal thermal power plants as well as oil and gas. Many developing countries in the world need more thermal power plants in future. Although oil and/or gas thermal power plants may be introduced into these countries, it is supposed that coal thermal power plants will still be used due to economical reasons. Considering these situations, the publication of this series of books that displays and explains the developing history and the present status of the most advanced thermal power plants in Japan and other advanced countries is a timely planning for engineers and researchers in the advanced countries to pursue the further advancement and for engineers and researchers in developing countries to learn and acquire this knowledge.

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Preface of JSME Series in Thermal and Nuclear Power Generation

Nuclear power generation technology in Japan started after being introduced from abroad approximately 60 years ago. Then, it reached the matured nuclear power technology through untiring endeavors for research and development. However, nuclear power plants at the Fukushima Daiichi nuclear power station were heavily damaged by huge tsunamis caused by the Great East Japan Earthquake in 2011 to result in contamination in the large area around the power station. Taking measures to improve nuclear power reactors to be more robustly is currently underway by analyzing the factors that caused this serious situation. Technical vulnerability can be solved by technology. Nuclear power generation technology is one of the definite promising technologies that should be used in the future. The nuclear power generation is still expected as one of the main ways to supply electricity in the framework of the basic energy plan of Japan as well as thermal power generation. It implies that the construction of new power reactors will be required to replace the nuclear reactors that will reach their useful lifetime. Looking overseas, many developing countries are introducing nuclear power generation technology as a safe and economically excellent way to obtain electricity. Transfer of the nuclear power generation technology developed and matured in Japan to those countries is naturally the obligation of Japan. In these situations, the necessity of human resource development in the field of nuclear power generation technology in the developing countries, as well as in Japan, is beyond dispute. Thus, it is an urgent task to summarize the nuclear power generation technology acquired by Japan to provide it. The Power and Energy Systems Division (PESD) of the Japan Society of Mechanical Engineers is celebrating its 30th anniversary from establishment in 1990. This department is entrusted with handling power supply technology in mechanical engineering. Responding to the earlier-mentioned is truly requested. This task cannot be done by others but the PESD that is composed of leading engineers and researchers in this field in Japan. In view of these circumstances, summarizing Japan’s and other countries’ power generation technology and disseminating it not only in Japan but also overseas seems significantly important. So, it has been decided to execute this book series, publishing as one of the 30th anniversary events of the PESD. Authors of this book series are those who have engaged in the most advanced research and development for the thermal power and nuclear power generation in Japan and Canada. Their experience and knowledge is reflected in their writing. It is not an introduction of what others did, but living knowledge based on their own experiences and thoughts are described. We hope that this series of books becomes learning material that is not yet in existence in this field. We hope that readers acquire a way of thinking as well as whole and detailed knowledge by having this book series in hand. This series is the joint effort of many individuals, generously sharing and writing from their expertise. Their efforts are deeply appreciated. We are very thankful for

Preface of JSME Series in Thermal and Nuclear Power Generation

xv

the unbiased and heartful comments given from many reviewers to make this series superb. Special thanks should be given to Maria Convey and Sara Valentino of the editorial staff at Elsevier.

Editors in Chief Yasuo Koizumi The University of Electro-Communications, Chofu, Tokyo, Japan Mamoru Ozawa Kansai University, Takatsuki, Osaka, Japan March 16, 2020

Preface to Volume 2: Advances in Power Boilers

Steam power has been constantly at the leading position of industrial technologies since the beginning of the 18th century. At the first stage, steam power appeared as the prime mover for the pumping system of coal mines. The advancement in steam power engineering made it possible to lead the factory systems for the mass production of textile products. The availability of steam engines extended their application to steamboats and locomotives for the mass transportation of people and industrial products. Such advancement is supported by the development of iron and steel technology, machine tool, control engineering, and, of course, by society and its economy. Following the development in electrical technology, steam power stations were constructed, and since then the electrical network thus has been the fundamental and principal infrastructure of the society. The development in steam power since the 18th century has been, in fact, dependent on the development in boiler technology during this 300-year period. A drastic increase in efficiency and unit output has been supported by the development in thermo-hydraulic engineering, materials engineering, control engineering, and of course chemical engineering while the development process was not straightforward. An increase in the unit power brought about many explosions together with a tremendous number of fatalities. To reduce and mitigate losses from explosions, a social system, that is, third-party inspection and regulations, has been introduced. In reality, the boiler development was a battle with explosions. A boiler is a system to generate steam by firing coal, oil, gas, and recently incineration. At the beginning, coal was a prime fuel, which continued to the 1950s for about 250 years. During this period, various coal-treatment technologies have been developed to raise efficiency and reduce the emission of smoke. Ash treatment was also a very important task. Oil was introduced to boilers, so efficiency issue and ash problems were in part resolved, while the mass consumption of oil for power generation brought about unstable oil prices due to economic and political situations. Especially Japan got involved in the oil-crisis in 1973 and 1979. This oil-crisis introduced natural gas firing and enhanced the construction of nuclear power plants. Nuclear power stations constructed in Japan counted 54 units, while they drastically reduced in number after the core meltdown in the Fukushima Daiichi power station. Since then, the economy and social welfare in Japan have been supported by the fossil-fuel firing power stations, that is, steam boilers. Such a situation is not just a

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Preface to Volume 2: Advances in Power Boilers

problem in Japan but rather universal in many developing countries. The importance of steam boiler technologies is still a prime issue. This volume is intended to present a state-of-the-art review of power boiler technology to help practical engineers and graduate student to build basic frameworks of ideas with which they can understand and treat practical problems of power boilers. Basic principles together with the practical state-of-the-art are described by the specialists of boiler companies in Japan. As the way of approach to boiler technology is not the same among university researchers, research institute members, and engineers in industries, the editorial board members and authors held many discussions in the course of writing manuscripts, so that the philosophy or common principal view on the power boilers and related technologies would remain consistent throughout this book while respecting the autonomy of each author. We would be grateful if the essence of our experience in boiler technologies is shared by the careful readers. The editors are deeply indebted to editorial board members, Akira Yamada, Atsuhiro Hanatani, Jun Inumaru and Toshihiko Yasuda for their valuable suggestions in planning and editing processes of this book, and thanks are extended to all the authors of the Central Research Institute of Electric Power Industry, Mitsubishi Heavy Industries, Ltd., Mitsubishi Hitachi Power Systems, Ltd., IHI Corporation, Research Institute for Advanced Thermal Power Systems, and Hitachi Zosen Corporation. The editors are also grateful to Elsevier Inc. for allowing publication and to Editorial Project Manager, Sara Valentino and Project Manager, Prasanna Kalyanaraman for their editorial works of this volume. Without their contribution, this volume could not have survived from the bustle of the ongoing pandemic of coronavirus disease 2019.

April 2020 Mamoru Ozawa Hitoshi Asano

Fossil fuels combustion and environmental issues

1

Jun Inumaru, Takeharu Hasegawa, Hiromi Shirai, Hiroyuki Nishida, Naoki Noda and Seiichi Ohyama Central Research Institute of Electric Power Industry, Tokyo, Japan

Chapter outline 1.1 Introduction 1 1.2 Overview and properties of coal, oil, and gas

4

1.2.1 Coal 4 1.2.2 Oil 5 1.2.3 Gas 12

1.3 Combustion of fuels

16

1.3.1 Coal 16 1.3.2 Oil 23 1.3.3 Gas 27

1.4 Emission-induced environmental issues and protection 36 1.4.1 Flue gas treatment technology 36 1.4.2 Wastewater treatment 45

1.5 Remarks 49 Nomenclature 50 Notations 50 Greek letters 51 Subscripts 51

References

1.1

51

Introduction

Coal, oil, and gas are mainly used as fossil fuels for power generation. Fig. 1.1 [1] shows shifts in global primary energy consumption by energy source. The global primary energy consumption has been increasing in line with economic growth, and oil is the highest in terms of consumption, followed by coal and then gas. The increase in oil is mainly due to its use as transport fuel. For the purpose of power generation, attempts are being made to substitute other energy sources for oil. Coal is widely distributed around the world, and about 60% of coal consumption goes toward power generation as a relatively cheap fuel. The consumption of coal had been increasing year on year, but after peaking in 2013, it is more or less on the decrease these days. This is due to the recent consumption decrease in China, which had long been driving the increase in consumption. Gas fuel trends are detailed in Section 1.2.3. Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00001-1 © 2021 Elsevier Inc. All rights reserved.

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Advances in Power Boilers

Figure 1.1 Transition of primary energy consumption in the world (by energy source) [1]. Note: Figures may not add up to the totals due to rounding. Mtoe: Million tons of oil equivalent

Figure 1.2 Power generation cost of each power source in Japan (in 2014) [2].

The matters to be considered in using these resources for power generation are the stable procurement of fuel, power generation costs, including fuel cost, and environmental characteristics such as emissions of carbon dioxide, nitrogen oxides, sulfur oxides, and particulate matter. As a reference, Fig. 1.2 [2] shows the power generation cost by fuel in Japan. The cheapest fuel is coal, followed by natural gas and oil. Fig. 1.3 [3] shows the life cycle CO2 emissions in Japan by power source. This takes into account not only the carbon dioxide from fuel combustion but also that produced in the operation of fuel development drilling, transportation, and power generation facilities. As for life cycle CO2 emissions, coal is the highest, followed by oil and natural gas. When using fossils fuel in power generation boilers, it is important to select appropriate methods for fuel supply, operation, and maintenance with an understanding of the specific characteristics of these fuels. In this section, we describe

Fossil fuels combustion and environmental issues

3

Figure 1.3 CO2 emissions intensity over the entire life cycle by source [3].

the environmental characteristics of coal, oil, and gas from the viewpoint of power generation fuel, including the characteristics of fuels, combustion characteristics, and emission gas and wastewater, as well as technological development issues.

4

1.2

Advances in Power Boilers

Overview and properties of coal, oil, and gas

1.2.1 Coal The estimated amount of coal deposits is much higher than those of other fossil fuels. Furthermore, coal is produced worldwide, and its price per calorific value is the cheapest among the fossil fuels. Therefore coal is the most commonly used fuel for thermal power generation in the world. However, its CO2 emission per calorific value is the largest among the fossil fuels. In recent years, there has been sustained worldwide effort to reduce CO2 emission from coal. In this chapter, we deal with the characteristics of coal.

1.2.1.1 Formation Coal is a combustible rock that is formed from decayed plants in the earth. The underground heat and pressure cause the coalification of decayed plants, which involves the loss of water, methane, and carbon dioxide from plants and an increase in the proportion of carbon. As the coalification progresses, lignite (brown coal), followed by subbituminous coal, bituminous coal, and finally anthracite, is formed. Lignite and subbituminous coal, which have high water contents, are used to generate steam and electric power. Bituminous coal is used to not only generate steam and electric power but also produce coke. Anthracite has a high carbon content and burns with a smokeless flame, but it ignites with difficulty. Therefore it is used as an ingredient of charcoal briquettes and filter media.

1.2.1.2 Classification Coal consists of organic matter, minerals, and moisture. Organic matter contains mostly carbon, hydrogen, oxygen, and a small amount of sulfur and nitrogen. Coal has a wide range of properties, because the types of plant, the degree of coalification, and the conditions of coalification vary in different locations around the world. Therefore it is important to logically classify into different types for its optimal utilization. In Japan, coal is classified on the basis of the calorific value, fuel ratio (the weight ratio of fixed carbon to volatile matter), and agglomerating character, as shown in Table 1.1 [4,5]. In the United States, it is classified on the basis of the content of fixed carbon, that of volatile matter, and the agglomerating character, as shown in Table 1.2 [5,6]. The calorific value and fuel ratio are important values in selecting the type of coal appropriate for use in a boiler, and the agglomerating character is an important value in selecting the type of coal for producing a coke, which is used for iron manufacture. The coal used in a boiler is called thermal coal or steam coal, and that for iron manufacture is called coking coal or metallurgical coal.

1.2.1.3 Properties In the field of coal combustion the important combustion properties of coal are determined by proximate and ultimate analyses [7,8], namely, calorific value [9],

Fossil fuels combustion and environmental issues

5

Table 1.1 Classification of coal in Japan [4,5]. Classification

Calorific value (dry ash-free basis) (MJ/kg)

Fuel ratio

Agglomerating character




4.0 ,

Nonagglomerating

35.16 #

Highly agglomerating Agglomerating Weakly agglomerating Nonagglomerating Nonagglomerating

Class

Group

Anthracite (A)

A1 A2 B1 B2 C D

33.910 # 32.650 #

,35.160 ,33.910

1.5 # ,1.5



E F1 F2

30.560 # 29.470 # 24.280 #

,32.650 ,30.560 ,29.470






Bituminous (B, C)

Subbituminous (D, E)

Lignite (F)

coal ash composition [10], ash fusibility [11], and grindability [11]. The composition of maceral (Fig. 1.4 [12]), which is a component from coalified plants that remains preserved in coal, is also fundamental to the combustion properties, since different maceral types (inertinite, vitrinite, and liptinite) combust at different temperatures and rates. In the proximate analysis the contents of moisture, ash, and volatile matter of coal dried in air are measured, and the content of the remaining part is calculated as the content of fixed carbon. In the ultimate analysis the contents of carbon, hydrogen, oxygen, total sulfur, combustible sulfur, and nitrogen are measured. The results of proximate and ultimate analyses in various coals are shown in Table 1.3 [5]. As coalification progresses, moisture and volatile matter decrease, and the calorific value and carbon content increase. The contents of sulfur and nitrogen are independent of coalification because they depend on the type of decayed plants present and the sediment that covered and buried the plants.

1.2.2 Oil In power plants in Japan, light oils, such as kerosene and diesel, are used for gas turbines. Heavy oils, the prices of which are relatively cheap compared to kerosene and diesel, are used for boilers. The quality requirements by the Japanese Industrial Standards (JIS) for kerosene, diesel, and fuel oil (heavier oils such as banker oil, marine fuel oil, and marine residual oil) are shown in Table 1.4 [13], Table 1.5 [14], and Table 1.6 [15], respectively. These standards are established mostly based on flash point, viscosity, and sulfur content. In addition to the physical properties for proper combustion, important aspects of fuel use in power plants include the presence of corrosive materials that can damage the local structure and contaminated matter that yields pollutants in the fumes. Regarding corrosive materials, trace amounts of alkali metals, such as sodium and potassium, produce detrimental impacts on the gas turbine. And

Table 1.2 Classification of coal in the United States [5,6]. Class

Group

I. Anthracitic

1. Metaanthracite

II. Bituminous

2. 3. 1. 2.

Anthracite Semianthracite Low-volatile bituminous coal Medium-volatile bituminous coal

Fixed carbon limits % (dry ash-free basis)

Volatile matter limits % (dry ashfree basis)

98 #

,2

92 # 86 # 78 # 69 #

III. Subbituminous

IV. Lignite

High-volatile B bituminous coal High-volatile C bituminous coal High-volatile C bituminous coal Subbituminous A coal Subbituminous B coal Subbituminous C coal Lignite A

2. Lignite B

2# 8# 14 # 22 #

, 69

3. High-volatile A bituminous coal 4. 5. 6. 1. 2. 3. 1.

,98 ,92 ,86 ,78

,8 ,14 ,22 ,31

31 ,

Calorific value limits MJ/kg (moist free basis)

Agglomerating character







Nonagglomerating













Commonly agglomerating

32.557 #

















































30.232 # 26.743 # 24.418 # 24.418 # 22.090 # 19.300 # 14.650 #

,32.557 ,30.232 ,26.743 ,26.743 ,24.418 ,22.09 ,19.3

, 14.65

Agglomerating Nonagglomerating

Nonagglomerating

Fossil fuels combustion and environmental issues

7

Figure 1.4 Maceral types consisting of liptinite and vitrinite Reproduced by permission from R. M. Flores, Coal and Coalbed Gas, Elsevier (2014),[12].

vanadium can also cause “vanadium attack” [16]. The sulfur content, which causes sulfidation corrosion, also negatively impacts the boiler (fuels with sulfur are never applicable to gas turbines). The causative agents of pollutants in the fumes are nitrogen, which produces nitrogen oxides (NOx), and sulfur, which produces PM2.5 (fine particulate matter) and sulfur dioxide (SOx). Due to the exceptional circumstances brought by SOx on the Yokkaichi asthma [17] during one of the “Four Big Pollution Diseases of Japan” in 1960s
1970s, the desulfurizer or use of low-sulfur crude oil, which is expensive but avoids petroleum refinery costs, became indispensable in Japan. Although the nitrogen content in the fuel causes NOx emissions, which is as harmful as SOx because NOx causes photochemical smog, there are no regulations of quality requirements for nitrogen emissions. This is partly because not all nitrogen content is converted into NOx, which is different for SOx, since all sulfur contents are converted into SOx. The constructions of new oil-fired thermal power plants are prohibited in Japan, based on the communique adopted by the International Energy Agency (IEA) governing board meeting at ministerial level in May 1979, the “Principles for IEA Action on Coal” [18]. Therefore both installed capacity of electric power and amount of electricity power generation for oil-fired power plants started decreasing with each passing year after the 1980s, as seen in Fig. 1.5 [19] and Fig. 1.6 [20]. However, some new oil-fired gas turbines were exceptionally introduced after the Great East Japan Earthquake of 2011. This is also one of the causes of oil being expensive compared with other fuels, such as coal and natural gas, as shown in Fig. 1.7 [21]. Refineries in Japan also pursued scrap-and-build designs of refinery capacity and “a shift toward white oil” (cleaner oils such as gasoline and naphtha) by improving the performance of reformers of heavy distillates and residues and following the

Table 1.3 Coal properties[5 Country

Coal

Item Calorific value (MJ/kg)

Australia

China Canada Indonesia South Africa The United States

Total moisture (%)

Proximate analysis (%)

Moisture

Ash

Volatile

Fixed carbon

Fuel ratio

Ultimate analysis (%)

Carbon

Hydrogen

Nitrogen

Oxygen

Sulfur

Total sulfur

Drayton Newlands Hunter Valley Lemington Warkworth Datong Nantong Obedarsh Coal Valley Satui Ermelo Optimum Pinacle

28.4 28.0 29.6 28.4 28.9 29.6 28.4 25.3 26.1 28.8 27.8 28.5 27.2

9.9 8.4 8.0 9.9 9.6 10.1 8.0 8.0 11.3 9.5 7.6 8.2 8.3

3.4 3.0 3.5 3.7 3.6 5.1 4.0 5.0 6.4 5.1 3.5 3.8 4.6

13.3 15.0 11.2 13.0 11.8 7.0 16.0 14.0 10.7 7.9 12.9 10.7 13.4

34.5 26.6 34.0 32.3 32.8 28.1 36.2 37.0 33.5 41.9 31.4 32.4 40.9

48.8 55.4 51.3 51.0 51.8 59.8 43.8 44.0 49.3 45.1 52.2 53.1 41.1

1.4 2.1 1.5 1.6 1.6 2.1 1.2 1.2 1.5 1.1 1.7 1.6 1.0

71.1 69.1 72.7 71.9 69.1 78.2 83.0 64.3 69.7 72.4 72.0 72.9 68.2

4.9 4.1 4.5 4.5 4.6 4.5 5.2 4.6 4.7 5.5 4.4 4.9 5.6

1.4 1.4 1.6 1.5 1.5 0.8 1.6 1.5 0.9 1.2 1.7 1.6 1.4

8.1 7.0 9.3 8.2 8.9 8.8 9.8 14.3 13.1 11.9 7.9 9.1 0.3

0.8 0.4 0.3 0.4 0.4 0.6 0.5 0.3 0.1 0.7 0.6 0.5 0.6

0.9 0.4 0.6 0.4 0.4 0.7 0.8 0.6 0.3 0.8 0.8 0.6 0.7

Plato

25.1

9.8

6.0

9.3

41.8

42.9

1.0

72.8

5.5

1.5

11.2

0.7

0.9

Fossil fuels combustion and environmental issues

9

Table 1.4 Quality requirements of kerosene [13]. Test item

Classification

Distillation characteristics 95% distillation temperature ( C) Flash point ( C)

No. 2

270 max.

300 max.

6.1

40 min.



Corrosiveness to copper (50 C, 3 h) Smoke point (mm) Sulfur content mass fraction (%)

1 max. 23 min.a 0.0080 max.b
125 min.

Color (saybolt color) a

No. 1

Test method

6.2




0.50 max.


6.3 6.4 6.5 6.6

For kerosene for cold climate, the smoke point shall be 21 mm or more. For kerosene for fuel cells, the sulfur content shall be 0.0010 mass fraction % or less.

b

Table 1.5 Quality requirements for diesel fuel [14]. Test item

Class Special No. 1

No. 1

Flash point ( C)

No. 2

50 min.

Distillation characteristics 90% distillation temperature ( C) Pour point ( C)

Cold filter plugging point ( C) Carbon residue in 10% residual oil mass (%) Cetane indexb

360 max.

350 max.

330 max.a

330 max.

15 max.

22.5 max.

27.5 max.

220 max.

230 max.




21 max.

25 max.

212 max.

219 max.

0.1 max. 50 min.

45 min. 0.0010 max.



0.86 max.

3

Density (15 C) (g/cm )

Special No. 3 45 min.

Sulfur content mass (%)

a

No. 3

In the case of kinematic viscosity (30 C) of 4.7 mm2/s or less, it shall be 350 C or lower. Instead of cetane index, cetane number may be used.

b

notices 1
3 based on the “Act on Sophisticated Methods of Energy Supply Structures” [22]. The supply for oils heavier than diesel used for power plants is decreasing, and the supply for light oil products such as gasoline and naphtha fractions is increasing, as shown in Fig. 1.8 [20].

Table 1.6 Quality of fuel oils [15]. Kinds

Class 1 Class 2 Class 3

a

No. 1 No. 2 No. 1 No. 2 No. 3

Reaction

Flash point

Kinematic viscosity (50 C) (mm2/s) (cSt)b

Pour point ( C)

Residual carbon content mass (%)

Water content volume (%)

Ash content mass (%)

Sulfur content mass (%)

Neutral

60 min.

20 max.

5 max.a

4 max.

0.3 max.

0.05 max.

50 max. 250 max. 400 max. Over 400
1000 incl.

10 max.a




8 max.




0.4 max. 0.5 max. 0.6 max. 2.0 max.

0.5 max. 2.0 max. 3.0 max. 3.5 max.



70 min.

Pour points of Class 1 and Class 2 for cold climate shall be 0 C and under, and pour points of Class 1 for warm climate shall be 10 C and under. 1 mm2/s 5 1 cSt.

b

0.1 max.


Fossil fuels combustion and environmental issues

Figure 1.5 Electricity generation capacity in Japan [19].

Figure 1.6 Electricity generation composition by resource in Japan [20].

11

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Advances in Power Boilers

Figure 1.7 Changes in energy resource prices [21].

Figure 1.8 Sales of petroleum products in Japan [20].

1.2.3 Gas Examples of gaseous fuels for use in boilers that are being studied include natural gas, blast furnace gas (BFG), biogas, and, with an eye toward a future hydrogen-

Fossil fuels combustion and environmental issues

13

using society, alternative fuels such as hydrogen and ammonia. However, BFG and biogas tend to be for personal or local consumption in the areas where they are produced and are almost never sold internationally. In addition, unlike fossil fuels such as natural gas, there is anticipation around the use of the secondary fuels, such as hydrogen and ammonia, in the transportation sector and distributed power production with environmental conservation in mind, and in the power generation sector in more efficient power generation facilities. We discuss natural gas, which is strongly influenced by external factors, as a fuel for gas-fired boilers, giving an overview of supply and demand trends.

1.2.3.1 World natural gas supply and demand outlook Based on the IEA World Energy Outlook 2017, Fig. 1.9 [23] shows the outlook regarding global supply and demand for natural gas. By 2040 the demand for natural gas is expected to increase by about 1.5 times compared to the 3635 Bcm (billion cubic meters)/year demand in 2016, and increased demand from the Middle East and China in particular is anticipated to make up about 40% of total increased demand. Meanwhile, although the amount of natural gas produced in Europe is

Figure 1.9 Trends and prospects of world natural gas: (A) demand outlook and (B) supply outlook [23].

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Figure 1.10 Supply of natural gas to China (2017) [23].

Figure 1.11 Trends and prospects of primary energy demand by fuel in China [23].

expected to decrease, the entire global supply of natural gas is anticipated to rise due to the production of shale gas in North America and China. Therefore the proportion of unconventional natural gas (shale gas, coalbed methane, and so on) will account for about 30% of the total in 2040. Although there are concerns about delays in establishing more new facilities for LNG, increased production of shale gas is expected to relax global supply and demand for natural gas. Fig. 1.10 [23] and Fig. 1.11 [23] show the supply for natural gas to China (2017) and China’s energy demand according to the IEA, respectively. In China, about 60% of natural gas demand is fulfilled by domestic production, and 22% is composed of imported LNG. As China suffers from serious air pollution, the State Council announced, “10 Measures to Prevent Air Pollution” in 2013 and is planning a rapid transition from coal to natural gas. According to the IEA forecast, the demand of natural gas in 2040 will be about three times higher than in 2016, and the proportion of natural gas demand to primary energy demand will rise to about 14%. On the other hand, the proportion of coal demand to primary energy demand

Fossil fuels combustion and environmental issues

15

Figure 1.12 Changes in the number of global LNG transactions [23].

Figure 1.13 Countries importing LNG worldwide (2017) [23].

is expected to fall from 60% to 40%. Demand for energy and natural gas in China is expected to continue being affected by policy, domestic gas production volume, and import volume in the future, and there are concerns that these fluctuations could affect the global supply of and demand for LNG.

1.2.3.2 Changes in global LNG transactions Fig. 1.12 [23] shows changes in the number of global LNG transactions. The number of global LNG transactions (2017) increased around 10% from the previous year due to increased demand from countries such as China. In particular, the proportion of spot or short-term transactions has risen (27% in 2017), and the liquidity of the LNG market is improving. However, as demonstrated by the primary nations importing LNG and the amounts imported (2017) shown in Fig. 1.13 [23], the

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Figure 1.14 World crude oil, natural gas, and LNG price trends [24].

amount of LNG imported to Asia makes up 73% of all LNG imports, and, moreover, 55% is imported by three countries: Japan, China, and Korea.

1.2.3.3 Changes in global natural gas sale prices Fig. 1.14 [24] shows changes in global natural gas sale prices in comparison to crude oil prices. Spot prices have been increasing since September of 2017 due to factors such as rising oil prices, China’s rapid shift to natural gas to improve its atmospheric environment, falling temperatures in northeastern Asia, and issues with European pipelines. The global supply and demand for LNG are tight particularly because China transitioned to natural gas without first securing a sufficient supply, and, even with the end of winter demand, prices still have not fallen due to issues such as delays in new LNG projects. There are concerns that the sale price of natural gas will continue to be affected by a variety of factors such as the state of supply and demand, geopolitical risks, and risk of developing fossil resources, all of which will require close attention.

1.3

Combustion of fuels

1.3.1 Coal 1.3.1.1 Fundamentals of combustion The combustion process for coal and the calculation methods for the amounts of combustion air and flue gas are explained next.

1.3.1.1.1 Combustion process The process of coal combustion is shown in Fig. 1.15 [25]. First, pulverized coal particles that are ejected from a burner are preheated and dried by convection and

Fossil fuels combustion and environmental issues

17

Figure 1.15 Coal combustion process.

radiation from the combustion flame. When the particle temperature reaches the thermal decomposition temperature, volatiles are released from coal particles and ignite at approximately 250 C
500 C [25]. The particle temperature increases during the homogeneous combustion of volatiles. Before and after the combustion of volatiles is completed, the heterogeneous combustion of char, which is the solid material that remains after volatiles have been released from coal, starts. After char combustion, ash particles and a small amount of unburnt carbon particles remain.

1.3.1.1.2 Combustion air and flue gas Carbon (C), hydrogen (H), oxygen (O), and sulfur (S) are the elements in coal considered in the theoretical calculation. It is assumed that C, H, and S burn are converted into carbon dioxide (CO2), steam (H2O), and sulfur dioxide (SO2), respectively. The theoretical amount of air A0 (m3N/kg-coal), which is the minimum amount of air to burn coal completely, is calculated by the following equation:
 Wh 2 Wo A0 5 8:89Wc 1 26:47 1 3:33Ws 7:94

(1.1)

Wc, Wh, Wo, Ws (kg/kg-coal) are the contents of C, H, O, and S in coal, respectively. The theoretical amount of flue gas G0 (m3N/kg-coal) is also calculated by the following equation: G0 5 0:790A0 1 1:866Wc 1 11:12Wh 1 0:699Ws 1 0:800Wn 1 1:244Ww

(1.2)

Ww and Wn are the contents of water and nitrogen in coal. It is assumed that nitrogen in coal is converted into N2. In actual combustion the actual amount of air used to burn is larger than the theoretical amount of air. The ratio of actual amount of the combustion air to the theoretical amount is defined as the excess air ratio λ (
). The actual amount of

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combustion air A (m3N/kg-coal) and the amount of flue gas G (m3N/kg-coal) are, respectively, calculated by Eqs. (1.3) and (1.4) with λ . 1.0. A 5 λA0

(1.3)

G 5 ðλ 2 1ÞA0 1 G0

(1.4)

In pulverized coal-fired power plants, coal is burned off at an excess air ratio of about 1.2.

1.3.1.2 Combustion systems Coal combustion systems include fixed-, fluidized-, and entrained-bed systems, as shown in Fig. 1.16 [25]. Typical examples of these combustion systems are explained as follows. A stoker furnace is a small furnace of a fixed-bed combustion system. In this system, lumps of coal are placed on a conveyor-type combustor and burned while moving. It is advantageous to be able to burn large lumps of coal without finely pulverizing them. In a fluidized-bed combustion system, grains of coal are injected into the bed medium (e.g., particles of limestone, silica, and ash) fluidized with an airflow and combusted. This system provides better heat transfer in the bed. Furthermore, it can be applied to in-furnace desulfurization by injecting limestone into the bed. However, it has problems in maintaining a stable fluidization when it is scaled up. A pulverized coal boiler system is an example of an entrained-bed combustion system in which pulverized coal and air are

Figure 1.16 Coal combustion system [26].

Fossil fuels combustion and environmental issues

19

Figure 1.17 Pulverized coal combustion method.

ejected from the center of the burner and burned. As this system uses coal particles pulverized to 30
40 µm, it provides high combustion efficiency and less excess air. Furthermore, as it allows the easy scaling up of a boiler, this system is now mainly used in coal-fired power plants.

1.3.1.3 Combustion characteristics An outline of the pulverized coal combustion system, which is mainly used in coalfired power plants, is shown in Fig. 1.17. To reduce NOx a two-stage combustion method is used in this system. Pulverized fine coal is ejected from the center of the burner with primary air. The ejected coal is burned with secondary air, which is ejected from the outer side of the coal flow. Unburned char is reburned with air in the second-stage combustion in which air is ejected from below downstream of the burner zone. The characteristics of combustion in this system are explained next.

1.3.1.3.1 Combustion efficiency The ratio of the amount of burned combustible matter to that of combustible matter in coal is defined as the combustion efficiency E (
), which is calculated by the following equations [27]:

20

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  U 5 A 3 Uc = ð1 2 AÞ 3 ð1 2 Uc Þ

(1.5)

E512U

(1.6)

The ratio of the amount of unburned carbon to that of the combustible matter in coal U (
) is defined as the unburned fraction and calculated using Eq. (1.5). Uc (kg-carbon/kg-ash) is the unburned carbon content in ash. A (kg-ash/kg-coal) is the ash content, which is defined in terms of the weight of oxides in JIS 8812. It should be noted that the ash content is different from the mineral content in coal. The unburned fraction correlates with the fuel ratio as shown in Fig. 1.18 [28]; that is, the unburned fraction increases with the fuel ratio [27,28]. In other studies, the unburned fraction correlates with the content of vitrinite in coal, which is a maceral; this is, the unburned fraction increases as the content decreases [29,30].

1.3.1.3.2 NOx formation NOx is the general term for the nitrogen oxides that are most relevant for air pollution, namely, NO and NO2. In a large boiler the NO2 content in NOx is less than 10%. NOx is produced from N2 contained in air and nitrogen in coal. NOx from N2 is called thermal NOx, and NOx from nitrogen in coal is called fuel NOx. Furthermore, the formation of fuel NOx has two pathways, the formation from nitrogen in volatiles and in char. In pulverized coal combustion, most of the NOx is

Figure 1.18 Correlation between unburned fraction and fuel ratio [28].

Fossil fuels combustion and environmental issues

21

Figure 1.19 Relationship between NOx concentration and nitrogen content in coal [28].

fuel NOx. Therefore the nitrogen content in coal FN (%) and the conversion ratio of nitrogen CR (%) to NOx affect the NOx concentration. The NOx concentration correlates with FN as shown in Fig. 1.19. However, the variation of the NOx concentration is large. This variation is caused by the variation of CR. CR increases with fuel ratio FR, and CR decreases as FN increase. Therefore FR/FN (1/%) and CR have a strong correlation, as shown in Fig. 1.20 [27]. The two-stage combustion method is mainly used to reduce NOx. In this method, part of the combustion air is injected from the two-stage combustion air port, which is located downstream of the burner zone. In the burner zone, pulverized coal burns with λ , 1.0. Part of generated NOx is reduced in the reducing atmosphere downstream of the combustion flame, and the amount of unburned carbon increases in the burner zone and is burned by two-stage combustion in air. The effect of the two-stage combustion ratio on Uc and the NOx concentration are shown in Fig. 1.21 [31]. The NOx concentration decreases as the two-stage combustion ratio increases, but Uc increases. This result indicates that it is important to select a suitable two-stage combustion ratio in accordance with the coal properties and the combustion characteristics of a boiler. Furthermore, various lowNOx burners used in the two-stage combustion method are being developed [32
36].

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Figure 1.20 Correlation between conversion of N in coal to NOx and FN/FR [27].

Figure 1.21 Effects of two-stage combustion ratio on the NOx and unburned carbon concentrations [31].

Fossil fuels combustion and environmental issues

23

1.3.2 Oil The combustion of liquid fuels consists of four reactions, that is, atomization, vaporization, mixing, and (combustion) reaction. For power plants the atomization is achieved by the energy (i.e., pressure or velocity) which is (1) involved in the fuel itself or (2) supplied by an external fluid. Fig. 1.22 shows the main examples of (1): a plain-jet and a pressure-swirl atomizer. Fig. 1.23 shows the main examples of (2), namely, an airblast atomizer [37] and a two-phase nozzle [38]. In both cases the droplets are formed by tearing large droplet, liquid column, or liquid film by a shear stress, as shown in Fig. 1.24 [39]. Because the produced droplets are uniform, the characteristics are evaluated using statistic values regarding distribution of droplet size, average droplet size, its variance, and so on. The Nukiyama
Tanasawa distribution [37] and the Rosin
Rammler distribution [40] are commonly used to represent these characteristics. The Rosin
Rammler distribution function is shown in Eq. (1.7), which describes the cumulative distribution RM (d) of the mass or volume as a function of total mass or volume contained in droplets of diameter d smaller than d. The differential fM (d) is also shown in Eq. (1.8) that indicates the mass or volume content of droplets with diameter d. "
 # d λ RM ðdÞ 5 1 2 exp 2 ; d0 "
 #
 λ d λ21 d λ exp 2 f M ðd Þ 5 ; d0 d0 d0

(1.7)

(1.8)

Figure 1.22 Plain-jet and pressure-swirl atomizer.

Figure 1.23 Airblast nozzle and two-phase atomizer: (A) Nukiyama
Tanasawa airblast nozzle [37] and (B) two-phase mixing nozzle [38].

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Figure 1.24 Three mechanisms of breakup atomization [39]: (A) droplet, (B) fibrous, and (C) film.

where λ and d0 are the distribution parameters. Fig. 1.25 shows the representative Rosin
Rammler distribution. The viscosity of the fuel oil is very important for the formation of the droplets. For high viscosity oils, such as fuel oil specified in JIS, the viscosity of the fuel is controlled by heating so that the fuel temperature becomes suitable for atomization, as shown in Fig. 1.26 [41], which was drawn based on the ASTM D341. The evaporation of a fuel strongly depends on the heat flux to the droplets and the diffusion rate of the fuel vapor around the droplets. The heat flux significantly depends on the conformations of the flame fronts and the droplets. These conformations are discussed by Chiu et al. [42], who modeled them into four conformations of combustion, as shown in Fig. 1.27. The group combustion number G is defined

Fossil fuels combustion and environmental issues

Figure 1.25 Rosin
Rammler distribution of droplets.

Figure 1.26 Correlation between viscosity and temperature of fossil fuels [41].

25

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Figure 1.27 Four group combustion modes of a droplet cloud [42]: (A) single droplet combustion, (B) internal group combustion, (C) external group combustion, and (D) external sheath combustion.

by the Lewis number Le and the Schmidt number Sc, as shown in the following equation:
   2=3 d 1=3 1=2 G 5 1:5Le 1 1 0:27Sc Re nT l

(1.9)

Chiu et al. established that the group combustion can be expressed by the product between the total number of droplets to the two-thirds power and the reciprocal of the nondimensional separation S, as illustrated in Fig. 1.28 (where, to simplify, Le 5 1) [42]. The nondimensional droplet separation S is defined by the following equation:

Fossil fuels combustion and environmental issues

27

Figure 1.28 Group combustion region diagram (Le 5 1) [42].

S5

 0:1 l=d 1 1 0:27Sc1=3 Re1=2

(1.10)

As mentioned earlier, because the liquid combustion depends on many factors such as evaporation, mixing, and spatial dispersion of droplets, the control in liquid fuel combustion is significantly more difficult than that in gaseous fuel combustion. Therefore the reduction of NOx in liquid fuel combustion is difficult compared to gaseous fuel combustion. In gaseous combustion, lean premixed combustion is common, because the fuel can be diluted sufficiently to avoid high-temperature combustion and reduce the generation of thermal NOx by the Zeldovich mechanism (Zeldovich NOx). The NOx emission levels for various fuels upon gas turbine combustion are compared in Fig. 1.29 [43].

1.3.3 Gas Unlike liquid fuels and solid fuels such as coal, gaseous fuels do not contain ash, fixed nitrogen, or sulfur content and do not produce air pollutants other than

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Figure 1.29 Predicted NOx emission levels of various fuels in gas turbine combustors [43].

thermal NOx, which is formed by the oxidization of nitrogen in the air. A variety of low-NOx combustion techniques have been developed because of relatively simple combustion process in which a combustion reaction progresses through only a gasphase reaction with an oxidizing agent such as air. In addition, the demand for natural gas fuels has been steadily rising in recent years because of the low carbon content in fuel (when comparing the CO2 emissions per unit calorific value, coal: fuel oil: natural gas 5 1:0.75:0.55, with natural gas being the lowest), i.e. low contribution to greenhouse effect. An outline of basic burner combustion technology in gasfired boilers for industrial or power generation purposes is provided in the following sections.

1.3.3.1 Natural gas
fired combustion Table 1.7 [44
46] shows examples of the composition of natural and city gases. The basic components of natural gas include methane, ethane, propane, butane, and hydrocarbons with a heavier molecular weight than pentane, as well as the inert gases, nitrogen and carbon dioxide. The proportion of these components varies depending on where the natural gas is produced. In addition, natural gas fuel contains almost no sulfur or fuel N that oxidizes easily in the combustion process, that is why natural gas is used as an environment-friendly fuel with low SOx and NOx emissions. The oil crisis in the 1970s and requirement to prevent environmental pollution have led to expanding demand for natural gas. In the case of the Japanese

Fossil fuels combustion and environmental issues

29

Table 1.7 Typical properties of natural gas and city gas [44
46]. Gas type

Natural gas [44]

City gas (type 13A) [45]

Higher heating value (MJ/m3N)

44.30

45 (range 43
46)

Component (vol.%)

85.48 8.26 3.06 1.42 0.71

89.60 5.62 3.43 1.35


1.17




0.67 (calculated) 54 (calculated) (range 5 44
55 [46])

0.638 56 (calculated)

CH4 C2H6 C3H8 C4H10 C5H12, etc. N2, CO2

Specific weight (air 5 1) Wobbe index (MJ/m3N)

city gas shown in the table, components such as propane gas are added to raw natural gas or LNG to adjust the fuel’s calorific value to 43
46 MJ/m3N and make the gas usable in standard household gas equipment. The adjusted gas is supplied through the city’s pipeline network. Fig. 1.30 [47] shows major gas-fired burner technology. A variety of burner technologies are being developed to fit the fuel type, calorific value, and supply pressure of gas fuels including high-calorie gases such as natural gas, LNG (including city gas), LPG, refined petroleum gas, and COG (coke-oven gas), and mid- to low-calorie gases such as BFG, LDG (Linz
Donawitz converter gas), H2, and biogas. All the burner technologies allow for cofiring of multiple gas fuel types and cofiring with oil. In particular, various manufacturers have recently developed a variety of low-NOx burners as an environment-friendly strategy for large-scale thermal power generation. Specific examples will be discussed later in Section 1.3.3.4. Fig. 1.31 [47] provides examples of oil/gas cofiring burner technology. In all the burner technologies an oil-spray burner is placed in the center of the burner tile with a gas burner positioned on the perimeter. A variety of combinations are possible depending on the fuel type, calorific value, and fuel supply pressure.

1.3.3.2 Blast furnace gas
fired combustion Table 1.8 [48,49] provides examples of the composition of BFG, COG, and LDG produced as a by-product of the production process in steelworks. BGF, a byproduct of producing pig iron by restoring iron ore with coking coal in a blast furnace (BF), contains the combustible components, carbon monoxide (CO) and hydrogen (H2), which make up about 1/4 of the whole composition. Other components include the inert gases nitrogen (N2) and carbon dioxide (CO2), which have a calorific value (of BFG) as low as about 3 MJ/m3N, and less than 1/10 of natural gas, and are referred to as low-calorie gases. COG has a high ratio of combustible

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Advances in Power Boilers

Figure 1.30 Typical properties of gas-fired burners [47].

Figure 1.31 Example of dual-fuel burners [47]: (A) oil burner/low-NOx gas burner, (B) oil burner/scroll-type burner, and (C) oil burner/multiple lance 1 ring-type gas burner.

components at about 90%, a calorific value of about 20 MJ/m3N, and makes up 1/2 of natural gas. LDG is around 70% CO, a combustible component, and is also composed of the inert gases nitrogen (N2) and carbon dioxide (CO2). Its calorific value

Fossil fuels combustion and environmental issues

31

Table 1.8 Typical properties of blast furnace gas (BFG), coke-oven gas (COG), and Linz
Donawitz converter gas (LDG) [48,49]. BFG [48]

COG [48]

LDG [49]

Higher heating value

(MJ/m3N)

2.98

19.26

8.4

Component (vol.%)

H2 CH4 C2H2 CO CO2 N2

2.8

20.8 21.3 55.2

57.4 24.6 2.4 7.1 2.4 6.1




66 16 18

1.06 (calculated) 2.9 (calculated)

0.36 (calculated) 32.0 (calculated)

1.06 (calculated) 8.2 (calculated)

Specific weight (air 5 1) Wobble index (MJ/m3N)

Figure 1.32 Example of manufacturing process scheme and energy flow of the steelworks [50].

is about 8 MJ/m3N, and it makes up 1/5 of natural gas. COG and LDG are called mid-calorie gases. Fig. 1.32 [50] shows an example of the manufacturing process and energy flow at a steelwork. The steelworks by-product gases BFG, COG, and LDG are supplied to nonutility generation facilities for use as boiler fuel. Specifically, high-calorie fuels such as coal, fuel oil, and LPG are supplied to and cofired in the nonutility generation facilities for the auxiliary fuel firing of by-product gas. In recent years, BFG single-fuel firing technology has also been put to practical use. In addition to

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Advances in Power Boilers

Figure 1.33 Example of BFG-fired boiler and burner: (A) boiler and (B) scroll-type burner [48]. BFG, Blast furnace gas.

using the energy produced as power within the steelworks, some power is also sold off. Furthermore, some of the steam produced by boilers is used as in-house process steam at the steelworks. Fig. 1.33 [48] shows an example of a BFG-fired boiler and a burner. The boiler illustrated is equipped with a total of 18 opposing burners on three rows and three levels. The lower level burners burn BFG, while BFG and natural gas (NG) are supplied to the mid-level burner, and COG is supplied to the upper level burner. The burners are structured such as scroll-type burners, with a natural gas
fired burner in the center of the burner to adjust the number of calories supplied and a BFGfired scroll-type burner positioned on the perimeter. In the example provided, natural gas is supplied to the auxiliary burner (stabilizer) for the auxiliary fuel firing of by-product gas, but BFG single-fuel firing technology is also being developed.

1.3.3.3 Biogas-fired combustion Table 1.9 [45] shows production methods and examples of the biogas composition. Biogas production methods are broadly divided into methane fermentation and partial combustion gasification. Methane fermentation gasification produces gas with methane as the main component by fermenting organic material such as food waste under anaerobic conditions. With a calorific value of 24 MJ/m3N, it makes up about 1/2 of natural gas. In partial combustion gasification, organic material is gasified in a gasification furnace to produce a gas with H2 and CO as the main components. Because gasification takes place through partial combustion using air as a gasifying agent, the gasified gas is a low-calorie gas containing CO2 and a large amount of N2. The composition of the gasified gas, amount produced, and calorific value varies depending on the type of food waste used as the raw material, the amount supplied, the conditions under which gasification occurred, and the form of gasification furnace. When being used as boiler fuel, misfiring may occur if there is any deviation from the combustion conditions in the boiler part, and to ensure stable combustion, fuel calories are adjusted by mixing in other fuels or an auxiliary burner is added. Anaerobic digestion gas from sewage treatment plants and methane

Fossil fuels combustion and environmental issues

33

Table 1.9 Typical properties of biogases [45]. Gasification process

Higher heating value (MJ/m3N) Component (vol.%)

H2 CH4 C2H2 CO CO2 N2 Trace

Methane fermentation

Partial combustion

24

4.0


60

40
Hydrogen sulfide, siloxane, moisture

10 4 1 10 15 60


Figure 1.34 Example of biogas upgrading system flow diagram [51].

fermentation gas from beer factories have long been in use, and biogas combustion boilers used as factory heat sources are also on the market. Methane fermentation is composed of around 60% methane, 40% CO2, and trace amounts of other components. With the broadening uses of biogas in mind, technologies are being developed to collect and refine methane at higher concentrations by separating out the CO2 in the gas. Fig. 1.34 [51] shows an example of the flow of a biogas (digestion gas) refinement system using methane fermentation gasification

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Advances in Power Boilers

Figure 1.35 Example of manufacturing facility for utilizing biogas as city gas [51].

of sewage sludge. After compressing the biogas, it is supplied to an absorption tower, and differences in water solubility are used to remove impurities such as carbon dioxide, hydrogen sulfide, and siloxane. Then, the methane concentration after the refinement is raised to 98% by eliminating moisture with a dehumidifier. The use of a separation membrane has also been proposed as a way to achieve a 98% methane concentration in the refined gas [52]. There are also efforts to use refine biogas as an alternative fuel for city gas. Fig. 1.35 [51] shows an example of biogas being injected into city gas pipes via a manufacturing facility for utilizing biogas as city gas. City gas manufacturing facilities adjust calories and burning velocities to gas quality standards, add a scent agent for the detection of gas leaks, and inject gas into city gas pipes. The City Gas Promotion Center is soliciting “Projects Demonstrating Biogas Being Injected into City Gas Pipes,” and biogas is being injected into pipe networks in two locations: the Ota Ward of Tokyo and Kobe in Hyogo prefecture. The former is using leftover food as the raw material, while the latter is using sewage sludge from sewage treatment plants, and both plans produce about 800,000 m3N per year for 10 years after starting in 2010.

1.3.3.4 Alternative fuel gas
fired combustion Table 1.10 compares the combustion properties of hydrogen gas and ammonia gas to those of methane, a major component of natural gas. It demonstrates that the combustion properties of these gases differ greatly from those of methane. The differences in their flammability limit, minimum ignition energy, quenching distance, maximum flame velocity, and theoretical flame temperature are particularly distinctive. When hydrogen or ammonia is used as a fuel, it is important to account for the differences between its combustion properties and those of natural gas when designing or reworking burners. In the development of boilers for industrial use, there are some examples of H2 gas being cofired with fuel oil and natural gas. To secure a large amount of calories and a large turndown ratio, the combustion device of single burner uses both multiple lance-type and ring-type gas burners for H2 gas and sets the supply amount of

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Table 1.10 Typical properties of hydrogen and ammonia gases.

(MJ/m3N)

Higher heating value Flammability limitsa (vol.% in air) Autoignition temperature (in air)a (K) Minimum ignition energy (mJ) Quenching distance (in air)b (cm) Maximum flame velocity (cm/s) Theoretical adiabatic flame temperature (in air)b (K) Specific gravity Wobbe index (MJ/m3N) a

Hydrogen

Ammonia

Methane

12.8 4
75 844 0.02 0.06 291 2381

17.1 15
28 924 8.0
1.5 2072

39.8 5.3
15 905 0.2 0.20 37 2224

0.0695 48

0.597 22

0.555 54

At 293K and atmospheric pressure. At ambient temperature and atmospheric pressure.

b

Figure 1.36 Example of ammonia cofiring test system in coal-fired boiler: (A) fuel supply system and (B) ammonia supply method [53].

H2 gas to 7500 m3N/h [47]. Up to this point, H2 gas cofiring boilers with a variety of gas fuels have been developed. Care must be taken because the position of the flame changes when cofiring of a larger amount of H2. Fig. 1.36 [53] shows NH3 gas cofiring test system with a coal-fired boiler. The power plants have pulverized coal-fired boilers with a rated output of 156 MW, and

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BOG (boil-off gas) from adjacent LNG storage tanks is cofired. In each of the multiple boiler burners setup, the five BOG injection nozzles were positioned around the central pulverized coal-fired burner, and ammonia was supplied to one of the five BOG injection nozzles. The results of tests on the cofiring amount of ammonia with an output of 0.6%
0.8% of the rated output (lower heating value basis) showed that no change in the NOx emissions and the boiler tube wall temperature was observed, and that no abnormal findings were detected in the air preheater or denitrification equipment on the downstream side of the boiler. Later, the IHI Corporation conducted tests using a 10 MW-class pulverized coal-fired boiler to increase the cofiring amount of ammonia up to 20%, and the results indicated that the NOx emission concentration was about the same as those of pulverized coal single-fuel firing. To create a hydrogen society in the future, a variety of initiatives are now underway, such as studies on production methods for ammonia, ways of utilization, and potential markets as a hydrogen carrier (e.g., Ref. [54]). For more information, see the website of the 2018 NH3 Fuel Conference [55], where you can find various literature and lecture materials.

1.4

Emission-induced environmental issues and protection

1.4.1 Flue gas treatment technology Main flue gas treatment technologies in a fossil combustion power boiler are used a dust collection technology, a De-NOx technology, and a desulfurization technology. The configuration of the flue gas treatment technologies is determined according to the best operating conditions of these systems. As an example, Fig. 1.37 shows a

Figure 1.37 Flow of a coal-fired power plant.

Fossil fuels combustion and environmental issues

37

configuration of a coal-fired power plant. The high-performance flue gas treatment technologies have been installed in thermal power plants, and since then the emission of environmental pollutants has become much lower than that in the past. In recent years the mercury emission from thermal power plants has been given increasing attention, and the establishment of mercury emission control technology is also desired. The outline of each technology adapted in thermal power plants is shown next.

1.4.1.1 Dust collection technology An electrostatic precipitator (ESP) is utilized as a dust collection technology in large-scale facilities such as thermal power plants. The outline of ESP is shown in Fig. 1.38. In the ESP, dust particles in the flue gas are charged by corona current and removed by the electric field. Therefore the collection performance of the ESP depends on the electrical properties of dust particles. The performance parameters of the ESP, such as collection efficiency, applied voltage, and corona current, depend on the dust resistivity as shown in Fig. 1.39 [56]. The dust resistivity has a suitable range for collecting dust. The overall collection efficiency of the ESP is over 99%, and the fractional collection efficiency, which is the collection efficiency

Figure 1.38 Outline of ESP. ESP, Electrostatic precipitator.

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Advances in Power Boilers

Figure 1.39 Collection characteristic of ESP and electric resistivity [56]. ESP, Electrostatic precipitator.

for the respective particle size, has a minimum value in the range of particle size of 0.1
1.0 µm as shown in Fig. 1.40 [56]. The ESP is effective for the removal of fine particle matter [56]. Ash produced by the combustion of pulverized coal is an example of highresistivity dust. The dust resistivity is affected by dust properties, temperature, humidity, and so on. The relationship between resistivity of coal ash and the temperature for various humidity conditions is shown in Fig. 1.41 [56]. The resistivity has a maximum value in the temperature range 100 C
200 C, except under dry condition of 0% humidity. At the same temperature the resistivity becomes higher with a decrease in humidity. One approach for decreasing the resistivity of dust is the high-temperature ESP operation at 350 C. This ESP operation is based on the fact that the resistivity of coal ash is less at high temperature. On the other hand, when the operating temperature of the ESP is reduced, e.g. below 100 C, the dust resistivity decreases, which is referred to as the advanced low-temperature ESP operation. In future, this type of ESP will be one of the option for high-resistivity ash. Since the reduction in collection efficiency with high-resistivity ash is due to the dust layer adhered to the collection electrodes, methods to minimize this problem are being developed. One of the techniques is a moving collection electrode in which the dust is removed by a brush [57]. Another is the semiwet-type ESP in

Figure 1.40 Fractional collection efficiency of ESP [56]. ESP, Electrostatic precipitator.

Figure 1.41 Relation between gas temperature and electric resistivity of coal fly ash [56].

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Advances in Power Boilers

which the dust layer is removed by washing with water. These two methods offer potential for performance improvement. An example of a low resistivity dust is the ash from the residual oil combustion. The collection efficiency of the ESP is related to only corona power irregardless of the gas temperature. To increase the resistivity of the oil dust, the technology is used that the ammonia is injected into the ESP inlet gas, and ammonium sulfate with a high-resistivity matter is produced. Another high-performance dust collection technology is the bag filter. Bag filters are constructed from porous woven or felted fabric through which gases flow to remove dust. The use of a bag filter requires the selection of a fabric material suitable for the characteristics of the flue gas and the maximum operating temperature. The choice between applying an ESP or a bag filter generally depends on the fuel type, plant size and configuration, and boiler type. The pressure drop in the bag filter is very high compared to the ESP. So, the bag filter is not suitable for largescale facilities and is mainly utilized as a dust collector in small scale facilities.

1.4.1.2 De-NOx technology The selective catalytic reduction (SCR) technique is widely applied for the reduction of NOx in a flue gas from large-scale facilities. The technique is the method of injecting ammonia (NH3) in a flue gas and reducing the NOx to nitrogen by the catalyst. The outline of SCR equipment is shown in Fig. 1.42. The operating

Figure 1.42 Outline of SCR equipment. SCR, Selective catalytic reduction.

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Figure 1.43 Relation between NH3/NOx ratio and NOx removal efficiency [58].

temperature range of SCR reactor is 300 C
400 C. A part of NH3 leaks from SCR reactor because of the incomplete reaction of NH3 in the De-NOx process. And usually 0.2%
2% of SO2 in the flue gas is oxidized to SO3 in the catalyst. The formation of SO3 brings about problems of corrosion and plugging in the downstream equipment. NH3 and SO3 in the flue gas react to form NH4HSO4 and are deposited in the air preheater. The NH3 slip at SCR installation increases with an increasing NH3-to-NOx ratio as shown in Fig. 1.43 and with decreasing catalyst activity [58]. An amount of NH3 slips can be guaranteed by proper maintenance of the catalyst system. NH3-to-NOx ratio is controlled about 70%
80%, and the concentration of NH3 slip is managed at lower than 5 ppm in thermal power plants. Since the catalyst activity decreases overtime due to factor such as poisoning, surface masking, or thermal degradation, the periodic replacement of catalyst is necessary. Another De-NOx technology is the selective noncatalytic reduction (SNCR) method. The process involves injecting either NH3 or urea into the outlet of boiler at a location where the flue gas temperature is 850 C
950 C to react with NOx formed. At the temperature above 1093 C, NH3 decomposes and NO is produced instead. In the practical example, when the NH3-to-NOx ratio sets 1.5, the efficiency was about 40%. However, SNCR method has an economical advantage over SCR method, because the catalyst is not used.

1.4.1.3 Flue gas desulfurization technology Wet scrubbers using limestone
gypsum processes are the main flue gas desulfurization (FGD) techniques in thermal power plants. The outline of wet scrubber is

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Advances in Power Boilers

Figure 1.44 Outline of wet scrubber using limestone
gypsum processes.

shown in Fig. 1.44. This process is based on the reaction that a limestone (CaCO3) slurry produces calcium sulfite (CaSO3). Further oxidization of CaSO3 produces gypsum. Limestone (CaCO3) used as the absorber of SO2 is available in large amounts in many countries and is cheaper to process than other sorbents. If gypsum can be sold, the total overall operating costs may be reduced. As the other absorbers in wet scrubber for FGD, magnesium hydroxide (Mg (OH)2), caustic (NaOH), aqueous ammonia, seawater, and so on are used. In scrubbing systems using magnesium and seawater, wastewater can be discharged into the sea, after the removal of dust and dust-absorbed metals, because magnesium sulfate is a constituent of seawater. To promote maximum gas
liquid surface area and residence time, a number of wet scrubbers are designed as shown in Fig. 1.45, such as spray tower and jet bubbling reactor, and are installed in thermal power plants. The pH value of absorption liquid and the liquid-to-gas ratio (L/G) have been controlled to a suitable value on the type of scrubber in consideration of desulfurization efficiency and utilization rate of the absorbers, etc. Usually, the pH value is set in the range of 4.0
6.0 in the limestone
gypsum process. Wet scrubbers can capture the water-soluble gas components, such as hydrogen chloride and hydrogen fluoride, in addition of SO2 removal. So, wet scrubbers require wastewater treatment to meet discharge regulations. Wet scrubber also has the dust removal performance, and the measures for dust emission are implemented by the combination of dust collector and FGD equipment. As the other FGD technology, spray dry absorber (SDA) is used in thermal power plants. This method is suitable for low- to moderate-sulfur fuels and for use

Fossil fuels combustion and environmental issues

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Figure 1.45 Examples of wet scrubber design: (A) spray tower and (B) jet bubbling reactor.

in smaller facilities. A slurry or solution of alkaline reagent is injected in the flue gas stream. The material reacts with SO2 to form a solid powder that removes by a bag filter or ESP. The sorbent for the SO2 absorption is typically calcium hydroxide (Ca(OH)2). Wastewater treatment is not required in these processes because all the water is completely evaporated in the SDA. As the absorbent containing SO2 mixes with fly ash, some installations use a dust control device before the spray dry scrubber for separate collection of the fly ash.

1.4.1.4 Combined technologies to reduce NOx and SOx emissions One of the combined technologies to reduce NOx and SOx emissions is active carbon (AC) process. The concept of this process is shown in Fig. 1.46 [59]. This

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Advances in Power Boilers

Figure 1.46 Concept of combined technology to reduce NOx and SOx emissions [59].

process is used the activated carbon as absorber of pollutant matters in flue gases. Simultaneous SO2 and NOx removal becomes possible by adding ammonia. NOx reacts catalytically with the ammonia to form nitrogen gas (N2) and water on the AC. SO2 in flue gases is captured in the AC. The sulfur laden AC passes to a regenerator where desorption is performed. The activated carbon process also has considerable potential for removing SO3 and air toxic substances such as mercury and dioxins. Activated carbon techniques combined use only a fraction of the water used in conventional abatement systems, for example, water use is as low as 1% of the water used in wet FGD.

1.4.1.5 Mercury emission control technology One of the mercury removal technologies is activated carbon injection (ACI) that has been commercially applied technology in coal-fired power plants. Typically, the powdered sorbent for mercury is injected upstream or downstream of the existing dust collector. Mercury in a flue gas is adsorbed to the activated carbon. If the absorber is injected downstream of the dust collector, BF needs to be added downstream of the existing dust collector. The ACI achieved over 90% Hg capture in a coal-fired power plant. When an ACI system is located upstream of dust collector, this mixing can negatively affect the utilization of fly ash in concrete production. Existing flue gas treatment facilities in thermal power plants is not primarily installed for mercury removal, they have cobeneficial effects on the removal of environmental pollutants, including mercury. Gaseous oxidized mercury is removed by a wet FGD facility, while particulate mercury is removed by a PM collector, such as an ESP or a BF. Even though the SCR facility does not remove mercury, the catalyst causes changes in mercury speciation by promoting the oxidation of gaseous elemental mercury into a gaseous oxidized form and improves the mercury removal efficiency of wet FGD. The mean values of the mercury removal efficiencies classified by the configurations of gas treatment facilities are shown in Fig. 1.47 with the 25th and 75th percentiles [60]. The mean mercury removal

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45

Figure 1.47 Mercury removal efficiency by gas treatment facilities in Japan [60].

efficiency of about 90% has been achieved for the configuration of SCR, LL-ESP, and FGD. The mercury removal efficiency of a plant with BF installed is nearly the same as that of a plant that implemented SCR, L-ESP, and FGD. Furthermore, the mercury removal efficiency increases with a decrease in the ESP temperature. In addition, the removal efficiency increases when SCR is implemented, because SCR promotes the oxidation of gaseous elemental mercury and mercury removal in FGD.

1.4.2 Wastewater treatment Boron and selenium are trace elements contained in coal [61,62]. In coal combustion at thermal power plants, they are released in the gas phase (flue gas) due to its volatility and then partitioned into bottom ash, fly ash, FGD wastewaters, and exhaust gas, mainly into fly ash and FGD effluents [63
66]. The electric power companies in Japan import a number of coal from all over the world, and the power plants use dozens of coals or sometimes more than 100 kinds of coals. Thus the content of trace elements is varied in the FGD effluent, depending on the coals employed.

1.4.2.1 Boron Boron is an essential micronutrient for plants and animals but also is toxic in large doses. In Japan the Environmental Quality Standard for water pollution, which is a target level to be achieved in public water to protect human health, is set at 1 mg/L for boron [67]. Reflecting this establishment, the national effluent standard for boron is set at 10 and 230 mg/L for effluents discharged to terrestrial water bodies and to coastal water bodies, respectively [68]. The main source of aqueous boron in the power plants is an effluent from a wet FGD scrubber. Thus we must manage the boron in the FGD effluent to meet the

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Advances in Power Boilers

Figure 1.48 Online boron monitor (500 mm width 3 500 mm depth 3 1500 mm height): (A) inside view and (B) close-up of the measurement cell [69].

regulations. Process monitoring of boron concentration in the combination of coal blending is one of the solutions to obtain control over the boron emission. A fully automated process monitor for aqueous boron (the online boron monitor, Fig. 1.48) was developed [69] on the basis of a rapid potentiometric determination with a BF2 4 ion-selective electrode [70,71]. The online boron monitor was installed at a 250 MW unit for 4 weeks, elucidating the boron behavior in the FGD effluent (Fig. 1.49A). The boron concentration varied significantly in the range of 40
210 mg/L, which showed an excellent correlation (R2 5 0.987) with the inductively coupled plasma (ICP) atomic emission spectroscopy measurements. Three types of coal with different boron contents were employed during the period (Fig. 1.49B). Apparently, the type of coal is a governing factor of the boron level in the effluent, but no proportional relationship was recognized between the effluent concentration and the boron content in coal. In addition, the power generation was constant in full-load operation (250 MW), except from the 13th to 15th days, in which the plant was shut down and then restarted (Fig. 1.49C). Corresponding to this, a V-shaped profile was observed with a delay of 2
3 days. Such boron behavior demonstrates the possibility of managing the boron emission in the combination of process monitoring and coal selecting (or blending). The boron compounds in the FGD effluent can be reduced to some extent in the conventional coagulation
sedimentation using aluminum sulfate and calcium hydroxide [72
74], which produces a huge amount of sludge and leads to a higher cost. Several improvements are made to reduce the sludge and operation cost [75]. Recently, a new coagulation by the use of hydrogen peroxide (H2O2) is also proposed as chemical oxo-precipitation, attracting attention [76].

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47

Figure 1.49 Boron concentration in FGD effluent: (A) boron concentration in FGD effluent, (B) boron content in coal, and (C) load of power generation. FGD, Flue gas desulfurization. Source: Reproduced based on S. Ohyama, K. Abe, H. Ohsumi, H. Kobayashi, N. Miyazaki, K. Miyadera, et al., Fully automated measuring equipment for aqueous boron and its application to online monitoring of industrial process effluents, Environ. Sci. Technol. 43 (11) (2009) 4119
4123.

Various adsorption removal systems [72,77,78] have been developed and employed for industrial effluents with a low concentration at small- or mediumsized plants. The removal system using a boron-selective chelating resin has been operated for the FGD effluent at the power plant.

1.4.2.2 Selenium Selenium is an essential trace element for human beings, but also toxic in excessive doses. In Japan the environmental quality standard for water pollution, which is a target level to be achieved in public water to protect human health, is set at

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Advances in Power Boilers

0.01 mg/L for selenium [67]. To achieve this standard the national effluent standard is set at 0.1 mg/L [68]. In aqueous environment, selenium mainly exists as tetrava22 lent selenite (SeO22 3 ) and hexavalent selenate (SeO4 ), and the chemical properties of Se are totally different owing to its chemical form. In coal-fired power plants the selenium in coal is partitioned mainly into fly ash and the FGD effluents [63
66,79]. The selenium in the flue gas is mainly SeO2 that enters the FGD scrubber, where it is dissolved in the liquid phase and oxidized 22 22 22 with S2 O22 8 to form SeO4 [80]. Thus SeO3 and SeO4 predominantly exist in the FGD effluent with a small amount of other Se species [81]. SeO22 3 is easily treated and removed by coagulation or adsorption, whereas SeO22 is hard to be precipi4 22 tated. SeO22 in the wastewater can be reduced to SeO or zerovalent selenium 4 3 with a metal reductant under acidic conditions and then removed in the coagulation
sedimentation [82
85]. However, it requires the cost for the reducing agent and generates a large amount of sludge as a by-product. The concentration of Se in the FGD wastewater fluctuates depending on the coals consumed. Several plants install selenium removal facilities for FGD wastewaters to meet the regulation [85]. The facilities consist of a reduction of selenate, pH control, coagulation, and sedimentation (Fig. 1.50). The reduction step employs metallic iron [82] or metallic titanium/aluminum [83
85] granules as a reducing agent. Monitoring of the Se concentration in the FGD effluent is important for operating the facilities efficiently. For this purpose an online process monitor for aqueous selenium has been developed (Fig. 1.51), which can measure the concentration in 1 hour using a Galvanic cell gas detector for hydrogen selenide [86,87]. The monitor was installed in a full-scale coal-fired power plant and monitored the FGD effluents, that is, the influent and effluent of the Se removal treatment [86]. The concentration of selenium varied in the range of 0.1 and 0.5 mg/L for the influent,

Figure 1.50 Selenium removal facilities for FGD wastewaters. FGD, Flue gas desulfurization.

Fossil fuels combustion and environmental issues

49

Figure 1.51 Online process monitor for selenium (dimensions: 1500 mm width 3 500 mm depth 3 1200 mm height). Source: Reproduced based on S. Ohyama, Online monitoring technology of selenium concentration in process effluents for process management, Nihon Enerugii Gakkai Kikanshi Enermix 96 (6) (2017) 788
795 (in Japanese).

whereas the effluent remained almost below the effluent standard (0.1 mg/L) (Fig. 1.52). A fairly good correlation (R2 5 0.98 for n 5 104) was obtained in the measurements between the monitor and the official method, inductively coupled plasma optical emission spectrometry (ICP-OES) that demonstrated the monitor serves as a useful tool for managing selenium emission in the FGD effluents.

1.5

Remarks

This chapter focused on the characteristics of coal, oil, and gas as fossil fuels for power generation and outlined the combustion systems peculiar to each of the fuels. The most important issues are higher combustion efficiency and limiting the formation of NOx. Aiming at these issues, R&D is ongoing for combustion methods and burner structure according to the type of fuel. For environmental protection measures, the issues that are drawing attention and that need to be addressed include the reduction in the concentration of particulates, nitrogen oxides, sulfur oxides, and mercury in emission gas and limiting and controlling boron and selenium in the wastewater. The matters to be considered in the utilization of resources as power generation fuel are stable procurement, power generation costs including fuel expenses and environmental characteristics such as carbon dioxide, nitrogen oxide,

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Figure 1.52 Selenium concentration in FGD effluent. The upstream and downstream of the Se removal treatment facility was monitored. FGD, Flue gas desulfurization. Source: Reproduced based on S. Ohyama, Online monitoring technology of selenium concentration in process effluents for process management, Nihon Enerugii Gakkai Kikanshi Enermix 96 (6) (2017) 788
795 (in Japanese).

sulfur oxide, and particulate emissions. Thus it is important to select appropriate methods for fuel supply, operation, and maintenance with an understanding of the specific characteristics of the fuels.

Nomenclature Notations A, A0 CR d D do E fM (d) FN FR G G, G0 L Le nT

amount of air conversion ratio of nitrogen in coal to NOx diameter of droplet diffusion coefficient parameter of the Rosin
Rammler distribution function combustion efficiency differential function of the cumulative distribution function nitrogen content in coal fuel ratio group combustion number amount of flue gas average distance between two droplets Lewis number (5Pr/Sc) total number of droplets in the cloud

Fossil fuels combustion and environmental issues

Pr RM (d) Re S Sc U Uc W

51

Prandtl number cumulative distribution function (cumulative value , d) Reynolds number nondimensional droplet separation Schmidt number (5υ/D) unburned fraction carbon concentration in ash content of element in coal

Greek letters λ excess air ratio λ parameter of the Rosin
Rammler distribution function υ kinematic viscosity

Subscripts c h n o s w

coal hydrogen nitrogen oxygen sulfur water

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Determination of Constituents, Japanese Industrial Standards Committee, n.d.

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[9] JIS M8814, Coal and Coke
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[31] H. Shirai, H. Tsuji, M. Nunokawa, M. Ikeda, N. Noda, H. Akiho, et al., The Functions and the Characteristics of Combustion and Flue Gas Treatment on the Coal Combustion Characteristic Evaluation Test Facility—The Role of the Coal Combustion Characteristic Evaluation Test Facility on the Development of the Advanced Pulverized Coal Fired Power Generation Technology, CRIEPI Report, W03025, 2003 (in Japanese). [32] Y. Oki, K. Koyata, S. Abe, H. Ogasawara, K. Higaki, T. Kiga, et al., Development of New Wide-Range Burner
Demonstration Test at Utility Boiler, CRIEPI Report, W94019, 1994 (in Japanese). [33] H. Makino, M. Kimoto, H. Tsuji, T. Kiga, Y. Endo, Development of Advanced LowNOx Burner for Pulverized Coal Combustion, CRIEPI Report, W13, 1999 (in Japanese). [34] K. Kiyama, H. Okazaki, H. Yoshizaki, M. Taniguchi, Latest low NOx combustion technology for pulverized coal fired boilers, Hitachi Rev. 91 (3) (2009) 30
35 (in Japanese). [35] M. Tanabe, S. Watanabe, E. Ohno, R. Itoi, T. Kozaki, Advanced development of pulverized coal firing technologies, J. IHI Technol. 51 (1) (2011) (in Japanese). [36] Y. Ukeguchi, K. Sakai, S. Kokuryo, K. Saito, T. Suto, T. Yamashita, Mitsubishi Hitachi Power Systems Ltd. Its boiler business and technology development, Mitsubishi Heavy Ind. Tech. Rev. 52 (2) (2015) 52
60 (in Japanese). [37] S. Nukiyama, Y. Tanasawa, Experiments on the atomization of liquids in an air-stream, Trans. Jpn. Soc. Mech. Eng. 5 (18) (1939) 131
135 (in Japanese). [38] Japan Boiler Association (Ed.), Fuels and Combustion of Boilers, Kyoritsu Shuppan Co., Ltd., 1967 (in Japanese). [39] Y. Tanasawa, Outline of liquid atomization method, Trans. Soc. Heat. Air Cooling Sanit. Eng. Jpn. 16 (9) (1942) 740
760 (in Japanese). [40] P. Rosin, E. Rammler, The laws governing the fineness of powdered coal, J. Inst. Fuel 7 (31) (1933) 29
36. [41] Y. Mizutani, Combustion Engineering, third ed., Morikita Publishing Co., Ltd., 2002, p. 13 (in Japanese). [42] H.H. Chiu, H.Y. Kim, E.J. Croke, Internal grope combustion of liquid droplet, in: 19th Symposium (Int) Combust
Combust Inst, vol. 19, Issue 1, 1982, pp. 971
980. [43] W.S.Y. Hung, The NOx Level of Unconventional Fuels for Gas Turbine, ASME Paper 77-GT-16, 1977, 575
579. [44] The North American Energy Standards Board (NAESB). ,https://www.naesb.org/pdf2/ wgq_bps100605w2.pdf. (accessed on 09.01.19). [45] S. Ito, T. Sato, Fuel for boiler (fuel oil and fuel gas), J. Jpn. Boiler Assoc. 386 (2014) 6
16 (ISSN0387-0162) (in Japanese). [46] D.J. Abbott, The impact of natural gas composition variations on the operation of gas turbines for power generation, in: The Future of Gas Turbine Technology, 6th International Conference, 17
18 October 2012, Brussels, Belgium, 2012. ,https://gasgov-mst-files.s3.eu-west-1.amazonaws.com/s3fs-public/ggf/Impact%20of%20Natural% 20Gas%20Composition%20-%20Paper_0.pdf. (accessed on 09.01.19). [47] H. Nakamura, The outline and feature of various burners for boilers, J. Jpn. Boiler Assoc. 386 (2014) 17
23. ISSN0387-0162. [48] T. Tsumura, N. Tsukada, Accomplishment of blast furnace gas mono-fuel combustion for 350t/h industrial boiler, J. Jpn. Boiler Assoc. 386 (2014) 29
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Energy/Energy Efficiency and Conservation Subcommittee/Working Group on Classification Standards for Thermal Power Generation, 2015. ,http://www.meti.go.jp/ committee/sougouenergy/shoene_shinene/sho_ene/karyoku/pdf/002_03_00.pdf. (accessed on 09.01.19). M. Miki, S. Hisayama, K. Sakamoto, The energy efficiency challenge at Kakogawa Works, Kobe Steel Eng. Rep. 53 (2) (2003) 70
74ISSN2188-0913. Available from: http://www.kobelco.co.jp/technology-review/pdf/53_2/070-074.pdf (accessed on 09.01.19). Renewable Energy “Kobe Biogas” (Released 09/2013), Kobe City PR Publication Records, No. 188 (PR publication Standard Form B-2), ,http://www.city.kobe.lg.jp/ life/town/waterworks/sewage/kobebiogaspamphlet.pdf., 2013 (accessed on 09.01.19). Biogas Upgrading System Flow Diagram, Tokyo Gas Co., Ltd. Press release. ,https:// www.tokyo-gas.co.jp/techno/english/category1/12_index_detail.html. (accessed on 09.01.19). H. Tanigawa, Test results of the ammonia mixed combustion at Mizushima Power Station Unit No. 2 and related patent applications, in: AIChE Annual Meeting, October 31, 2018, Pittsburgh, PA, 2018. ,https://nh3fuelassociation.org/wp-content/uploads/ 2018/12/1530-Chugoku-Electric-Power-Co.pdf. (accessed on 09.01.19). S. Muraki, Development of technologies to utilize green ammonia in energy market, in: AIChE Annual Meeting, October 31, 2018, Pittsburgh, PA, 2018. ,https://nh3fuelassociation.org/wp-content/uploads/2018/11/AEA-Imp-Con-01Nov18-Shigeru-MurakiKeynote-Address.pdf. (accessed on 09.01.19). ,https://nh3fuelassociation.org/conference2018/#implementation. (accessed on 09.01.19). C. Kanaoka, H. Makino, Hajimete No Shuujin Gijutsu (Introduction to Dust Collection Technology), Nikkan Kogyo Shimbun, Tokyo, 2013 (in Japanese). H. Yabuta, Moving electrode type electrostatic precipitators, Hitachi Hyoron 64 (2) (1982) 21
26 (in Japanese). CRIEPI, Improvement of pulverized coal combustion technology for power generation, CRIEPI Rev. 46 (2002) 59
73 (in Japanese). T. Hanada, T. Watanabe, Dry-SOx and de-NOx technology for coal-fired power station
dry activated char and sulphur recovery process, Therm. Nucl. Power 40 (1) (1989) 37
48 (in Japanese). N. Noda, S. Ito, Mercury partitioning in coal-fired power plants in Japan, J. Inst. Energy 97 (2018) 342
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402. A.H. Clemens, L.F. Damiano, D. Gong, T.W. Matheson, Partitioning behavior of some toxic volatile elements during stoker and fluidized bed combustion of alkaline subbituminous coal, Fuel 78 (1999) 1379
1385. A.H. Clemens, J.M. Deely, D. Gong, T.A. Moore, J.C. Shearer, Partitioning behaviour of some toxic trace elements during coal combustions the influence of events occurring during the deposition stage, Fuel 79 (2000) 1781
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[66] N. Noda, S. Ito, The release and behavior of mercury, selenium, and boron in coal combustion, Powder Technol. 180 (2008) 227
231. [67] Ministry of the Environment, Japan, Environmental quality standards for water pollution. ,https://www.env.go.jp/en/water/wq/wp.pdf. (accessed on 19.06.19). [68] National Effluent Standards. ,https://www.env.go.jp/en/water/wq/nes.html. (accessed on 19.06.19). [69] S. Ohyama, K. Abe, H. Ohsumi, H. Kobayashi, N. Miyazaki, K. Miyadera, et al., Fully automated measuring equipment for aqueous boron and its application to online monitoring of industrial process effluents, Environ. Sci. Technol. 43 (11) (2009) 4119
4123. [70] H. Ohsumi, S. Ohyama, S. Kudo, M. Sakata, A simple and rapid determination method of boron in wastewater using ion-selective electrode, J. Environ. Chem. 14 (2004) 81
89 (in Japanese). [71] H. Ohsumi, S. Ohyama, S. Kudo, M. Sakata, Japanese Patent 4210146, 2008. [72] Y. Xu, J. Jiang, Technologies for boron removal, Ind. Eng. Chem. Res. 47 (1) (2008) 16
24. [73] Y. Taguchi, Y. Takahashi, T. Iwakura, S. Baba, T. Yamaguchi, Coagulative precipitation and adsorption removal of boron from and the adsorption wastewater, J. Environ. Chem. 11 (3) (2001) 557
565 (in Japanese). [74] S. Kudo, M. Sakata, Coagulation-sedimentation method using aluminum sulfate and calcium hydroxide for removal of boric acid from wastewater -improvement of removal rate of boric acid by addition of gypsum into wastewater, J. Chem. Soc. Jpn. 2 (2002) 265
268 (in Japanese). [75] NEC Facilities, Ltd. ,https://www.necf.jp/en/service/wastewater.html#anc-2., (accessed on 19.06.19). [76] Y.J. Shih, C.H. Liu, W.C. Lan, Y.H. Huang, A novel chemical oxo-precipitation (COP) process for efficient remediation of boron wastewater at room temperature, Chemosphere 111 (2014) 232
237. [77] Z. Guan, J. Lv, P. Bai, X. Guo, Boron removal from aqueous solutions by adsorption
a review, Desalination 383 (2016) 29
37. [78] Kurita Water Industries Ltd. ,https://www.kurita.co.jp/products/boron.html. (accessed on 19.06.19). [79] P. Co´rdoba, Partitioning and speciation of selenium in wet limestone flue gas de sulphurisation systems: a Review, Fuel 202 (2017) 184
195. [80] H. Akiho, S. Ito, H. Matsuda, T. Yoshioka, Elucidation of the mechanism of reaction between S2O822, selenite and Mn21 in aqueous solution and limestone-gypsum FGD liquor, Environ. Sci. Technol. 47 (19) (2013) 11311
11317. [81] P.K. Petrov, J.W. Charters, D. Wallschl¨ager, Identification and determination of selenosulfate and selenocyanate in flue gas desulfurization waters, Environ. Sci. Technol. 46 (3) (2012) 1716
1723. [82] Japanese Patent 1997
477790 (1997); 2011
72940 (2011); 2014
53249, Japan Patent Office (2014). [83] Japanese Patent 2009
11915 (2009); 2015
39651, Japan Patent Office (2015). [84] Kurita Water Industries, Ltd. ,https://www.kurita.co.jp/english/aboutus/press100422. html. (accessed on 19.06.19). [85] Y. Muramatsu, N. Suzuki, T. Hashikawa, Operation performance of selenium removal equipment for FGD wastewater at a coal-firing thermal power plant, Therm. Nucl. Power 65 (5) (2014) 348
352 (in Japanese).

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[86] S. Ohyama, Online monitoring technology of selenium concentration in process effluents for process management, Nihon Enerugii Gakkai Kikanshi Enermix 96 (6) (2017) 788
795 (in Japanese). [87] S. Ohyama, A. Aota, Development of Simplified Monitor for Selenium in Aqueous Solution (Part 6)
Long-Term Online Monitoring of Selenium Concentration in Flue Gas Desulfurization Wastewater, CREPI Research Report, V15013, 2016 (in Japanese).

Introduction to boilers

2

Mamoru Ozawa Kansai University, Osaka, Japan

Chapter Outline 2.1 2.2 2.3 2.4

Start of steam application to pumping water 57 Dawn of steam power 59 Classification of boilers 61 History of boiler development 61 2.4.1 2.4.2 2.4.3 2.4.4

Cylindrical boiler development 63 Development in water tube boiler 66 Once-through boiler 87 Summary of boiler development 98

2.5 Historical development of power generation boilers in Japan 99 2.6 Similarity law in boiler furnace and other various important issues 99 References 103

2.1

Start of steam application to pumping water

The first trial of steam to generate power for mechanical motion might be Heron’s rotating machine at around CE 100, while the machine was not a practical engine to produce useful power. Practical applications of steam to produce power started at around the end of the 17th century, while Giovanni Branca’s concept appeared at the beginning of the century [1]. In the meantime, wind- and/or water mills were prime mover to support human life. The unit power of these mills was at most 8 kW [2], which is suitable for the demand from society. At that time, coal was utilized as the fuel for heating, and later iron making. This latter application enhanced the coal mine industries while essentially induced the necessity of pumping water from coal mines. The depth of coal mine in England reached 120 m. Thus the pumping of water was an essential task. Practical application of steam for pumping water might start Edward Somerset’s Water-Commanding Engine or Marquis of Worcester’s Engine [3,4]. Shortly after Somerset, Thomas Savery was granted the patent Machinery for Raising Water, Giving Motion to Mill in 1698. Fig. 2.1 shows Savery’s The Miner’s Friend [5]. This machine was based on the concept that the pressure difference is generated between the ambient air and the vacuum induced with condensation by cooling a steam-filled cylinder. Then the water sucked into the cylinder was raised upward by the use of steam pressure from the spherical-shaped boiler. On the other hand, Papin [6] proposed a fundamental idea shown in Fig. 2.2 to generate power by Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00002-3 © 2021 Elsevier Inc. All rights reserved.

58

Figure 2.1 Savery’s The Miner’s Friend [5].

Figure 2.2 Papin’s steam engine [6].

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Introduction to boilers

59

introducing a piston. His principal idea was further extended to construct practical steam engine by Thomas Newcomen and later James Watt.

2.2

Dawn of steam power

The concept of Papin is not separated between the sections of steam generator and prime mover, while Thomas Newcomen separated steam generator, that is, boiler, with large heat capacity from the section to produce power, that is, cylinder and piston. In addition to this, Newcomen introduced direct-contact condensation, with which rapid generation of vacuum is realized leading to practical steam engine. Fig. 2.3 shows such Newcomen’s steam engine. The Newcomen’s boiler is usually referred to as haystack boiler, being constructed by soldering and/or brazing small copper plates similarly to distillers of brandy or whiskey. The materials of such boiler were later changed to wrought iron, and rivet joint was introduced. The materials transited to cast iron, again wrought iron produced by pudding furnace, and steel in the middle of the 19th century. Haystack boilers of Newcomen engines are shown in Fig. 2.4. The right-ended boiler was the Smeaton’s cast-iron boiler (1773). Based on the detailed investigation of Newcomen’s engine, James Watt further separated functions of power generation process, that is, the introduction of separated condenser from cylinder
piston system. His research and development was further extended to rotating machine with a pinion gearing and later crank, introduction of steam flow control by governor, pressure, and water-level control. In a sense, Watt founded the principal concept of steam engine leading to the present systems. Watt first used conventional haystack boiler, while later wagon-type boiler was utilized for his engines. The wagon-type boiler is exemplified in Fig. 2.5.

Figure 2.3 Newcomen’s steam engine (1712). Source: Drawn by the author referring to R.H. Thurston, A Manual of Steam-Boilers: Their Design, Construction, and Operation, John Wiley & Sons, New York, 1888, p. 6. [7]

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Figure 2.4 Haystack boilers for Newcomen’s engine [8].

Figure 2.5 Wagon-type boiler [9].

Figure 2.6 Technology transition from Newcomen- to Watt-type engines. Source: Data from L.T.C. Rolt, J.S. Allen, The Steam Engine of Thomas Newcomen, Landmark Pub., Ashbourne, 1993. [10]

Technology transfer is not drastic at that time. As shown in Fig. 2.6, the cumulated number of Newcomen engines increase after the appearance of Watt’s highefficiency engine. In some sense the engine users were conservative to risks of newly developed technologies, that is, it took relatively long period and many experiences to prove being useful for the fundamental infrastructure.

Introduction to boilers

2.3

61

Classification of boilers

Essential features or processes of fossil fuel
fired boilers are combustion process, water circulation with heat transfer through wall, water treatment, and also steam
water separation. Among these processes, water circulation has substantial importance in boiler technology. This is mainly because heating process may be altered to electric heating or nuclear fission process. The fuels are not limited to fossil resources but are alternated to incineration or solar thermals. On the other hand, steam and/or some vapor are not replaced by other means or not removed. Here the concept of water circulation involves boiling process at the heated wall. Locally, bubbles are formed on the heated wall, and these bubbles are smoothly removed, and water is substituted there. Otherwise, the heated wall may become red hot, that is, overheated beyond the limited range of temperature. Such a process may be considered as an extended concept of the water circulation. Based on such concept, boilers are classified into dominant categories: submerged cylindrical type, water tube type, and once-through type [11]. Typical examples of cylindrical ones are demonstrated by the simple cylindrical boiler heated outer wall of the drum having large amount of water. This type includes tubular or smoke-tube boiler, flue-tube boiler, and flue- and smoke-tube boiler. In such boilers, water, in principle, stays still in the vessel, that is, drum, and is circulated within the drum induced by bubbles generated on the heated wall. The difference among the abovementioned type is the degree of extension of heating surface for efficient use of thermal energy generated by the combustion of fuels. The second type of boiler, water tube boiler, includes submerged water tube boiler, natural-circulation boiler, and forced-circulation boiler. It may be easily understood that the tube is high in strength against pressure, and heating area becomes rather large relative to the conventional cylindrical boilers. Submerged water tube boiler is, in principle, the same concept with the cylindrical boiler in the context of water circulation, while in the natural- and forced-circulation boiler, water is circulated through the circuit of tube. Natural circulation is induced by the driving force, that is, difference between water heads of downcomer and riser or steam-generating tube. In the forcedcirculation boiler, water circulation is assisted by pump. The last once-through boiler is constructed by water tubes as well, while water is, in principle, not circulated through the circuit but is forced to flow throughout the tubes from the inlet as water to exit as steam. Thus the principle of water circulation is different from the abovementioned water tube boilers. These boiler classifications and the related problems to be solved are listed in Table 2.1. The development of boiler is the process of enhancement of boiler efficiency and scale-up to produce large steam output. In the next section the boiler development is historically traced.

2.4

History of boiler development

Fig. 2.7 shows the historical trend of boiler development starting from Newcomen to the present state of power boiler technology. At the same time, steam pressure

Table 2.1 Boiler classification and related problems. Category

Type of boiler

Water circulation

Gas circulation

Furnace

Common problems

Safety measures

Cylindrical

Simple cylindrical boiler Tubular (smoke-tube) boiler Flue (furnace)-tube boiler Flue- and smoke-tube boiler Submerged water tube boiler Natural-circulation boiler

Submerged

Outside shell

Brick walled Brick walled Flue tube

Construction Materials Incrustation Inside corrosion Outside corrosion Priming Superheat and burnout Creep Deterioration Explosion Water treatment Flue-gas treatment

Water-level control Pressure control Safety valve Registration and inspection Insurance Boiler code

Water tube

Oncethrough

Forced-circulation boiler Once-through boiler

Outside shell and smoke tube Single- and multiple-flue tubes Flue tube and smoke tube Submerged

Outside of tube

Inclined water tube Vertical water tube

Outside of tube

Natural and forced Forced flow

Flue tube

Outside of tube Outside of tube

Brick walled Brick walled Brick walled Waterwall Waterwall

Outside of tube

Waterwall

Outside of tube

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63

Figure 2.7 Development of boiler at a glance. Source: Data from S. Ishigai, Design Principles of Steam Boiler, Sankaido, Tokyo, 1961, pp. 58
59; Report from the Select Committee on Steam Boiler Explosions; together with the Proceedings of the Committee, Minutes of Evidence, and Appendix, The House of Commons, 1870; The Manchester Steam Users’ Association (MSUA), A Sketch of the Foundation and of the Past Fifty Years’ Activity of the Manchester Steam Users’ Association for the Prevention of Steam Boiler Explosions and for the Attainment of Economy in the Application of Steam, Taylor, Granett, Evans, & Co., Manchester, 1905; K. Akagawa, Thermal and Hydraulic Design of Steam-Generation Systems, in: S. Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 276
283 [12
15], Central Research Institute of Electric Power Industry, and Thermal and Nuclear Engineering Society.

and temperature data of boilers are plotted. As mentioned earlier, the practical application of steam power started from Newcomen and Watt engines. Both were operated at around atmospheric pressure, and motive force was generated by the difference between the atmospheric pressure and the vacuum in the cylinder. To generate larger power, it is necessary to raise steam pressure and temperature. At this time, steam superheater was not developed, and the engines were referred to as atmospheric engines. This is reasonable from the standpoint of material and constructing technologies underdeveloped. In accordance with the development of industrial technologies, the steam pressure and temperature increased, and the boiler type changed water tubetype and once-through boilers. Up to around 1900 the steam temperature remained at saturated temperature and increased rapidly by the introduction of superheater. Detailed discussion may be found in the next section. Since around 1980, variable pressure supercritical boilers have become a dominant type for power generation. In the following the boiler development of each type is traced.

2.4.1 Cylindrical boiler development In 1800 Watt’s patent expired, and so-called high-pressure engine appeared. Typical example was the Trevithick engine, being constructed by cast iron shown in Fig. 2.8.

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Figure 2.8 Trevithick’s Camborne road carriage, 1802 [16]. Source: Reproduced with permission of the Licensor through PLSclear.

Figure 2.9 Trevithick’s wrought-iron boiler, 1812 (p. 121 of [1]). Source: Reproduced with permission of the Licensor through PLSclear.

His cast-iron boiler exploded, and he introduced various safety measures. One improvement was an adoption of wrought iron, and fusible plug for safety measure. Such improvements are exemplified in wrought-iron boiler shown in Fig. 2.9, being later called Cornish boiler. Trevithick introduced a flue tube, that is, furnace was installed within the drum, which is a very important improvement in heat transfer and construction. Then the heat released by the combustion is rather efficiently transferred to the surrounding mass of water. Flue gas may be returned around the drum if the boiler is installed on the brickwork; and/or if smoke tubes are added, flue gas is circulated through the submerged water, and then the brickwork may be removed. In addition, the highest heat flux is found around the flue tube, and the bottom of boiler, sedimented various contaminated materials or muds are free from deterioration of heat transfer. Trevithick’s concept made it possible to make boiler compact, leading to the development of locomotive boiler of Robert Stephenson.

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Figure 2.10 Woolf’s cast-iron sectional boiler, 1803 [17].

The scale-up and enhancement of boiler efficiency are realized by applying water tubes with cast iron, that is, Arthur Woolf’s sectional boiler, and William Fairbairn’s Lancashire boiler. The former consisted of smaller diameter water tubes absorbed radiant heat from coal firing, and larger diameter tube, actually steam drum, installed perpendicular to the water tubes at the upper level, as shown in Fig. 2.10. All waterubes are connected with upper drum via downcomers, respectively. Even the cast iron may be applicable to high-pressure boiler, when the temperature fluctuation is small. An increase in the steam generation rate is covered by an increase in the number of water tubes. The flue gas flows zigzag path around the water tube that enhanced heat transfer performance outside the tubes. The technology development in materials and construction, for example, punching machine, plate rolling machine, and riveting machine enabled an appearance of high-performance Lancashire boiler shown in Fig. 2.11. Lancashire boiler patented by William Fairbairn 1844 has two flue tubes, and an increase in steam generation rate is conducted by an elongation of boiler and flue tubes or by an additional flue tube, for example, three flue-tubes. The standard dimensions of such type of boilers are listed in Table 2.2. The fuel for steam boilers was coal of large size. For full burning of lump of coal, it is necessary to distribute uniformly, and the coal bed height should be relatively low. Burning, that is, heat release rate, per unit area of fire grate, is limited at low level under the natural draft induced by chimney. Then an enhancement in steam generation is essentially led to an extension of fire-grate area. Thus multipleflue tube boiler was one of reasonable solutions for scale-up of boilers.

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Figure 2.11 Lancashire boiler [18].

Table 2.2 Standard dimensions of flue-tube boilers in Germany at around 1920.

Diameter of boiler (m) Diameter of flue tube (m) Length (m) Heat transfer area (m2) Fire-grate area (m2) Water volume (m3) Steam volume (m3)

Cornish boiler

Lancashire boiler

Three-flue boiler

1.1
2.2 0.55
1.35 3.5
11 11.4
88 0.38
2.86 1.7
20.8 0.6
5.4

1.7
2.5 0.6
1.05 5.5
12.5 35,140 1.08
4.4 6.5
29.8 2.3
9.7

2.5
3.0 0.7
1.15 10.5
15 134.3
247.9 4.4
8.1 25.6
50 7.4
11.7

Source: Data from S. Ishigai, Design Principles of Steam Boiler, Sankaido, Tokyo, 1961, pp. 58
59 [12]; R. Spalckhaver, Fr. Schneiders und A. Ru¨ster, Die Dampfkessel nebst ihren Zubeho¨rteilen und Hilfseinrichtungen, Verlag von Julis Springer, Berlin, 1924, p. 125
141. [19]

Lancashire boiler is further advanced to include smoke tubes, then the heat transfer surfaces increased drastically. Typical example is so-called Scotch boiler, exemplified in Fig. 2.12, well-known Titanic installed 29 Scotch boilers that produced a total 46,000 HP. Scotch boiler is, in general, referred to as flue- and smoke-tube boiler, being characterized by stable operation even against fluctuation of steam demand, and therefore very useful means for district heating/cooling system. The technology transition, in general, is conducted as first appearance with small capacity and number, alternate with the conventional system, rapid increase in capacity and number, and another newcomer is substituted and thus decreases in number. Such alternate process of boilers is exemplified in Fig. 2.13.

2.4.2 Development in water tube boiler In Woolf’s primitive water tube boiler, water is not actually circulated but flows back and forth in the same tube. Considering smooth replace of bubble with water, such a flow situation may easily bring about burnout, when heat flux is high enough. Similar concept boiler is shown in Fig. 2.14, John and Frederick Howards’ boiler.

Introduction to boilers

Figure 2.12 Scotch boiler for steamboat, 1900 [8].

Figure 2.13 Transition of boiler type in Japan. Source: Data from Japan Boiler Association.

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Advances in Power Boilers

Figure 2.14 Howard’s boiler, 1866 [20].

Water is supplied at the feedwater inlet, while water is actually stagnant and water circulation does not occur in the water tubes, being not suitable at high heat flux condition. To improve water coirculation, Edward Field and Jules & Albert Niclausse applied double tube
type evaporator, where subcooled water flowed through core tube, and two-phase mixture flowed back through annulus. To assure water circulation, downcomer was introduced, while probably the first trials were conducted by Joseph Eve (1825) and Goldsworthy Gurney (1826) as shown in Fig. 2.15, and later, for example, Julien Belleville (1855) , and Benjamin Root (1873). The Belleville boilers exemplified in Fig. 2.16 were installed on many fighting ships of French, English, and later Japanese navies. The merits of this Belleville’s boiler are summarized as easy in cleaning tubes, rapid response owing to small water volume (inventory) in the boiler, and also weak effect of explosion. In such boilers with water circulation, however, the circulation rate of water was naturally at low level. In the Belleville boiler, water flow through the downcomer was in a free-fall state, being quite different from so-called natural-circulation concept. A substantial development in water tube boiler was conducted by George Babcock and Stephen Wilcox. Their sectional boiler patented in 1867 is shown in Fig. 2.17. They realized sound circulation of water, ease in scale-up, and stable steam generation. The left-sided vertical section was a downcomer, connected straight steam generation tubes inclined gently, and led to vertical riser and upper large diameter tubes. These parts consist of each section, horizontally arranged. Every tube end has a plug so that cleaning of inner wall was easily conducted. An application of straight

Introduction to boilers

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Figure 2.15 Gurney’s water tube boiler, 1826 [21].

Figure 2.16 Belleville’s boiler, ca.1890 [20].

pipe is based on this cleaning, because water treatment was not sufficiently established at that time. The gentle inclination of tubes might be also the same background. Considering the natural-circulation performance, steeply inclined or vertical arrangement of steam-generating tubes and downcomer is preferable, that is, natural circulation is induced by a difference in gravitational pressure drop between these tubes.

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Figure 2.17 Babcock & Wilcox’s sectional boiler, 1867 [21].

Alan Stirling started R&D of boiler in 1883, and he put his developed steeply inclined three-drum boiler in the market. Then he developed four- and five-drum boilers successively. Fig. 2.18 is his four drum
type Stirling boiler patented in 1892. Owing to the steeply inclined arrangement, so-called rapid circulation was realized, while in the mud drum the water is almost stagnant, and thus the mud or some contaminated matters owing to usage of impure water settled there. A difference from Babcock & Wilcox’s boiler shown in Fig. 2.17 is an installation of curved pipe and large diameter multiple drums connected. The rapid circulation enabled to reduce nonuniformity of the temperature of tube banks. In addition, most of the materials of boiler were wrought iron and mild steel. Even though the rapid circulation, the cleaning of the tubes was necessary, and therefore hydraulic turbine tube cleaner was also developed. When saturated steam was supplied to a steam engine, an increase in the steam pressure is naturally followed by an increase in steam temperature. This increase in steam temperature enhances the boiler efficiency, of course, being dependent on the development in tube materials for high-temperature use. Steam pressure was almost equal or slightly higher than the atmospheric pressure before 1800. The rapid increase in steam pressure started around 1840
50, which was supported by the combustion technology, water wall design, introduction of air and water preheaters, and of course water-treatment technology, while an increase in boiler explosions was brought about as will be described in Chapter 9, Boiler Explosion and Inspection.

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Figure 2.18 Four drum
type Stirling boiler, 1892 [22].

Such an example is shown in Fig. 2.19, where chain-grate stoker was introduced. By installing tube banks in a large furnace, applicability of various kinds of fuels was highly extended. As is easily understood, the lump of coal needs relatively long period so as to fully burn, and also coal contains moisture and ash, both are inconvenient for efficient use of energy. In addition, the contents of these moisture, ash, char, etc. are different among coals. To cover such problems and to assure steady burning, mechanical stokers were developed. Probably, the first successful mechanical stoker was first introduced by William Brunton in 1819 and later by John George Bodmer in 1834. Their stoker was so-called traveling stoker. The chain-grate stoker was developed by John Jukes in 1841. Further, the inclined stoker was introduced, and sufficient space for burning was provided [24]. The historical trend of arrangement of stoker in a furnace space is shown in Fig. 2.20 [24]. Source: Reproduced by permission from E.L. McDonald, Improvement in Missouri-Kansas coal and their burning equipment, Trans. ASME 54 (1932), 91
98 (FSP-54-10) [25] In advancing boiler technology the furnace height increased in accordance with an increase in steam output. This is mainly because of ensuring sufficient residence time for burning of large amount of coal needed to generate large amount of steam. In the figure, only flat stokers are presented, while various types of stokers, for example, underfeed, top feed, inclined as mentioned earlier, and spreader stokers. One of the typical examples of chain-grate stoker is shown in Fig. 2.21.

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Figure 2.19 Five drum
type Stirling boiler with chain-grate stoker and superheater [23].

Figure 2.20 History of furnace design (arrangement of stoker and tube bank in furnace).

Inclined-type stoker is exemplified in Fig. 2.22, being developed around 1930. Piston pushes the coal into the coal bed from lower side. Burning coalbed traverses successively on the inclined stoker supplied with sufficient air from the lower side of stoker. To enhance rapid burning of coal and to make easy to regulate, the size of coal is preferably small. The first trials of pulverized coal combustion were for internal combustion engine, iron refinery process, and rotary kiln for cement production.

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Figure 2.21 Jukes’ chain-grate stoker, 1841. Source: Reproduced by permission from J.G. Worker, T.A. Peebles, Mechanical Stokers, McGrow-Hill, New York, 1922, pp. 23
40. [24]

Figure 2.22 Taylor-type underfeed inclined stoker. Source: Reproduced by permission from F. Mu¨nzinger, Dampfkraft—Berechnung und Bau von Wasserrohlkesseln und ihre Stellung in der Energieerzeugung, Verlag von Julius Springer, Berlin, 1933, p. 190 [26].

Practical application of pulverized coal to boilers was at the end of 1880 to the beginning of the 1900s. Among them, examinations at Oneida Street and Lakeside plants shown in Fig. 2.23 are very famous. The specifications of these boilers are listed in Table 2.3.

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Figure 2.23 Boiler with pulverized coal burner of Lakeside power station. Source: Reproduced by permission from F. Mu¨nzinger, Americanishe und deutsche Großdampfkessel, Verlag von Julius Springer, Berlin, 1923, pp. 39
48. [27].

Table 2.3 Specification of pulverized coal boilers at the beginning. Power station

Oneida

Lakeside

Lake Shore

Type of boiler Volume of furnace (m3) Steam temperature ( C) Steam pressure (MPa) Steam generation (t/h) Boiler efficiency (%)

Edge Moor 45.3 220.5
228.9 1.27
1.29 B8.7 82.7
85.1

Edge More 177 290.0
318.3 1.86
1.98
91.0
93.8

Stirling 736 323
337 1.74 B44 85.9
88.3

Source: Data from F. Mu¨nzinger, Americanishe und deutsche Großdampfkessel, Verlag von Julius Springer, Berlin, 1923, pp. 39
48 [27]; J. Wolf, Test of pulverized-fuel-fired boilers at the Lake Shore Station, Cleveland, Mech. Eng. ASME 47 (1) (1925), pp. 25
29. [28]

Table 2.4 summarized the water tube arrangement up to around 1910. General trends show the transition from gently inclined straight tubes without downcomer, gently inclined straight tubes with downcomer, and to steeply inclined curved tubes with downcomer. To enhance gas-side heat absorption, an economizer is an important element. The economizer was developed by Edward Green at around 1845, and the example is shown in Fig. 2.24. Coal is not free from ash, and heat transfer tubes often suffer from fouling of ash and some pollutant matters. The devices attached around water tubes are scrapers, and upper located ones are driving systems of scrapers. By such economizer, flue gas is cooled down to a sufficient level, while low-temperature corrosion may be

Table 2.4 Tube arrangement until 1910. Year

Inventor

Water tube materials

1776 1788 1793 1803 1803 1815

William Blakey Nathan Read Joel Barlow Arthur Woolf John Stevens Humphrey Edwards

Copper

1815 1825 1825 1837

Richard Trevithick Joseph Eve Goldsworthy Gurney J. A. Schubert

1840 1845

Ernst Alban John Penn

Copper

1847

Ernst Alban

Wrought iron

1855 1856

Julien Belleville Stephen Wilcox and O. M. Stillman Loftus Perkins Edward Field Joseph Twibill Howard Julien Belleville

Wrought iron

1861/78 1862 1865 1866 1867

Diameter (mm)

Length (m)

Cast iron Cast iron and wrought iron (1825) Wrought iron Wrought iron

Wrought iron Steel Wrought iron Wrought iron Wrought iron

Configuration of tube

Downcomer

Inclined straight Vertical tube Horizontal straight Horizontal straight Gently inclined straight Horizontal straight

Without downcomer Without downcomer Without downcomer With cross tube Without downcomer With cross tube Without downcomer With downcomer With downcomer Cylindrial with water tube Without downcomer Cylindrial with water tube With water-chamber (downcomer) Without downcomer With water-chamber (downcomer) Without downcomer Double tube With downcomer Without downcomer Without downcomer

330 38
64 32 80

2.6

1.0

Vertical straight Vertical curved Gently inclined curved Gently inclined straight

102 70

1.3
1.9 1.0

Gently inclined straight Gently inclined straight

B6

Gently inclined straight Vertical Gently inclined curved

76 57

1.2

230 70

3.1 2.1

Horizontal straight Vertical straight Inclined straight Gently inclined straight Horizontal U-bend

(Continued)

Table 2.4 (Continued) Year

Inventor

Water tube materials

Diameter (mm)

Length (m)

Configuration of tube

Downcomer

1869 1871

Wrought iron Wrought iron

102 230

3
5.5 3.1

Gently inclined straight Gently inclined straight

With downcomer Without downcomer

100
127

2.84
4

Gently inclined straight

Without downcomer

1874 1878

Babcock & Wilcox John & Frederick Howard Benjamin Root (Walther & Co.) L. & C. Steinmu¨ller L. & C. Steinmu¨ller

95 60, 95

3
5

Gently inclined straight Gently inclined straight

c.1884
85 1889

Babcock & Wilcox Alfred Yarrow

Steel Seamless steel

59
203 45

1.8
5.5

With downcomer With water-chamber (downcomer) With downcomer With downcomer

1890 1890 1892/93 1893/94 1894 1894 1896 c.1910

Alexander Chaplin Jules & Albert Niclausse Alan Stirling Gustav Du¨rr R. Schulz John Isaac Thornycroft Julien Belleville A. Bu¨ttner

Steel tube Seamless steel Seamless steel

57 80 83 80
114 36

0.8

96
139 95

2
2.2 3.7
5

c.1910

Herman Garbe

60

3.5
4.5

1870/73

Wrought iron

2
4.5

Gently inclined straight Steeply inclined straight Vertical Gently inclined straight Steeply inclined curved Gently inclined straight Steeply inclined curved Steeply inclined curved Gently inclined straight Steeply inclined straight Steeply inclined straight

Without downcomer Double-tube With downcomer Double-tube With downcomer With downcomer Without downcomer With water-chamber (downcomer) With downcomer

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Figure 2.24 Green’s economizer, ca.1845 [29].

brought about below a certain limited level of flue gas temperature, especially for coal-fired boilers. Another important problem is water treatment that must be discussed before the second-stage development of boilers. Water problems are classified mainly into scale formation, corrosion, and priming/forming. The beginning of boiler development, normal river water, and/or underground water is used for feedwater. On the other hand, steamboat utilized seawater when the steam condenser had not been developed. Probably, the oldest paper on the scale formation is of Payen [30]. He found an effectiveness of potato against scale formation in marine boilers. In addition, oil, fat, sawdust, clay, ammonia compound, caustic soda, talc, starch, etc. are listed up in 1854 published paper by Elsner [31]. Before the development of chemistry the countermeasures for scale formation were, in principle, based on experiences. Christie has reviewed boiler water [32], which is reproduced in Table 2.5. Fig. 2.25 shows typical example of incrustation by Christie. Investigations for water treatment are typically demonstrated in Fig. 2.26. Fig. 2.26 shows transition of the number of published papers on water treatment in Polytechnischen Journals from 1820 to 1931. In the period 1860
90, papers on incrustation have been so often published, while the corrosion problems are focused slightly later, and around 1930 much more investigation were conducted. A Stirling boiler was developed during such period. Comprehensive investigation of the incrustation was conducted by Partridge [33]. He presented nomogram on heat transfer. Similar nomogram is shown in Fig. 2.27. Based on the thickness of boiler scale, thermal conductivity of scale, and heat flux, the wall superheat is easily estimated graphically. As to the corrosion-related trouble, inside and outside of boiler tube are summarized as shown in Fig. 2.28.

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Table 2.5 Boiler water trouble and countermeasure. Trouble/cause

Countermeasure

Incrustation Sediment, mud, clay Soluble salts Bicarbonate of magnesia, lime, iron Sulfate of lime

Filtration, blow off Blow off Heating feedwater and precipitate, caustic soda, lime, magnesia Sodium carbonate, barium chloride

Corrosion Organic matter Grease Chloride or sulfate of magnesium Acid Dissolved carbonic acid and oxygen Electrolytic action

Precipitation with aluminum or ferric chloride and filter Slaked lime or carbonate of soda and filter carbonate of soda Alkali Slaked lime, caustic soda, heating Zinc plates

Forming/priming Sewage Alkalies Carbonate of soda

Precipitate with aluminum or ferric chloride and filter Heating and precipitate Barium chloride

Source: Data from W.W. Christie, Boiler-Waters Scale, Corrosion, Forming, D. Van Nostrand Co., New York, 1906. [32]

Figure 2.25 Typical incrustation [32].

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79

Figure 2.26 Transition of the number of published papers on water treatment. Source: Drawn by the author.

Figure 2.27 Effect of scale on heat transfer (calculation nomogram). Source: Drawn by the author referring to E.P. Partridge, Formation and properties of boiler scale, in: Engineering Research Bulletin, No. 15, Department of Engineering Research, University of Michigan, 1930. [33]

These water-treatment problems are partly solved by introducing steam condenser and in accordance with the development in chemistry, while the water treatment is still an important issue at present.

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Figure 2.28 Boiler tube deterioration. Source: Data from I.G. Salter, N.L. Parr, Marine Boiler Deterioration, Proc. Inst. Mech. Eng. 160 (1) (1949), pp. 341
358. [34]

Figure 2.29 Development of waterwall: (A) spaced tube, (B) studded, (C) tangent tube, and (D) membrane. Source: Reproduced by permission from T.B. Hurst, C.C. Hamilton, Industrial boiler design, Mech. Eng. ASME 82 (1960), pp. 52
57. [35]

The scale-up of the boiler essentially led an increase in furnace size. Then, relatively large amount of thermal energy is absorbed by the fireproof brickwork surrounding the furnace. This means that the dynamic response of the steam output becomes delayed by the large heat capacity of the brickwork, and that the heat release from the furnace wall becomes significant, while the stability of steam output is ensured. To remove such a problem, waterwall was used instead of brickworks surrounding the furnace. Historically, the types of waterwall transit from spaced tube, studded (finned tube), tangent tube, and membrane wall as is illustrated in Fig. 2.29. In the course of technology development, a new system is often added to so-far used conventional system to form intermediate combined type. As mentioned earlier, there are two types of water tube arrangement, that is, gently inclined and steeply inclined. The combined-type boiler naturally succeeded the tradition of construction. The first class is typically exemplified by Babcock & Wilcox’s sectional

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81

Figure 2.30 Babcock
Boiler gently inclined single-drum sectional boiler, 1928. Source: Reproduced by permission from A. Loschge, Die Dampfkessel, Verlag von Julius Springer, Berlin, 1937, p. 195. [36]

boiler, shown in Fig. 2.30. In the upper part of furnace, conventional Babcock
Wilcox-type boiler is installed, and the furnace is surrounded by the waterwall with downcomer and riser from and to the steam drum. Thus this type of boiler consisted of two circulation lines. Another system with steeply inclined water tubes is exemplified in Fig. 2.31. Two sets of conventional Stirling boilers are arranged across from each other, installed in the upper part of the furnace surrounded by waterwalls. The final style of so-called radiant boiler leading to the present technology is shown in Fig. 2.32. This boiler was examined especially for furnace heat absorption by ASME, and detailed temperature distribution with ash adhesion on the waterwall surfaces was reported. These data became a basis for radiative heat transfer in a furnace design. The natural circulation is based on the difference between gravitational pressure drops of riser and downcomer. A primitive but substantial approach was conducted in 1896 by Alfred Yarrow and his company as shown in Fig. 2.33 Then Ch. Bellens [40], Gensch [41], Hoefer [42], and very famous Mu¨nzinger [43] conducted various experiments. Especially the first theoretical approach was conducted by Mu¨nzinger [43]. He formulated force balance of natural circulation based on the assumption of homogeneous two-phase flow model as, F

h 2h5




hFe

1 hFR

 v21 ρw 1ξ 1 ½he 1 hBe 1 hR 1 hB 1 ha  ρ0 g

(2.1)

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Figure 2.31 Combustion engineering’s pulverized coal combustion double Stirling boiler, 1929. Source: Reproduced by permission from W.J. Wohlenberg, H.F. Mullikin, W.H. Armacost, C.W. Gordon, An experimental investigation of heat absorption in boiler furnaces, Trans. ASME 57 (1935), pp. 541
554. [37]

The left-hand side corresponds to the driving force given by the water head of downcomer and that of riser. The first square bracket corresponds to the flow resistance in the downcomer and the second one to the riser. The superscript F denotes values of downcomer and subcripts e, R, B, Be, a denote inlet pressure loss, friction loss, acceleration loss, acceleration loss at the riser inlet, and exit pressure loss of the riser, respectively. Applied the homogeneous flow model, the water head of the riser is given by h5

1 ρ0 g

ðL 0

ρgdl 5


   Lρw ρD ρ 2 ρD ln 1 1 w x2 ; ρ0 ρw 2 ρD ρD

(2.2)

where ρ0 denotes the water density at 4 C, ρw ; ρD demote densities of saturated water and steam, respectively, L is the length of the riser (downcomer), g is the gravitational acceleration, and x2 is the steam quality of the riser exit. Based on his model, calculation example is shown in Fig. 2.34. In Fig. 2.34, experimental results are plotted as well, around 0.2 m/s lower in the circulation velocity. This difference is caused by the homogeneous flow model, that is, relative velocity or slip velocity between phases is neglected. Later, Schmidt [44] conducted flow visualization study and various measurements with his coworker.

Figure 2.32 Foster Wheeler’s pulverized coal-fired single-drum radiant boiler of Paddy’s Run power station, 1947. Source: Reproduced by permission from R.I. Wheater, M.H. Howard, Furnace heat absorption in Paddy’s Run pulverized-coal-fired steam generator, using turbulent burners, Louisville, Ky. Part I. Variation in heat absorption as shown by measurement of surface temperature of exposed side of furnace tubes, Trans. ASME 72 (1950), pp. 893
923. [38]

Figure 2.33 Yarrow’s experimental setup for natural circulation. Source: Reproduced by permission from C, Eleanor, Barnes (Lady Yarrow), Alfred Yarrow
His Life and Work, Edward Arnold & Co., London, 1923, pp. 123
138. [39]

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Figure 2.34 Circulation velocity and exit quality by Mu¨nzinger model (heated length 6 m, pressure 0.98 MPa G). Source: Data from F. Mu¨nzinger, Untersuchungen an Steilrohrkesseln—Der Wasserumlauf in Steilrohrkesseln, Z. Ver. Dtsch. Ing. 64 (25) (1920) 453
457. [43]

And theoretical model, including slip velocity, and self-evaporation owing to pressure drop, was formulated based on so-called separated flow model. Actually, their investigation is the milestone of two-phase flow researches. Seikan Ishigai and Koji Akagawa collaborated in investigation on the design criteria of natural circulation and presented nomogram shown in Fig. 2.35, based on theoretical considerations and practical data. Two-phase flow investigations were essential so as to formulate two-phase flow properties, design criterion, and design and construction of control and safety system. The history of two-phase flow researches is shown in Fig. 2.36 together with the number of papers on heat transfer published in the ASME Transactions. Data until around the middle of the 1940s corresponds to papers related to boiler development, while those after 1940 related mainly to the nuclear power. In a natural-circulation boiler the circulation velocity increases at first with an increase in heat input, while beyond a certain maximum value, it decreases gradually. This is because the driving force, that is, a difference in gravitational head losses, becomes almost constant owing to very slight increase in the void fraction in higher quality region even though with a significant increase in the friction loss. In addition, flow fluctuation, that is, flow instability, takes place at such condition. This means that the scale-up in steam generation rate is confined to a certain

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Figure 2.35 Steam generation rate per tube. Source: Data from S. Ishigai, K. Akagawa, Boira-no-mizujunkan (Water Circulation in Boiler), Corona Pub., Tokyo, 1959 (In Japanese). [45]

Figure 2.36 History of two-phase flow and heat transfer researches. Source: Data from S.W. Gouse Jr., An Index to the Two-Phase Gas-Liquid Flow Literature, The MIT Press, Cambridge, 1966 and Trans. ASME. [46]

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Figure 2.37 Flow diagram of LaMont boiler.

limited level. To maintain steady but larger circulation of water, a certain forcedflow device, such as pump, is needed, which results in a forced-circulation boiler, that is, the operation range is extended by assisting driving force by circulating pump. LaMont boiler was a typical forced-circulation boiler, being an intermediate type between the natural-circulation boiler and later described once-through boiler. Fig. 2.37 shows the principal feature of the LaMont boiler. The LaMont boiler was first patented in the United States in 1925, while the substantial R&D for practical use was conducted in Herpen-La Mont-Gesellschaft in Berlin. Fig. 2.38 shows an example of LaMont boiler developed by Combustion Engineering Co. An important parameter of the natural- and/or forced-circulation boiler is circulation ratio, being defined as the relative steam generation rate against circulation rate, that is, circulation rate divided by steam generation rate. The inverse of the circulation ratio is approximately equal to the exit quality. Typical specification of the forced-circulation boiler is shown in Table 2.6. Other types of forced-circulation boilers are, for example, SchmidtHartmann boiler, Lo¨ffler boiler, and Atoms boiler. One typical boiler to be listed up is the Velox boiler developed Brown, Boveri Co. around 1932, shown in Fig. 2.39. The flue gas from the pressurized combustor drives gas turbine, which drives air compressor. In the combustor, steam is generated and superheated through the superheater installed upstream the gas turbine. The power generated by the turbine is used for air compressor, being similar to gas turbine engine, while different from the present combined cycle plant in no actual output from the gas turbine. In this sense the Velox boiler is considered to a certain supercharged boiler. This type of boiler covered the range 4
75 t/h steam generation, up to 4 MPa, and 454 C steam temperature [48].

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87

Figure 2.38 Combustion Engineering’s LaMont boiler, ca 1941. Source: Reproduced by permission from F.S. Clark, F.H. Rosencrants, W.H. Armacost, 1825-Lb-pressure topping unit with special reference to forced-circulation boiler, Trans. ASME 65 (5) (1943) 461
477. [47]

Table 2.6 Standard characteristic value of forced-circulation boiler. Boiler pressure

1 MPa class

2 MPa class

3 MPa class

17 MPa class

Circulation ratio Exit quality Exit void fraction

4
8 0.12
0.25 0.75
0.88

5
9 0.1
0.2 0.61
0.78

6
11 0.09
0.17 0.53
0.7

c. 4 B0.25 B0.48

Source: Data from K. Akagawa.

2.4.3 Once-through boiler The R&D for high-efficiency power plants gave rise to a high-pressure and hightemperature steam generation boiler. High pressure of steam, however, essentially

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Figure 2.39 Velox boiler of Brown, Boveri Co., 1932. Source: Reproduced by the permission from F. Mu¨nzinger, Dampfkraft—Berechnung und Bau von Wasserrohlkesseln und ihre Stellung in der Energieerzeugung, Verlag von Julius Springer, Berlin, 1933, p. 190. [26]

Figure 2.40 Benson’s boiler concept. Source: Reproduced by permission from A. Loschge, Die Dampfkessel, Verlag von Julius Springer, Berlin, 1937, p. 195. [36]

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Figure 2.41 State change in Benson boiler. Source: Drawn by the author referring to F. Ohlmu¨ller, The influence of the Benson boiler on the development of power stations, J. Inst. Electr. Eng. 75 (452) (1934), 161
184; A.G., Siemens, Benson boilers for maximum cost-effectiveness in power plants. ,http://www. energy.siemens.com/ru/pool/hq/power-generation/power-plants/steam-power-plant-solutions/ benson%20boiler/BENSON_Boilers_for_Maximum_Cost_Effectiveness.pdf., 2001 (accessed 28.08.19). [50,51]

means the small density difference between steam and water, not appropriate for natural circulation. Mark Benson obtained German patent on his once-through boiler concept as “Process for generation of working steam ready for use at any pressure” in 1922. In his boiler, feedwater was first pressurized to supercritical condition and heated in the boiler, and then depressurization was conducted so as to obtain steam at “any pressure” [49]. His test boiler is illustrated in Figs. 2.40 and 2.41. The test plant of Benson boiler at Rugby, England is composed of two-preheater (process a-f-b), heating section (b-g-m-Cr-h-i-c), pressure reduction by regulator valve (c-d), and superheater (d-e) as exemplified in Fig. 2.41. By changing pressure drop at the valve, any pressure steam was realized. This process was improved in the practical plant of supercritical pressure operation at Siemens-Schuckert cable factory, Berlin to economizer (a-f), radiant heat transfer section in the furnace (f-b-g), transition zone of around critical point of steam (g-m-Cr-h), radiant superheater (h-i-j), and superheater (j-k-l). The heat transfer around critical point becomes deteriorated, and thus the transition zone relatively mildly heated was provided. On the other hand, subcritical operation was followed by economizer (a-f), radiant heat transfer section (f-b-o at lower pressure case, f-b-g-m-n at higher pressure case), transition zone of liquid deficient area at high quality (o-p at lower pressure case, n-h-j-k at higher pressure case), and superheater (p-q at lower pressure case, k-l at higher pressure case).

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Figure 2.42 Benson boiler of Langerbrugge Power Station, 1930. Source: Reproduced by permission from F. Hodgkinson, Latest developments of the Benson boiler I—review of early problems, Mech. Eng. ASME 61 (1939), 217
221. [52]

Figure 2.43 Sulzer monotube boiler. Source: Drawn based on the image of A. Stodola, Der Sulzer-Einrohr-DampferzeugerAufbau/Regelung/Regelversuche, Z. Ver. Dtsch. Ing. 77 (46) (1933) 1225
1232. [53]

The first stage of Benson boiler used spiral windup type water tube arrangement, while later vertical tubes with intermediate headers were applied. One of the examples is shown in Fig. 2.42. Sulzer Brothers developed once-through boiler and applied patent in 1929. Typical tube arrangement is exemplified in Fig. 2.43. Sulzer’s once-through boiler

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91

Figure 2.44 The first practical Ramzin boiler 1932. Source: Reproduced by permission from T. Egusa, Kanryu-boira (Once-Through Boilers), Ohmsha, Tokyo, 1963, p. 20 (In Japanese). [54]

was first single-tube construction, and later parallel-tube system was employed, although called monotube boiler. At the beginning of development of Sulzer boiler, steam
water separator was not installed, while later on installed considering the turbine efficiency and scale formation. The last type of typical once-through boiler was so-called Ramzin boiler developed by Ramzin et al. 1932. The first practical Ramzin boiler is shown in Fig. 2.44. The spiral windup tubes were typical feature of the Ramzin boiler. In summarizing once-through boiler, once-through boilers are categorized into three typical types as shown in Fig. 2.45. Table 2.7 shows comparison among three types of water tube boilers on their share and capacity. Around 1938, Stirling boiler of natural circulation occupied 44%, and Benson boiler followed 30.7%. Averaged value of unit evaporation rate is about 90 t/h, while the latter is smaller, 84 t/h. As mentioned earlier, the oncethrough boiler is developed aiming at larger power boilers than conventional water tube boilers. This is typical feature of technology transition. Although the potential of once-through boiler is rather high, such potential does not come up to the surface in the developing stage. As to the forced-circulation boiler, LaMont boiler had 0.5% share, while another German boiler of Schmidt boiler dominated as 13.8%. As mentioned earlier, the original Benson boiler started as supercritical pressure boiler. By removing pressure reduction process, the Benson boiler becomes supercritical pressure boiler, while not only boiler but also steam turbine must be suitable for supercritical pressure operation. The first supercritical pressure unit was Hu¨lles II power station in 1956, and Philo 6 unit followed in 1957. Tables 2.8 and 2.9 list up the supercritical units started operation in between 1956 and 1965.

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Figure 2.45 Three types of once-through boilers. Source: Drawn by the authors referring to R. Doleˇzal, Durchlaufkessel—Theorie, Bau, Betrieb und Regelung, Vulkan-Verlag Dr. W. Classen, Essen, 1962, pp. 82-84 (Fig. 85-87). [55]

Table 2.7 List of the share of boiler in Germany in October 1938. Category

Type of boilers

Number of boilers

Share (%)

Total evaporation rate (t/h)

Averaged unit evaporation rate (t/h)

Naturalcirculation boiler Forcedcirculation boiler Once-through boiler Total

Stirling Sectional

83.0 5.0

44.0 2.6

7515 361

90.5 72.2

LaMont Schmidt Lo¨ffler Benson Sulzer

1.0 26.0 5.0 58.0 11.0 189.0

0.5 13.8 2.6 30.7 5.8 100.0

90 1538 255 4850 801 15,409

90.0 59.2 51.0 83.6 72.8 81.5

Source: Data from F. Hodgkinson, Latest developments of the benson boiler I—review of early problems, Mech. Eng. ASME 61 (1939) 217
221 [52]; F. Hodgkinson, Latest developments of the benson boiler II. Description of typical installations, Mech. Eng. ASME 61 (1939) 287
294 [56].

Typical trace of pressure, temperature, and mass flow rate of Hu¨ls II 1 supercritical pressure Benson Boiler is illustrated in Fig. 2.46. Hu¨ls II 1 unit has nine feedwater heaters by regenerators, high-pressure turbine, and tandem-compound intermediate-pressure and low-pressure turbines. The fuel was coal and the furnace wad slag-tap furnace. The thermal efficiency of this system was estimated at 41.4%.

Table 2.8 Representative supercritical pressure unit in West Germany, 1956
65. Power station

Start operation

Boiler capacity (t/h)

Turbine capacity (MW)

Type of turbine system

Steam pressure (MPa G)

Steam temperature/reheat temperature/reheat temperature ( C)

Boiler manufacturer

Hu¨ls II, Block 1 Hattingen, Block 1 Hattingen, Block 2 Hattingen, Block 1 Hu¨ls II, Block 2 Gebenstorf II Hattingen, Block 2 Stauginger, Block 1 Stauginger, Block 2 Manheim Wedel, Block 4

1956 1958

260 350

85 107

Condensing Condensing

29.4 23.0

600/560/560 600/525

Du¨rr Du¨rr

1958

350

107

Condensing

23.0

600/525

Du¨rr

1959

175

9

Noncondensing

29.1

525/525

VKW

1960 1962 1963

255 304 175

40 100 9

Noncondensing Condensing Noncondensing

29.4 24.4 28.8

555/530 520/530/530 525/525

Du¨rr Du¨rr VKW

1965

416

270

Condensing

22.1

535/535

B&W

1966

416

270

Condensing

22.1

535/535

VKW

1965 1965

650 520

222 214

Condensing Condensing

23.5 24.5

530/540 540/540/540

B&W Du¨rr

Source: Data from S. Miyaoka, State-of-the-art of supercritical pressure units and their economic efficiency, Therm Power. 16 (11) (1965) 902
916 (In Japanese) (Table 2 p. 904). [57].

Table 2.9 Representative supercritical pressure unit in the United States and the United Kingdom (1956
65).

United States

United Kingdom

Power station

Strat Boiler operation capacity (t/h)

Turbine capacity (MW)

Steam pressure (MPa G)

Steam temperature/reheat Boiler Fuel/burner temperature/reheat temperature manufacturer ( C)

Philo 6 Eddystone 1

1957 1959

306 907

125 325

31.0 34.5

621/566/538 649/566/566

B&W-UP CE/Sulzer

Avon 8

1959

780

250

24.1

593/566

CE/Sulzer

Eddystone 2

1959

1000

325

24.1

566/566/566

CE/Sulzer

Breed 1 Phillip Sporu 5 Tanners Creek 4 Chalk Point 1

1960 1960

1360 1360

450 450

24.1 24.1

566/566/566 566/566/566

B&W-UP B&W-UP

Cyclone burner Pulverized coal/ tangential Pulverized coal/ tangential Pulverized coal/ tangential Cyclone burner Pulverized coal

1964

1900

580

24.1

538/552/566

B&W-UP

Cyclone burner

1964

(1000)

335

24.1

538/566/538

B&W-UP

Chalk Point 2

1965

(1000)

335

24.1

538/566/538

B&W-UP

Hudson 1

1965

(1200)

400

24.1

538/552/566

B&W-UP

1135 1135

375 375

24.1 24.1

593/566 593/566

IC B&W

Pulverized coal, oil Pulverized coal, oil Cyclone burner/ oil



Drakelow C 3 1965 Drakelow C 4 1965

Values in ( ) are estimated ones based on the data of Eddystone 2 Source: Data from R. Doleˇzal, Durchlaufkessel—Theorie, Bau, Betrieb und Regelung, Vulkan-Verlag Dr. W. Classen, Essen, 1962, pp. 82
84 (Fig. 85
87)[55].; T. Kawauchi, Principal planning of 500MW supercritical pressure unit of Chita thermal power station, Therm. Power 16 (11) (1965), pp. 933
947 (Table 1, p. 934). [57].

Introduction to boilers

Figure 2.46 Pressure, temperature, and mass flow rate throughout the Chemische Werke Hu¨ls II 1 unit. Source: Drawn by the author referring to G. Noetzlin, Das neue Kraftwerk Hu¨ls—eine Anlage mit 300 at/600 Frischdampfzustand, Mitt. Ver. Grosskesselbesitzer, 55 (1958) 230
255. [58]

Figure 2.47 Philo 6 supercritical pressure boiler, 1957. Source: Reproduced by permission from S.N. Fiala, First commercial supercritical-pressure steam-electric generating unit for Philo plant, Trans. ASME 79 (1957) 389
407. [59]

95

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Advances in Power Boilers

Figure 2.48 Transition of power generation efficiency. Source: Data from S. Miyaoka, State-of-the-art of supercritical pressure units and their economic efficiency, Therm. Power 1 (11) (1965), 902
916 (In Japanese)(Table 2 p. 904); [60] J. Gubler, Eddystone steam power station, Philadelphia, Sulzer Tech. Rev. 41 (1) (1959), 3
20. [61]

Babcock & Wilcox Co. conducted R&D in Alliance and developed supercritical pressure boiler, referred to as UP (universal pressure) once-through boiler. Fig. 2.47 shows the first commercial plant in the United States, Philo 6 commissioned in 1957. The pressure is rather high 31.0 MPa. The fuel was crashed coal and was burnt by cyclone burner. To reduce the fouling and/or slagging of ash, flue gas recirculation was employed. The boiler efficiency was 89.4%, and power generation efficiency was estimated 38.2%. After the successful construction, Eddystone and many other supercritical pressure units were constructed as shown in Table 2.9. Based on these developments in boiler and steam turbine technologies, the power generation efficiency was successively increased as shown in Fig. 2.48. In harmony with such boiler development, many heat transfer investigations were conducted. As to supercritical pressure, a heat transfer deterioration was an important factor in designing boilers, that is, tube arrangement corresponding to pseudocritical region. Typical heat transfer deterioration was probably reported by Styrikovich and his group as shown in Fig. 2.49. In the pseudocritical region the heat transfer coefficient becomes worse when the heat flux is high enough. Such problems were widely investigated by the Japanese group as well, for example, Nishikawa, Ito in Kyushu University, and also Kawamura et al. and Iwabuchi et al. of MHI Ltd. In 1970s nuclear power stations were extensively constructed and substituted as the baseload power generation system. This means that the load variation burdened on the fossil fuel
fired power stations. DSS (daily start and stop) and partial load operations were one of the countermeasures to such duty. To reduce the effect on the efficiency by the partial load operation, a sliding-pressure boiler was developed. The success of such development depends largely on the development in control and related computer technologies. Typical example of such sliding-pressure supercritical pressure boiler is shown in Fig. 2.50.

Introduction to boilers

97

Figure 2.49 Heat transfer deterioration near pseudocritical region. Source: Data from M.A. Styrikovich, T.K. Margulova, Z.L. Miropol’slii, Problems in the development of designs of supercritical boilers, Therm. Eng. 14 (6) (1967) 5
9. [62]

Figure 2.50 Pulverized coal-fired supercritical sliding-pressure once-through Benson boiler at Tachibana-wan. Source: Courtesy of Mitsubishi Hitachi Power Systems, Ltd.

The supercritical boiler shown in Fig. 2.50 was commissioned in 2000, generated 3000 t/h steam at 25.1 MPa, 600/610 C. As mentioned earlier, the membrane wall consisted of spiral windup type, and steam separator was installed, being different from the original one. As such feature, the boilers have been flexibly developed

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Advances in Power Boilers

Figure 2.51 Classification of boilers and the history of development. Source: Courtesy of S. Ishigai.

dependent on the fuel, operating conditions, environmental issues, and so on as is described in detail in Section 8.1.

2.4.4 Summary of boiler development As mentioned throughout this chapter, principal factor of the boiler is water circulation. Based on this concept, Seikan Ishigai classified types of boilers and proposed intrinsic strategy of technology development in boilers. Typical classification and sequence of boiler development is exemplified in Fig. 2.51. Principal types of boilers are cylindrical boilers, based on the submergence principle without outer circulation, water tube boiler with natural circulation, and oncethrough boiler. Newcomen and/or Watt’s boilers are primitive types of boilers. Before the appearance of water tube boiler, noncirculating submerged water tube boilers were brought into the market, while limited at relatively small capacity owing to the poor water-circulation performance, that is, poor cooling capability of the tube wall materials. The natural-circulation boilers have also limitations depending on the dynamics between driving force and flow resistance. To assist the water circulation, pump is added, which does not alter the circulation principle, while the forced-circulation boiler is categorized as an intermediate type from natural-circulation to once-through boilers. In summarizing boiler development the technology of boiler followed the sequence from submergence, circulation, and to once-through principles. It should be noted here, although cylindrical boilers appeared early in 1800s, the principal feature is transferred to present flue and smoke-tube boiler. Natural- and forced-circulation boilers are a dominant type of small- and/or intermediatecapacity range. Once-through boilers are dominant in a large capacity power generation area.

Introduction to boilers

2.5

99

Historical development of power generation boilers in Japan

The most important parameters directly affected efficiency are steam temperature and pressure. The history of these parameter in Japan since after World War II is plotted in Fig. 2.52. Both these parameters successively increased in accordance with the surrounding technologies, for example, material, heat transfer, and twophase flow. At present, further increase in these parameters is advancing as A-USC project in Japan, being described later. Historical development of power boilers is clearly observed the sequence, that is, from natural, forced, and then once-through boilers. Fig. 2.53 represents the history of power boiler development in Japan after World War II. The first stage was dominated small-capacity natural-circulation boiler, and then the second class with larger capacity, forced-circulation boiler, appeared. The highest capacity is naturally dominated by once-through boilers. Every type of boiler, only in the initial stage of introduction, was imported mainly from the United States and Germany, while constructions by Japanese companies were increased later on. The power generation is closely related to the economical state, which is clearly demonstrated in Fig. 2.54. Without stable power generation, highly developed economics was not possible in Japan.

2.6

Similarity law in boiler furnace and other various important issues

In designing boiler, similarity law may lead sound design, while it should be rather difficult to include many affecting parameters. Here a simplified law of the furnace is based on practical data.

Figure 2.52 History of steam pressure and temperature. Source: Data from J. Inumaru.

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Advances in Power Boilers

Figure 2.53 Boiler type and steam generation rate of boilers commissioned 1947
79 in Japan. Source: Data from F. Mu¨nzinger, Dampfkraft—Berechnung und Bau von Wasserrohlkesseln und ihre Stellung in der Energieerzeugung, Verlag von Julius Springer, Berlin, 1933, p. 190; [26] S. Ujita, Y. Tamai, Historical evolution of boiler technology, Therm. Nucl. Power 31 (12) (1980) 1315
1367; [63] A.M. Godridge, A.W. Read, Combustion and heat transfer in large boiler furnaces, Prog. Energy Combust. Sci. 2 (2) (1976), 83
95 (Pergamon Press). [64]

Figure 2.54 Unit output and type of fuels. Source: Data from T. Kuroishi, M. Ogawa, History of the boiler control, Therm. Nucl. Power, 63 (4) (2012), 287
297; [65] Cabinet Office, Government of Japan. ,http://www. esri.cao.go.jp/jp/sna/data/data_list/kakuhou/files/h10/12annual_report_j.html., ,http://www. esri.cao.go.jp/jp/sna/data/data_list/kakuhou/files/h27/h27_kaku_top.html. (accessed 05.07.17); [66] The Federation of Electric Companies of Japan, Infobase. ,http://www.fepc. or.jp/library/data/60tok. (accessed 05.07.17). [67]

A steam generation rate is proportional to the heat release rate in the furnace, which is a function of the volumedensity of heat release rate and the furnace volume. Generated heat is absorbed by the water tubes and thus following relationship holds. ðVolume density of heat release rateÞ 3 ðVolumeÞ 5 ðHeat fluxÞ 3 ðArea of heat transfer surfaceÞ

Introduction to boilers

101

Let L the representative length of furnace, volume is proportional to L3 , area to L2 . Then, ðVolume-density of heat release rateÞ~

ðSteam generation rateÞ L3

and ðHeat fluxÞ~

ðSteam generation rateÞ L2

gives ðVolume-density of heat release rateÞ~ðHeat fluxÞ3=2 ðSteam generation rateÞ21=2 Fig. 2.55 shows the relationship between the heat release rate and the steam generation rate obtained from the practical data. Solid lines represent surface heat flux

Figure 2.55 Relationship between volume density of furnace heat release rate and boiler capacity. Source: Data from E. Nishikawa, General Planning of the Boiler Gas-Side Heat Transfer Surface, in: Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 119
122; [68] F. Mu¨nzinger, Modern forms of water-tube boilers for land and marine use, Proc. Inst. Mech. Eng. 134 (1936) 5
87. [69]

102

Advances in Power Boilers

density, almost data align along these solid lines representing (Steam generation rate)21/2. In addition, heat flux is high for gas, and oil is almost similar level, while the lowest is coal. This is mainly because of the slagging of coal ash. Another important feature is the volume density of heat release rate is rather high for small capacity boiler, smaller than about 30 t/h. Circulating fluidized-bed boiler is higher in volume density than conventional pulverized coal-fired and bubbling-bed boilers. In viewing fossil-fired boilers, many issues are to be considered in the design and operation stages.

Figure 2.56 Deterioration of power boiler. Source: Drawn by the author referring to ,Chemical processing for boiler water, Therm. Nucl. Power 58 (5) (2007) 367
407. [70]

Figure 2.57 R&D history on fossil fuel
fired power generation in Japan. Source: Drawn by the author.

Introduction to boilers

103

The problems to be considered are not limited shown in Fig. 2.56, while each problem has been resolved successively, but with meanderings through valuable experiences in construction and operation and maintenance processes, that is, power boilers are surely a product of integrated technology based on around 300-year history together with surrounding technologies. The fossil-fired power plants generated the largest power through such long history, and in this context the power boiler was continuously assessed as the “high-tech” industry throughout. The essences of such power boilers at present are described systematically in the following chapters. In closing this chapter, overall R&D process emphasized on coal-related technologies in Japan is illustrated in Fig. 2.57. Based on the reduction of CO2 emission to the environment, governments and people hesitate to install coal-fired plants, while considering long history and amount of energy resources, advancement in so-called clean-coal technology is essential for future perspective of the society.

References [1] H.W. Dickinson, A Short History of the Steam Engine, Cambridge University Press, 1938. [2] H.W. Dickinson, Chapter 6: The steam-engine to 1830, in: C. Singer, E.J. Holmyard, A.R. Hall (Eds.), A History of Technology, Oxford University Press, Oxford, 1958, pp. 168
198. [3] A.M. Greene Jr., History of the ASME Boiler Code, ASME, 1955. [4] E. Somerset, A Century of the Names and Scantlings of such Inventions, F. Grismond, London, 1663. [5] T. Savery, The Miner’s Friend, or an Engine to Rais Water by Fire, 1702 (Described, and of the Manner of Fixing it in Mines, with an Account of the Several Other Uses it is Applicable unto and an Answer to the Objections Made against it, S. Crouch, London). [6] D. Papin, Nova methodus ad vires motrices validissimas levi pretio comparandas, in: Acta Eruditorum, Leipzig Grosse & Gleditsch, 1690, pp. 410
414. [7] R.H. Thurston, A Manual of Steam-Boilers: their Design, Construction, and Operation, John Wiley & Sons, New York, 1888, p. 6. [8] C. Matschoß, Die Entwicklung der Dampfmaschine, Julius Springer, Berlin, 1908. [9] E.B. Marten, Records of Steam Boiler Explosion, E. & F. N. Spon, London, 1872. [10] L.T.C. Rolt, J.S. Allen, The Steam Engine of Thomas Newcomen, Landmark Pub, Ashbourne, 1993. [11] S. Ishigai, Historical development of strategy for steam power, in: S. Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 1
41. [12] S. Ishigai, Design Principles of Steam Boiler, Sankaido, Tokyo, 1961, pp. 58
59. [13] Select Committee on Steam Boiler Explosion, Report From the Select Committee on Steam Boiler Explosions; Together With the Proceedings of the Committee, Minutes of Evidence, and Appendix, The House of Commons (1870). [14] The Manchester Steam Users’ Association (MSUA), A Sketch of the Foundation and of the Past Fifty Years’ Activity of the Manchester Steam Users’ Association for the

104

[15]

[16] [17] [18] [19]

[20]

[21] [22] [23]

[24] [25] [26] [27] [28] [29]

[30] [31]

[32] [33] [34]

Advances in Power Boilers

Prevention of Steam Boiler Explosions and for the Attainment of Economy in the Application of Steam, Taylor, Granett, Evans, & Co., Manchester, 1905. K. Akagawa, Thermal and hydraulic design of steam-generation systems, in: S. Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 276
283. H.W. Dickinson, A. Titley, Richard Trevithick
The Engineer and the Man, Cambridge University Press, 1934, p. 49. A. Woolf, Improved apparatus, applicable to steam engines and other purpose of art and manufacture, Philos. Mag. 17 (1803) 40
47. 164-166, 275-278. A. Pohlhausen, Dampfkesselanlagen
Lehr- und Handbuch fu¨r Techniker und Ingenieure, Verlag der Polytechnischen Buchhandlung, 1899. Tafel 13. R. Spalckhaver, Fr. Schneiders und A. Ru¨ster, Die Dampfkessel nebst ihren Zubeho¨rteilen und Hilfseinrichtungen, Verlag von Julis Springer, Berlin, 1924, pp. 125
141. D.K. Clark, Steam Engine
A Treaties on Steam Engines and Boilers With Examples of Recent Design and Construction, Blackie & Son, London, 1891, pp. 757
759 (In Part 6) and pp. 777-782 (in Part 7). The Babcock and Wilcox Co., Steam
Its Generation and Use, 22nd ed., The Babcock & Wilcox Co., New York, 1890. The Engineering Staff of the Stirling Co., Stirling
A Book on Steam for Engineers, The Stirling Co, 1905, pp. 8
9. R. Kennedy, The Book of Modern Engines
A Practical Work on Prime Movers and the Transmission of Power Steam, Electric, Water, Gas, and Hot Air, 6, Caxton Pub., London, 1912, p. 68. J.G. Worker, T.A. Peebles, Mechanical Stokers, McGrow-Hill, New York, 1922, pp. 23
40. E.L. McDonald, Improvement in Missouri-Kansas coal and their burning equipment, Trans. ASME 54 (1932) 91
98. FSP-54-10. F. Mu¨nzinger, Dampfkraft
Berechnung und Bau von Wasserrohlkesseln und ihre Stellung in der Energieerzeugung, Verlag von Julius Springer, Berlin, 1933, p. 190. F. Mu¨nzinger, Americanishe und deutsche Großdampfkessel, Verlag von Julius Springer, Berlin, 1923, pp. 39
48. J. Wolf, Test of pulverized-fuel-fired boilers at the Lake Shore Station, Cleveland, Mech. Eng. ASME 47 (No. 1) (1925) 25
29. W.H. Howler (Ed.), Fifty Years’ History of the Development of Green’s Economizer, With Notes on Other Economizer Inventions and Early Tubular Boilers, G. Falkner, Manchester, 1895. M. Payen, Note sur l’emploi des pmmes-de-terre pour prevenir les incrustations dans les Chaudie`res a` Vapeur, J. Phar. Sci. Accessoires IX-8 (1822) 467
470. L. Elsner, Verzameling der Tot Heden Angewende Middelen om Het Onstaan van den Ketelsteen (Zoogenaade Salpeter.), in: Stoomketels te Verhinderen, Deventer, J. De Lange, 1854. W.W. Christie, Boiler-Waters Scale, Corrosion, Forming, D. Van Nostrand Co., New York, 1906. E.P. Partridge, Formation and properties of boiler scale, in: Engineering Research Bulletin, No. 15, Department of Engineering Research, University of Michigan, 1930. I.G. Salter, N.L. Parr, Marine boiler deterioration, Proc. Inst. Mech. Eng. 160 (1) (1949) 341
358.

Introduction to boilers

105

[35] T.B. Hurst, C.C. Hamilton, Industrial boiler design, Mech. Eng. ASME 82 (1960) 52
57. [36] A. Loschge, Die Dampfkessel, Verlag von Julius Springer, Berlin, 1937, p. 195. [37] W.J. Wohlenberg, H.F. Mullikin, W.H. Armacost, C.W. Gordon, An experimental investigation of heat absorption in boiler furnaces, Trans. ASME 57 (1935) 541
554. [38] R.I. Wheater, M.H. Howard, Furnace heat absorption in Paddy’s Run pulverized-coalfired steam generator, using turbulent burners, Louisville, KY. Part I. Variation in heat absorption as shown by measurement of surface temperature of exposed side of furnace tubes, Trans. ASME 72 (1950) 893
923. [39] C. Eleanor, Barnes (Lady Yarrow), Alfred Yarrow
His Life and Work, Edward Arnold & Co., London, 1923, pp. 123
138. [40] Ch. Bellens, Z. Ver. Dtsch. Ing. 43 (52) (1899) 1637. [41] M. Gensch, Berechnung, Entwurf und Betrieb rationeller Kesselanlagen, Verlag von Julius Springer, 1913. [42] K. Hoefer, Untersufungen u¨ber Stro¨mungsvorg¨ange im Steigrohr eines Druckluftwasserhebers, Z. Ver. Dtsch. Ing. 57 (30) (1913) 1174
1182. [43] F. Mu¨nzinger, Untersuchungen an Steilrohrkesseln
Der Wasserumlauf in Steilrohrkesseln, Z. Ver. Dtsch. Ing. 64 (25) (1920) 453
457. [44] E. Schmidt, Der Wasserumlauf in Steilrohrkesseln, Festschrift “Fu¨nfundzwanzig Jahre Technische Hochshule Danzig”, Verlag Kafemann, 1929, pp. 231
250. [45] S. Ishigai, K. Akagawa, Boira-no-mizujunkan (Water Circulation in Boiler), Corona Pub., Tokyo, 1959. In Japanese. [46] S.W. Gouse Jr., An Index to the Two-Phase Gas-Liquid Flow Literature, The MIT Press, Cambridge, 1966. [47] F.S. Clark, F.H. Rosencrants, W.H. Armacost, 1825-Lb-pressure topping unit with special reference to forced-circulation boiler, Trans. ASME 65 (5) (1943) 461
477. [48] A. Gaffert Gustaf, Steam Power Stations, McGraw-Hill, New York, 1940, pp. 228
229. [49] J. Franke, The Benson boiler turns 75, Siemens Power J. Online. ,http://www. energy.siemens.com/co/pool/hq/power-generation/power-plants/steam-power-plantsolutions/benson%20boiler/The_Benson_Boiler_Turns_75.pdf., 2002 (accessed 29.08.19). [50] F. Ohlmu¨ller, The influence of the Benson boiler on the development of power stations, J. Inst. Electr. Eng. 75 (452) (1934) 161
184. [51] A.G. Siemens, Benson Boilers for Maximum Cost-Effectiveness in Power Plants. ,http://www.energy.siemens.com/ru/pool/hq/power-generation/power-plants/steampower-plant-solutions/benson%20boiler/BENSON_Boilers_for_Maximum_Cost_Effectiveness.pdf., 2001 (accessed 28.08.19). [52] F. Hodgkinson, Latest developments of the Benson boiler I
Review of early problems, Mech. Eng. ASME 61 (1939) 217
221. [53] A. Stodola, Der Sulzer-Einrohr-Dampferzeuger-Aufbau/Regelung/Regelversuche, Z. Ver. Dtsch. Ing. 77 (46) (1933) 1225
1232. [54] T. Egusa, Kanryu-boira (Once-Through Boilers), Ohmsha, Tokyo, 1963, p. 20. In Japanese. [55] R. Doleˇzal, Durchlaufkessel
Theorie, Bau, Betrieb und Regelung, Vulkan-Verlag Dr. W. Classen, Essen, 1962, pp. 82
84. Fig. 85-87. [56] F. Hodgkinson, Latest developments of the Benson boiler II. Description of typical installations, Mech. Eng. ASME 61 (1939) 287
294. [57] T. Kawauchi, Principal planning of 500MW supercritical pressure unit of Chita thermal power station, Therm. Power 16 (11) (1965) 933
947 (Table 1, p. 934).

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[58] G. Noetzlin, Das neue Kraftwerk Hu¨ls
eine Anlage mit 300 at/600 Frischdampfzustand, Mitt. Ver. Grosskesselbesitzer 55 (1958) 230
255. [59] S.N. Fiala, First commercial supercritical-pressure steam-electric generating unit for Philo plant, Trans. ASME 79 (1957) 389
407. [60] S. Miyaoka, State-of-the-art of supercritical pressure units and their economic efficiency, Therm. Power 1 (11) (1965) 902
916 (In Japanese) (Table 2 p. 904). [61] J. Gubler, Eddystone steam power station, Philadelphia, Sulzer Tech. Rev. 41 (1) (1959) 3
20. [62] M.A. Styrikovich, T.K. Margulova, Z.L. Miropol’slii, Problems in the development of designs of supercritical boilers, Therm. Eng. 14 (6) (1967) 5
9. [63] S. Ujita, Y. Tamai, Historical evolution of boiler technology, Therm. Nucl. Power 31 (12) (1980) 1315
1367. [64] A.M. Godridge, A.W. Read, Combustion and heat transfer in large boiler furnaces, Prog. Energy Combust. Sci. 2 (2) (1976) 83
95. [65] T. Kuroishi, M. Ogawa, History of the boiler control, Therm. Nucl. Power 63 (4) (2012) 287
297. [66] Cabinet Office, Government of Japan. ,http://www.esri.cao.go.jp/jp/sna/data/data_list/ kakuhou/files/h10/12annual_report_j.html., ,http://www.esri.cao.go.jp/jp/sna/data/ data_list/kakuhou/files/h27/h27_kaku_top.html., 2017 (accessed 05.07.17). [67] The Federation of Electric Companies of Japan, Infobase, ,http://www.fepc.or.jp/ library/data/60tok. (accessed 05.07.17). [68] E. Nishikawa, General planning of the boiler gas-side heat transfer surface, in: Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 119
122. [69] F. Mu¨nzinger, Modern forms of water-tube boilers for land and marine use, Proc. Inst. Mech. Eng. 134 (1936) 5
87. [70] Thermal and Nuclear Power Engineering Society, Chemical processing for boiler water, Therm. Nucl. Power 58 (5) (2007) 367
407.

3

General planning of thermal power plant Atsuhiro Hanatani1 and Mamoru Ozawa2 1 IHI Corporation, Tokyo, Japan, 2Kansai University, Osaka, Japan

Chapter Outline 3.1 Overview of steam power plant 107 3.2 Concept of general planning and factors to be considered 109 3.3 Principal concept for high-performance plant 110 3.3.1 3.3.2 3.3.3 3.3.4 3.3.5

Site location 110 Fuel 110 Type of boiler 112 Unit capacity 112 Steam condition 113

3.4 Reheat cycle and regenerative cycle 3.4.1 3.4.2 3.4.3 3.4.4 3.4.5 3.4.6 3.4.7

113

Steam pressure 113 Steam temperature 113 Condenser vacuum 113 Regenerative cycle 114 Reheat cycle 114 Example of heat balance 115 Feedwater temperature 116

3.5 Enthalpy pressure diagram along steam generating tube 3.6 Legal regulations in Japan 117 References 118

3.1

116

Overview of steam power plant

A boiler is a system to generate steam by firing coal, oil, gas, and recently incineration. At the beginning, coal was a prime fuel that continued to the 1950s for about 250 years. During this period, various coal-treatment technologies have been developed to raise efficiency and reduce smoke. Ash treatment was also a very important one. Oil was introduced to boiler and efficiency and ash problems were partly resolved, while oil price is fluctuating and unstable depending on economic and political situation. Especially Japan became involved in oil crisis in 1973 and 1979. This oil crisis enhanced the natural gas firing and the introduction of nuclear power. Nuclear power stations constructed in Japan counted 54 units while drastically reduced in number after the core meltdown in the Fukushima Daiichi power station. The economy and social welfare are supported by the electric network, which is Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00003-5 © 2021 Elsevier Inc. All rights reserved.

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nowadays based on the fossil fuel fired power station, that is, steam boilers, in Japan. Such a situation may be unique alone in Japan; instead many developing countries depend on fossil fuel fired power generations, and the importance of steam boiler technologies is still a prime interest. Overall feature of a thermal power plant is exemplified in Fig. 3.1. This is the case of coal fired power plant. Coal is unloaded at the port and stacked on the coal yard or accumulated in a silo. Then coal is transported via belt conveyor to coal bunker. Coal mill pulverizes coal into a suitable particle size for injecting into a furnace. In addition to coal feed system, light oil is needed for the ignition of coal. The drain from coal yard and/or light oil tank is fed to sedimentation pit and oil separator. Condensate from condenser together with some portion of water chemically treated through a water treatment system is supplied via circulation pump and boiler feedwater pump. Generated steam in the boiler is fed to steam turbine, while steam is recirculated to boiler to reheat before entering low pressure (LP) turbine and then condensed by cooling with sea water in the condenser. Flue gas from boiler furnace pass through de-NOx system, electrostatic precipitator (EP), and flue-gas desulfurization system and finally ejected through chimney to the environment. Ash from the EP is discharged as ash slurry mixed with sea water to ash pond. Generated electricity is distributed through a transformer, open air type substation, and high-voltage cable to the demand side.

Figure 3.1 Overall feature of thermal power plant. Source: Courtesy of MHPS.

General planning of thermal power plant

3.2

109

Concept of general planning and factors to be considered

General planning is the process to make concrete plan of the plant, master plan drawing, determination of specification, and based on these processes to make primary quotation of the plant. This process includes planning of principal specification, main components and their arrangement on the installation location, selection of the type of plant and construction, instrumentation, and control system. When the variable pressure operation for demand variation and power generation fluctuation is the case, it is necessary to estimate not only the static characteristics but also dynamic behavior of the plant. Especially in the transient states, thermal stress, and thermal fatigue, if fluctuation continues long period, of the materials, flow instability in boiler tubes, and so on must be somehow prevented. Thus the computer simulations of thermohydraulic behavior of boiler are substantially important in designing process. Power boilers design and construction need, in general, the following factors to be considered: Fuel unloading and accumulation Common system Coal Oil Gas

Port infrastructure, quay Unloader, stack or silo, belt conveyor, coal bunker, pneumatic conveying Oil unloading system, accumulation tank, pumping system LNG unloading system, LNG tank, vaporizer, pumping system

Fuel supply and combustion Common system Coal Oil Gas Water supply Boiler construction

Combined cycle Piping system Air and flue gas

Wastewater Safety system Control system Emergency system

Instrumentation, combustion control system, safety device Coal feeder, pulverizer, coal burner, light oil Pump, oil burner Gas burner Water storage tank, deaerator, water treatment system, water feed pump Economizer, feedwater heater, steam water separator, water wall, steam generating tube, superheater, reheater, and framework supporting heat transfer surface Gas turbine, combustor, heat recovery steam generator, compressor, superheater, economizer, steam water separator Water feed pipe, main steam pipe, reheat steam pipe, etc. Induced draft fan, forced draft fan, flue duct, soot blower, deNOx and de-SOx systems, bag filter, electrostatic precipitator, environment monitoring system Waste water tank, oil separator, sedimentation pit, filtration, neutralization Failsafe system, instrumentation Instrumentation, controller, process computer, recording unit Diesel generator, batteries, etc.

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When the power boiler construction is conducted as the repowering of existing plant, fuel supply and water treatment, sea water pumping, and so on are partly available, while new construction is the case these components are newly constructed. An ordering party, for example, electric power company, concerns the output of electricity, maximum continuous rating (MCR), and partial load performance if used for the absorption of fluctuation, and capital and operation cost. In making general planning the designers and/or manufacturer are needed to keep in mind that these systems are combined and united to form one steam generation system together with a turbine generator and condenser. Thus each element or system is closely related with each other and a certain impact affect whole system, which shows power plant to be one of the typical complex system. In what follows, important factors to be considered in the general planning are successively described.

3.3

Principal concept for high-performance plant

For development of power plant, it is necessary to examine the balance between supply and demand to determine whether stable power supply is possible for future market demand assumptions. Thermal power plant is used in a wide range from the base to the peak load as the supply capacity, and it is comprehensively examined from the aspects of system operation, fuel procurement, site location and environment issue, etc. As considering the objective of the power plant and available resources, the suitable system will be selected among various types of thermal power system, such as conventional boiler steam cycle system, gas turbine, diesel or gas engine, and gas turbine combined cycle systems, etc. The conventional boiler turbine generator (BTG) system has a long history and is most widely used in the world due to its flexibility of applicable fuels and operability.

3.3.1 Site location In thermal power plants, it is necessary to properly arrange various facilities that consist of boiler, steam turbine, generator, auxiliary equipment, and other balance of plant based on related regulations. Also, since heavy equipment such as boilers and steam turbine generators are installed, a wide and stable land area with high ground strength is required. The site location shall be selected in consideration of access to roads and/or port facilities for loading fuel, utilities, etc., and unloading wastes, access to water resources for fresh water and cooling water, and access to the grid facilities for power transmission.

3.3.2 Fuel The conventional BTG system has flexibility of applicable fuels. The major fuel for utility boiler is coal, fuel oil, natural gas, etc. Recently, considering energy saving

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and decarbonization, alternative fuels, such as waste or by-product from industry and biomass fuel are applied. For planning applicable fuels, it is necessary to evaluate the characteristics, such as economy, supply stability, operability, and environmental impact. Table 3.1 exemplified specific feature of fuels and their effect on boiler. Conventional boilers use coal, oil, and natural gas as is described in Chapter 1, Fossil Fuels Combustion and Environmental Issues. Each fuel has unique characteristics as is discussed in Chapter 1, Fossil Fuels Combustion and Environmental Issues, and the effects of each fuel on the boiler components are listed in Table 3.1 as well. Coal is quite different from the other and relatively low combustibility, while having almost 300 years history of application. Current innovation such as Clean Coal Technology enhanced the development in the coal combustion technology and integrated coal-gasification combined cycle is a typical evidence of this development. In addition, various deteriorations are expected throughout whole steam plant. Then it is useful to refer Fig. 2.56, which is a valuable guideline at the design stage for taking measures for a variety of deteriorations arisen in steam power plants.

Table 3.1 Fuel characteristics and effect on boiler components. Coal

Oil

Natural gas

Effect on boiler component

Solid High

Liquid Intermediate

Gas Low

Broad

Good

Good

Ash content

High and broad

Broad

None

Nitrogen content Sulfur content

High

Broad

Low

High

Broad

None

Nearly 0

Broad

None

Combustor Furnace, water tube (specific heat of flue gas) Furnace (residence time) Furnace, water tube (slagging, fouling, and wear) Furnace, denitration system High-temperature heat transfer tube, gas air heater (corrosion) High-temperature heat transfer tube (corrosion)

Form Carbon/ hydrogen ratio Combustibility

Vanadium content

Source: Data from K. Hirayama, General Planning of Boilers and Design Consideration, Seminar Resume of Thermal and Nuclear Power Engineering Society, 2019 (in Japanese) [1].

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3.3.3 Type of boiler General or primary planning starts first the specification of steam temperature and pressure at the turbine inlet, steam generation rate, and operation, for example, rated operation and/or partial load operation. These three specifications have a significant influence on the selection of boiler size, structure, efficiency, fuel selection, control system, and of course capital and operation costs. Primary planning of the boiler is selection of boiler type and fuel. If the solid fuel, that is, coal, is the case, there are several types of boilers depending on the steam generation rate as shown in Fig. 3.2. Current stoker combustion boiler is limited in incineration firing. Bubbling and circulating fluidized bed boilers have a merit in relatively small capacity field of coal, incineration, and/or industrial wastes combustions. Relatively large capacity field are almost dominated by pulverized coal combustion boilers. As to the current power boilers, there are natural circulation, forced circulation, and once-through boilers, and boiler capacity increases in this order, that is, the largest capacity boilers are once-through type, while in a small capacity field, natural and/or forced circulation boilers are used.

3.3.4 Unit capacity In general, it is more economical to increase the unit capacity of the BTG as much as possible and reduce the number of units. When the unit capacity is increased, the construction cost per MW and the number of operators decreases, while the thermal efficiency increases. On the other hand, there is a disadvantage that the failure becomes larger impact. In determining these unit capacities and numbers of unit, it is necessary

Figure 3.2 Types of coal fired boilers. Source: Drawn referring to M. Horio, S. Mori (Eds.), Fluidization Handbook, Baifukan Pub., 1999, p. 295 (in Japanese) [2].

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to take into account such factors as equipment accidents during operation and spare equipment for periodical outage. In addition, it is important to consider the unit capacity in the power grid system in consideration of the abnormal situation. The unit capacity is determined by the voltage fluctuation at the time of the failure, the allowable limit of frequency reduction and the reserve output, etc. In general, the optimum unit capacity is considered to be about 7% 10% of the maximum power of the power grid system.

3.3.5 Steam condition In steam turbines the higher the main steam pressure and temperature, the better the thermal efficiency. When the energy release in the steam condenser is constant, larger energy input to the steam turbine generates larger available energy converted into mechanical work in the turbine. The steam conditions should be chosen so that the total of capital and operation costs are minimized and best suited to the operating conditions of the power plant. Increasing steam conditions to high temperatures and pressures will increase the capital costs while reducing operation costs. Therefore from an economic point of view, there is the most suitable steam condition for unit capacity.

3.4

Reheat cycle and regenerative cycle

The cycle of conventional BTG thermal power plant is the Rankin cycle. Various factors affecting the value of thermal efficiency are described next.

3.4.1 Steam pressure When the steam pressure is increased, under the constant steam temperature and exhaust pressure, the thermal cycle efficiency also increases, except when the steam pressure is very high or the temperature is not very high (up to about 29.4 MPa).

3.4.2 Steam temperature When the steam temperature is increased, the thermal cycle efficiency increases. Considering the steam pressure and exhaust pressure as constant in the enthalpy entropy diagram, normally, every 28K increase in the main steam temperature results in an improvement in net efficiency by 1.1% 1.3% for nonreheat type, and 0.55% 0.65% for one-stage reheat type.

3.4.3 Condenser vacuum Lowering the LP turbine exhaust pressure under constant turbine steam conditions will increase the thermal efficiency. The vacuum pressure in the condenser is

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greatly affected by the cooling water temperature. It depends on the atmospheric condition such as ambient temperature or sea water temperature. Usually, the cooling water temperature for sea water system is 21 C and the vacuum pressure is 722 mmHg in Japanese utility units.

3.4.4 Regenerative cycle In Rankine cycle the heat lease rate in the condenser, that is, the latent heat in turbine exhaust steam being carried away by the cooling water, accounts for almost half of the heat input. If a part of the steam is extracted from the appropriate stage in the steam turbine and the boiler feed water is heated by this steam, the latent heat of the extracted steam is recovered in the feed water, so the heat lease rate in the condenser can be minimized. By extracting a certain amount of steam, the turbine output becomes less than that without extraction, while the heat recovery with feedwater heating by the extracted steam is much effective to improve plant efficiency. The efficiency increases with the number of extraction stages, excluding the limitations on the turbine design. The number of feed water heaters is determined based on the balance between the additional cost and performance improvement. In general, the number of stages of the feed water heater is 4 5 stages for 20 50 MW, 5 6 stages for 50 100 MW, 5 7 stages for 100 200 MW, and 6 8 stages for 200 MW or more.

3.4.5 Reheat cycle Increasing the reheat steam pressure and temperature improves the thermal efficiency of the Rankine cycle. On the other hand, an increase in the steam pressure without increasing the steam temperature results in an increase in the wetness of the exhaust steam. A high wetness steam may cause erosion of turbine blades and reduced efficiency. As a countermeasure, if the entire steam is extracted from the turbine intermediate stage during expansion, heated by the reheater in the boiler and returned to the turbine for work, the wetness of the exhaust can be kept within the allowable limit. Although it is not easy to raise the steam temperature due to material limitations, reheat cycle provides the same improvement effect in the cycle efficiency as raising the steam temperature without reheating even at the same wetness. Compared with the nonreheat cycle, an increase in thermal efficiency of the reheat cycle is about 4% 5%, although it depends on the turbine output and other conditions. In order to increase the thermal efficiency, multistage reheating is possibly considered. However, an increase in thermal efficiency due to the double reheating remains at about 2% relative to the case of single reheat, that is, an increase in efficiency by an increase in the number of reheater does not counterbalance with an increase in the capital. Therefore single reheat cycle has been generally applied considering its asset cost increase, while in recent years, a double reheating has been reevaluated in the development of advanced ultra supercritical UA-USC) units.

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3.4.6 Example of heat balance This reheat and regenerative plant is the case of 600 MW economical continuous rating (ECR). The pressure (MPa), temperature ( C), and mass flow rate (t/h) are shown for 100% ECR (600 MW) and 15% ECR (90 MW). Together with enthalpy pressure diagram exemplified in Fig. 3.3, heat absorption allocation and heat balance are estimated. The detailed design and adjustment are conducted based on these conceptual diagrams. In constructing conceptual design, similarity law such as Fig. 2.55 is quite helpful. Fig. 2.55 represents practical data of volume heat release rate plotted as a function of steam generation rate. When the gas fuel is the case, the volume heat release rate is rather high, but lower in the case of oil firing, and lowest for coal firing boiler. This means that the furnace volume, that is, residence time, becomes large in the order of gas fired, oil fired, and coal fired. The practical data is effectively applied in constructing such conceptual design.

Figure 3.3 Pressure, temperature, and flow rate at each component of supercritical variablepressure steam power plant at rated and partial load operations (ECR/15%ECR) Source: Data from T. Fujii, Thermodynamic Design of the Plant Cycle, in S. Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 87 112 [3].

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3.4.7 Feedwater temperature In the reheat cycle system the plant heat rate depends greatly on the reheat steam pressure and the final feed water temperature. Generally, higher feedwater temperature brings about higher efficiency. However, it should be noted that too high feedwater temperature may reduce the heat transfer efficiency of the economizer and increase in the enthalpy of the flue gas exhausted from the boiler.

3.5

Enthalpy pressure diagram along steam generating tube

As is discussed in Chapter 2, Introduction to Boilers, the principal factor is the steam generation by heating water. Focused on the heat transfer in the whole boiler, the water circulation is substantially important. This water circulation is to be designed with special reference to the heat transfer in the boiler furnace and flue duct, that is, division of heat absorption among various components consisting of boiler. At the same time, it is generally requested to realize effective use of thermal energy generated by the combustion of fuels, but the burnout at the critical heat flux in heat transfer tubes should be avoided. Typical example of supercritical pressure boiler with variable pressure operation, that is, partial load operation, is shown in Fig. 3.4. The pressure at MCR, ECR, and above about 77% ECR is supercritical, while below 77% ECR the pressure becomes subcritical, and boiling takes place in the

Figure 3.4 Enthalpy pressure diagram for rated and partial load operations. Source: Data from M. Funakura, Y. Kunihiro, A. Sugano, Design and operating experience of 1,000 MW variable pressure operation Benson boiler with LNG firing, Hitachi Hyoron, 69 (10) (1987) 15 20 (in Japanese) [4].

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Table 3.2 Representative values of velocity and mass flux for supercritical variable pressure boiler at economical continuous rating.

Economizer Furnace water wall Smooth tube Rifled tube Wall tube in downstream flue Flue evaporator Superheater

Velocity (m/s)

Mass flux (kg/m2 s)

Pressure drop (MPa)

1.5 2.0 (inlet)

1000 1500

0.3 0.4

B6.6 (inlet) 3 5 (inlet) 10 15 (exit)

B3300 2000 2500 2000 3000

1.0 1.5 0.3 0.4

5 10 (exit) 10 20 (exit)

1000 1500 1000 2500

0.1 0.2 0.5 1.0

Source: Data from K. Akagawa, Steam-Generating System Design, in S. Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 259 272 [5].

furnace water wall. Above 25% ECR the furnace water wall exit before entering the primary superheater is at the superheated state, while in the case of 15% load two-phase flow is observed at the furnace exit. To ensure the soundness of the water wall, steam is separated in the steam water separator and water is recirculated to avoid the burnout at this low partial load operation, that is, forcedcirculation mode operation. Such a diagram is estimated in accordance with the design conditions, so that the arrangement of heat transfer surface, material selections, and cost evaluation are possible, of course, together with those shown in Fig. 3.3. Table 3.2 lists up typical design value of velocity and mass flux in various components at 100% ECR. Such rough data becomes guideline for detailed design described in Chapter 4, Power Boiler Design.

3.6

Legal regulations in Japan

Such power generation significantly affects industries, commerce, people’s life, health, and safety, and therefore power generation is regulated by various acts [6]. In Japan the most important one for power generation plant and business is “Electricity Business Act” being the fundamental and principal requirement. The combustion of fuel is regulated by “High Pressure Gas Safety Act” and “Fire Service Act.” Water supply and discharge is regulated by “River Act,” and “Industrial Water Act.” Cooling water from sea is controlled by “Act on Prevention of Marine Pollution and Maritime Disaster.” Unloading at a harbor is under the control of “Port and Harbor Act.” In addition, such whole site is regulated by “Act on the Prevention of Disaster in Petroleum Industrial Complexes and Other Petroleum Facilities.”

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The staffs, operators and/or other workers are protected by “Industrial Safety and Health Act” from suffering from accidents and disasters. Overall energy use and reduction of CO2 emission is controlled by “Act on Rationalizing Energy Use.” The flue is finally ejected to the environment and is regulated by “Air Pollution Control Act.” In addition, “Factory Location Act,” “Noise Regulation Act,” “Water Pollution Prevention Act,” and “Environmental Impact Assessment Act” are some examples. When steam power plant is planned and constructed, electric power company and/or manufacture are requested to meet abovementioned various acts and need countermeasures. Environmental impact assessment and agreement from local communities are complicated tasks. In order to obtain legal permissions, scientific and/ or technical data obtained by environmental and geological survey around the construction site are essentially conducted prior to the proposal. These data have a principal importance for aseismic design and air and water pollution countermeasure. As is well known, East Japan Earthquake in 2011 gave severe damages not only on nuclear power plants but also fossil fuel fired steam power plants located in the East Japan area. Main bodies of boilers remained without injury. The damages, mainly caused by Tsunami, were concentrated on auxiliary systems, including EPs, bag filters, electric power systems, sea water pump, and so on. Many steam power plants recovered soon, except a few plants such as Haramachi coal-fired power plant, which contributed to the recovery of the suffered area. In the case of Haramachi plant, the tsunami reached about 18 m in height caused severe damages in the above-mentioned auxiliary systems, and recovery from these damages was after 20 to 23 months. This suggests that the electric power plant must be tough against various natural hazards. In designing and constructing power plants the electric power company and manufactures must keep in mind the disaster prevention and mitigation measures.

References [1] K. Hirayama, General Planning of Boilers and Design Consideration, Seminar Resume of Thermal and Nuclear Power Engineering Society, 2019, (in Japanese). [2] M. Horio, S. Mori (Eds.), Fluidization Handbook, Baifukan Pub., 1999. in Japanese. [3] T. Fujii, Thermodynamic design of the plant cycle, in: S. Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 87 112. [4] M. Funakura, Y. Kunihiro, A. Sugano, Design and operating experience of 1,000 MW variable pressure operation Benson boiler with LNG Firing, Hitachi Hyoron 69 (10) (1987) 15 20. in Japanese. [5] K. Akagawa, Steam-generating system design, in: S. Ishigai (Ed.), Steam Power Engineering, Cambridge University Press, New York, 1999, pp. 259 272. [6] Thermal and Nuclear Power Engineering Society, Guideline of legal regulations for security and disaster prevention, in: Environmental Protection of Thermal Power Plant, 2011 (in Japanese).

4

Power boiler design

Masashi Hishida1, Kenjiro Yamamoto1, Kenichiro Kosaka1, Wakako Shimohira1, Kazuaki Miyake2, Senichi Tsubakizaki1, Sachiko Shigemasa3 and Hitoshi Asano4 1 Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan, 2Mitsubishi Hitachi Power Systems Environmental Solutions, Ltd., Yokohama, Japan, 3Hitachi Zosen Corporation, Osaka, Japan, 4Kobe University, Kobe, Japan

Chapter Outline 4.1 Heat transfer in boiler 4.1.1 4.1.2 4.1.3 4.1.4

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Radiation 120 Conduction 120 Convection 121 Heat transfer in boiler 121

4.2 Boiler gas side performance for furnace design 4.2.1 4.2.2 4.2.3 4.2.4 4.2.5 4.2.6 4.2.7

4.3 Water circulation design 4.3.1 4.3.2 4.3.3 4.3.4 4.3.5 4.3.6

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Principles of boiler furnace design 125 Boiler components 127 Membrane wall 146 Pulverized coal combustion 149 Fluidized bed combustion 167 Stoker combustion 173 DeNOx, deSOx process, gas cleaning 180

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Water circulation system principle 194 Submerged cylindrical type 195 Water tube type 197 Steam drum 208 Once-through boiler 213 Supercritical sliding pressure operation once-through boiler 223

4.4 Deposition, erosion and corrosion, and water treatment 240 4.4.1 4.4.2 4.4.3 4.4.4

Importance of water quality control in thermal power plants 241 History of water treatment methods for thermal power plants 242 New technologies regarding water treatment for thermal power plants Remarks 250

References

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Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00004-7 © 2021 Elsevier Inc. All rights reserved.

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4.1

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Heat transfer in boiler

Heat transfer occurs with combination of radiation, convection, and conduction. The basic equations of these three types of heat transfer are as in the following subsections.

4.1.1 Radiation qr 5 5:67 3 1028 εT 4

(4.1)

where qr is the radiant heat transfer (W/m2), 5.67 3 108[W/(m2K4)] is the Stefan
Boltzmann constant, T the absolute temperature (K), and ε the gas emissivity. Radiant heat transfer in the boiler is described as follows:

 ! Tg 4 Tw 4 Qr 5 A r e 2 (4.2) 100 100 where Qr is the radiant heat transfer in the boiler (W), Ar the effective radiant heating surface (m2), e the effective radiant heat transfer coefficient [W/(m2K4)], Tg the Absolute temperature of combustion gas (K), and Tw the absolute temperature of furnace wall surface exposed to combustion gas (K).

4.1.2 Conduction Qcd 5

λ Aðtwh 2 twl Þ δ

(4.3)

where Qcd is the heat transfer by conduction (W); λ the thermal conductivity [W/(mK)]; δ the thickness of wall (m); A the heating surface (m2); and twh, twl are the higher and lower side temperature (K or  C) (see Fig. 4.1).

Figure 4.1 Temperature distribution across wall.

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4.1.3 Convection   Qcv 5 αg A tg 2 twh 5 αs Aðtwl 2 ts Þ

(4.4)

where Qcv is the heat transfer by convection (W); αg, αs are the heat transfer coefficient of gas side and steam side [W/(m2K)]; A is the heating surface (m2); and tg, ts are the gas and steam temperature (K or  C). Convective heat transfer coefficient for single-phase flow such as flue gas, steam, and water is described by Nu (Nusselt number). Nu 5

α‘ 5 f ðRe; Gr; Pr; . . .Þ λ

(4.5)

where λ is the thermal conductivity of fluid [W/(mK)], ‘ the characteristic length (m), α the convective heat transfer coefficient [W/(m2K)], Re the Reynolds number, Gr the Grashof number, Pr the Prandtl number, and α is determined by various empirical formula for Nu in accordance with fluid condition.

4.1.4 Heat transfer in boiler The basic concept for the actual boiler design is described in the following subsections.

4.1.4.1 Furnace Heat balance for boiler furnace:   X QL FHl 1 ðQa 1 Qb Þ 5 Qc 1 Qr 1 Gg Cpg tgFOT 2 to 1

(4.6)

where F is the fuel flow rate (kg/s), Hl the lower calorific value (J/kg), Qa the sensible heat input by preheated air (W), Qbthe sensible heat input by fuel (W), Qc the  convective (W), Q 5 αA t 2 t the radiant heat transfer (W), , Q  heat transfer  c g w r 4  4 Qr 5 Ar e Tg =100 2 Tw =100 , Gg the gas production (kg), Cpg the specific heat of gas (J/kgK), tP gFOT the furnace outlet gas temperature (K), to the reference temperature (K), and QL the total heat losses (W). Furnace outlet gas temperature (FOT) is theoretically derived from the abovementioned heat balance; however, theoretical calculations have limitations in the actual boiler furnace because of various factors, such as flame configuration, nonhomogeneous distribution of heat and material, ash deposition on the furnace wall, are intricately intertwined. In the actual boiler design, some databases have been established in which FOT is back-calculated from economizer outlet gas temperature to furnace outlet with the operation data (steam and gas temperature of each heating surface, fuel flow, fuel calorific value, fuel properties, oxygen content in flue gas, and so on). These estimated FOTs have been accumulated for various boilers and co-related with some furnace parameters such as heat input per furnace

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cross-sectional area (plan area), heat input per furnace effective project radiant heating surface, excess air ratio, recirculated gas flow, and ash deposition condition on the furnace wall. Recently computational fluid dynamics (CFD) analysis for the boiler furnace is remarkably developing, so higher precision furnace design has become possible by the combination of the traditional inverse analysis based on the actual operation data of many boilers with state-of-the-art CFD analysis.

4.1.4.2 Computational fluid dynamics For reducing environmental impact and keeping the reliable operation of solid-fueled boilers such as pulverized coal firing boilers, the prediction method of the emission and the temperature or heat flux distribution of boiler tubes are important. Due to the recent growth of computer performance, numerical simulation is effective for understanding the complex phenomena inside the boiler furnace. Many organizations are developing the simultaneous evaluation method of the emission and operation reliability such as metal temperature, wall corrosion, and slagging characteristics by numerical simulation. This section shows examples of advances in CFD technologies for boiler design. Fig. 4.2 shows experimental instruments for validation of numerical combustion model for boiler CFD analysis. Fig. 4.2A and B shows different types of drop-tube furnaces (DTFs) used validation of combustion model and measuring basic properties of fuel. Fig. 4.3A is large-scale burner test furnace (4 t/h combustion furnace), which has 4 t/h of coal feed rate. Fig. 4.3B is an example of temperature distribution in this test furnace. Fig. 4.4 is an example of real boiler’s temperature distribution by CFD analysis. Furthermore, recent advances in computational power enable more precise

Figure 4.2 Experimental instruments for measuring basic properties of fuel: (A) single staged DTF and (B) two-staged DTF. DTF, Drop-tube furnace.

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Figure 4.3 Example of large-scale burner test furnace: (A) 4 t/h combustion test furnace and (B) CFD result of temperature distribution. CFD, Computational fluid dynamics.

Figure 4.4 CFD result of temperature distribution of a real boiler. CFD, Computational fluid dynamics.

analysis. Fig. 4.5 is an example of the result of combustion, fluid dynamics, and heat transfer coupled analysis. This figure shows total surface heat flux distribution on superheater (SH) tubes. Fig. 4.6 is a sample of large eddy simulation analysis in real boiler. Nowadays, CFD supports boiler design in such a way.

4.1.4.3 Heat transfer for heating surface (superheater, reheater, economizer) in the flue gas pass Heat transfer for heating surface installed in the boiler flue gas pass consists of direct furnace radiation, nonluminous radiant heat transfer, and convective heat

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Figure 4.5 Example of combustion and heat transfer coupled analysis: (A) analysis model includes superheaters and (B) CFD results of heat flux on superheater tubes. CFD, Computational fluid dynamics.

Figure 4.6 Example of LES analysis. LES, Large eddy simulation.

transfer. Contribution of these three kinds of heat transfer depends on the location of heating surface. Direct radiation from the furnace is primary heat transfer for heating surface installed above the furnace and radiant heat decreases as going to the downstream. In intermediate gas pass, convective heat transfer is a primary factor and nonluminous radiation is secondary.

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Figure 4.7 Flow and temperature relationships in heat exchanger.

Carbon dioxide and moisture in the flue gas are mainly gaseous radiating components and they are defined as nonluminous radiation. Nonluminous radiation is relatively large where flue gas temperature is high and tube spacing is wide as well as large cavity spacing between tube banks such as tertiary SH (3ry SH) and secondary reheater (2ry RH) or spacing for soot blowers, etc. The large cavities cause the large nonluminous radiation. The fluid flow direction and related temperature relationship are illustrated in Fig. 4.7. The heat transfer in the flue gas pass is described as follows: Q 5 Qc 1 Qnl 5 cfRt AΔTm

(4.7)

where Qc is the convective heat transfer (W); Qnl the nonluminous radiation (W); cf the empirical correction factor considering heating tube arrangement, flue gas flow 2 deviation, effect of baffle plate, etc.; A the heating surface   (m ); ΔT  m the logarithmic mean temperature difference: 5 ðΔt2 2 Δt1Þ= ln Δt =Δt 2 1    ; Rt the overall thermal transmittance [W/(m2K)]: 1=Rt 5 1=αg 1 δ=λ 1 1=αs .

4.2

Boiler gas side performance for furnace design

4.2.1 Principles of boiler furnace design Furnace design is a prime issue of boiler design. This section describes first how to burn fuels completely in the limited space, secondary how to absorb radiant heat from high-temperature combustion gas without overheating furnace wall tubes and fins.

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Fuels are divided broadly into solid, liquid, and gaseous. Coal, coke, wood, municipal, and industrial wastes are classified into solid fuels and their combustion characteristics including ash behavior widely vary. Crude oil, residual oil, heavy oil, etc. are liquid fuels. Natural gas, liquefied natural gas, liquefied petroleum gas, refinery gas, by-product gas such as coke oven gas, blast furnace gas (BFG) are gaseous fuels. BFG is low-calorific gas, so special consideration for combustion is needed. Furnace size is designed in accordance with fuel characteristics as shown in Fig. 4.8. In this section the design concept of a boiler furnace is described considering coal as the typical solid fuel. Furnace design, such as furnace configuration/dimension, burner configuration/location, should be considered in accordance with combustion characteristics and ash behavior which vary with coal mining area. Basic design aspects for a pulverized coal-fired boiler are: how to burn up coal stably and completely, how to avoid/control heavy slagging, how to avoid/control heavy fouling, and how to avoid/control heavy ash erosion.

These four aspects are closely related with coal properties and boiler design as shown Fig. 4.9. Furnace dimension for coal firing is mainly designed from standpoints of both combustion completion and control ash adhesion, namely, slagging/fouling of coal ash.

Figure 4.8 Boiler furnace dimension relative to gas-firing boiler.

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Figure 4.9 Relationship between boiler design and coal properties.

4.2.1.1 Required space for complete combustion: H2
H4 The required space above the burner zone (refer to Fig. 4.9) to the furnace outlet, in other words, required residence time above burner zone to furnace outlet where combustion gas enters into the first heating surface is determined to complete combustion of coal particles. Combustion speed rapidly decreases as combustion gas temperature falling, so proper sizing is an important issue. In order to minimize combustion space, coal particle size is an important factor as shown in Fig. 4.10.

4.2.1.2 Control ash adhesion to furnace wall: FD 3 FW, H4 Control of ash adhesion is also an important furnace design point for stable operation. Melting characteristics of coal ash depend on not only the chemical composition but also complicated interaction of melting components, so that the prediction of ash characteristics has been hard task, while current prediction capability makes steady progress by introducing microstructural analysis as well as chemical analysis.

4.2.2 Boiler components Power boiler consists of the following major components: G

G

G

G

furnace wall, passage sidewall and secondary (2ry) pass wall tubes and roof tubes water separator and water separator drain tank SHs RHs

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Figure 4.10 Effect of coal particle size.

G

G

G

G

desuperheaters economizer (ECO) boiler supports casing and insulation

4.2.2.1 Furnace wall, passage sidewall, and 2ry pass wall tubes and roof tubes 4.2.2.1.1 Structure Furnace enclosure and the flue gas path are made of water- and steam-cooled walls that resist high heat flux from high-temperature combustion flue gas, and tightly sealed to prevent gas leakage. The furnace is formed by four water-cooled walls, namely, the front, rear, right, and left (customarily, right wall is the right side looking from the front and left wall is the left side looking from the front). Each furnace wall is formed by welding tubes and fins alternately as gastight membrane wall panels. Fig. 4.11 shows work of furnace wall installation to grasp wall construction and its hugeness of a large capacity power boiler. The overall structure of once-through boiler is exemplified in Fig. 4.12. The burners and the additional air (AA) compartments are mounted on the lower part of furnace. In the upper part of furnace the 2ry and tertiary (3ry) SH banks are arranged which absorb radiant heat. The front and side water-cooled walls have an inlet header at the bottom and they terminate at an outlet header in the roof housing. A nose section overhanging from rear wall is adopted to turn away the combustion flue gas flow for proper flow direction entering into upper furnace zone. This nose section is formed by bending the rear wall tube panels. This nose section is extended to the bottom of passage wall and connected to the rear wall outlet header. Configuration of furnace bottom is hopper type to smoothly slide down molten ash. Then, the ash is discharged through a narrow opening at the bottom. The 2ry pass walls are formed by welding fins and tubes to provide a gastight finned wall. The upper part of 2ry pass front wall formed screen tubes both to support lower part of 2ry pass front wall and to allow gas flow from furnace to the 2ry pass. The 2ry pass is divided into two passages by a division wall formed by tubes extracting from the 2ry pass division panel inlet header. Similar to the 2ry pass front wall, screen tubes are adopted above the division wall to allow the gas flow through both sections. The lower portion of the division wall is formed with finned tubes similar to other wall sections. Two manifolds are adopted at the roof inlet and

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Figure 4.11 Work of furnace wall installation. Source: Courtesy MHPS.

the 2ry pass wall inlet. These manifolds make a homogeneous mixing and distribution of steam and water to avoid unstable flow condition. The furnace wall and 2ry pass walls are joined together by horizontal pass made of welding construction with tubes and fins. From the rear wall outlet header, pipes are connected to two rear wall hanger inlet manifolds and one passage sidewall inlet manifold. Distribution pipes are connected from these manifolds to the inlet headers of passage sidewall tubes and rear wall hanger tubes. The water from the furnace front and sidewalls join together at the roof inlet header and then flows to the roof outlet header through roof tubes. The water from the rear wall hanger and passage sidewall is collected in their respective outlet headers and enters directly into the roof outlet header, where tubes are spaced out to allow for burner openings, manholes, observation ports, or for other tube exit through roof panel.

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Figure 4.12 Overall structure of once-through boiler.

The gap between the tubes is closed with split fins and sealed with castable refractory and/or sheet casing to make a completely sealed surface. This arrangement prevents leaking of the hot furnace gases from these gaps (refer to Fig. 4.13). The special designs as detailed later are adapted to furnace wall to avoid overheating and structural problem due to excessive thermal deformation. The entire weight of all walls is supported by the steel structure through rigid hangers provided on the furnace walls outlet headers. The four sides of the furnace walls are surrounded by buckstay beams which avoid buckling and deformation of the furnace wall tubes due to forces by the furnace inside pressure and the thermal stress caused by nonuniform temperature distribution along the furnace wall tubes. The buckstays equalize the force around the walls through the corner plates and corner links. The buckstays have provision to allow the walls to expand in the transverse direction during hot condition along the boiler stoppers provided on the buckstay beams. Buckstay positioners installed between two adjacent elevation buckstays to avoid the overturning force. Boiler stoppers are provided at different elevations as required. The purpose of these stoppers is to limit movement of the whole boiler and transfer the seismic forces to the steel structure during earthquake (refer to Fig. 4.14).

4.2.2.1.2 Fluid circuits Water from the economizer outlet header is supplied to the furnace inlet headers through furnace inlet manifolds for assisting equal flow distribution to the furnace wall inlet headers (refer to Fig. 4.15). For the final proper distribution of the flow

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Figure 4.13 Inlet superheater headers at boiler roof.

Figure 4.14 Construction of furnace wall.

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Figure 4.15 Water circuit: (A) vertical view and (B) horizontal view.

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Figure 4.16 Rifled tube.

through each tube, all the tubes in the four furnace walls are fitted with flow adjusting orifices at the outlet of inlet headers considering the difference of the amount of heat absorption for each tube due to various tube arrangement such as unheated tubes behind burners and the heat flux distribution in the furnace. The equalization of the enthalpy at the outlet of the furnace wall tubes is achieved by installing the distribution manifolds. Manifolds are also provided between the front wall outlet header and the roof inlet header, rear wall outlet header, and passage-sidewall inlet header/rearwall intermediate inlet header. Steam-water two-phase flow is equally distributed by these manifolds into the tubes in the roof, passage wall, and rear wall hanger. Rifled tubes with inner spiral grooves are applied to the furnace water walls (refer to Fig. 4.16). The rifled tubes have high heat transfer characteristics even at lower mass flow rate. The rifled tubes cover the furnace from the starting level of furnace hopper to the top of the intermediate outlet header height. In all the other locations smooth tubes are used.

4.2.2.1.3 Water separator and water separator drain tank The two water separators are located adjacent to the 2ry pass rear wall to receive the steam or water/steam mixture from the 2ry pass outlet header (refer to Figs. 4.17 and 4.18). The drain pipe of each water separator is connected to the

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Figure 4.17 Water separator.

bottom half of the water separator drain tank. A nozzle at the bottom end of the water separator drain tank directs any water to the boiler circulation pump (BCP). The function of the water separator is to separate the water and steam from the wet steam during wet operation. The separated steam flows to the primary (1ry) SH. The separated water flows to the water separator drain tank through a vortex breaker installed at the bottom of each water separator. Offset connection is adapted to two outlet pipes from the 2ry pass rear wall outlet header to each water separator. This offset connection provides the tangential entry for the wet steam to generate swirling motion which separates water from the steam effectively. Each water separator is supported on four lugs with spring hangers connected to the hanger beams. Provision is made in the water separator drain tank for level transmitters which provide remote-level indications in the control room and level signals for the auto control loop.

4.2.2.2 Superheaters The function of the SH is to raise the steam temperature. The SH consists of three basic sections. Each section is illustrated in Fig. 4.19. G

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primary SH (1ry SH): horizontal type secondary SH (2ry SH): pendant type tertiary SH (3ry SH): pendant type

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Figure 4.18 Water separator drain tank.

4.2.2.2.1 Primary superheater The steam from the water separators enters the 1ry SH inlet header and then into horizontally arranged tubes that make up the 1ry SH assembly (refer to Fig. 4.20). The 1ry SH tube banks are located in the 2ry pass between the 2ry pass rear wall and the division wall and above the economizer bank. They absorb heat from the

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Figure 4.19 Superheaters.

flowing flue gases mainly by convection. The 1ry SH consists of two parts— horizontal and a terminal. The terminal part consists of straight tubes connecting the horizontal part to the outlet header inside the roof housing. The 1ry SH tube banks are supported by the economizer hanger tubes. Due to the different temperature mediums handled by the two sets of tubes, there is a differential thermal expansion due to temperature difference between the 1ry SH terminal tubes and the economizer hanger tubes. In order to avoid the mechanical strain due to the differential thermal expansion, the terminal part is provided with cold pull near the tube joints between the terminal part and the horizontal part. Fixed spacers, sliding spacers, and band spacers are provided on the 1ry SH tube banks at the specific locations to maintain alignment between the adjacent tubes and to reduce vibrations. Ash erosion protectors are provided on the 1ry SH tubes and bend at the specific erosion-prone locations and also at the front and rear walls to prevent erosion of tubes due to ash flow. At locations where the 1ry SH terminal tubes penetrate the roof panel, sealing is provided to prevent the leakage of the flue gas and fly ash into the roof enclosure. Outlet pipes from the two water separators join the two individual 1ry SH inlet headers located in the secondary pass. The steam passes through the lower and upper banks, terminal tubes and enters the outlet header. The 1ry SH banks are of the horizontally arranged drainable type. The entire assembly is supported at the outlet header.

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Figure 4.20 Primary superheater. Source: Courtesy MHPS.

4.2.2.2.2 Secondary superheater Steam from the 1ry SH outlet header enters the 2ry SH inlet header via the 1ry SH
desuperheater (refer to Fig. 4.21). There are four sets of the 2ry SH assemblies each set consisting of an inlet/outlet header. The 2ry SH is of the U-shaped pendant type. The 2ry SH assembly is installed in the upper furnace and most of the heat absorption takes place by radiation. The 2ry SH bank is fabricated from alloy steel and stainless-steel tubes. There are 16 panels arranged along the width and each has 4 banks along the depth of the furnace. Transition pieces are provided for insertion and welding between alloy steel and stainless-steel tubes. The locations where the 2ry SH tubes penetrate the furnace roof panel are provided with sealing arrangements to prevent the leakage of flue gas and fly ash. The 2ry SH panels and the 2ry SH inlet and outlet headers are supported by rigid hanger supports connected to the hanger beams.

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Figure 4.21 Secondary superheater. Source: Courtesy MHPS.

4.2.2.2.3 Tertiary superheater Steam from the 2ry SH outlet header enters the 3ry SH inlet header via the 2ry SH
desuperheater (refer to Fig. 4.22). The 3ry SH bank is of the U-shaped pendant type. Steam from the 3ry SH outlet header is connected to the main steam pipe. The 3ry SH bank is located above the nose portion in the upper furnace. This SH absorbs heat by radiant and convective heat transfer from the hot flue gas. The 3ry SH bank is fabricated from alloy steel tubes and stainless-steel tubes. Transition pieces are provided for insertion and welding between alloy steel and stainless-steel tubes. The locations where the 3ry SH tubes penetrate the roof wall panel are provided with sealing arrangements to prevent leakage of flue gas and fly ash. The 3ry SH bank and the 3ry SH inlet and outlet headers are supported by rigid hangers to the collector beams which are in turn connected to the hanger beams through spring hangers. The outlet header is connected to the main steam pipe.

4.2.2.3 Reheaters The exhaust steam from the high pressure (HP) turbine (having residual thermal energy after rotating HP turbine) is at a temperature of approx. 350 C (at the RH inlet) at boiler maximum continuous rating and is reheated up to approx. 600 C.

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Figure 4.22 Tertiary superheater. Source: Courtesy MHPS.

The RH consists of two sections of the 1ry and 2ry RH as shown in Fig. 4.23. Cold reheat steam from the exhaust of the HP turbine flows to the 1ry and then to the 2ry section of the RH.

4.2.2.3.1 Primary reheater The 1ry RH assembly consists of horizontal part and terminal part (refer to Fig. 4.24). The horizontal bank basically consists of four sections of bent tube assemblies stacked one above the other with short vertical connecting tubes. The terminal part consists of straight long tubes. The 1ry RH tube banks are supported by the economizer hanger tubes. There is a differential thermal expansion due to temperature difference between the 1ry RH terminal tubes and the economizer hanger tubes. The 1ry RH bank is made of low alloy steel for low-temperature areas and stainless-steel for high-temperature areas. The terminal tubes are made of stainlesssteel only. Both banks absorb heat mainly by convection from the flue gas.

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Figure 4.23 Reheater.

Ash erosion protectors are provided on the 1ry RH tubes and bend at specific erosion-prone locations including the front and rear walls. At locations where the 1ry RH tubes penetrate the roof, sealing is provided to prevent the entry of flue gas and fly ash.

4.2.2.3.2 Secondary reheater The 2ry RH is of the U-shaped pendant type and is located in the passage wall downstream of the 3ry SH (refer to Fig. 4.25). The heat transfer takes place mainly by convection. The steam after passing through the 1ry RH enters the 2ry RH section. The 2ry RH bank is made of stainless-steel tube. Necessary protectors are provided on the RH tubes to avoid damages due to erosion. At locations where the 2ry RH tubes penetrate the roof, sealing arrangements are provided to prevent the entry of flue gas and fly ash into the roof housing.

4.2.2.4 Material for final superheater, main steam pipe, final reheater, hot reheat pipe The Cr content of heat resistant materials is ranging widely from lower to higher. Material should be selected in accordance with steam and metal temperature so as to avoid excessive thickness that leads to the difficulty in processing such as bending and welding, lack of flexibility, and thermal fatigue due to temperature difference between inner and outer surfaces during start-up or load changing period. Fig. 4.26 shows typical materials for high-temperature components.

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Figure 4.24 Primary reheater. Source: Courtesy MHPS.

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Figure 4.25 Secondary reheater. Source: Courtesy MHPS.

Figure 4.26 Materials for high-temperature components.

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4.2.2.5 Desuperheaters To control the final steam temperature at the 3ry SH outlet, spray type desuperheaters are provided between the 1ry and the 2ry SHs and 2ry and the 3ry SHs (refer to Fig. 4.27). Similarly, to control the reheat temperature when large load changes during normal operation or emergency condition, desuperheaters are provided between the 1ry and 2ry RHs. All desuperheaters have similar internal construction. When the RH desuperheater spray is not continuously used, a steam warming pipe connection is provided to avoid any thermal stress to the internal parts due to sudden injection of spray water.

4.2.2.6 Economizer The function of the economizer is to raise the feedwater temperature by absorbing heat from the exiting flue gas before the feedwater enters the furnace wall inlet manifolds (refer to Fig. 4.28). The feedwater enters the economizer via economizer inlet header and then flows upward through the economizer banks in counterflow to the downward flue gas path to increase the heat transfer rate efficiently. Economizers are of horizontal configuration, consisting of tubes placed across the width of SH and RH pass. Carbon steel material is used for economizer tubes. The outlet of the economizer horizontal bank is connected to the economizer intermediate headers. Economizer hanger tubes connect economizer intermediate header to the economizer outlet header. These economizer hanger tubes support the economizer banks as well as the 1ry RH and the 1ry SH coils. The hanger tubes passing through the 1ry SH and 1ry RH tube bank support them using fixed and sliding supports. Antivibration plates are provided over the top tubes of the economizer banks to prevent damage from tube vibration. Ash erosion protectors and cassette baffles are provided on the economizer tubes and bend at specific locations to prevent erosion of tubes due to ash flow. At locations where the economizer hanger tubes penetrate the roof, sealing arrangements are provided to prevent the entry of flue gas and fly ash into the roof housing. The economizer outlet header is supported by spring hangers from the top of the roof housing.

Figure 4.27 Desuperheater.

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Figure 4.28 Economizer: (A) overview of economizer and (B) side view and spiral fined tube of economizer. Source: Courtesy MHPS.

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Figure 4.29 Boiler support construction.

4.2.2.7 Boiler supports The boiler pressure parts are supported and hung from the boiler steel structure (refer to Fig. 4.29). The outlet tubes from each side of the furnace waterwalls, 2ry pass walls, passage walls; 1ry SH, 1ry RH, economizer, etc. are welded to their respective outlet headers located inside the roof housing. The outlet headers are supported on the boiler structural beams using rigid and spring hangers. The inlet headers of the 1ry SH and 1ry RH are supported by economizer hanger tubes. The economizer intermediate headers are also supported by economizer hanger tubes. The economizer inlet header is supported by economizer hopper frame. The 2ry SH, 3ry SH, and the 2ry RH inlet and outlet headers are located in the roof housing and supported on the boiler steel structure. Feedwater and steam pipes connected to the boiler and feedwater are routed outside of the furnace and are supported on the boiler steel structure. Water separator, water separator drain tank, BCP, etc. are the equipment located external to the boiler.

4.2.2.8 Casing and insulation Thermal insulation is provided in the boiler for the following reasons (refer to Fig. 4.30): G

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to prevent burn injury to the operation personnel, to improve efficiency by reducing heat loss from steam and hot water systems, and to protect the boiler internal components from damage.

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Figure 4.30 Insulation of finned tube walls.

The thermal insulation used in the boiler is mainly in the form of refractory, mineral fiber materials, and ceramic fiber products. Refractory materials are provided mainly in the form of castable refractory, in access doors, observation ports, soot blower openings, roof tube penetrations, screen seals, secondary pass division wall seals, and on antishort pass plates in the 2ry pass. Bricks in the form of shaped blocks are provided in the access doors.

4.2.3 Membrane wall Furnace walls are constructed at the site with large-sized panels, being referred to as membrane wall as shown in Figs. 4.31 and 4.32, of tubes and fins welded alternately in the boiler manufacturer’s workshop. Number of tubes, pitch of tubes, tube inside diameter, kinds of material, etc. are selected to attain enough cooling effect against high heat flux from a large volume of fire. There are many openings, on the furnace wall, such as burner ports, manholes, peepholes, soot blowers as exemplified in Fig. 4.33. Around the opening, tubes are

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Figure 4.31 Typical drawing of welding procedure.

Figure 4.32 Manufacturing of furnace-wall panels in a workshop. Source: Courtesy MHPS.

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Figure 4.33 Manufacturing furnace wall in a workshop: (A) furnace-wall opening for manhole and (B) furnace-wall opening for burner. Source: Courtesy MHPS.

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Figure 4.34 Typical drawing of buckstay system.

three-dimensionally bended so as to make opening and to minimize tube space. The wider tube space is, the higher fin metal temperature is. Membrane wall is also applied to rear pass wall and roof. Wider tube space is applied to a part of roof so as to penetrate SH/RH/ECO tubes. As the membrane wall is plate-like structure and is easily deformed, some reinforcements are needed to avoid deformation due to pressure difference between furnace inside and atmosphere, temperature difference among tubes. Backstay system, being one of the reinforcements, is applied to around furnace walls like as hoop of barrel. The four sides of the boiler walls are surrounded by buckstay beams that avoid the possible buckling and deformation of the furnace-wall tubes due to forces applied by the furnace pressure and temperature variations. The buckstays equalize the force around the walls through the corner plates and corner links. The buckstays have provision to allow the walls to expand in the transverse direction during hot condition along the boiler stoppers provided on the buckstay beams. Typical buckstay system is shown in Fig. 4.34.

4.2.4 Pulverized coal combustion 4.2.4.1 Combustion Requirements for coal combustion in the limited combustion space are [1,2]: G

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maximize combustion efficiency; minimize NOx formation; minimize corrosion and erosion; and minimize unbalance of gas temperature, heat flux, gas flow.

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Matching of fuel characteristics, furnace configuration, burner design (primary and secondary air distribution, pulverized coal flow pattern, injection velocity, etc.) pulverizer performance (particle size distribution, reduction of coarse particle, mass ratio of primary airflow and pulverized coal, etc.) is essential to achieve the abovementioned requirements. Flame model of pulverized-coal combustion zone is described as shown in Fig. 4.35. Primary air and pulverized coal are injected from coal burner nozzle to furnace, forming primary combustion zone after they ignited by radiant heat from the surrounding flame and hot slag adhered to the furnace wall. In the primary combustion zone, mainly volatile matter in the coal burns, CH4, H2, CO, and other matters devolatilized from coal particles mix with oxygen diffusing from surroundings and form flames around the coal particle. In the rear stream of primary combustion zone the secondary combustion zone is formed, where mainly char burns. Unburned gas and char flowing from the primary

Figure 4.35 Flame model of pulverized coal combustion: (A) flame model of pulverized coal combustion and (B) transition of pulverized coal particle.

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Figure 4.36 Concept of staged combustion system.

combustion zone are diffusedly mixed with the secondary air injected from auxiliary air nozzles surrounding coal burner nozzle and burns. Char combustion is the combustion of the carbon and oxygen diffusing to char surface and diffusing through pores of char. The combustion speed is far lower than volatile matter. It takes more than 80%
90% of total burning up time for entire coal to burn up char. Staged combustion system is applied to the latest low-NOx combustion by means of dividing the furnace into three zones as shown in Fig. 4.36: 1. Main burner zone In the main burner zone the flame is formed by the ignition of volatile matters emitted from the burner by the radiation heat from its surroundings. NOx produced in this zone results mainly from the volatile matters and is reduced by highly active char as a reducing agent, which is produced by burning the pulverized coal at a high temperature in a reducing atmosphere with an air ratio below 1. 2. Zone from the main burner to AA (reductive deNOx zone) In the zone from the main burner to AA, NOx produced in the main burner zone is reduced by being well mixed with the char as a reducing agent and being kept in the reducing atmosphere for sufficient residence time. In this case, it is important to keep a long residence time in the NOx-reducing atmosphere.

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3. Zone after AA (combustion completion zone) In the zone after feeding AA the complete combustion of the char is carried out by residual combustion air. In this zone, when the oxygen concentration is uneven in the furnace, high oxygen concentration spots are locally formed producing NOx, and extremely low concentration spots produce unburnt carbon in fly ash. Therefore it is essential to keep the air ratio uniform inside the furnace. Although the AA ports of the conventional boiler are composed of a single stage at the corners of the furnace, the current boiler has AA ports of two stages, that is, the lower stage ports located at the corners and the upper stage form feeding. This method (multi AA system) can simultaneously reduce NOx, CO, and unburnt carbon in fly ash.

4.2.4.2 Firing system Typical pulverized coal firing system is shown in Fig. 4.37. The basic principle is mixing fuel and combustion air with the use of jet effect, swirling effect, and eddy effect. This is similar to any burner design. However, since the burner design concept and configuration greatly depend on the furnace design such as heat flux distribution, water circulation, kinds of fuel, etc., various types of burners have been developed by boiler manufacturers to meet stricter NOx regulation and to maximize combustion efficiency with stable ignition over wide load range. Typical firing systems for solid, liquid, and gaseous fuel are circular corner firing and wall firing (opposed firing and front wall firing). Circular corner firing mainly uses parallel flow and wall firing mainly use concentric flow with swirl

Figure 4.37 Typical pulverized coal firing system.

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motion. The important point for circular firing is optimization of a large vortex flame as well as individual burner while optimization of individual burner is more important for wall firing.

4.2.4.2.1 Circular corner firing system Burners are located near each corner. Fuel and air are tangentially injected into the virtual center circle in the furnace so as to form a large vortex flame. For 1000 MW-class boiler, two large vortex flames rotating in clockwise and counterclockwise direction, respectively, are formed in a furnace without partition wall. One set of burner consists of a fuel compartment and two combustion air compartments they are vertically arranged with other sets of burners. A part of combustion air is also injected to furnace around the fuel nozzle in the fuel compartment. Injection velocity and air distribution of each nozzle are designed so as to make relatively long individual flame to form a large vortex flame in the furnace.

4.2.4.2.2 Wall firing The burners are arranged in rows on furnace front and rear wall for opposed firing and on furnace front wall only for front firing. Flame length is controlled to be relatively shorter than circular corner firing with rapid mixing of air and fuel which is effective for complete combustion; on the contrary, gradual mixing is important to control NOx reduction. In order to resolve conflict between the complete combustion and NOx reduction, various type of air and fuel mixing devices such as deflector vane and swirl generator have been applied. The main concepts of low-NOx burner consist of concentration of pulverized coal at burner nozzle outlet and mixing combustion air to proper point of combustion flame as shown in Fig. 4.38. In order to establish proper mixing of pulverized

Figure 4.38 Concept of low-NOx pulverized coal burner.

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coal and combustion air, there are various designs for pulverized coal burner in accordance with kinds of fuel and firing systems. Fig. 4.39 shows the low-NOx firing burner for circular firing system. The lowNOx firing burner for opposed firing system is shown in Fig. 4.40.

Figure 4.39 Low-NOx firing burner for circular firing system (MHPS’s MPM burner). MHPS, Mitsubishi Hitachi Power Systems, Ltd.

Figure 4.40 Low-NOx firing burner for opposed firing system (MHPS’s NR3 burner). MHPS, Mitsubishi Hitachi Power Systems, Ltd.

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4.2.4.3 Pulverizer performance Coarse particle is hard to burn up in the limited furnace space and remains unburned carbon. Performance of pulverizer is an important factor for efficient combustion of coal. Particle size of pulverized coal is evaluated by fineness which is the ratio of passing through 200 mesh (B74 μm) screen. In order to minimize unburned carbon, reduction of coarse particle is effective. Rotary separator type pulverizer can remarkably reduce coarse particles of 100 mesh (149 μm) or larger that plays the dominant role in increasing unburnt carbon as shown in Fig. 4.41. However, because coarse particles are separated by the rotary separator pile on the raw coal on the grinding table, slip vibration occurs when the coarse particles are caught between the rollers. This slip vibration harms the stable operation to maintain high fineness. The latest designed pulverizer realizes stable production of even finer pulverized coal by two-stage separator with fixed type separator integrated with a conventional rotary separator pulverizer. The

Figure 4.41 Fineness of pulverized coal.

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fixed type separator is integrated to return the coarse particles to the center of the table and mix them with raw coal, so that the mill vibration is controlled to ensure stable operation even at a high fineness containing fine particles with 90% or more passing 200 mesh (refer to Fig. 4.42).

4.2.4.4 Slagging and fouling Ash adhesion, which is inevitable for coal-fired boiler as shown in Fig. 4.43, should be controlled within the allowable range in order to keep the boiler stable operation. There are two issues—one is slagging control and the other is fouling control.

4.2.4.4.1 Slagging Excessive slagging on the furnace wall is caused by adhesion of fused ash on the furnace wall surface and building up to thicker and bigger ash layer as shown Fig. 4.44. Thick ash surface is not fully cooled by furnace wall, so ash is partially or fully fused due to radiant heat from fire. Fused ash, in other words, running slag is not easily removed by wall-deslagger, and thus excessive ash adhesion causes deterioration in heat absorption on the furnace wall that leads to unpredictable temperature rise of the furnace outlet combustion gas. Furthermore, big ash deposits on the furnace wall often detach and fall to the furnace bottom. Detached big ash caused damage to furnace bottom tubes. Basic design parameter for slagging control is the ratio of furnace net heat input and furnace plan area (NHI/PA), which has been established by many good and bad experiences for various size furnace and various kinds of coal as exemplified in Fig. 4.45. Ash adhesion on heating surface located at the furnace outlet leads to another problem. The definition of furnace outlet is different for boiler manufacturers and heating surface arrangement, generally inlet of the first convectional heating section, is defined as furnace outlet from the viewpoint of ash adhesion. In order to avoid heavy adhesion the combustion gas temperature at the furnace outlet should be designed to be lower than the softening temperature of ash. This gas temperature is determined by the balance of total heat input such as fuel, heated air, recirculated gas, heat absorption by furnace wall, and sensible heat of combustion gas leaving the furnace. Specifically, the distance between top burner level to furnace outlet plane is selected so that furnace outlet combustion gas temperature becomes lower than softening temperature of ash (refer to Fig. 4.46).

4.2.4.4.2 Fouling Adhesion and accumulation of ash on the heating tubes in the convective heating section are termed “fouling.” Fouling phenomenon depends on the various factors such as composition of ash, ash content, flue gas temperature, tube surface temperature, flue gas velocity passing through row of tubes, tube arrangement (tube diameter, tube pitch, etc.). Fouling is unavoidable phenomenon for coal-fired boiler. Even in the normal operating condition, the amount of heat absorption frequently deviates from statically stable condition due to repeating ash adhesion, naturally falling, and removal by soot blowing. Some deviation for steam temperature can be adjusted by

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Figure 4.42 High-fineness coal pulverizer: (A) concept of two-stage separator and (B) typical coal pulverizer with rotating separator.

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Figure 4.43 Deterioration in coal-fired boiler.

Figure 4.44 Slagging on the furnace wall. Source: Courtesy MHPS.

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Figure 4.45 Furnace size and coals.

Figure 4.46 Ash deposition on the tube surface located above the furnace. Source: Courtesy MHPS.

SH/RH spray, gas distribution damper, gas recirculation, etc. However, deviation cannot be adjusted in spite of continuous soot blowing in case of excessive fouling. Excessive fouling is the cause of many undesirable operating conditions such as: G

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Reduction of heat transfer from flue gas to water/steam leads to steam temperature lower than rated temperature and to increase flue gas temperature at the boiler outlet and lower boiler efficiency. Increase in gas side pressure losses leads to increase in auxiliary power for draft fans. Gas side flow unbalance leads to unbalance of heat absorption and to ash erosion due to locally higher gas velocity, etc. Auxiliary steam consumption increases due to frequent soot blowing.

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Ash accumulation on the tube surface is accelerated by sticky ash deposit catching other ash particles. Accumulated ash plugs the space of tubes and this leads to the reduction in gas passing space and the increase in local flue gas velocity. This causes severe ash erosion of heating tubes leading to tube leakage.

4.2.4.4.3 Coal ash characterization One of the conventional ash characterization methods is based on the ash fusibility evaluated by observation for changing shape of ash molded in accordance with the standards such as ASTM and DIN, typically exemplified in Fig. 4.47. Ash fusibility was originally established to evaluate clinkering behavior of coal ash for stoker-type firing, so they are not directly related to actual condition of pulverized coal-fired boiler. Other conventional ash characterizations are based on oxides such as CaO, Al2O3, Fe2O3, which have been widely used as prediction of ash behavior, and there are plenty of examples for the preceding actual boilers, so ash characterization for new similar coal can be performed with high accuracy by comparison with past records and new coal ash analysis. Various indices for slagging such as base acid ratio, silica aluminum ratio, iron calcium ratio are based on the analysis of completely oxidized ash in laboratory so they do not necessarily match actual fireside phenomenon; however, the accuracy of prediction is improved by cross-checking with prediction and actual phenomenon in the boiler, where base
acid ratio: (Fe2O3 1 CaO 1 MgO 1 Na2O 1 K2O)/(SiO2 1 Al2O3 1 TiO2) silica
aluminum ratio: SiO2/Al2O3 iron
calcium ratio: Fe2O3/CaO

Fouling phenomenon, shown in Fig. 4.48, mainly depends on alkali content in ash. Alkaline compound is vaporized in high-temperature flue gas and condensed on the heating tube surface. Condensed alkaline compound serves as glue that accelerates ash adhesion. Various indices to correlate with slagging and fouling characteristics of coal are shown in Table 4.1. Conventional methods are widely used as principle evaluation of ash behavior; however, they are empirical method and in reality preliminary guidance. There are various attempts to predict ash behavior in the actual boiler, such as computational model, characterization of mineral in the coal by a computer-controlled scanning electron microscope, DTF testing, etc.

4.2.4.5 Corrosion and erosion 4.2.4.5.1 Corrosion Gas side corrosion is roughly classified as sulfide corrosion, sulfide attack, vanadium attack, and circumferential cracking. 1. Sulfide corrosion is caused by sulfurization reaction of metal and corrosive gas such as H2S in reducing atmosphere and sometimes detected on the furnace wall tube surface (refer to Fig. 4.49). In addition to the sulfurization reaction of metal and corrosive gas the other type of sulfide corrosion is groove type corrosion on the furnace wall tubes under the cyclic

Figure 4.47 Ash fusion test ASTM D 1857. Source: Drawn referring to ASTM D 1857: Standard Test Method for Fusibility of Coal and Coke Ash.

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Figure 4.48 Fouling phenomenon.

Table 4.1 Various indices to correlate with slagging and fouling characteristics. Index

Factors

Slagging

Ash fusibility

Temperature for initial deformation, softening, hemispherical, fluid (Fe2O3 1 CaO 1 MgO 1 Na2O 1 K2O)/ (SiO2 1 Al2O3 1 TiO2) SiO2/Al2O3

x

x

Fe2O3/CaO

x

Fe2O3/(CaO 1 MgO)

x

(CaO 1 MgO)/ (Fe2O3 1 CaO 1 MgO 1 Na2O 1 K2O) Fe2O3/(equivalent Fe2O3) 3 100 Equivalent Fe2O3 5 Fe2O3 1 1.11Fe2O 1 1.43Fe SiO2/(SiO2 1 Al2O3 1 CaO 1 MgO) 3 100 Na2O 1 K2O (Fe2O3 1 CaO 1 MgO 1 Na2O 1 K2O)/ (SiO2 1 Al2O3 1 TiO2) 3 Na2O

x

Base
acid ratio Silica
alumina ratio Iron
calcium ratio Iron
dolomite ratio Dolomite percentage Equivalent Fe2O3 percentage Silica percentage Total alkalis Fouling index

x

Fouling

x

x x

x x

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Figure 4.49 Mechanism of sulfide corrosion.

Figure 4.50 Mechanism of groove type corrosion.

thermal stress due to temperature change by load change or ash adhesion/taking off, etc. The mechanism of this type is illustrated in Fig. 4.50. 2. Sulfide attack is caused by sulfurization reaction of metal and sulfur derived from alkaline sulfuric acid such as Na2SO4, K2SO4, or sodium sulfate compound such as Na2S2O7 as illustrated in Fig. 4.51. 3. Vanadium attack is caused by accelerated oxidized corrosion due to melting vanadium compound (nNa2O  mV2O5) as illustrated in Fig. 4.52.

Example for corrosion rate and metal temperature for high sulfur oil fired boiler is shown in Fig. 4.53. It should be noted that this figure is just an example. It is strongly recommended to customize in accordance with the tube material and the specified fuel properties.

4.2.4.5.2 Erosion Erosion is caused by the impact of hard ash particles to tube surface, refractory, and hardware. Ash erosion often occurs in the high gas velocity area of the convective heat transfer section, and it is accelerated by deviated gas flow due to excessive ash fouling. Erosion rate mainly depends on the gas velocity, ash loading (kg/MJ of coal), quartz, iron oxide. In order to minimize ash erosion, erosion protectors are coated on surfaces of tubes including bends at specific erosion-prone locations. Baffle plates are also installed at the front and rear walls to prevent shortcut of gas

Figure 4.51 Sulfide attack.

Figure 4.52 Vanadium attack.

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Figure 4.53 Example of relationship of corrosion rate and metal temperature for high sulfur oil fired boiler.

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Figure 4.54 Protection for ash erosion.

flow through the gap between bend part of heating tubes and wall. Fig. 4.54 exemplify the protector coating and baffle plates installation.

4.2.5 Fluidized bed combustion 4.2.5.1 Principle of fluidized bed combustion Pattern of fluidizing behavior in the furnace varies from fixed bed, fluidized bed, to entrained flow for pulverized coal firing in accordance with the combination of particle size of fluidizing material, solid particle suspending velocity, and upward gas velocity (refer to Fig. 4.55). The stoker combustion is described later in this chapter, and pulverized coal combustion has been described in the previous sections. Then in this section, typical fluidized-bed combustions, that is, bubbling bed and circulating fluidized-bed, are described. The former bed is suitable, in general, for particle size of 2
25 mm, superficial gas velocity in the furnace of 1
2 m/s, and the latter for 0.1
10 mm, 4
8 m/s. NOx generation in both types of fluidized bed is inherently suppressed by relatively low-temperature combustion, which is possible by the large heat capacity of the bed material. On the other hand, deSOx is conducted by adding limestone into the bed, that is, in-bed desulfurization. One of the features of fluidized-bed combustion is adaptability for various kinds of fuel, such as coal, petroleum coke (PC), woody biomass, refused paper and

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Figure 4.55 Pattern of fluidizing behavior in coal-fired furnace.

plastic fuel (RPF), refused-derived fuel, cut tires, paper sludge, as exemplified in Fig. 4.56. Examples of contents of typical fuels are listed in Table 4.2. As listed in Table 4.2 the construction waste contains relatively large water content, and the ash contains K, Na, and P, which may lead to agglomeration of the bed materials. RPF contains relatively high Cl-component, and sulfur content in waste tire is high. Thus the high-temperature corrosion problem may arise by burning them. In such a manner, various problems may arise by burning a variety of fuels, for which fluidized bed boilers should provide countermeasures for long durability and reliability of the system. Typical relationship between the contents and related troubles is summarized in Fig. 4.57 [3]. When the heat transfer tube, for example, evaporator, immersed in the fluidized bed, heat transfer tubes are covered by the cloud of solid particles and thus radiative heat transfer is suppressed even at rather high temperature of the bed, while convective and conductive heat transfer dominate. In addition, solid attack or contact frequency is different around the periphery of the tube, that is, the lower sidewall has rather high contact frequency, but on the upper side solid stagnant may often occur. This solid stagnant suffers the heat transfer. In the inner wall, if evaporator is the case, velocity and mass flux of water should be higher beyond the phasestratification limit for avoiding dryout at the upper periphery of the tube. As shown in Fig. 4.58, there exist solid stagnation at the wake (upper side of tube) and at the upstream stagnation and the horizontal gap of tubes bubbles attack or pass through. Thus the void fraction becomes high, while the fluctuation of void is also high in the horizontal gap, and at the upstream stagnation the void fraction becomes very high. High void fluctuation means frequent exchange of particles and

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Figure 4.56 Various solid fuels for fluidized-bed combustion.

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Table 4.2 Properties of typical fuels.

Water content Volatile matter Char Ash LHV C H N O S Cl Na2O 1 K2O in ash

Unit

Construction waste

RPF

Waste tires

wt.% dry-wt.% dry-wt.% dry-wt.% kJ/kg dry-wt.% dry-wt.% dry-wt.% dry-wt.% dry-wt.% dry-wt.% ash-wt.%

12.7 82.7 16.2 1.1 18.0 46.5 6.3 1.1 45.0 0.020 0.08 6.0

4.4 81.8 6.3 11.9 20.9 40.0 5.9 , 0.3 44.0 0.003 0.15 0.98

0.4 63.4 32.9 3.7 36.8 87.0 7.7 , 0.3 , 1.0 1.71 0.02 0.93

RPF, Refused paper and plastic fuel; Source: Data from T. Takebayashi, A. Otsuka, K. Shintani, Development of 2nd generation MSFB boiler, Mitsui Zosen Tech. Rev. 185 (2006) 1
8.

Figure 4.57 Interrelationships between components of fuels and resulting technical problems. Source: Drawn referring to T. Takebayashi, A. Otsuka, K. Shintani, Development of 2nd generation MSFB boiler, Mitsui Zosen Tech. Rev. 185 (2006) 1
8.

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Figure 4.58 Flow pattern in tube-bank of in-line arrangement (neutron radiography image).

Figure 4.59 Example of heat transfer data of in-line tube-bank (JG/JGmf means volumetric gas flux relative to the minimum fluidization velocity, 0 degree corresponds to upstream stagnation point, and 180 degrees to wake-side).

high-frequency contact of solid on the wall. Then, the heat transfer coefficient at the upstream stagnation becomes worse, and the gap area of around 120 and 240 degrees has very high heat transfer performance as shown in Fig. 4.59. The wake region is deteriorated in heat transfer owing to weak exchange of solid, that is, solid stagnant. Increased volumetric flux beyond a certain limit, the heat transfer becomes rather low as in the case of the highest relative volumetric flux shown in Fig. 4.59. The heat transfer coefficient becomes around 250 even in a worse case, and 400 of the highest case, which means heat transfer outside water tube is rather high. On the other hand, the heat transfer inside the evaporator tubes immersed in the bed is high enough, so that the tube wall is suitably cooled. This is also the case of immersed SH tubes, and wall temperature is at sufficiently lower level relative to the bed temperature. The heat transfer tubes in the bed are arranged usually in horizontal. The flow pattern in such horizontal tube is demonstrated in Fig. 4.60. Even when mass velocity is intermediate level, the intermittent dryout and/or dryout take place at the upper wall

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Figure 4.60 Boiling two-phase flow pattern in a horizontal tube.

of the periphery. When the heat flux through the tube wall is high enough, the wall temperature becomes rather high beyond this dryout point, and approaches to the bed temperature. If the heat transfer tubes are in a serpentine form, bubbles sometimes agglomerate at the bends of the serpentine, or phase separation may occur in the bends, which may lead tube-wall superheat. In actual plants, various countermeasures, for example, setting suitable circulation rate of water and/or slightly inclined tube arrangement, effectively prevent damages of the heat transfer tubes.

4.2.5.2 Bubbling fluidized bed boiler Bed material (sand) are suspending and randomly moving by bubbles forming within the fluidizing bed when upward gas velocity is low, and fuel burns in fluidizing bed material. This type of boiler named bubbling fluidized bed boiler, as illustrated in Fig. 4.61 [4]. Under the higher temperature and pressure conditions, SH (final SH) protected by refractories is installed in the fluidized bed to reduce corrosion from sulfur content and abrasion by sand as shown in Fig. 4.62.

4.2.5.3 Circulating fluidized-bed boiler As the upward gas velocity increases, fluidized bed expands and particle motion becomes more furious. In the combustor, highly dense dispersion of fuel and sand is achieved [5]. A large volume of particles is leaving from combustor, so leaving particles are captured by cyclone installed downstream of the combustor and recirculated to the combustor in order to keep the required residence time for combustion and to keep the required particle concentration in the combustor. A part of recirculated particles returns to the combustor through U-shaped seal pot and the residual recirculated particles flow into the fluidized-bed heat exchanger (FBHE), in some cases being referred to as external heat exchanger. In the FBHE, SH and evaporator are installed to heating up steam and feedwater and cooled recirculated particles return to the combustor. Temperature of the combustor is maintained by the balance of fuel input, sensible heat of air, flow rates of directly recirculated particles, and cooled recirculated particles. In the combustor, slip velocity (5gas velocity 2 particle velocity) takes maximum, so higher heat transfer is achieved. The amount of recirculated particles is

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Figure 4.61 Bubbling fluidized-bed boiler.

40
100 times of fuel, so homogeneous gas temperature can be kept inside the whole of combustor. After removing particles by the cyclone, combustion gas flows into the convection heating section, SH, RH, and ECO. Fig. 4.63 is a block diagram of boiler plant. The draft system is a balanced draft system. Primary air is boosted by a forced draft fan and primary air draft fan, preheated by an air preheater, and sent into the wind box at the bottom of the combustor. Secondary air is preheated by the air preheater and injected into the combustor from the secondary air nozzle installed in the lower part of the combustor. Combustion gas leaving the combustor is separated from the bed material in the cyclone, reaches the back pass to undergo heat exchange in the SH and economizer, undergoes further heat exchange by the air preheater, and leaves the boiler. After leaving the boiler the combustion gas is cleaned off dust by a bag filter and is guided into exhaust duct installed in the upper part of the boiler by an induction draft fan.

4.2.6 Stoker combustion 4.2.6.1 History of stoker combustion Coal combustion technology started by hand-scattering of coarse grain coal on a fire grate. In accordance with an increase in boiler capacity, mechanical stokers, for example, chain grate stoker, traveling grate stoker, inclined stoker, stepped stoker, spreader stoker, and so on, appeared. The first mechanical stoker with circular-plate type grate rotating around vertical axis was proposed by W. Brunton in 1819, while this first stoker was abandoned. Practical and efficient stoker was the traveling grate stoker developed by J. G. Bodmer in 1834. Since then, J. Jukes (1841), S. Hall (1845), R. F. Weller (1871), and so on developed successively various types stokers mentioned previously. The stoker combustion was one of the main boiler technologies, while pulverized coal combustion has successively expelled stokers from large-capacity power boilers. The stoker combustion has, on the contrary, shrunk

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Figure 4.62 Bubbling fluidized-bed boiler of high temperature and pressure condition.

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Figure 4.63 Circulating fluidized-bed boiler.

successively in the power generation filed, while still remains mainstream in the field of incineration firing [6]. As mentioned earlier, stoker incinerators have conventionally been combustiontype and used as coal or bark incinerators, however, since the world’s first stokertype incinerator facility was established in 1873 in Manchester. This technology has gained attention as a way to counteract the rise of industry and increased waste processing problem. Continuous incinerators capable of operating around the clock started being built throughout the world from around 1950 [7]. Seventy-four percent of all stoker-type incinerators built as waste incinerators have been built within the last 10 years [8].

4.2.6.2 Characteristics of waste as a fuel Waste possesses the following characteristics which differ from solid fuels such as coal and require advanced technologies for stable combustion [9]. G

G

G

G

The lower heating value has a wide range of approximately 6
13 MJ/kg, depending on the season and region. A high water content of between 35% and 65%. A mix of plastic and cellulose material with differing burning characteristics. A variety of different shapes and sizes without a constant burning velocity.

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4.2.6.3 Basic configuration of stoker-type incinerators and the waste combustion process Many different varieties of stoker incinerators exist and the grate type stoker incinerator is the most widely adopted for burning waste. A rough sketch of a grate type stoker incinerator is shown in Fig. 4.64. Waste inserted onto the charging hopper is fed onto the grate using a waste feeder. The equipment is configured with multiple different grates including a drying grate, combustion grate, and aftercombustion grate and is set up in such a way to provide ample staying time for the combustion of waste. Combustion air is supplied via nozzles installed under the grates and combustion chamber. A conceptual diagram of the waste combustion process is shown in Fig. 4.65. Waste fed into the incinerator is first dried on the drying grate from the radiant heat of a high-temperature wall surface and luminous flame. Next, it is placed on the combustion grate where the volatile matter content is released. The volatile matter is burned by mixing it with the air supplied from below the grate, generating a luminous flame. Finally, fixed carbon and other combustible material are completely burned on the aftercombustion grate and the residual is discharged as ash.

4.2.6.4 Stoker-type combustion incineration configuration 4.2.6.4.1 Waste feeder The state of the feed provided by the waste feeder has a significant impact on combustion and requires the following functions [9]: G

G

Waste can be stably and continuously supplied. Sufficient allowance for adjustment of feed quantity to an appropriate range according to changes in the waste heating value and combustion conditions within the incinerator.

Figure 4.64 Stoker incinerator schematic.

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Figure 4.65 Diagram of combustion process in stoker-type incinerator.

Figure 4.66 Pusher waste feeder. G

Waste that has become compressed while residing in the hopper is loosened when being fed into the incinerator to obtain good air permeability.

Almost all stoker incinerators are equipped with a pusher to satisfy these requirements. A drawing of the pusher waste feeder is shown in Fig. 4.66.

4.2.6.4.2 Stoker The stoker must be able to homogeneously transfer waste and provide moderate agitation and mixing for stable combustion. The most well-known grate configurations making this possible are explained below and shown in Fig. 4.67. G

Horizontal reciprocating type: Waste is agitated while being fed through the reciprocating motion of the variable grate and movable and fixed grates alternate in the direction of the waste feed. This method is well suited for waste with a comparatively high heating value.

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Figure 4.67 Grate diagram (yellow mean movable grates, green mean fixed grates): (A) horizontal reciprocating type, (B) reverse acting type, and (C) vertical oscillating type.

G

G

Reverse-acting type: Movable and fixed grates are oriented at a slight angle to the waste feed and a part of the waste layer is reversed to the direction of the main movement by reciprocating movable grates to the waste upstream. This provides a high level of waste loosening and agitation. Vertical oscillating type: Grates are arranged in the direction of the incinerator width in moving, stationary and alternating, and waste is transported and agitated by reciprocating the operating grate from front to back. Widely used for low to comparatively high heating value waste.

It is vital to feed combustion air uniformly throughout the incinerator for stable combustion. However, because waste comprises flammable material, flame resistant material, and incombustible material, partial blow-by can occur due to changes in air-flow resistance of the grates. As a way to counteract this, in many cases the stoker itself has an air-flow resistance greater than the air-flow resistance of the waste layer.

4.2.6.4.3 Incinerator types It is essential that the radiant heat of the luminous flame be appropriately imparted on the surface of the waste layer for stable combustion and the shape of the incinerator is a vital element, similar to the grate configuration. Incinerator shapes are classified as follows according to the relationship between the flow of combustible gas and waste. The conceptual diagram for each incinerator shape is shown in Fig. 4.68. G

G

G

Counter-current flow type: Type with opposing combustible gas and waste flows which is suitable for low heating value waste with a high moisture content due to the ability to easily supply radiant heat from the flame to the layer of waste near the drying step. Cocurrent flow type: Type with cocurrently flowing combustible gas and waste which is suitable for high heating value flammable waste. Center current flow type: Type in between the countercurrent flow and cocurrent flow types which crosses combustible gas flows with waste flows. Most suitable for waste heating values with significant fluctuations.

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Figure 4.68 Incinerator types: (A) countercurrent flow type, (B) cocurrent flow type, and (C) center current flow type.

4.2.6.4.4 Measures for increased durability Because an especially significant heat load is placed on the main combustion area of stoker, the following considerations are required to improve durability. G

G

G

Use of heat-resistant material with excellent thermal strength, heat, and corrosion resistance and wear resistance for grate blocks, mainly those in the burning area. The grate block is made of a shape with high coolant effect. There are also recent examples of water-cooled grates. Particular attention is paid to the thickness of the waste layer and grate momentum so the grate blocks do not come into contact with the high-temperature flame within the incinerator.

4.2.6.5 Combustion control technology for stoker-type combustion incinerators It is important to appropriately control the feed speed, grate speed, and air supply volume for the stable combustion of fluctuating waste. The stoker incinerator combustion control integrates control elements such as those shown in Table 4.3 and is performed automatically [10]. In addition, recently practical development is moving forward to predictive control technologies using AI technology to forecast CO concentration and the steam generation volume to prevent destabilization in advance [11].

4.2.6.6 Recent stoker combustion technology In recent years, waste incinerator facilities have been required to further reduce harmful substance emissions and have higher efficiency power generation. An increasing number of facilities are combining the use of low excess air combustion with a general air ratio of approximately 1.3 with exhaust gas recirculating systems as one means of achieving this. Exhaust gas recirculating systems used in stoker incinerators use a system to blow exhaust combustion gas into the combustion chamber after dust removal, which is effective for reducing NOx concentration with the benefit of reducing oxygen concentration and flame temperature. Also, adjustments to the supply method of recirculating gas make it possible to promote mixing within the combustion chamber. An example of an exhaust gas recirculating system is shown in Fig. 4.69 [12].

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Table 4.3 Control elements for stoker incinerator automatic combustion control. Control elements

Typical sensor

Typical operating elements

Waste layer thickness control Steam generation control Combustion position control Ignition loss control

Waste layer thickness

Feeder and grate speed

Steam generation

Feeder speed, air volume from under grates Grate speed

Temperature control Oxygen control

Temperature at burnout zone Temperature at burnout zone Temperature at second chamber Oxygen concentration

Air volume from under burnout grate Air volume from under grates and nozzles Air supply volume from nozzles

Source: Data from M. Furubayashi, Frontline and Issues Concerning the Use of Biomass and Waste Power Generation as Energy, S&T Publishing, Chapter 9, Section 2 [2] (in Japanese).

Figure 4.69 Diagram of exhaust gas recirculation system [12].

Also, Fig. 4.70 shows an example of operating data from a facility using this technology [13]. The quick supply of recirculating exhaust gas from the rear of the combustion chamber thoroughly mixes the primary combustion chamber resulting in operation with a low air ratio of an average O2 concentration of 3.6% at the boiler outlet. This achieves a stable steam generation volume, low NOx, and CO.

4.2.7 DeNOx, deSOx process, gas cleaning In Japan environmental issues became serious from the 1960s, and to address these issues, emission regulations were progressively introduced and laid down stricter standards. The Japanese NOx, SOx, and PM emission standards are more stringent than any other country. In recent years, global emission standards have become

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Figure 4.70 Sample of operating data with exhaust gas recirculation system [13].

more demanding every year, and the number of regulated substances is increasing. Thus advanced technologies are required to deal with new types of fuel and more extensive operations conditions.

4.2.7.1 NOx reduction (selective catalytic reduction) 4.2.7.1.1 History and basic technique The first NOx emission regulation in Japan was established in 1973. Development of selective catalytic reduction (SCR) was started in the 1960s, and the first SCR system was commercialized for thermal power plants in 1977 in Japan, the earliest anywhere in the world. After that to comply with tightening of regulations the technologies have been improving. In SCR system, NOx is decomposed into N2 and H2O by NH3, injected upstream of catalyst as following reactions. Since NOx is reduced specifically, the process is referred to as “SCR.” 4NO 1 4NH3 1 O2 ! 4N2 1 6H2 O NO 1 NO2 1 2NH3 ! 2N2 1 3H2 O 6NO2 1 8NH3 ! 7N2 1 12H2 O Most SCR catalysts are roughly divided into plate-type, honeycomb-type, and corrugated catalysts, of which plate and honeycomb types are mainly adopted (Fig. 4.71) in consideration of the type of fuel, system configuration, operating conditions, customer needs, and so on. Plate-type catalyst was proven to have much higher erosion resistance than homogeneous-type catalyst. Once ash particles plug part of catalyst layer, the gas velocity of the rest part of catalyst layer increases, which accelerates erosion of the catalyst. So, prevention of both plugging and erosion is an important issue for high reliability of the SCR process.

4.2.7.1.2 Technology lineup 4.2.7.1.2.1 Examples of selective catalytic reduction system application To mitigate NOx emissions from various thermal power plants including coal-fired, gas

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Figure 4.71 SCR catalyst. SCR, Selective catalytic reduction.

Figure 4.72 SCR system schematic. SCR, Selective catalytic reduction.

turbine combined cycle, gas turbine simple cycle, and PC-/heavy oil-/other lowquality solid fuel-fired types, it is essential to apply an SCR system suitable for each thermal power plant. Fig. 4.72 shows a schematic of an SCR system. An SCR system is in some cases installed in a brand-new thermal power plant under

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construction, while in other cases, it is retrofitted to reduce nitrogen oxide emissions under the intensified environmental regulations over thermal power plants in operation or as part of environmental preservation measures. 4.2.7.1.2.2 High-performance/low-SO2 oxidation catalyst SCR catalyst converts part of SO2 in the flue gas to SO3, which causes air heater fouling, corrodes downstream equipment, and increases sulfuric acid mist emission from the stack. The SO2-to-SO3 conversion rate is usually closely related with denitration activity so that when the SO2-to-SO3 conversion activity is reduced, larger catalyst volume is required to maintain the required denitration performance. R&D of catalyst manufacturing process and the screening of new materials resulted in highdenitration activity while maintaining low SO2-to-SO3 conversion rate (Fig. 4.73). This type of catalyst is delivered to plants in Japan and abroad mainly in the United States, Europe, and Asia (China, South Korea, and Taiwan). 4.2.7.1.2.3 Mercury oxidation catalyst Under the regulations for mercury and other toxic substances in the United States (MATS: Mercury and Air Toxics Standards) and the international Minamata convention on mercury, it is necessary to reduce the amount of mercury emitted from power plants. Accordingly, the adoption of a system that oxidizes mercury at the denitration catalyst section into soluble mercury halide and then collects it by wet desulfurization equipment at a later stage is being considered. Hence, a mercury oxidation catalyst which oxidizes mercury efficiently has been developed and applied mainly to the US market, where mercury emission regulations have intensified. As mentioned earlier conventional technology had the problem that if the catalyst’s activity of mercury oxidation increased, the conversion from SO2 to SO3 also

Figure 4.73 Characteristics of high-performance denitration/low-SO2 oxidation rate.

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Figure 4.74 Concept of mercury oxidation catalyst.

Figure 4.75 Characteristics of mercury oxidation catalyst.

increased. On mercury oxidation catalyst, the mercury oxidation activity alone was increased, with its SO2 conversion and NOx reduction activities maintained at a level equivalent to those of the conventional catalyst, through the reaction mechanism-based optimization of catalyst composition/manufacturing method (Figs. 4.74 and 4.75).

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4.2.7.1.2.4 Recycling of catalyst Used catalysts are able to be recycled on demand through one of the following processes: G

G

G

G

Water-washing spent catalysts and coating catalytic component (ecological catalysts). Reshaping once-powdered spent material into a grid pattern and coating catalytic component (recycled catalysts). Washing spent catalysts with a chemical solution to be reprocessed (new-type cleaned catalysts). Renewing spent catalysts on-site instead of bringing back them to the processing factory (on-site renewed catalysts).

4.2.7.1.2.5 High-performance catalyst in case of high NO2 ratio When a gas turbine starts up or is low-loaded, exhaust gas from the turbine tends to contain NOx with high NO2 concentration. As the ratio of NO2/NOx increases, NOx reduction performance decreases. A high-performance catalyst has been developed to avoid performance degradation even if the ratio of NO2 increases (Fig. 4.76). It has been delivered to plants in Japan and abroad. 4.2.7.1.2.6 High-temperature selective catalytic reduction catalyst SCR system, if installed in a simple-cycle gas turbine power facility to supply emergency power, is required to have high-denitration performance over the high-temperature range because of lack of heat recovery system in front of the SCR system. In response, high-temperature SCR catalyst has been developed. It suppresses the decomposition of ammonia on catalyst to provide sufficient performance at high temperatures up to 530 C (Fig. 4.77).

Figure 4.76 Characteristics of catalyst for high NO2 ratio.

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Figure 4.77 High-temperature SCR system outline. SCR, Selective catalytic reduction.

4.2.7.1.2.7 Low-SO2 oxidation catalyst for low-quality solid fuel Exhaust gas from high-sulfur content PC, heavy oil and other low-quality solid fuel-firing boilers incurs an increase in the rate of SO2 oxidation at SCR catalyst section with time, and such an increase must be suppressed in plant operation. A low-quality fuel-purpose low-SO2 oxidation catalyst is capable of suppressing an increase in the SO2 oxidation rate through the surface treatment of the catalyst.

4.2.7.2 SOx reduction (wet flue gas desulfurization) 4.2.7.2.1 History and basic technique The first SO2 emission regulation in Japan was established in 1968. Development of flue gas desulfurization (FGD) technologies was started far before the regulation establishment. There are three major types of desulfurization processes for the flue gas of thermal power plants—wet, dry, and semidry, and the wet-type desulfurization process is the most prevalent method for the power plant field because of its reliability and cost effectiveness. In particular, limestone
gypsum process is the most prevalent technology among wet FGDs in which natural limestone is used as absorbent slurry and by-product gypsum is recovered as a valuable resource for recycling. After SO2 is absorbed and reacts with the limestone, gypsum is generated by oxidization as the following reaction. The generated gypsum can then be effectively utilized as a raw material for cement or plasterboard. CaCO3 1 SO2 1

1 O2 1 2H2 O ! CaSO4U2H2 O 1 CO2 2

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Figure 4.78 Double contact flow scrubbers. Source: Courtesy MHI.

In Japan, wet FGD was commercialized for thermal power plants in 1972, since then to comply with tightening of regulations the technologies have been improving. Early wet FGD employed grid-type or tray tower type absorber. In the late half of the 1970s and the 1980s double contact flow scrubber (DCFS) type and spray tower type absorbers became mainstreams. In 1990 an innovative configuration that performs absorption and oxidation of SO2 in a single absorber tower equipped with an in situ forced-oxidation system came into practical use. After that, new techniques using high gas-flow velocity and high-concentration slurry were developed, thereby achieving high SO2 and PM removal performance. Now this type of desulfurization equipment has been utilized in many countries around the world. Figs. 4.78 and 4.79 show DCFSs and a spray tower scrubber, respectively. The optimal scrubber type is selected based on flue gas conditions, site layout, etc. The DCFS comes in two design configurations; single tower and twin tower as shown in the figure. The single tower design is typically used on low-to-medium sulfur coals and the twin tower design is typically used on medium-to-high sulfur coals to achieve high PM removal. In a spray tower scrubber, to achieve high SO2 and PM removal performance, a high effective contact between flue gas and spray droplets has to be achieved. For this purpose the flue gas leakage through spray zone should be avoided and the contact efficiency between flue gas and sprayed droplet should be maximized.

4.2.7.2.2 Technology lineup 4.2.7.2.2.1 Limestone
gypsum wet desulfurization equipment for bituminous/subbituminous coal-fired boilers The wet limestone
gypsum method is the most common technology used in the treatment with a high desulfurization efficiency covering flue gas with a wide range of inlet SO2 levels. For example, one FGD equipment in the United States that has the world’s largest flue gas treatment capacity of more than 4 million m3N/h through the use of a single tower,

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Figure 4.79 Spray tower scrubber. Source: Courtesy MHI.

Figure 4.80 Desulfurization equipment installed at Kozienice power plant (equivalent to 800 MW) [14].

and another in Poland which collectively treats flue gas emitted from five different boilers through the use of a single tower (refer to Fig. 4.80). 4.2.7.2.2.2 Limestone
gypsum wet desulfurization equipment for lignitefired boilers Because of its relatively abundant reserves and economic advantages, the amount of lignite used has tended to increase in recent years. Generally, compared with bituminous or subbituminous coal-fired boilers, lignite-fired boilers have a tendency of both moister content in flue gas and the sulfur content in the coal being high. Therefore, in many cases, the desulfurization equipment should be capable of treating high-temperature flue gas with a high SO2 removal rate. To respond such

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requirement desulfurization equipment that can handle flue gas with an inlet SO2 level exceeding 18,000 mg/m3N has been designed and provided. 4.2.7.2.2.3 Limestone
gypsum wet desulfurization equipment for heavy oil-fired boilers The residues of petroleum refining were conventionally disposed of as waste, but recently, they are often used as fuel for thermal power generation. Because the residues are rich in sulfur and their flue gas contains higher concentrations of SO2 as well as SO3, flue gas treatment technology is necessarily suitable for such types of flue gas. A comprehensive flue gas treatment system, being capable of handling flue gas containing high concentrations of SO3 under stable operation, has been developed and put in practical use. 4.2.7.2.2.4 Seawater desulfurization equipment In this desulfurization system, no chemicals such as magnesium hydroxide or limestone are used as absorbents. Instead, alkaline compounds naturally contained in seawater are utilized for desulfurization. This simple framework of a desulfurization system can serve as an alternative method even when the plant location makes it difficult to prepare absorbents or handle by-products. There has been a noticeable increase in the number of power plants that employ this seawater desulfurization process, especially in emerging countries such as India and those in Southeast Asia and the Middle East. The mechanism of seawater desulfurization is the absorption of SO2 in flue gas into seawater at the absorption tower, followed by the formed sulfate ions (HSO32) being oxidized through contact with large quantities of aeration air in the aeration basin, thus producing harmless sulfate ions (SO422). As sulfate ions are contained abundantly in seawater, there is little impact on the marine environment. Simultaneously in the aeration basin, pH values are adjusted by means of neutralization and aeration and lowered levels of dissolved oxygen are recovered by oxidation, before the treated seawater is ultimately discharged into the sea (refer to Fig. 4.81).

Figure 4.81 System flow of seawater desulfurization equipment [14].

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As examples, one installed at a heavy oil-fired plant treats flue gas with one of the highest SO2 levels for desulfurization using seawater (Saudi Arabia), and another is installed at the world’s largest class 856 MW coal-fired plant (Indonesia).

4.2.7.3 PM reduction (electrostatic precipitator) 4.2.7.3.1 History and basic technique During the high economic growth period of Japan, the amount of exhaust gas discharged from thermal power plants rapidly increased due to the development of the heavy and chemical industry. As a result, air pollution problem became intensified. The particulate matter (PM) emission standards of Japan were established in 1968 and enforced. Then, a demand for high-performance PM collectors increased at accelerating speed, and dust collection technology also developed rapidly. There was a surprisingly great increase in the number of electrostatic precipitator (ESP) in demand, in particular. Compared with bag filter that has almost constant performance for various kinds of PM, ESP has difficulty in sizing which depends on characteristics of PM, because its performance is affected by property (especially resistivity) of PM. However, ESP has economic advantages in small pressure loss (low operation cost), easy maintenance, etc., so that it is basically applied as the most popular equipment in this filed. Japan’s economy entered a period of stable growth after the twice energy crises in 1973 and 1979. In those days, PM emission standards were enforced. Therefore high-performance and economical PM reduction equipment and flue gas treatment systems were required for a further reduction in dust emissions. The situation led to the development of a variety of unique ESP technologies and waste gas processing systems in Japan ahead of the rest of the world. The PM reduction principle of ESP is as follows (refer to Fig. 4.82). Supplying high voltage between collecting electrode and discharge electrode generates a corona discharge that produces minus ion. The electrically charged PMs are attracted toward the collecting electrode by an electrical force. The accumulated dusts are discharged by rapping hammer (dry-type ESP) or by flushing water (wettype ESP).

4.2.7.3.2 Technology lineup 4.2.7.3.2.1 Dry-type electrostatic precipitator Most of the ESP for coal-fired boiler application is the so-called dry-type ESP shown in Fig. 4.83, which adopts mechanical impact such as rapping as the method of removing PM being adhered to electrodes. Main construction of ESP is as follows: 1. Collecting field: Electric field being composed of discharge electrodes and collecting electrodes is referred to as collecting field, and its capacity is determined according to the treating gas volume, required collecting efficiency, etc. Collecting field is divided into several chambers being independently applied high DC voltage. 2. Hopper: Hopper stores dust collected and removed from collecting field, and it is usually designed as inverted pyramidal shape. It is required to be designed with enough valley angle, and also with ancillary devices such as steam heater, for the prevention of dust

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Figure 4.82 Principle of ESP. ESP, Electrostatic precipitator.

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Figure 4.83 Structure of dry-type ESP. ESP, Electrostatic precipitator. clogging and easy discharge of the dust. Such hopper valley angle and ancillary devices are determined according to characteristics of dust such as agglomeration and fluidity. 3. Inlet and outlet nozzle: Defusing and reducing parts connecting between collecting field of ESP and ducts installed at upstream and downstream of ESP. They must be designed considering gas flow distribution in ESP. Especially, gas distribution plates, which are usually three-stage-type in coal-fired boiler application, are installed in the inlet nozzle in order to achieve uniform gas flow distribution in ESP. 4. Supporting structure: Steel structure, which supports the upper construction mentioned above, is required.

4.2.7.3.2.2 Moving electrode electrostatic precipitator In a conventional drytype ESP, which comprises only general fixed electrodes, fine PM is entrained in the flue gas, and reemitted during hammering for the detachment and collection of PM accumulated at the collecting electrode, resulting in an increase of the concentration of PM emitted from the stack [15]. In addition, PM with high electric resistivity has a strong adhesion force to the collecting electrode and a strong cohesive force between particles, and it is difficult to detach by the impact of hammering,

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Figure 4.84 Structure of MEEP. MEEP, Moving electrode electrostatic precipitator.

resulting in degradation of the performance of the electrode due to contamination over time. The general fixed electrodes are installed at the front stage to roughly remove PM of several tens of thousands mg/m3N floating in flue gas to a certain degree, and the MEEP (moving electrode electrostatic precipitator) technology developed by Mitsubishi Hitachi Power Systems, Ltd. (MHPS) is installed at the rear stage to remove the remaining fine PM and high electric resistivity PM. Thus the concentration of PM at the ESP outlet is reduced to several tens of mg/m3N. MEEP is structured like a caterpillar as shown in Fig. 4.84. While the collecting electrode element is rotated by the driving chain, the electrostatically collected PM on the element surface is scraped off using a brush installed in the hopper in which no flue gas flows. Therefore MEEP exerts a superior particulate collection performance for high electric resistivity PM at the general fixed electrode which is difficult to detach by hammering or for fine PM which is entrained in the gas flow and reemitted by hammering. Accordingly, when MEEP is applied to a retrofit project for the purpose of enhancing the capability of the existing ESP, the performance is improved without increasing the ESP installation area, and the use of MEEP is a very effective measure to cope with the recent strengthening of flue gas regulations in various countries around the world. 4.2.7.3.2.3 Wet-type electrostatic precipitator The wet-type ESP shown in Fig. 4.85 collects electrically charged PM in gas to the collecting electrode by electrostatic force (Coulomb force) just like a dry-type ESP; however, the collected PM on the collecting electrode is removed by water washing in the wet-type ESP, while it is removed by rapping in a dry-type ESP. The wet-type ESP has various advantages compared with a dry-type ESP, such as less affection from electric resistivity of PM, few reentrainment of PM which enables removing to very low PM concentration, so

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Figure 4.85 Structure of wet-type ESP. ESP, Electrostatic precipitator.

that recently sometimes wet-type ESP is installed at downstream of conventional flue gas treatment system consisting of dry-type ESP and wet-type FGD system, when very severe PM emission regulation is required.

4.3

Water circulation design

One of the important concerns and performances desired in the course of social implementation of boiler has been the safety to prevent damage, sometimes becomes destruction, caused not only by explosion due to rapid combustion but also by rupture (burst) caused by creep and/or fatigue. Considerations to suppress the former damage are related to the field of combustion phenomena as described in Section 4.1. As for the latter damage, practices and know-hows have been accumulated to keep boiler components, made of ferrite-base materials for water circulation system, from excessive temperature and thermal stress at which they cannot endure creep rupture and fatigue damage.

4.3.1 Water circulation system principle Among design principles to prevent excess temperature and thermal stress, water circulation system is probably one of the most complicated and important assemblies to be equipped with desirable configuration and selected to have appropriate materials to satisfy the specified function. The main reason is that the water circulation system inevitably handles steam-water two-phase mixture, and the other is that the boiler pressure parts are nowadays usually enclosed in the membrane wall composed of water circulation system. This means that the water circulation system constitutes dominant structure of boiler to the extent that reconstruction is not easy.

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Figure 4.86 Typical three types of boiler classified by water circulation system.

Along with upgrading in steam condition (pressure and temperature) together with expanding capacity (steam evaporation rate), water circulation system in the course of evolution, as explained in Chapter 2, Introduction to Boilers, is classified as three major types below listed [16], also illustrated in Fig. 4.86: 1. Submerged cylindrical type 2. Water tube type a. Natural circulation b. Forced circulation 3. Once-through type

In Fig. 4.86, concepts of water circulation are illustrated together with one of the typical design parameters, circulation ratio (CR) defined as: CR 5

Flow through evaporator Evaporation flow

CR expresses how much ratio of mass of coolant (water and steam), which is wetting heating tubes, to evaporating steam, and also represents average top dryness (steam quality at the outlet of water circulation system) by its inverse value.

4.3.2 Submerged cylindrical type This type has the feature of construction that water in a vessel evaporates on the outer surface of the furnace and flue tubes heated by fire flame and flue gas. This

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Figure 4.87 Specific weight of water, steam, and their mixture. Source: Data from H. Herkenrath, P. Mork-Morkstein, U. Jung, F.J. Weckerman, W¨armeu¨bergang am Wasser bei Erzwungener Stro¨mung im Druckbereich von 140 bis 250 bar, EUR3658d, 1967.

type is applied to the boiler at relatively low pressure around 1 MPa with small capacity up to around 10 t/h of steam generation. Function to cool tube metals, together with vessel, is ensured by quick and continuous wetting action of water (replacement of water to bubble at boiling surface), which is enhanced by (1) large density differences between water and steam at low pressure as illustrated in Fig. 4.87, and (2) enough amount of water filled in vessel. In other words, gravity ensures necessary cooling capability as long as water is contained at a certain level in the vessel. In terms of CR the value is close to infinite. High value of circulation ratio decreases anxiety of critical heat flux (CHF, heat deterioration phenomenon caused by liquid film dryout or boiling transition from nucleate to film boiling, being referred to as burnout, occurs at the CHF). Heat transfer of this type is referred to as pool boiling heat transfer. Vapor bubble nucleation occurs at the heated surface, and bubbles detach by buoyancy due to large density difference between water and vapor as illustrated in Fig. 4.88. The induced velocity by the bubble detachment is relatively low, but the bubble

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Figure 4.88 Replacement action by water to bubble by gravity.

departure diameter is small and the frequency is high enough that heated surfaces may be prevented from overheating in a wide range of heat flux. Beyond the CHF, however, film boiling may take place leading to red-hot of heated surface. The thick-scaled wall is also the case. At the above background, it is easily understood that the regulation stipulates the installation of water-level gauge(s) at the vessel and periodical observation to check no loss of water which would directly bring sudden burst and fatal incident, as you may imagine when an empty kettle is heated up.

4.3.3 Water tube type Water tube type illustrated in Fig. 4.86 had been innovated in order to overcome the difficulties to cope with increased pressure and capacity. When the steam pressure increases, and density difference between water and steam becomes small, then the cooling mechanism of submerged cylindrical type no longer provides enough water quantity to boiling surface, which potentially degrades cooling performance. Furthermore, larger steam evaporation rate requires too much water storage in vessel to realize economical and reliable construction. The above two factors of obstacle necessitated water tube type boiler which literally separates “water tube” from vessel. The separated vessel, which is changed to “steam drum” without any heat input from fire flame or flue gas, is illustrated in Figs. 4.86 and 4.89. This separation enabled to adopt the following merits with decreased CR. The design of steam drum is concentrated to satisfy the required efficiency for separation of steam from water and vice versa to fit the higher pressure. On the other hand, water tube becomes ensured to be cooled by forced convection through continuous supply of enough water for avoiding DNB (Departure from Nucleate Boiling). Then, “water circulation circuits” are composed of steam drum, downcomer, and water tube that form so-called waterwall as illustrated in Fig. 4.89. Combustion chamber became to be surrounded by waterwall, referred to as “furnace

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Figure 4.89 Flow diagram of water tube type boiler.

waterwall” as illustrated in Figs. 4.11 and 4.14. The furnace waterwall should be designed to realize proper size (height and width) for combustion process, as described in Section 4.1, that is, for complete combustion, slagging suppression, and appropriate volumetric heat release rate. The driving force that induce natural circulation of water to keep the water velocity in water tube to avoid DNB is caused by the difference in gravitational pressure drop between downcomer and water tube. The circulation rate is determined by the momentum balance between this driving force and the frictional pressure drop throughout the circuit. Force balance is principally formulated by Mu¨nzinger, as described in Section 2.4.2, as shown in the following again:  v21 ρw F F F h 2 h 5 he 1 hR 1 ξ (4.8) 1 ½he 1 hBe 1 hR 1 hB 1 ha  ρ0 g

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Fluid velocity is calculated by the major inputs such as boiler height, subcooled temperature and inner diameter of downcomer, steam quality and inner diameter of water tube, and the length together with surface roughness of each component consisting the circuit. As long as sufficient cooling capability is obtained, boiler manufacturers adopt the proper combination for the above design parameters and specifications. There are two types of circulation system to assure the cooling capability, classified into natural circulation and forced circulation. The driving force of the former relies on downcomer fluid weight, and the latter is equipped with BCP in downcomer to assist driving force as illustrated in Fig. 4.89. In the former type, relatively taller height and larger diameter are preferable to attain the reliable cooling rate, and as for the latter type, relatively lower boiler height and smaller diameters are applied, owing to the “forced” energy assisted by BCP. An increase in the operation cost of the power consumption of BCP is compensated by the lower capital cost due to the lower height and smaller diameters of water tubes. As mentioned earlier the driving force for the water circulation is mainly owing to specific gravity difference between saturated water and saturated steam. Thus applicable pressure range of this type of boiler is restricted below around 18 MPa according to the limit of steam
water separation capability in the steam drum, as explained in Section 4.3.4.2.

4.3.3.1 Cooling principle in water tube The critical issue in desining water tube type boiler is to avoid CHF and/or suppression of DNB phenomenon. There exists lots of research and development output conducted by research authorities, boiler manufactures’ laboratories, etc. [17
25], which provide helpful criteria to analyze the precise conditions to avoid DNB. Not only the prediction of DNB in smooth tube but also the improvement of the tube configuration for higher heat transfer coefficient had been intensively investigated so far, so that the current boilers have utilized the rifled tube, also known as a ribbed tube shown in Fig. 4.90. CHF of rifled tube is improved by the enhancement of wetting capability by the swirl flow induced by spiral rib(s). The parameters that influence the occurrence of DNB are pressure, heat flux, steam quality, fluid velocity, and tube diameter. In the process of circulation system design, pressure is first specified and heat flux is given as a result of combustion chamber design as explained in Section 4.1, as is indicated in Table 4.4 for average volumetric heat release rate.

4.3.3.1.1 Heat flux consideration The highest heat flux is observed around burner zone. Then, considering the heat flux distribution, at its maximum and its pattern in lateral and perpendicular direction on the water wall surface as illustrated in Fig. 4.91 for normal and stable rated operating condition, the proper selection of combination among steam quality, fluid velocity, and tube diameter is highlighted as the main concern. As is usual in design process, some margin should be added to the values described in Fig. 4.91 in order to check whether DNB is avoided or not. Reflecting fluctuation of radiation energy

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Figure 4.90 Photos of waterwall tubes: (A) smooth tube, (B) rifled tube (ribbed tube), and (C) CFD simulation [26]. CFD, Computational fluid dynamics.

from flames, drift of ignition, and combustion process which are caused by possible deviation of fuel and air distribution, and so on, this margin is commonly acknowledged to be below and around 1.5.

4.3.3.1.2 Heat transfer consideration It is a key design process to select proper combination of fluid velocity (often expressed as mass velocity) and steam quality for specified pressure, given heat flux and selected tube diameter in order to avoid CHF, such as DNB, at any points of any water tubes in the waterwall. Fig. 4.92 shows wall temperature distribution of smooth and rifle tubes for two mass velocity cases. Actually, designer should check whether DNB occurs or not using the chart as exemplified in Fig. 4.93. Such

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Table 4.4 Average volumetric heat release rate and radiant surface heat release rate.

Water tube boiler

Type of firing

Volumetric heat release rate (kW/m3)

Radiant surface heat release rate (kW/m2)

Pulverized coal firing

105
233

174
349

Gas firing

174
465

186
582

582
1520 233
814

233
582

Oil firing

Package type Stational land boiler

Source: Data from Lectures by Thermal and Nuclear Power Engineering Society (Japan), No. 32 Boiler, 2005.

Figure 4.91 Measured and calculated (by CFD simulation) heat flux in combustion chamber, (A) comparison of CFD simulation with measured heat fluxes and (B) heat flux distribution by CFD somulation [28]. CFD, Computational fluid dynamics.

chart has been developed by and reduced from abundant empirical heat transfer data such as Fig. 4.92 as a function of various parameters, for example, mass velocity, steam quality, pressure. Further increase in fluid enthalpy, another CHF condition, so-called dryout appears in higher steam quality region where water no longer flows as a liquid film, and the metal surface is not suitably cooled due to blow off of water by steam. As practical design concern, DNB has much more important meaning. This is mainly because DNB occurs at relatively low steam quality region with small void fraction and resultant low fluid velocity, which means that the capability of wetting and cooling by water phase is rather limited compared with

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Figure 4.92 Wall temperature distribution against enthalpy for smooth tube and rifled tube [29]: (A) smooth tube, (B) smooth and rifled tube, and (C) smooth and rifled tube.

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Figure 4.93 DNB chart for smooth tube and rifled tube at 18.6 MPa [29]. DNB, Departure from Nucleate Boiling.

that in dryout condition. Thus a certain amount of margin against the occurrence of DNB is essential, which is checked as illustrated in Fig. 4.94. In this figure, XDNB stands for CHF steam quality for smooth tube and rifled tube along with furnace height, analyzed by DNB chart (Fig. 4.93). Predicted steam quality for the lower circulation ratio is higher than previous circulation ratio; however, when applying rifled tube, the margin against CHF is enlarged. An example for amply selected combination between fluid mass velocity and CR is described in Table 4.5. In order to avoid CHF, it is usually recommended to have lower steam quality (higher CR) and higher mass velocity at potential maximum heat flux point. However, designers should be noted that this is not always a proper selection as presented Fig. 4.95. The value of the vertical axis represents the reduced heat flux to that of 20 mm of inside diameter normalized by the diameter correction factor Kd. Kd is 1.0 for 10 mm diameter tube, and 0.75 for 20 mm determined based on the tendency that in a larger diameter tube the DNB (CHF) quality and heat flux become lower [33
35]. This figure suggests that at around 14 MPa and mass

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Figure 4.94 Check margin against CHF [30]. CHF, Critical heat flux. Table 4.5 Ample selection of combination between circulation ratio (CR) and mass velocity. Type of water tube

Smooth tube

Refiled tubea

Remarks

CR

More than 4 for FC (2.5c) More than 5
6 for NC More than 1000
1500 kg/m2/s

More than 2 for FC More than 4
5 for NC More than 700
1000 kg/m2/s

With BCP Without BCP

Mass velocity in water tubeb

BCP, Boiler circulation pump; FC, forced circulation; NC, Natural circulation a Also called ribbed tube. b For heat flux of ample design of furnace combustion chamber. c 2.5 is the lowest value with mass velocity of 1600 kg/m2/s [31].

velocity above 1760 kg/m2/s in smooth tube is rather dangerous than those below this value, like 1480 kg/m2/s and 1356 kg/m2/s. This phenomenon is opposite to the expectation that the higher mass velocity provides larger margin to CHF. This is interpreted as the deposition-controlled CHF as illustrated in Fig. 4.96, that is, the tube surface is prevented from wetting by blown-away at high steam velocity at around 14 MPa. Above 15 MPa, this

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Figure 4.95 CHF versus steam quality in change with mass velocity at 13.7 MPa. CHF, Critical heat flux. Source: Solid lines are obtained based on H.S. Swenson, Influence of axial heat flux distribution on departure from nucleate boiling in water cooled tubes, in: ASME Paper 62WA-297, 1962 [32].

Figure 4.96 Deposition-controlled CHF. CHF, Critical heat flux. Source: Data from L.S. Tong, Y.S. Tang, Boiling Heat Transfer and Two-Phase Flow, second ed., Taylor & Francis, Oxford, 1997 [36].

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phenomenon ceases and higher mass velocity and lower steam quality become a preferable selection. As described earlier, when smooth tube is applied at the pressure range around 14 MPa, it is necessary for natural circulation system to keep CR higher (steam quality lower) enough in order not to enter dangerous zone. For forced circulation system, it is also necessary to keep an adequate combination of quality and mass velocity with good flow stability, as described in Section 4.3.3.2.2, in order not to enter dangerous zone.

4.3.3.1.3 Hydrodynamic consideration Pressure drop calculation in heated section is explained briefly hereunder, and detailed discussion will be found in Section 4.3.6.2.2. Frictional pressure drop: Single-phase flow region Two-phase flow region Static head for two-phase flow region

Colebrook
Darcy
Weisbach formula Homogeneous flow model, or slip model such as Thom’s correlation Integrated mean (log mean) specific volume from the inlet to the outlet. Specific volume in two-phase region is calculated by void fraction defined by slip model under uniform heat flux distribution.

4.3.3.2 Stability of mass velocity against heat absorption deviation Regardless of the operation pressure, the mass velocity deviation from designed value should be strictly controlled within the allowable level, so that the temperature of tube metal and mechanical construction is below the limiting values leading to creep and/or fatigue rapture.

4.3.3.2.1 Natural circulation characteristic Major factors of the mass velocity deviation are (1) deviation from the designed values in configurations of pressure parts (allowance of tube/pipe diameter, thickness, inside surface roughness, and so on) and (2) change in the heat absorption. The former should be controlled when purchasing and manufacturing, the latter be also controlled by combustion adjustment. However, the latter is not always adjustable, then designers should prepare the methodology to suppress or make calming its influence. Since water tube type boiler had been started to be utilized at relatively lower pressure, owing to the large density difference between water and steam, natural circulation boiler without BCP is designed to have relatively higher CR value with proper configuration of circulation circuit. Higher CR value brings about lower steam quality at potential CHF point, and even lower mass velocity can secure the soundness of avoiding DNB, which also enables to design water circulation circuit with ample diameter and amount for water tubes and downcomer pipes. In case the heat absorption deviation at a certain tube happens to increase, the static pressure drop, which is bigger than friction pressure drop due to high CR value, contributes to adjust mass velocity to increase, as illustrated in Fig. 4.97. If

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Figure 4.97 Flow stability in natural circulation characteristic.

the designed state of “A” is changed to intermediate state of “B” in one of the tubes along with an increase in heat absorption (dQ) having the designed mass velocity (G), the frictional pressure drop increases due to an increase in the steam quality caused by the higher fluid velocity, and simultaneously the static head decreases due to an increase in the steam quality, and also total pressure drop decreases owing to the static head being a dominant factor. In order to compensate the total pressure drop to balance with the pressure drop of other tubes keeping the same level, mass velocity increases. This compensation action is so-called natural circulation characteristic. This tendency is favorable to secure the soundness for avoiding DNB. As explained in Section 2.4.2, Yarrow’s test, shown in Fig. 2.33, and calculation example for Mu¨nzinger model in Fig. 2.34 revealed the above tendency, together with the saturation of this tendency at pressure 0.98 MPa-G.

4.3.3.2.2 Forced circulation characteristic By introducing BCP, desired mass velocity in water tube is attained with the smaller diameter/quantity of water tubes and downcomers. This is because assisted circulation force by BCP does not need large extent of driving force induced by the circuit configuration, which means static head difference between downcomer and water tube is reduced and the steam quality at waterwall outlet is increased. Flow stability for securing mass velocity is different from natural circulation characteristic. Fig. 4.98 shows thermo-hydraulic dynamics of this type. Contrary to natural circulation, an increase in the heat absorption results in a decrease in the mass

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Figure 4.98 Flow stability in forced circulation characteristic.

velocity. This is because frictional-pressured drop increases so much due to higher outlet steam quality, which leads to the reduction in static pressure drop. The state change from the designed state “A” to the intermediate state of “B” in one of the tubes causes total pressure drop increases when the frictional pressure drop is dominant. In order to balance with the surrounding tubes, mass velocity decreases to state “C.” This action is so-called forced circulation characteristics. This characteristic should be controlled within a certain level enough to avoid DNB. Then an installation of orifice is necessary not only for obtaining appropriate flow rate to cope with DNB but also for maintaining flow deviation within allowable range.

4.3.4 Steam drum One of the most important components that realize natural circulation or forced circulation water tube type boiler is steam drum, which separates saturated steam and saturated water from two-phase flow entered into the steam drum through riser pipes from water tubes. Separated steam flows into saturated steam pipes and separated water flows into downcomers. Typical construction of steam drum is illustrated in Fig. 4.99. The name of “drum boiler” is often used to denote these two types of boiler, because this component features them very much.

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Figure 4.99 Drum internals [27]: (A) baffle screen type, (B) turbo-separator type, (C) cyclone separator type, and (D) horizontally arranged centrifugal separator type. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society.

4.3.4.1 Reasons for better separation performance Failure of desired separation performance is listed as follows: 1. Failure in suppressing water carryover to steam a. Impurity substances, i.e. scales such as Si compound, adhere inside tube that causes overheat. b. Peeled-off scale erodes turbine nozzle to reduce efficiency. c. Steam temperature drops at SH outlet. d. Flow imbalance, which induces overheat at heating section due to unexpected liquid entrainment. 2. Failure in suppressing steam carryunder to water a. Decrease in circulation rate due to decreased static head in downcomer. b. BCP cavitation induces cutoff state of Q
H (head-flow rate) curve of BCP, then flow reduction.

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Vaporous carryover should be taken into consideration, being well-known phenomenon that the solubility of impurity substance to steam phase becomes close to that to water phase at higher pressure, as shown in Fig. 4.100, for example, of SiO2. Since this vaporous carryover is unavoidable, water mist or droplet, which contains impurity substances, passed through separation apparatus of steam drum should be strictly suppressed so that the water carryover in saturated steam pipe should be, for example, below 0.2%. This extent of separation function can resultantly control the sum of substances brought by vaporous carryover and water carryover under the limit at the inlet of turbine, commonly known as less than 0.2 ppm of SiO2. Boiler water quality is accordingly regulated considering the above aspect as is shown in Table 4.6 (JIS B8223).

Figure 4.100 SiO2 concentration in boiler water and steam versus pressure. Source: Data from Thermal and Nuclear Power Engineering Society, Handbook for Thermal Power Engineers, eighth ed., Thermal and Nuclear Power Engineering Society, Tokyo, 2017 [37].

Table 4.6 Boiler water quality. Watertube type (circulation) boiler Pressure (MPa) mg SiO2/L

7.4
9.8 s2

Source: Data from JIS 8223.

9.8
12.3 s 0:5

12.3
14.7 s 0:3

14.7
19.6 s 0:2

Once-through boiler 19.6
s 0:02

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4.3.4.2 Separation principles Separation principles are summarized in the following subsections.

4.3.4.2.1 Suppression of water carryover to steam A: Centrifugal force separation by using defection baffle component or centrifugal separation component B: Gravitational separation C: Impingement separation

The separation force of process A is centrifugal force in curved flow due to the difference in specific weights between saturated steam and water. It is well recognized that separation efficiency of this primary process is not so much high, such that as deflection baffle plate commonly used under 14 MPa and centrifugal separation component, such as turbo-separator or cyclone-separator used above around 14 MPa, are just functioning primary separation followed by second and third processes of B and C. Gravitational separation B is governed by Stokes law: Wg 5 d2 gðρl 2 ρg Þ=ð18μg Þ

(4.9)

where Wg is the critical velocity of steam below which water droplet is no longer carried over (m/s), d the mist diameter (m), d is proportional to σ1/4, σ the surface tension of saturated water, ρg, ρl are the density of steam and water, respectively (kg/m3), g is the gravitational acceleration (m/s2), and μg the viscosity of steam (Pas). Capacity by processes of gravitational separation, Cpg, is given by: Cpg 5 Kb Wg Hρg where Kb is the constant and H the representative height of space (m). Impingement separation, C, is governed by the following (Souders
Brown expression) for a model as described in Fig. 4.101: ρl 2ρg Ws 5 K ρg

(4.10)

equation

!0:5 (4.11)

where Ws is the critical velocity of steam below which water droplet is captured by screen dryer (m/s), K is the constant. Capacity by impingement separation, Cpi , is expressed as: Cpi 5 Kc Ws Wρg where Kc is the constant, and W the representative width of space (m), such as width of scrubber screen dryer.

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Figure 4.101 Impingement separation model.

It is important to select proper size/quantity for processes A
C, respectively. Among them, process B (gravitational separation) is dominant, while the critical velocity Wg and thus the gravity separation capability Cpg decrease with an increase in the pressure as shown in Fig. 4.102. The applicable pressure range of circulation boiler is restricted also by such separation characteristics.

4.3.4.2.2 Suppress steam carryunder to water As for buoyancy separation in water storage at trough part, essential parameter that affects the separation is the volume of water in the drum. In the process of satisfying separation performance, both for suppression of carryover and carry under, water level in steam drum is a key factor to controlled spaces above and below the water level adequately, which are trade-off for the drum size reasonably economical. It is very important to avoid maldistribution of circulation flow rate, which induces CHF as described in Section 4.3.3.1.2. Very low level of water in drum may induce steam carryunder more or less which might lower the driving force of fluid circulation due to reduced static head of downcomer and increased friction loss of water tube. In natural circulation system, low water level is critical because the driving force is directly influenced by the balance between the two factors described previously. In forced circulation system, owing to the driving force by BCP, low water level itself does not affect the circulation rate. Instead, flow rate monitoring is preferable, that is, differential pressure between inlet and outlet of BCP is monitored. As illustrated in Fig. 4.103, in the case of pressure loss increases unexpectedly, gradient of system loss curve increases, then the pressure of balanced point with pump Q
H curve will increase, which will be detected as high differential pressure alarm. In serious case of BCP cavitation, Q
H curve suddenly drops along with deficiency of available net positive suction head and resultant so-called cutoff phenomenon (mass flow deficiency due to replacement of vapor created by cavitation) brings balance point to lower operating pump head [38], which will be detected as low differential pressure alarm.

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Figure 4.102 Gravitational separation capability along with pressure.

In addition, it is a matter of course that flow imbalance should be suppressed by arranging the pipes uniformly, not only for riser pipes (two-phase flow of water and steam) but also saturation steam pipes and downcomers (single-phase flow of steam or water).

4.3.5 Once-through boiler At the beginning of the 20th century, an attempt to reduce accidents in natural circulation and forced circulation boilers, which had been increasingly occurred along with increased pressure and temperature, was taken place by Mark Benson to design the once-through boiler as described in Section 2.4.3. His idea was patented in 1922, in which evaporator was eliminated thermo-hydraulic crisis induced by malfunction of water and steam flow behavior, such as DNB and/or flow imbalance or unbalance, by setting evaporator operation pressure above critical pressure 22.1 MPa. Test boiler was operated under supercritical pressure at evaporator with

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Figure 4.103 Example of flow rate monitoring for BCP operation. BCP, Boiler circulation pump.

subcritical pressure at SH outlet by throttling valve. The evaporator of this boiler was also operated at subcritical pressure without throttling the valve, while Benson’s patent did not include such operation mode. Original Benson boiler did not have water separator at evaporator outlet. Sulzer boiler had the separator for blowing, which was tested in 1929. Fig. 4.104 shows the principle of the circuit of these two types of boiler compared with drum boiler, that is, water tube boiler, and modern once-through boiler now utilized. Modern oncethorough boiler has a water separator to circulate necessary amount of water to cool evaporator tube at start-up stage and very low load, just like circulation boiler. The most remarkable feature of once-through boiler is dryness at outlet of evaporator. Steam quality of evaporator outlet for drum boiler is less than 50%, but that for once-through boiler is 100% or more, which means major theme of this type of boiler is to overcome two important factors as described in the following: 1. Cooling capability Evaporator tube passing through maximum heat flux zone in furnace, which is usually upper part of burner zone as explained in Section 4.3.3.1.1, contains fluid with higher enthalpy than drum boiler. Thus enhanced cooling measure is essentials in order to keep the tube metal temperature low enough to avoid rapture. Evaporator tubes are also requested to have enough cooling capability. In all over the subcritical pressure range, higher flow rate is preferable to obtain better cooling capability; however, it is simultaneously necessary to reduce pressure drop that affects power consumption of boiler feed water pump for efficient operation. 2. Flow stability Heat absorption of each tube is not even unless boiler is single-tube construction such as Sulzer Monotube as illustrated in Fig. 2.43. Furthermore, tube inside diameter varies due to purchasing tolerance of outer diameter and thickness, and, for example, in tube flow area, its variation range spreads between 101% at maximum and 77% at minimum compared with 100% at purchasing specification of outside diameter 38 mm with 0.15 mm tolerance, thickness 7 mm with 120%/ 2 0% tolerance.

Figure 4.104 Flow diagram for each type of boiler.

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The abovementioned two factors cause imbalance not only in flow rate but also in outlet steam temperature. Excess imbalance in temperature may cause mechanical distortion and resultantly unexpected thermal stress, which should be suppressed in order to avoid rapture not only from creep but also fatigue. Flow stability along with heat absorption increase is a major concern, and lower flow rate is preferable, as explained in Section 4.3.3.2. Flow unbalance, flow instability which most often accompanies oscillation at a cycle of no matter how long or short, is another subject to concern. Parallel heating tubes in between headers have potential to occur this phenomenon, which has been investigated, tested, and verified by lots of research institutes and manufactures to place countermeasures, for example, “An Assessment of the Literature Related to LWR Instability Modes (NUREG/CR-1414 (1980)” by R.T. Lahey, Jr. and D.A. Drew is a typical example. As for the countermeasures to flow instabilities, it is effective to apply either alone or in combination of the following several measures: increase in the operation pressure high above around 5 MPa, setting the evaporator inlet enthalpy not so much low below saturation within around 200 kJ/kg, avoidance of medium value of outlet steam quality in between 20% and 80%, installation of throttling device such as orifice/valve at inlet appropriately, or setting mass velocity high enough. Nowadays, industrialized once-through boiler satisfies the above conditions and measures, and then it is very rare to face the abovementioned phenomena. Two important factors, cooling capability and flow stability, are in relation of trade off in the viewpoint of flow rate, and essence of know-how to realize reliable once-through boiler lies in how to take balance between these two factors.

4.3.5.1 Subcritical pressure once-through boiler Operating pressure remained in subcritical during the first half of the 20th century, then, fluid flows evaporator has two phases (water and steam). Inevitable high steam quality at maximum heat flux zone, which is unavoidable in once-through boiler, necessitates different criteria to keep required cooling capability from that applied to drum boiler. Even after CHF crisis (DNB) occurs, heat transfer coefficient at film boiling condition should be high enough to cool tube metal. Fig. 4.105 is again referred as in Fig. 4.92. For this type of boiler, sharp metal temperature rise should be suppressed within allowable level by adopting higher mass velocity. Since there exists a possibility for maximum heat flux point to meet with DNB steam quality (XDNB) due to inevitable high steam quality, the construction of evaporator, composed of furnace water wall, becomes like meander as illustrated in Fig. 4.106, in order to keep mass velocity high enough to obtain required cooling capability by increasing fluid velocity through reducing tube number in a section through which fluid flows. The minimum heat transfer coefficient ðαmin Þ which corresponds to peak temperature at XDNB is applied to whole tube length, and mass velocity is resultantly set up high enough at around 4000 kg/m2s as its typical figure, taking into consideration of the severest combination of maximum heat flux and αmin . As the same manner in drum boiler, consideration for phenomenon at αmin point has an important meaning for practical design. Selecting mass velocity that

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Figure 4.105 Wall temperature versus enthalpy in deference of mass velocities. Source: Data from H. Herkenrath, P. Mork-Morkstein, U. Jung, F.J. Weckerman, W¨armeu¨bergang am Wasser bei Erzwungener Stro¨mung im Druckbereich von 140 bis 250 bar, EUR3658d, 1967.

endures the combined condition of maximum heat flux and αmin may also endure dryout condition. An example for αmin is illustrated in Fig. 4.107 along with pressure at mass velocity of 1500 kg/m2s. For hydrodynamic concern to predict pressure drop the same manner is applicable as that of drum boiler. As has been discussed in Section 4.3.3.2.2, when increased steam quality at the tube outlet and high mass velocity, the forced circulation characteristic becomes obvious, because the large friction loss dominates total pressure drop, which potentially increases probability of flow imbalance inducible by heat absorption difference. However, the following two considerations are effective to moderate this characteristic: 1. From the viewpoint of moderating heat absorption imbalance among water tubes which pass around furnace wall, where heat flux from combustion fire and gas has potential imbalance in direction of furnace width, depth and height as shown in Section 4.3.3.1.1, multiupward flow sections (group of tubes in which fluid flows in parallel) in Benson boiler or multi-up and -down flow sections in Sulzer boiler as illustrated in Fig. 4.106 had been adopted. By consisting a flow section of limited number of tubes, these constructions enable the flow section to pass almost all area of waterwall in depth, width, and height to calm heat absorption imbalance. 2. From the viewpoint of improve flow stability, intermediate header installed at outlet of each upward flow section in Benson boiler resets pressure difference among water tubes, then

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Figure 4.106 Tube arrangement: (A) Benson boiler and (B) Sulzer boiler.

the proportion of frictional pressure drop in total pressure drop between headers is reduced to moderate forced circulation characteristic, as is discussed in Section 4.3.3.2. Throttling valves installed at the inlet of flow section in Sulzer boiler, as illustrated in Fig. 4.106, contributes to maintain flow stability, as will be discussed in detail in Section 4.3.6.3.

As the once-through boiler uses relatively smaller diameter tube than that of drum boiler and has no steam drum with large diameter and thick wall, the failure or explosion was thought to be suppressed to smaller extent and much safer. Manufacturing

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Figure 4.107 Minimum heat transfer coefficient along with pressure for smooth tube. Source: Data from A. Bahr, H. Herkenrath, P. Mork-Morkenstein, Anomale Druckabh¨angigkeit der W¨armeu¨bertragung im Zweiphasengebiet bei Ann¨aherung an den Kritischen Druck, Brennst. W¨arme Kraft 21 (12) (1969) 631
633.

facilities were no longer requested to have heavy weight bending machine for fabricating of steam drum. It has been said that these two factors are dominant for European boiler manufactures to encourage developing once-through boiler.

4.3.5.2 Supercritical pressure once-through boiler Supercritical pressure units, Hu¨ls II Block 1 85 MW in Germany and Philo 6 125 MW in the USA, had started operation in 1956 and 1957, respectively. Steam condition of the former is 29.4 MPa-G, 600 C/560 C/560 C and the latter is 31.0 MPa-G, 621 C/566 C/538 C (see more details in Section 2.4.3).

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Figure 4.108 Water circulation system: (A) combined circulation boiler and (B) universal pressure boiler.

The operation mode of “supercritical constant pressure operation,” distinguished from “supercritical sliding pressure operation” which is discussed in Section 4.3.6, had been popular in the USA and Japan. Besides the very beginning of start-up stage, boiler waterwall circuit is always operated in supercritical pressure above 22.1 MPa, that is, after pressurization up to supercritical, and before initial firing is taken place by throttling waterwall or primary SH outlet valve, as illustrated in Fig. 4.108, followed by the rest of start-up procedures and load operation.

4.3.5.2.1 Heat transfer consideration Similarly to the subcritical pressure boilers, the prediction of heat transfer coefficient in evaporator tubes is a key issue for prediction of metal temperature. Following correlations can provide sufficient value to endure industrial accuracy for calculating metal temperature in the condition without CHF crisis.

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Dittus
Boelter’s correlation: 0:4 Nub 5 0:023Re0:8 b Pr b

(4.12)

Styrikovich’s correlation [39]: 0:8 Nub 5 0:023Re0:8 b Pr min

(4.13)

where Pr min 5 minimum ðPr b ; Pr w Þ Bishop’s correlation [40]: 0 Nub 5 0:0069Re0:99 b Pr b

0:66


0:43 vb vw

(4.14)

where Pr 0b 5

ðHw 2 Hb Þμb ðTw 2 Tb Þkb

Petukhov’s correlation [41]:
0:11
20:33
0:35 Cp kb 0 μb Nub 5 Nub μ Cpb kw w   ζ=8 Reb Prb  Nu0b 5 pffiffiffiffiffiffiffiffi 2=3 1:27 ζ=8 Prb 2 1 1 1:07  22 ζ 5 1:82log10 Reb 21:64 Cp  5 ðHw 2 Hb Þ=ðTw 2 Tb Þ

(4.15)

where Cp is the specific heat (J/kg/K), H the specific enthalpy (J/kg), k the thermal conductivity (W/m/K), Nu the Nusselt number, Pr the Prandtl number, Re the Reynolds number, T the temperature ( C), v the specific volume (m3/kg), μ the dynamic viscosity (Pas), subscript b the bulk, and subscript w the tube wall. Even though supercritical pressure fluid has no appearance of two phases, water and steam, its properties vary very much widely near pseudo-critical temperature, at which specific heat reaches at it maximum value in supercritical pressure condition, as shown in Fig. 4.109. It is reported that CHF phenomenon occurs similarly to that in subcritical pressure region, as illustrated in Fig. 4.110. Sharp metal temperature rise inside of tube metal in lower enthalpy region is like DNB, and gradual metal temperature rise in higher enthalpy region like dryout. The former phenomenon is sometimes referred to as “pseudo-DNB” in supercritical pressure, and this phenomenon has been

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Figure 4.109 Steam properties near pseudo-critical temperature.

realized in finite element computation by introducing drastic change in physical properties around pseudo-critical temperature [43]. As in the same manner in drum boiler, CHF has much more important practical meaning in once-through boiler design. Since operation pressure is supercritical even at partial load, specific volume of fluid does not change, and volume flow rate is proportionally reduced along with a decrease in load. The countermeasure to keep necessary mass velocity for cooling is secured by adopting the circuit as illustrated in Fig. 4.108. The left-side figure shows a kind of partial circulation boiler with superimposed pump on feedwater line to waterwall to keep mass velocity enough at partial load below around 60%. The right-side figure shows a kind of modified Benson boiler with reduced number of up-flow tubes, following original Benson system as described in Fig. 4.106A, to keep mass velocity at low load. Each type of boiler has mass velocity around 1500 kg/m2s at rated load.

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Figure 4.110 Heat transfer deterioration in supercritical pressure at 24.5 MPa, 458 kW/m2. Source: Data from S. Aramaki, Y. Takahashi, M. Iwabuchi, An outline of supercritical pressure combined circulation test boiler and some experimental results, Mitsubishi Heavy Ind. Ltd Tech. Rev. 4 (1) (1967) 1
7 [42].

4.3.5.2.2 Hydrodynamic consideration To predict pressure drop in heated section, following formulas are used: Frictional pressure drop: Colebrook
Darcy
Weisbach formula Static head for two-phase flow region: Integrated mean specific volume of inlet and outlet

For flow stability, owing to lower friction loss of single-phase flow without large void fraction like in subcritical pressure region, no such significant concerns for forced circulation characteristics discussed in Section 4.3.3.2.2 is needed.

4.3.6 Supercritical sliding pressure operation once-through boiler After the 1970s, fossil-fuel-fired power stations had been requested to operate socalled middle load operation, such as daily start and stop and partial load operation with high efficiency, supercritical sliding pressure operation boiler become the most popular type, as introduced in Section 2.4.3. As summarizing the operational condition of each boiler type, drum boiler (natural circulation or forced circulation), once-through boiler (subcritical or supercritical pressure), and supercritical sliding pressure operation once-through boiler are illustrated in Fig. 4.111. Wide range of pressure from supercritical (25 MPa) to subcritical (8 MPa), and of single-phase fluid to two-phase fluid are range of this type of boiler to be operated.

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Figure 4.111 Boiler operation condition on enthalpy
pressure diagram.

4.3.6.1 Merit and effectiveness of supercritical sliding pressure operation Typical pressure curve for this operation mode is shown in Fig. 4.112. Control stage was widely adopted in constant pressure operation steam turbine, and operation mode throttling valves at turbine inlet had generated large temperature difference inside first stage of turbine as is shown in Fig. 4.113. This induced large thermal stress and degraded the performance, particularly for middle load operation. In order to minimize these disadvantages, sliding operation mode, for example, the mode: two governing valves out of four are controlling sliding pressure, which is so-called as 50% minimum admission under a partial arc control, is applied [45]. It also provides wider control range of reheat steam temperature due to higher exhaust temperature at HP turbine, which is brought by synergy effect of smaller enthalpy drop and higher inlet steam enthalpy in HP turbine. Furthermore, heat rate at low load is improved by lessen power of boiler feedwater pump, elevated steam temperature and improved stage efficiency (decreased exergy loss) as shown in Fig. 4.114. Other merits are to reduce operating pressure at low loads which bring prolonged lifetime in all components and reducing auxiliary power between feedwater pump and HP turbine and to improve steam flow distribution in SH and RH sections due to the higher specific volume at low load. This operation mode affects boiler components near saturation temperature zone such that temperature variation to some extent is generated at different loads because of varying saturation temperature due

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Figure 4.112 Supercritical sliding pressure operation.

Figure 4.113 Turbine control stage outlet temperature by partial arc control [44].

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Figure 4.114 Turbine heat rate by partial arc control [44].

to varying pressure along with load. This is, as a matter of fact, burden of thermal stress and thermal fatigue problem is sifted from turbine to boiler. Evolution of sophisticated design for pressure parts, particularly the portion with the configuration having large thermal stress and those potentially induces stress concentration, such as thicker metal, weld metal edge or fin edge, and so on, had been taken place to relax thermal stress as much as possible by introducing high-grade material, adopting the shape with lessen stress concentration against all types of loading to ensure lifetime. The abovementioned temperature variation along with the load variation brings lager variation in heat holding of components (metal weight multiplied by temperature and specific heat) than in constant pressure operation mode with very small temperature variation, as illustrated in Fig. 4.115. When increasing load, the difference of heat holdings between starting load (50%) and ending load (100%) necessitates supplemental heat input in order to warm up components, which is called “acceleration heat.” The amount of acceleration heat for supercritical sliding pressure operation boiler within a certain load ramping period is about three times to that for supercritical constant pressure operation, which means flow stability issue against heat absorption increase becomes a matter to concern for the boiler used in this mode, together with evolved control technology discussed in Chapter 5, Construction, Operation, and Control of Power Boiler.

4.3.6.2 Heat transfer and hydrodynamic consideration As shown in Fig. 4.111, the operation condition of supercritical sliding pressure boiler is considered as an integration of that of subcritical pressure once-through boiler discussed in Section 4.3.5.1, that of supercritical pressure once-through boiler discussed in Section 4.3.5.2, and that of subcritical HP region near-critical pressure, hereunder described.

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Figure 4.115 Heat holding along with load in supercritical sliding pressure operation boiler.

4.3.6.2.1 Heat transfer consideration Along with an increase in heat flux, at near-critical pressure region, subcooled boiling occurs very likely and transition to film boiling takes place as similar to low enthalpy CHF phenomenon as explained in Section 4.3.5.2.1. Fig. 4.116A is developed by reduced data to relate CHF enthalpy and pressure for smooth tube, which reveals at pressure in between 96% and 100% of critical pressure, CHF enthalpy drops to subcooled region. Swirl effect by rifled groove contributes decreased summit temperature as shown in Fig. 4.116B. The decrease in summit temperature results in a larger minimum heat transfer coefficient αmin than in the smooth tubes as illustrated in Fig. 4.117. It is important to predict metal temperature in accuracy by using film boiling coefficient in subcritical pressure region for the design of this type of boiler with economy and high reliability. As for heat transfer correlation in post-CHF region (film boiling) for smooth tube, Groeneveld proposed the following equation [48]:  q n4 n2 n3 NuG 5 CRen1 (4.16) x Prg y 3:155

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Figure 4.116 CHF in smooth and rifled tube [46]: (A) CHF enthalpy for smooth tube and (B) Inside wall temperature in rifled tube. CHF, Critical heat flux.

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Figure 4.117 Minimum heat transfer coefficient of smooth and rifled tubes [47].

where Rex and y are defined by the following equations: 2

3 v 1 Rex 5 Reg 4x 1 ð1 2 xÞ5 vg
0:4 vg y 5 1 2 0:1 v1 21 ð12xÞ0:4 The values of C, n1, n2, n3, and n4 depend on the shape and size of flow circuit and are 1.85 3 1024, 1.0, 1.57, 21.22, and 0.131, respectively, with 10.1% RMS error for vertical and horizontal tubes, x is the steam quality. The Groeneveld type correlation is also applicable to the case of rifled tube. As, for example, in pressure above 20.6 MPa and quality x from 20.4 to 0.8, Nusselt number for rifled tube NuG
R, modified from that for smooth tube by Groeneveld equation NuG, is expressed as follows:
 0:274 NuG2R 5 NuG 0:9 1 (4.17) x 1 0:68 By integrating the design criteria explained from Section 4.3.3.1.3, the waterwall of supercritical sliding pressure operation boiler is constructed with vertically arranged tubes and/or spirally wounded tubes, as shown in Fig. 4.118A and B.

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Figure 4.118 Tube arrangement for supercritical sliding pressure boiler: (A) Vertical tube type, (B) spirally wound type, (C) vertical versus spirally wound.

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Figure 4.119 Comparison of furnace water wall tube mass velocity of supercritical siding pressure operation boilers [29].

Rifled tubes are applied for vertical tube type, while smooth tube for spirally wound type. Tube amount of the spirally wound type is reduced to half or one-third in relation to the inclined angle as illustrated in Fig. 4.118C, which results in an increase in the mass velocity. Fig. 4.119 illustrated the relation between average design mass velocities and critical mass velocities for spirally wound type and vertical type along with load. Cooling principle to eliminate excess metal temperature at water wall is secured as to avoid undesirable metal temperature rise due to CHF as explained in Section 4.3.5.2 in supercritical pressure region, and to secure necessary film boiling heat transfer coefficient near-critical pressure region at the condition as in Section 4.3.6.2, and also to secure the same for smooth tube as in Section 4.3.5.1 or to avoid CHF for rifled tube as in Section 4.3.3.1. Metal temperatures to be paid attention in design process for membrane wall are tube crown point outside temperature for gas side corrosion, fin tip temperature for the same aspect and tube crown point midwall temperature for creep strength. Fig. 4.120 exemplifies temperature-contour of membrane wall tube-fin in the cases

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Figure 4.120 Temperature-contour figure for tube-fin configuration.

Figure 4.121 Reduction of heat flux at crown point of tube.

of high and low heat transfer coefficients. Close look at heat flow direction across isotherm curves perpendicularly suggests that in the former case heat flow is directed to the center of tube in line with radius; however, in the latter case, it goes around the arc of tube thickness because low heat transfer coefficient acts as thermal barrier. This means, heat flux at crown point is reduced in the latter case as illustrated in Fig. 4.121. Proper heat conduction analysis is needed to provide proper metal temperature.

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Since the theme for introducing this type of boiler is to cope with the need of middle load operation with high efficiency, once-through operation is desirable to the lower load as much as possible to eliminate increased circuit pressure loss brought by flows through circulation pump for maintain cooling capability. Normally below 25%
30% load including start-up period, circulation pump assists to feed water flow to keep necessary amount of cooling mass velocity adding the recirculation flow to water separated from water separator by adjusting circulation pump outlet control valve. Water separator for this type of boiler is rather simple construction compared with drum boiler, because operation pressure is low enough around 8 MPa at its maximum due to sliding pressure operation.

4.3.6.2.2 Hydrodynamic consideration Total pressure drop is the sum of pressure drop components, that is, friction, static, and acceleration pressure drops. Practically, the former two factors are dominant for industrial design. 4.3.6.2.2.1 Pressure drop in single-phase flow region The frictional pressure drop is described by Colebrook
Darcy
Weisbach formula, using friction factor λ and adopting hydraulic equivalent diameter dH as follows: ΔPf 5

λL ρvl 2 2dH

(4.18)

4.3.6.2.2.2 Pressure drop in two-phase flow region As for the model for the pressure drop prediction of evaporating tube in the two-phase flow region, there are two types of concept—the homogeneous flow model and the slip flow model. If it is limited within the relatively HP region, the satisfactory prediction for a design work is obtained by using the homogeneous flow model. However, it is necessary to adopt the slip flow model to predict the pressure drop precisely for the sliding pressure operation boiler of which lower operating pressure becomes around 8 MPa or less. The slip factor S was assumed by Thom’s correlation [49]. Thus the specific volume of the two-phase flow is given by the following equation:
 1 1 1 1 x ð S 2 1Þ    5 ρTP ρl 1 2 x 1 1 S ρ =ρ g

(4.19)

l

Then, the static and acceleration pressure drops in the two-phase flow can be obtained by the same equations as those in a single-phase flow, using the specific volume defined by the above equation. As for the frictional pressure drop, Thom proposed the following correlation: ΔPf 5

λs L 2 ρ v rf 2S 2dH l l

(4.20)

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Figure 4.122 Multiplier for rifled tube [47].

where dH, L, and vl denote diameter (hydraulic equivalent diameter), tube length, and inlet velocity (of liquid single-phase flow), respectively, and ρl, λS, and rf2S are density of liquid, friction factor, and two-phase friction multiplier, respectively. rf2S is given by a function of pressure and quality. rf2S for smooth tube is presented by Thom [49]. This friction multiplier rf2S is modified so as to fit rifled tube, rf2R as exemplified in Fig. 4.122 for 11.8 and 20.6 MPa, together with Thom’s correlation. As for static head for two-phase flow region, specific volume is estimated by the void fraction based on the slip flow model.

4.3.6.2.3 Other aspects to be considered 4.3.6.2.3.1 Inclined tube critical heat flux Tubes enclosing boiler are not always arranged in vertical direction but are often arranged in horizontal or inclined as in the roof part or furnace hopper waterwalls. Then, it is necessary to investigate the CHF in horizontal and inclined tubes and countermeasure to avoid CHF. Fig. 4.123 shows CHF of horizontal tube encountered in lower steam quality than that in a vertical tube, even though peak temperature at CHF is lower than that in

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Figure 4.123 Comparison of wall temperature between horizontal and vertical tube [46].

vertical ones. Fig. 4.124 shows CHF enthalpy versus pressure relationships for horizontal, 15-degree inclined and vertical tubes. CHF enthalpy in horizontal tube is far lower than vertical tube, and 15-degree inclined tube is in between. 4.3.6.2.3.2 Hydrodynamic behavior in downward flow of stem
water mixture In heating tubes located in downstream of furnace, such as hanger tubes, extended sidewall, back pass wall, and so on, consisting circuit upstream water separator, unexpected adverse flow (downward flow) often observed at low load when mass velocity becomes low and heat flux is potentially low. Such unexpected downward flow should be avoided, because there is a possibility of flow stagnation, and the flow no longer goes up or down to cool tube metal. The flow stagnation of steam
water mixture also induces apprehension of flow instability like flow oscillation. In order to investigate the possibility of flow stagnation and to take measure for avoidance of such flow stagnation, thermo-hydrodynamic research and development has been conducted so far. Fig. 4.125 shows measured void fraction in heated downward flows at pressures 11.7 MPa. Void fraction is larger than that in homogeneous flow, and at low mass flux and low steam quality, this tendency becomes much more prominent. This is mainly because buoyancy effect of bubbles affecting flow direction is significant in low-quality and low-velocity region. This effect becomes rather weak in high velocity region where the flow pattern becomes annular or dispersed flows. Fig. 4.126 shows measured friction multiplier for downward two-phase flow at 8.8 MPa in comparison with that of upward or horizontal flow proposed by Thom and Martinelli
Nelson. In the low-velocity region, friction multiplier in downward

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Figure 4.124 Comparison of pressure effects on CHF [46]. CHF, Critical heat flux.

flow is remarkably larger than that of upward or horizontal flow and significantly increases as mass flux is decreased.

4.3.6.3 Flow stability As the supercritical sliding pressure once-through boiler covers subcritical pressure region, the same apprehension as in subcritical pressure once-through boiler as described in Section 4.3.5.1 may happen, that is, remarkable tendency of forced circulation characteristic. The construction of waterwall circuit shown in Fig. 4.118 is simpler to that of subcritical pressure once-through boiler shown in Fig. 4.106, which means, without countermeasure described in Section 4.3.5.1, supercritical sliding pressure once-through boiler should overcome unexpected temperature rise, together with temperature gradient within waterwall panel induced by flow imbalance leading to creep and/or fatigue rapture. Thermal stress induced by temperature gradient might be decreased mechanically through proper arrangement of buckstays which restrict waterwall panel distortion. In this section, countermeasures based on the hydrodynamic improvement and its theoretical explanation are discussed.

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Figure 4.125 Measured void fraction of downward flow [50].

Figure 4.126 Friction multiplier [50].

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The major concern of static flow stability, not dynamic or oscillated instability as described in Section 4.3.5 (2), is attributed to how much outlet enthalpy differs caused by heat absorption difference, as in the following equation: Let H be enthalpy increase, Q heat absorption rate, G mass flow rate, and DP pressure drop: H5

Q G

or

HG 5 Q

(4.21)

Considering small perturbation, H 5 H0 1 dH, G 5 G0 1 dG, Q 5 Q0 1 dQ, and linearized, dH dQ dG 5 2 H0 Q0 G0

(4.22)

 dH dQ dG=G0 5 12 H0 Q0 dQ=Q0

(4.23)

then,

Define SDG as: SDG 

dG=G0 dQ=Q0

(4.24)

Substitute Eq. (4.24) into Eq. (4.23), dH dQ 5 ð1 2 SDG Þ H0 Q0

(4.25)

dH=H0 5 1 2 SDG dQ=Q0

(4.26)

then

Eq. (4.26) means: 1. When SDG is positive, (dH/H0)/(dQ/Q0) is less than 1. The increase in the outlet enthalpy is less than the increase in heat absorption. This case is preferable and is the natural circulation characteristic as described in Section 4.3.3.2.1, The increase in heat absorption leads to the increase in flow rate. 2. When SDG is negative, (dH/H0)/(dQ/Q0) is larger than 1. The increase in the outlet enthalpy is larger than the increase in the heat absorption, and heat flux perturbation is amplified. This is not welcomed and is unstable condition as described in Section 4.3.3.2.2. Then countermeasure is needed to bring SDG not to be negative so much.

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Figure 4.127 Flow deviation study by introducing pressure drop (three dimensionally explained, A
C correspond to the state in Fig. 4.98).

Since once-through boiler is designed to have higher mass velocity than circulation boiler in order to cool water tube in unavoidably higher steam quality, it is not easy to obtain natural circulation characteristics. Then, even if SDG is negative, the countermeasure to decrease the absolute value is necessary and discussed in the following. SDG is rewritten as: SDG 

dG=G0 dG Q0 dG 5 H0 5 5 dQ G0 dQ dQ=Q0

(4.27)

Thus the countermeasure for decreasing the absolute value of dG/dQ for negative SDG is described as later. Introduce DP as in Fig. 4.127, dG dDP dG tan θ1F 5 5 dQ dQ dDP tan θ2

(4.28)

where suffix F stands for forced circulation characteristic. In order to lessen θ1F a decrease in frictional pressure drop is effective as discussed in Section 4.3.3.2.1. This means that low mass velocity selection is

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Figure 4.128 Pressure drop versus flow rate characteristics.

recommendable. In order to increase θ2, it is easily understood that the increase in friction pressure drop is effective; however, this degrades lessening θ1F. Then the installation of inlet orifice which also increases θ2 as illustrated in Fig. 4.128 is effective.

4.4

Deposition, erosion and corrosion, and water treatment

Water treatment for thermal power plants is conducted to prevent problems such as carryover to the turbine components, as well as corrosion and scale formation/deposition in the boiler and turbine systems. Since 1959, water treatment methods have been improved to deal with equipment nonconformities. The Japanese Industrial Standards Committee established a “specialists group for boiler feedwater and boiler water” in the Mechanical Engineering Division to assess and determine the water quality control criteria. In February 1961 these were stipulated by JIS B 8223 (titled Water Conditioning for Boiler Feed Water and Boiler Water) [51]. JIS B 8223, which stipulates the required water quality for boilers and turbines of thermal power plants, is regularly amended based on operational results, technological innovation, equipment nonconformities, etc. The execution of “appropriate water quality control” is considered important not only for decreased amounts of chemicals in use and wastewater to lower the environmental impact but also from an economical point of view (such as shortening of plant startup time and operational cost reduction). In recent years, there have been cases of abnormal water quality affecting the boiler/turbine systems extensively, which were caused by mismanaged operation or inadequate handling of the situation when, for example, aging facilities failed to maintain the required water quality or cooling water (seawater) leaked in the

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condenser. These resulted in serious problems such as leakage from boiler steamgenerating tubes. The causes of such water quality abnormalities can lie in raw water or facilities to supply make-up water (demineralized water) to the plant, rather than in the main water system.

4.4.1 Importance of water quality control in thermal power plants Fig. 4.129 is a typical diagram of water-related systems used at thermal power plants [52]. In the main water system, water circulates starting as condensate, followed by boiler feedwater, boiler water (in the boiler) and steam (in the turbine), and finally returning to condensate. The water that is lost during circulation is compensated by supplying make-up water. In addition to the main system, the plant can also have the following water-related facilities: (1) the make-up water treatment system by which raw water such as industrial water is treated to produce/supply highly purified water, (2) the chemical dosing and water-quality monitoring system through which water quality is monitored and adjusted to keep water noncorrosive, (3) the condensate treatment system in which circulating water in the plant is purified (mainly installed in once-through boilers), and (4) the wastewater treatment system to purify wastewater from the equipment and facilities of the plant. Fig. 4.130 shows water-induced problems and the sites where they occur [52]. In recent years, there have been an increasing number of incidents in which the causes are contamination by impurities such as ion-exchange resins and chemicals from the demineralizer (e.g., hydrochloric acid). Some of them pertained to the affected properties of raw water as a result of contamination by organic compounds or aging water treatment facilities. There are also other water-induced or related problems

Figure 4.129 A typical water/steam system at thermal power plants [52].

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Figure 4.130 Water-induced problems and their occurrence sites [52].

such as pipe wall thinning due to flow-accelerated corrosion (FAC) and an increased drop in the feedwater heater pressure due to scale deposition. These issues indicate the increasing importance of water quality control.

4.4.2 History of water treatment methods for thermal power plants The history of water treatment methods for domestic thermal power plants is shown in Fig. 4.131 [53]. Table 4.7 gives identified problems and the relevant events for water treatment [53]. Table 4.8 is a list of the treatment methods for boiler feedwater and boiler water [54]. As shown in Fig. 4.131, a subcritical pressure drumtype boiler of 17 MPa class was built in 1959 and started operations using alkali treatment. However, problems due to alkali corrosion of waterwall tubes frequently occurred about 6 months after the commencement of operations. The subsequent demand for urgent improvement of feedwater and boiler water treatment technologies led to the introduction of all-volatile treatment (AVT) using ammonia and hydrazine, which had been under development in Europe. AVT, adopted by subcritical pressure circulation-type boilers in 1960 and by once-through boilers in 1961, brought about good results. Thereafter, with the rapid popularity of its application, AVT was used for most of the new large-scale thermal power plants [54].

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Figure 4.131 History of water treatment methods for domestic thermal power plants [53].

In the middle of 1965 the inspection results of scale deposition on the inner surface of steam-generating tubes over the years necessitated the reassessment of phosphate treatment (PT) application. As a result, circulation-type HP boilers adopted low-pH PT (low-pHT), in which the phosphate ion level was maintained low (3 mg/L or less) and the Na/PO4 molar ratio in sodium phosphate was adjusted to be between 2.5 and 2.8 in terms of the prevention of alkali corrosion. Favorable effects, such as a reduced build-up rate of scale deposition in steam-generating tubes, more stable-scale properties, and less frequent chemical cleaning of boilers, were demonstrated. In both AVT and low-pHT, scale deposition and corrosion of materials used for the system components are suppressed by maintaining the dissolved oxygen level as low as possible, thereby preventing the occurrence of waterrelated problems. In oxygenated treatment (OT), on the other hand, a high anticorrosion effect can be achieved through the use of highly purified water containing an appropriate level of dissolved oxygen. Following the success in other countries such as Germany and Russia, Japan also conducted verification tests for OT and in 1989 published its first water quality control criteria in JIS B 8223. The first Japanese OT application was to a large once-through boiler in 1990. As of the end of October 2019, OT is operational at 54 once-through boiler plants [54]. And currently in heat recovery steam generators (HRSGs), feedwater undergoes AVT in which ammonia and hydrazine are injected, while boiler water is subjected to PT in which phosphates are added [54].

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Table 4.7 Identified problems at thermal power plants and the relevant events for water treatment [53]. Year 1940s

Newly identified corrosion-related problems G

G

1950s

G

G

1960s

G

G

1970s

G

G

1980s

G

Pitting and brittleness of steamgenerating tubes Cracks in turbine components Alkali corrosion in steam-generating tubes Ammonia corrosion in aluminum or brass condenser tubes Increase in pressure loss and overheating due to steamgenerating tube-scale deposition Feedwater heater inlet attack Detachment of deposited scale from the superheater or reheater Corrosion fatigue Feedwater heater drain attack

Events for water treatment

G

G

G

G

G

G

G

G

G

1990s

G

2000s

G

G

Valve corrosion caused by oxygenated treatment FAC Powdered-scale deposition in oxygenated treatment

G

G

Technological introduction from United States PT/AVT application Boiler chemical cleaning application JIS criteria (1 Feb. 1961) Oxygenated treatment application (Germany and Russia) Use of titanium condensers Use of total condensate treatment equipment Start of commercial combined-cycle plant operations JIS oxygenated treatment criteria (1989) Commercial application of oxygenated treatment Viability assessment of high-AVT for nuclear power plants (as a measure against FAC)

AVT, All-volatile treatment; FAC, flow-accelerated corrosion; PT, phosphate treatment.

4.4.3 New technologies regarding water treatment for thermal power plants 4.4.3.1 Measures against flow-accelerated corrosion Fig. 4.132 shows an example of tube wall thinning caused by FAC in an HRSG [54], which occurred at an overseas combined cycle plant. Over 3 years after the start of commercial operation, the wall thickness of the tubes was reduced by half or more, resulting in leakage. In this case the probable cause is the pH level of feedwater or low-pressure drum water, which was kept low. Fig. 4.133 gives the relationship between the pH and the rate of wall thinning due to FAC [54]. As it has been demonstrated that the rate of tube wall thinning due to FAC is reduced at higher pH levels, increasing the pH level is expected to have a mitigating effect against FAC. AVT with a high pH level exceeding the Japanese Feedwater Quality Control Standards (upper pH limit of 9.7) provided by JIS B8223:2006 is known as “High-AVT water

Table 4.8 Treatment methods for boiler feedwater and boiler water [54]. Power generation method

Heat source

Type of power generation

Operating pressure

Type of boiler

Treatment method of feedwater

Treatment method of boiler water

Steam power plant

Flame burner

Steam power generator

Subcritical

Circulation

AVT

AVT PT

Supercritical Ultra supercritical Subcritical

Once-through

AVT OT AVT

Combined cycle power plant

Combustion exhaust gas

HRSG

Supercritical

HRSG (circulation) HRSG (oncethrough)

AVT, All-volatile treatment; HRSG, heat recovery steam generator; OT, oxygenated treatment; PT, phosphate treatment.

AVT

AVT PT

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Figure 4.132 Example of FAC [54]. FAC, Flow-accelerated corrosion.

Figure 4.133 Relationship between pH and FAC rate [54]. FAC, Flow-accelerated corrosion.

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Table 4.9 Comparison of phosphate treatment (PT) and high-AVT (all-volatile treatment) water treatment [55]. Chemical used Feedwater

Feedwater: AVT Boiler water: PT Feedwater/boiler water: high-AVT

pH of feedwater

Boiler water

Ammonia

Hydrazine

Sodium phosphate

Used

Used

Used

8.5
9.7

Used

Not used

Need not be used

9.8
10.3

In cases when PT is replaced with high-AVT, it is recommended that chemical cleaning should be performed at the time of replacement to remove risks due to phosphorus remaining in scale.

Figure 4.134 Relationship between the pH and the iron concentration at the low-pressure feedwater pump outlet (measured values from an actual unit) [54].

treatment.” Since the JIS revisions in 2015, the upper pH limit for feedwater has been elevated from 9.7 to 10.3, allowing high-AVT water treatment (with a feedwater pH of 9.8 or higher) to be applied to actual units. Table 4.9 shows a comparison of the conventional PT and the high-AVT water treatment [55]. Fig. 4.134 illustrates the relationship between the pH and the iron concentration at the feedwater pump outlet (measured values from an actual unit) [54]. The change in the feedwater pH level (from 9.6 to 9.8) has reduced the iron concentration by about 27%, which is considered to have resulted from the mitigating effect against FAC. Fig. 4.135 shows the relationship

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Figure 4.135 Relationship between pH and FAC thinning rate (high-pressure economizer) [56,57]. FAC, Flow-accelerated corrosion.

between pH levels and the FAC rate [56,57]. It has actually been measured that an increase of the pH of feedwater from 9.5 to 9.8 reduces the rate of the thinning of pipe walls by half [56], and at a pH level of 10, the rate of the thinning of pipe walls is expected to be further reduced [57].

4.4.3.2 Measures against powdered-scale deposition in oxygenated treatment operation in once-through boiler OT in Japan has effectively (1) reduced the frequency of chemical cleanings by lowering the build-up rate of scale, (2) alleviated the increase of boiler pressure loss by preventing rippled-scale build-up, (3) improved environmental conservation by reducing ammonia usage, (4) reduced-scale deposition on equipment surfaces, and (5) reduced FAC. As shown in Fig. 4.136, OT has slowed the build-up rate of rippled scale compared with AVT [53], alleviating the increase of boiler pressure loss. Thus an increase in feedwater pressure at the boiler inlet (i.e., the increase in feed-water pump power) has been curbed. In addition, the slower build-up rate via OT allows the boiler chemical cleanings (scale removal) to be deferred from 2 to 4 years to more than 10 years. With this effect and others, it has contributed in some boilers to a savings of more than 50 million yen per year for a 600-MW plant [58]. In recent years, an increased amount of iron transferred into the boiler and the deposition of hematite scale on the inside surfaces of the boiler furnace wall tubes in some OT plants have caused the temperature of the metal furnace wall tubes to increase. The deposited hematite scale, called “powdered scale,” has low thermal

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Figure 4.136 Difference of scale on the inner surface of furnace steam-generating tubes between AVT and OT [53]. AVT, All-volatile treatment; OT, oxygenated treatment.

conductivity and a porous structure consisting of small particles. Fig. 4.137 shows powdered scale deposited [9] on the inside surfaces of boiler furnace wall tubes. Test results of material balance of iron in the plant systems indicated that iron removal and transfer are primary sources of powdered scale and therefore it is thought that the reduction in the transfer of iron particles into the boiler will reduce powdered-scale deposition by decreasing the iron concentration in the drain system of the low-pressure feed-water heater. The following countermeasures were studied and introduced in the plants: 1. replacing the low-pressure feedwater heater material with stainless steel (reducing iron elution), 2. shifting the pH value of the feedwater (lowering iron solubility), 3. shifting the pH value in the low-pressure feedwater heater drain system by injecting ammonia (lowering iron solubility), 4. injection of oxygen into the low-pressure feedwater heater drain system (accelerating hematite formation), 5. closed operation of the vent valve of the low-pressure feedwater heater (accelerating hematite formation), and 6. installation of a high-temperature filter for removing suspended iron in the low-pressure feedwater heater drain system (lowering iron concentration).

Fig. 4.138 shows an example in which implementing countermeasures (2)
(4), that is, controlling water quality and lowering the iron concentration of the

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Figure 4.137 Powdered scale deposited on a boiler generating tube [59].

low-pressure feed-water heater drain system, reduced powdered-scale deposition [59]. For the prevention of powdered-scale deposition the iron levels transferred into the boiler need to be lowered. As stipulated by the water quality control (recommended) criteria (Table 4.10), the iron level at the inlet of boiler (economizer inlet) should be 2 μg/L or less (targeting 1 μg/L or less) [53].

4.4.4 Remarks Water treatment technologies for thermal power plants have been examined and improved as a countermeasure against equipment damage due to factors such as corrosion and scale deposition. The actual performance of high-AVT water treatment, which is a watertreatment method for HRSG at combined cycle plants, has been well received, and

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Figure 4.138 Powdered-scale reduction via optimized water quality during normal operations [59].

Table 4.10 Once-through boilers: water quality control criteria during oxygenated treatment operation (recommended values) [53]. Water quality pH Dissolved oxygen Iron Cation conductivity

Economizer inlet (recommended value) 

At 25 C (μg/L) (μg/L) (mS/m)

8.5
9.3 (9.0) 20
200 (50 6 30) 2 or less (1 or less) 0.02 or less

() represents target value.

high-AVT water treatment was adopted as the standard in JIS B8223 which was revised and issued in October 2015. It has been verified that its high-pH operation has the effect of reducing FAC and phosphate corrosion and also allows hydrazinefree operation/storage. OT is superior to AVT for a once-through boiler. Recently, some OT plants have experienced increased iron concentrations of feedwater. In addition, a powdered-scale deposit has been generated and attached to the inside of the furnace wall tubes, contributing to an increase in the wall tube temperature. Controlling water quality and lowering the iron concentration of feedwater, reduced powdered-scale deposition. Abnormalities in water quality can be a precursor of problems and therefore serious problems can be prevented by analyzing the data and taking necessary measures.

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References [1] T. Aruga, S. Tadakuma, K. Kosaka, Y. Yamauchi, A. Takayama, M. Mori, Verification of tube temperature prediction method for pulverized coal-fired boiler, in: Procedure of the 24th National Symposium on Power and Energy Systems, Paper No. 19-16, 2019. [2] K. Matsumoto, J.T. Saeki, Y. Takei, T. Suto, Development of ultra-low NOx coal firing M-PM burner and successfully operational results, Mitsubishi Heavy Ind. Tech. Rev. 52 (2) (2015) 72
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4 (in Japanese). [8] Do¨ing M., Heumer J., Eich J., Emelianova P., Kunz C., Rhiel F., et al., Waste to Energy 2017/2018, 10th ed., 2017. [9] Japan Waste Management Association, Planning and Design Guidelines for Waste Processing Facility Development, third version first printing, 2017 (in Japanese). [10] M. Furubayashi, Frontline and Issues Concerning the Use of Biomass and Waste Power Generation as Energy, S&T Publishing, Chapter 9, Section 2 [2] (in Japanese). [11] K. Yamase, H. Sakaguchi, M. Furubayashi, T. Sato, T. Katayama, Stabilization of combustion in grate type incinerator with AI technology, in: The 10th International Conference on Combustion, Incineration/Pyrolysis, Emission and Climate Change, ICIPEC-0014, 2018. [12] K. Yamase, M. Furubayashi, A. Usutani, Low NOx combustion with exhaust gas recirculation and SNCR in stoker type incinerator, in: The Ninth International Conference on Combustion, Incineration/Pyrolysis, Emission and Climate Change, PROGRAM CODE: 0065, 2016. [13] K. Yamase, M. Furubayashi, A. Usutani, T. Ishida, “Low NOx combustion with exhaust gas recirculation and SNCR in Stoker type incinerator”, Environ. Sanit. Eng. Res. 30 (3) (2016) 39
42 (in Japanese). [14] Mitsubishi Hitachi Power Systems, Ltd, Wide air quality control system (AQCS) product line-up to meet the needs of any country world wide, Mitsubishi Heavy Ind. Tech. Rev. 52 (2) (2015) 101
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[18] H.S. Swenson, J.R. Carver, G. Szoeke, The effects of nucleate boiling versus film boiling on heat transfer in power boiler tubes, Trans. ASME, Ser. A 84 (1962) 365
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part 2: combustion and heat transfer analysis, Mitsubishi Heavy Ind. Tech. Rev. 20 (5) (1983) 24
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119 (in Japanese). [30] T. Kawamura, K. Nakamura, K. Fukahori, Multiple fuel firing controlled circulation boiler using rifled tubing, Mitsubishi Heavy Ind. Tech. Rev. 17 (2) (1980-3) 83
93 (in Japanese). [31] U. Akita, Introduction for new products, Shikoku Electric Power Co. Ltd., Shin-Saijo no. 2 boiler (low circulation ratio control circulation boiler), Mitsubishi Heavy Ind. Tech. Rev. 7 (3) (1970) 156
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[37] Thermal and Nuclear Power Engineering Society, ed., Handbook for Thermal Power Engineers, eighth ed., Thermal and Nuclear Power Engineering Society, Tokyo, 2017. [38] I.J. Karassik, Engineering Guide to Centrifugal Pumps, McGraw-Hill, New York, 1964. [39] M.A. Styrikovich, S.L. Miropolsky, M.E. Schitzrnan, W¨armeu¨bergang in kritischen Druckgebiet bei erzwangener Stro¨mung des Arbeitsmediums, VGB 61 (1959) 288
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[55] S. Tsubakizaki, T. Wada, T. Iwato, T. Nakahara, M. Nakamoto, Y. Noguchi, Advanced water treatment technologies (high-AVT) for HRSG corrosion control corresponding to new JIS B8223 (Japanese Industrial Standards), Mitsubishi Heavy Ind. Tech. Rev. 54 (3) (2017) 63
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554.

Construction, operation, and control of power boiler

5

Michio Sasaki1, Shingo Naito1 and Akira Yamada2 1 Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan, 2Mitsubishi Heavy Industries, Ltd., Nagasaki, Japan

Chapter outline 5.1 Construction of coal-fired boiler 257 5.1.1 5.1.2 5.1.3 5.1.4 5.1.5 5.1.6

Introduction 257 Advanced construction method/simultaneous construction method 258 Floor block erection method/floor unit construction method 258 Hyper core structure construction method 259 Top girder and pressure parts integrated block jack-up method 259 Module construction method 259

5.2 Operation and control of power boiler 5.2.1 5.2.2 5.2.3 5.2.4 5.2.5

262

Dynamic behavior of power boiler and control system 262 Boiler control system 267 Boiler start-up and shut-down operation 289 Partial load operation/sliding pressure (variable pressure) operation 299 Remarks 301

Nomenclature 302 References 302

5.1

Construction of coal-fired boiler

5.1.1 Introduction Overall feature of thermal power generation plant to be installed on the site is exemplified as shown in Fig. 5.1. Even when focused on boiler construction, there are many components to be assembled smoothly and economically. Whenever we are engaged in the construction of a coal-fired boiler on site, we have to consider our customer’s needs, for example, a short construction lead-time, a reduced material laydown area(s), the actual size of equipment, and the Power Station’s location and its relevant environmental conditions/restrictions, for which so far we have been able to accommodate through the development of a variety of different construction methods. In the past, as it was the norm to follow a sequential method for separately installing single equipment, and given the pressing need to optimize the existing installation procedures, we resorted to devising a block style preassembly of the various equipment parts at the ground level. In order to maximize the benefits of the block style assembly, we needed to assemble larger equipment and parts Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00005-9 © 2021 Elsevier Inc. All rights reserved.

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Figure 5.1 Example of coal-fired power generation plant system. Source: Courtesy MHPS.

to achieve the highest degree of completion. To match the strides of achieving a higher degree of block completeness, we faced the difficult challenge in finding an effective method for erecting the block to its final position and went on to developing the most suitable methodology for each situation. Furthermore, in order to forecast and minimize all risks related to safety, quality, site schedule and every other aspect of a plant construction, and from this perspective, we needed to reduce the site manpower, prompting us to shifting the assembly of a large block from site, to being assembled in factory, which scope kept on growing to eventually evolve from a large block to a module type assembly. Listed in the following sections are some representative examples of construction methods of coal-fired power plant. Similar procedures are applied to oil-fired and gas-fired power generation plants with some exceptions.

5.1.2 Advanced construction method/simultaneous construction method The method for carrying out the erection of the steel frame structure for boiler based on simultaneously configuring, duct, coal bunker, pulverized fuel pipe and its pipe support device block, long pipe, heavy equipment, and so on, to a predetermined position in advance. This system has been designed to improve the efficiency of product logistics and handling work by reducing the volume of product parts that are difficult to install after completing the steel frame structure erection works.

5.1.3 Floor block erection method/floor unit construction method The floor of each level comprising the steel frame structure for boiler and platform are assembled in advance into a block either assembled on the ground level in a different place on site, or in factory, and after it had been transported to site; it is lifted and installed in the designated position. When lifting the floor block, the product (equipment and facilities such as handrail, duct, pipe, field instrument panels, cable

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trays, and soot blower) supported by the steel frame structure constituting the floor are assembled on the ground as a built-in unit before lifting the floor block by crane, as a final product. Measures should be put in place to reduce the number of site crane lifting operations and crews working at heights.

5.1.4 Hyper core structure construction method The inner column of the steel frame structure for boiler is completed in advance, and the boiler top steel frame structure which supports the boiler pressure parts from above is erected. After completion of the boiler top steel frame structure, the boiler outer steel frame structure is erected concurrently with lifting and assembling of the boiler pressure parts. Furthermore, by commencing the assembly of pressure part before the completion of the whole erection of boiler steel frame structure, we are able to achieve a substantial shortening of the erection lead time.

5.1.5 Top girder and pressure parts integrated block jack-up method This is a method consisting of lifting a boiler top steel frame structure composed of top girder supporting the boiler’s pressure parts by using a hydraulic jack, after ground assembly on a boiler mat. Depending on the level at which the steel frame structure is lifted, the steel frame structure and the pressure parts are integrated while the pressure parts (header and connecting pipe around the roof, various tube elements) are sequentially suspended onto the steel frame structure. Then the steel frame structure, and the pressure parts are lifted to the designated position. This method is meant to reduce work at heights in the field, since hanging work of pressure parts product can be done at a lower position than the predetermined level one.

5.1.6 Module construction method From a risk hedging viewpoint in relation to Q (quality), C (cost), D (delivery period), S (safety) during boiler installation work in the field, a boiler is assembled to a nearly completed module, transported to a power plant construction site, and placed in a specified position ready for erection works. The shortening of the boiler installation work process in the field is achieved, only when the module which constitutes the whole boiler is carried out in parallel to the construction work in the field. As the module itself becomes an ultra-large block configuration, it is necessary to pay special attention to the transportation restrictions from the place of assembly to the project site predetermined position, prompting the need to consider the applicable modularization scope.

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Regarding the module construction method, there are various types, depending on the scope extent of the intended boiler modularization. For example, among the different construction methods we can depict the following: boiler pressure parts, coil module, boiler split module, and boiler zone module. Assembly of the module is mainly carried out in a place different from the power plant construction site (e.g., factory), however depending on the location of the construction site; the module can also be assembled in proximity to the boiler installation site.

5.1.6.1 Coil module for boiler pressure parts method As one type of boiler assembly method, the scope of coil heating surface, which constitutes the boiler pressure parts, is modularized. After it has been placed onto the boiler mat, it is lifted to the predetermined position.

5.1.6.2 Boiler split module method A method in which a boiler is divided vertically, each of which is assembled as a module, in a state of a finished product at a place different from the construction site, (e.g., factory, laydown area). After transportation, the vertically divided boiler is joined together in the field.

5.1.6.3 Zone module construction method As an applicable module method for a large sized boilers, a zone module method was developed in which the boiler was divided into multiple zones. In each zone, the boiler was divided into modules consisting of boiler steel frame structure, and those modules were joined in the field. Herewith, the modularization of the boiler scope extent had increased; to the benefit of reducing the site erection of manpower. The zone module is composed of boiler steel frame structure, duct, pipe, and modules composed of various equipment assembled for each zone. So far, the types of zone module in a coal-fired boiler are described as per the following, and in addition to the aforementioned, it is worth mentioning that almost all scopes of a boiler are suitable for modularization.

5.1.6.3.1 Side, front, and rear zone The steel frame structure is divided in multiple zones which consists of the boiler’s right and left sides, front end and rear end zones. Each zone is conformed of multiple modules at each level. At the module assembly place the modules are assembled, and by incorporating in its scope the relevant parts (e.g., duct, pulverized fuel pipe, pipe, light oil pipe, local panels, cable trays, steam separator, separator drain tank, connecting pipe), which are arranged as part of each module scope, we seek to achieve a substantial reduction in field workload as well as the shortening of the erection schedule.

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5.1.6.3.2 Mill zone The zone below the coal bunker is modularized. The module assembly is placed by incorporating onto the steel frame structure the duct, pulverized fuel pipe, pipe, local panel, and cable trays. Such a method is aimed at substantial reduction in field workload as well as the shortening of the construction schedule.

5.1.6.3.3 Bunker zone The coal bunker zone is modularized by integrating coal bunker onto the steel frame structure for boiler.

5.1.6.3.4 Eco hopper zone The zone below rear pass is modularized. The modules are assembled by incorporating onto the steel frame structure eco hopper, duct, piping, local panel, and cable trays. Such a modularization is aimed at substantial reduction in field workload as well as the shortening of the construction schedule.

5.1.6.3.5 Selective catalytic reduction and air heater zone The air heater (AH) zone is modularized by integrating the selective catalytic reduction (SCR) onto the AH steel frame structure forming one module. The modules are assembled by incorporating onto the steel frame structure the AH, duct, pipe, SCR, local panel, and cable trays. Depending on the site configuration, the AH and SCR are modularized in two separate modules.

5.1.6.3.6 Furnace upper zone This is a method aimed at modularizing the upper zone of furnace side dividing it vertically into two parts. At the module assembly place the module is assembled, and by incorporating onto the steel frame structure the pressure and nonpressure parts, which are arranged as part of the scope into the module, we seek to achieve a substantial reduction in field workload as well as the shortening of the construction schedule.

5.1.6.3.7 Furnace lower zone This is a method aimed at modularizing the lower zone of furnace side and Eco zone into one module. The module is assembled by incorporating onto the steel frame structure the pressure and nonpressure parts, eco lower hopper, duct, pipe, local panel, and cable trays.

5.1.6.3.8 Secondary pass zone The convection pass zone module is assembled by incorporating onto the steel frame structure all relevant pressure and nonpressure parts.

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Operation and control of power boiler

As the amount of renewable energy introduced has increased in recent years, the stable supply of electric power in response to natural changes has become an extremely important issue. It is expected that coal-fired steam power stations will also play a role in the stable supply of electric power as they are required to have load regulating power. For this purpose, it is essential to understand the characteristics and control of boilers in coal-fired steam power plants and to construct a control system according to the situation. There are various methods for main steam temperature control (STC), which is one of the main control for once-through boiler. This section introduces the behavior of dynamic characteristics and control of drum boiler and once-through boiler, the main STC method for once-through boilers, and the start-up and shut-down operation procedure for coal-fired once-through boiler. In addition, the latest main STC technology applying improved water
fuel ratio control is introduced.

5.2.1 Dynamic behavior of power boiler and control system Power boilers can be broadly classified into two types, one is a drum type, that is, water-tube boilers including natural- and forced-circulation boilers, and the other is a once-through type. The drum boiler is characterized by the evaporation completion point fixed at the steam drum. The once-through boiler has no steam drum and the evaporation completion point in the evaporator moves due to the change of state. The difference in the dynamic characteristics of two types of boilers needs different control systems.

5.2.1.1 Dynamic characteristics of drum boiler In the drum-type boiler a steam drum is installed at the outlet of the furnace, a saturated steam mixture heated by the furnace flows into the drum, and saturated steam is led to the superheater (SH). The amount of saturated steam (boiler evaporation rate) is controlled by the amount of fuel input as boiler heat input. Fig. 5.2 shows the principle of the drum boiler. Steam is generated by increasing the boiler heat input by the burner, and the water level in the steam drum does not change if the feedwater is supplied smoothly. Thus the evaporation rate of the drum boiler is determined by the amount of fuel supply. In addition, when the water level in the steam drum falls due to evaporation, water sufficient for the amount of evaporation is fed into the boiler to keep the same level. Feedwater control (FWC) is responsible for this function. That is, when the drum water level of the boiler goes up and down, the water level is controlled to a specified value by increasing or decreasing the feedwater flow. Meanwhile, the drum boiler is divided into evaporation zone and superheating zone. In the drum boiler, as described above, the steam in the evaporation zone is always saturated steam and becomes superheated steam at the superheating zone.

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Figure 5.2 Drum boiler principle. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

At this time the temperature of the superheated steam is determined by the balance between the heat input to the SH (i.e., the combustion gas flow and temperature) and the amount of heat carried by the steam passing through the SH (i.e., the saturated steam flow at the SH inlet). Therefore the outlet steam temperature from the boiler changes according to the heat transfer characteristics. However, turbines require a constant steam temperature. Thus in the boiler side, the steam temperature is controlled to a specified value by spraying low temperature water in the middle of the SH. In the boiler with a reheater (RH), it is necessary to keep the RH outlet temperature at a specified value. In the SH the temperature at the outlet of the SH is adjusted by reducing the temperature of the steam in the middle of the SH by spraying. On the other hand, the RH outlet temperature is controlled to a specified value by changing the amount of heat input to the RH (i.e., the combustion gas flow). The combustion gas flow to the RH is controlled by the distribution of the combustion gas flow to the SH system and the RH system, or the change in the recycle gas flow. These movements can be confirmed by the dynamic characteristic chart of a once-through boiler and drum boiler shown in Fig. 5.3.

5.2.1.1.1 Step increase in fuel flow rate An increase in the fuel input causes an increase in the evaporation rate. and the main steam pressure rises accordingly. On the other hand, the drum water level falls due to evaporation. The steam temperature is also rising due to the increase of the combustion gas temperature and the combustion gas flow rate.

5.2.1.1.2 Step increase in feedwater flow rate Changes in feedwater only raise the drum water level, and the evaporation amount, main steam pressure and steam temperature are little influenced.

5.2.1.1.3 Step change in governing valve opening position The governing valve opening position increase results in an increase in the steam flow rate to the turbine and a decrease in the main steam pressure. This leads to an increase in the evaporation in the drum and lowers the drum water level. The steam temperature drops as the steam flow rate to the SH increases.

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Figure 5.3 Dynamic characteristic chart of drum boiler and once-through boiler. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [2].

Since the drum boiler has a large heat capacity and a slow pressure fluctuation as compared with the once-through boiler, changes in the generator output and main steam flow are large, and the duration of these changes is long. Therefore governor-free (GF) operation is more suitable for the drum boiler.

5.2.1.1.4 Step increase in spray water flow rate By supplying the spray water to the middle of the SH the steam flow rate at the boiler outlet increases accordingly. The main steam temperature is lowered by this spray. The main steam pressure slightly increases because the spray water flow rate is low. Based on the dynamic characteristics for each state change shown in Fig. 5.3, the drum boiler is controlled by a noninterference system. Since the drum boiler has a fixed heating zone, the load characteristics of the main steam temperature depend on the type of the boiler. The rated operating range of the main steam temperature is approximately 50% or more as shown in Fig. 5.4.

5.2.1.2 Dynamic characteristics of once-through boiler The once-through boiler has no drum, and the evaporation completion point changes inside the evaporator. The once-through boiler can be considered as a model in which one water pipe is heated to saturate and superheat as shown in Fig. 5.5. In this case the boiler evaporation rate is determined not only by the fuel input but also by the feedwater flow rate.

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Figure 5.4 Main steam temperature characteristics. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

Figure 5.5 Once-through boiler principle. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

In addition, when the fuel input is increased under constant feedwater flow rate, the saturation region becomes short, and the superheated part becomes relatively long. As a result, the boiler outlet main steam temperature rises. Conversely, when the fuel input is reduced, the main steam temperature will decrease. SH sprays are also used for main STC in the case of a once-through boiler. However, the usage is basically different from that of the drum boiler. Fig. 5.6 shows the SH and SH spray system of the once-through boiler. Generally, an SH spray system constitutes a bypass system in the evaporation zone and part of the SH. For this reason, in the spray system, the flow rate of steam passing through the evaporation zone and part of the SH (shown as primary in the figure) is reduced accordingly. This means that even if the spray water flow is increased to lower the steam temperature downstream of the spray point, the steam temperature upstream of the spray point rises over time. Therefore it may happen that even though an increase in the spray water flow, the steam temperature cannot be adjusted. However, SH spray is effective for control of transient steam temperature disturbance because of its quick response, although it is a temporary effect. In a boiler with an RH, it is necessary to keep the reheat steam temperature at a specified value. The concept of this control is similar to that of the abovementioned drum boiler at the point of, e.g. distribution of the combustion gas flow to the SH system and RH system or adjusting the recycle gas flow.

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Figure 5.6 Steam temperature control characteristics of once-through boiler. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

The behaviors of various parameters are confirmed by the dynamic characteristic chart shown in Fig. 5.3.

5.2.1.2.1 Step increase in fuel flow rate The evaporation completion point moves upstream due to an increase in boiler heat input, and the evaporation rate temporarily increases at this time. As the feedwater flow remains constant, the evaporation rate returns to the original value. The main steam temperature rises with an increase in the relative superheating zone. Along with this, the specific volume of steam also increases, the volumetric flow rate increases, and the main steam pressure rises slightly. Such increase results in an increase in the turbine generator output.

5.2.1.2.2 Step increase in feedwater flow rate As the feedwater flow rate increases, the main steam flow rate increases and the main steam temperature decreases. On the other hand, an increase in the main steam flow rate is an increase in the main steam pressure and the generator output, but as time passes, due to a decrease in the main steam temperature and the RH steam temperature, they all fall close to the original value. Therefore, if the steam

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temperature is kept constant, the main steam pressure increases due to an increase in the main steam flow.

5.2.1.2.3 Step increase in spray water flow rate An increase in spray water flow rate brings about a temporal increase in the main steam flow rate, and the main steam pressure and generator output also rise. The main steam temperature drops temporarily. However, as the time passes, every parameter will become close to the original value. From the characteristics of each state parameter of the boiler in Fig. 5.3, it should be understood that the oncethrough boiler is a mutual interference system. Since this is an advantage and at the same time becomes a disadvantage, high control accuracy is required. Since the once-through boiler relatively elongates or shortens the superheating zone depending on the fuel/feedwater ratio, the rated operating range of the main steam temperature is approximately 25% or more, being wider than the drum boiler. Fig. 5.7 shows the basic control method for each type of boiler configured based on the above.

5.2.2 Boiler control system Basically, a boiler-following mode and a turbine-following mode are adopted as the operation method of the thermal power plant. The former is a method to obtain highload follow-up characteristics by effectively utilizing the amount of heat possessed by the boiler and is generally applied to a drum-type boiler having a large heat storage capacity. The latter is a method that has been conventionally adopted in a

Figure 5.7 Basic control method of drum boiler and once-through boiler. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

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European once-through boiler, which is an operation method that does not utilize boiler heat storage, and although the boiler can obtain the most stable operation, it has a disadvantage that load following performance is inferior. The boiler
turbine coordinated control is currently generally applied as a control system for once-through boilers and drum boilers. This control method is intended to ensure high load following performance by using the boiler heat-storage capacity effectively and to obtain stable operation performance. The features of the above control method are shown in Table 5.1. The response of the amount of power generation by the boiler
turbine coordinated control method is faster than the turbine following method in load increase and load decrease, and is later than the boiler follow method. However, in this case, even if the response is slightly delayed, the amount of over/undershoot of the amount of entering and leaving the boiler can be properly suppressed. For this reason the coordinated control method has the smallest time integral value of the difference between the required power generation amount and the actual power generation amount.

5.2.2.1 Drum boiler Automatic control of the drum boiler is composed of three main controls: combustion control, feedwater control, and STC. When a boiler is considered as a controlled object, the relationship between these inputs and outputs can be modeled as shown in Fig. 5.8. In order to enable the boiler to supply steam at a constant pressure and temperature, it is necessary to maintain the mass balance of the water in the boiler by replenishing the feedwater flow at the same steam flow carried away to the outside. The amount of heat carried away by the steam must be supplied to the boiler to maintain energy balance. FWC is performed to maintain the mass balance of water. In drum boilers, the success or failure of the mass balance appears in the drum water level. It is indirectly performed as drum level control. The energy balance is performed by controlling the heat release rate by combustion, that is, the amount of fuel and the amount of air, so that the steam pressure becomes constant, and concomitantly, the air
fuel ratio control is performed. And the furnace pressure control is performed in the balanced draft type boiler. Control of this energy balance is referred to as automatic combustion control (ACC).

5.2.2.1.1 Automatic combustion control The ACC controls the fuel flow and air to the furnace to control the steam pressure and the excess air rate. These control methods are described in the following subsections. 5.2.2.1.1.1 Steam pressure control (boiler master control) The pressure control system in the drum boiler is shown in Fig. 5.9. It is configured to detect steam pressure, compare it to a set point, and control the fuel flow and air to eliminate this deviation. When a change occurs in the steam flow rate, if the fuel flow is changed in advance in accordance with the change amount, the steam pressure

Table 5.1 Characteristics of each control method. Control method

Boiler
turbine coordinated control

Boiler following control

Turbine following control

Load control: turbine (governing valve) Boiler (feedwater, fuel) MSP control: boiler (feedwater) Supercritical pressure once-through boiler (Constant pressure operation) (Sliding pressure operation)

Load control: Turbine (governing valve)

Load control: Boiler (fuel)

MSP control: Boiler (fuel) Drum boiler (Natural circulation boiler) (Forced circulation boiler)

MSP control: Turbine (governing valve) Monotube boiler (Sulzer boiler)

System

Basic control

Applicable plant

(Continued)

Table 5.1 (Continued) Control method

Boiler
turbine coordinated control

Boiler following control

Turbine following control

Advantages

1. Satisfactory load tracking Since the governing valve operates quickly according to the required amount of power generation within the boiler stability limit and at the same time the boiler load is changed by the required power generation signal, a satisfactory load tracking property can be obtained 2. Stable operating characteristics can be obtained The control system is more complicated than the boiler following control and turbine following control

1. Satisfactory load tracking Since the quick-acting governing valve is used and the heat storage capacity of the boiler is utilized as energy damper, the rising and falling of the generated power following the required value are extremely good

1. Stable operating characteristics The unit operation state is very stable because the unit does not use the boiler heat storage at all and changes according to the required amount of power generation while maintaining the steady state

Instability phenomenon due to mutual interference of controlled variables

Inferior load tracking

Disadvantages

MSP, Main steam pressure. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

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Figure 5.8 Relation between boiler input and output. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [2].

Figure 5.9 Example of steam pressure control (boiler master signal) logic. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

change can be suppressed to a small value, and the steam flow rate signal is added as a preceding signal. In general, the steam flow rate is not often measured, and in this case, a signal obtained by correcting the turbine first stage pressure with the main steam temperature is used to improve load change characteristics. 5.2.2.1.1.2 Air
fuel ratio control at low
excess air ratio An optimal combustion airflow must be supplied to effect combustion in the furnace. Supplying an excessive airflow not only increases the heat loss carried away from the boiler but also increases the auxiliary power such as the fan, resulting in uneconomical operation. Therefore O2 control is added to the combustion control system as shown in Fig. 5.10 and so-called low
excess air ratio combustion control is performed in which combustion is performed with air close to the theoretical airflow.

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Figure 5.10 Example of combustion control logic. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

On the other hand, the operation of the boiler with a low
excess air ratio temporarily loses the balance of the air
fuel ratio due to the response delay of the air control system in the transient state at the time of load change. As a result, problems such as generation of black smoke and unstable combustion may occur. For this reason, when performing a low
excess air ratio operation, it is necessary to always consider that the airflow does not run out in the transient state at the time of load change. To response, as shown in Fig. 5.10, cross-limit circuit is provided to increase the airflow at load increase (low signal selector; LS) and to decrease the fuel flow at the load decrease (high signal selector; HS), and then reduce the airflow.

5.2.2.1.2 Feedwater control FWC in the drum-type boiler means the water level control in the drum. An example of the water supply control method is shown in Fig. 5.11. Since the feedwater system configuration, quantity/type (e.g., adoption of a turbine drive feed pump) of feedwater pumps and operation method differ depending on the capacity, pressure, and so on of the boiler, it is necessary to give due consideration to the configuration of the control system. Fig. 5.11 is a typical example of three-element FWC consisting of drum water level, steam flow, and feedwater flow. The purpose of water supply control is to maintain the weight balance in the boiler by supplying the same amount of water as the amount of steam carried away to the outside. In the case of a drum boiler a shift in the mass balance appears as a change in drum water level. Therefore the three-element FWC controls the feedwater flow rate by the change of the steam flow rate and further adjusts the feedwater flow supplied into the boiler by the deviation from the specified level of

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Figure 5.11 Example of three-element feedwater control logic. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

the water in the drum. The proportional integrator (PI) controller installed at the drum level appears as an offset of the drum level because the amount of auxiliary steam used in the boiler system is relatively large with respect to the amount of evaporation of the boiler. Therefore the PI controller is provided to remove the offset.

5.2.2.1.3 Steam temperature control The STC system comprises a main STC system and a reheat STC system and maintains each steam temperature at a prescribed level in a prescribed boiler load area. 5.2.2.1.3.1 Main steam temperature control In the drum boiler the steam temperature is determined by the heat input to the SH, that is, the balance between the amount and temperature of combustion gas and the amount of heat carried by the steam passing through the SH. Therefore the boiler outlet steam temperature is controlled by regulating the amount of spray water to the attemperator installed between the primary and secondary SHs. Fig. 5.12 shows the concept of STC for the drum boiler. As this feature: 1. Since the temperature at the SH inlet is constant, the temperature fluctuation at the outlet of the SH is also reduced. 2. The effect of an increase in the evaporation rate and the heat transfer rate in the SH offsets the fluctuation of the main steam temperature, that is, the decoupling of the pressure control and the STC by the amount of fuel is realized. 3. The main steam temperature can be actively controlled by the SH spray with a good control response.

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Figure 5.12 Characteristics of steam temperature control of drum boiler.

Therefore these are all configured by the decoupling control system. Fuel Feedwater SH spray

Pressure control Drum water level control Steam temperature control

An example of the main STC logic is shown in Fig. 5.13. This control system is based on the boiler master signal by a boiler load, and a correction circuit is added to finally pull the deviation of the main steam temperature back to zero. That is, the boiler master signal given by the function generator and the spray water flow characteristics required for each boiler load becomes a flow control signal for the SH spray water. On the other hand, the output signal of the PI controller due to the deviation of the main steam temperature is given to attemperator to keep the main steam temperature at the specified value. Then, cascade control is performed to improve the control variable of the flow control of the SH spray water for the steam temperature at the outlet of the attemperator. 5.2.2.1.3.2 Reheat steam temperature control Reheat STC includes operation methods such as gas recirculation (GR flow), parallel path method (gas-dividing damper),

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Figure 5.13 Example of main steam temperature control logic. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

and burner tilt, and these are used alone or in combination, being common to the drum boiler and the once-through boiler. A comparison of reheat STC methods is shown in Fig. 5.14. Since, for example, the GR flow and the gas pass flow (gas-dividing damper) have the same effect on the RH outlet steam temperature, these two control methods are concurrently processed, compensating each other. RH spray is used as an emergency application when the reheat steam temperature rises during rapid load change and cannot be reduced on the combustion gas side such as GR amount, gas-dividing damper, and burner tilt. It has the role of pulling GR flow back to the normal control area.

5.2.2.2 Control of once-through boiler The large capacity once-through boiler includes the constant pressure type and the sliding pressure type. Although these have some differences in the start-up control method, basically the common control method for normal operation is adopted.

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Figure 5.14 Comparison of reheat steam temperature control methods.

Figure 5.15 Steam temperature control method of once-through boiler.

5.2.2.2.1 Main steam temperature control The STC method of the once-through boiler can be roughly classified into water
fuel ratio control and enthalpy control, as shown in Fig. 5.15. In Japan and the United States the boiler input is based on the feedwater flow rate, and STC by changing the fuel flow rate, that is, a water
fuel ratio control type has mainly been adopted. On the other hand, in Europe, the boiler input is based on the fuel flow rate, and STC based on changes in feedwater flow rate, that is, enthalpy control type is mainly adopted. The concept of the water
fuel ratio control type (conventional type) is shown in Fig. 5.16. The feature of this control is as follows: 1. Interference occurs because both the fuel and the SH spray control the main steam temperature. 2. Due to the influence of (1), constant spray operation tends to be a disturbance of the main STC.

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Figure 5.16 Concept of water
fuel ratio control type (conventional type) of once-through boiler. 3. The evaporation completion point fluctuates, and since the water wall outlet steam temperature is free, it has a potential to further expand the temperature fluctuation in the SH.

The concept of the enthalpy control is shown in Fig. 5.17. The feature of this control is as follows: 1. Since the water wall outlet steam enthalpy is controlled and fluctuations in the SH inlet temperature are reduced, the temperature fluctuation range of the SH outlet is also reduced. 2. The main steam temperature can be actively controlled by the SH spray with a good control response. 3. Since the function assignment of (1) and (2) is clear, the constant spray function can be configured without difficulty. 4. Fixation of evaporation completion point is not ideal, but is effectively controlled by the feedwater control with a good control response.

The following is a description of general main STC. The main steam temperature at the final SH (FSH) outlet is controlled by balancing the ratio of the feedwater flow and the fuel flow to the boiler. However, with this alone, since the response characteristic is slow, it is difficult to make a transient

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Figure 5.17 Concept of enthalpy control type of once-through boiler.

response to various disturbances such as load fluctuation. Therefore SH spray is used in combination with to improve the main steam temperature characteristics. The SH spray control system is composed of a cascade control system, operates the SH outlet steam temperature controller with the control target value of the SH outlet steam temperature deviation, and controls the SH inlet temperature (attemperator outlet). The SH inlet temperature set value is the static characteristic value of the boiler. In the case of multiple stages of SH spray, the same control is installed independently in series. Fig. 5.18 shows an example of such multistage SH spray control system. The reheat STC methods are, in principle, the same both in the drum and the once-through boilers.

5.2.2.2.2 Recirculation flow control system in the once-through boiler 5.2.2.2.2.1 Recirculation operation zone During start-up and low load, steam and water are separated in the steam separator installed at the inlet of the primary SH, and steam is circulated to the SH, and water is recirculated to the inlet of the economizer (ECO) by the boiler circulating pump (BCP) (Wet operation).

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Figure 5.18 Example of SH spray control system. SH, Superheater.

In the recirculation operation zone the behavior of the steam temperature is similar to that of the drum boiler, because the heat transfer area of the SH does not change. 5.2.2.2.2.2 Once-through operation zone At high load (30% load or more), the furnace outlet steam becomes superheated, so that water level in the steam separator disappears (dry operation), and the operating characteristics shifts to that of the once-through boiler. The one-through operation zone has the following characteristics: 1. The position of evaporation completion point is not constant, so the heat transfer area of the superheating section is not constant, and the steam enthalpy at the furnace outlet is not constant. 2. In order to secure the water velocity in the water tube, the diameter of water tube is small. There is no drum, so the amount of stored fluid and thermal energy is small.

From the above, it is necessary to more accurately balance the load, the feedwater flow, the fuel flow, and the airflow in the through-flow operation region. When this relationship is disturbed, the controlled amount fluctuates as follows: Feedwater flow/load!main steam pressure Fuel flow/feedwater flow!main steam temperature Airflow/fuel flow!excess air ratio (ECO outlet exhaust gas O2)

That is, in the once-through boiler, the main steam flow is determined by the feedwater flow, and the turbine side also receives the same main steam flow. Since

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the governing valve for turbine control also needs a movement corresponding to the main steam flow from the boiler side, coordination between the boiler and the turbine is essential.

5.2.2.3 Other boiler control 5.2.2.3.1 Unit output command control 5.2.2.3.1.1 Unit output signal The output command from load dispatch command or the power plant output request command (or automatic load regulator) is converted into a signal that changes at the desired rate of change. The output fluctuation for the frequency correction operation by GF of the turbine governor is allowed, but the output signal equivalent to the governor arbitration rate is further synthesized so as to correct the required output command only when the frequency fluctuation range is exceeded. This signal is limited by the load runback signal and the output upper/lower limit signal by the output setting determined by the number of auxiliary equipment such as the operable water supply pump and becomes a unit output signal. And the signal becomes an output demand signal to the turbine and the boiler. Fig. 5.19 shows the concept of generating the output command signal. Further, the unit load request signal automatically switches to the actual load signal, and when an abnormal state occurs in the boiler or turbine side, this signal holds the current condition (actual load tracking control). 5.2.2.3.1.2 Automatic frequency control Load fluctuations in the power system are the cause of frequency fluctuations and tidal current changes, which are divided into a sustaining component that changes relatively slowly and a fringe component that rapidly changes in period as shown Fig. 5.20. There is an optimal control assignment with respect to the period and magnitude of such various variable loads, and the abovementioned relationship is classified in Japan as shown in Fig. 5.21.

Figure 5.19 Concept of unit output signal creation. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

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Figure 5.20 Power system load fluctuation. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

Figure 5.21 Frequency fluctuation and control sharing.

That is, the load fluctuation of an early cycle of about 2 minutes or less is absorbed by GF operation of a hydropower or thermal power plant, and the load fluctuation belonging to the range of about 2
20 minutes is absorbed by automatic frequency control (AFC) operation. For longer term load fluctuation, the load dispatch adjustment is performed after determining the optimal power distribution of each power plant to minimize the power generation cost of the entire system. It is dealt with by so-called economic operation. Fluctuations in grid frequency occur when imbalances occur between supply and demand, with the following consequences: Supply . Demand . . .. . . Frequency rise Supply , Demand . . .. . . Frequency drop

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In other words the system frequency is a measure of the balance between supply and demand. Detecting this frequency and automatically increasing or decreasing the output of the generator is called AFC operation. On the other hand, mainly European power systems have Grid Code defined and operated for each European country, and frequency control is broadly divided into primary, secondary, and tertiary frequency control. In general, GF corresponds to primary frequency control, AFC corresponds to secondary frequency control, and dispatching power control corresponds to tertiary frequency control. 5.2.2.3.1.3 Turbine master control Fig. 5.22 represents the cocept of turbine master control. The amount of power generation is controlled by the governor controller to be equal to the unit load request signal; however, the following correction is received along the way. In the once-through boiler, since the amount of heat stored in the boiler is small, it is necessary to correct the amount of power generation while looking at the balance state of the boiler (coordinated control). That is, when the main steam pressure falls below the set value due to the delay in the follow-up of the boiler, the amount of power generation is apparently corrected if the main steam pressure is normal at that time. In addition, it prevents over opening of the governing valve position due to the main steam pressure drop. As the main steam pressure recovers, the actual power generation and the demand signal naturally become equal. When the main steam pressure further decreases, the governor automatically switches to the main steam pressure control and waits for the main steam pressure to return to the set value by the control on the boiler side. If the main steam pressure recovers, the governor will automatically return to the power

Figure 5.22 Turbine master control. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

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generation control. Also, when the main steam pressure rises, the control is the reverse of the above. Such abovementioned function is referred to as turbine master control. 5.2.2.3.1.4 Boiler master control Fig. 5.23 represents the concept of boiler master control. The main steam pressure target value (main steam pressure program) is determined by the unit load demand signal in the sliding pressure once-through boiler. Also, since it is necessary to supply boiler inputs (feedwater, fuel, and air) that always match the amount of power generation (boiler load), the unit load request signal is converted to a feedwater flow based signal for each load. It is basically feedwater flow command. Normally, this maintains the balance between load and boiler input, but when turbine efficiency changes or load change, an unbalanced state occurs, which is the deviation between the target value and actual value of the main steam pressure. The signal converted to the feedwater flow rate base is corrected by this main steam pressure deviation signal to become a boiler input demand (BID). The circuit that generates BID signal is called boiler master control.

5.2.2.3.2 Feedwater flow control In the once-through boiler, when unbalanced occurs in the water
fuel ratio, the main steam temperature changes abnormally. The feedwater flow is normally controlled by the feedwater controller so as to meet the boiler input command, however if the amount of fuel becomes too small for some reason, it is corrected so that the feedwater flow corresponds to the fuel flow (cross limit). Also, a restriction is added to secure the necessary minimum water supply amount in the furnace pipe, which becomes the final feedwater flow demand (FWD). The feedwater flow command is sent to the feedwater controller and the turbine-driven feedwater pump so that the feedwater flow becomes equal to the feedwater flow command. In addition, in the motor-driven feedwater pump, differential pressure control of the feedwater flow control valve is performed by the hydraulic coupling, and the feedwater flow is controlled by the feedwater flow control valve. Fig. 5.24 shows such concept of feedwater flow control.

Figure 5.23 Boiler master control.

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Figure 5.24 Feedwater flow control. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

5.2.2.3.3 Water
fuel ratio control In a once-through boiler the fuel flow and the feedwater flow must always be kept at a constant ratio in order to maintain the main steam temperature. Therefore the boiler input demand is corrected at the required fuel ratio to generate a basic combustion flow demand. Normally, this balances the amount of water supplied with the amount of fuel, but the correction described below is added to compensate the unbalance due to load change and boiler efficiency change. It is the final combustion demand for fuel and air, which is firing rate demand (FRD). At the time of load change or the like the required fuel flow changes with respect to the feedwater flow, this appears as a main steam temperature deviation. The main steam temperature controller corrects FRD so that this deviation disappears. Moreover, in order to prevent an abnormal rise of the main steam temperature, when the feedwater flow is reduced to a certain extent with respect to the FWD, an operation of limiting the fuel flow to an amount corresponding to the feedwater is added (cross limit). As described previously, the main steam temperature is controlled by the water
fuel ratio but is controlled by the immediate effect spray system for temporary changes in the main steam temperature such as load fluctuation. An example of main STC by water/fuel ratio control is shown in Fig. 5.18.

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Besides, as described in Section 5.2.3.2, there is also an enthalpy control type as a method of controlling the steam temperature. 5.2.2.3.3.1 Fuel flow control Fig. 5.25 shows an example of the fuel flow control concept. The fuel flow is controlled by FRD signal, but if the airflow decreases abnormally with respect to the fuel flow, combustion failure is caused, so FRD is limited to match the air amount (cross limit). FRD is sent to the fuel controller via this limiting circuit and controlled so that the amount of fuel becomes equal to the command. In the pulverizer (coal mill) the mill hot air damper (tempering damper) controls the ratio of the coal supply flow to the primary airflow to a set value. In addition, as the premise, the pulverizer inlet hot air pressure is controlled by the primary air fan so as to be constant. 5.2.2.3.3.2 Air
fuel ratio control Fig. 5.26 represents the concept of air-fuel control. In order to obtain efficient and stable combustion, an airflow corresponding to the fuel flow is required, but the basic airflow command is created by the fuel command. At that time, the airflow demand (AFD) is generated by the program taking into consideration of the optimal excess air ratio at each load. Since the change of the air/fuel ratio appears as a deviation of the ECO outlet O2, AFD is corrected so that the deviation is eliminated by the O2 controller. Since the O2 setting value depends on the load (combustion flow), it is created by programing from the FRD.

Figure 5.25 Example of fuel flow, primary airflow, and pulverizer outlet temperature control. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

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Figure 5.26 Air
fuel ratio control. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

5.2.2.3.3.3 Airflow control FRD is corrected by the air
fuel ratio control and becomes AFD, which is sent to the airflow controller to operate the burner wind box inlet damper to control the airflow. In the process, the following corrections receive. An abnormal increase in the fuel flow with respect to the airflow causes a combustion failure, so the airflow is increased to meet the fuel flow when the fuel flow exceeds a certain level (cross limit). The total airflow for the required AFD is controlled by the forced draft fan (FDF) blades. The burner wind box inlet damper is operated by a program based on the fuel flow of each burner stage. Two-stage combustion to reduce NOx is performed at the over firing air (OFA) port. It creates an OFA port inlet AFD commensurate with the two-stage combustion ratio for AFD (AFD 3 two-stage combustion ratio) and performs feedback control using the measured value of the OFA inlet airflow. Fig. 5.27 shows the concept of airflow control described above. 5.2.2.3.3.4 Furnace pressure control The concept of furnace pressure control is shown in Fig. 5.28. Coal fuel contains more ash and fuel in the fuel than oil and gas fuel and contains considerable dust in the flue gas. Therefore the pressure in the furnace is maintained below atmospheric pressure to prevent the emission of dust from the boiler. In this function the combustion gas flow in the furnace is adjusted by the induced draft fan (IDF) blade according to the combustion airflow supplied, and the pressure in the furnace is maintained at a specified value.

5.2.2.4 Latest boiler steam temperature control As shown in Fig. 5.15, there are two types of water
fuel ratio control type of the STC of once-through boiler, which are controlled by main steam temperature (conventional type) and intermediate SH outlet steam temperature (improved type). The improved water
fuel ratio control whose controlled object is the secondary SH outlet steam temperature is described in the following.

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Figure 5.27 Airflow control.

The FSH outlet steam temperature of the boiler is controlled by the water
fuel ratio (fuel flow) and the FSH spray water, but they interfere with each other. As a result, the settling of the FSH outlet steam temperature is delayed. In order to solve this problem the number of boilers adopting the latest STC method of improved water
fuel ratio control has been increasing in recent years, and the effectiveness has been confirmed in actual units. The control conceptual diagram of the improved water
fuel ratio control is shown in Fig. 5.29. The improved water
fuel ratio control system controls the secondary SH (2ry SH) outlet steam temperature disposed at the top of the furnace with the water
fuel ratio (fuel flow). And it is the method to control the tertiary SH (3ry SH) outlet steam temperature with secondary spray water, that is, 3ry SH outlet STC is dedicated to secondary spray operation only. As a result, the response to the endothermic change of the furnace and 2ry SH was improved, and the interference between the fuel and the spray water of 3ry SH outlet STC was also avoided. Also in the actual unit, it has been confirmed that the unit adopting the improved water
fuel ratio control settles the 3ry SH

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Figure 5.28 Furnace pressure control. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [1].

Figure 5.29 Comparison of conventional steam temperature control and improved steam temperature control (controlled object of each outlet temperature) [3].

temperature earlier. In addition, since the improved water
fuel ratio control has a simple control system, it has the advantage of being easier to tuning than before, and the dynamic characteristic test can be completed in a shorter time than before.

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5.2.3 Boiler start-up and shut-down operation 5.2.3.1 Boiler start-up Fig. 5.30 shows the overview start-up process of the coal-fired supercritical pressure once-through boiler.

5.2.3.1.1 Boiler cold cleanup Fig. 5.31 shows the overview of the water and steam system. If the preboiler cleanup is completed and the water quality criteria to the boiler is satisfied, it will shift to boiler cold cleanup. 5.2.3.1.1.1 Boiler water filling If all the water in the boiler has been discharged, water is filled to the water wall, ECO, storage tank, etc. before boiler cold cleanup. After completion of preboiler cleanup, use the boiler feedwater pump (BFP) booster pump system or the water filling system to fill the boiler with water until the level of the water storage tank rises while removing air by the air vent valve in the system. 5.2.3.1.1.2 Boiler cold cleanup blow Boiler cold cleanup blow is performed from the BFP booster pump system through the blow valve at a feedwater flow of approximately 25% economical continuous rating (ECR). Boiler cold cleanup blow completion is judged based on the water quality criteria established by the boiler manufacturer. 5.2.3.1.1.3 Boiler cold cleanup circulation After the completion of the boiler cold cleanup blow the storage tank drain system is switched from the blow line to the condenser recovery line, and the water quality is improved while passing through the demineralizer.

5.2.3.1.2 Boiler light-off preparation 5.2.3.1.2.1 Feedwater system In supercritical pressure once-through boilers, since two-phase flow region exist in the evaporating tube under the subcritical pressure condition during the start-up operation, there is a limitation of the minimum mass velocity of water to prevent the tube metal temperature rise due to the deterioration of the tube surface heat transfer. Normally, it is managed with the minimum feedwater flow, and a minimum feedwater flow equivalent to 25% ECR is setting. In preparation for boiler light-off, start motor-driven BFP (M-BFP) to secure a minimum feedwater flow rate of 25% ECR (feedwater flow 5% and recirculation flow 20%). 5.2.3.1.2.2 Air and flue gas system and furnace purge AH, IDF, FDF, and other auxiliary equipment are activated to perform furnace purge. In order to prevent the explosion in the furnace of the boiler due to residual unburned gas the furnace and the flues must be purged at a predetermined airflow before the boiler is lighted-off. In NFPA 85 (National Fire Protection Association, Boiler and combustion systems hazards code) the furnace purge of the coal-fired boiler is specified as follows: 1. Purge rate airflow shall not be less than 25% maximum continuous rating (MCR) and greater than 25% MCR.

Figure 5.30 Example of unit start-up process (cold start-up). Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [4].

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Figure 5.31 Example of steam and water system. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [4]. 2. Completion of the boiler enclosure purge shall require a minimum of 5 minutes and at least five volume changes of the boiler enclosure.

Based on the above, a furnace purge of 5
10 minutes is usually performed at an airflow rate of 30% MCR. After the furnace purge is complete, charge the electrostatic precipitator. 5.2.3.1.2.3 Fuel system In-service fuel system for start-up (light oil or heavy oil) and perform the leak check of the system. In the leak check, fuel is charged up to a specified pressure or more to the burner inlet valve and the ignitor inlet valve around the burner, then the fuel shut-off valve is closed and contained, and the pressure drop amount in a fixed time judges success or failure. If the leak check fails,

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identify and repair the leak location, perform the furnace purge again, and leak check again. 5.2.3.1.2.4 Master fuel trip reset When the following conditions are met, the master fuel trip (MFT) is reset, the fuel shut-off valve is opened, and light-off preparation is completed. 1. Furnace purge completed 2. Feedwater flow normal 3. Fuel leak check completed (for ignitor and start-up)

5.2.3.1.2.5 Others Before light-off, confirm that the drain trap of the burner atomize steam (or air) system operates normally and there is no stagnation of drain. If the boiler has heavy oil system, start heavy oil warming. Then, the boiler start mode is selected, and the fuel program and the start-up bypass valve/drain valve control are determined according to the start-up mode. Table 5.2 shows an example of determination of the start-up mode.

5.2.3.1.3 Boiler light-off After the boiler is ignited the combustion status is confirmed by the furnace TV, frame scanner output, and visual inspection of the furnace. If there is any abnormality in combustion, check the burner wind box inlet damper position, wind box
furnace differential pressure, burner inlet pressure, etc. It is safer to use an ignitor until the number of burners used increases and the temperature in the furnace rises and the combustion state becomes stable. Also, in order to ensure stable combustion, the minimum airflow is set, which is usually 30% MCR. Since the furnace purge air volume and the minimum airflow described above are different in purpose, they can be set separately. Special attention should be paid to cold start-up, in particular, since splashing of the oil mist due to poor spray of the burner/ignitor or excessive air ratio leads to AH fire. During start-up, be aware of changes in AH outlet gas temperature, and if a fire occurs, stop the boiler immediately and extinguish it.

5.2.3.1.4 Boiler hot cleanup The scale of the inner surface of the furnace increases in elution amount as the internal fluid temperature rises, but it turns to adhesion at a certain temperature or Table 5.2 Example of boiler start-up mode judgment. Operation mode (shut-down time)

Metal temperature on inner surface of steam separator

Cold (168 h) Warm 1 (56 h) Warm 2 (32 h) Hot (8 h) Very hot (2 h)

Lower than 170 C 170 C
197 C 197 C
265 C 265 C
298 C Higher than 298 C

Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [4].

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higher. Thus, the optimum temperature for hot cleanup is determined, which is usually around 150 C at the furnace outlet. In cold start the fluid temperature at the furnace outlet is raised to the hot cleanup target temperature, and after reaching the target temperature, the fuel flow is reduced to adjust the temperature to the target value. The hot cleanup usually complete in approximately about 2 hours. The criteria of water quality at hot cleanup are determined by the total iron concentration . Although the temporary deterioration of the water quality during hot cleanup is dealt with by circulation pump (CP) blow, when the water quality does not improve, the boiler may be shut down and restarted for cold cleanup.

5.2.3.1.5 Boiler pressure and temperature rise The pressure and temperature of the boiler are raised to target the steam conditions at the start of the turbine determined by the start-up mode of the turbine. 5.2.3.1.5.1 Limit target at start-up During start-up of the boiler, adjustment of the fuel flow and position adjustment of the start-up bypass valve and the steam system drain valve are performed in order to complete the pressure and temperature rise within the target time while observing the following limit values. 1. The furnace outlet gas temperature; around 560 C For the purpose of RH protection (burnout prevention) during the period when steam is not flowing into the reheat steam system (after starting the turbine, until the specified steam flows), the gas temperature at the RH inlet is monitored by the retractable thermometer. 2. Fuel flow; less than 20% MCR Same as (1). 3. Temperature rise rate; less than 220 C/h The temperature rise rate at the outlet of the steam separator and the SH is monitored for the purpose of relieving the thermal stress of the boiler thick section.

5.2.3.1.5.2 Adjustment of fuel flow Boiler start-up time and main steam temperature are adjusted to the turbine start-up condition by the fuel program for each start-up mode. 5.2.3.1.5.3 Feedwater flow and storage tank level control During temperature and pressure rise, constant operation is performed at the minimum feedwater flow equivalent to 25% ECR. The ratio of feedwater/recirculation is 5%/20%, and the recirculation flow gradually decreases with an increase in the boiler evaporation rate. After a certain period of time after the boiler is lighted-off, fluctuations in the storage tank level and fluctuations in the feedwater flow occur due to swelling, so these need to be monitored by the operator. Swelling means that local boiling (sudden boiling) caused by sudden heat input to the burner zone due to ignition and sudden volume expansion by the boiling causes the fluid on the downstream side to push into the storage tank and the water level in this tank rises rapidly. Also, after the level rise, the level suddenly drops due to the inflow of the vapor phase, and the recirculation flow rate suddenly decreases, so the feedwater flow decreases transiently. Swelling varies to some extent depending on boiler banking conditions, and special attention must be paid during warm and hot start-up. If swelling is severe,

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it can be mitigated by slowing the increase in fuel input after ignition. In addition, the boiler pressure after ignition starts to rise in earnest after the end of swelling. 5.2.3.1.5.4 Operation of drain valve and star-up bypass valve Decide the operation of the SH drain valve and start-up bypass valve for the purpose of reliable warming and drainage of the SH system, ensuring sufficient steam flow, shortening the start-up time (early establishment of turbine start-up conditions). The operation overview for the drain valve and start bypass valve is shown in Table 5.3. Refer to Fig. 5.31 for the valve symbol and start-up system. 5.2.3.1.5.5 Temperature rise/pressure rise completed When the main steam pressure reaches a specified value (e.g., 8.5 MPa), the boiler shifts to pressure control using a turbine bypass valve (TB valve) or boiler start-up extraction valve. After the pressure rise is completed, the auxiliary steam is switched from auxiliary boiler or other unit supply to boiler supply. When the main steam temperature reaches the turbine start target temperature, the temperature rise/pressure rise is completed. In cold start the fuel input may be reduced after the pressure rises so that the turbine thermal stress does not increase after the turbine start due to excessive rise in the main steam temperature.

5.2.3.1.6 Turbine start-up, acceleration, and synchronization preparation The turbine starts when the turbine start-up conditions are established. If the fuel flow is reduced during cold start-up, the fuel is increased by an amount corresponding to the required steam flow rate accompanying turbine acceleration. Confirm that the ash handling system, desulfurization system, and SCR system have been started or are in standby in preparation for the coal in-service after synchronization. SCR ammonia starts injection when the SCR inlet gas temperature exceeds the specified value. If coal on the feeder belt is being discharged, place the coal on each coal feeder belt.

5.2.3.1.7 Synchronization/load up (I) After synchronization, start-up the coal air system in preparation for coal input. During the load increase up to 20% ECR, the main steam pressure is controlled by the TB valve, and the fuel increases according to the start-up program. The lowpressure/high-pressure feedwater heater is serviced in during the load increase, but the fuel program is programed taking into account the main steam pressure drop for the extraction. The feedwater flow is constant at a minimum value equivalent to 25% ECR, but the feedwater/recirculation ratio gradually decreases as the boiler evaporation increases. During the load increase, the first stage of the coal burner is lighted-off. Coal burner light-off permission is judged by whether ignition energy is sufficient and is based on conditions of ignition source (ignitor or adjacent burner) and combustion atmosphere (furnace wall temperature, combustion air temperature, boiler load, etc.). In addition, it is necessary to allow for the time required for pulverizer warming before the coal in service.

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Table 5.3 Examples of operating description for various drain valves and start-up bypass valves at start-up. Valve symbol

Valve name

Operation

EC valve

Boiler start-up extraction valve

TB valve

Turbine bypass valve

D1

Primary SH inlet drain vale

D2

Final SH outlet drain valve

D3

Main steam drain valve

Used at hot/very hot start-up. Open after the end of swelling phenomenon. This valve is used to raise the temperature of SH to the same valve as the main steam, and then switches to the TB valve (EC/TB valve switching). Used to raise the temperature of SH and main steam pipe at cold and warm start-up. This valve is opened when the main steam pressure reaches 0.7 MPa and the swelling is finished. Used to raise temperature and pressure after the EC/TB valve switching at hot and very hot start-up. After the completion of the pressure rise, this valve shifts to the main steam pressure control, and after the start of parallel operation to the network, the pressure control is performed within approximately 20% of the generator output. Opened after the light-off regardless of the start mode. This valve is for drainage and is opened at the minimum position until the pressure rise is completed. Opened after ignition for draining at the cold start-up and closed when the main steam pressure reaches 0.4 MPa. At the hot/very hot start-up, the valve is opened or closed in conjunction with EC valve. Opened when the main steam pressure reaches 0.4 MPa for draining at the cold start-up and closed after the parallel operation to the network. At the warm, hot, and very hot start-up, the valve is opened in conjunction with the TB valve and closed after the start of parallel operation to the network. (Continued)

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Table 5.3 (Continued) Valve symbol

Valve name

Operation

D4

Hot reheat steam pipe drain valve

D5

Cold reheat steam pipe drain valve

BR valve

Boiler recirculation flow control valve

WDC valve

Water separator drain tank (storage tank) level control valve WDC valve rear valve

Opened from the condenser vacuum-up for draining and closed at the generator output around 15% after start of parallel operation to the network. Opened from the condenser vacuum-up for draining and closed at the generator output around 15% after start of parallel operation to the network. Used for recirculation flow control in proportion to the level of water separator drain tank. Fully closed during dry operation. Used for level control of water separator drain tank

W1 W2

Water separator drain blow valve

Used for recovery of the water separator drain to the condenser Used for blowing off the water separator drain out of the boiler

EC valve, Extraction valve; SH, superheater; TB valve, turbine bypass valve, WDC valve, water drain control valve. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [4].

After coal in service (starting the coal feeder), the operator must confirm the operation behavior of the pulverizer (current value, roller lift, vibration, etc.) and whether combustion and ignition are stable. When the actual discharge coal flow from the crusher roller does not match the expected discharge coal flow for control, care must be taken because the main steam pressure fluctuates due to fluctuations in the actual fuel input. Temporary changes in main steam pressure are absorbed by pressure control using a TB valve. Since the NOx at the boiler outlet rises after coal injection, pay attention to the operation of SCR ammonia injection control. After reaching about 20% ECR load, switch the boiler feed pump from M- to turbinedriven BFP (T-BFP). After that, the unit auxiliary system (station power) is switched from the start-up transformer to the unit transformer.

5.2.3.1.8 Load up (II) Increase load up to 50% ECR. As the load increases, the TB valve is fully closed, and the main steam pressure control shifts to water
fuel ratio control. The TB valve stands by with highpressure relief (override) control. In the boiler condition the recirculation flow gradually decreases and becomes the once-through state. At this point the control mode also shifts from the wet mode to the dry mode (i.e., one-through control). After

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shifting to the dry mode, pay attention to the main steam pressure deviation and the degree of superheat at the steam separator inlet, and check the balance between the feedwater flow and the fuel flow. In particular, since the main steam pressure is increased during the sliding pressure mode from around load 30% ECR, pay attention to the BID and the water
fuel ratio. As the load increases, the second and third stages of ignition of the coal burner are performed sequentially. After the second stage ignition of the coal burner, the fuel control shifts from the start-up oil (e.g., heavy oil) master to the mill (pulverizer) master. Check the combustion condition and the operation condition of the pulverizer, and if there is no abnormality, after lighted-off the third stage of coal burner, shut down all start-up oil burners and shift it to coal-fired. The airflow increases from the minimum airflow (usually 30% MCR) according to the program corresponding to the fuel demand. In particular, pay attention to the ECO outlet O2 and raise the air
fuel ratio if O2 decreases. During the load increase, the second T-BFP is in service.

5.2.3.1.9 Load up (III) Increase load up to 100% ECR. The coal burners are lighted-off sequentially as the load increases. When the load reaches 100%, the operator performs the load dispatching ferry.

5.2.3.2 Boiler shutdown There are turbine normal shutdown and turbine forced cooling shutdown as the shut-down methods until desynchronization. Turbine forced cooling shutdown is different from normal shutdown only in the feature that the main steam temperature/reheat steam temperature is lowered from the normal set point according to the load down and the main steam pressure set higher than usual. The basic operation of the boiler is not different from normal shutdown. There are boiler hot banking shutdown and boiler forced cooling shutdown as the boiler shut-down methods after desynchronization. Fig. 5.32 shows the overview unit shut-down process.

5.2.3.2.1 Normal shutdown Once the unit stop schedule is determined, heavy oil warming and steam AH inservice, etc. are performed in accordance with the scheduled load-down time. Auxiliary steam is prepared to be supplied from other unit or auxiliary boiler. When the load drop starts, the coal burners are shut down sequentially as the fuel flow decreases. From around load 95% ECR the main steam pressure also drops according to the sliding pressure program. In particular, pay attention to the balance of feedwater/fuel/air [boiler input demand (BID), water
fuel ratio, air
fuel ratio]. The start-up burners are lighted-off sequentially with the load 50% ECR or less. The steam separator drain tank level rises around load 25% ECR, and boiler condition switches to dry/wet when BCP starts. The load reaches 20% ECR, and after confirming that the shift to oil-only firing has been completed and that the unit auxiliary system (station power) switching

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Figure 5.32 Unit shut-down process (turbine normal shutdown). Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [4].

(change from unit transformer to start-up transformer) has been completed, the load is reduced to the desynchronization target value (5% ECR). When the load reaches the target value for desynchronization, the load is desynchronized, and then the turbine trips. After confirming that the auxiliary steam has been switched to the other unit or auxiliary boiler, shut down all oil burners. When the burner purge is completed after the final burner is shut down, the MFT operates and confirms that all fuel has been shut off. After the MFT operation, the furnace purge (after purge) is performed for 5 minutes.

5.2.3.2.2 Shut-down mode after desynchronization 5.2.3.2.2.1 Boiler hot banking shutdown In order to minimize the boiler heat loss after the MFT is activated and the furnace purge is completed, it is necessary to contain the air/flue gas system and the water/steam system in preparation for restart. The continuation operation auxiliary equipment are the air preheater, GR fan turning device, frame scanner/TV cooling fan, and oil pump for fan cooling. Stop the boiler recirculation pump. Confirm that the SH/main steam drain valve and start-up bypass valve are closed. The feedwater system maintains the vacuum and performs low-pressure cleanup circulation. Check the drop in boiler pressure and steam temperature during hot banking. If the drop is abnormally fast, check for leaks in the start-up bypass valve and SH drain valve. 5.2.3.2.2.2 Boiler forced cooling shutdown As a safety measure, performing boiler-related inspection work or periodic inspection work, as well as turbine-side work, the boiler is forced cooling and shutdown.

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After the unit is desynchronized, the auxiliary equipment for air/flue gas system continues to operate. The airflow increases to about 50%. The feedwater system starts the BCP after starting the M-BFP and secures the minimum feedwater flow. Normally, the distribution is 5% feedwater/20% recirculation for 25% feedwater flow, but as the boiler cools down, the recirculation flow is decreased to increase the cooling effect. The steam system opens the main steam/SH drain valve, releases steam, and depressurize. The position of the drain valve is adjusted according to the boiler pressure. The main steam drain valve connected to the condenser is fully closed when the boiler pressure is 0.2 MPa or less to prevent air suction. Completion of boiler forced cooling is targeted at the steam separator inlet fluid temperature of 90 C or less, but the target temperature varies depending on the purpose of forced cooling (contents of the outage work). After completing the forced cooling, stop the auxiliary equipment of the air/flue gas system and the water supply system, and break the condenser vacuum.

5.2.4 Partial load operation/sliding pressure (variable pressure) operation 5.2.4.1 Partial load operation of sliding pressure once-through boiler In the past, coal-fired thermal power plants have been centered on constant load operation in high-load zones as the base power source. However, with the introduction of renewable energy in recent years, in order to maintain a stable power system (balance between supply and demand), coal-fired power plants are also required to improve the load adjustment capability of partial load operation needs. For this reason, sliding pressure operation is often applied to meet these needs. The boiler type of the supercritical pressure plant introduced in the early stage is a constant pressure once-through boiler. Supercritical pressure boilers have high plant efficiency due to high steam conditions, and once-through boilers have a high-load change rate due to the small amount of water retained. On the other hand, the system configuration and start valve operation for pressurizing to the supercritical pressure at the start are complicated. In contrast, the feature of the sliding pressure once-through boiler, which is the mainstream in current electric utility thermal power plant, include the following points, and has an excellent function as intermediate load thermal power. 1. Good partial load efficiency. 2. Longer material life due to lower pressure at partial load. 3. Since the feedwater pressure can be reduced with partial load, the power of the feedwater pump can be reduced. 4. Since the temperature is high even at partial loads, the start-up time after shutdown can be shortened.

Table 5.4 compares the features of the constant pressure once-through plant and the sliding pressure once-through plant.

Table 5.4 Comparison the constant pressure and the sliding pressure once-through boiler plant. Constant pressure once-through plant

Sliding pressure once-through plant

Main steam pressure (PT) is constant and the load (MW) depends on the CV position. The constant pressure once-through plant is superior to the sliding pressure once-through plant in terms of load followability.

The load (MW) depends on the main steam pressure (PT) because the CV position is constant in the sliding pressure area. The restriction loss of the CV is small, and the plant efficiency is superior to the constant pressure once-through plant.

Pressure at each load

Main steam pressure and turbine control valve (CV) position

Relation between load, main steam pressure and CV position [MW] 5 α 3 [PT] 3 [CV position] α: coefficient

MW, load or output; PT, pressure. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society [5].

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In steam power plant, the load adjustment is performed by changing the steam flow by the turbine control valve (CV) in constant pressure operation, On the other hand, the sliding pressure operation is performed by changing the steam pressure with the steam flow (CV position) being almost constant.

5.2.4.2 Challenges of sliding pressure operation Contrary to the above merits, the boiler control technology has the following challenges in the sliding pressure operation: 1. The fluid temperature in the vicinity of the furnace water wall outlet changes to about 300 C
400 C
450 C due to the sliding pressure operation, and thermal stress is generated in thick parts such as steam separators and storage tank. Further, in order to change the fluid temperature in the water wall, it is necessary to similarly change the metal temperature of the relevant part of the water wall. 2. Over/under pumping is necessary because the density of the fluid retained in the boiler changes due to sliding pressure operation. 3. Due to the increase/decrease in heat retained by metal related to item 1 and the increase/ decrease in retained fluid related item 2, over/under firing during load changes increases significantly compared to constant pressure boilers.

As is clear from the above issues, the key to realize good operation characteristics in middle-load thermal power plant is boiler heat input control, and it is necessary to supply sufficient fuel for the transient heat quantity of the boiler. Especially in the case of coal-fired boilers, it is difficult to measure the fuel flow at the burner inlet, in contrast to oil/gas-fired boilers. And it must be adjusted through a pulverized coal mill with a large excess/deficiency delay in fuel flow. For this reason, various considerations are required to achieve good boiler heat input control. When turbine load control is performed by transformer operation, the load change that matches the boiler time constant until the boiler pressure changes by changing the boiler input amount when the load changes is stable as a plant. Therefore the primary steam pressure set value and the control valve opening command may be provided with a primary or secondary delay time corresponding to the boiler time constant. In addition, the boiler time constant needs to be compensated for the load change taking into account the through-speed during the load change.

5.2.5 Remarks In recent years, along with the introduction of renewable energy, many sliding pressure once-through boilers have been adopted in coal-fired power plants to cope with intermediate load operation. Since the sliding pressure once-through boiler has larger enthalpy and steam temperature fluctuations than the constant pressure once-through boiler, the fluctuation range of fuel and feedwater tends to increase as the operation amount of the boiler in order to obtain good pressure followability. These tendencies become noticeable in the case of coal-fired boilers with larger furnace dimensions. In order to obtain good dynamic characteristics as intermediate-load operation thermal power, precise correction to the combustion amount demand is necessary and important. Therefore the

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water
fuel ratio control is the most important position in the sliding pressure oncethrough boiler. The main STC by improved water
fuel ratio control was developed and introduced in this chapter. In the future, it is expected that the load-adjusting capability will be required more actively with coal-fired boilers. For this reason, system configuration and control improvements are being actively studied, focusing on lowering the minimum load and responding to high-speed load changes.

Nomenclature Δ ΔMSP ΔMST ΔRST , . Σ A AFC BFP BID CV ELD F(X) GF GR H/A LC LFC MSP MWD P PC PI SH T TC

difference main steam pressure deviation main steam temperature deviation reheat steam temperature deviation low selecting high selecting high/low limiting summing variable signal generator automatic frequency control boiler feedwater pump boiler input demand turbine control valve economic load dispatching control nonlinear function governor free gas recirculation manual-automatic selector level controller load frequency control main steam pressure load demand pressure pressure controller proportional integrator superheater temperature temperature controller

References [1] Thermal and Nuclear Power Engineering Society, Thermal power station—master plan and accessories, Therm. Nuclear Power 64 (9) (2013) 34
52. [2] Thermal and Nuclear Power Engineering Society, Instrumentation and control—boiler control, Therm. Nuclear Power 33 (5) (1982) 60
65.

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[3] K. Domoto, T. Ishiwaki, H. Sanda, S. Miyake, T. Takenouchi, K. Takei, New functions and technologies of steam power plant which are expected to change for recent power grid necessity, Mitsubishi Heavy Ind. Tech. Rev. 56 (3) (2019) 1
10. [4] Thermal and Nuclear Power Engineering Society, Operation of thermal power station, Therm. Nuclear Power 66 (7) (2015) 40
46. [5] Thermal and Nuclear Power Engineering Society, Automatic boiler control, Therm. Nuclear Power 56 (12) (2005) 65.

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Shigehiro Shiozaki1, Takashi Fujii1, Kazuhiro Takenaga1, Mamoru Ozawa2 and Akira Yamada3 1 Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan, 2Kansai University, Osaka, Japan, 3Mitsubishi Heavy Industries, Ltd., Nagasaki, Japan

Chapter Outline 6.1 Gas turbine combined cycle power generation 305 6.1.1 6.1.2 6.1.3 6.1.4 6.1.5

Overall feature of combined cycle plant 305 Thermodynamic principle of gas turbine combined cycle power plant 309 Types of gas turbine combined cycle power plant 312 Features of gas turbine combined cycle power plant 315 Heat recovery steam generator 316

6.2 Pressurized fluidized-bed combustion boiler 325 6.3 Integrated coal-gasification combined cycle 326 6.3.1 6.3.2 6.3.3 6.3.4 6.3.5 6.3.6 6.3.7 6.3.8 6.3.9 6.3.10 6.3.11

Overview of integrated coal-gasification combined cycle development in the world 326 Gas turbine combined cycle system 327 Benefits of integrated coal-gasification combined cycle 328 Environmental advantage 329 Development history of air-blown integrated coal-gasification combined cycle 331 Development history of oxygen-blown integrated coal-gasification combined cycle 332 Gasifier facilities 332 Gasifier 334 Char recycle system 336 Gas clean-up system 338 Combined cycle system 341

References

6.1

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6.1.1 Overall feature of combined cycle plant Combined cycle power generation drastically improves thermal efficiency compared with conventional steam power generation by combining gas turbine (GT) cycle and steam turbine (ST) cycle. Thermal energy flow to GT, and then ST, output from cycles, and heat release to the enviroment are represented by U0, UG, LG, LS, QG and QS, respectively, then the Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00006-0 © 2021 Elsevier Inc. All rights reserved.

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Figure 6.1 Energy balance of combined cycle.

energy flow of combined cycle is simplified as shown in Fig. 6.1. The thermal energy input to GT, U0, GT output, LG, gives thermal efficiency. ηG 5

LG U0

(6.1)

The exhaust energy from GT is given by: U0 2 LG 5 ð1 2 ηG ÞU0

(6.2)

Assmuing all the amount of this energy is absorbed by steam cycle, and set the thermal efficiency of steam cycle, ηS , then the output of steam cycle is given by: LS 5 ηS ð1 2 ηG ÞU0

(6.3)

The total output of the combined plant is given by: LG 1 LS 5 ηCC U0 5 ηG U0 1 ηS ð1 2 ηG ÞU0

(6.4)

Then, the following simple relationship for the efficiency of combined cycle is obtained: ηCC 5 ηG 1 ηS 2 ηS ηG

(6.5)

Based on this equation and the data from Gas Turbine World 2010 Handbook [1], thermal efficiencies of gas and steam cycles are estimated as shown in Fig. 6.2. For example, when the steam cycle efficiency is set at 30%, and GT side at 40%, then the total efficiency becomes 58%. When combined power plant is designed, it is important to consider the division of power generation between GT and ST. Mostly this division is determined by the performance of selected GT. The output ratio of GT against total output of power plant is exemplified in Fig. 6.3. In a current large output plant the ratio is about

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Figure 6.2 Thermal efficiency of gas and steam cycles and of total plant. Source: Data from Gas Turbine World 2010 Handbook, Pequot Pub., Southport, 2010.

Figure 6.3 Output ratio of combined cycle plant. Source: Data from Gas Turbine World 2010 Handbook, Pequot Pub., Southport, 2010.

0.65. Such practical data from the market may be helpful in the planning of combined cycle plant. Then the improvement in thermal efficiency of the combined cycle plant is highly dependent on the efficiency of GT. Fig. 6.4 shows the relationship between GT inlet temperature (TIT) and power generation efficiency. At the beginning of combined cycle power generation, the cycle efficiency with the 1100 C class GT was about 47%, and current 1600 C class GT has realized over 60%. When a 1700 C class GT, now developing, is adopted, higher efficiency is expected. Fig. 6.5 shows the trend of TIT. About 20 years were needed for the initial development from 1100 C class GT, and the 1500 C class GT was put in the market in the beginning of 2000s. In order to increase TIT, it is essential to improve the cooling technology for blades and shell adjacent to the gas passage at very high temperature, and also to develop heat resistant materials. In addition, the improvement was extended to introduce surface coating for oxidation corrosion resistance and heat shielding. Thermodynamic fundamentals on combined cycle plant are successively described in the following sections.

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Figure 6.4 GT turbine inlet temperature and GTCC efficiency. GTCC, gas turbine combined cycle; GT, gas turbine. Source: Data from T. Matsumoto, Y. Nakajima, M. Sugimoto, R. Okura, F. Takayama, N. Suzuki, Overview of combined cycle power plants, Therm. Nucl. Power, 61 (5) (2010) 405423.

Figure 6.5 Trend of GT turbine inlet temperature. GT, Gas turbine. Source: Data from T. Matsumoto, Y. Nakajima, M. Sugimoto, R. Okura, F. Takayama, N. Suzuki, Overview of combined cycle power plants, Therm. Nucl. Power, 61 (5) (2010) 405423.

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6.1.2 Thermodynamic principle of gas turbine combined cycle power plant Prior to the discussion of thermodynamic principle of GT combined cycle (CC) power generation, each power generation system composing gas turbine combined cycle (GTCC) is described in the following [24].

6.1.2.1 Steam power generation The steam power generation cycle, being the mainstream of conventional thermal power generation, is a thermal engine based on Rankine cycle using water and steam as working fluid. The basic structure and cycle diagram of the steam power generation cycle are shown in Figs. 6.6 and 6.7, respectively. In a thermal engine, as the maximum temperature of the working fluid is higher and the minimum temperature is lower, the ratio of work to heat input, that is, thermal efficiency, increases. Seawater and/or air is effectively used as a lowtemperature heat source. On the other hand, although a high-temperature heat source of 1000 C2000 C is obtained by combustion of fossil fuel, the working fluid temperature in the heat exchange process remains at most 550 C650 C owing to the thermal strength limit of materials, that is, heat exchange is conducted under very large temperature difference between high-temperature heat source and water or steam as the working fluid. This large temperature difference is a cause of severe irreversibility, that is, large entropy generation takes place. In order to improve thermal efficiency, the current supercritical pressure plant of unit output 1000 MW employs, in general, reheat and regeneration cycle, and thus the thermal efficiency reaches about 45%. However, such an improvement of efficiency seems almost saturated, and alternative approach is needed in order to drastically increase thermal efficiency.

Figure 6.6 System of steam power cycle.

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Figure 6.7 Steam power cycle diagram.

Figure 6.8 System of gas turbine.

6.1.2.2 Gas turbine power generation GT cycle is a so-called Brayton cycle, and the basic configuration of and cycle diagram power generation system with air and combustion gas as working fluid are shown in Figs. 6.8 and 6.9, respectively. In this cycle the atmospheric air is first flown through inlet manifold, and compressed air [at high pressure (HP)] by a compressor is supplied to combustor with fuel for combustion, and the turbine is driven by high-temperature combustion gas. The high-temperature combustion gas generated in the combustor directly drives the turbine principally without heat exchange, and expands to low pressure (LP) through the turbine. Thus only limited parts are faced to high-temperature gas and are protected by applying intensive cooling technology as well as high-grade materials with excellent heat resistance. Such countermeasures enable effective and economical utilization of thermal energy of high-temperature gas. Conventional cooling has been conducted by using compressed air supplied through and around blades, while advanced cooling technology with steam together with advanced heat resistant materials realized 1600 C class GT, and further improvement of thermal efficiency has been brought about.

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Figure 6.9 Gas turbine cycle diagram.

GT power generation system has features of rapid load change and start/stop because of large output per equipment weight and small heat capacity, and has excellent operability usable for peak load and emergency. However, the temperature of the exhaust gas discharged from the GT is still as high as about 550 C650 C, and utilization of thermal energy of this high-temperature gas is an important issue for effective use of energy.

6.1.2.3 Gas turbine combined cycle power generation GTCC is a system in which GT power generation cycle is applied to hightemperature heat source as a topping cycle, and steam power generation cycle is applied to low-temperature heat source as a bottoming cycle, and extremely high thermal efficiency can be obtained by combining these two cycles. The basic configuration of combined cycle power generation (exhaust heat recovery type) and the cycle diagram are shown in Figs. 6.10 and 6.11. Only in the steam power generation, cycle efficiency is about 45%, while GT combined cycle power generation has cycle efficiency of 58%59% with 1500 C class GT, and over 60% with 1600 C class GT. Such an improvement in thermal efficiency is principally due to the suppression of entropy generation through heat transfer process between high-temperature combustion gas and water tubes by substitution of GT with high compression ratio and high temperature. In principle, a variety of fuels are usable for GT, while considering various problems including ash adhesion, abrasion, and corrosion and emission of pollutant matters to the environment, it is necessary to use clean gas and/or liquid fuel. By introducing gasification and refining process, coal and heavy oil are utilized as a fuel of the GT. Integrated coal-gasification combined cycle (IGCC) is a typical

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Figure 6.10 System of gas turbine combined cycle (heat recovery).

Figure 6.11 Gas turbine combined cycle diagram.

example. In this context, the combined cycle system will become a mainstream as a future thermal power generation system.

6.1.3 Types of gas turbine combined cycle power plant There are various types of combined cycle power generation depending on the equipment composition, and the optimum system is adopted in accordance with the circumstances and operating conditions of the construction site. Here, the types and features of these various combined cycle power generation are briefly explained.

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Here in this section, combined cycle power generation systems are classified focusing on cycle composition and shaft composition.

6.1.3.1 Classification by cycle configuration 6.1.3.1.1 Heat recovery combined cycle The exhaust gas from the GT is introduced into an exhaust heat recovery steam generator (HRSG), and generated steam drives the ST. Although it is the simplest, the highest thermal efficiency is obtained by optimizing the configuration of GT and steam system. The main features are as follows: 1. 2. 3. 4. 5. 6.

Effective utilization of heat source, and the thermal efficiency is high. The higher the combustion temperature is, the higher the thermal efficiency becomes. High output ratio of the GT Short start-up time. Simple configuration and simple control. Independent ST operation is impossible.

6.1.3.1.2 Full fired heat recovery combined cycle Much amount of oxygen remains in the GT exhaust gas, and it is utilized as combustion air for a normal steam power boiler. The GT exhaust temperature is high, and thus the air preheater for the boiler is not needed. Instead, feedwater heater is used for recovering the thermal energy from boiler exhaust gas. This obstructs the regeneration cycle, and thus the plant efficiency is improved by reducing O2 quantity in the boiler exhaust by consuming O2 through combustion in the HRSG. System configuration is shown in Fig. 6.12. The main features are as follows: 1. Suitable for repowering of an existing boiler. 2. High output ratio of the ST. 3. System and operation control become complicated.

Figure 6.12 System of gas turbine combined cycle (full fired heat recovery).

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4. Independent ST operation is possible by installation of an additional forced draft fan. 5. A boiler forced draft fan is required when remained O2 in GT exhaust gas is too low. 6. The maximum thermal efficiency is expected when the steam power cycle makes full use of thermal energy of GT exhaust gas.

6.1.3.1.3 Supplementary fired heat recovery combined cycle This system is similar to the exhaust heat recovery cycle, while the exhaust gas temperature is raised and the output of the ST is increased by injecting fuel into the GT exhaust gas. The thermal energy of auxiliary fuel is not effectively utilized; the system efficiency does not reach the level of optimally designed waste heat recovery cycle. This system is suitable for the case where the GT and the steam cycle are not matched well. System configuration is shown in Fig. 6.13. The main features are as follows: 1. When the amount of auxiliary fuel is large, the thermal efficiency becomes lower than that of the exhaust heat recovery system. 2. When the amount of auxiliary fuel increases, the output ratio of the ST increases. 3. Independent operation of the ST is impossible. 4. The start-up time is slightly longer than that of the exhaust heat recovery system. 5. Warm water discharge increases with an increase in the amount of auxiliary fuel .

6.1.3.2 Classification by shaft configuration Combined cycle power generation plants are classified into two main types according to their shaft configuration, i.e. multishaft and single-shaft types as shown in Fig. 6.14.

6.1.3.2.1 Multishaft combined cycle In a normal heat recovery cycle, the output ratio of GT to ST is approximately 2:1. Therefore the steam generated from multiple GTs and HRSGs is collected and

Figure 6.13 System of gas turbine combined cycle (supplementary fired heat recovery).

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Figure 6.14 System configuration comparison of multishafts and single shaft.

guided to one large ST, thereby the efficiency of ST is improved by the scale merit. In a partial-load operation, however, the thermal efficiency becomes slightly lower.

6.1.3.2.2 Single-shaft combined cycle This system is provided with one HRSG and one ST for one GT. Shafts of GT and ST are mechanically connected, and construction cost and arrangement space are reduced by using a common generator. The thermal efficiency at the rated load is slightly lower than the multishaft type because of the smaller size of the ST, but higher thermal efficiency than that of the multishaft type is obtained even at the partial load by reducing the number of operating units. This system has advantages in short plant starting time due to the small heat capacity of ST, and independent execution of periodic inspection for each shaft since there is no interference between shafts.

6.1.4 Features of gas turbine combined cycle power plant 6.1.4.1 Advantage of gas turbine combined cycle power plant There are several advantages as mentioned above. Here the advantages are summarized as follows: 1. High efficiency 2. Simple system When the steam control valve at the inlet of ST is fully opened and the ST is operated in variable pressure according to the GT load, the plant is controlled only by GT inlet airflow and fuel flow. In this case the control logic becomes simple and the partial load characteristics of the steam system are improved by the variable pressure operation. However, when a fuel heating system using feed water is introduced for further efficiency improvement, or when the high-temperature part of the GT is cooled by steam, new interferences occur between the GT and the steam cycle. 3. Efficient load response Since the weight of the component per output is small, the heat capacity is naturally small, and therefore, the response to the load change becomes excellent. Typically load change rate is about 5%/min. Necessary steam flow rate and time for warming up at

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starting are small, and therefore the start-up time is short, about 1 hour (after 8 hours of shutdown). 4. Environmental performance Due to the high thermal efficiency, the exhaust gas volume flow rate per unit output is small, and since the output of steam cycle is about 1/3 of the total output, warm drainage can be drastically reduced. NOx in the exhaust gas is reduced by installing denitration equipment using ammonia into the exhaust heat recovery boiler. 5. Small footprint The GT has a high-output density and a small required arrangement area per output. Especially for single-shaft configuration, since the common generator for GT and ST is used, and HRSG are arranged in a straight line, so that many shafts can be arranged in a limited space.

6.1.4.2 Disadvantage of gas turbine combined cycle power plant Combined cycle plants have some disadvantages as shown below. Therefore, the optimum cycle should be selected considering the situation of each plant. 1. Low efficiency at partial load operation At partial loads operation the thermal efficiency of the combined cycle becomes lower. As the multiple combined cycle units are usually located in the power plant site, high partial load performance is achieved as a whole plant by starting and stopping operation of each axis. 2. Dependence of generated power on ambient temperature The power output of GT decreases depending on a decrease in the mass flow rate of air in accordance with the atmospheric temperature rises. This disadvantage is typically observed in a daytime in summer when the electric power demand peaks. Thus in the current GTCC an intake cooling system is installed as the countermeasure for this disadvantage. 3. Restriction to fuel types Since the GT is driven by introducing combustion gas directly into the GT, it is impossible to use fuel containing components that corrode metals and dust components that cause wear. Therefore the fuel for GT is normally confined to such as natural gas and refined liquid fuel. However, pressurized fluidized-bed boiler combined cycle plants (PFBC) and IGCC plants equip with dust-removing and desulfurizing facilities of produced gas, and thus variety of fuels, especially coal, is utilized as a fuel of combined cycle power generation plant without significant impact to the environment.

6.1.5 Heat recovery steam generator A HRSG is one of the major pieces of equipment in a GTCC power plant that leads to improvement in the thermal efficiency and reduction of CO2 emissions. An HRSG is a kind of heat exchanger that recovers heat from the exhaust gases of the GT. The recovered heat is utilized for steam generation being a source of a power-generating ST. In addition, selective catalyst reduction (SCR) equipment is installed inside the HRSG for reducing NOx released into the atmosphere [5].

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6.1.5.1 Feature of heat recovery steam generator Spiral finned tubes are applied to the HRSG heat-transfer tubes, considering a large amount of exhaust gas from GT, and relatively low temperature, that is, approx. 600 C700 C. Fig. 6.15 shows typical spiral finned tube, that is, solid finned tube and serrated finned tube. By using such finned tubes the number of heat-transfer tubes and installation area is reduced. The heat-transfer tubes are installed inside of casing, consisting of steel plated and insulation. Type of HRSG is classified by the pressure level, with or without reheat system, the direction of exhaust gas flow. The popular system of large size HRSG is triple pressure reheat type. Figs. 6.16 and 6.17 show the HRSG cross-sections horizontal gas flow type and vertical gas flow type.

6.1.5.2 Technical trend of heat recovery steam generator HRSG is an important equipment for high plant efficiency, high output, high operability, high environmental performance, and high constructability discussed as follows.

6.1.5.2.1 Optimization for water and steam system Large size combined cycle power plants generally use triple pressure with reheat system to achieve high heat recovery performance. HRSG system is divided into three pressure levels: HP, intermediate pressure (IP), and LP. Each pressure system consists of three heat exchangers: superheter, evaporator, and economizer. Fig. 6.18 shows typical HRSG steam/water system for triple pressure reheat type. Feedwater supplied from condenser is heated in the economizer, and then supplied to the steam drum of the natural circulation boiler. The generated steam is superheated in the superheater, and led to ST. Exhaust steam from HP ST is mixed with IP superheater outlet steam and reheated in the reheater. Since HRSG has no feedwater heater, the feedwater temperature is relatively low. Therefore economizer recirculation system and/or economizer bypass system are installed to prevent dew point corrosion at heat-transfer tube surface. The arrangement and specifications of

Figure 6.15 Spiral finned tube. Source: Courtesy MHPS.

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Figure 6.16 Horizontal gas flow type HRSG. HRSG, Heat recovery steam generator.

HRSG heat exchanger section are optimized to satisfy the heat balance requirement of combined cycle power plant.

6.1.5.2.2 High steam temperature condition According to an increase in the exhaust gas temperature from the upgraded GT, steam temperature of HRSG outlet is raised to improve the plant efficiency. The temperature of the latest plant reaches 600 C. The tube materials of the conventional HP superheater and reheater of HRSG are generally 9Cr steel and/or 2.25Cr steel. For 600 C of steam temperature condition, stainless steels like 18Cr material are used. When stainless-steel material is used, it is necessary to take into account material feature like brittleness and thermal expansion. Stainless-steel material has been used since 2013 based on the verifications for finning fabrication, thermal cycle strength, support structure of finned tubes, etc.

6.1.5.2.3 Supplementary firing heat recovery steam generator Supplemental firing HRSG have duct burners inside of the HRSG. Under the high ambient temperature in summer, the output of combined cycle power plant

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Figure 6.17 Vertical gas flow type HRSG. HRSG, Heat recovery steam generator.

Figure 6.18 HRSG steam/water system (triple pressure reheat type). HRSG, Heat recovery steam generator.

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Figure 6.19 Example of supplementary firing.

decreases, because of less density of the compressed air, and ST output decreases due to the vacuum down in the condenser. Supplemental firing in the duct burner makes up the decrease in the output. Fig. 6.19 shows an example of supplementary firing HRSG. Duct burner elements are installed upstream or middle of the HP superheater and reheater section. By supplementary firing, the plant output will increase, while the plant efficiency decreases a little.

6.1.5.2.4 Selective catalytic reduction system SCR system is installed inside of the HRSG casing to remove NOx. Fig. 6.20 shows the installed location of SCR system. SCR catalyst is installed in the area with gas temperature at 300 C400 C. This temperature range is suitable for the reaction of NOx removal. Generally, ammonia is used as the NOx removal chemical, and ammonia injection grid is installed upstream of the SCR catalyst [6]. Fig. 6.21 shows examples of the SCR catalyst, i.e. plate type, and honeycomb type.

6.1.5.2.5 Construction method of heat recovery steam generator Construction methods of HRSG are classified into harp, block, and modular, depending upon shipping configuration. In the harp and block construction methods, tube bundle panels or tube bundle blocks, casing panels, connecting pipe, etc. are assembled on site. Figs. 6.22 and 6.23 show the examples for harp and block construction method. The size and weight of tube bundle blocks and casing panels are optimized considering the transportation limit and site condition, so that the total cost and construction period are minimized. In the modular construction method, the tube bundle, casing, steel

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Figure 6.20 SCR system for combined cycle plant. SCR, Selective catalyst reduction.

Figure 6.21 SCR catalyst. SCR, Selective catalyst reduction. Source: Courtesy MHPS.

structure, piping, walkway, instruments, etc. are assembled as semifinished products in a factory and shipped to the site by barge. Fig. 6.24 shows the examples for modular construction. The work volume and construction period at site can be minimized. Modular weight will be a few

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Figure 6.22 Harp construction method. Source: Courtesy MHPS.

Figure 6.23 Block construction method. Source: Courtesy MHPS.

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Figure 6.24 Modular construction method. Source: Courtesy MHPS.

Figure 6.25 Kawasaki thermal power station units 2-2 and 2-3. Source: Courtesy MHPS.

thousand tons, and modular size will be huge. Hence, the modular construction method requires large pier, wide road, large size barge, etc. for transportation.

6.1.5.3 Example of heat recovery steam generator 1. Kawasaki Thermal Power Station Units 2-2 and 2-3, Japan (see Fig. 6.25) Customer: JERA Co., Inc. GT: MHPS M701J HRSG type: Triple pressure with reheat, natural circulation, with SCR system Steam rate: 480 t/h (HP), 140 t/h (IP), 100 t/h (LP) Steam condition: HP superheater outlet 602 C/15.4 MPa RH outlet 602 C/3.6 MPa LP superheater outlet 252 C/0.7 MPa Start of operation: 2016

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2. Jawa-2 Combined Cycle Power Plant, Indonesia (see Fig. 6.26) Customer: PT PLN (PERSERO) GT: MHPS M701F4 HRSG type: Triple pressure with reheat, natural circulation Steam rate: 310 t/h (HP), 63 t/h (IP), 54 t/h (LP) Steam condition: HP Superheater outlet 582 C/16.0 MPa RH outlet 581 C/3.5 MPa LP superheater outlet 291 C/0.6 MPa Start of operation: 2019

6.1.5.4 Remarks HRSG has been improved in accordance with an increase in capacity and upgrade of GT, which is leading to an increase in the combined cycle plant efficiency. GTCC power plants is the cleanest and highest efficiency power generation system, and further improvement in the plant efficiency contributes to further reduction of carbon dioxide (CO2) emission.

Figure 6.26 Jawa-2 combined cycle power plant. Source: Courtesy MHPS.

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Pressurized fluidized-bed combustion boiler

As described in Section 4.2.5, fluidized-bed combustion is suitable for NOx and SOx reduction owing to the large heat capacity of bed material. In addition, in-bed desulfurization is possible. On the other hand, the heat transfer is conducted still large temperature difference even though relatively low-temperature combustion is possible. This means the thermal efficiency is still suppressed by this large temperature difference. To improve the efficiency, substitution of GT into this large temperature difference, that is, combined cycle, is one of an effective means keeping various merits of fluidized-bed combustion. Typical feature of the pressurized fluidized-bed combustion combined cycle is exemplified in Fig. 6.27. This system consists of the bubbling-type fluidized bed within a pressure vessel, a cyclone separator, GT system of compressor, GT and generator, ST system of ST, condenser, and generator. The pressure of gas in the fluidized-bed combustor is about 0.891.3 MPa. The PFBC plant has high compatibility for environmental and variety of fuel brought about fluidized-bed combustion, and combining with GT system high-efficiency power plant is realized. This is however not an easy task. Coal is a solid fuel and small particles are entrained into combustion gas even after the dust collection devices such as cyclones, which bring about erosion of GT blades. In addition, the furnace of the PFBC plant is installed in a pressure vessel, and therefore fuel supply method needs special consideration, for example, coal-water paste (CWP). This CWP is easily supplied to the pressure vessel via CWP pump, while the fraction of coal and water has a critical importance in its viscosity affecting pumping power and flow through fuel nozzle. If a dry feed is selected, a lock hopper may be substituted to pneumatic conveying line of pulverized coal and limestone with air. When ceramic filter is used for dust separation upstream the GT, blockage may take place. Thus some innovative technologies are needed for dust collection, erosion prevention, fuel supply, and so on.

Figure 6.27 Simplified flow model of PFBC.

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Table 6.1 Scale-up of PFBC.

Bed height (m) Relative bed area (2) Bed pressure (MPa) Bed temperature ( C) Fluidizing velocity (m/s) Gas turbine inlet temperature ( C) Steam pressure (MPa) Steam temperature ( C) Thermal input (MW)

CTF

Tidd

Sporn

3.5 1 1.21.6 860 0.9 790 9.9 532 15

3.2 16 1.2 860 0.9 830 9.2 496 200

3.7 24 1 24a 1.6 860 0.9 830 13.9 566/538 800

CTF, Component test facility. a Twin beds. Source: Data from US Department of Energy, Tidd: The Nation’s First PFBC Combined-Cycle Demonstration, Clean Coal Technology, Topical Report Number 1, 1990.

The first laboratory test started in the late 1960s. In the 1970s fundamental R&D started in Germany, the United States, Alstom Power Co., UK B&W Co., etc. in the 1980s, IEA project of 60 MW pilot plant at Grimthorpe Inst., United Kingdom started, and the United States and West Germany also jointly financed this IEA project. The 40 MW pilot plant in Achen TU, and Alstom 15 MW pilot plant were constructed. In the 1980s US Department of Energy (DOE) project started to construct Tidd PFBC plant, being the first PFBC combined-cycle demonstration plant in the United States in the late 1980s, technology assessment and fundamental R&D stated in Japan, and 199091, Alstom 7080 MWe commercial plant started test operation [7]. A general procedure leading to construct large-scale plant is first starting from a small-scale experimental system, leading to pilot plant, demonstration plant, and finally commercial plant. Just the same manner, the Tidd plant started first as component test facility (CTF) designed by ABB Carbon, operated since 1982. Various component tests were conducted so that the demonstration plant was designed and constructed. The DOE Clean Coal Technology [8] reported the scale-up process as shown in Table 6.1. The integrated test facility CTF was constructed and operated since 1982. The data was reflected to Tidd demonstration plant design which started test operation in late 1989. The commercial plant was first planned with the specification listed in Table 6.1 but was decided not to construct Sporn plant in 1991.

6.3

Integrated coal-gasification combined cycle

6.3.1 Overview of integrated coal-gasification combined cycle development in the world IGCC is a highly efficient power generation system utilizing coal as fuel. The system is not only a combined cycle system like the natural gas firing combined cycle

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but also coupled with a fuel production system by converting coal to syngas fuel. IGCC mainly consists of major components such as a gasifier, a gas clean-up system, and a GTCC system. Large-capacity IGCC systems have a potential of improving power generation efficiency by 10%15%, and reduce CO2 compared with conventional coal-fired steam power systems. The first IGCC plant was constructed in Lu¨nen, Germany and operation started in 1972, while the configuration was not the current system. Gasifier was air-blown Lurgi’s moving-bed type operated at 2.0 MPa. Syngas was supplied to the GT after cleaning and was expanded to 1.1 MPa and then supplied to pressurized boiler. Owing to the complexity of the system, load-following capability was not good, which was mainly because the control technology for two systems was not fully developed at that time. This plant intended first 400 MW, while the maximum net output of the plant was 163 MW. In the United States, a joint project of Energy R&D Administration, Electric Power Research Institute (EPRI), and Commonwealth Edison proposed gasification combined cycle test facility (GCCTF), but complexity of the system configuration and problem in the selected gasifier obstructed the project. In the 1980s the first IGCC based on a traditional GT combined cycle, Cool Water Coal Gasification Program (CWCGP) was constructed at Dagget in the United States and generated net 93 MW output, in which Texaco slurry-fed oxygen-blown gasifier was used. The net thermal efficiency was 29.1% (HHV). This plant was operated from 1984 to 1989 [9]. In the 1990s, not only in the United States but also in Europe successful IGCC plants appeared. Typically, Demokolec project in the Netherlands constructed 253 MW IGCC with Shell’s solid entrained flow type gasifier. The thermal efficiency reached 41.4% (HHV) and was operated from 1994 to 2013. In the United States, Wabash River project, a part of the US DOE’s Clean Coal Technology program, constructed 252 MW IGCC with E-Gas entrained flow type gasifier, and operated in the period 19952016. The thermal efficiency was 38.5% (HHV). Tampa Electric Polk County IGCC was also a successful example, and realized 249 MW for Bituminous coal and 250 MW for pet coke with thermal efficiency 36.5% and 37.5%, respectively, since 1996. Such IGCC projects are conducted worldwide, including India, Sweden, Czech Republic, Spain, and Italy [9], while in this section, discussion on the IGCC development is focused on Japanese projects.

6.3.2 Gas turbine combined cycle system In the framework of thermodynamic cycle for power generation system, IGCC is categorized as a kind of GTCC as shown in Fig. 6.28. In Japan, two types of coal gasification technology, namely, air-blown and oxygen-blown technologies, have been developed, and these gasification processes are leading technology in the world. In line with expectations that the needs for the IGCC system will increase further due to its ability to both effectively utilize coal resources and protect the environment, this system has been gaining attention around the world.

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Figure 6.28 IGCC system configuration. IGCC, Integrated coal-gasification combined cycle.

Figure 6.29 IGCC plant environmental performance. IGCC, Integrated coal-gasification combined cycle.

6.3.3 Benefits of integrated coal-gasification combined cycle IGCC has a lot of benefits. As shown in Fig. 6.29, compared to USC (ultra-supercritical) conventional technology set as a benchmark at 100%, IGCC has achieved higher plant efficiency of 10%15%. Accordingly, it reduces CO2 emission by 10%15%. Ash volume is reduced by 60% because IGCC discharges glassy solid slag instead of fly ash. Circulating water amount is reduced by 30% because IGCC is a combined cycle power plant. Because of the excellent thermal efficiency with low emissions, IGCC is surely an environment-friendly system.

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6.3.4 Environmental advantage IGCC has several environmental advantages of slag, sulfur and water as described in the following. 1. Slag

IGCC produces waste slag as a tradable by-product. In the case of USC, although a part of fly ash discharged from boiler is utilized as a concrete aggregate, most of the fly ash is disposed. On the other hand, all of the slag from IGCC is utilized as a salable industrial byproduct for use of road pavement, construction, and plantation soil as shown in Fig. 6.30. Slag discharged from IGCC has several characteristics as follows: Less ash volume.less than 45% in volume compared with fly ash from steam power save ash disposal facilities and pond Minimum unburned carbon.less than 0.1% in slag, that is, more than 99% of carbon in fuel is converted to synthesis gas No leaching from slag.min. environmental impact 2. Sulfur

IGCC is suitable for application of both gypsum production and sulfuric acid production, dependent on the client’s preferences (see Fig. 6.31). Even when the gypsum produced is disposed, sulfuric acid is more beneficial as a salable industrial byproduct for use of chemical such as fertilizer depending on the clients.

Figure 6.30 Environmental advantage (slag). Source: Courtesy MHPS.

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Figure 6.31 Environmental advantage (sulfur). Source: Courtesy MHPS.

Figure 6.32 Environmental advantage (water).

3. Water

In the case of USC, a large amount of cooling water for condenser is needed for single steam power generation. On the other hand, IGCC is a double power generation system using ST and GT cycles. Because the exhaust heat from GT is recovered in the HRSG for steam generation, an amount of cooling water for IGCC becomes 70% of that of USC as illustrated in Fig. 6.32.

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6.3.5 Development history of air-blown integrated coalgasification combined cycle Fig. 6.33 illustrates an example of air-blown IGCC development history. Mitsubishi Hitachi Power Systems (MHPS) and nine Japanese electric power companies have been working together with Electric Power Development Co., Ltd. (J-POWER) and Central Research Institute of Electric Power Industry (CRIEPI) to develop a more efficient and highly reliable air-blown IGCC, with subsidy funding from the Japanese Government. From 1986 to 1996 the collaborators built and operated a pilot test plant with a coal feed capacity of 200 t/day (corresponding to 25 MWe) in a project entrusted by the Agency for Natural Resources and Energy, and the New Energy and Industrial Technology Development Organization (NEDO). Clean Coal Power R&D Co., Ltd. established in June of 2001, and they have been moving forward with design, fabrication, construction, commissioning and operation of the 250 MW Nakoso IGCC demonstration plant (hereinafter called the “IGCC demonstration plant”). As a result, the demonstration plant successfully completed its demonstration operation and is now operating as the commercial plant Nakoso #10 after taken over by Joban Joint Power Company in 2013. Based on the success, MHPS is now planning the 500 MW class commercial plants.

Figure 6.33 History air-blown IGCC/gasification technology development of MHPS. IGCC, Integrated coal-gasification combined cycle; MHPS, Mitsubishi Hitachi Power Systems. Source: Courtesy MHPS.

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6.3.6 Development history of oxygen-blown integrated coalgasification combined cycle The development of oxygen-blown gasification systems has been carried out since the 1980s in Japan (see Fig. 6.34). At first, a gasification element testing using a process development unit (PDU) with a coal feed rate of 1 t/day. Continuously the HYCOL project at 50 t/day [a project on commission from the NEDO and the HYCOL Research Association], and the EAGLE project at 150 t/day [a joint project by NEDO and J-POWER] were conducted. An upscaling possibility of a gasifier was verified with steady steps through these projects. With the knowledge obtained from the EAGLE project, the Osaki CoolGen project, the first step IGCC demonstration tests, was carried out from FY2016 to FY2018. This Osaki CoolGen project had been subsidized by the Ministry of Economy, Trade and Industry (METI) since FY2012 and has been supported by the NEDO since FY2016.

6.3.7 Gasifier facilities 6.3.7.1 Coal pulverizing and feeding system The purpose of the coal drying system is drying and grinding the raw coal for stable transportation of pulverized coal to gasifier and stable/high-efficiency gasification at the gasifier.

Figure 6.34 History oxygen-blown IGCC/gasification technology development of MHPS. IGCC, Integrated coal-gasification combined cycle; MHPS, Mitsubishi Hitachi Power Systems. Source: Courtesy MHPS.

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In the same way with conventional coal firing boiler, raw coal fed from coal bunker is dried and grinded in the coal pulverizer. However, in the case of IGCC, part of the flue gas from the GT is extracted from the HRSG as the drying gas at the pulverizer. Pulverized and dried coal is fed to the gasifier by a pulverized coal feeding system. The system is generally called lock-hopper system, because entrained bed gasifier developed by MHPS is operated under HP and the coal feed is conducted at pressurized condition.

6.3.7.2 Coal pulverizer The pulverizer which is applied for IGCC is basically vertical shaft type as shown in Fig. 6.35. Since MHPS has abundant experiences of that in conventional boiler, MHPS realizes high reliability and efficiency pulverizer. The pulverizer is executed with three rollers made of abrasion-resistant material and furnished with a built-in separator. While pulverizer of conventional boiler applies fixed separator, that of IGCC can apply both rotary and fixed separator. Raw coal is fed to pulverizer from the coal feeder via a center feed pipe. The coal is grounded between the three grinding rollers and the rotating table in the pulverizer. Pulverized coal is simultaneously dried by the drying gas fed from bottom part of pulverizer and carried into the separator fixed at the top of pulverizer. Through the separator, particle size of pulverized coal is controlled, and that particle is carried to pulverized coal collector.

Figure 6.35 Structure of pulverizer. Source: Courtesy MHPS.

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The mean particle diameter at the outlet of pulverizer should be around 5070 µm.

6.3.7.3 Pulverized coal feeding system A schematic flow diagram of the typical example of the coal feeding system is shown in Fig. 6.36. After the coal grinding and drying process, pulverized coal is separated by collector, stored in the pulverized coal storage bin, and then enters the pulverized coal distribution hoppers. From the pulverized coal distribution hoppers, coal is transported into the gasifier using nitrogen gas provided by the air separation unit (ASU).

6.3.8 Gasifier 6.3.8.1 Air-blown gasifier Fig. 6.37 shows the principle of the air-blown gasifier developed by MHPS. Airblown gasifier has a two-chamber two-stage entrained bed type configuration consisting of a lower combustor and upper redactor. A half of the coal and recycled char is fed to the combustion chamber, along with the whole amount of gasification agent. Air extracted from GT compressor outlet is used as gasification agent. Partial oxidation takes place to generate a gas mixture such as CO, H2, CO2, and H2O.

Figure 6.36 Coal feeding system flow diagram.

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Figure 6.37 Principle of air-blown gasifier.

Temperature in the combustor is maintained high enough to melt ash and produce molten slag. The molton slag is discharged from the bottom of the combustor chamber and quenched in a water bath. In the second stage (the “reductor” chamber) the remaining coal is fed into the hot gas stream flowing upwards in the reductor. In this fuel-rich, reducing environment, the key reactions take place such as the char gasification and the shifting of CO and H2O to H2 and CO2. Since these reactions are endothermic, the temperature of the mixture gas drops below the temperature the solid particles of which such as char or carried-over ash are hardened before the syngas entered into syngas cooler (SGC). This reaction will minimize fouling risk in the downstream SGC heat exchangers. SGC is furnished after the gasifier directory as one unit together with the gasifier. It provides efficient heat recovery from syngas as well as steam generation applicable to either power generation or auxiliary use for various purposes. Char recycle system collects entrained char in raw syngas and recycles it to the combustor. As a result, it provides the high carbon conversion rate of over 99.9% and minimizes the unburned carbon in slag. No black water effluent generation is also an outstanding feature of this system. Molten slag flowing down from the bottom of the combustor turns into granulated slag in slag water bath and then is discharged from the gasifier through lock-hopper system. This hardened granulated slag is nonleaching of heavy metals originally contained in coal, thus it can be suitable for a raw material for aggregate, road paving, and so on. Furthermore, dry-feed system is applied to the transportation of both coal and char. It provides low latent heat loss inside the gasifier compared with the slurry feed design, thus enables higher cold gas efficiency.

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6.3.8.2 Oxygen-blown gasifier Fig. 6.38 shows the principle of the oxygen-blown gasifier developed by MHPS. The oxygen-blown gasifier is mainly composed of a single-chamber, two-stage, swirl-flow entrained-bed equipped with burners in the upper and lower stages of a cylindrical furnace. Appropriate oxygen/coal ratios can be allocated to the upper and lower stages, in order to match the lower stage to the temperature required for ash melting and the upper stage to the conditions for efficient gasification reaction according to the type of coal used. Moreover, a swirl flow can be generated in the gasifier to allow residence time for coal particles and to suppress the dispersion of char. The oxygen-blown gasifier was subjected to the following measures: 1. The oxygen/coal ratios in the upper and lower stages were optimized, and the way of supplying seal gas was improved at the gasifier outlet (throat) to protect the throat from ash deposits (slagging). 2. The water-cooled piping on the gasifier wall was narrowed in clearance to step up cooling, and heat-resistant material was fusion-injected into the local high-temperature parts, in order to protect the gasifier walls. 3. The high-temperature gas flow (self-circulating flow) in the furnace and the slag flowdown promoting nozzle were used to insulate and heat up the molten ash (slag) tapping hole, in order to cause slag to flow down stably.

These measures solved the problems associated with the oxygen-blown gasifier.

6.3.9 Char recycle system Fig. 6.39 shows char recycling system. This system mainly consists of char collecting equipment such as cyclone and porous filter, and distribution hoppers same as

Figure 6.38 Principle of oxygen-blown gasifier.

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Figure 6.39 Typical schematic diagram of char recovery and feed system.

pulverized coal feeding system. This system separates all of the char included in the syngas and recycles it back into the gasifier. This improves efficiency by eliminating unburned carbon exiting the gasifier and also avoids generation of black water that poses water treatment challenges.

6.3.9.1 Char cyclone The char cyclone separates most of the char (approx. 90%) from the syngas flow. It consists of a pressure vessel and an inner cylinder. The char is separated from the syngas at the inner cylinder by centrifugal force and then collected in the car storage bin below the cyclone. Char cyclone and storage bin are carried out as one vessel. After the syngas exits the cyclone, it enters the porous filter.

6.3.9.2 Porous filter The porous filter captures the char which cannot be separated in the char cyclone. It consists of a pressure vessel and several sintered metallic filter elements as major components. The filter elements are installed inside the pressure vessel. For backwashing of the filter elements, several backwashing pipes are installed above. Char accumulated on the outside surface of the sintered metallic filter elements is removed periodically by nitrogen gas backwashing. The removed char drops into the porous filter outlet hopper located below the porous filter.

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6.3.10 Gas clean-up system The gas clean-up system consists of processes below (see Fig. 6.40) G

G

G

G

Carbonyl sulfide (COS) hydrolysis and scrubbing/washing H2S removal Off-gas treatment furnace Sulfur recovery system

After the gas clean-up system removes impurities (sulfur, NH3, halogen, etc.) from the syngas, the treated gas transfers to the GT. The method of impurity removal is shown in Table 6.2. It should be noted that the diagram in Fig. 6.40 shows only the concept and function of the gas clean-up system. The number of equipment and component may be changed in the real plant.

6.3.10.1 COS hydrolysis and scrubbing/washing section From the gasifier island, the syngas firstly flows to GGH (Gas-Gas Heater) where the gas is cooled. The gas is fed to COS converter and converted from COS to H2S and HCN to NH3 (see Fig. 6.41). COS 1 H2 O ! H2 S 1 CO2 COS can’t be removed with MDEA solvent at H2S removal section, it needs to convert to H2S with COS hydrolysis catalyst.

Figure 6.40 Gas clean-up system block flow diagram.

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Table 6.2 Method of impurity removal. Items

Method

COS, HCN

Convert to H2S with COS hydrolysis catalyst COS 1 H2O3H2S 1 CO2 (equilibrium reaction) HCN hydrolysis reaction also occurs with COS hydrolysis catalyst HCN 1 H2O!NH3 1 CO Halogens are removed at the venturi scrubber Halogens are treated at the wastewater treatment system NH3 is removed at the washing column NH3 is converted to N2 at off-gas treatment furnace H2S is removed with MDEA solvent (COS can’t be removed with MDEA solvent) H2S is converted to SO2 at off-gas treatment furnace and treated at Sulfur Recovery System.

Halogen NH3 H2S

Figure 6.41 COS hydrolysis reactor. COS: carbonyl sulfide

HCN hydrolysis reaction is also occurred at the same operation condition as COS hydrolysis catalyst. HCN 1 H2 O ! NH3 1 CO HCN is deadly poison gas in raw syngas; therefore it needs to be converted to NH3. After COS hydrolysis process the gas is further cooled by another GGH, then the gas flows to a washing tower to remove dusts, NH3, and halogens (such as HF, HCl). In the washing section the syngas is cooled to around 40 C in the washing column where NH3 is removed deeply. The wastewater from washing section is fed to wastewater treatment section. The syngas from washing tower includes only H2S as impurity, and it is fed to H2S absorber section.

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6.3.10.2 H2S absorber/stripper section H2S absorber section removes H2S from the raw syngas to meet environmental emission regulations. To remove H2S, the amine solvent is used in a general way. Methyl diethanolamine (MDEA) is used as amine solvent (see Fig. 6.42) because of the two points as below: 1. High absorbability and selectivity of H2S. 2. Low energy to regenerate the solvent

In a H2S absorber the cooled syngas is contacted with MDEA to remove H2S components. Clean syngas exits the top of the H2S absorber and is sent through GGH before the GTs (see Fig. 6.43). On the other hand, the lean MDEA solution is provided at the top of the H2S absorber column. The solvent and syngas contact to create an acidbase reaction and the warm rich (H2S loaded) MDEA leaves from

Figure 6.42 Methyl diethanolamine.

Figure 6.43 H2S absorber section.

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the bottom of the absorber. This MDEA is provided to the H2S stripper. The stripper regenerates the MDEA solvent by using adequate heat to reverse the acidbase reaction. The amine taken from the bottom of the stripper is recycled back to the H2S absorber and the released H2S off-gas is sent to off-gas treatment furnace.

6.3.11 Combined cycle system The power block equipment is arranged in a combined cycle configuration with the GT, ST, electric generator, and the HRSG as the major components. Optimizing the power block thermodynamic cycle offers a higher combined cycle efficiency while lowering the life cycle costs. The design also considers the need for meeting the target reliability and availability, while allowing for flexible operation. The following subsections provide additional description of the major power block components.

6.3.11.1 Gas turbine Coal gasification synthesis gas (syngas) has less (1/81/10) calorific value compared with that of natural gas. In order to apply this syngas to GTs originally designed for natural gas application, consideration mainly for combustor design needs to be taken care of. On the other hand, as shown in Fig. 6.44, the syngas calorific value is almost the same level as that of blast furnace gas (BFG) mixed with coke oven gas from steel mill. Therefore experiences of BFG firing GT can be effectively applicable to the design of syngas firing GT. As shown in Fig. 6.45, MHPS has syngas application experiences to large frame GT such as D- and F-class. Nakoso 250 MW Air-blown IGCC Demonstration Plant applied DA-frame GT and has been operating since 2007. F-class GT was firstly

Figure 6.44 Comparison of fuel calorific value.

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Figure 6.45 Operational experience of low calorie gas firing gas turbine. Source: Courtesy MHPS.

applied to vacuum residue oil gasification IGCC at the beginning of the 2000s, and coal firing IGCC with F-class starts its commercial operation in 2020 (see Fig. 6.46). There is a possibility of applying further large-scale GT for syngas utilization in the future. On the other hand, there is a track record of relatively smallscale H-100 GT for the Osaki Cool Gen project.

6.3.11.2 Heat recovery steam generator HRSG is connected to the GT exhaust duct, and the waste heat of exhaust gas is efficiently recovered by generating steam for working ST. Low temperature exhaust gas is routed to a stack and discharged to atmosphere. Basic function of HRSG for IGCC application shown above is same as those for natural gas or BFG firing GT combine cycle plant, but there are some additional functions for IGCC application such as: Steam from the gasification area SGC is further superheated in the HRSG for the ST generator. Heating of a boiler feedwater prior to the introduction to SGC is also conducted. Part of the GT exhaust gas is extracted and supplied to coal pulverizing and drying process as a coal drying gas with enough sensible heat and volume flow.

6.3.11.3 Steam turbine ST for IGCC application has no specific technical feature compared with those for natural gas firing GTCC, and same design consideration such as the volume of generated steam and the design vacuum needs to be taken care of. In the case of IGCC,

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Figure 6.46 History of low calorific value syngas to large frame gas turbine. Source: Courtesy MHPS.

the power-producing components such as GT, ST, and an electric generator are basically coupled along a single shaft line. Besides being suited for base-load operation, this single shaft configuration allows for faster start-ups, allows the use of a single electric generator and related electrical equipment, and reduces the power block footprint, as compared to a multishaft arrangement.

References [1] R. Farmer, editor-in-chief, Gas Turbine World 2010 Handbook, Pequot Pub, Southport, 2010. [2] T. Matsumoto, Y. Nakajima, M. Sugimoto, R. Okura, F. Takayama, N. Suzuki, Overview of combined cycle power plants, Therm. Nucl. Power 61 (5) (2010) 405423. [3] Thermal and Nuclear Power Engineering Society (TENPES), Combined Cycle Power Generation, Tech. Lecture Book, Vol. 37, TENPES, Tokyo, 2011. [4] K. Kawakami, J. Kawai, M. Nagai, Design and test operation performance of 1,500 C class gas turbine combined-cycle power plant, Mitsubishi Heavy Industries Tech. Rev. 46 (2) (2009) 3135. [5] Y. Takei, N. Saito, HRSG for large capacity and high efficiency GTCC plant, J. Gas Turbine Soc. Jpn. 46 (2) (2018) 96100. [6] H. Miyanishi, T. Masuda, SCR system for gas turbine power plant, J. Gas Turbine Soc. Jpn. 45 (3) (2017) 146150.

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[7] T. Sakata, Y. Otani, Development of Pressurized Fluidized-Bed Combustion Combined Plant, Report of Research Committee on High Efficiency Coal Combustion Power Generation, P-SCD 338, JSME, 2004 (in Japanese). [8] US Department of Energy, Tidd: The Nation’s First PFBC Combined-Cycle Demonstration, Clean Coal Technology, Topical Report Number 1, 1990. [9] J.N. Phillips, G.S. Booras, J. Marasigan, The history of integrated gasification combined-cycle power plants, in: Proc of ASME Turbo Expo 2017: Turbomachinary Technical Conference and Exposition, Paper No. GT201764507, Charlotte, 2017, pp. 113.

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Kenjiro Yamamoto1, Masafumi Fukuda2 and Atsuhiro Hanatani3 1 Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan, 2Research Institute for Advanced Thermal Power Systems, Tokyo, Japan, 3IHI Corporation, Tokyo, Japan

Chapter outline 7.1 Introduction 345 7.2 Efficiency improvement

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7.2.1 Pragmatic approach in thermodynamic point of view 347 7.2.2 Definition of thermal power plant efficiency 349

7.3 History of elevating steam condition in the world 352 7.4 Development programs for ultrasupercritical and advanced ultrasupercritical power plants in the world 356 7.4.1 Development program of ultrasupercritical power plants in Japan 358 7.4.2 Development program of advanced ultrasupercritical power plants in Japan 360

7.5 Aspects of metallurgy and stress analysis

370

7.5.1 Creep-rupture properties 370 7.5.2 Corrosion resistance properties 384

7.6 Concluding remarks References 386

7.1

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Introduction

The terms of ultrasupercritical (USC) and advanced USC (A-USC) are acknowledged as the following steam parameters, respectively, in their most popular and typical conditions to aim better thermal efficiency beyond SC condition. The typical representative steam conditions of these power plants are listed in the following: SC: 24 MPa, 538
C/566
C USC: 25 MPa, 600
C/600
C A-USC: 35 MPa, 700
C/720
C

where steam condition is, in general, represented as prime steam pressure, prime steam temperature/first reheat steam temperature/second reheat steam temperatures. It should be noted that the development of A-USC plant is still ongoing in 2020 [1], as described in Section 7.4.2, and is before utilization and major components made of candidate materials that have been tested to demonstrate manufacturability (bending, welding) and durability.

Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00007-2 © 2021 Elsevier Inc. All rights reserved.

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Figure 7.1 Steam condition and applicable materials.

Each steam condition is able to be classified by material used for thick-wall components at the highest temperature in the steam power plant, that is, boiler superheater/reheater outlet headers and leading pipes to steam turbine, even though there exist some variations of pressure and temperature from the earlier: SC: Low-alloy steel (CrMo steel), such as A335-Gr. 22 and Gr. 23 USC: CSEF steel, such as SA213-Gr. 91, Gr. 92, and Gr. 122 A-USC: Nickel-based superalloy, such as HR-6W and Alloy617

where CSEF steel means “creep strengthenhanced ferritic” steel. The theorem that the elevated temperature brings better thermal efficiency could be realized thorough the innovation of CSEF steel and Nickel-based superalloy accompanied by good quality and manufacturability, which can easily draw an analogy to the 16th century’s industrial revolution in which Watt’s engine could be realized thorough the innovation of Wilkinson’s boring machine with better machining accuracy for controlling clearance between cylinder and piston. The deployment of each material to compose each component of power plant is briefly illustrated in Fig. 7.1. This chapter describes the development and utilization processes of USC plant and the state of the art of A-USC technology, for both of which the material development, utilization, and maintenance methodology are briefly covered.

7.2

Efficiency improvement

In accordance with Carnot’s theorem the maximum power extracted from heat by a reversible heat engine is proportional to the temperature difference between a hot source and a cold source [2]. This means that the prime measure to improve thermal efficiency of steam power cycle (Rankine cycle) is to operate it with elevated hotside fluid temperature.

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7.2.1 Pragmatic approach in thermodynamic point of view 7.2.1.1 Elevating steam condition As a nature of steam property, below and around the critical pressure of 22.12 MPa, an increase in the pressure contributes to elevate evaporating temperature at which most of the heat absorption is taken place as descried in Fig. 7.2B. This is the reason why SC condition has been adopted in place of subcritical pressure condition (Fig. 7.2A). Because increasing pressure above critical pressure no more brings drastic elevation in evaporating temperature, the focus has been on elevating steam temperatures at superheater and reheater outlets in the case of single-reheat cycle that has been most popular from the viewpoint of economic feasibility compared with doublereheat cycle. This condition, as illustrated in Fig. 7.2C, had been realized as USC. Improvement in steam turbine heat rate (inverse value of steam turbine efficiency) by adopting 24.6 MPa, 600
C/600
C compared with SC of 24.2 MPa, 538
C/566
C is around 3.3% in relative value, as presented in Fig. 7.3.

7.2.1.2 Double-reheat cycle Although pressure increase has no longer been effective above SC in improving efficiency for single-reheat cycle as mentioned earlier, it is worth applying doublereheat cycle increases available energy convertible to turbine output power, as illustrated in Fig. 7.2D. In this cycle, prime pressure is apt to increase up to 30 or

Figure 7.2 Effect of elevating pressure and temperature on thermal efficiency. (A) Sub— 17.5 MPa, 538
C/566
C; (B) SC—24.1 MPa, 538
C/566
C; (C) USC single reheat— 24.5 MPa, 600
C/600
C; and (D) USC double reheat—32.1 MPa, 600
C/600
C/620
C. Sub, Subcritical condition; SC, supercritical condition; USC, ultrasupercritical condition.

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Figure 7.3 Turbine heat rate reduction along with elevated steam condition. Source: Data from The Institute of Electrical Engineers of Japan, in: Handbook of Electrical Engineering, seventh ed., Ohmsha, 2013, p. 1096, Sec. 26 [3].

35 MPa in order to keep exhausted enthalpy at the last blade within appropriate level as containing slight moisture, which secures turbine efficiency at high level. This effect of increasing pressure in double-reheat cycle can be observed in Fig. 7.3, as such that, when increasing pressure of single-reheat cycle from 24.2 to 31.1 MPa at 566
C/566
C, turbine heat rate gain is 0.4% (from 1.2% to 1.6%), on the other hand, in case of double-reheat cycle from 24.2 to 31.1 MPa at 593
C/ 593
C/593
C, its gain is improved to 1.1% (from 4.3% to 5.4%). Furthermore, the gain can be attained by increasing temperature by 10K20K or more at reheat system, because CSEF steels are still applicable due to the lower pressure than prime system. In the recent years, 31.1 MPa, 600
C/620
C/620
C system is in operation as introduced in Section 7.3, which has a potential to attain 3.5% gain compared with 24.2 MPa, 600
C/600
C system, combining the gain of 2.5% (from 2.9% to 5.4% which corresponds to; from 24.2 MPa, 593
C/593
C to 31.1 MPa, 593
C/593
C/ 593
C) as observed in Fig. 7.3 and the gain of 0.9% (each 20K temperature increase in reheat systems). Some of the representative SC units in Tables 2.8 and 2.9 adopted double-reheat cycle that has one more reheat cycle than single-reheat system in order to let Rankine cycle become close to Carnot cycle with resultantly higher efficiency.

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Although also in Japan, more than 10 units of this type with oil-/gas-fired had been constructed and operated, the type had not become popular nowadays because balance of capital cost versus operation cost in firing cheaper coal is not so much feasible. Furthermore, proper consideration should be paid in order to withstand the complexity for controlling temperature of one additional reheat system, such as spray injection (causing decrease in cycle efficiency), so-called damper control system that directly varies flue gas flow in reheat heating surface (increase in capital cost) and flue gas recirculation system (also increase in capital cost) shall be introduced.

7.2.2 Definition of thermal power plant efficiency Efficiency of a power plant is described as percentage of electric energy output to energy input, which differs by the definition of coal energy content, higher heating value (HHV) or lower heating value (LHV) of coal, and which also differs by other aspects of employed electrical energy, gross or net output power, and thus four values of efficiency exist as ηp HHV-gross, ηp LHV-gross, ηp HHV-net, and ηp LHV-net, expressing one state of operation. When comparing the efficiency data from different sources, it is important to ensure that the efficiency values are expressed on a common basis. Then, it should be carefully examined in which way the efficiency value is calculated, such as being aware that European and Chinese engineers tend to use LHV, while the United States and Japanese tend to use HHV to determine the efficiencies.

7.2.2.1 Higher or lower heating value base efficiency The HHV value, known as gross calorific value of coal, is the total amount of heat released by combustion, which includes heat of condensation of water vapor in the combustion products that originate from the combustion of hydrogen and evaporation of the moisture contained in coal. The LHV, net calorific value of coal, is the amount of heat released by combustion, which deducts latent heat of vaporization of water as mentioned earlier. HHV is higher than LHV by around 2%20%, which depends on moisture and hydrogen content, like that much carbonized (old) coal as anthracite with little composition of water and hydrogen deviates nearly 2%, medium carbonized coal as bituminous or subbituminous coal deviates around 5%10%, and less carbonized (young) coal with much composition of water and hydrogen as lignite (brown coal) deviates around 20%. Thus the value of power plant efficiency calculated using HHV is lower than that based on LHV and differs as much as mentioned earlier between ηp HHV-gross and ηp LHV-gross or between ηp HHV-net and ηp LHV-net. In principle, HHV represents the potential energy that combustible compounds of fuel has and is thought to be reasonable to define energy input to power plant, even if stack exhaust flue gas contains vaporization energy because of the gas temperature above dew point, which means the vaporization energy in question is in no serve for generating steam in boiler to be utilized generating electricity. The HHV

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value can be defined clearly by direct measurement, such as a procedure of “bomb method” defined as JIS M8814. However, in firing high moisture coal such as lignite or relatively less carbonized coal, the efficiency based on HHV presents very low value because of large vaporization energy that cannot be used to generate steam in boiler, and the interpretation that vaporization energy in no serve should be subtracted obtains appropriateness. LHV is calculated by the formula: LHV 5 HHV 2 (w 1 9H) 3 2.51 MJ/kg (where w means moisture, H stands for hydrogen content in fuel), and it is pointed out that biased selection for values of w and H would be out of fare evaluation [4].

7.2.2.2 Gross efficiency or net efficiency Gross output power is electricity generated at terminal of the generator. Net output power is net electricity transmitted from a power plant to grid, subtracting electricity used in the plant by auxiliaries such as fans, pumps, flue gas treatment systems, air conditioning, and lighting, so-called house power. In general, the difference between gross and net output power is estimated at 3%5% for a coal-fired plant, depending on the coverage of auxiliaries. Thus the value of power plant efficiency for the gross output is higher than that a for the net output and differs as much as mentioned in the between ηp HHV-gross and ηp HHV-net or between ηp LHV-gross and ηp LHV-net.

7.2.2.3 Other factors to be considered The factors described next should be considered to evaluate the performance itself unless credibility could not be secured for evaluating the plant efficiency, particularly by careless or willful negligence. A comparison for the unique characteristic of the power plant machinery independent from environmental condition would be revealed to be nonsense. When steam energy is utilized for district heating (combined heat and power) or bigger auxiliary driving power, such as induced draft fans, the energy extracted from Rankin cycle is considered as fully utilized energy so that the energy utilization efficiency increases. Since the output power from Rankin cycle increases with a decrease in the coolant temperature in accordance with Carnot’s theorem, as is referred in Section 7.2. This means that the lower seawater temperature or the lower atmospheric temperature reflects on the lower condenser coolant to make the lower vacuum leading to an improvements of the plant efficiency as much. Plant energy loss such as leakage and radiation loss should be counted. About 0.5% loss is a typical example. When such loss and/or additional factors are quantitatively identified, the value of efficiency defined in one way can be converted into those in other ways. In case of 5% of auxiliaries power and 7% difference between HHV and LHV, with normalization into 296.26 kPa (2722 mm Hg) for back pressure of turbine (to condenser), 40.9% HHV-net, as marked in Table 7.1 in Section 7.3, is equivalent to around 43.0% HHV-gross, 43.7%LHV-net and 46.0%LHV-gross, respectively.

Table 7.1 Example of Japanese ultrasupercritical units with efficiency and material used. Power station

Boiler manufacturer

Unit

Company

Matsuura 2 Misumi 1

EPDC Chugoku

BHK MHI

Nanao-Ota 2 Haramachi 2 Tachibanawan Tachibanawan 1 Turuga 2

Hokuriku Tohoku Shikoku EPDC Hokuriku

Tachibanawan 2

Capacity (MW)

Steam parameters (turbine inlet)

Back pressure of turbine (kPa)

Plant efficiency (% HHV-net)

Boiler/steam line material

Commercial operation year

Super304H/P91 Super304H, HR3C/P91 TP347H/P91 Super304H/P91 Super304H/P91 Super304H/P91 Super304H, HR3C/P122 Super304H/P91, P92, P122 Super304H/P91 Super304H/P91 Super304H/ P122, P91 Super304H/ P122, P91 Super304H, HR3C/P122 Super304H/P122 Super304H, HR3C/P122 Super304H/P122

1997 1998

Pressure main steam (MPa)

Temperature main/reheater (
C)

1000 1000

24 24.5

593/593 600/600

296.26 296.26

39.6 40.9

IHI BHK BHK IHI MHI

700 1000 700 1050 700

24 24.5 24 25 24

593/593 600/600 566/593 600/610 593/593

296.3 297.1 296.26 296.26 296.3

39.4 40.9 40.6 40.0 39.4

EPDC

BHK

1050

25

600/610

296.26

40.0

Hekinan 4 Hekinan 5 Tomato-Atsuma 4

Chubu Chubu Hokkaido

IHI IHI IHI

1000 1000 700

24 24 25

566/593 566/593 600/600

296.26 296.26 298

39.9 39.9 42.0

Isogo 1

EPDC

IHI

600

25

600/610

296.26

40.9

Reihoku 2

Kyusyu

MHI

700

24

593/593

296.26

40.7

Hitachinaka 1 Hirono 5

Tokyo Tokyo

BHK MHI

1000 600

24.5 24.5

600/600 600/600

296.26 296.26

40.9 40.9

Maizuru 1

Kansai

MHI

900

24.5

595/595

296.3

40.9

1998 1998 2000 2000 2000 2000 2001 2002 2002 2002 2002 2003 2004 2004

Source: Data from Survey of ultra-supercritical coal power plants in Japan and China: phase I & II, in: Report No. 1020526, EPRI, Palo Alto, CA and ENEL, Pisa, Italy, 2009; K. Kimura, Safety preservation for high temperature machinery based on several years long term creep test, in: No. 107 Science Seminar in Tokyo Institute Technology, 2006, p. 7.

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7.3

Advances in Power Boilers

History of elevating steam condition in the world

Historically, in 1949, after World War II, the first attempt to operate at 29.4 MPa, 600
C was experimentally and industrially conducted with 12 t/h boiler in AllRussia Thermal Engineering Institute (VTI in Russian abbreviation), Moscow USSR. This boiler had been in service for 220,000 hours to provide steam to turbine that generated electricity to the grid of Moscow and rehabilitated to 650
C with 15 t/h after 40,000 hours service in 1960. Fig. 7.4 shows the photo of this boiler preserved in VTI, Moscow. In 1956 Hu¨lls II Block 1 at 29.4 MPa, 600
C with 260 t/h in West Germany was put in operation, and in 1957 Philo no. 6 at 31.0 MPa, 621
C with 306 t/h was in service in the United States, as illustrated in Fig. 2.48. In 1959 Eddystone unit 1, Philadelphia Electric Co., the United States at 34.5 MPa, 649
C with 907 t/h was also put in operation. In 1960 Kashira GRES plant no. 6 at 30.9 MPa, 655
C with 710 t/h was put in service in Russia. Superheater tube material of VTI boiler (29.4 MPa, 600
C, rehabilitated to 650
C) and Kashira GRES plant no. 6 (30.9 MPa, 655
C) were 3P(EP)-184 steel with 17%Cr17%Ni [5]. Final superheater header and main steam pipes of Eddystone unit 1 (34.5 MPa, 649
C) were Type 316 stainless steel. Fig. 7.5A

Figure 7.4 World first USC boiler for commercial use in Moscow. USC, Ultrasupercritical. Source: Reproduced by permission from VTI.

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Figure 7.5 Operation experience of Eddystone unit 1, Philadelphia Electric Co., the United States. (A) Record of service condition after start operation in 1960. (B) Isometric drawing of main steam pipeline. Source: Data from T. Daikoku, T. Tsuchiya, F. Masuyama, W.F. Siddall, K. Setoguchi, F.V. Ellis, et al., Operating experience and reliability evaluation on main steam line pressure parts of ultra-supercritical (USC) power plant, Mitsubishi Heavy Ind., Ltd. Tech. Rev. 22 (1985), 1222.

illustrates the record of service condition of Eddystone unit 1 after start operation. It is observed that the efforts to maintain the elevated steam condition had been paid, during 130,000 hours in service till 1983; however, the operating condition had fallen down to the level around 26 MPa, 600
C. Actually, during the start-up after scheduled outage in 1983, steam leakage occurred in the main steam pipe, followed by precise investigation and replacement [6]. The investigation reported that the damage was considered to be caused by creep damage related to material degradation of Type 316 stainless steel after long-term service and particular operating conditions of the main steam pipe, high thermal stress of which was induced by the very much different pipe system from these days, that is, main steam pipe was cooled down rapidly during shutdown because feedwater was designed to be evacuated to bypass water separator downstream of the pipe, as illustrated in Fig. 7.5B. Modern design never adopts such system, and the results of analysis had lighted the framework of improvement of not only reliability of USC boilers but also evaluation of existing old plants. This experience suggests how to manage the durability of key components against severe thermal stress is vital. After other possible pressures and temperatures had been attempted as described in Tables 2.8 and 2.9, in the 1960s, steam condition of 24 MPa, 538
C/566
C

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(3500 psig, 1000
F/1100
F) for primary steam pressure, primary/reheat steam temperatures had become popular and settled as SC condition. Untill the 1980s, some of the efforts had been continued to develop hightemperature resistance materials to encourage seeking higher efficiency; however, major efforts had been concentrated to improve economic performance through decreasing construction cost by seeking scale merit with larger capacity of power plant as shown in Figs. 2.52 and 2.53. Subsequently to the experience of twice “oil crisis,” deficiency of oil supply started from 1973, the needs to surpass SC in efficiency had been waked up from the viewpoint of energy resource conservation. As described in Section 7.2.1, the effect of increasing steam pressure above 24 MPa is almost saturated to improve thermal efficiency with single-reheat cycle, it was attempted to elevate steam temperature. In such a direction, development program funded by governments had been started, as explained in Section 7.4.1. First attempt to elevate temperature above 538
C/566
C in Japan was done in reheat temperature to 593
C in 1993, then after in superheater to 593
C in 1997. The first 600
C/600
C unit, Chugoku Electric Power Co. Misumi no. 1, was put into commercial operation in 1998. Including these, examples for the Japanese USC plant are shown in Table 7.1 with their efficiencies on a basis of %HHV-net, together with related parameters such as steam condition and back pressure of turbine [7,8]. Fig. 7.6 shows the history of the capacity of coal power plants in Japan. Although a minor difference between two sets of plotted data in 2009 may be caused by the difference in database of industrial boilers, the trend of increasing USC units is clearly observed. The capacity of USC units started in 1993 increased successively to 16.8 GW at the end of 2009 corresponding to about 45% of coalfired plants. Since 2004 the newly commissioned utility boilers in Japan were all USC units, and the capacity of USC units reached 21.0 GW at the end of 2019 occupying about 48% of the total capacity of coal-fired boilers. European utilities also built a lot as shown in Table 7.2 [8].

Figure 7.6 Trend of capacity of coal power plant in Japan. Source: Data from MHPS and M. Fukuda, Advanced USC technology development in Japan, in: Ninth Liege Conference: Materials for Advanced Power Engineering 2010, Forschungszentrum Ju¨lich, 2010, pp. 317 [9].

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Table 7.2 Example of European ultrasupercritical units with material used. Power station Unit

Country

Skaerbaek 3 Nordjylland 3 Lippendorf Boxberg Avedore 2 Niederaussen

Denmark Denmark Germany Germany Denmark Germany

Max. temp. (
C)

Material

Commercial operation year

580 580 583 578 600 600

TP347H/P91 TP347H/P91 1.4910/P91 1.4910/P91 TP347H/P92 TP347FG/E911

1997 1998 1999 1998 2001 2002

Source: Data from K. Kimura, Safety preservation for high temperature machinery based on several years long term creep test, in: No. 107 Science Seminar in Tokyo Institute Technology, 2006, p. 7.

Figure 7.7 Example of Japanese USC units’ availability. USC, Ultrasupercritical. Source: Data from Survey of ultra-supercritical coal power plants in Japan and China: phase I & II, in: Report No. 1020526, EPRI, Palo Alto, CA and ENEL, Pisa, Italy, 2009.

In Japan equivalent availability factor (including planned outages) of USC units has been high in the range up to 96% [7]. It is reported that J-POWER Tachibanawan no. 1 and 2 are 85.6% and 87.8%, and Matsuura no. 2 is 87.6%, as the equivalent availability factor since the start of commercial operation till 2007. As shown in Fig. 7.7, J-POWER’s Isogo 1 has achieved availability (including planned outages) 93.6% in 2002, 90.2% in 2003, and 96.5% in 2006. Fig. 7.7 shows also the availability factors of Tokyo Electric Power Co.’s Hitachinaka no. 1 both, including and excluding planned outage, the latter of which is reaching around 100% [7]. The deployment of USC has been accelerated worldwide since 2006, and the fraction of USC increased up to 41.5% of the total worldwide installation in 2017. The

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majority of new USC constructions were in China, more than Japan and Europe, reaching over 193.2 GW with 235 U till 2018 since the first unit of Huaneng Yuhuan 1000 MW, 25 MPa, 600
C/600
C had commenced in 2006 [10]. Chinese manufacturers have introduced USC technology licensed from Japan, the European Union, and the United States to cope with extensive construction demand, which reached up to more than 20 GW per annual in a year of the 2000s. In the United States the first USC unit, AEP Turk 600 MW with 600
C/603
C, has been put into commercial operation in 2012. As for other countries and areas, following the number of USC units is in operation or under construction nowadays, nearly 20 U in Korea, several, and more in Indonesia; several in Malaysia and Taiwan; one or more in Philippine, Thailand, and Morocco; and several and more under construction or designing in India. Recently, in China, USC units applied double-reheat cycle have been actively constructed, starting Anyuan units no. 1 and 2 of 660 MW with 31 MPa, 600
C/ 620
C/620
C, as had been previously applied in the United States, the European Union, and Japan, followed by several units of 1000 MW class capacity. Furthermore, two of 1000 MW unit with 35 MPa, 615
C/630
C/630
C are under construction from 2018 [11]. As for high-temperature materials as typical, six materials (P92, P122, Super304H, TP347H, TP347FG, and HR3C) were developed in Japan, two materials (1.4910, E911) in European Union, and one (P91) in the United States. The thermal efficiency operationally recorded for each unit is very limited, but some of them are found in references [1215]. In these days, high thermal efficiency is highly desired due to the significant contribution not only to energy resource conservation but also to climate change mitigation. The climate change issue is requested by advocators consisted of meteorologists who had exercised influence to policy guideline for OECD investment, such as promoting ineligible official support for export credit to above 500 MW capacity thermal power plant less than 24 MPa or 593
C [16], which practically advises USC unit is mandatory. As will be described and discussed in Section 7.5, since incidents caused by overestimation of long-term creep strength for CSEF steels base metal and welded joint have forced installers in Japan from 2004 to shut down the plant and repair the failure or replace the degraded components, interaction among boiler/plant engineers and metallurgists in laboratories/authorities has extensively changed information and established countermeasures to maintain the reliability of USC units. Almost the same situation has occurred in other countries, also in China with most majority installation [17], and thus international cooperation in this field is strongly desired.

7.4

Development programs for ultrasupercritical and advanced ultrasupercritical power plants in the world

Utilization of USC units had been a fruitful outcome from development programs conducted worldwide, and fossil fuel will continue to be the major resource of

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energy for the foreseeable future. Further improvement in operating plant efficiency has been desired to cope with the demand for clean and affordable energy supply, which has initiated consistent development program to realize A-USC plant in near future. From around 1980, Japan, the United States, and the European Union had started the programs dedicated to USC development and have sifted to develop A-USC project, which is briefly illustrated in Fig. 7.8. Recently, China, India, and Korea have also started the program aiming A-USC project. There is no significant difference in the targeted steam condition, 35 MPa and 700
C720
C. Thus overview around the world for A-USC development nowadays is very briefly summarized as follows:

Japan Development and plant operation : EPDC 1981–2000 Boiler and turbine -Material development -Component manufacturing -Pilot plant operation -Target : 30 MPa, 650 /650 °C

NIMS material development 1997–2007 -Ferritic steel for 650 °C

Development and plant operation : NEDO 2008–2016 Boiler and turbine -Material development -Component manufacturing -Pilot plant operation -Target : 35 MPa, 700 /720/720 °C

EU Development COST 501/522/536/538 1980–2008 Boiler and turbine

1978–2003 -Basic studies, boiler and turbine,

-Interaction with VGB, Brite-Euram, Matcko, ECCC, etc. -All major power plant components -Target : 30 MPa, 620 °C/650 °C

thick-walled pipe steels (United States, Japan, European Union) -Standardization achieved -Trial components in service

THERMIE AD 700 Comtes 700 Next Gen Macplus 1994–2013 -Materials testing, prototype component manufacturing -Long-term material testing -Component testing in 700 MW plant -Coatings for fire and steams id. protection -Refractory furnace materials Target : 700 °C

2017–2022 -Large diameter pipe creep test -Small test piece creep test

A-USC materials projects DOE 2001–2015 Materials development and qualification -Validation of boiler component fabrication techniques -Steam loop test at utility boiler -Target : 35 MPa, 760 °C (870 °C)

Comtest DOE/OCDO 2015–2021

DP 700 A-USC Components test : NEDO

USA Development EPRI

1994–2013 -Design by analysis -Material properties and modeling -Component manufacturing -Open access material database -Target : 700 °C

-Fabrication of boiler and turbine components -Pressure relief valve qualification -Target : 760 °C

Figure 7.8 Typical USC, A-USC development program in Japan, the United States, and the European Union. A-USC, Advanced ultrasupercritical; USC, ultrasupercritical. Source: Drawn referring to P. Bernard, DP700-phase 1—preparation for commercial demonstration of 700
C power plant, IEA Clean Coal Center, in: Third Workshop “AUSC3”, Rome, December 2017 [18]; H. Hack, R. Purgert, United States advanced ultra-supercritical component test facility for 760
C steam power plants, IEA Clean Coal Center, in: Third Workshop “AUSC3”, Rome, December 2017 [20]; R. Purgert, H. Hack, United States advanced ultra-supercritical project including full-scale 760
C superheater and steam turbine components, in: 2019 IEA Clean Coal Technologies Conference (IEA CCT 2019), Houston, TX, June 2019 [21]; F. Abe, Rising the durability of steels for power plant, in: 7. Ferritic Strength Materials, Sec. 3, Article 5, NIMS Research Outlook, 2006, pp. 334339 (in Japanese) [25]; New Energy and Industrial Technology Development Organization (NEDO) home page, ,https://www.nedo.go.jp/activities/ZZJP_100115.html. (accessed 24.05.20) [26].

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Japan: A-USC Project (PJ) from 2008, Front End Engineering and Design (FEED), material evaluation, manufacturing verification, component test for boiler/turbine/valves, demonstrated in an industrial plant with test sections [1]. European Union: AD-700, COMTES 700, and others from 1997, FEED, material evaluation, manufacturing verification, component test for boiler/turbine/valves, demonstrated such as in 700 MW class utility unit with test sections (discontinued), followed by another demonstration test for durability [18,19]. United States: DOE Vision 21, ComTest PJ, and others form 2001, FEED, material evaluation, manufacturing verification, components test for boiler/turbine/piping, partly demonstrated in utility boiler with boiler tube test sections [20,21]. China: National PJ from 2011, FEED, material evaluation, manufacturing verification, components test for boiler/turbine/piping, demonstrated in 320 MW utility plant with test sections [22]. India: National PJ form 2017, FEED, material evaluation, manufacturing verification, components test for boiler/turbine/piping, partly demonstrated in 210 MW boiler with test tubes [23,24].

Following two sections are addressed to explain USC and A-USC development programs in Japan.

7.4.1 Development program of ultrasupercritical power plants in Japan Fig. 7.9 shows the road map of the program of USC development in Japan, which is divided into Phase 1/Step 1, Phase 1/Step 2, and Phase 2. Phase 1/Step 1 aimed at a steam condition of 31.4 MPa/593
C using newly introduced ferritic materials. The target steam condition of Phase 1/Step 2 was 34.3 MPa/649
C, which required heavy use of austenitic materials for high-temperature parts. Phase 2 prioritized the early introduction of the USC technology to the market, employing the steam condition of 30 MPa/630
C which is lower than that of Phase 1/Step 2. The boiler materials selected for Phase 2 are mainly ferritic steels, except for high-temperature

Figure 7.9 Road map of USC technology development program. USC, Ultrasupercritical. Source: Data from T. Otsuka, Development history and operational experience of ultra-supercritical (USC) power plants, in: Int. Conf. on Power Engineering 2007, Hangzhou, 2007 [27].

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R&D at lab. and factory (creep strength, fabrication durability, and weldability)

Verified by boiler manufacturer

Demonstration at actual units Commercial operation Material (ASME Code)

1980

1985

1990

1995

2000

HCM2S (SA213T23) 2.25 Cr–0.1 Mo–1.6 W HCM9M 9 Cr–2 Mo Super 9Cr (SA213T91) 9 Cr–1 Mo HCM12 12 Cr–1 Mo–1 W HCM12A (SA213T22) 11 Cr–0.4 Mo–1.9 W Super 304H 18 Cr–10 Ni–3 Cu HR3C (SA213TP310HCbN) 25 Cr–20 Ni–Nb

Figure 7.10 Japanese history of USC materials R&D. USC, Ultrasupercritical.

heat transfer tubes, to achieve flexible operation and lower construction cost of power plants. Some newly developed 12Cr materials were tested for turbine rotors. Focused on the USC material R&D, the development and demonstration plant operation program during 19812000 is described in Figs. 7.10 and 7.11 (corresponding to Phase 1 in Fig. 7.9). It was not left alone to steel production manufacturers, but boiler manufacturers took important roles, participation in evaluation of creep strength, fabrication durability, and weldability, and demonstration at actual units and verification of their utilization. In actual demonstration units, candidate tube materials, such as 9%Cr, 12%Cr, 18% Cr, and 25%Cr steels had been tested in several panels of newly added fifth superheater (595
C) and sixth superheater (650
C) at 250 MW coal-fired boiler (Fig. 7.11), all of which materials for tubes and large diameter pipes (applied to headers and leading pipes) are listed in Table 7.3 [26]. The candidate materials, such as utilized as shown in Table 7.1, had been confirmed to have appropriate performance of durability together with antisteam oxidation property. As for investigating the property of gas side corrosion, materials for tube and attachment listed in Table 7.3 had been set up in the air-cooled probes and demonstrated at the 500 MW coal-fired boiler as in Fig. 7.11B, which had been also confirmed proper applicability [26]. Corrosion resistance capability is explained in Section 7.5.2. As for the surface appearance of a tested pipe material, SUS316, Fig. 7.12 shows its observation at 650
C. Ferritic steel enhancement program had been also conducted in 19972007, aiming the higher strength up to 650
C together with suppression of strength degradation at welded joint (see Section 7.5.1.3), one of the outcomes of which is shown in Fig. 7.13 [27]. Comprehensive development history of ferritic boiler steel with 9%Cr and 12%Cr content is illustrated in Fig. 7.14.

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Figure 7.11 USC Material demonstration in Japan (198187) [28]. (A) Steam side duration test. (B) Gas side corrosion test. USC, Ultrasupercritical.

7.4.2 Development program of advanced ultrasupercritical power plants in Japan 7.4.2.1 Development system and sequence Following the USC technology development program, Japanese boiler, turbine, and valve manufacturers, institutes, and utility companies developed 700
C class A-USC technology between 2008 and 2016 with the support of Ministry of Economy, Trade and Industry (METI) and New Energy and Industrial Technology Development Organization (NEDO).

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Table 7.3 Candidate materials in Japanese ultrasupercritical development program for duration demonstration test: (1) steam side duration test and (2) gas side corrosion test. Item

Steel

Nominal composition

1. Steam side duration test 595
C SH (fifth SH)

650
C SH (sixth SH)

Header

Piping Valve

STBA24 Super9Cr HCM9M SUS321HTB SUS321HTB (inner surface fine grained) SUS321HTB chromized SUS347HTB SUS347HTB chromized TP347H (fine grained) TP347H TP347H (fine grained) TP347H chromized Tempaloy A-1 Tempaloy A-1 chromized 1714CuMo 1714CuMo chromized 1714CuMo/310 (composite tube) HR3C NCF800HTB STPA23 HCM9M Super9Cr SUS316HTP Super9Cr SUS316HTP SUSF316H SCS14A

2.25Cr1Mo 9Cr1MoVNbN 9Cr2Mo 18Cr10NiTi 18Cr10NiTi

18Cr10NiTi 18Cr10NiNb 18Cr10NiNb 18Cr10NiNb 18Cr10NiNb 18Cr10NiNb 18Cr10NiNb 18Cr10NiTiNb 18Cr10NiTiNb 17Cr14NiCuMo 17Cr14NiCuMo 17Cr14NiCuMo/25Cr20Ni 25Cr20NiNbN 21Cr32NiAlTi 11/4Cr0.5MoSi 9Cr2Mo 9Cr1MoVNbN 18Cr12NiMo 9Cr1MoVNbN 18Cr12NiMo 18Cr12NiMo (forging) 18Cr12NiMo (casting) (Continued)

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Table 7.3 (Continued) Item

Steel

Nominal composition

2. Gas side corrosion test Tubes

Attachment

STBA24 STBA26 HCM9M NSCR9 Super9Cr X20CrMoV121 HCM12 SUS321HTB SUS347HTB TP347HTB Tempaloy A-1 1714CuMo 1714CuMo, NiCr sprayed 1714CuMo chromized 1714CuMo/310 (composite tube) Esshete 1250 HK4M HR3C NCF800HTB SUS405 SUS410S SUS410L SUS430 YUS409D SN9 NAR160 SUS304 SUS309S NAR305B FH-11 45Cr30Ni

2.25Cr1Mo 9Cr1Mo 9Cr2Mo 9Cr2MoVNb 9Cr1MoVNbN 12Cr1MoV 12Cr1Mo1WVNb 18Cr10NiTi 18Cr10NiNb 18Cr10NiNb 18Cr10NiTiNb 17Cr14NiCuMo 17Cr14NiCuMo 17Cr14NiCuMo 17Cr14NiCuMo/25Cr20Ni 15Cr10Ni6Mn1MoVNbB 25Cr25Ni 25Cr20NiNbN 21Cr32NiAlTi 13Cr 12Cr 12Cr 17Cr 11CrTi 11Cr2Si 17CrNbCu 18Cr10Ni 25Cr12Ni 20Cr13Ni3.5Si 17Cr2.5SiNbN 45Cr30NiAlTi

Source: Data from New Energy and Industrial Technology Development Organization (NEDO) home page, ,https:// www.nedo.go.jp/activities/ZZJP_100115.html. (accessed 24.05.20).

The A-USC technology was developed based on today’s latest 600
C class USC technology. The target of the A-USC project is to develop 700
C class material and component technologies by raising the steam temperature 100K to achieve HHV base net thermal efficiency of 46%HHV-net of coal-fired power generation, aiming

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Figure 7.12 Photo of demonstration test at 650
C. Source: Observation of component test for main steam pipe, Courtesy J-POWER.

Figure 7.13 Enhanced 650
C ferritic steel. (A) Creep-rupture date for welded joints of Boron added 9Cr steel and conventional 9Cr steel. (B) Creep-rupture date for CSEF steel. CSEF, Creep strengthenhanced ferritic. Source: Data from F. Abe, Rising the durability of steels for power plant, in: 7. Ferritic Strength Materials, Sec. 3, Article 5, NIMS Research Outlook, 2006, pp. 334339 (in Japanese).

at 48% HHV-net at 750
C in the future. That means more than 10% reduction in CO2 emissions, which is the same level as the IGCC described in Section 6.3.3. Fig. 7.15 shows the project structure [28]. Fig. 7.16 shows the master schedule of the project [9]. During the first half of the project, basic materials and manufacturing technology for boilers, turbines, and valves were developed and verified. In the second half of the project, the boiler component test and the turbine rotating tests

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Figure 7.14 Progress in development of 9%Cr and 12%Cr CSEF steels. CSEF, Creep strengthenhanced ferritic.

Figure 7.15 Project structure [29].

were carried out to check the components’ reliability. Throughout the project, longterm creep-rupture tests were done on each candidate material and welded joint.

7.4.2.2 Material development for advanced ultrasupercritical power boilers Further efforts to elevate steam temperature, higher than 650
C up to 700
C, have been made from 2008 to 2016, applying Ni-based superalloy for the candidate

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Figure 7.16 Master schedule [30].

material applicable to tubes and large diameter pipes, which is categorized as AUSC development. The candidate A-USC materials to be verified and demonstrated are shown in Table 7.4 and in Fig. 7.17. Realizing A-USC unit requires materials with excellent creep-rupture properties and corrosion resistance at elevated temperature. Fig. 7.18 shows the comparison in the creep strength among USC and A-USC materials, and the same creep strength as CSEF steels (for pipe and header) and austenitic stainless steels (for heating tube) have at around 600
C is expected to be attained by Ni-base superalloy at around 700
C. Evaluation for candidate materials and verification for boiler components fabrication had been carried out untill 2012 as shown in Fig. 7.19 [31], followed by components demonstration test in an industrial boiler in 201516 as shown in Fig. 7.20 [30,32]. The boiler component test facility flowchart is shown in Fig. 7.21 consisting of superheaters, pipes, valves, and a turbine casing, and there confirmed to be applicable to required durability. Corrosion resistance capability is also confirmed as explained in Section 7.5.2. Ni-based superalloy has a merit to compose long and large size components, such as headers and leading pipes to mitigate apprehension against thermal stress induced by the force and momentum due to thermal expansion, because of lower thermal expansion rate in between low-alloy CrMo steels austenitic stainless steels. This apparatus is much recommendable to avoid the incident such as at Eddystone unit 1 main steam piping made of Type 316 stainless steel, as explained in Section 7.3. As for long-term creep property for Ni-based superalloy, some of them have been tested more than 100,000 hours, and good weldability and weld performance were confirmed [1,3335].

Table 7.4 Candidate materials for advanced ultrasupercritical boiler. Material name

Composition

Thick large diameter pipe

Small diameter tube

High-temperature header and connecting pipe Main steam pipe Hot reheat steam pipe    Header Connecting pipe (up to around 650
C)

Hot heat transfer tube

HR6W HR35 Alloy617

Ni based Ni based Ni based

45Ni23Cr7W 50Ni30Cr4WTi Ni22Cr12Co9MoTiAl

Alloy263 Alloy740 Alloy141 HighB-9Cr steel

Ni based Ni based Ni based Advanced ferritic steel Advanced Ferritic steel Advanced Ferritic steel

Ni20Cr20Co6Mo2TiAl Ni20Cr20Co2Nb2TiAl Ni20Cr10Mo2TiAl 9Cr3W3CoNbVB

Low C-9Cr steel SAVE12AD

Heat transfer tube (temperature range similar to conventional high Cr steel)

0.035C9Cr2.4W1.8CoNbV

9Cr3W2.6CoNbVB

Source: Data from New Energy and Industrial Technology Development Organization (NEDO), Project on component technology development for commercial use of A-USC thermal power generation, fact sheet (2016) (in Japanese).

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Figure 7.17 Plates made of candidate materials [30].

Figure 7.18 Comparison of 100,000 h creep strength for each material.

From 2017 untill 2022, A-USC components test program has been continued under the support of NEDO [26]. In that period, large diameter pipe creep test with actual size at multiaxis stress state and creep tests for two of Ni-based superalloy have been conducted, targeting header and pipes in order to verify life prediction analysis method together with nondestructive examination (NDE) evaluation, as shown in Fig. 7.22, which is the same test facility as conducted for Gr. 91 material [36,37]. It is recognized that the cost of Ni-based superalloy for a A-USC plant would be higher than that of a USC plant [38]; however, the higher thermal efficiency of the A-USC technology contributes to the reduction of the fuel cost and the environmental cost. In addition the public pressure worldwide to reduce the CO2 emissions

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Figure 7.19 A-USC material evaluation and manufacturing (200812) [31]. A-USC, Advanced ultrasupercritical.

Figure 7.20 A-USC components demonstration test (201516) [30]. A-USC, Advanced ultrasupercritical.

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Figure 7.21 Boiler component test facility flowchart [29].

Figure 7.22 A-USC large size components test at multiaxis stress state (201722). A-USC, Advanced ultrasupercritical. Source: Reproduced by permission from M. Yaguchi, T. Sakai, T. Ogata, T. Matsumura, Internal pressure creep test on grade 91 steel longitudinal welded pipe, in: HIDA-6 Conference, Nagasaki, Japan, December 2013; M. Yaguchi, N. Miura, T. Ogata, T. Sakai, Development of component test facility “BIPress: bending & internal pressure on real structural samples”, in: Material Science Research Laboratory Rep. No. Q08001, CRIEPI, 2008 (in Japanese).

would be a clear driver to promote the commercialization of the A-USC technology. Some of the measures to apply the outcome of A-USC development program have been studied, such as partial replacement of high-temperature components, superheater/reheater panels, final outlet headers, leading pipes to turbine and highpressure turbine, to increase operating temperature and like to diminish leading pipes length by adoption “L-shaped boiler” with inverse gas flow as illustrated in Fig. 7.23 [39], and in China, actual USC units applying this concept have been constructed [40].

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Figure 7.23 L-shaped boiler with inverse gas flow [39].

7.5

Aspects of metallurgy and stress analysis

Since steam cycle configuration of USC or A-USC unit is basically nothing changed from that of SC, even if it is single-reheat or double-reheat system, the issue to realize the cycle is the development and utilization of materials with excellent creep-rupture properties and corrosion resistance at elevated temperature. Good manufacturability (bending, welding) is also required. Hereunder very briefly, the important aspects which thermomechanical engineers of steam generator are ought to be aware of, concerning metallurgical and stress analysis.

7.5.1 Creep-rupture properties It is a common sense widely acknowledged, “the leading cause of mechanical failure of boiler in thermal power plant is a failure of creep rupture excluding abnormal overheating by miss operation and so on” [8] [summarized wording from D. N. French, Metallurgical Failures in Fossil Fired Boilers, Wiley-Interscience, New York (1983), p. 2].

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Figure 7.24 Creep degradation of CSEF steel. CSEF, Creep strengthenhanced ferritic.

Designers must take into account the metallurgical property, at which temperature the material is in use, in time-independent (lower temperature) region or timedependent (higher temperature) region. In the latter region the lifetime is certainly affected by creep-rupture strength, which begins to govern the allowable stress value around or a little lower than 400
C for carbon steels, 500
C for low-alloy CrMo steels, 550
C for CSEF steels, and 600
C for austenitic stainless steels. Metallurgical aspect of creep process of CSEF steel is briefly explained as next, illustrated in Fig. 7.24, where in the right sketch, precipitates of M23C6 (complex cubic carbide with Cr or Mn, etc.) and MX [Nb(C, N); niobium carbide or nitride or V(C, N); vanadium carbide or nitride] located on boundaries of the grains; prior austenitic grain, packet, block, and lath (shape like bamboo leaf) have a function to restrict the distortion of the grains. Continuous stress degrades its function and initiates cavity, followed by creation of void, then coalesce into microcrack, thus, into macrocrack that induces fluid leakage, finally burst of the component.

7.5.1.1 Development of creep strengthenhanced ferritic steel Historical improvement of creep-rupture strength of boiler steels is illustrated in Fig. 7.25. One of the typical CSEF steels, modified 9Cr1Mo (ASME Grade 91 like SA-213-P91, ASME: The American Society of Mechanical Engineers), had been developed based on conventional 9Cr1Mo (ASME Grade 9 like SA213-T9) under the program supported by EDRA (former of DOE: Department of Energy, the United States) as a strategic material applicable to fast breeder reactor, aiming less content of chromium (Cr). It was produced by differentiating chemical specification from the conventional alloy, such as (1) an addition of small amount of

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Figure 7.25 History of improvement for creep-rupture strength of USC boiler steels. USC, Ultrasupercritical.

niobium (Nb) and vanadium (V), (2) a narrower range for each element, and (3) a stipulation of nitrogen [41], as listed in Table 7.5. This modification was intended to have, at elevated temperature, precipitation strengthen effect that is interpreted as fine precipitate particles (M23C6: complex cubic carbide with Cr or Mn, etc.) nucleated on vanadium and niobium carbide or nitride: (V, Nb) (C, N). Tempering heat treatment is essential to produce the precipitates mentioned earlier with high ductility and toughness. These strengthening effects are illustrated schematically in Fig. 7.26, and briefly interpreted as (1) precipitates created by the addition of microcomponents restrict distortion of grain, which contributes to delay strength reduction by creep, (2) martensitic formation by quenching brings three types of strengthening mechanism, lath structure of minute substance, solid solution with oversaturated carbon, and work hardening by rich dislocation density. Finally, tempering is conducted in order to release residual stress and to obtain workability and ductility. Thus this steel had excellent high-temperature durability superior not only to ordinal low-alloy (CrMo) steel such as A335-P22 used for SC but also to the conventional 9Cr1Mo steel as described in Fig. 7.27 [41]. Gr. 91 has been widely and massively applied to USC units worldwide after first full-scale application for superheater outlet header and main steam pipes at Chubu Electric Power Co. Ltd. (from 2015 JERA Co., Inc.) Kawagoe no. 1 and 2, Japan,

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Table 7.5 Chemical components of modified 9Cr1Mo steel compared with conventional 9Cr1Mo. Content range (wt.%) Element

Modified 9Cr1Mo (Grade 91)

Conventional 9Cr1Mo (Grade 9)

Carbon Manganese Phosphorus Sulfur Silicon Chromium Molybdenum Nickel Vanadium Niobium Nitrogen Aluminum

0.080.12 0.300.60 0.020 max 0.010 max 0.200.50 8.009.50 0.851.05 0.40 max 0.180.25 0.060.10 0.0300.070 0.04 max

0.15 max 0.300.60 0.030 max 0.030 max 1.00 max 8.0010.00 0.901.10

Source: Data from W. Feng, L. Li, A new degree of all turbine casings elevated arrangement for high-efficiency double reheat units, in: 2019 IEA Clean Coal Technologies Conference (IEA CCT 2019), Houston, TX, 2019.

Figure 7.26 Enhancement mechanism of strengthen in CSEF steel. (A) Dislocation in high density restrains deformation of microstructure against stress. (B) The finer distribution of precipitate particles (M23C6) adds to the strength and its retarded growth holds the strength for long periods of time at the service temperature.

700 MW LNG units 31 MPa, 566
C/566
C/566
C, in 1989 and 1990. In this power station, reductions both in fatigue damage brought by the thinner wall thickness and in steam oxidation by the higher content of Cr were also intended. Other CSEF steels, Gr. 92, Gr. 122, etc., have the same methodology to strengthen creep-rupture properties and have been also widely applied to USC units

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Figure 7.27 Stress-rupture plot of 9Cr1Mo steel. Source: Data from V.K. Sikka, Development of modified 9 Cr-1 Mo steel for elevatedtemperature service, in: Proc. TMS/AIME Topical Conference on Ferritic Alloys for Use in Nuclear Energy Technologies (CONF-830659-16), Snowbird, UT, 1983.

worldwide, in reflection of the outcome of the development programs conducted in Japan, Europe, and the United States, as described in Section 7.4.

7.5.1.2 Revised allowable stress and its account The first incident of CSEF steel had been investigated in Japan, 2004. A steam leakage occurred at hot reheat pipe of long seam welded, ASME Gr. 122 at 595
C, after 35,000 hours service in 700 MW plant. The cause had been reported to be the overestimation of long-term creep strength of base material and welded joint as the result of extensive analysis work. As for Gr. 91 steel, three long seam welded pipe failures were reported [7], which included the incident after 65,000 hours service in 2001 [42]. Accumulated outcomes have been reported worldwide [4346], and collaboration had started among Japan, Europe, and the United States, sharing the data and providing them to authorities.

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Figure 7.28 Revision history of CSEF steel allowable stress in Japan. CSEF, Creep strengthenhanced ferritic.

It was pointed out that the actual creep-ruptured strength is less than extrapolated 100,000 hours strength from those obtained in relatively short term with high stress, while at the time, EU organizations had been argued that minimum 30,000 hours creep tests were needed [7]. In Japan, METI had revised allowable stress several times for CSEF steels. Those figures for Gr. 91, for example, are described both for base metal and welded joint as Fig. 7.28, in which the deduction is to 82% of originally registered value in base metal (tube), from 66 to 54 MPa and to 54% in welded joint, from 66 to 35.4 MPa at 600
C, which is based upon amendment information published by METI on July 9, 2019. ASME also revised to 83.5% of originally registered value (tube), from 65.0 to 54.3 MPa at 600
C, which was published by Sec II Part A, D of Boiler and Pressure Vessel Code (2019), and previously developed supplement 7 of Code Case 2864 Sec II Part D (2017) had narrowed the range of chemical compositions and regulated stringent heat treatment condition, the effect of which is accounted in Section 7.5.1.3.1. The cause of this deduction has been so explained metallurgically as summarized and interpreted in Fig. 7.29, that microstructure degradation behaviors at high stress and at low stress are very different from each other. At high stress, deformation of tempered martensitic microstructure takes place rapidly because the higher stress actively promotes recovery of displacement the more homogeneously so as to deform plastically and then brings significant decrease in rupture time. At low stress, deformation of the microstructure takes place slowly because the effect of the lower stress concentrates in vicinity of gain boundary and coarsens precipitates before extending inside the grain, which proceeds inhomogeneously, and then it ruptured [47,48]. Another mechanism is also presented, such as the suggestion that gain size is the dominant cause of increasing creep-rupture strength in long-term region, and that boundary sliding is an important deformation mode at the low strain rate [49].

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V

Low stress

V

High stress

Big degradation at short term

Homogeneous dislocation recovery

C LMP=20(conventional)

Previous fit curve at C LMP=38 Short term

Long term

tR Time to rupture (h)

tR (time to rupture)

Inhomogeneous dislocation recovery

Overestimation based on high-stress data C LMP: Constant of Larson–Miller parameter

Figure 7.29 Mechanism of creep strength degradation. Source: Dawn referring to K. Kimura, H. Kushima, K. Sawada, Long-term creep strength prediction of high Cr ferritic creep resistant steel based on degradation mechanism, in: Sixth International Charles Parsons Turbine Conference, Dublin, 2003, pp. 444456.

Although the conventional wisdom for ferritic steel had presented around 20 for C value of LarsonMiller parameters (CLMP), the data obtained in short term provided 3238 for C in development of the best fit curve. This caused relatively lower inclined curve, thus overestimated the strength in long term and low-stress region. Even when evaluating by C value of around 20 in low-stress region, this CSEF steel is still stronger than noncreep strengthenhanced 9%Cr steel, such as footnoted in Fig. 7.28. For reference, since the degradation rate in welded joint is large, one of the examples of countermeasures in order to prolong the service life by thermomechanical compensation of cooling down the limited area near around welded joint is invented and patented, such as Japanese Patent 6289347.

7.5.1.3 Management for creep strengthenhanced ferritic steel This material, which has the properties in between low-alloy and austenitic stainless steel in strength, corrosion resistance and cost, is an inevitable one that reasonably realizes USC/A-USC boiler with economic feasibility. Unless otherwise developed and utilized, those of the wisdom obtained within the recent two decades, later described briefly, have been and will be applied to new construction and existing units.

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7.5.1.3.1 Quality improvement Quality control for CSEF steel both in manufacturing at steel producer and in fabrication at component assembler, as such as fine adjustment of chemistries and stringent control of heat treatment condition have been discussed in the ASME Boiler and Pressure Vessel Code Committee for CSEF steel [50]. Its outcome has been reflected to ASME code as mentioned in Section 7.5.1.2. This could be understood that the original philosophies for strengthening creep property of Gr. 91, precipitation strengthening, and displacement strengthening, are thoroughly intensified. Simultaneously, deviation of chemical composition within one product should be considered, as has been illustrated in Fig. 7.30. The standard deviation value for Cr concentration within 40 µm width along with wall thickness has strong relation to decrease in creep-rupture time. It has been also reported that the creep-rupture time is prolonged in a certain time by renormalization followed by tempering with standard heat treatment condition and that segregation should be reduced to obtain high creep strength with homogeneous concentration of chemical composition [51]. Undesired contaminants, such as phosphorus (P), sulfur (S), or aluminum (Al) which form substances with no contribution to precipitates strengthen effect, are to be of course strictly eliminated.

7.5.1.3.2 Enhancement of heat-affected zone The MARBN steel, being one of the outcomes of Japanese national project 1997-2007, is superior to other materials in termed of creep-fatigue damage as illustrated in Fig. 7.13. The creep property of this material is closely concerned with the solid solution of boron (B) and nitrogen (N) corresponding to the white area illustrated in Fig. 7.31. Well controlled fraction of these two elements and absolute levels contribute largely to strengthening, while excessive amount of either element leads to the

Figure 7.30 Relation between deviation of Cr concentration and time to rupture [51]. (A) Cr concentration represented with contrast. (B) Time to rupture. Source: Reproduced by the permission from The Iron and Steel Institute of Japan (ISIJ).

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Figure 7.31 Boron and nitrogen solubility in 9Cr steels. Source: Data from F. Abe, Precipitate design for creep strengthening of 9% Cr tempered martensitic steel for ultra-supercritical power plants, Sci. Technol. Adv. Mater. 9 (1) (2008). https://doi.org/10.1088/1468-6996/9/1/013002.

formation of boron nitrides (BN) being not fully dissolved into matrix during solidification process of the heat treatment [52,53]. Reflecting on the abovementioned effect, SAVE12AD steel (Gr. 93) had been developed to contain 0.01% B for suppressing M23C6 coarsening on the grain boundary and to contain 0.02% neodymium (Nd) for grain boundary strengthening with preventing sulfur segregation. Simultaneously, in order to keep stability of fine MX and suppress BN precipitation, N content is set low, resulting in resistance of creep-rupture strength degradation [54,55]. It has been also reported that the effect of controlling B/N ratio could be observed to enhance creep strength against Type IV fracture as shown in Fig. 7.32 at welded joint [56,57].

7.5.1.3.3 Life prediction It is also a common sense widely acknowledged that there is neither an explicit nor an implicit expression for design life associated with the stipulated allowable stresses, which means it ultimately owes installer’s responsibility to avoid incident or accident caused by failure such as creep damage. This policy of self-responsibility has been accepted, such as in Japan Electric Business Act-1995. The process of establishing allowable stress in each code/norms is the methodology defined, respectively, with the intention that sufficient margin is provided in the allowable stress to preclude failure during normal operation for any reasonable life of boilers constructed according to the regulation. For example, ASME, JSME (The Japan Society of Mechanical Engineers), and EN (European Norm) stipulate

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Figure 7.32 Type IV fracture at welded joint. (A) Classification of cracking. (B) Example of failure of welded joint [57]. Source: (A) Drawn referring to D.J. Abson, J.S. Rothwell, Review of type IV cracking of weldments in 9-12%Cr creep strength enhanced ferritic steels, J. Int. Mater. Rev. 58 (8) (2013), 437473. Table 7.6 Methodology for allowable stress calculation defined by each code/norm. Japan

ASME Sec. I

EN 12952

Not to exceed the lowest of the following: 0.67SRavg—100,000 0.8SRmin—100,000 1.0SC Not to exceed the lowest of the following: FavgSRavg—100,000 0.8SRmin—100,000 1.0SC 0.8SRavg—200,000 0.67SRavg—100,000

SRavg—100,000: average stress to cause rupture at the end of 100,000 h SRmin—100,000: minimum stress to cause rupture at the end of 100,000 h SC: average stress to produce a creep rate of 0.01%/1000 h. SRavg—200,000: average stress to cause rupture at the end of 200,000 h Favg: 0.67 at 815
C and below Above 815
C, it is determined from the slope of the log time-to-rupture versus log stress plot at 100,000 h such that log Favg 5 1/n, but it may not exceed 0.67. Source: Data from V.K. Sikka, Development of modified 9 Cr-1 Mo steel for elevated-temperature service, in: Proc. TMS/AIME Topical Conference on Ferritic Alloys for Use in Nuclear Energy Technologies (CONF-830659-16), Snowbird, UT, 1983.

the allowable stress, considering tensile strength, yield stress, and creep strength as descried in Table 7.6. The abovementioned two paragraphs suggest that, in order to secure the selfresponsibility, judgment based upon life prediction evaluation with inspection is vital. As for METI, linked to the revision of allowable stress, equation for estimating

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Table 7.7 Lifetime estimation for creep strengthenhanced ferritic steels welded joint. Welds

Region

a0

a1

a2

C

SEE

Gr. 122

Short term Long term All region Short term Long term Short term Long term

35,081.0 24,670.0 34,154.0 8716.0 24,076.0 34,544.0 23,290.0

21,655.0 1225.3 3494.0 28,199.0 1685.0 27090.0 22631.0

27952.3 21237.8 22574.0 28409.0 21332.0 0 0

47.0 21.0 31.4 31.0 20.8 19.4 16.6

0.316 0.192 0.267 0.412 0.150 0.272 0.076

Gr. 91 Gr. 92 Gr. 23

tR: creep-rupture life (hours); a0, a1, a2, C: constant; SEE: standard error of estimation T: temperature (K), σ: stress (MPa) LarsonMiller parameter regression equation for estimating creep-rupture life of welds logðtR Þ 5 aT0 2 C 1 aT1 logσ 1 aT2 ðlogσÞ2 2 2:33 3 SEE Source: Data from V.K. Sikka, Development of modified 9 Cr-1 Mo steel for elevated-temperature service, in: Proc. TMS/AIME Topical Conference on Ferritic Alloys for Use in Nuclear Energy Technologies (CONF-830659-16), Snowbird, UT, 1983.

creep-rupture time of welded joint is presented in NISA-234a-07-4, published in 2007, as explained in Table 7.7. Region split method is adopted in it, reflecting the observation result that deformation process in high- and low-stress regions is strongly related to be plastic or not, Thus the boundary between the regions is referred to as the elastic limits defined as half of 0.2% proof stress [47,48].

7.5.1.3.4 Analysis in multiaxial stress field Generally, it had been a common approach to apply maximum principal stress to design the components and evaluate the damage by stress analysis method; however, von Mises equivalent stress based upon maximum distortion criterion and other defined stresses have been considered to evaluate the possibility to coincide the analyzed damage amount with ruptured test result. Fig. 7.33 shows that, comparing with expected creep-rupture lifetime (stress) using uniaxial rupture data of Gr. 91, because the maximum principal stress (A) showed a higher stress value than the von Mises equivalent stress (B), so the former gave a conservative prediction than the latter [58]. Both stresses reflect multiaxial stress state, and how they can account the reality depends on the extent of multiaxial stress state, such as influenced by thickness. There is a case that maximum principle stress can account for Type IV fracture at thick part. Unstable precise elastic-creep analysis using finite element method (FEM), which combines newly developed long-term creep life prediction and stressstrain curve considering multiaxial stress state, can present precise result of rupture time and point, as illustrated in Fig. 7.34, where an inspection nozzle is installed at main steam pipe. At time “zero” the maximum stress point is located at the edge of inner surface of the nozzle as is commonly known, and then after 100,000 hours the middle of the wall thickness becomes the maximum stress point that coincides the actual failure [59].

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Figure 7.33 Evaluation on governing stress for creep-rupture time. (A) Maximum principal stress. (B) von Mises stress. Source: Data from T. Himeno, Y. Chuman, T. Tokiyoshi, T. Fukahori and T. Igari, Creep Rupture Behavior of girth-welded mod. 9Cr-1Mo steel pipe subject to internal pressure and axial load, in: Proc. Sixth Int. High-Temperatures Defect Assessment Conference (HIDA-6), Nagasaki, 2013, pp. 110.

Stress analysis and creep-rupture data in multiaxis condition have become necessary for precise prediction in reflection of the strong relationship between stress distribution and creep void density distribution under multiaxis stress field, as described, for example, in Fig. 7.35 as the information obtained from relatively long-term notch bar tests. The highest number density of creep voids recorded in the cross section at the root of the notch slightly away from the surface as shown in Figs. 7.35B and 7.35C, and the variations in creep void density are a direct consequence of variations in the stress state as shown in Fig. 7.35A [6064]. In A-USC components test program, actual size component test for header and pipes of two of Ni-based superalloy with large diameter at multiaxis stress state have been conducted in order to obtain clear and precise observation for fracture and verify life prediction analysis method together with NDE evaluation till 2022, as introduced in Section 7.4.2.

7.5.1.3.5 Nondestructive testing and examination Microcomponents, ductility, hardness, etc. will scatter and then straintime curve scatters, which automatically mean that the result of elastic-creep analysis mentioned earlier (Section 7.5.1.3.4) based upon a certain stresstime curve will also

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Figure 7.34 Management for existing units. Source: Data from T. Tokiyoshi, H. Katafuchi, T. Honda, K. Tominaga, H. Ohyama, Base metal failure analysis for nozzle-to-pipe connection of CSEF steel, in: EPRI Expert Workshop on Structural Integrity of Components in High Temperature Applications in Collaboration with ASME PVP2019, Session 6, 2019.

Figure 7.35 Distribution of creep voids around notch region. (A) Maximum principal stress [60], (B) creep void distribution, and (C) number density of void [61]. Source: Courtesy Dr. J. Siefert and Dr. J. Parker of EPRI.

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scatter. Although the situation is like as above, allowable stress and life prediction formula have been developed to have reasonable accuracy to preclude failure as much as possible based on state-of-the-art methodology. However, if it is not clear that the properties of component would lie within the range of the population that consists on basis of developed principles, nondestructive testing (NDT)/examination is recommendable. It is important to have recognition that most “minimum” values do not always reflect a “real minimum” value, and that a 95% confident interval (CI) does not equate to probability; for example, it is not accurate to say that a 95% CI means 95% of the data lie above the lower limit. The other point to raise is that the location of a “real minimum” would not be the place we are taking care. It might be at welded metal, not heat-affected zone that might occur due to quite low ductility because of poor welding performance. Damage detection capability with accuracy can be secured by NDT (PT, MT, RT, UT, etc.) for flaws and NDE (replication, hardness, electrochemical, physical properties, etc.) for material degradation to microcrack (lattice defects up to one grain size cracks) as is explained for some of them in Section 9.5.1, such that damages of creep, fatigue, corrosion and interaction of those, brittle fraction due to embrittlement, loss of specified properties by thermal aging (microstructural degradation), etc. can be detected. Fig. 7.36 represents one of the examples describing relation between detected number density of cavity and creep life fraction (time divided by anticipated rupture time) for the surface of Gr. 91 base metal by

Figure 7.36 Number density of cavity versus life fraction of Gr. 91 tube base metal. Source: Data from F. Masuyama, Long time reliability and life assessment of Gr.91 and CSEF steels for boiler and steam line components, in: The First International 9%Cr CSEF Steels Conference, Beijing, October 2018.

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replication method [65], and each creep life fraction should be evaluated according to the master curve for each portion. Phased array UT is effective to detect internal congestion state of creep voids as explained in Section 9.5.1. Conventionally, hardness detection is effective for assessment for creep life, because the hardness reflects the change in precipitates/lath structure, which strongly relates to creep life fraction.

7.5.2 Corrosion resistance properties Components are also exposed to severe corrosion atmosphere due to the elevated steam temperature. Corrosion at gas side is discussed in Section 4.2.4.5, and that at water side is described in Section 4.4. Corrosion at steam side is the steam oxidation being considered to be driven by the oxygen generated by dissociation of steam. An increase in steam temperature accelerates the oxidation controlled by iron oxide equilibrium, thus the countermeasure to suppress the oxidization is important issue for USC and A-USC conditions. Scale exfoliation from superheater and reheater with flake shape may cause blockage tube bends when the amount becomes too much. Furthermore, it may erode steam turbine nozzle block of which shape is one of the key factors for better turbine efficiency. On both sides, corrosion decreases the component thickness required for strength, furthermore, steam oxidation layer act as heat resistance to increase the temperature of heated component, which may accelerate creep damage. Generally, higher Cr concentration suppresses both gas side corrosion and steam oxidation, and finer grain size contributes to suppress steam oxidation in austenitic stainless steels, as illustrated in Fig. 7.37. Shot-blast treatment inside the tube to attain deformation near the surface is also effective to suppress steam oxidation as well as fine grain in austenitic stainless steels. The materials of 12%Cr have been under development reflecting the preferable effect by higher percentage of Cr contents comparing 9%Cr [66]. The effect of this is also confirmed for A-USC materials as shown in Fig. 7.38, where Fig. 7.38A shows the average weight loss per given unit in the corrosion test plotted against the Cr contents, and Fig. 7.38B shows the steam oxidation property, that is, the average thicknesses of steam oxidation scale after 10,000 hours of steam exposure.

7.6

Concluding remarks

This chapter briefly reviewed recent development in USC and A-USC power plants and the state-of-the-art material technology for USC and A-USC boilers, including not only the properties of developed materials but also maintenance related issues, for example, management of lifetime and NDT. The A-USC technology development project is going on in Japan, and thus the description hereinabove may give the readers the vivid and valuable information, even though a brief review.

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Figure 7.37 Suppress high-temperature corrosion. (A) Relation of Cr contents in alloy and quantity of high-temperature corrosion reduction [67]. (B) Relation of Cr contents and steam oxidation [68]. Source: Reproduced by permission from Thermal and Nuclear Power Engineering Society.

Figure 7.38 Corrosion resistance properties of A-USC materials. (A) High-temperature corrosion property [69]. (B) Steam oxidation property [70]. A-USC, Advanced ultrasupercritical.

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References [1] T. Tokairin, K. Hashimoto, K. Kubushiro, M. Fukuda, Development of boiler material technology and the verification of its practical applicability in Japanese National A-USC Project, in: 43rd MPA-Seminar, Stuttgart, 2017. [2] N.L.S. Carnot, Reflexious sur la Puissance Mortice du Feu et sur les Machines, Chez Bachelier, Libraire, Paris, 1824. [3] The Institute of Electrical Engineers of Japan, Handbook of Electrical Engineering, seventh ed., Ohmsha, 2013, p. 1096. [4] F. Mu¨nzinger, Dampfkraft: Berechnung und Bau von Wasserrohrkesseln und ihre Stellung in der Energieerzeugung, 2 aufl, Julius Springer, Berlin, 1933. [5] E.V. Somova, E.H. Verbovetsky, A.L. Schwarz, Development of Coal-Fired Boilers with Ultra-Supercritical Steam Parameters in Russia [original: Докладчик Сомова Елена Владимировна, к.т.н. Соавторы Вербовецкий Э.Х., Шварц А.Л., д.т.н. Разработка пылеугольных котлов на суперсверхкритическиепараметры в РоссииVTI] https://docplayer.ru/42339983-Razrabotka-pyleugolnyh-kotlov-na-supersverhkriticheskie-parametryv-rossii.html (accessed 31.03.20). [6] T. Daikoku, T. Tsuchiya, F. Masuyama, W.F. Siddall, K. Setoguchi, F.V. Ellis, et al., Operating experience and reliability evaluation on main steam line pressure parts of ultra-supercritical (USC) power plant, Mitsubishi Heavy Ind. Ltd. Tech. Rev 22 (1985) 1222. [7] EPRI, ENEL, Survey of ultra-supercritical coal power plants in Japan and China: phase I & II, in: Report No. 1020526, EPRI, Palo Alto, CA and ENEL, Pisa, Italy, 2009. [8] K. Kimura, Safety Preservation for High Temperature Machinery Based on Several Years Long Term Creep Test, Institute Technology, 2006, p. 7. [9] M. Fukuda, Advanced USC technology development in Japan, in: 9th Liege Conference: Materials for Advanced Power Engineering 2010, Forschungszentrum Ju¨lich, 2010, pp. 317. [10] Q. Zhu, Historic Efficiency Improvement of the Coal Power Fleet, CCC/300, IEA Clean Coal Center, 2020. [11] L. Wenkai, Development and prospect of double reheat technology in China, in: IEA Clean Coal Center 3rd Workshop “AUSC3”, Rome, 2017. [12] M. Wani, H. Fukuda, M. Tsuchiya, T. Fujikawa, T. Yamamoto, Design and operating experience of a1000MW steam turbine for the Chugoku Electric Power Co., Inc. Misumi No. 1 Unit, Mitsubishi Heavy Ind. Ltd. Tech. Rev. 36 (3) (1999) 6669. [13] S. Kaneko, K. Yamamoto, M. Kinoshita, Y. Wakabayashi, Y. Iida, Design and operating experience of a 1000-MW ultra supercritical coal fired boiler with steam condition of 25.4-MP 604/302
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[18] P. Bernard, DP700-phase 1 preparation for commercial demonstration of 700
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C steam power plants, in: IEA Clean Coal Center 3rd Workshop “AUSC3”, Rome, December 2017. [21] R. Purgert, H. Hack, United States advanced ultra-supercritical project including fullscale 760
C superheater and steam turbine components, in: 2019 IEA Clean Coal Technologies Conference, IEA CCT 2019, Houston, TX, 2019. [22] X. Ping, China’s Key Component Test Facility of 700
C Advanced Ultra-Supercritical Coal-fired Power Generation Unit, Huaneng Clean Energy Research Institute (2017). [23] A. Kumar, Indian AUSC program, in: 2019 IEA Clean Coal Technologies Conference, IEA CCT 2019, Houston, TX, June 4, 2019. [24] B.G. Setty, A.P. Samal, S. Pande, A long view on AUSC programs calls for vastly improved global technology processes, in: IEA Clean Coal Center 3rd Workshop “AUSC3”, Rome, December 2017. [25] F. Abe, Rising the durability of steels for power plant, in: 7. Ferritic Strength Materials, Sec. 3, Article 5, NIMS Research Outlook, 2006, pp. 334339 (in Japanese). [26] NEDO, New Energy and Industrial Technology Development Organization (NEDO) Home Page. https://www.nedo.go.jp/activities/ZZJP_100115.html (accessed 24.05.20). [27] T. Otsuka, Development history and operational experience of ultra-supercritical (USC) power plants, in: Int. Conf. on Power Engineering 2007, Hangzhou, 2007. [28] Y. Nakabayashi, H. Yugami, J. Iritani, H. Haneda, M. Miyazawa, Y. Nishimoto, et al., Field test and evaluation of high temperature materials for ultra super critical (USC) power plant boiler, Mitsubishi Heavy Ind., Ltd. Tech. Rev. 23 (1986) 1019. [29] M. Fukuda, T. Nishii, The Japanese Program on Developments for New High Efficiency Power Plants and Progress in 700
C A-USC Technology Development, in: 41st MPA Seminar, Stuttgart, University of Stuttgart, October 2015. [30] New Energy and Industrial Technology Development Organization (NEDO), Project on Component Technology Development for Commercial Use of A-USC Thermal Power Generation, Fact Sheet, 2016 (in Japanese). [31] N. Saito, N. Komai, Y. Takei, Fabrication trials of Ni-based alloys for advanced USC boiler application, in: Advances in Materials Technology for Fossil Power Plants: Proceedings of the Seventh International Conference, October 2013, ASM International, Materials Park, OH, 2014, pp. 190201. [32] N. Saito, N. Komai, Y. Sumiyoshi, Y. Takei, M. Kitamura, T. Tokairin, Development of materials for use in A-USC Boilers, Mitsubishi Heavy Ind. Tech. Rev. 52 (4) (2015) 2736. [33] J.A. Siefert, J.P. Shingledecker, J.N. DuPont, S.A. David, Weldability and weld performance of candidate nickel based superalloys for advanced ultrasupercritical fossil power plants, Part II: Weldability and cross-weld creep performance, Sci. Technol. Weld. Joining 21 (5) (2016) 397427. Available from: https://doi.org/10.1080/ 13621718.2016.1143708. [34] T. Tokairin, T. Sato, M. Kitamura, A. Shimada, K. Sakae, Metallurgical investigation of orbital narrow gap HST weldment of Ni-based alloy pipe, in: Proceedings of 13th International Conference on Creep and Fracture of Engineering Materials and Structures, Toulouse, 2015.

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[35] N. Komai, N. Saito, Y. Takei, Evaluation of creep rupture strength in Ni-based alloy weldments for an advanced USC boiler, in: Advances in Materials Technology for Fossil Power Plants: Proceedings of the Seventh International Conference, October 2013, ASM International, Materials Park, OH, 2014, pp. 903913. [36] M. Yaguchi, T. Sakai, T. Ogata, T. Matsumura, Internal pressure creep test on grade 91 steel longitudinal welded pipe, in: HIDA-6 Conference, Nagasaki, Japan, 2013. [37] M. Yaguchi, N. Miura, T. Ogata, T. Sakai, Development of component test facility “BIPress: bending & internal pressure on real structural samples”, in: Material Science Research Laboratory Rep. No. Q08001, CRIEPI, 2008, (in Japanese). [38] Y. Bi, 630-650 DG A-USC technology and material selection, game-changing materials meetings the energy challenge, in: IEA Clean Coal Center Third Workshop “AUSC3”, Rome, 2017. [39] S. Sato, T. Maruta, K. Yamamoto, H. Suganuma, T. Ichinose, Design for L-shaped boiler, Mitsubishi Heavy Ind. Tech. Rev. 41 (5) (2004) 242275 (in Japanese). [40] W. Feng, L. Li, A New Degree of all turbine casings elevated arrangement for highefficiency double reheat units, in: 2019 IEA Clean Coal Technologies Conference, IEA CCT 2019, Houston, TX, 2019. [41] V.K. Sikka, Development of Modified 9 Cr-1 Mo Steel for Elevated-Temperature Service, Proc. TMS/AIME Topical Conference on Ferritic Alloys for Use in Nuclear Energy Technologies, Snowbird, UT (1983). [42] K. Yoshida, H. Nakai, M. Fukuda, Regulatory review results on allowable tensile stress values of creep strength enhanced ferritic steels, Eighth International Conference on Creep and Fatigue at Elevated Temperatures, CREEP2007-26512, ASME, San Antonio, TX, July 2007. [43] K. Kimura, Assessment of long-term creep strength and review of allowable stress of high Cr ferritic creep resistant steels, in: Proceedings of PVP2005, 2005 ASME Pressure Vessels and Piping Division Conference, PVP2005-71039, Denver, July 2005. [44] M. Tabuchi, Y. Takahashi, Evaluation of creep strength reduction factors for welded joints of modified 9Cr-1Mo steel (P91), in: Proceedings of PVP2006, 2006 ASME Pressure Vessels and Piping Division Conference, PVP2006-ICPVT11-93350, Vancouver, July 2006. [45] K. Kimura, Creep strength assessment and review of allowable tensile stress of creep strength enhanced ferritic steels in Japan, in: Proceedings of PVP2006, 2006 ASME Pressure Vessels and Piping Division Conference, VP2006-ICPVT-1193294, Vancouver, July 2006. [46] Y. Takahashi, M. Tabuchi, Evaluation of creep strength reduction factors for welded joints of HCM12A (P122), in: Proceedings of PVP2006-ICPVT-11 2006 ASME Pressure Vessels and Piping Division Conference, PVP2006-ICPVT1193488, Vancouver, July 2006. [47] K. Kimura, H. Kushima, K. Sawada, Long-term creep strength prediction of high Cr ferritic creep resistant steel based on degradation mechanism, in: 6th International Charles Parsons Turbine Conference, Dublin, 2003, pp. 444456. [48] K. Kimura, K. Sawada, K. Kubo, H. Kushima, Stress dependence of recovery process and long-term life prediction of 9Cr-1Mo-V-Nb steel, International Conference on High Temperature Plant Integrity & Life Extension, Robinson College, Cambridge University, 2004. [49] K. Maruyama, J. Nakamura, N. Sekido, K. Yoshimi, Causes of heat-to-heat variation of creep strength in grade 91 steel, Mater. Sci. Eng. A 696 (2017) 104112. [50] F. Masuyama, J.P. Shingledecker, Recent status of ASME code on creep strength enhanced ferritic steel, Proc. Eng. 55 (2013) 314325.

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[51] K. Sawada, K. Sekido, K. Kimura, K. Arisue, M. Honda, N. Komai, et al., Effect of initial microstructure on creep strength of ASME grade T91 Steel, ISIJ Int. 60 (2) (2020) 382391. [52] F. Abe, Precipitate design for creep strengthening of 9% Cr tempered martensitic steel for ultra-supercritical power plants, Sci. Technol. Adv. Mater. 9 (1) (2008). Available from: https://doi.org/10.1088/1468-6996/9/1/013002. [53] H. Semba, F. Abe, Alloy design and creep strength of advanced 9%Cr USC boiler steels containing high concentration of boron, Energy Mater.: Mater. Sci. Eng. Energy Syst. 1 (4) (2006) 238244. [54] T. Hamaguchi, H. Okada, H. Semba, H. Hirata, A. Iseda, M. Yoshizawa, Development of high strength 9Cr-3W-3Co-Nd-B heat-resistant steel tube and pipe, in: JSPS Report of the 123rd Committee on Heat Resisting Materials and Alloys, 2015, pp. 114117. [55] M. Kondo, M. Tabuchi, S. Tsukamoto, F. Yin, F. Abe, Suppressing type IV failure via modification of heat affected zone microstructures using high boron content in 9Cr heat resistant steel welded joints, Sci. Technol. Weld. Joining 11 (2) (2006) 216223. [56] D.J. Abson, J.S. Rothwell, Review of type IV cracking of weldments in 9-12%Cr creep strength enhanced ferritic steels, J. Int. Mater. Rev. 58 (8) (2013) 437473. [57] N. Komai, T. Tokiyoshi, T. Igari, H. Ohyama, F. Masuyama, K. Kimura, Experimental observation of creep damage evolution in seam-welded elbows of mod. 9Cr-1Mo steel, J. Mater. High Temp 33 (6) (2016) 617625. [58] T. Himeno, Y. Chuman, T. Tokiyoshi, T. Fukahori, T. Igari, Creep rupture behavior of girth-welded mod. 9Cr-1Mo steel pipe subject to internal pressure and axial load, in: Proc. 6th Int. High-Temperatures Defect Assessment Conference (HIDA-6), Nagasaki, 2013, pp. 110. [59] T. Tokiyoshi, H. Katafuchi, T. Honda, K. Tominaga, H. Ohyama, Base metal failure analysis for nozzle-to-pipe connection of CSEF steel, in: EPRI Expert Workshop on Structural Integrity of Components in High Temperature Applications in Collaboration with ASME PVP 2019, Session 6, (n.d.) 2019. [60] K. Takita, Y. Takeda, M. Nakamura, K. Takezoe, Cavitation during creep in notched bar of CrMoV-steel, Zairyo 39 (440) (1990) 496502 (in Japanese). [61] J.A. Siefert, J.D. Parker, Evaluation of the creep cavitation behavior in grade 91 steels, Int. J. Press. Vessels Pip. 138 (2016) 3144. Available from: https://doi.org/10.1016/j. ijpvp.2016.02.018. [62] J. Parker, Component relevant creep damage in tempered martensitic 9 TO 12%Cr steels, advances in materials technology for fossil power plants, in: Proceedings from the Eighth International Conference, Algarve, 2016, pp. 7289. [63] J.A. Siefert, J.D. Parker, Y. Takahashi, H. Shigeyama, A summary of 10 years research on grade 91 and grade 92 steel, Joint EPRI-123HiMAT International Conference on Advances in High Temperature Materials, JSPS & EPRI, Nagasaki, 2019, pp. 370378. [64] K. Yamada, T. Ogata, Clarification of creep damage condition and rupture time prediction method for round notch bar specimens on modified 9Cr-1Mo steel under creep loading, Trans. JSME 85 (878) (2019). Available from: https://doi.org/10.1299/transjsme.18-00428 (in Japanese). [65] F. Masuyama, Long time reliability and life assessment of Gr.91 and CSEF steels for boiler and steam line components, in: The 1st International 9%Cr CSEF Steels Conference, Beijing, October 2018. [66] S.C. Ceuca, A. Ferrara, S. Baietta, S. Campanari, P. Chiesa, N. Zecca, Benchmarking CCPP designs employing 912% Cr CSEF steels in steam oxidation prone environments, in: Joint EPRI 123HiMAT International Conference on Advances in High Temperature Materials, Nagasaki, 2019, pp. 990997.

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[67] T. Yokoyama, F. Masuyama, Application of boiler materials for ultra-high temperature and high-pressure power plants, Therm. Nucl. Power 45 (11) (1994) 12971308. [68] Handbook for Thermal Power Engineers. eighth revised ed., Thermal and Nuclear Power Engineering Society, Tokyo, 2017. [69] Y. Tanaka, N. Komai, Y. Takei, Hot Corrosion Properties on Ni-Based Alloys Used in an Advanced-USC Boiler, Advances in Materials Technology for Fossil Power Plants, ASM International, Materials Park, OH, 2014, pp. 14221431. [70] M. Shimizu, Y. Fukuda, Steam oxidization properties of candidate materials for 700
C A-USC boilers, in: 2nd EPRI-NPL Workshop on Scale Exfoliation from SteamTouched Surface, National Physical Laboratory, London, 2012.

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Takatoshi Yamashita1, Shigehiro Shiozaki1, Shingo Naito1, Takashi Fujii1, Mamoru Ozawa2 and Akira Yamada3 1 Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan, 2Kansai University, Osaka, Japan, 3Mitsubishi Heavy Industries, Ltd., Nagasaki, Japan

Chapter outline 8.1 Tachibana-Wan Thermal Power Station Unit No. 2 (ultrasupercritical, sliding pressure, once-through boiler) 391 8.1.1 8.1.2 8.1.3 8.1.4 8.1.5

Development of advanced steam condition boilers 392 Main design features of the boiler 393 Construction 395 Achievements in the commissioning 398 Remarks 399

8.2 Himeji No. 2 Power Plant (gas turbine combined-cycle plant) 400 8.2.1 8.2.2 8.2.3 8.2.4

Outline of the plant 401 Characteristics of the main component Test operation performance 405 Remarks 405

402

8.3 Karita PFBC plant 406 8.4 Nakoso and Osaki Integrated Coal Gasification Combined Cycle (IGCC) Plants 410 8.4.1 Nakoso 250MW air-blown IGCC demonstration plant 410 8.4.2 EAGLE project and Osaki CoolGen project (oxygen-blown IGCC) 418

8.5 Incineration firing by circulating fluidized bed References 424

8.1

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In the fossil-fueled power utility area the large-capacity coal-fired boiler has been developed for higher efficiencies. The Tachibana-Wan Thermal Power Station Unit No. 2 owned by the Electric Power Development Co., Ltd. (J-POWER) is 1050 MW of electricity gross output and the highest efficiency thermal power plant in Japan, with application of advanced steam parameters of 25.0 MPa 600
C/ 610
C. The boiler is coal-fired, ultrasupercritical, sliding-pressure operation, single Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00008-4 © 2021 Elsevier Inc. All rights reserved.

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reheat, and once-through type and was supplied by Mitsubishi Hitachi Power Systems, Ltd. (MHPS) (the former Babcock-Hitachi K.K.) [1]. To achieve these high-level steam parameters, newly developed high-strength materials were used in the high-temperature areas, and the latest combustion technology was used for environmental protection as well as for high levels of efficiency and reliability. It started commercial operation in December of 2000. This section focuses on the boiler technologies, construction methods, and operating experiences during commissioning.

8.1.1 Development of advanced steam condition boilers The strength of demands for Japanese utility companies to reduce emissions of air pollutants and, in particular, of CO2, has led to a dramatic improvement in the steam conditions of thermal power plants in Japan, and thus to higher plant efficiencies [1]. Fig. 8.1 shows the improvements in steam conditions of MHPS’s experienced boilers. As shown here, conventional steam parameters (supercritical) of 24.1 MPa 538
C/566
C had been applied up to 1994. Since then, steam conditions started to improve drastically and MHPS achieved the high steam temperature (ultrasupercritical) of 593
C/593
C for the J-Power at the Matsuura Thermal Power Station Unit No. 2 boiler in 1997 and of 600
C/600
C for Chugoku Electric Power Co., Inc. at the Misumi Thermal Power Station Unit No. 1 boiler and for Tohoku Electric Power Co., Inc. at the Haramachi Thermal Power Station Unit No. 2 boiler in 1998, which resulted in a significant improvement in plant efficiency. As the next step, for the J-POWER at the Tachibana-Wan Thermal Power Station Unit No. 2 boiler, the advanced steam parameter of 25 MPa 600
C/610
C was applied. It has been still the highest steam condition for large capacity 1000 MW class units in Japan [13].

Figure 8.1 Improvements in steam condition of MHPS boilers. MHPS, Mitsubishi Hitachi Power Systems, Ltd. Source: Courtesy of MHPS.

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8.1.2 Main design features of the boiler The J-POWER had been paying particular attention to environmental conservation and decided to apply an advanced steam condition, 25.0 MPa 600
C/610
C, to the Unit No. 2 boiler at the Tachibana-Wan Thermal Power Station. This 3000t/h coal-fired boiler was supplied by MHPS. Table 8.1 gives the principal specifications of the boiler [1]. Fig. 8.2 is a cross-sectional schematic view of the Tachibana-Wan Unit No. 2 boiler. As this boiler plant was designed to be cyclic operation capability between high and low load once per day and to be used coals with a wide range of grades stably and efficiently, various factors, including sliding-pressure operation with advanced steam parameters, were considered in designing the boiler. The boiler employs a combination of a spiral-wound furnace waterwall structure and the opposed firing method that has been proven in many domestic and overseas largecapacity boilers. The furnace size was selected appropriately considering the design coal characteristics and combustion performance requirements. The furnace waterwall is spiral-wound tube furnace type in lower furnace section to achieve uniform fluid temperature distribution at the furnace outlet, even though with frequent slag Table 8.1 Main specification of the boiler [1]. Items

Specification

Boiler type

Ultrasupercritical, sliding-pressure operation, once-through boiler

MCR

Steam flow

Main steam

3000 t/h

Reheat steam

2490 t/h

Steam pressure

Main steam

25.0 MPa

Steam temperature

Main steam

600
C

Reheat steam

610
C

Economizer inlet feedwater temperature

288
C

Combustion system

Pulverized coal firing

Draught system

Balanced draught system

Steam temperature control system

Steam temperature control range

Main steam

Waterfuel ratio control and three-staged spray attemperation

Reheat steam

Parallel gas dampering and intermediate spray attemperation

Main steam

35% ECR to MCR

Reheat steam

35% ECR to MCR

ECR, economical continuous rating; MCR, maximum continuous rating.

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Figure 8.2 Cross-sectional schematic view of the Tachibana-Wan Unit No. 2 boiler. Source: Courtesy of MHPS.

desorption on the furnace waterwall. In the spiral-wound tube furnace waterwall section, the multiribbed tube was applied to achieve high reliable heat-transfer coefficient on the inner surface of the water tube at low mass velocities compared with smooth tube applied spiral furnace waterwall. Thus the pressure drop in the water tubes was reduced. Due to the spiral wound water tubes, sufficient water was successfully provided to prevent the departure from nucleate boiling (DNB). To achieve higher steam temperatures, superheaters and reheaters were divided into multiple sections. The increase in the heating surfaces was kept to a minimum by optimizing the furnace in terms of combustion performance and the slagging potential of the coals. Furthermore, a three-stage superheater spray system was used to control the temperature of the main flow of steam, while gas recirculation and gas-biasing dampers were installed to overcome the performance differences encountered in the firing of various imported coals and to control reheat steam temperature.

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8.1.2.1 Use of high-strength materials When high-level steam conditions are selected, it is essential to use high-strength materials in order to reduce the thicknesses of the walls of parts under pressure, resulting in low level of thermal stress. For pendant superheaters, austenitic stainless-steel tube of SUS304J1HTB (18Cr9Ni3CuNbN), which is currently registered as ASME Code Case 2328-2 and has significantly high levels of creep strength in the high-temperature region, was selected. For pendant reheaters, another high creep strength austenitic stainless-steel tube of SUS321J1HTB (18Cr10NiTiNb) was selected. The performance of these materials had been fully confirmed by our earlier experiences with 600
C level utility boilers. By employing these materials, wall thickness in the high-temperature zone was kept within a similar range to that used in conventional boilers [13]. Under the high-level steam condition, it is important to minimize the generation of inner oxidation scale for reliable and stable operation with long term. When austenitic stainless-steel tubes are shot-blasted, the generation of inner oxidation scale remains minimum up to 700
C of metal temperature. Both of the abovementioned austenitic stainless-steel tubes were internally shot-blasted when manufactured.

8.1.2.2 Combustion system For environmental protection the latest combustion technologies have been applied in Tachibana-Wan Unit No. 2 boiler. One is the HT-NR2 burner with low levels of emission of NOx and high levels of combustion efficiency. Another is large-capacity and high-efficiency pulverizer with rotating classifier [1]. MHPS has developed HT-NR2 burner as the succession model of HT-NR burner in which an innovative concept of in-flame NOx reduction had been realized. This burner features a strengthened flame in terms of high-temperature reduction and achieves extremely low levels of NOx emission and high levels of combustion efficiency. The HT-NR2 burner incorporates two novel devices: a pulverized coal (PC) concentrator and a space creator. The configuration of the burner is shown in Fig. 8.3. This burner enables a low level of excess air, at only 15%, at the economizer outlet for various kinds of imported coals. Forty-eight burners were installed, together with a two-stage combustion system. These elements were enclosed in a suitably dimensioned furnace. The supply of very fine coal is essential to maximize the performance of burner. To achieve this requirement the Tachibana-Wan Unit No.2 boiler had six largecapacity roller-type pulverizers of the MPS300 type with rotating classifiers as shown in Fig. 8.4 [1].

8.1.3 Construction Due to the limited site construction area, the boiler design for this project was following the module assembly method; where after the module had been completely assembled in factory, it was hauled to site and ready to be erected to its final

396

Figure 8.3 Configuration of HT-NR2 burner [1].

Figure 8.4 MPS-300 rollertype pulverizer. Source: Courtesy of MHPS.

Advances in Power Boilers

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position (modularization method). In addition, regarding the applicable scope of modularization, the steel frame structure zone and the pressure parts zone were divided into modules so as to provide a load shape suitable for boiler construction in a limited space.

8.1.3.1 Side span module for steel frame structure zone Within the side span of the boiler steel frame structure, the scope of first- and second-tier steel structure and the connecting parts had been set up as the applicable scope of modularization. Contained in the built-in product was the steel frame structure for boiler, platform, duct, pipe, local panel, etc.

8.1.3.2 Coil module for pressure parts zone The equipment subject to the pressure parts zone were pendant convection pass sidewall area, reheater area, and superheater area (see Fig. 8.5). Assembled pressure parts in factory were transported and lifted to position using the jack-up construction method in the field.

8.1.3.2.1 Pendant convection pass sidewall area As built-in products, there were coil heating surface, header and manifold for final superheater and secondary reheater, roof and pendant convection pass floor wall part, among others. Refer to Fig. 8.5 for final superheater and secondary reheater

Figure 8.5 Final superheater and secondary reheater coil module at factory. Source: Courtesy of MHPS.

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coil module at factory. In addition, while performing the jack-up of the module in the field, the nose wall and the convection pass floor wall, etc. were incorporated, and the final jack-up was carried out.

8.1.3.2.2 Reheater area Built-in products in this area consist of the primary reheater standing tube and header, horizontal reheater (horizontal reheater upper bank), roof, convection pass front wall and division wall of convection pass among others. In addition, while the jacking up of the module in the field was being carried out, and before the final jacking up was completed, the horizontal reheater bottom bank was incorporated under the upper bank and among other parts.

8.1.3.2.3 Superheater area Built-in products consist of primary superheater standing tube and header, horizontal superheater, roof, among others. In addition, while the jacking up in the field was being carried out, and before the final jacking up was completed, the evaporator, economizer, etc., were incorporated.

8.1.3.3 Wind box module for pressure zone The wind box, placed in front of and behind the boiler furnace, was modularized in factory splitting it into two parts in a vertical direction (burner, overfire air ports were built-in). While performing the jacking up in the field, the upper and lower modules were integrated into one module, and subsequently, the final jacking up was carried out to the designated position.

8.1.4 Achievements in the commissioning Tachibana-Wan Unit No. 2 boiler was ignited for the first time in April 2000. Commissioning continued, with two imported coals being burnt. In December 2000, the plant successfully started commercial operation as planned. Stable operation with the advanced steam condition was confirmed in both static and dynamic modes. Fig. 8.6 shows the steam-and-water characteristics at each turbine load. The main steam and reheat steam temperatures were at the anticipated values without causing any alarms. The backend gas temperature and amounts of excess air and unburned carbon (UBC) in fly ash were well below the designed values. The boiler’s level of efficiency was found to be quite satisfactory across the load range [1]. The combustion testing was carried out for the A-type coal and the B-type coal. Both coals had a high fuel ratio (fixed carbon to volatile matter 5 2:1 and 2:4, respectively) and high nitrogen content, which means that the simultaneous reduction of both NOx and UBC is very difficult. Applying the latest combustion technology, the combustion test results with both coals met the planed value of NOx emission and UBC. Fig. 8.7 shows the flame during burning of the B-type coal at a load of 35% economical continuous rating (ECR) (368 MW). A very bright and

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Figure 8.6 Steam-and-water temperature and main steam pressure characteristics at firing A-type coal [1].

stable flame was maintained at the tip of the fuel nozzle at the low coal-firing load of 35% of ECR, along with stable boiler performance.

8.1.5 Remarks The Tachibana-Wan Unit No. 2 boiler, which had the advanced steam condition of 25.0 MPa 600
C/610
C, represented an important step toward improved steam condition. Also, this boiler indicated good boiler performance at commissioning with the latest technologies such as application of proven high-strength materials, advanced combustion system, and so on. The boiler plant has contributed to the

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Figure 8.7 Flame of HT-NR2 burner at 35% ECR load [1].

utility demand and environmental protection with high reliability and high efficiency since December of 2000.

8.2

Himeji No. 2 Power Plant (gas turbine combinedcycle plant)

Power plants are requested to have high energy utilization efficiency and excellent environmental characteristics in addition to being highly reliable. Kansai Electric Power Company Himeji No. 2 (Himeji No. 2) Power Station is a state-of-the-art combined-cycle plant composed of six single-shaft blocks rated for a total of 2919 MW. This modern plant replaces Kansai Electric’s 2550 MW thermal power station, which had been in operations since 1963. The plants adopted largecapacity, high-efficiency M501J gas turbines (GTs) with turbine inlet temperature (TIT) at 1600
Cs. A heat-recovery steam generator (HRSG) and a steam turbine (ST) that satisfied the conditions for high-temperature and high-pressure steam were introduced for the steam cycle. The first shaft started commercial operation in August 2013, and the final shaft started in March 2015. This section describes the plant and its operating performance [47].

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8.2.1 Outline of the plant 8.2.1.1 Description The Himeji No. 2 plant is a heat-recovery combined-cycle plant with a largecapacity high-efficiency GT M501J of MHPS for 1600
C combustor exit gas temperature. The Himeji No. 2 station consists of six single-shaft combined-cycle power plants, in which a GT, an ST, and a generator are configured on the same single shaft. Each shaft generates an output of 486 MW, and the group output totals 2919 MW in the rated operation. Fig. 8.8 shows a schematic bird-eye view of the GT combined-cycle (GTCC) in single-shaft configuration.

8.2.1.2 Main characteristics 8.2.1.2.1 High plant efficiency

A triple-pressure HRSG was adopted in addition to the 1600
C class M501J GT. A gas turbine cooling air (TCA) cooler with a heat exchange by the feedwater and a fuel gas heater (FGH) were also employed to enhance the efficiency of the plant. Thus the loss of heat sources was minimized, and higher thermal efficiency than conventional combined-cycle plants was achieved.

8.2.1.2.2 Environment protection In order to reduce NOx emissions brought about by the combustor outlet temperature 1600
C, the low-NOx combustor with steam-cooled shell is applied in addition

Figure 8.8 Image of J-series gas turbine combined cycle. Source: Courtesy of MHPS.

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to the conventional premixing system. A dry de-NOx apparatus was also installed in the HRSG to meet sufficiently environmental regulation limits.

8.2.1.2.3 Excellent operational characteristics Better start-up characteristics of the combined-cycle plant relative to conventional thermal power plant make it possible to perform daily start and stop and weekly start and stop operations.

8.2.1.3 Plant-rated performance and equipment specification 8.2.1.3.1 Plant-rated performance The Himeji No. 2 plant was designed to produce a total output of 2919 MW at an atmospheric temperature of 4
C. The design-based plant thermal efficiency was 54.5% (based on the higher heating value, HHV), and therefore the thermal efficiency is at least 20% (relative value) better than that of a conventional thermal power plant.

8.2.1.3.2 Equipment specification Specifications of individual equipment for the plant were determined considering the output characteristics and the operational controllability. The specifications of the major equipment are listed in Table 8.2.

8.2.2 Characteristics of the main component 8.2.2.1 Gas turbine The features of M501J GT are the large power generation capacity and high thermal efficiency. An improvement in the thermal efficiency of GTCC power plant is highly dependent on the turbine inlet temperature (TIT). M501J was designed to operate at 1600
C TIT, being 100
C higher than the preceding G-type GT of MHPS. An increase in TIT is a key issue for GTCC but involves difficult technical challenges to be overcome by exhaustive R&D efforts and verification test. The J-series GT features are as follows: G

1600
C TIT Table 8.2 Main equipment specification. Plant system Fuel Output of power station Unit configuration Gas turbine Steam turbine Hear recovery steam generator Steam condenser cooling system LNG, liquified natural gas.

Single-shaft gas turbine combined cycle LNG-vaporized gas 2,919 MW 486 MW 3 6 units Single-shaft open cycle Single casing, reheat, mixed pressure, condensing type Vertical gas flow, reheat, natural circulation heat-recovery steam generator Seawater

Examples of thermal power station

G

G

403

23:1 pressure ratio technology developed under the Japanese national project: advanced turbine cooling technology advanced thermal barrier coating high-efficiency, high loading turbine G

G

G

The pressure ratio of J-series GT shown in Fig. 8.9 is higher than that of G-series with 21:1. The J-series compressor was developed based on the MHPS’s M501H compressor having pressure ratio of 25:1. Based on the extensive steam cooling experience accumulated in over 80 units of G-type GT, the J-series also employed steam cooling combustor. The reliability of the units was confirmed with 40,000 start cycles. Fig. 8.10 shows the shipment of the first gas turbine unit from Takasago Works.

8.2.2.2 Steam turbine The ST is designed for the steam condition matching with the M501J exhaust gas conditions. A single-casing turbine integrated with high and middle pressure is applied as shown in Fig. 8.11, and fully 3D-designed blades were introduced for the high- and middle-pressure turbines.

Figure 8.9 Sectional view of J-series gas turbine. Source: Courtesy of MHPS.

404

Figure 8.10 Shipment of first gas turbine unit. Source: Courtesy of MHPS.

Figure 8.11 Sectional view of steam turbine. Source: Courtesy of MHPS.

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In addition, advanced technologies, for example, hollow stationary blades to counter wet steam, are introduced for low-pressure turbine to improve the overall efficiency and reliability.

8.2.2.3 Heat-recovery steam generator The HRSG adopted a triple-pressure, reheat, and natural circulation system so as to match high-temperature exhaust gas. The important issues to be considered in the desigh of the plant are to secure the steam for GT combustor cooling from the intermediate-pressure steam and to extract steam from the cold reheat for the supply to the adjacent factories.

8.2.2.4 Turbine cooling air cooler and fuel gas heater To achieve higher efficiency than conventional combined-cycle plants, the gas TCA cooler and FGH are built into the bottoming cycle to minimize the heat loss discharged from the plant. In conventional TCA coolers, thermal energy from gas TCA has not been effectively used, instead released outside the plant. In addition, fuel gas has been fed into the GT without any heating. The Himeji No. 2 plant was designed to realize a high efficiency by combining the TCA cooler and FGH with the HRSG at the bottoming cycle so that the heat released from the TCA cooler was used to generate steam in the HRSG. Further, fuel gas was heated by the feedwater heated in the HRSG so as to enhance the plant efficiency.

8.2.3 Test operation performance The plant performance and environmental and operational characteristics were confirmed throughout the commissioning operation tests. The rated output of 486 MW was ensured at an atmospheric temperature of 4
C and higher. The de-NOx technology using the steam cooling-type low-NOx combustor and the dry-type de-NOx system provided safe operation with reduced NOx emissions. The concentration of NOx emitted from the stacks was lower than the environmental regulation limit of 4 ppm (O2 5 16% equivalent). In addition, a variety of tests of the operational characteristics, including various kinds of starts and stops, and load dispatching operation tests, were successfully conducted during the commissioning period.

8.2.4 Remarks Kansai Electric Power Company Himeji No. 2 Power Plant shown in Fig. 8.12 was constructed as a combined-cycle plant with leading-edge technologies, and since then, it has been operating successfully as designed. The sophistication of the plant and the environmental measures introduced through technological innovation are noteworthy. In particular, the development of the GT was remarkable. The development of the entire plant system, including the steam cycle, meets the current social demand for plant efficiency and environmental issues. The valuable results obtained

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Advances in Power Boilers

Figure 8.12 Plant overview. Source: Courtesy of MHPS.

from this plant become a great contribution toward the planning of future plants, both in terms of capacity and efficiency.

8.3

Karita PFBC plant

The development of pressurized fluidized-bed combustion (PFBC) combined cycle power plant started in Japan, for example, by IHI Corporation, Babcock-Hitachi K. K. (BHK, presently MHPS) and Mitsubishi Heavy Industries, Ltd. (MHI) in the 1980s. Based on the fundamental investigations, pilot plants were constructed, 3 MWt of IHI in 1990, 2 MWt of MHI in 1989, 2 MWt in 1991, and 4 MWt in 1994 of BHK. The demonstration plants started test operation in the 1990s, for example, 71 MWe of Wakamatsu in 1994 and 85 MWe of Tomato-Atsuma No. 3 in 1998. Based on these experiences, large-scale commercial plants, typically Osaki No. 1-1 of Chugoku Electric Power Co. in 2000 and Karita New No. 1 of Kyushu Electric Power Co. in 2001 [8], were constructed. Such R&D process is exemplified in Fig. 8.13. The specification of abovementioned demonstration plants and commercial plants are listed in Table 8.3 [8,9]. The Karita plant overview illustrated in Fig. 8.14 is one of the largest classes in the world. The flow is also illustrated in Fig. 8.15. Coal is pulverized and mixed with water and limestone to make fuel slurry, being fed by slurry pump to fluidized-bed boiler in the pressure vessel. Combustion gas entrained by ash is separated by the primary and secondary cyclones. Then GT is driven by the combustion gas at high pressure. Desulfurization is conducted in the fluidized-bed boiler, while

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Figure 8.13 Example of development process of PFBC. Source: Courtesy of IHI.

the denitration equipment is located just downstream of the GT outlet. Water from feedwater pump is first heated in the feedwater heater and fed to fluidized-bed boiler to generate steam. The steam from high-pressure turbine is reheated and fed to intermediate-pressure turbine. ST output is 290 MW, and GT generates 75 MW, and the GT output ratio is 0.208, being rather small compared with conventional GTCC. The emission of SOx is 75 ppm, NOx 60% at O2 5 6%, and dust content 30 mg/m3N at O2 5 6%, well below the regulations. Although two-stage cyclone is installed, wear resistance coating was conducted for gas turbine blades. Construction of the pressure vessel was conducted in the shipyard of IHI, and internal elements were installed. The total weight of the pressure vessel became 3600 t, and the height was 45 m as shown in Fig. 8.13. The pressure vessel was loaded on a barge as shown in Fig. 8.16 using 4100-t floating crane and transported to the site of installation [11]. The construction methods of Tonato-Atsuma and Osaki are similar. These commercial plants realized excellent performance, but the initial cost for installation is rather high and also improvement in PC combustion as well as newly appeared integrated coal gasification combinedcycle (IGCC) plant interferes the expansion of the market of PFBC in Japan. Tomato-Atsuma finished operation in 2005 and Osaki in 2011.

Table 8.3 Specification of PFBC plant. Plant

Electric Power Development Co. Wakamatsu

Hokkaido Electric Power Co. Tomato-Atsuma No. 3

Chugoku Electric Power Co. Osaki No. 1-1

Kyushu Electric Power Co. Karita New No. 1

Plant output (MWe) Gas turbine (MWe) Steam turbine (MWe) Type of fluidized bed Steam generation (t/h) Coal-feed Steam pressure (MPa) Steam temperature (
C) Gas turbine inlet temperature (
C) Dust collection

71

85

250

360

14.8

11.1

44

75

56.2

73.9

215

290

Pressurized bubbling

Pressurized bubbling

Pressurized bubbling

Pressurized bubbling

146.6

195

522

760

CWPa 10

Dry-feed 16.6

CWP 16.6

CWP 24.1

593/593

566/538

566/593

566/593

830

831

840

850

One-stage cyclone 1 ceramic tube filter

One-stage cyclone 1 ceramic filter

Two-stage cyclone 1 bag filter

Desulfurization Denitration

In-bed with limestone Dry ammonia catalytic reduction method

In-bed with limestone Dry ammonia catalytic reduction method

Plant gross thermal efficiency (%) Start operation



40.1

In-bed with limestone Noncatalytic denitration 1 dry ammonia catalytic reduction method 41.5

Two-stage cyclone 1 electrostatic precipitator In-bed with limestone Dry ammonia catalytic reduction method

September 1994

March 1998

November 2000

a

42.5

July 2001

CWP, Coalwater paste. Source: Data from T. Sakata, T. Shikata, PFBC boiler, J. Jpn. Inst. Energy 86 (2007) 270277 (in Japanese) and T. Sato, The Large Capacity Gas Turbine for Pressurized Fluidized Bed Combustion (PFBC) Boiler Combined Cycle Power Plant, Gas Turbine Technology in Japan, Bulletin of GTSJ, 2003.

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Figure 8.14 Bird’s eye view image of Karita PFBC plant. Source: Courtesy of Kyushu Electric Power Co.

Figure 8.15 Plant flow diagram of Karita PFBC. Source: Drawn referring to catalogue of Kyushu Electric Power Co., Pressurized Fluidized Combustion PFBC, Karita Power Station Catalogue [10].

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Figure 8.16 Transportation of PFBC pressure vessel. Source: Courtesy of Kyushu Electric Power Co.

The main problem of the PFBC plant is that the combustion gas containing solid particles entrained with is introduced to GT, and therefor GT performance is deteriorated. In addition, bed temperature is relatively low, and thus gas temperature is also low, which suppress the gas and STs’ efficiencies. In this context the PFBC is an intermediate technology as the coal-based combined-cycle plant, that is, from PC-fired boiler to IGCC.

8.4

Nakoso and Osaki Integrated Coal Gasification Combined Cycle (IGCC) Plants

8.4.1 Nakoso 250MW air-blown IGCC demonstration plant In collaboration with the Japanese Government, nine electric utility companies, J-POWER, the Central Research Institute of Electric Power Industry (CRIEPI), and MHPS developed a highly efficient and reliable air-blown integrated coal

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gasification combined-cycle (IGCC) plant optimized for electric power generation [1215]. A 250 MW IGCC plant, which is called the “Nakoso” plant based on the name of the area where the plant is located, was constructed as the final step before commercialization. The IGCC plant project was led by Clean Coal Power R&D Co. (CCP), which was founded in June 2001. MHPS signed the engineering, procurement, and construction (EPC) single-point turnkey contract for the entire IGCC plant and supplied the gasifier, syngas cleanup system, GT, ST, and the HRSG. After completion of the design, construction, and delivery of the plant, a series of tests was conducted at the Nakoso IGCC plant from September 2007 and proceeded on schedule successfully. The demonstration plant was built inside of Joban Joint Power Company’s Nakoso Power Station, which is located about 200 km north of Tokyo, in Iwaki City, Fukushima Prefecture, Japan. Gross output of Nakoso IGCC is 250 MW, and the net plant efficiency is 42% by lower heating value (LHV) bases. Nakoso IGCC employs air-blown as gasification agent, dry feed as supplying method of coal, methyldiethanolamine (MDEA) method as gas cleanup and M701DA as GT of MHPS. Figs. 8.17 and 8.18 show project scheme, location, and overview of Nakoso IGCC.

8.4.1.1 Construction The gasifier facility consists of the gasifier, raw coalreceiving equipment, coal pulverized and feeding system, kerosene oilfiring equipment, liquefied natural gasfiring equipment, char removal and recovery equipment, and slag processing equipment. The various products and parts of each facility are large sized as well as in its majority are heavy, and in an effort of ensuring, quality, delivery schedule, and safety during the time of construction, where the carry-in, lifting, and positioning procedures become of the utmost importance. As an installation method, a hydraulic jack-up system is adopted for the gasifier pressure vessel, and an

Figure 8.17 Scheme and location of Nakoso 250 MW demonstration project.

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Figure 8.18 Nakoso 250 MW IGCC plant. Source: Courtesy of MHPS.

advanced installation method using a large crane is adopted for other equipment, upon executing the installation works.

8.4.1.2 Jack-up construction method for gasifier pressure vessels Due to the heavy hauling restrictions, pressure vessel was manufactured in factory, dividing it into multiple separate blocks, which was eventually transported and assembled as one piece of equipment on site. In the field, it was necessary to install the divided pressure vessel in a fixed position while it is being assembled, and in order to lift the heavy object a multiple hydraulic jack system controlled simultaneously was adopted, and the installation of the gasifier and syngas cooler (SGC) was carried out. After steel frame structure for pressure vessel erection was completed, the hydraulic jacks were installed at the top of the frame steel structure, and the assembly of pressure vessel was carried out by repeating the work procedure of block jack-up!carrying-in of the block setting in down!coupling and adjustment between the blocks!welding!inspection!weld zone heat treatment!jack-up. Once the pressure vessel was assembled in one piece, it was jacked and set up at the designated position. Furthermore, in parallel with the assembly of pressure vessel, gasifier membrane waterwall (combustor and reductor) in the vessel and the SGC membrane waterwall, economizer, evaporator, and superheater were also brought into position. Hence, the aforementioned equipment were also included in the applicable scope of the jack-up construction method.

8.4.1.3 Advanced installation method For large heavy equipment such as steam drum, raw coal bunker, coal feeder, coal pulverizer, char cyclone, and porous filter, the lifting arrangements were set up for the use of a large-capacity crane. In installing these large equipments to the predetermined position, the conventional method of carrying-in after the erection of the steel frame structure had been

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aborted. Instead, the method of carrying-in the equipments in parallel with the erection of the steel frame structure had been used and substantial reduction of the risk of any dangerous situations during the carrying-in and heavy lifting operations was performd.

8.4.1.4 Operation Table 8.4 summarizes the results of the verification tests of 250 MW Nakoso IGCC plant started in 2007. The plant reached its rated load of 250 MW and succeeded at 2000 hours of continuous operation in 2008 after less than 1 year from the beginning of the startup. Achieving continuous operation in less than 1 year after initial startup demonstrates the high reliability of MHPS’s air-blown IGCC design. The 5000 hour long-term durability test was completed in June 2010 with the majority of the target figures such as net thermal efficiency, environmental performance, and start-up time accomplished successfully. Also, 10 kinds of coal, including 6 subbituminous, were tested and confirmed coal flexibility. As coal is imported from overseas in Japan, applicability for wider range of coal properties is essential. In this regard, the plant has accumulated much experience, and it is reflected in the commercial plant design. Fig. 8.19 shows a cumulative gasification experience of MHPS gasifiers, in terms of coal properties, including experiences at demonstration tests shown earlier. Entrained-bed coal gasifiers discharge coal ash as molten slag, and thus coals with low ash fluid temperature are more suitable. In addition, MHPS also addresses coal with high ash fluid temperature and has successfully gasified. Accumulation of these experiences enables MHPS to cover wide range of coals. After successful completion of all the verification items, in the spring of 2013, the plant was taken over to Joban Joint Power Company and renamed Nakoso No. 10 plant. It was started the first IGCC commercial operation in Japan. In December 2013, world record of continuous IGCC operation for 3917 hours was achieved.

8.4.1.5 Fukushima IGCC project (Nakoso, Hirono) Based on the experiences of abovementioned 250 MW Nakoso IGCC Plant, consortium led by MHPS has been implementing commercial IGCC project for Nakoso IGCC Power GK and Hirono IGCC Power GK. The IGCC project is intended to contribute to the revitalization in Fukushima Prefecture through the construction and operation of the world’s most advanced thermal power plants. The project will result in the development of industrial infrastructure and economic recovery in the area. In the case of Nakoso IGCC Power GK the new plant will be located on property adjacent to Joban Joint Power Co., Ltd.’s Nakoso Power Station in Iwaki City. The plant for Hirono IGCC Power GK will be built on the site of JERA’s Hirono Thermal Power Station in Fukushima’s Futaba District. Perspective view of the plant is shown on Fig. 8.20. Table 8.5 summarizes major specifications of the projects. Both plants will have a generating capacity of 543 MW and the processes of major components such as gasifier, gas cleanup, etc.

Table 8.4 Targets and achievements of 250 MW Nakoso IGCC plant.

Performance

Emission (@dry, 16% O2) Operational flexibility

Reliability a

PRB: Powder River Basin.

Targets

Achievements

Output (gross) (MW) Output (net) (MW) Efficiency (net, LHV) (%) Carbon conversion (%) SOx (ppm) NOx (ppm) Dust (mg/m3N) Coal kinds

250 220 .42.0 .99.9 ,8 ,5 ,4 Bituminous, Subbituminous

Start-up time (h) Minimum load (%) Ramping rate (%/min) Long-term continuous operation (h)

,18 50 3 2000

250 225 42.9 .99.9 1.0 3.4 ,0.1 Chinese, Canadian, 2 United States (including PRBa), 3 Indonesian (Adaro, etc.), Colombian, 2 Russian 15 36 3 3917

Note

10 kinds of coal in total, including 6 subbituminous and 4 bituminous, have been used

Cumulative operating hours: .50,000

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Figure 8.19 Experience of coal gasification.

Figure 8.20 Fukushima IGCC plant. Source: Courtesy of MHPS.

Table 8.5 Specifications of the Fukushima IGCC plant. Major specification Output Gasifier Gas cleanup Gas turbine Project schedule Operation start MDEA, Methyldiethanolamine.

543 MW (gross) 480 MW (net) Air-blown MDEA M701F GT (1 on 1) 2020 (Nakoso site) 2021 (Hirono site)

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are the same as those of 250 MW IGCC Plant. As shown on Table 8.6, construction started in April 2017, and the start of operation is scheduled in September 2020 and September 2021, respectively. MHPS is committed to successfully executing the newly ordered IGCC plant project while working closely with its three partners in the consortium: MHI, Mitsubishi Electric Corporation, and Mitsubishi Hitachi Power Systems Environmental Solutions, Ltd. In the process, every effort will be made to further improve IGCC technologies to enable even more efficient use of resources and further protect the environment. In June 2018 MHPS shipped components of a coal gasifier shown in Fig. 8.21 that serves as the core of the 543 MW Nakoso IGCC plant in Iwaki, Fukushima. The components are the first of their kind produced at MHPS’ new coal gasifier factory at Nagasaki Works. The overview of construction site is shown in Fig. 8.22. Table 8.6 Major milestones of the Fukushima IGCC plant. May 2014 August 2014 September 2016 October 2016 December 2016 April 2017 September 2020 (scheduled) September 2021 (scheduled)

Environmental impact assessment (EIA) started Engineering work started EIA completed/permition obtained Site mobilization started EPC full turnkey contracts awarded Construction started Nakoso IGCC commercial operation Hirono IGCC commercial operation

EPC, engineering, procurement, and construction.

Figure 8.21 Coal gasification furnace pressure containers. Source: Courtesy of MHPS.

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MHPS has established a remote monitoring center (RMC) in its Nagasaki Works shown in Fig. 8.23 in January 2019. The RMC supports operations and maintenance (O&M) for various types of power generating equipment, including steam power plants, as well as IGCC, GTCC, and geothermal power systems. The RMC

Figure 8.22 Status of plant construction in Nakoso, Fukushima (as of November 2019). Source: Courtesy of MHPS.

Figure 8.23 Remote monitoring center in Nagasaki Works. Source: Courtesy of MHPS.

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enhances the availability and reliability of power generating facilities, and also expands after-sales service functionality by strengthening solutions capabilities that utilize MHPS-TOMONI digital solutions. This is MHPS’ fourth RMC, along with centers in Takasago (Hyogo Prefecture, Japan), Orlando (Florida, United States), and Alabang (Muntinlupa, Philippines). The newly established RMC will support O&M by monitoring the overall status of power plants, focusing on the boilers and STs in a steam power plant and coal gasifiers in IGCC plants. The establishment of an RMC at Nagasaki Works, built upon utilizing a wealth of operational technologies and expertise in designing and developing boilers to burn a variety of fuels with high efficiency, then combining this with digital technologies, is expected to make significant contributions to customer O&M services.

8.4.2 EAGLE project and Osaki CoolGen project (oxygen-blown IGCC) The development of oxygen-blown gasification systems has been carried out since the 1980s in Japan. Starting with the gasification element test using the process development unit with a coal feed rate of 1 t/day, continuously, the HYCOL project at 50 t/day [a project on commission from the New Energy and Industrial Technology Development Organization (NEDO) and the HYCOL Research Association] and the EAGLE project at 150 t/day [a joint project by NEDO and J-POWER] had been conducted. Upscaling possibilities of a gasifier were verified with steady steps through these projects. With the knowledge obtained from the EAGLE project, the Osaki CoolGen project, first step IGCC demonstration test, was carried out from FY 2016 to FY 2018. This Osaki CoolGen project had been assisted by the Ministry of Economy, Trade and Industry (METI) since FY2012 and has been assisted by NEDO since FY2016. Fig. 8.24 shows the development history of oxygen-blown gasifier.

8.4.2.1 EAGLE project The EAGLE (coal energy application for gas, liquid, and electricity, or a program for developing a technology for manufacturing multipurpose coal gas) project is a joint research project undertaken by NEDO and J-POWER. The pilot plant overview is shown in Fig. 8.25.

8.4.2.1.1 EAGLE—step 1 (1998 to March 2007) EAGLE—step 1 test-running: J-Power achieved all initial development goals and completed the test run for the first stage in March 2007. Table 8.7 lists the basic specifications and test results of the project.

8.4.2.1.2 EAGLE—step 2 (April 2007 to March 2010) J-POWER conducted a test run on a retrofitted gasifier until March 2010 to expand the range of applicable coal types and to verify reliability. Moreover, ahead of the rest of the world, the company conducted a demonstration tests on carbon dioxide

Examples of thermal power station

Figure 8.24 Development history of oxygen-blown gasifier. Source: Courtesy of MHPS.

Figure 8.25 EAGLE pilot plant. Source: Courtesy of MHPS.

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Table 8.7 Basic specifications and test results of the project. Coal feed rate Gasification pressure Syngas volume Gas cleanup Sulfur recovery GT output

150 t/day 2.50 MPa 14,800 m3N/h Absorption with MDEA Limestonegypsum 8000 kW

Category

Item

Target

Results

Gasification

Efficiency

Gas cleanup

Reliability Operability Performance (real O2)

Carbon conversion Cold gas efficiency Continued operation time Coal type Desulfurization performance, precision desulfurization outlet Dust removal performance

.98% .78% .1000 h 8 s1 ppm

^ 99% ^ 82% 1015 h 8 ,1 ppm

s1 mg/ m3N

,1 mg/ m3N

GT, Gas turbine; MDEA, methyldiethanolamine.

capture (chemical absorption) from coal gas (gas feed rate of 1000 m3N/h, carbon dioxide capture of about 24 t/day).

8.4.2.1.3 EAGLE—step 3 (April 2010 to June 2014) J-POWER constructed demonstration tests on carbon dioxide capture (physical absorption) from coal gas at gas feed rate of 1000 m3N/h and carbon dioxide capture of about 24 t/day and obtained design data applicable to the Osaki CoolGen project described later. The company completed 1295 consecutive hours of operation and 14,511 cumulative hours of operation, thereby completing its 11 years of test running in November 2013.

8.4.2.2 Osaki CoolGen project The Osaki CoolGen project is currently underway from FY 2012. The oxygen-blown IGCC system consists of a single-chamber, two-stage, spiralflow entrained bed of gasifier with a coal feed rate of 1180 t/day, gas cleanup unit, and 166-MW combined-cycle power generation equipment such as GT (1300 class H-100 series), ST, generator, and HRSG (see Fig. 8.26 and Table 8.8). This project is consists of three steps, the first step is the oxygen-blown IGCC demonstration test, the second step is the oxygen-blown IGCC with CO2 capture demonstration test in which CO2 capture facility is added to this IGCC, and the third step is the integrated coal gasification fuel cell combined-cycle (IGFC) with CO2 capture demonstration test in which a fuel cell is further combined. The first step demonstration test had been implemented from FY 2016 to FY 2018, and the following were verified during the test: basic performance related to the plant performance and environmental performance, facility reliability, plant

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Figure 8.26 The Osaki CoolGen project. Source: Courtesy of MHPS.

Table 8.8 Specifications of plant facilities and project schedule for oxygen-blown IGCC. Specification Generation output Coal gasification unit Gas turbine Plant performance efficiency Project schedule Construction start Power reception Gasification operation Demonstration test operation start

166 MW (gross) Oxygen-blown, single-chamber, two-stage, spiral-flow entrained bed H-100 1300
C class 40.8% (HHV, net)

March 2013 November 2015 June 2016 March 2017

HHV, Higher heating value.

controllability and operability, multicoal applicability, and economic efficiency. In terms of the basic performance a net thermal efficiency of 40.8% (HHV) was achieved, and in terms of environmental performance, the exhaust gas property was less than 8 ppm for SOx, less than 5 ppm for NOx, and less than 3 mg/m3N for soot at a conversion of oxygen (O2) concentration of 16%. In the reliability confirmation through the long-term durability test, a maximum of 2168 continuous operation hours and 5119 cumulative operation hours were recorded.

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Figure 8.27 Schedule for oxygen-blown IGCC demonstration.

Following this first step, the second step, demonstration tests for oxygen-blown IGCC with CO2 capture, began in 2019. And, as the third step, it is planned to demonstrate IGFC with CO2 capture, in FY 2022 (See Fig. 8.27).

8.5

Incineration firing by circulating fluidized bed

Worldwide vendors of circulating fluidized-bed (CFB) combustor are, for example, Foster Wheeler, Babcock & Wilcox, General Electric, JFE Engineering, Mitsubishi Hitachi Power Systems, Mitsui E&S, Siemens, Toshiba, Valmet, and so on. Eventually, the principal constructions are, as described in Chapter 2, Introduction to Boilers, classified into two, Lurgi and/or MSFB type and Ahlstrom type. Commercial CFB plants above 200 MWe are mainly supplied by two groups, Alstom and Foster Wheeler. The former is Lurgi type, and the latter is Ahlstrom type. The largest unit of Foster Wheeler 440 MWe was commissioned in 2009, Lagisza, Poland, while other plants above 200 MWe are around 260270 MWe. Based on the EPRI report [16], Alstom’s plants count 19 units and the total 5084 MWe, averaged unit power 268 MWe, and other Foster Wheeler’s 18 units, total 5164 MWe and averaged unit power 287 MWe. Most of these relatively large plants burn coal, while incineration- and/or biomass-fired boilers have relatively small capacity. The CFB boilers have very high potential of an applicability to a variety of fuels, while the boiler capacity in Japan is not so large relative to the power stations of CFB in the worldwide. This is mainly because most of the coal is imported and the quality is normally rather high. Then the coal is used, in general, in PC combustion boilers of large-capacity power plants. Fig. 8.28 shows CFB in Japan constructed in 198697. Even though the data is relatively old, but the averaged unit output, horizontal dashed line, around 150 t/h, is almost consistent throughout all data, including biomass-fired CFBs in the worldwide. This is mainly because the CFB boilers for incineration and biomass need additional costs to collect the materials

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distributed relatively widely. In the following the practical CFB boiler of MSFB type is explained briefly. The CFB for electric power generation rate 49.9 MW shown in Fig. 8.29 was constructed by Mitsui E&S in 2006 and commissioned in 2008, that is, more than

Figure 8.28 CFB constructed in Japan and biomass-fired recent plant (data from Refs. [16,17]. In plotting data the electric output 200 MW is converted to stream generation rate 600 t/h based on conventional power plant data).

Figure 8.29 Multisolid-type circulating fluidized-bed biomass boiler. Source: Courtesy of K. Shintani.

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10-year experience. Maximum steam generation rate is 182 t/h, maximum steam pressure 12.75 MPa, and steam temperature is 541
C. Four types of fuels, RPF (refuse paper and plastic fuel), wood chips, palm kernel shell, and harvested wood are simultaneously burnt to generate 182 t/h steam. The operating principles are the same as described in Chapter 2, Introduction to Boilers. The temperature in the combustor is maintained 850
C. Owing to the existence of 850
C-bed materials, even the fuels with high water content are combustible. As mentioned in Chapter 4, Power Boiler Design, high-temperature corrosion is hardly protected even by using SUS310S at air nozzles and mechanical valves for control of solid recirculation rates, being regularly replaced at constant interval. The tertiary superheater of SUS310J1 in the external heat exchanger suffered from high-temperature chlorine corrosion, where steam temperature was around 540
C and metal temperature became almost 600
C, thereafter protected by the overlay welding of heat-resistant metal. In such a manner, various problems have been successfully resolved by regular inspection and related maintenance, and this biomass power plant has been continuously operated.

References [1] H. Iwamoto, J. Matsuda, Y. Suzuki, K. Ochi, Experiences in designing and operating the latest 1,050-MW coal-fired boiler, Hitachi Rev. 50 (2001) 100104. [2] K. Sakai, S. Morita, T. Sato, State-of-the-art technologies for 1,000-MW 24.5-MPa/ 600
C/600
C coal-fired boiler, Hitachi Rev. 48 (1999) 273276. [3] K. Sakai, S. Morita, T. Yamamoto, T. Tsumura, Design and operating experience of the latest 1000-MW coal-fired boiler, Hitachi Rev. 47 (1998) 183187. [4] K. Kawakami, J. Kawai, N. Nagai, Design and test operation performance of 1,500
Cclass gas turbine combined-cycle power plant, Mitsubishi Heavy Ind. Tech. Rev. 46 (2) (2009) 3135. [5] H. Matsuda, K. Uchida, Renewal work of power plant for high efficiency GTCC power plant with 1,500
C—class gas turbcine, Mitsubishi Heavy Ind. Tech. Rev. 47 (1) (2010) 1518. [6] S. Shiozaki, et al., Mitsubishi Latest Large Frame Gas Turbine Development and Operating Experience, PowerGen Asia 2012, Bangkok, 2012. [7] K. Tsukagoshi, et al., Mitsubishi Latest Large Frame Gas Turbines Latest Development for High Efficiency, Asian Congress on Gas Turbines (ACGT), Tokyo, 2009. [8] T. Sakata, T. Shikata, PFBC boiler, J. Jpn. Inst. Energy 86 (2007) 270277. in Japanese. [9] T. Sato, The Large Capacity Gas Turbine for Pressurized Fluidized Bed Combustion (PFBC) Boiler Combined Cycle Power Plant, Gas Turbine Technology in Japan, Bulletin of GTSJ (2003). [10] Kyushu Electric Power Co., Pressurized Fluidized Combustion PFBC, Karita Power Station Catalogue. [11] J. Koike, S. Nakamura, H. Watanabe, T. Imaizumi, Manufacturing and Construction, Operation of Karita PFBC 360 MW Unit, in: Proc. Int. Conf. on FBC, Paper, 39, ASME, 2003.

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[12] N. Nagasaki, T. Akiyama, Latest technology for coal-fired thermal power generation: coal-fired combined cycle power generation (oxygen-blown), Therm. Nucl. Power 65 (No.10) (2014) 6973. [13] K. Sakamoto, T. Fujii, Building on success: MHPS takes on two 500-MW class IGCC projects, GTW Handbook, 33, Pequot Pub, Fairfield, 2018, pp. 2732. [14] K. Sakamoto, T. Fujii, T. Kizu, IGCC Revisited, in Japan, Modern Power Systems 39 (1) (2019) 3032. [15] T. Suto, T. Kizu, T. Fuji, Progress update of MHPS air blown IGCC and oxygen blown gasification plant, in: International Conference on Power Engineering-2019 (ICOPE2019), Kunming, China. [16] J.M. Wheeldon, Developments in circulating fluidized-bed combustion technology, in: EPRI Technical Update Report 1015695, 2009. [17] M. Kono, Design and operational results of the Mitsui MSFB boiler, in: Circulating Fluidized Bed Combustion Technology Workshop, UNDDSMS, Fushun, 1996.

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9

Mamoru Ozawa1, Mikiyasu Urata2 and Masaki Honda2 1 Kansai University, Osaka, Japan, 2Mitsubishi Hitachi Power Systems, Ltd., Yokohama, Japan

Chapter Outline 9.1 Historical trend of boiler explosions 427 9.2 Legislative framework 433 9.3 Development in boiler code and inspection organization in the United States and Germany 439 9.4 Historical development of boiler regulation in Japan 441 9.5 Outline of current inspection of power boiler 443 9.5.1 Nondestructive inspection technology for thermal power plants 443 9.5.2 Boiler inspection technology by drones 453

References

9.1

458

Historical trend of boiler explosions

Boilers is one of the essential components of energy conversion, where thermal energy generated by firing fossil fuels is transmitted to water through metallic walls to generate high-pressure and high-temperature steams. Thus the boiler is essentially exposed high-temperature flame, gas, and/or solids in the case of fluidizedbed boiler on one side, and on the other side high-temperature and high-pressure steam/water. Then the metallic walls constructed boiler tube and/or shell suffer from corrosion, erosion, creep, thermal fatigue, deposition of ash, fouling, scale formation, red-hot or superheat, and so on leading to deterioration. Boiler must withstand such severe situation; otherwise, it collapses or explodes so that surrounding people and many other things, and economy suffer serious damages. To prevent or reduce such damages, operation, material, and construction technologies are needed to be sufficient and suitable. In the development process of boilers, these technologies are not simultaneously developed or advanced. Delay or mismatch between them was normal cases. Historically recorded first explosion was Savery’s pumping machine in 1716 [1]. The danger of the boiler was recognized before the Newcomen engine, and D. Papin had developed safety valve in 1680 to be operated when the steam pressure increased beyond a certain predetermined level [2]. Papin-type safety valve consisted simply of valve, lever, and weight. This weight was determined so as to meet an allowable pressure. The first-recorded explosion was caused by adding additional Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00009-6 © 2021 Elsevier Inc. All rights reserved.

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weight. This addition of weight is not a direct cause but leads to explosion from weak part of boiler. The pumping action of Savery’s pump was induced by the pressure difference between the vacuum cylinder and the atmosphere, while the raisingup process was performed by high-pressure steam. Aside from whether James Watt noticed this explosion or not, his patent limited the operating pressure at around atmospheric pressure. When expired Watt’s patent, high-pressure machine brought about in practice. One of the typical boiler explosions was recorded by Richard Trevithick. He constructed high-pressure boiler at that time by cast iron, being 0.41 MPaG, and 3 persons suffered fatality and another two were heavily injured. The cause of explosion was an operator of machine manipulated not to open safety valve even when the steam pressure exceeded beyond the rated pressure [3]. Trevithick improved after the serious explosion by introducing feasible plug, wrought iron instead of cast iron, and so on. Around this time, steamboats were developed, while at the initial stage sea water was used for boiler-water and therefore corrosion and scale formation were quite usual and faulty operation of the safety valve was also a usual way to obtain lager output of the steam engine. Famous accident was the explosion of Steamboat at Norwich 1817, 12 persons suffered fatality, 10 injured. Based on this severe accident, the House of Commons formulated Select Committee. This Select Committee investigated the cause of explosion and proposed several countermeasures to prevent explosions, including registration and inspection of steamboat, while the legislative action of the government was not suitably conducted [4]. The economical development in United Kingdom was rapid, and the drastic increase in mass production in cotton industries and steal-making industries brought about essentially scale-up of steam power and size and capacity of steamboats. Fig. 9.1 represents such economic development in United Kingdom together with that in Germany.

Figure 9.1 Raw cotton consumption and pig-iron production in United Kingdom and Germany. Source: Data from B.R. Mitchell, International Historical Statistics: Europe 1750 1993, fourth ed., Macmillan Reference Ltd., London, 1998 [5].

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In United Kingdom the boiler regulations for steam locomotive and steam boat started relatively early time, Railway Regulation Act, 1840 and The Steam Navigation Act, 1846. This is mainly because explosions of locomotive and steamboat brings about serious number no fatalities rather than land-use boilers. Especially the latter act ordered to install safety valve not to be manipulated by operators, inspection and certification by eminent engineer appointed by the Board of Trade [6]. This is also the case in the United States. Steamboats suffered often from explosion, especially in the western rivers, for example, Steamboat Washington in 1816, as shown in Fig. 9.2. In Philadelphia, United States, Joint Committee on boiler explosions was formulated in 1817 and started detailed discussions on the cause of explosions and

Figure 9.2 Number of boiler explosion installed on steamboats and number of fatalities involved. Source: Data from L.C. Hunter, Steamboats on the Western Rivers An Economic and Technological History, Harvard University Press, Cambridge, 1949 [7].

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proposed the necessity of regulation and inspection, while the proposal was not enforced as a law. The discussion and investigation were not systematically conducted so far, and thus the committee failed to get consent from the Commonwealth [8]. The number of boiler explosion on the western rivers dominates, which represents the traffic or transportations on the western rivers were very important in the economy of the United States at that time. The Select Committee on the boiler explosions was formulated as in the United Kingdom, and various investigations were conducted. Finally Steam Boat Act was enforced in 1838, being slightly early. By the way, the reasonable causes of explosion, although various hypothesis had been proposed, for example, electrostatic charge and hydrogen generation from steam contacted red-hot wall, were not systematically investigated so far. The Board of Franklin Institute formulated investigation committee for boiler explosion and countermeasures in 1830 based on the recommendation from the US Secretary of the Treasury. The tasks of the committee were “What are the probable causes of the explosions of boilers used on-board of steamboats?,” “If any, what are the best means to obviate the recurrence of these evils, or to diminish the extent of their injurious influence, if they cannot be wholly guarded against?,” and “By what means can these remedies be applied and enforced?” [9]. Here, the term “probable causes” might be based on the thought that explosions were brought about by integrated multiple causes. Nonzero risk and disaster mitigation concepts involved into the tasks were also very important even though about 200 years ago with reference to the present risk management. The investigation committee conducted extensive researches on, for example, boilers’ dimension, shell-plate thicknesses and materials, form and dimension of safety valves, boiler locations and number, reliability, maintenance system, water gauges, arrangement of boilers in steamboats, and construction of boilers. This committee conducted various experimental works as well. The results were reported in three reports in 1836 and 1837 [10,11]. These investigations were the first systematic one on boiler. The results revealed the following important facts: a large amount of water was ejected together with steam when the pressure reduced through opening if any; when a water contacted red-hot surface, rapid steam generation and thus drastic pressure increase was followed by; no hydrogen was produced even when steam contacted red-hot surface; depending on the size of safety valve, the pressure happened to increase after opening safety-valve. The substantial mechanisms were included in the abovementioned results. Later, D. Clark and Colburn proposed so-called Clark Colburn theory on the boiler explosion mechanisms probably based on the abovementioned results as follows: even at rated pressure, a certain location weakened by, for example, red-hot, suffered from break, through where steam was rapidly ejected, then rapid pressure decrease was followed by. Then the water in the boiler at saturated condition was transformed to steam by self-evaporation. Then steam water mixture lashed to the break of opening. This caused a large impact on the wall and broke or clashed the boiler wall [12].

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This mechanism does not make clear why the initial break or opening appear, thus the theory is phenomenological, while the prediction of initial break is still rather difficult issue in the current state. The prediction of this direct cause was extremely difficult at that time, while the indirect factors leading to the break was deterioration and corrosion of boiler and safety valve, faults in the design and construction, water treatment failure, ignorance and unawareness, and so on. Thurston listed up the percentage of these factors as shown in Table 9.1. The explosions cause serious effects surroundings. One of the typical illustrations was published in Scientific American 1882, two of three boilers exploded in Brooklyn shown in Fig. 9.3. Boiler explosions were not, of course, limited in marine applications but happened in land-use boilers. The trend of explosion and fatality by the explosions are shown in Fig. 9.4. The number of explosions increased rapidly from around 1830 and the fatalities by the explosions as well as shown in Fig. 9.4. Based on such rapid increase in the number of explosions, William Fairbairn, inventor of Lancashire boiler, proposed in 1851 a necessity of inspection and experiments. He proposed to formulate nongovernmental association for boiler inspections, and the association based on the Fairbairn’s proposal was established at Manchester in 1854, being referred to as “The Association for the Prevention of Steam Boiler Explosions, and for Effecting Economy in the Raising and Use of Steam,” which was renamed as “The Manchester Steam Users’ Association for the Prevention of Boiler Explosions and for the Attainment of Economy in the Application of Steam (MSUA),” being the first third-party boiler inspection organization [17]. Extending the number of boiler inspection and, also similar organizations, for example, The Steam Boiler Assurance Co. (later Vulcan Boiler and general Assurance) being founded in 1859, the number of inspected boilers increased drastically as shown in Fig. 9.5. Such extension of inspections, and also the development in boiler construction technologies, the number of explosions and fatalities turned to decrease drastically around 1860 70. At the beginning, MSUA did not have insurance function, while following such foundations of insurance companies MSUA installed insurance function in 1864 as well. Similar insurance companies were founded in this time, for example, The National Boiler Insurance Co. in 1864, The Engine and Boiler Insurance Co. in 1878, The Scottish Boiler Insurance and Engine Inspection Co. in 1881, and The Ocean Accident and Guarantee Corporation in 1889. These many foundations of insurance companies enhanced the boiler inspections throughout United Kingdom [14]. In the United States, Hartford in Connecticut the investigation committee on boiler explosions, similarly to Philadelphia in 1854, was found, and based on the discussion in this committee, a state law for boiler inspection was enacted in 1864. Following the MSUA and other insurance companies in the United Kingdom, total 12 insurance companies had been established in Hartford in 1865. By unifying these insurance companies the Hartford Steam Boiler Inspection and Insurance Co. was founded in 1866 [21]. The Hartford published “the Locomotive” regularly and the

Table 9.1 Causes of boiler explosions. Cause

United Kingdom (cause of explosion)

United States (number of defects detected) Danger

Deterioration, corrosion Faults in design/construction Failure in water treatment Ignorance and unawareness Miscellaneous Total

Number of defects

Danger/defects

Number

Percentage

Number

Percentage

Number

Percentage

Percentage

20 11 4 4 4 43

46.5 25.6 9.3 9.3 9.3 100

1727 2957 56 983 1403 7126

24.2 41.5 0.8 13.8 19.7 100

17873 15895 130 6404 6928 47230

37.8 33.7 0.3 13.6 14.6 100

9.7 18.6 43.1 15.3 20.2 15.1

Source: Data from R.H. Thurston, Steam-Boiler Explosions

in Theory and in Practice, third ed., John Wiley & Sons, New York, 1903, (1st ed. 1887, 2nd ed. 1894) [12].

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Figure 9.3 Boiler explosion at Brooklyn [13].

annual report. Based on the Locomotive in 1902, around 255,000 boilers were inspected in 1901, about 100,000 boilers among them received internal and external inspections, and hydrostatic tests were conducted for over 11,000 boilers [22]. Based on these inspections, 950 boilers were judged unusable. The scale formations occupied around 20% and defects of rivets 17% among the total number of defects detected. The trends of these data are shown in Fig. 9.5.

9.2

Legislative framework

Although the effectiveness of the regular inspection of boilers had been well demonstrated, without legislative framework the further extension of inspection was limited. In 1869, M.P. Sheridan Bill (Bill to provide for the periodical inspection of steam boiler) was proposed, while the bill was not accepted by the House of Commons. A main reason was that excess interference from the government was

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Figure 9.4 Trends of boiler explosions and fatalities in the United Kingdom. Source: Data from Refs. W.H. Chaloner, Vulcan The History of One Hundred Years of Engineering and Insurance 1859 1959, The Vulcan Boiler and General Insurance Co. Ltd., Manchester, 1959; The Manchester Steam Users’ Association (MSUA), A Sketch of the Foundation and of the Past Fifty Years’ Activity of the Manchester Steam Users’ Association for the Prevention of Steam Boiler Explosions and for the Attainment of Economy in the Application of Steam, Taylor, Granett, Evans, & Co., Manchester, 1905; Report from the Select Committee on Steam Boiler Explosions; together with the Proceedings of the Committee, Minutes of Evidence, and Appendix, The House of Commons, 1870; His Majesty’s Stationery Office, Report to the Secretary of the Board of Trade upon the Working of the Boiler Explosions Act 1882 and 1890 with Appendices, Darling & Son, Ltd., London, 1906 [6,14 16].

hesitated by the boiler owners. In 1870 the Select Committee on Steam Boiler Explosions was formulated under the House of Commons, and extensive discussions were conducted. At the hearings of the Committee, Fairbairn insisted that the legislative framework was needed not for inspection by the government but to certificate the inspection organizations of nongovernmental side. He further insisted not to formulate direct regulation system from the government [23]. The number of accidents of inspected boilers was 1/10,000 per year, while noninspected boilers suffered 279 accident in 5 years (1866 70). The abovementioned Select Committee reported the causes of boiler explosions in 1861 70 as follows: defects in construction 40%, defects of shell and fittings 29%, defects in rivets 15%, low water level 10%, scale formation and related red-

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Figure 9.5 Trend of inspected boilers. Source: Data from The Hartford Steam Boiler Inspection and Insurance Co., in: The Locomotive, vol. 32, 1918 1919, p. 51; The Hartford Steam Boiler Inspection and Insurance Co., in: The Locomotive, vol. 33, 1920 1921, p. 51, 102, 184, 215; The Hartford Steam Boiler Inspection and Insurance Co., in: The Locomotive, vol. 35, 1924 1925, p. 215. [18 20].

hot 3%. The number of explosions in this decade was 411, the fatalities were 639 together with 782 injured. The effort of the MSUA was successively accepted by the society and finally MSUA proposed a bill for legislative framework, being finally enacted as Boiler Explosion Act, 1882. This act was not focused on the strict control or regulation of boilers but focused on accident investigations after the boiler explosions, as being very important not to repeat accidents. Based on this act, many accident investigations were conducted. One of the examples was shown in Fig. 9.6. The No. 90 boiler explosion investigated based on the framework of Boiler explosion Act, 1882 was a vertical boiler of 10 years old. This boiler was inspected

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Figure 9.6 Exploded vertical boiler No. 90 in August 1884 [24].

by the National Boiler Insurance Co. The boiler suffered from external corrosion caused by the leakage of boiler-water and deteriorated in its strength, while this defect was not detected at the inspection owing to the brickworks. This boiler was regularly inspected during these 10 years, but with minor defects. Before the explosion the inspector advised detailed examination of the corroded part through the internal inspection in April 1884. The fact that the severity in external corrosion was not detected, although the corrosion of inner wall detected, revealed an importance of the quality of inspection [24]. This Boiler Explosion Act, 1882 was not applied to official and/or boilers inspected by the Department of Commerce and, therefore, was amended in 1890 so as to be applicable to all boilers including steamboats. The detailed descriptions can be found in several books and reports as listed in the literatures. Acts related to the boiler explosion up to 1912 in United Kingdom are here listed up in the following: Railway Regulation Act, 1871 Obligation of prompt report to the Department of Commerce after the boiler explosion, and order for accident investigation by the Department. Coal Mines Regulation Act, 1872 Obligation of installation of syeam and water guages, and safety valve.

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Factory and Workshop Act, 1901 Enactments of official accident investigation and regular inspection of all boilers. Quarry Act, 1894 Act for accidents in mining. Merchant Shipping Act, 1894 Obligations of report within 24 hours after boiler explosions, and of the accident investigation. Notice of Accidents Acts, 1894 and 1906 Obligation of report of all industrial products. Railway Employment (Prevention of Accidents) Act, 1900 Prevention of suffering injury from accidents, and rule for water gauge location, and so on. Coal Mines Act, 1911 Obligation for regular inspection of boilers, prohibition of installing boilers underground, and rules for safety valves, water gauges, pressure gauges, and so on.

The enactments of such many acts suggest an importance of boiler explosions based on the severity and influences on the safety and economy. It should be noted here that the Lloyds’ Register of Shipping was a nongovernmental representative organization for third-party inspection. Lloyds’s Register of Shipping was established in 1760 and reorganized in 1834 to Lloyds’ Register of British and Foreign Shipping and set up the Rules for Classification. This rule was for certification of steamboats based on the regular inspection and boilers specification so on, thus the rule was one of the standards of steamboat at that time. Based on this standard, regular inspections were conducted by the Lloyds’ master engineers. Lloyds’ often set up and/or amended rules so as to meet the-state-of-the-art of boiler and Table 9.2 Statistics of boiler explosions and collapses in 1882 1910. Type of boilers

Plain cylindrical Locomotive and portable Cornish Vertical with internal fire-box Lancashire Galloway Chimney Marine Return flue Water tube Multitubular externally fired Miscellaneous Hot water Total

Land boilers

Marine boilers

Explosions

Collapses

Explosions

Collapses

68 43 40 25 20 0 1 1 0 15 1 25 89 328

0 37 66 154 32 10 6 0 0 0 0 4 4 313

0 0 0 8 0 0 0 5 7 1 0 0 0 21

0 2 0 35 0 0 0 77 10 0 0 3 0 127

Source: Data from E.J. Rimmer, Boiler Explosions, Collapses and Mishaps, Constable & Co. Ltd., London, 1912 [26].

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shipbuilding technologies. Lloyds’ rules, for example, in 1883 84, steamboats and boilers installed were needed to be inspected regularly through all periods from their construction and to practical operations. Boilers must be regularly examined through hydrostatic test, and also boiler shells, flanges, man-hole rivets, and stays were examined [25]. Similar standards might be set up by MSUA, and other insurance companies of nongovernmental organization as well. On the other hand, there have been no unified governmental regulations for boilers at this time except prompt reports after accidents and accident investigations, which might be a British way of thinking. Rimmer listed up and classified boiler explosions and collapses as shown in Table 9.2 and 9.3 [26]. Rimmer also presented the trends of boiler explosions. Based on his data, the trends were plotted in Fig. 9.7. Table 9.3 Statistics of causes of boiler explosions and collapses in 1882 1910. Cause

Corrosion Grooving Excessive pressure Outlet frozen Failure of stays Deficiency of water Weak structure Fractures Deterioration Seam rips Scale deposits Uncertain Total

Land boilers

Marine boilers

Explosions

Collapses

Explosions

Collapses

106 29 33 70 15 19 15 14 5 7 13 2 328

150 4 27 4 13 68 29 2 0 0 12 4 313

11 0 3 0 0 0 1 0 4 0 0 2 21

18 0 9 0 4 53 4 0 0 0 35 4 127

Source: Data from E.J. Rimmer, Boiler Explosions, Collapses and Mishaps, Constable & Co. Ltd., London, 1912 [26].

Figure 9.7 Trend of boiler explosions and mishaps. Source: Data from E.J. Rimmer, Boiler Explosions, Collapses and Mishaps, Constable & Co. Ltd., London, 1912 [26].

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In the beginning of boiler technology, explosions were of highest level. With the development of technologies, explosions and collapses in land boilers reduces in their number. It should be noted here that mishaps increased successively from around 1880 in land and marine boilers, instead of decreasing explosion and/or collapses.

9.3

Development in boiler code and inspection organization in the United States and Germany

As mention previously, Steamboat Act was enacted in the United States in 1838, which set up rules of regular inspection of steamboats. Based on this inspection, a certificate for safety was given, while the standard for inspection was not well established, so that the level of inspectors must be sufficiently high in their engineering skills. This act was amended in 1843, and again in 1871, so that the act became “An Act to Provide for the Better Security of Life on Board of Vessels Propelled in Whole or in Part by Steam, and for the Other Purpose”. Based on this amended act, Supervising Inspector Office was established for supervising boiler inspections in the whole United States, and General Rules and Regulations for boiler inspections were set up [27]. Around this period, there were no common standards of boiler evaluations, and various types of evaluation methods prevailed. Thus the American Society of Mechanical Engineers (ASME) started the standardization of boiler evaluation method in the Committee on Standard and Gauge and established the first ASME standard, “Code for the Conduct of Trials of Steam Boilers.” [28]. In the United States the American Boiler Manufactures Association (ABMA) was established for the standardization of boiler construction and preventing unsafe boilers, while conflicts between boiler makers became tangible and initial purpose was failed. Fig. 9.8 shows the number of explosions in the United States and Germany. There are two data, one from ASME and the other from NBBI. Both data do not strictly coincide but trends of both data agree with each other as a whole, that is, both data clearly indicate that around 400 explosions took place in the United States. From such trend, Commonwealth of Massachusetts organized the Board of Boiler Rules and set up the rules for constructions and installations in 1907. This rule is officially referred to as “An Act Relating to the Operation, and Inspection and Inspection of Steam Boilers” [29], which consisted of 30 articles: (1) regular inner and outer inspection of once in a year; (2) registration of boiler installation; (3) outer inspection includes rated pressure, safety valves, pressure gauges, water gauges, and so on; and (4) chief engineer was registered by regional police or certificated by assurance company. Important issue of this rule is that boilers constructed based on the Massachusetts rule shall be stamped “Massachusetts Standards”. Rules similar to the Massachusetts rules were set up in Ohio. Similar movement was extended to whole United States, while these rules were not uniform throughout the United States, and there were some conflicts that boilers constructed outside the corresponding states could not installed. To unify the boiler code,

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Figure 9.8 Number of boiler explosions in the United States and Germany. Source: Data from A.M. Greene, Jr., History of the ASME Boiler Code, ASME, 1955; M. el Mehelmy Kotb, ASME/Statistics from the National Board of Boiler and Pressure Vessel Inspectors in the presentation “100 Years of the BPVC”, National Board General Session Bellevue, Washington, DC, 2014; F. Mu¨nzinger, Dampfkraft-Berechnung und Bau von Wasserrohrkesseln und ihre Stellung in der Energieerzeugung, Julius Springer, Berlin, 1933, p. 11 [9,30,31].

ASME set up the Boiler Code Committee in 1911. The first report from the Committee appeared in 1913, and final code was established in 1915 as the ASME Boiler Code, being based on the Massachusetts rules while rather different [9]. To ensure appropriate operation based on ASME boiler code the National Board of Boiler and Pressure Vessel Inspectors (NBBI) was founded in 1919. The purpose of NBBI was to “promote one uniform code of rules and one standard stamp to be placed upon all boilers in accordance with the requirements of that code, and one standard of qualifications and examinations for inspectors who are to enforce the requirements of said code.” This is simply “One Code, One Stamp, One Standard” principle. Both of ASME and NBBI collaborated to ensure the safety of boilers. Such trends of boiler rules and formation of NBBI enhanced the boiler inspections and thus the number of explosions reduced drastically after the peak around 1900. Since then the ASME Boiler and Pressure Vessel Code have been widely applied and became a very important standard of boilers. In Fig. 9.8, data of Germany of are also shown, while the number was far below those of the United States. Before closing this section, boiler regulation history in Germany is briefly described.

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¨ V Bayern. Figure 9.9 Boiler inspection data by DU ¨ berwachungs-Verein Bayern, Sicherheit in der Technik: 100 Source: Data of Technischer U ¨ berwachungs-Verein Bayern e.V., Festschrift den Mitgliedern und Jahre Technischer U Freunden zum Jubil¨aum, 1970 [33].

As is seen in Fig. 9.1, industrial development was around 30 years behind the United Kingdom. The industrialization in Germany started in Preußen (Prussia) in 1831, that is, introduction of registration of boiler installation (Allerho¨chiste Kabinetsorder). In 1838, rules for materials of boiler construction were set up in Preußen, and rules for boiler operations and regulations were established. Then the ¨ berwachung und association for boiler inspection and insurance (Gessellshaft zur U Versichrung von Dampfkesseln) was established in Mannheim in 1866. This associ¨ V in Germany, which leads to the present TU ¨ V [32]. ation was the first DU ¨ Similar inspection associations (DUV) were founded in Northern Germany (1869), Bayern (1870). Magdeburg (1871), Rheinland (1872), Sachsen (1873), Hannover (1878), Brauschweig (1893), and so on. In 1883, Deutscher Verbund von ¨ berwachungsvereinen (German Union for Boiler Inspectors’ Dampfkessel-U Associations) was formulated. This union together with the VDI (Verein Deutscher Ingenieure, The Association of German Engineers) standardized method of boiler ¨ V reorganized as TU ¨ V (Technischer U ¨ berwachungsverein) to examination. The DU cover not only boiler and pressure vessel but also technologies in general. The ¨ V Bayern is shown in Fig. 9.9. inspected number of boilers by DU An increase in the number of inspections demonstrated the economic growth in Bayern, which decreased successively from around 1920 (World War I). This trend continued to the end of World War II. Thereafter, the number kept almost constant, while the heat transfer area and steam generation rate drastically increase, that is, the growth of unit capacity of boiler.

9.4

Historical development of boiler regulation in Japan

The first regulation for boilers started in 1877 by the Ordinance No. 60 from Tokyo Police Officer. This ordinance focused mainly on the emission of smoke and

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requested to register boiler installation. The regulation system was introduced from Germany and, therefore, the Ministry of Interior, that is, police agency, which was quite different from United Kingdom. This is mainly because Japanese industrial technologies were far behind the western countries, and police agency was considered suitable as the regulation and control organization. In 1889, instead of the first ordinance, rules for regulation of boilers and steam engines, Police Order No. 21, which was in reality the first practical regulation for boilers. The rules requested the registration of boiler installation with the data of boiler specification, and hydrostatic test, and two-times inspections per year were ordered. The Police Order No. 21 was amended several times to become Police Decree No. 24 in 1894, which was amended in 1911 so that the nongovernmental organization certified by Police Agency could conduct boiler inspections. The first such nongovernmental organization was insurance company, later included in Yasuda Fire & Marine Insurance. In the same year 1912, Electricity Business Act was enacted. The boiler regulation was conducted by each prefectural police, which meant that the detailed descriptions of the rules were different between each prefecture. In a certain case, boiler constructed in one prefecture could not be installed in the other prefecture. In 1920 boiler regulations together with the internal combustion engines included into the rules for regulation of prime movers, Ordinance No. 24 of Tokyo Metropolitan Police Office. This prime mover rule was divided in 1932, and again Boiler Regulation Rules of the Ordinance No. 60 of the Metropolitan Police Office. After these elapsed periods, Japanese unified standard, Boiler Regulation Act, was set up by the Ministry of Interior in 1935, by which the conflict between prefectures were resolved. At the same time the boiler construction code was established. These Act and Construction Code included rather detailed rules of boilers, which represented typical features that governmental regulations dominated throughout boiler designs, installations, constructions, operations, and inspections in Japan, being quite different from United Kingdom. As mentioned previously the industrial boilers were in charge of the Ministry of Interior, that is, Police agency, while Electricity Business Act was in charge of Ministry of Communication and Transportation. In 1935, boilers for power generation were regulated by the Rules for Regulation of Power Boiler and Power Generation. Later boilers for power generation became in charge of the Ministry of International Trade and Industry. On the occasion of enact of unified boiler rule the boiler association was established and published bulletins and textbooks of boilers. The activity of this association was stopped owing to the World War II and, after the war, was newly established by Japan Boiler Association. This association mainly focused on the inspection of industrial boilers. On the other hand, the power boilers were in charge of the ministry of Communication & Transportation since 1935 based of the Electricity Business Act, while after World War II, government systems were reorganized, and the power generation was transmitted to the charge of the Ministry of International Trade and Industry in 1964 together with an enactment of new Electricity Business Act. In 1970, Japan Power Engineering and Inspection Corporation was established. As

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such, boiler inspection system in Japan was operated by nongovernmental organization but the administrative agencies of the government and detailed rules were given under the governmental regulations, but not of the nongovernmental third parties.

9.5

Outline of current inspection of power boiler

As mentioned previously, boiler explosions and many other troubles are prevented and mitigated by careful and comprehensive inspections, which has been verified through a long history of boiler technology. Then the regular and/or temporal boiler inspections, nowadays conducted, have a substantial importance for safe and steady operation of the power generation plant. Starting from direct observation and/or hammering, various inspection technologies and devices have been developed and evaluated in accordance with the boiler development. This section describes current sophisticated inspection technologies and devices.

9.5.1 Nondestructive inspection technology for thermal power plants Boiler facilities for thermal power plants are necessarily operated for long periods in high-temperature and high-pressure states, and there are concerns that each facility may be damaged due to aging and deterioration such as wear, corrosion, and creep. Therefore on top of daily maintenance inspection, it is important to conduct inspections with due consideration given to various forms of damage. In addition, since maintenance budgets are being reduced along with the deregulation of electric utilities, more reasonable and higher precision inspection methods are required. As such, various nondestructive inspection technologies for the accurate and timely detection of damage have been developed, e.g., inner ultrasonic testing (UT)/cable-less inner UT, phased-array UT, thin film UT monitoring, eddy current testing (ECT) technology, etc., and their application to maintenance work for actual boiler facilities has been promoting. This section describes the outline of nondestructive inspection technology applied to boiler inspection.

9.5.1.1 Boiler damage and nondestructive inspection technologies In boiler facilities, various types of damage may occur from rapid load change or as a result of the operation mode. Nondestructive inspection technologies for detecting damage must be developed with full knowledge of the forms of damage and the structures of target facilities. Fig. 9.10 shows damage to boiler facilities and the nondestructive inspection technologies. First, there are concerns that on the outer surfaces of heat exchanger tubes such as economizer and reheater tubes, local erosion thinning or wide-area thinning may occur. In many cases, it is difficult to

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Figure 9.10 Damage to boiler facilities and nondestructive inspection technologies.

measure the wall thickness from the outside of tubes with a high degree of precision, and depending on where damage occurs, a significant amount of supplementary work is required. Therefore cable-less inner UT [34], which is ultrasonic immersion methods for measuring thickness from inside a tube, is effective. In addition, on the inner surface of heat exchanger tubes, corrosion thinning due to oxygen corrosion, alkali corrosion, etc., occurs, which generates corrosion products (scale), resulting in difficulty in measurement using inner UT. In addition, inspection over a wide area becomes necessary, and so tube-inserted ECT technology [35,36], which is barely affected by scale, is effective. On the other hand, at welds of large-diameter pipes such as header and main steam pipes, creep damage occurs due to the many hours of use at high temperatures. Therefore the detection of the congestion state of creep voids, which are precracking, enables the execution of appropriate maintenance, and so the application of the phased-array UT technique is effective. Furthermore, the application of the thin film UT technique [37], in which the state of damage due to the present thinning can be monitored during operation, enables the prevention of problems such as steam leaks.

9.5.1.2 Outline of various nondestructive inspection technologies 9.5.1.2.1 Cable-less inner ultrasonic testing system Fig. 9.11 shows the schematic diagrams of the conventional inner UT system [38] and the cable-less inner UT system. The cable-less inner UT system uses a small ultrasonic sensor that can be inserted into a heat exchanger tube. The cable-less inner UT system can measure the tube thickness over the whole circumference and

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the full length while traveling with the use of water pressure. Because the cableless inner UT system requires no signal cable, the large cable feeding device and pressure pump are eliminated, and thus the total weight of the system is reduced by 90% in comparison with the conventional system. In this manner the size of the system has been significantly reduced. Fig. 9.12 shows the developed small ultrasonic sensor. The small ultrasonic sensor is reduced in size according to the limitation imposed by the pipe inner diameter and consists of the ultrasonic probe, a very small pulser-receiver, a memory device for recording of measured values, and an electronic circuit and a battery for the control of such components. The measured values can be sent to a computer through a USB connection after inspection, and then data processing system

Figure 9.11 Outlines of the inner UT system and the cable-less inner UT system. UT, Ultrasonic testing.

Figure 9.12 Ultrasonic sensor for cable-less Inner UT system. UT, Ultrasonic testing (courtesy of MHPS).

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visualizes the measured waveforms and output as a thinning state diagram. The system adopts multichannel ultrasonic probes that are placed at equal intervals in the circumferential direction of the sensor. The number of channels (number of probes) used is selected depending on the tube inner diameter. In this manner the cable-less inner UT system can measure the tube thickness from the inner surface and therefore needs no tube grinding work or scaffolding, in contrast to general thickness measurement technologies that measure the tube thickness from the outer surface. Therefore the cable-less inner UT system can efficiently measure the thickness of the tubes entirely in a boiler heat exchanger tube consisting of a tube bundle. The cable-less inner UT system is also applicable to finned tubes. Fig. 9.13 shows an external view of a mockup panel that simulates a boiler heat exchanger tube. The mockup panel consists of a tube with an inner diameter of 34 mm and a bending radius of 57.5 mm. Several parts of the tube are artificially thinned to make thinning flaws. The minimum thickness values of the thinning flaws are 2.0, 2.7, and 3.8 mm. Table 9.4 and Fig. 9.14 show the measured results. Fig. 9.14 shows the analyzed results of measurement data with the use of a data processing system, and the minimum thickness values are indicated as a chart. Table 9.4 indicates that thinning parts is well detected and the tube thickness is measured at an accuracy of 6 0.1 mm against the actual thickness measured from

Figure 9.13 External view of mockup panel (courtesy of MHPS). Table 9.4 Thickness measurement results.

Actual measured valuea (mm) Measured valueb (mm) a

Thinning A

Thinning B

Thinning C

2.0 2.0

1.5 1.5

2.9 3.0

Actual measured value: Thickness measured in cross sectional inspection. Measured value: Thickness measured with cable-less inner UT.

b

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the outer surface of the tube. Fig. 9.15 shows the passage situation of the small ultrasonic sensor. It was confirmed that the small ultrasonic sensor passed smoothly through the tube and bends having a bending radius of 57.5 mm. Among many tube thickness measurement technologies, this technology is the only high-efficiency technology measurable entire heat exchanger tube thickness at

Figure 9.14 Thickness measurement results (chart diagram) (courtesy of MHPS).

Figure 9.15 Passage situation of sensor (courtesy of MHPS).

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high speed and with high accuracy and is expected to significantly contribute to the improvement in the operation ratio of boilers.

9.5.1.2.2 Corrosion thinning part inspection technique by tube-inserted eddy current testing There are concerns that on the inner surface of boiler heat exchanger tubes, corrosion thinning due to oxygen corrosion, alkali corrosion, etc., may occur. Depending on the position where the corrosion occurs, it is difficult to measure the thickness from outside the tube. Therefore application of a high-efficiency inspection technology such as inner UT is desirable. At corrosion thinning parts, however, scale is produced in association with corrosion reaction. When ultrasonic waves are applied from the inside of tube, the ultrasonic waves may scatter at scaled parts, and as a result, it becomes impossible to measure the thickness. Therefore at present, the presence or absence of thinning or abnormalities are evaluated by cutting part of the tube, inserting a fiber scope in the tube, and observing the state of the deposition of surface scale. However, since the evaluation by visual inspection is qualitative, it is difficult to quantitatively evaluate the thinning rate. A tube-inserted ECT sensor is an effective means for such inner surface corrosion thinning. ECT is a technology for detecting surface flaws on specimen by generating the eddy current on the electrically conductive specimen and observing changes in the eddy current. Since ECT uses electromagnetic reaction, thinning depth is quantitatively evaluated without the effect of scale. Fig. 9.16 shows the appearance of the developed ECT sensor and the evaluation example of simulated thinning defect. The ECT sensor adopts a multichannel system in which a plurality of small coils is arranged to prevent thinning from being overlooked and detects both local and wide-area thinning within the range of accuracy of 6 0.3 mm.

9.5.1.2.3 Surface defect detection technology by pencil eddy current testing Major damage occurring on boiler welds includes thermal fatigue, creep fatigue, etc. In periodic inspections, penetrant testing (PT) and magnetic particle testing (MT) are applied as an evaluation method of cracks caused by this damage. However, when high-temperature oxidized scale, etc., are formed on the surface of the inspection object, polishing such as blasting or grinding is required, and such preprocessing work takes time. In the case of PT the detection of cracks utilizes the capillary phenomenon of penetrant and developer, so it takes time for the penetration of detecting liquid and for the detection of defects. Furthermore, when the inspection object has a complicated shape and exists in a narrow space, such as a header tube, the work efficiency of PT and MT decreases, resulting in longer inspection times. On the other hand, there is a growing need to shorten the periodic inspection process of thermal power plants to improve the operation rate, and the efficiency improvement of nondestructive inspection implemented during periodic inspection is required. The pencil ECT sensor [39] using this feature detects defects even when the scale is attached. Fig. 9.17 shows the pencil ECT sensor. The pencil ECT sensor consists of a pencil-like holder and a small coil. The small coil is mounted on the

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Figure 9.16 Appearance of the tube-inserted ECT sensor and the evaluation example of simulated thinning defect. ECT, Eddy current testing (courtesy of MHPS).

Figure 9.17 Pencil ECT sensor. ECT, Eddy current testing (courtesy of MHPS).

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tip of the sensor and embedded in a low friction material. By bringing the tip of the sensor directly into contact with the weld end, it is possible to detect a defect even in locations where the weld shape is sharply changed. In addition, due to its pencillike shape, the sensor is easy to hold and makes inspection relatively easy, requiring no advanced skills for sensor scanning. In some cases where the inspection area has a complicated shape and is a narrow space, such as a header tube, the magnetizing device for MT is hard to access. Due to its small size, pencil ECT is easy to use even in a narrow area. Pencil ECT is also applied to the inspection of cracks occurring on not only welds but also element pipes, flat plates, etc. Fig. 9.18 indicates an inspection example of a weld of a header tube in an actual boiler. As shown in the figures, it is confirmed that penetration-indication patterns have been detected as a result of PT implemented at the location where the pencil ECT has detected a defect. Fig. 9.19 shows a comparison between the conventional PT method and the developed pencil ECT for the operation time per header pipe. While the operation time of PT is 30 minutes (including treatment of the surface) per location, that of ECT is shortened to about 5 minutes, shortened by about 80%, under the same conditions. This is greatly attributed to the reduction in the preprocessing time. This sensor is capable to shorten the time periods for defect detection and crack evaluation as well. In addition, as the inspection records is stored as digital data, the handling of records is easier than ever used ones and it is possible to create a database. As such, many advantages can be expected by applying ECT.

Figure 9.18 Inspection example of header tube in actual boiler (courtesy of MHPS).

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9.5.1.2.4 Creep damage detection technique by phased-array ultrasonic testing On large-diameter pipes such as boiler header and main steam pipe, creep damage occurs at parts affected by welding heat in long hours of use at high temperatures. Creep damage generates a significant amount of creep voids at grain boundary. The creep voids are congested and connected, and then, they become cracks, and finally penetrate wall thickness, causing a leakage. In order to prevent creep fracture and conduct maintenance as planned, it is desirable to detect creep voids before they become cracks. Phased-array method, one of ultrasonic flaw detection methods, is effective for detecting creep voids. Fig. 9.20 shows a phased-array probe for creep void inspection. This probe was designed with the optimum probe conditions found

Figure 9.19 Comparison of ECT and PT. ECT, Eddy current testing; PT, penetrant testing.

Figure 9.20 Phased-array probe (courtesy of MHPS).

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from the supersonic simulation to detect the congestion state of creep voids. Fig. 9.21 shows the comparison between the flaw detection result and the crosssectional state on the actual pipe. This shows that with the developed phased-array probe, the congestion state of creep voids is properly detected. On the actual boiler pipe the inspection was conducted using a dedicated scanner in order to improve the data reliability and the workability. The operation time has been reduced to about 50% of that of the conventional method. Thus the application of this technology enables the early detection of creep damage, prevention of serious problems such as steam leaks, and implementation of effective maintenance as planned.

9.5.1.2.5 Thickness-monitoring technique by thin film ultrasonic testing For boiler heat exchanger tubes and pipes the state of thinning is managed by periodical thickness measurement. On HRSG heat exchanger tubes, flow-accelerated corrosion (FAC) which causes thinning at a relatively high speed has been observed. As such, thickness management is important. With the conventional method, supplementary work such as the removal/restoration of thermal insulation, setting-up of scaffolding and the polishing of the tubes is required, and the workability and reliability of inspection are degraded at narrow portions. As a result, there has been a need to develop a method to solve these problems. Such damage can be effectively monitored by a thin film UT sensor. Fig. 9.22 shows an outline of the thin film UT sensor. The sensor comprises upper and lower electrodes, piezoelectric film, and signal wires, and it is a thin film with a thickness of 1.0 mm or less with great flexibility and has a heat resistance of up to about 300 C. After polishing the area to be measured, the sensor is fixed by adhesive curing, so that the thickness is monitored in the state with thermal insulation restored. Therefore no supplementary work such as the setting-up of scaffolding is required, resulting in the substantial reduction of long-term maintenance costs. In addition, by continuous monitoring, the tendency of thinning is detected, and the method is expected to be effective for thickness management especially for FAC of relatively high thinning speed. Furthermore, as the sensor has flexibility, it

Figure 9.21 Comparison between the result of flaw detection by phased-array UT and the state of the actual pipe. UT, Ultrasonic testing (courtesy of MHPS).

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Figure 9.22 Outline of the thin film UT sensor. UT, Ultrasonic testing (courtesy of MHPS).

is possible to measure the thickness of part near the weld toe, being difficult to measure using the conventional UT and other methods, and then highly reliable maintenance is implemented. There are various techniques, as mentioned previously, in the nondestructive inspection technology. It is necessary to select an appropriate technique that demonstrates required defect detection performance, after understanding each feature and considering material, damage mode, working environment, and work process. And, in order to carry out the nondestructive inspection, an accurate knowledge on the technique is necessary in evaluation and judgment.

9.5.2 Boiler inspection technology by drones In recent years, improvement of the operational rate by shortening the shutdown period of thermal power plants has been highly sought after, and, in particular, the shortening of forced outage periods and the prevention of failures in boilers have become important issues. During periodic inspections of boilers, temporary scaffolding construction in the furnace becomes an essential task, and the drastic shortening of the shutdown period becomes possible if this temporary scaffolding is

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eliminated. Accordingly, Mitsubishi Heavy Industries, Ltd. (MHI) and Mitsubishi Hitachi Power Systems, Ltd. (MHPS) focused on the utilization of drones, which have recently seen remarkable technical advancement, to develop a drone usable for initial investigations (identification of leaking parts) of unexpected tube leaks, as well as for intermediate inspections, without requiring the installation of scaffolding. Commercially available conventional drones use information such as global navigation satellite system (GNSS) and magnetic field to control the position and attitude of the drones themselves. However, GNSS is not available in a boiler because it is an enclosed space. In addition, the magnetic field is disturbed because the inside of the boiler is surrounded by metal such as the boiler tube, meaningful stable flight is not possible, and safety equipment does not work properly. Thus a boiler inspection drone with the specifications shown in Table 9.5 was developed. Since inspection accuracy equivalent to the visual inspection is necessary for the drone for boiler inspection, the defect recognition performance target was set to detect a pinhole of 1 mm in diameter or a crack of 1 mm in width, and one of the requirement specifications was that the drone could be carried in from the standard man-hole size [40].

9.5.2.1 Characteristics of inspection drones Fig. 9.23 shows the flight range of the boiler inspection drone. The flight range is the inside of the boiler furnace (red frame) and the pendant superheater just above the furnace (blue frame), where large-scale temporary scaffolding work is required for boiler inspection. Other areas, such as the rear flue, are not applicable because they are accessed relatively easily from the manhole of the rear flue and scaffolding is erected immediately. It is necessary to approach the subject as closely as possible to distinguish a defect, and two kinds of bumpers—the wheel type bumper for inspection in the boiler furnace (red frame) and the spherical type bumper for inspection of the Table 9.5 Specifications of boiler inspection drone. Item

Specifications

Size/weight of drone Wheel bumper size Spherical bumper size

590 mm/1.3 kg φ570 mm (wheel part can be divided into two parts) φ570 mm (spherical part can be divided into two parts) 5/16 m/s 0 C 40 C At least 7 h of flight φ1 mm At least 10 15 min per flight Inspection camera, LED light

Maximum rising/horizontal speed Operating ambient temperature Resistance to soot and dust Defect detection capability Duration of continuous flight On-board equipment

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Figure 9.23 Flight range of boiler inspection drone.

Figure 9.24 Wheeled bumper mounted drone (courtesy of MHPS).

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pendant superheater (blue frame) just above the furnace—have been developed, and the characteristics are shown later.

9.5.2.1.1 Wheeled bumper mounted drone Fig. 9.24 depicts the developed wheeled bumper mounted drone. One major characteristic of this airframe is that a wheeled bumper for collision prevention is mounted on its left and right sides. The hovering property is improved when this bumper comes into contact with the furnace wall, and imaging as close as 250 mm to the subject became possible. This bumper also adopted a slide structure, which can change the interval of the wheel according to the tube pitch of the furnace wall. Fig. 9.25 gives the results of an in-house flight test of this bumper. In the test the bumper was brought into contact with a large panel simulating the boiler furnace wall, and the effectiveness and defect detectability of the bumper were verified by photographing a boiler tube simulating a φ1 mm pinhole installed at the position of 6.5 m in height. As a result, it was confirmed that a pinhole of φ1 mm could be clearly photographed by flying with the wheeled bumper against the furnace wall.

Figure 9.25 Flight test results of wheeled bumper mounted drone (courtesy of MHPS).

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9.5.2.1.2 Spherical bumper mounted drone The developed spherical bumper mounted drone is shown in Fig. 9.26. It is characterized by the 360 spherical bumper made of carbon surrounding the airframe. This bumper can prevent collisions from all directions, and it can fly in narrow spaces such as the pendant superheater just above the furnace. Fig. 9.27 presents the test results of the actual flight test of this bumper. In the test the drone flies between the burner part and the pendant superheater just above the furnace and verifies the effectiveness of the bumper and the imaging accuracy of the burner part and heat transfer surface. As a result, it was confirmed that the drone flew without issue between the narrow pendant superheater, and that the conditions of the heat transfer surfaces, etc., were clearly photographed.

Figure 9.26 Spherical bumper mounted drone (courtesy of MHPS).

Figure 9.27 Actual flight test results of spherical bumper drone (courtesy of MHPS).

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9.5.2.2 Customer advantages The following lists the expected advantages of using a boiler inspection drone reflecting the results of past inspections (however, the significance of these advantages depends on the local situation): G

G

In the case of leakage abnormality the leakage position can be confirmed before the installation of scaffolding, so that the repair process can be shortened through the early identification of the cause, prior arrangement, and manufacturing of the material for repair, and shortening the scaffolding installation period by limiting the areas where scaffolding needs to be installed. By confirming the conditions in the furnace such as the condition of the burner, furnace wall tube and pendant superheater (wear, deformation, expanding, etc.), and the condition of clinker (the state in which ash has melted and hardened) adhesion during the simple periodic inspection without requiring the installation of scaffolding, it is possible to support the periodic inspection plan with high accuracy from the next time and reduce the leakage risk.

References [1] J.T. Desaguliers, A Course of Experimental Philosophy, Vo. II, Section XV, Printed for W. Innys and 2 persons in London, 1744, pp. 484 490. [2] T. Ewbank, A Descriptive and Historical Account of Hydraulic and Other Machines for Raising Water, Ancient and Modern; Including the Progressive Development of the Steam Engine, Tilt and Bogue, London, 1849, pp. 441 452. [3] A. Tilloch (Ed.), Dreadful accident, Philos Mag. 16 (1803) 372 373. [4] Select Committee on Steam Boats, Report of the select committee appointed to consider of the means of preventing the mischief of explosion from happening on board steam-boats, to the danger or destruction of his majesty’s subjects on board such boats, Philos. Mag. J. 50 (1817) 50-65, 83 100, 167 182, 243 256, 327 336. [5] B.R. Mitchell, International Historical Statistics: Europe 1750 1993, fourth ed., Macmillan Reference Ltd., London, 1998. [6] W.H. Chaloner, Vulcan The History of one Hundred Years of Engineering and Insurance 1859 1959, The Vulcan Boiler and General Insurance Co. Ltd., Manchester, 1959. [7] L.C. Hunter, Steamboats on the Western Rivers An Economic and Technological History, Harvard University Press, Cambridge, 1949. [8] J.G. Burke, Bursting boilers and the federal power, Technol. Cult. 7 (1) (1966) 1 23. [9] A.M. Greene Jr., History of the ASME Boiler Code, ASME, 1955. [10] Franklin Institute of the State of Pennsylvania, General Report on the Explosions of Steam-Boilers, C. Sherman & Co., Philadelphia, PA, 1836. [11] Report of the Committee of the Franklin Institute of the State of Pennsylvania, for the promotion of the Mechanic Arts, on the Explosions of Steam Boilers, of Experiments Made at the Request of the Treasury Department of the United States, Part II, Merrihew & Gunn, Philadelphia, PA, 1837. [12] R.H. Thurston, Steam-Boiler Explosions in Theory and in Practice, third ed., John Wiley & Sons, New York, 1903. 1st ed. 1887, 2nd ed. 1894. [13] Explosion of two steam boilers at Jewell’s Mill, Brooklyn, N. Y., Sci. Am., Vol. 13, No. 333 (May 20, 1882), p. 5303.

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[14] The Manchester Steam Users’ Association (MSUA), A Sketch of the Foundation and of the Past Fifty Years’ Activity of the Manchester Steam Users’ Association for the Prevention of Steam Boiler Explosions and for the Attainment of Economy in the Application of Steam, Taylor, Granett, Evans, & Co., Manchester, 1905. [15] Report from the Select Committee on Steam Boiler Explosions; Together With the Proceedings of the Committee, Minutes of Evidence, and Appendix, The House of Commons, 1870. [16] His Majesty’s Stationery Office, Report to the Secretary of the Board of Trade upon the Working of the Boiler Explosions Act 1882 and 1890 with Appendices, Darling & Son, Ltd., London, 1906. [17] W. Fairbairn, Useful Information for Engineers, Longman, fourth ed., Green, Longman, Roberts, & Green, London, 1864. [18] The Hartford Steam Boiler Inspection and Insurance Co., in: The Locomotive, vol. 32, 1918 1919, p. 51. [19] The Hartford Steam Boiler Inspection and Insurance Co., in: The Locomotive, vol. 33, 1920 1921, p. 51, 102, 184, 215. [20] The Hartford Steam Boiler Inspection and Insurance Co., in: The Locomotive, vol. 35, 1924 1925, p. 215. [21] G. Weaver, 1866 1966 The Hartford Steam Boiler Inspection and Insurance Company, Hartford, 1966. [22] The Hartford Steam Boiler Inspection and Insurance Co., in: The Locomotive, vol. 23, 1902, p. 27. [23] Report from the Select Committee on Steam Boiler Explosions; Together With the Proceedings of the Committee, Minutes of Evidence, and Appendix, The House of Commons, 1870. [24] Report to the President of the Board of Trade upon the Working of the Boiler Explosions Act, 1882; With Appendices, Eyre and Spottiswoode, London, 1886. [25] Lloyd’s Register of British and Foreign Shipping, Rules & Regulations for the Construction and Classification of Steel Vessel, London, 1901. [26] E.J. Rimmer, Boiler Explosions, Collapses and Mishaps, Constable & Co. Ltd, London, 1912. [27] Act of Congress Relating to Steamboats, Collated with the Rolls at Washington United States, Little Brown and Co., Boston, MA, 1853. [28] W. Kent, Rules for conducting boiler tests (CXLVII), Trans. ASME 5 (1883 and 1884) 260 281. [29] Acts, An Act Relating to the Operation and Inspection of Steam Boilers, Acts and Resolves Passed by the General Court - State Library of Massachusetts, Wright & Potter Printing Co., Boston, MA, 1907, pp. 410 417. Chapter 465. [30] M. el Mehelmy Kotb, ASME/Statistics from the National Board of Boiler and Pressure Vessel Inspectors in the presentation “100 Years of the BPVC”, National Board General Session Bellevue, Washington, DC, 2014. [31] F. Mu¨nzinger, Dampfkraft-Berechnung und Bau von Wasserrohrkesseln und ihre Stellung in der Energieerzeugung, Julius Springer, Berlin, 1933, p. 11. ¨ V Nord Gruppe, Die Geschichte der Technischen U ¨ berwachung in Norddeutschland, [32] TU Books on Demand GmbH, Norderstedt, 2003. ¨ berwachungs-Verein Bayern, Sicherheit in der Technik: 100 Jahre [33] Technischer U ¨ berwachungs-Verein Bayern e.V., Festschrift den Mitgliedern und Technischer U Freunden zum Jubil¨aum, 1970.

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[34] M. Urata, K. Aoki, N. Urata, T. Wada, S. Tsubakizaki, S. Matsumoto, Thickness measurement technology using cable-less inner UT for boiler heat exchanger tube, Mitsubishi Heavy Ind. Tech. Rev. 53 (4) (2016) 60 64. [35] M. Urata, K. Aoki, N. Urata, T. Yamaguchi, K. Jinno, S. Matsumoto, High-efficiency inspection technology for inner surface corrosion of lengthy tubes by ECT, Mitsubishi Heavy Ind. Tech. Rev. 55 (2) (2018) 1 4. [36] M. Urata, T. Yamaguchi, N. Urata, T. Nakahara, Y. Kurosawa, H. Takahashi, Development of inspection technology for caustic gouging of combined cycle HRSG (Pneumatic Transfer ECT), Mitsubishi Heavy Ind. Tech. Rev. 55 (4) (2018) 1 5. [37] N. Urata, S. Tsubakizaki, K. Aoki, Y. Yamamoto, T. Hirasaki, S. Iida, Development of thickness trend monitoring technology (thin-film UT sensor) and field verification of water treatment technology (high-AVT) for HRSG FAC control, Mitsubishi Heavy Ind. Tech. Rev. 56 (1) (2019) 1 7. [38] K. Iwamoto, M. Torichigai, S. Kaneko, J. Ichinari, K. Moizumi, Development of automated superheater and reheater tube wall thickness measurement system for boilers, Mitsubishi Heavy Ind. Tech. Rev. 24 (3) (1987) 173 178. [39] Mitsubishi Hitachi Power Systems, Surface defect detection technology contributes to shortening of inspection time, Mitsubishi Heavy Ind. Tech. Rev. 54 (3) (2017) 50 52. [40] Mitsubishi Hitachi Power Systems, Inspection technology for inside of power plant boilers by drones, Mitsubishi Heavy Ind. Tech. Rev. 56 (3) (2019) 1 4.

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10

Jun Inumaru, Saburo Hara and Takeharu Hasegawa Central Research Institute of Electric Power Industry, Tokyo, Japan

Chapter Outline 10.1 Introduction 461 10.2 Situation of thermal power generation

462

10.2.1 Efforts by major nations to reduce greenhouse gas emissions 462 10.2.2 Efforts by Japan to reduce greenhouse gas emissions 464

10.3 Next-generation thermal power generation technology for a decarbonized society (B2030) 464 10.3.1 Future outlook for next-generation, high-efficiency technology 468 10.3.2 Outlook for developing carbon dioxide capture, utilization, and storage and hydrogen power generation technology 470

10.4 Future outlook for thermal power generation (2030B) 10.5 Conclusion 477 References 478

10.1

472

Introduction

Chapters 1
9 cover power boilers, describing the characteristics of fuels to be used, the history of development, the perspective of thermal power plants, the details of each element of equipment, and information on plant design, operation, and maintenance, as well as the latest technology trends. In this chapter, by providing an understanding of the circumstances of thermal power generation, that greenhouse gas (GHG) reduction efforts by Japan and other major countries, as well as the development of high-efficiency technology as the next-generation thermal power generation technology in the aim of a carbon-free society, and the outlook on the development of carbon dioxide capture, utilization, and storage (CCUS) and hydrogen power generation technology are introduced. The new issues are also organized that are surfacing, including the response to the introduction of large amounts of renewable energy. Then, the future direction of thermal power generation for 2030
50 from that standpoint will be considered.

Advances in Power Boilers. DOI: https://doi.org/10.1016/B978-0-12-820360-6.00010-2 © 2021 Elsevier Inc. All rights reserved.

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Situation of thermal power generation

The Paris Agreement was adopted at COP21 (the 21st Conference of the Parties to the United Nations Convention on Climate Change) in 2015, and it came into effect in 2016. It sets out a plan to keep the rise in the global average temperature to below 2 C compared to preindustrial levels and to make continued efforts to limit the increase to 1.5 C. The members of the agreement are working on efforts to reduce GHG emissions.

10.2.1 Efforts by major nations to reduce greenhouse gas emissions The efforts by major nations in Europe and America to reduce GHGs will be organized and introduced [1]. In order to reduce energy-based CO2 emissions, it is important to raise the proportion of nonfossil fuel power in the supply of electric power, improve the electrification rate, convert to low-carbon fuel in the use of fossil fuel (e.g., natural gas instead of coal), and save energy. The European Union seeks to reduce GHG emissions by 40% (compared to the 1990 level), raise the percentage of renewal energy to 32.5 (the final energy consumption base), and achieve energy consumption efficiency that represents energy-saving performance of 32.5% (compared to business-as-usual levels) by 2030. The United Kingdom seeks to reduce GHGs by 57% by 2030. It has set out a policy of raising the percentage of renewable energy power to 53 by 2030, with nuclear power usage at 22, and moving forward with the additional installation of new nuclear power plants. It is shifting from coal to natural gas for thermal power generation, and the percentage of coal-fired power generation has decreased from 65 in 1990 to 9 in 2016. The United Kingdom also plans to close coal-fueled power plants with emission factors equal to or higher than 450 g CO2/ kWh by 2025, unless the plants take emission countermeasures. It is estimated that in 2030, natural gas-fired power will account for 24% of power. In Germany the target is to reduce GHGs by 55% (compared to the 1990 level) by 2030. It plans to raise the percentage of renewable energy to 55
60 by 2035, close nuclear power plants by 2022, and close coal-fueled thermal power plants by 2038. Germany has seen an expansion of renewable energy in recent years, and the associated increase in electricity costs is becoming apparent. The major challenge is what should be an alternative power source for coal-fired power that accounts for 43% as of 2016. In the United States the target is to reduce GHG emissions by 26%
28% by 2025 (compared to the 2005 level). So far, it has maintained the percentage of nuclear power generation at about 20, and renewable energy is on the increase at the same time, reaching 15 in 2016. The introduction of cheap shale gas has led to a shift from coal to gas fuel, and power generated from coal was reduced from 51% in 2005 to 32% in 2016. The United States has not indicated a national target for introducing renewable energy. China, the world’s largest GHG emitter, is aiming for a reduction of 60%
65% in CO2 emission per GDP by 2030 (compared to the 2005 level) and brings the percentage of nonfossil fuel in the primary energy consumption to about 20 [2].

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Fig. 10.1 shows the composition of power sources in major countries in 2016 [3]. Thermal power generation exceeds 50% in all these countries, except France, where the proportion of nuclear power is high. And in Japan, in particular, many of its nuclear power plants shut down since the 2011 Fukushima Daiichi Nuclear Power Station accident, thermal power generation is as high as 84%. As mentioned earlier, major countries have set goals of reducing GHG emissions and are working to increase the proportion of power generated from nonfossil fuels. It is expected that this will likely lead to a decrease in the proportion of thermal power generation in the future. Since coal in particular has a high GHG emission factor, it is expected that it would be difficult in major countries to add new facilities because of the shift from coal to natural gas, which has a lower emission factor, and because of the movement by financial institutions to limit investment globally. In India and the Pacific region, however, it is expected that the use of coal will continue to grow as an important power source in the future because it is relatively cheap, globally widespread, and can be supplied stably. It is likely that gas-fired power, including LNG, will grow globally because of climate change countermeasures and the downward trend of gas prices in the recent years. Particularly in the Middle East
which has many gas producing countries
and in Africa, Europe, and America, it is expected that demand will increase significantly. In response to the Paris Agreement adopted at COP21, each country is expected to move forward with its respective efforts according to its own situation as regards energy security and economic efficiency. This includes efforts to enhance the efficiency of coal-fired power generation and promote the use of gas-fired power generation.

Figure 10.1 Power generation composition by source in major countries in 2016 [3].

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Figure 10.2 Primary energy supply and power generation composition in 2017 and 2030 [4].

10.2.2 Efforts by Japan to reduce greenhouse gas emissions Fig. 10.2 shows the breakdown of Japan’s primary energy supply in 2030 and the target composition of power sources in comparison with the 2017 results [4]. Japan aims to reduce GHGs by 26% in 2030 (compared to 2013 levels). Based on this, it seeks to bring the percentage of renewable energy to 22
24 and nuclear power generation to 20
22. Thermal power generation will drop from 81% in 2017 to 56% in 2030. The breakdown shows that LNG will be reduced to 27% with a decrease of 13 points, coal to 26% with a decrease of 13 points, and oil to 3% with a decrease of 6 points. In June 2019 the Japanese government agreed on its “LongTerm Strategy Under the Paris Agreement” at a cabinet meeting and decided to reduce emission of GHGs by 80% by 2050 (compared to the 2013 level) while continuing antiglobal warming measures and economic growth. It would be difficult to achieve such a large reduction of emissions by expanding conventional measures, so Japan will seek solutions through innovation by developing and disseminating innovative technology that can drastically reduce emissions.

10.3

Next-generation thermal power generation technology for a decarbonized society (B2030)

To achieve its mid-term goal of reducing GHG emissions by 26% by 2030, Japan is now working on measures to achieve the so-called S 1 3E: a safety-first policy

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(Safety) as the foundation for a stable energy supply (Energy Security), a low-cost energy supply with higher economic efficiency (Economic Efficiency), and adapting to the environment (Environment). Also, in February 2016, the electric industries developed its “Action Plan for the Electricity Business to Achieve a LowCarbon Society” [5] that has a fiscal 2020 reduction target when building a new thermal power plant using the best available technology (BAT) that is economically feasible. It is expected that the maximum reduction potential will be a reduction of 7 million t-CO2. Also, for the fiscal 2030 reduction target, it is expected that the emission factor will be around 0.37 kg-CO2/kWh (using-end), and with the use of BAT the maximum reduction potential is expected to be about 11 million t-CO2 emissions. However, the estimated CO2 emissions in fiscal 2030 are 0.36 billion t-CO2, and the estimated electric power demand in fiscal 2030 is 980.8 billion kWh (in FY 2016, 0.43 billion t-CO2). In terms of the supply of electricity, Japan seeks to encourage the development and spread of renewable energy and to promote the electrical efficiency of thermal power generation. Developing thermal power generation technology that can reduce the environmental burden and responding to the use of large amounts of renewable energy were mentioned as R&D issues in accomplishing these goals. The METI developed its “Technology Roadmap for Next-Generation Thermal Power Generation” [6] in June 2016. This roadmap recognizes basic policies for the early establishment of next-generation thermal power generation technology and its practical use as follows: 1 In principle, next-generation thermal power generation technology will be developed simultaneously with short-to-medium-term technology and long-term technology. a Ensuring the achievement of the composition of power sources assumed for fiscal 2030. To achieve this, high-efficiency technology will be developed for coal-fired power and LNGfired power. b Developing innovative technology that can serve as the key to both the economic growth and climate change countermeasures after fiscal 2030. To achieve this, CCUS technology and hydrogen power generation technology will be developed. 2 Policy for coal- and LNG-fired power would serve as the center of the initiative toward fiscal 2030. a Early establishment of third-generation technology for the ultimate development phase while seeking to enhance the first-/second-generation technology. To achieve this, technology for higher efficiency will be developed, from a single turbine single cycle (first generation) to a combined cycle of gas turbine and steam turbine (second generation) to a triple combined cycle using a fuel cell (third generation). 3 It is important to advance the high-efficiency technology for thermal power generation while securing economic efficiency, reliability, and operability.

The characteristics of the next-generation thermal power generation technology are shown in Table 10.1 [6]. As shown in the table, there is no technology that excels in all aspects. Also, there are still other technologies not listed in the table; we should develop technologies to take advantage of the characteristics,

Table 10.1 Characteristics of next-generation thermal power generation technology [6]. High-efficiency coal-fired power

High-efficiency LNG-fired power

CCS

CCU

Hydrogen power generation

CO2 emissions

Approximately 710
590 g/kWh.

Approximately 350
280 g/kWh.

Up to approximately 0 g/kWh.

Up to approximately 0 g/kWh.

Economic efficiency (target value)

Cost of power generation: up to 9.3 JPY/kWh. Cost of CO2 countermeasures: up to 3.0 JPY/ kWh (the unit price of power generation: the same level as the conventional plant, USC).

Cost of power generation: up to 12.4 JPY/kWh. Cost of CO2 countermeasures: up to 1.3 JPY/kWh (the unit price of power generation: the same level as the conventional combined cycle plant).

The cost of storage is unknown at present, but those of capture and storage will be added to the cost of power generation.

Up to approximately 0 g/kWh, however, there are issues with the amount of treatment. The cost will increase because of capture and storage, but produced valuables may reduce the treatment cost.

Cost of power generation: 17 JPY/kWh.

Table 10.1 (Continued) High-efficiency coal-fired power

High-efficiency LNG-fired power

CCS

CCU

Hydrogen power generation

Maturity of technology

Demonstration plant of air-blown IGCC is in commercial operation.

Demonstration system of 1600 C class gas turbine is in commercial operation.

Demonstration has started at Tomakomai, Hokkaido, but there are practical issues to be solved, for example, selection of storage site.

Hydrogen-fired boiler is still in R&D stage. There are issues of NOx reduction technology.

Issues

Double the amount of CO2 is generated compared with LNG-fired boiler.

The cost of power generation is higher than that of coal-fired power. The stability of fuel supply is poor compared with coal.

There are issues such as low efficiency, increase in power generation cost, and selection of storage site.

Currently still in the research stage. Issues include the expansion of application of large amount of CO2, establishment of mechanisms for profit generation, enhancement in efficiency of treatment technology. There are issues such as low efficiency, increase in power generation cost. Still at the R&D stage, the amount of treatment is unknown.

CCS, Carbon dioxide capture and storage; CCU, carbon dioxide capture and utilization; IGCC, integrated coal gasification combined cycle.

The power generation cost is higher than the other thermal power plants. It is essential to establish hydrogen supply chain.

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considering the policy trends and technological development stages of the respective countries.

10.3.1 Future outlook for next-generation, high-efficiency technology The technological development stage for enhancing the efficiency of thermal power generation is shown in Table 10.2 [6]. Currently, the gas turbine combined cycle (GTCC) and the integrated coal gasification combined cycle (IGCC) are being developed based on the second-generation combined cycle as the core technology. The development of third-generation technology based on the triple combined cycle is planned, intended for practical use after 2020. In order to respond to the recent expansion of the introduction of variable renewable energy (VRE)—such as solar power and wind power—what is now required of thermal power generation, in addition to higher efficiency, is a high load following capability that contributes to the stabilization of the electrical power system. This will be described in Section 10.4. Japan’s outlook for developing the next-generation, high-efficiency thermal power generation technology is shown in Fig. 10.3 [7] As to LNG-fueled power, Japan aims to establish the technology for the 1700 C class GTCC (with a power generation efficiency of 57% and a CO2 emission factor of around 0.31 kg/kWh) in 2020 or so. It also aims to establish the technology for a gas turbine fuel cell (GTFC) combined cycle (with a power generation efficiency of 63% and a CO2 emission factor of approximately 0.28 kg/kWh) with the aim of reducing the CO2 emission factor by around 20% in 2025 or so. Table 10.3 [6] shows the development policy of the individual technology for coal-fired power. For advanced ultrasupercritical (A-USC) (with a power generation efficiency of 46% and a CO2 emission factor of around 0.71 kg/kWh), the plan is to develop the elemental technology to establish the technology by fiscal 2016, and continue the assessment of materials, and enhance the reliability of technology by developing the maintenance technology to gradually improve the power generation efficiency. As to the 1700 C class IGCC (with a power generation efficiency of 46 to 50% and a CO2 emission factor of around 0.65 kg/kWh), the technology for medium-sized, air-blown IGCC machines will be developed first, followed by the technology for oxygen-blown IGCC and larger air-blown IGCC machines. Then, the efficiency will be enhanced using the achievement of ultrahigh temperature GTCC (1700 C). The integrated coal gasification fuel cell (IGFC) combined cycle (with a power generation efficiency of 55% and a CO2 emission factor of around 0.59 kg/kWh) will be developed in an integrated manner with the oxygen-blown IGCC. Additional technology will be developed after the end of a demonstration project of a small-scale IGFC in fiscal 2021. Then, large-scale IGFC technology will be established using the achievement of GTFC technology development. The requirement for the practical application and dissemination of these technologies is excellent economic efficiency.

Table 10.2 The technological development stages of enhancing the efficiency of thermal power generation [6]. First generation

Second generation

Third generation

Common elements

Single cycle Single gas turbine (GT)/single ST

Combined cycle GT 1 ST

LNG-fired power

GT/ST (1950s) AHAT (2010s)

Coal-fired power

SUB-C (1950s) SC (1970s) USC (1990s) A-USC (2010s)

1100 C class GTCC (1980s) 1700 C class GTCC (2020s) Over 1800 C ultraclass GTCC 1300 C class IGCC (2010s) 1800 C class IGCC Innovative IGCC

Triple combined cycle (fuel cell combined cycle) Fuel cell 1 GT 1 ST

GTFC (2020s
)

IGFC (2020s
)

AHAT. Advanced humid air turbine; A-USC, advanced ultrasupercritical; GT, Gas turbine; GTCC, gas turbine combined cycle; GTFC, gas turbine fuel cell; IGCC, integrated coal gasification combined cycle; IGFC, integrated coal gasification fuel cell.

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Figure 10.3 Prospects of next-generation thermal power generation technology, raising efficiency and lowering carbon emission in Japan [7].

10.3.2 Outlook for developing carbon dioxide capture, utilization, and storage and hydrogen power generation technology CCUS technology and hydrogen power generation technology can be a trump card for zero CO2 emissions from thermal power generation. The technologies will be promoted strategically [6] from the following long-term perspective: G

G

For carbon dioxide capture and storage (CCS) technology, economical storage technology will be established from around the latter half of the 2020s
30 or so. As for conventional technology, the cost of power generation was growing because of a large decline in efficiency due to the motive power consumption of CO2 storage equipment. Economical CCS technology will be developed based thereon. For the time being, promising future technology for carbon dioxide capture and utilization (CCU) will be established with an eye toward fiscal 2030 and beyond. With CCU, it is currently difficult to treat CO2 on a large scale, but there is the possibility of creating profit by producing valuables. However, there are issues with CO2 treatment capacity and enhancing the efficiency of producing valuables. Great innovation is needed for practical use. While there are currently many uncertainties, we will verify the goals of treatment capacity and creating profits as well as the possibility of higher efficiency through technological innovation and continue to develop the technology to establish promising future technology with an eye toward fiscal 2030 and onward.

Also, Japan plans to promote hydrogen power generation concurrently with the CCUS technology, seeking practical application in around 2030. In introducing hydrogen power generation, however, there are issues with the supply of hydrogen, such as production, transport, and storage, in addition to the technical issues of declining efficiency due to limiting NOx emissions. To be more specific, there is the issue of the

Table 10.3 Development policy for individual technologies [advanced ultrasupercritical (A-USC), integrated coal gasification combined cycle (IGCC), and integrated coal gasification fuel cell (IGFC)] [6]. Development policy A-USC IGCC

IGFC

Element technologies have been developed by FY 2016. The developed materials are continuously assessed, and the maintenance technology is now being developed to improve reliability of the system. Power generation efficiency is gradually improved. The technology of medium-sized air-blown IGCC will be established as the first priority. Current tasks are the technology establishment of large-sized oxygen-blown and air-blown IGCCs. After the development of ultrahigh temperature GTCC, the thermal efficiency will be further improved. The development will be conducted integrally with oxygen-blown IGCC. After the small-scale IGFC demonstration project in FY 2021, the results of GTFC and additional technology development will be applied to establish large-scale IGFC technology. Timing of technology establishment

CO2 emissions

Net thermal efficiency (HHV)

Coat target

A-USC

Around FY 2016

Approximately 46%

Similar to conventional system

IGCC

Around 2020 (1700 C class IGCC)

Approximately 46%
50%

IGFC

Around FY 2025

Approximately 710 g-CO2/kWh Approximately 650 g-CO2/kWh (1700 C class IGCC) Approximately 590 g-CO2/kWh

The same level as conventional system after large-scale introduction The same level as conventional system after large-scale introduction

GTCC, Gas turbine combined cycle.

Approximately 55%

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Figure 10.4 Prospects of next-generation CO2 capture-related technology development in Japan [8].

economic-efficiency viewpoint on how to reduce the cost of power generation, which is more expensive than coal- or LNG-fired power generation. There are also issues from the viewpoint of supply stability, such as how to secure and supply sufficient hydrogen. What is essential to overcoming these challenges is to establish an inexpensive and stable hydrogen supply chain. At present, we are mainly using fossil fuelbased hydrogen, but CO2 is produced at the hydrogen production stage. Accordingly, in future, we need to achieve a hydrogen supply mechanism with lower CO2 emissions by using technology that reduces CO2, such as CCS and renewable energy. The outlook for next-generation CCUS-related technology is shown in Fig. 10.4 [8] This diagram shows a closed IGCC (high-efficiency CGCC), which is a nextgeneration IGCC system using CO2 capture based on a new concept: oxy-fuel technology is applied to IGCC in which the carbon dioxide in the emission gas is used as an oxidizing agent to be circulated in the gasification furnace and in the gas turbine to perform combined cycle power generation. This system does not require a shift reaction vessel or CCS equipment. It is expected that the effect of promoting gasification by circulating CO2, even after CO2 capture, will result in achieving efficiency of about 42%. At present, elemental technology is being developed with the aim of starting practical services for 2030 onward. Fig. 10.5 [9] shows the structure of this system in comparison to the conventional CO2 capture system, and Fig. 10.6 [9] shows the power generation efficiency in comparison with conventional systems.

10.4

Future outlook for thermal power generation (2030B)

In this section, we would like to look at the direction of thermal power generation for 2030
50. As mentioned in Section 10.1, in line with the 2015 Paris Agreement,

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Figure 10.5 Comparison of schematics of IGCC system with CCS [9]. (A) Precombusion capture system and (B) high-efficiency oxy-fuel IGCC system. IGCC, Integrated coal gasification combined cycle; CCS, Carbon dioxide capture and storage.

countries around the world are making various efforts to reduce GHG emissions. As a result, in countries that are rapidly introducing large amounts of VRE, we are likely to see a further decrease in operation availability of thermal power generation. The shift from coal to gas will also be accelerated. In addition, the major challenges will be a decline of profitability caused by the decrease in the use of thermal power generation facilities and a lower wholesale electricity cost. If a large amount of VRE is introduced, it will be necessary to adjust the output fluctuation using thermal power generation as the backup. This is a major challenge in facility operation, and it is becoming more apparent. In order to stabilize the electrical power system frequency while maintaining the supply and demand balance, what is required of thermal power generation facilities is to adjust to frequent starts and stops, operation in the lower load zone, and rapid load changes. Considering this situation, for example, the target facility performance related to flexibility is mentioned as indicated in Table 10.4 [10]. For both USC and GTCC, it is necessary to improve the current speed of the load change by double, reduce the minimum output to half of the current level, and further reduce the start-up time. However, issues have been pointed out, such as the impact that these operational changes may have

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Figure 10.6 Comparison of efficiencies of IGCC system with CCS [9]. IGCC, Integrated coal gasification combined cycle; CCS, Carbon dioxide capture and storage.

on the fatigue deterioration of materials for thermal power generation facilities and the decline in efficiency due to partial power operation. These issues need to be considered in the future. It is also essential to adequately assess the values of adjustability of thermal power generation (kWh, kW, and ΔkW) and improve the framework that can serve as an incentive to the operators in developing and introducing highly flexible facilities. According to Japan’s long-term climate change strategy, it is expected that one of the most important challenges toward 2050 will be the accomplishment of the energy policy of S 1 3E that aims to reduce GHGs by 80% and supply economical and stable energy through safety policy. With the trend of renewable energy as a key power source and unfavorable winds toward coal-fired power generation due to the expanded investment in the environment, society, and governance (ESG), it is needless to say that we need to further accelerate efforts for decarbonization. To that end, as described in Section 10.3, it is important to investigate CCUS technology in addition to achieving the development, practical use, and dissemination of next-generation thermal power technology that can reduce CO2 emissions with higher efficiency. In June 2019 the Japanese government proposed carbon recycling as a new concept for CCUS and unveiled a carbon recycling technology road map [11]. The concept of carbon recycling is shown in Fig. 10.7 [11] and the carbon recycling technical road map in Fig. 10.8 [11]. With carbon recycling technology the CO2 obtained after the capture and storage process is considered a resource. Using renewable energy such as photovoltaic power generation (i.e., artificial photosynthesis, and methanation) to convert CO2 to chemical products and fuels or to a mineral will make it possible to effectively utilize it as a replacement

Table 10.4 Target facility performance related to flexibility [10]. Plant type

USC (coal) 600
1000 MW GTCC (single spindle) 1100 C
1500 C class

Change speed

Minimum output

Start-up time

Current status !

Potential !

Targets

Current status !

Targets (%)

Current status !

Targets

1
3% !

3
5% ! 8% !

Approximately 30% ! 50%
60% !

15

1%
5% !

5% (low power zone) 8% (high power zone) 14 (in CC) (20% by GT alone)

4 hours or more ! 40 minutes or more !

4 hours or less 30 minutes or less

GTCC, Gas turbine combined cycle.

25

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Figure 10.7 Concept of carbon recycling [11].

Figure 10.8 Road map for carbon recycling technologies [11].

for ready-made products, if only in small amounts. We will be able to limit CO2 emissions this way. Currently, most such efforts are still at the basic research and development stage, but we expect that in the future, there will be a revolutionary innovation that can contribute to reducing CO2 emissions. Similarly, Power-to-X is also under review. Power-to-X is a collective term to describe concepts such as the following: Power-to-Power or power storage based on hydrogen and methane produced in surplus VRE; Power-to-Gas or gas production by power; Power-to-Fuel or the production of fuel; and Power-to-Feedstock or the production of raw materials. Power-to-X is being studied in Europe as one of the

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means for electric power companies to secure profit in future. Also, review has begun for new efforts, such as installing storage batteries at thermal power plants to enhance the adjustability of supply and demand based on charging and discharging. It is important for thermal power operators to improve profitability through efforts with a new business model. On the other hand, it is expected that thermal power generation, including coal, will continue to play a major role in India, East Asia, and Africa. Given this, it is an important viewpoint to transfer to these nations next-generation, high-efficiency thermal power technology that can contribute to reducing CO2 emissions so that the entire world can act together to reduce GHGs. As engineers involved in energy, we must ensure decarbonization, energy supply reliability, and economic efficiency simultaneously by achieving total optimization of energy production, distribution, and usage toward building a better and more affluent society. In order to achieve these goals, it will be effective, for example, to promote so-called sector coupling for decarbonization through the collaboration of various sectors in heating and transport, in addition to the power producing sector and the electrification of these sectors. It is also necessary to challenge ourselves with carbon recycling, Power-to-X, and other new technologies. To solve these issues, we need to use all of the technologies to make constant efforts to develop revolutionary innovation. We earnestly hope that those who read this book will play a leading role in these efforts. In the recent years the situation surrounding thermal power generation has been changing significantly.

10.5

Conclusion

In terms of facility operation, if a large amount of VRE is introduced, it will be necessary to adjust the output fluctuation with the thermal power generation as the backup to VRE. This issue is becoming more apparent. The direction of thermal power generation for 2030
50 is as follows: 1. Technological development to reduce the environmental burden of thermal power generation a. Practical service of next-generation, high-efficiency technology to significantly reduce GHG emissions, and the transfer of this technology to developing countries b. Development of economically reasonable CCUS technology and hydrogen technology 2. Enhancing the adjustability of thermal power plant to respond to the introduction of large amounts of VRE a. Adequate assessment of the values for adjustability (ΔkW) and improvement of the framework that can serve as an incentive to the utilities in developing and introducing the adjustability 3. Cross-sectional and innovative efforts to secure new sources of profit, including the conversion/storage technology for renewable energy combined with thermal power generation a. Carbon recycling, Power-to-X, and enhancing the adjustability of supply and demand through the installation of storage batteries b. Cross-sectional efforts to achieve the total optimization of energy production, distribution, and usage, such as sector coupling.

478

Advances in Power Boilers

References [1] The FY, 2019. Annual Report on Energy (Japan’s Energy White Paper 2019), https:// www.enecho.meti.go.jp/about/whitepaper/2019html/1-2-1.html, accessed on 2019.7. [2] T. Ueno, Tracking process of national targets under the Paris agreement—case study on China’s Targets and its Implications for transparency rules-, Rev. Electricity Econ. 65 (2018) 82. in Japanese. [3] The FY, 2019. Annual Report on Energy (Japan’s Energy White Paper 2019), Agency for Natural Resources and Energy, Japan, Figure 123-3-4 Power Generation Composition by Source in Major Countries in 2016, ,www.enecho.meti.go.jp/about/ whitepaper/2019html/1-2-3.html., accessed on 16.07.19. [4] Japans Energy, MITI, Agency for Natural Resources and Energy, 2018, 9, ,https:// www.enecho.meti.go.jp/en/category/brochures/pdf/japan_energy_2018.pdf., (accessed 16.07.19). [5] Establishment of an Action Plan for the Electricity Business for Achieving a LowCarbon Society, The Federation of Electric Power Companies of Japan, ,https://www. fepc.or.jp/about_us/pr/pdf/kaiken_s2_e_20150717.pdf. (accessed 16.07.19). [6] Ministry of Economy, Trade and Industry, Japan, Figure Greenhouse gas reduction target in Japan, Technology Roadmap for Next-generation of Thermal Power Generation, 2016, 4, ,https://www.meti.go.jp/press/2016/06/20160630003/20160630003-1.pdf. (accessed 16.07.19) (in Japanese). [7] 1st Featured Article, Highly Efficient and Eco-Friendly Next-Generation Thermal Power Generation, Reporting on Today and Tomorrow’s Energy, Environmental, and Industrial Technology, Focus NEDO 2017 No.62, New Energy and Industrial Technology Development Organization (NEDO), 2017, 6, ,https://www.nedo.go.jp/ content/100859169.pdf. (accessed 16.07.19). [8] 1st Featured Article, Highly Efficient and Eco-Friendly Next-Generation Thermal Power Generation, Reporting on Today and Tomorrow’s Energy, Environmental, and Industrial Technology, Focus NEDO 2017 No.62, New Energy and Industrial Technology Development Organization (NEDO), 2017,10 ,https://www.nedo.go.jp/ content/100859169.pdf. (accessed 16.07.19). [9] Y. Oki, S. Hara, S. Umemoto, K. Kidoguchi, H. Hamada, M. Kobayashi, et al., Development of high-efficiency oxy-fuel IGCC system, Energy Procedia 63 (2014) 471
475. Available from: https://doi.org/10.1016/j.egypro.2014.11.050. accessed 16.07.19). [10] Reports to the Long-Term Energy Supply and Demand Outlook Subcommittee on the subject of the Verification of Power Generation Costs, ,https://www.enecho.meti.go. jp/committee/council/basic_policy_subcommittee/mitoshi/cost_wg/pdf/cost_wg_02. pdf. (accessed 16.07.19). [11] Roadmap for Carbon Recycling Technologies, 2019, Ministry of Economy, Trade and Industry, Cooperation of Cabinet Office, Ministry of Education, Culture, Sports, Science and Technology & Ministry of the Environment, ,https://www.meti.go.jp/ press/2019/06/20190607002/20190607002-2.pdf. (accessed 16.07.19).

Index

Note: Page numbers followed by “f” and “t” refer to figures and tables, respectively. A Act on Prevention of Marine Pollution and Maritime Disaster, 117 Act on Rationalizing Energy Use, 118 Activated carbon injection (ACI), 44 Active carbon process (AC process), 43 44 Additional air compartments (AA compartments), 128 Adhesion, 156 159 Advanced ultra-supercritical power plant (AUSC power plant), 345, 468, 471t. See also Himeji No. 2 Power Plant; Ultrasupercritical power plant (USC power plant) development programs for, 356 369 in Japan, 360 369 material development for, 364 369 efficiency improvement, 346 351 pragmatic approach, 347 349 thermal power plant efficiency, 349 351 elevating steam condition, 352 356 metallurgy and stress analysis, 370 384 Air and flue gas system, 289 291 Air heater zone (AH zone), 261 Air Pollution Control Act, 118 Air separation unit (ASU), 334 Air-blown gasifier, 334 335 Air-blown IGCC, 331 Airblast atomizer, 23, 23f Airflow control, 286, 287f Airflow demand (AFD), 285 Air fuel ratio control, 285, 286f at low excess air ratio, 271 272 All-volatile treatment (AVT), 242, 249f Alloy steel, 137 Alternative fuel gas fired combustion, 34 36

ammonia cofiring test system, 35f Ambient temperature, 113 114 Ammonia (NH3), 12 13, 34, 40 41 Anthracite, 4 Arthur Woolf’s sectional boiler, 65 Ash, 74 77 adhesion, 156 behavior, 160 erosion, 163 167 protection for, 167f protectors, 136, 143 ASU. See Air separation unit (ASU) Atmospheric engines, 61 63 Automatic combustion control (ACC), 268 272. See also Biogas-fired combustion air fuel ratio control at low excess air ratio, 271 272 steam pressure control, 268 271 Automatic frequency control (AFC), 280 282 B Babcock & Wilcox’s boiler, 70, 70f Band spacers, 135 136 Belleville boilers, 68, 69f Benson boiler, 88f, 89, 89f, 90f, 218f Benson system, 222 Best available technology (BAT), 464 465 Biogas-fired combustion, 32 34 biogas upgrading system flow diagram, 33f typical properties of hydrogen and ammonia gases, 35t Biogases, properties of, 33t Bituminous coal, 4 Bituminous/subbituminous coal-fired boilers, 187 188

480

Blast furnace (BF), 29 31 Blast furnace gas (BFG), 12 13, 31t, 126, 341 BFG fired combustion, 29 32 BFG-fired boiler and burner, 32f manufacturing process scheme and energy flow, 31f single-fuel firing technology, 32 Block construction method, 320 321, 322f Board of Boiler Rules, 439 440 Boil-off gas (BOG), 35 36 Boiler circulation pump (BCP), 133 134, 278, 299 Boiler code cleanup, 289 blow, 289 boiler water filling, 289 circulation, 289 and inspection organization, 439 441 Boiler control system, 267 288 characteristics of control method, 269t control of once-through boiler, 275 280 drum boiler, 268 275 other boiler control feedwater flow control, 283 latest boiler steam temperature control, 285 unit output command control, 280 283 water fuel ratio control, 284 286 Boiler Explosion Act, 435 436 Boiler feedwater pump (BFP), 289 Boiler input demand (BID), 283, 296 297 Boiler Regulation Act, 442 Boiler(s), 110 boiler turbine coordinated control, 268 classification of boilers, 61, 62t cold cleanup, 289 components, 127 146 boiler supports, 145 casing and insulation, 145 146 design, 130 desuperheaters, 143 economizer, 143 144 furnace wall, passage sidewall, and 2ry pass wall tubes and roof tubes, 128 134 material for final superheater, main steam pipe, final reheater, hot reheat pipe, 140 142

Index

reheaters, 138 140 superheaters, 134 138 dawn of steam power, 59 60 design and coal properties, 127f development, 61 98, 63f, 98f cylindrical, 63 66 once-through boiler, 87 98 in water tube boiler, 87 98 explosions, 427 433 development in boiler code, 439 441 legislative framework, 433 439 power boiler, 443 458 feedwater, 245t forced cooling shutdown, 298 299 fuel, 32 33 furnace design principles, 125 194 boiler furnace dimension relative to gas-firing boiler, 126f control ash adhesion to furnace wall, 127 space for complete combustion, 127 gas side performance for furnace design boiler components, 127 146 DeNOx, deSOx process, gas cleaning, 180 194 fluidized bed combustion, 167 173 membrane wall, 146 149 principles of boiler furnace design, 125 127 pulverized coal combustion, 149 167 stoker combustion, 173 180 heat transfer in, 120 125 hot banking shutdown, 298 hot cleanup, 292 293 inspection boiler code and, 439 441 of power boiler, 443 458 light-off preparation, 292 air and flue gas system and furnace purge, 289 291 feedwater system, 289 fuel system, 291 292 MFT reset, 292 master control, 268 271, 283, 283f plant, 173 power generation boilers in Japan, 99 pressure, 145 parts method, 260 pressure and temperature rise, 293 294

Index

adjustment of fuel flow, 293 feedwater flow and storage tank level control, 293 294 limit target at start-up, 293 operation of drain valve and star-up bypass valve, 294 regulation in Japan, 441 443 shutdown, 297 299 mode after desynchronization, 298 299 normal shutdown, 297 298 similarity law in boiler furnace, 99 103 split module method, 260 start-up, 289 297, 292t steam application to pumping water, 57 59 steam temperature control, 285 synchronization/load up, 294 296 system, 107 108 turbine start-up, acceleration, and synchronization preparation, 294 type, 112, 112f water, 245t filling, 289 quality, 210t Boiler steam cycle system, 110 Bomb method, 349 350 Boron, 45 47, 47f Boron nitrides (BN), 377 378 Brayton cycle. See Gas turbine cycle (GT cycle) Bubbling fluidized bed boiler, 172, 173f Buckstay system, 149 Bunker zone, 261 Butane, 28 29 C C value of Larson Miller parameters (CLMP), 376 Cable-less inner ultrasonic testing system, 444 448 Calcium sulfite (CaSO3), 41 42 Carbon (C), 17 recycling, 474 476, 476f steel material, 143 Carbon dioxide (CO2), 2, 17, 29 31 emission, 4 Carbon dioxide capture, utilization, and storage (CCUS), 461, 470 472

481

Carbon dioxide capture and storage technology (CCS technology), 470 Carbon dioxide capture and utilization (CCU), 470 Carbon monoxide (CO), 29 31 Casing and insulation, 145 146 insulation of finned tube walls, 146f Cassette baffles, 143 Center current flow type, 178 Central Research Institute of Electric Power Industry (CRIEPI), 331, 410 411 Chain-grate stoker, 71, 72f Char cyclone, 337 recycle system, 336 337 Circular corner firing system, 153 Circulating fluidized bed (CFB), 422 boiler, 172 173, 175f incineration firing by, 422 424 Circulation ratio (CR), 195, 204t Clark Colburn theory, 430 Clean Coal Power R&D Co. (CCP), 411 Coal, 1, 4 5, 5t, 6t, 8t. See also Pulverized coal (PC) ash characterization, 160 classification, 4 combustion characteristics, 19 22 combustion efficiency, 19 20 NOx formation, 20 22 combustion process, 17f, 111, 173 175 systems, 18 19, 18f correlation between conversion of N in, 22f feeding system, 332 333 formation, 4 fundamentals of combustion, 16 18 NOx concentration and nitrogen content in, 21f particle size, 127, 128f properties, 4 5 gas, 12 16 oil, 5 11 pulverizer, 333 334 pulverizing system, 332 333 Coal Mines Act, 437 Coal-fired boiler, 156 159, 359. See also Drum boiler; Once-through boilers

482

Coal-fired boiler (Continued) advanced construction method/ simultaneous construction method, 258 construction, 257 258 floor block erection method/floor unit construction method, 258 259 hyper core structure construction method, 259 module construction method, 259 261 top girder and pressure parts integrated block jack-up method, 259 Coal-fired power plant, 36 37 Coal-water paste (CWP), 325 Coalbed methane, 13 14 Coarse particles, 155 156 Cocurrent flow type, 178 Coil module for boiler pressure parts method, 260 Coke-oven gas (COG), 29 Coking coal, 4 Colebrook Darcy Weisbach formula, 223 Combined cycle (CC), 309 plant, 305 308 system, 341 343 Combustion, 149 152 air and flue gas, 17 18 coal combustion fundamentals, 16 18, 18f concept of staged combustion system, 151f control logic, 272, 272f technology for stoker-type combustion incinerators, 179, 180t efficiency, 19 20 flame, 153 154 of fuels coal, 16 22 oil, 23 27 phenomena, 194 process, 16 17, 61 system, 395 Component test facility (CTF), 326 Computational fluid dynamics (CFD), 121 123, 123f, 124f, 201f Condensate, 108 Condenser, 110 vacuum, 113 114

Index

Conduction, 120 Confident interval (CI), 383 Control ash adhesion to furnace wall, 127 Control system, 262 267 Control valve (CV), 301 Convection, 121 Convective heat transfer, 123 124 coefficient, 121 Conventional boiler steam cycle system, 110 Conventional boiler turbine generator (BTG) system, 110 111 Cool Water Coal Gasification Program (CWCGP), 327 Cooling principle in water tube, 199 206 heat flux consideration, 199 200 heat transfer consideration, 200 206 hydrodynamic consideration, 206, 223, 226 236 pressure drop in single-phase flow region, 233 pressure drop in two-phase flow region, 233 234 COP21, 462 463 Cornish boiler, 64 Corrosion, 160 163, 240 251 example of relationship of corrosion rate and metal temperature, 166f mechanism of groove type corrosion, 163f resistance properties, 384 sulfide attack, 164f thinning part inspection technique, 448 vanadium attack, 165f COS hydrolysis and scrubbing/washing section, 338 339 Counter-current flow type, 178 Creep damage detection technique, 451 452 Creep-rupture properties, 370 384 Creep strength enhanced ferritic steel (CSEF steel), 346, 371 374 Critical heat flux (CHF), 204f, 205f Cyclone-separator, 211 Cylinder piston system, 59 Cylindrical boiler development, 63 66 transition of boiler type in Japan, 67f Trevithick’s wrought-iron boiler, 64f Woolf’s cast-iron sectional boiler, 65f

Index

D Daily start and stop (DSS), 96 De-NOx technology, 40 41, 41f, 180 194 Decarbonized society next-generation thermal power generation, 464 472 CCUS technology, 470 472 characteristics of, 466t future outlook for, 468 469 hydrogen power generation technology, 470 472 in Japan, 470f Department of Energy (DOE), 326 Departure from nucleate boiling (DNB), 393 394 Deposition, 240 251 DeSOx process, 180 194 Desulfurization, 36 37 Desuperheaters, 143, 143f Diesel, 5 Diesel fuel, quality requirements for, 9t Dioxins, 44 Double contact flow scrubber (DCFS), 187, 187f Double-reheat cycle, 347 349 Draft system, 173 Drain valve and star-up bypass valve, 294, 295t Drones, boiler inspection by, 453 458 Drop-tube furnaces (DTFs), 122 123 Droplets, 23 24 Drum boiler, 267f, 268 275, 271f. See also Coal-fired boiler ACC, 268 272 dynamic characteristics of, 262 264, 263f, 264f step change in governing valve opening position, 263 264 step increase in feedwater flow rate, 263 step increase in fuel flow rate, 263 step increase in spray water flow rate, 264 feedwater control, 272 273 STC, 273 275 Drum type Stirling boiler, 70 Dry-type ESP, 190 192, 192f Durability, 179 Dust collection technology, 37 40

483

Dynamic behavior of power boiler and control system, 262 267 dynamic characteristics of drum boiler, 262 264 of once-through boiler, 264 267 E EAGLE project, 418 420 East Japan Earthquake (2011), 118 Eco hopper zone, 261 Economical continuous rating (ECR), 115, 289 Economizer (ECO), 123 125, 128, 143 144, 278 hanger tubes, 139 Eddy current testing technology (ECT technology), 443 pencil, 448 450 tube-inserted, 448 Eddy effect, 152 Electric Power Research Institute (EPRI), 327 Electricity Business Act, 117 Electrostatic precipitator (ESP), 37 38, 37f, 38f, 39f, 108, 190 194, 191f Emission, 2 emission-induced environmental issues and protection flue gas treatment technology, 36 45 wastewater treatment, 45 49 Engineering, procurement, and construction (EPC), 411 Enthalpy pressure diagram along steam generating tube, 116 117, 116f Entrained-bed systems, 18 19 Environment, society, and governance (ESG), 474 Environmental impact, 110 111 Environmental Impact Assessment Act, 118 Environmental Quality Standard for water pollution, 45 Erosion, 160 167, 240 251 protection for ash erosion, 167f Ethane, 28 29 European once-through boiler, 267 268 Evaporation zone, 262 263 Exhaust gas recirculation system, 180f External heat exchanger, 172

484

F Factory and Workshop Act, 437 Factory Location Act, 118 Feedwater flow control, 283, 284f rate, 263, 266 267 and storage tank level control, 293 294 system, 289 temperature, 114 Feedwater control (FWC), 262, 272 273, 273f Feedwater flow demand (FWD), 283 Fire Service Act, 117 Firing rate demand (FRD), 284 Firing system, 152 154 circular corner firing system, 153 wall firing, 153 154 Five drum type Stirling boiler, 72f Fixed spacers, 135 136 Fixed-bed systems, 18 19 Flame model of pulverized-coal combustion zone, 150, 150f Floor block erection method/floor unit construction method, 258 259 Flow stability, 236 240 Flow-accelerated corrosion (FAC), 241 242, 246f, 452 measures against, 244 248 Flue gas, 108 heat transfer for heating surface in flue gas pass, 123 125 treatment technology, 36 45 combined technologies to reduce NOx and SOx emissions, 43 44 De-NOx technology, 40 41 dust collection technology, 37 40 mercury emission control technology, 44 45 Flue gas desulfurization technology (FGD technology), 41 43, 186 187 Flue-tube boiler, 66, 66t Fluid circuits, 130 133, 132f Fluid dynamics, 122 123 Fluidized-bed combustion system, 18 19, 167 173 bubbling fluidized bed boiler, 172 circulating fluidized-bed boiler, 172 173 principle of, 167 172

Index

boiling two-phase flow pattern in horizontal tube, 172f example of heat transfer data of in-line tube-bank, 171f flow pattern in tube-bank of in-line arrangement, 171f interrelationships between components of fuels and resulting technical, 170f pattern of fluidizing behavior in coalfired furnace, 168f properties of typical fuels, 170t Fluidized-bed heat exchanger (FBHE), 172 Forced circulation characteristic, 207 208 Forced draft fan (FDF), 286 Forced-circulation boiler, 61, 84 86, 87t Fossil fuels, 2 3 combustion and environmental issues combustion of fuels, 16 36 emission-induced environmental issues and protection, 36 49 properties of coal, oil, and gas, 4 16 transition of primary energy consumption, 2f fossil fuel fired boilers, 61 Fossil-fired boilers, 102 Fossil-fired power plants, 103 Fouling, 156 160 coal ash characterization, 160 indices to correlate with slagging and fouling characteristics, 162t phenomenon, 162f “Four Big Pollution Diseases of Japan”, 7 Four drum type Stirling boiler, 71f Front End Engineering and Design (FEED), 358 Fuel, 110 111, 111t NOx, 20 21 oils, 5 quality of, 10t system, 291 292 Fuel flow, 293 control, 285 rate, 263, 266 Fuel gas heater (FGH), 401 Himeji No. 2 Power Plant, 405 Fukushima Daiichi power station, 107 108 Fukushima IGCC project, 413 418 Full fired heat recovery combined cycle, 313 314

Index

Furnace, 121 122 boiler gas side performance for furnace design, 125 194 lower zone, 261 pressure control, 286, 288f purge, 289 291 upper zone, 261 Furnace outlet gas temperature (FOT), 121 122 Furnace walls, 146 fluid circuits, 130 133 inlet headers, 130 133 manufacturing furnace wall in workshop, 148f structure, 128 130 construction of furnace wall, 131f Inlet superheater headers at boiler roof, 131f structure of once-through boiler, 130f work of furnace wall installation, 129f water separator and water separator drain tank, 133 134 G Galvanic cell gas detector, 48 49 Gas, 1, 12 16 changes in global LNG transactions, 15 16 global natural gas sale prices, 16 clean-up system, 338 341 cleaning, 180 194 NOx reduction, 181 186 PM reduction, 190 194 SOx reduction, 186 190 fuel, 1 primary energy demand by fuel in China, 14f supply of natural gas to China, 14f turbine, 341 342 gas turbine combined cycle systems, 110 M501J GT, 402 403 world natural gas, 13f supply and demand, 13 15 Gas recirculation flow (GR flow), 274 275 Gas turbine combined cycle (GTCC), 309, 327, 468. See also Combined cycle (CC); Integrated coal-gasification combined cycle (IGCC)

485

advantage of, 315 316 disadvantage of, 316 feature of combined cycle plant, 305 308 Himeji No. 2 Power Plant, 400 406 HRSG, 316 324 power generation, 305 324 thermodynamic principle of, 309 312 types of, 312 315 classification by cycle configuration, 313 314 classification by shaft configuration, 314 315 Gas turbine cycle (GT cycle), 305 power generation, 310 311 Gas turbine fuel cell (GTFC), 468 Gas-Gas Heater (GGH), 338 Gas-side heat absorption, 74 Gaseous oxidized mercury, 44 45 Gasification combined cycle test facility (GCCTF), 327 Gasified gas, 32 33 Gasifier, 334 336 facilities, 332 334 pressure vessels, 412 General planning, 14 15 Giovanni Branca’s concept, 57 Global LNG transactions changes in, 15 16 number of global LNG transactions, 15f countries importing LNG worldwide, 15f Global natural gas sale prices changes in, 16 world crude oil, natural gas, and LNG price trends, 16f Global navigation satellite system (GNSS), 454 Governor-free operation (GF operation), 264 Gravitational pressure drop, 69 Green’s economizer, 77f Greenhouse gas (GHG), 461 emissions, 462 464 Grid Code, 282 Gurney’s water tube boiler, 69f H H2S absorber/stripper section, 340 341 Harp construction method, 320 321, 322f Haystack boiler, 59, 60f Heat

486

Heat (Continued) absorption, 206 207 balance, 114, 115f flow and temperature relationships in heat exchanger, 125f flux consideration, 199 200 distribution, 152 recovery combined cycle, 313 Heat recovery steam generators (HRSGs), 243, 313, 316 324, 342, 400 construction method of, 320 323 example of, 323 324 feature of, 317 technical trend of, 317 323 Heat transfer in boiler, 120 125 computational fluid dynamics, 122 123 conduction, 120 convection, 121 furnace, 121 122 heat transfer for heating surface, 123 125 radiation, 120 coefficient, 168 171 in evaporator tubes, 220 consideration, 200 206, 220 222, 226 236 coupled analysis, 122 123 for heating surface in flue gas pass, 123 125 Heat-recovery steam generator, M501J GT, 402 403 Heavy oil-fired boilers, 189 Herpen-La Mont-Gesellschaft, 84 86 High pressure (HP), 310 turbine, 138 139 High Pressure Gas Safety Act, 117 High signal selector (HS selector), 272 High sulfur oil fired boiler, 163 High-performance catalyst in case of high NO2 ratio, 185, 185f high-performance/low-SO2 oxidation catalyst, 183, 183f Lancashire boiler, 65 plant, 110 113 fuel, 110 111

Index

site location, 110 steam condition, 113 type of boiler, 112 unit capacity, 112 113 High-pressure engine, 63 High-temperature components, 140, 142f Higher heating value (HHV), 349 350, 402 Himeji No. 2 Power Plant, 400 406 characteristics of component, 402 405 outline of plant, 401 402 test operation performance, 405 Homogeneous two-phase flow model, 81 82 Horizontal reciprocating type grate, 177 Hot reheat pipe, 140 142 HT-NR burner, 395, 396f Hu¨ls II 1 unit, 92 Hydrocarbons, 28 29 Hydrodynamic behavior in downward flow, 235 236 Hydrogen (H), 12 13, 17, 29 31 gas, 34 power generation technology, 470 472 Hydrogen peroxide (H2O2), 46 Hyper core structure construction method, 259 I Impingement separation model, 212f Incineration firing, 422 424 Incinerator types, 178, 179f Inclined tube critical heat flux, 234 235 Inclined-type stoker, 72 Incrustation, 77 Induced draft fan (IDF), 286 Inductively coupled plasma (ICP), 46 Industrial Safety and Health Act, 118 Industrial Water Act, 117 Inert gases nitrogen, 29 31 Inertinite, 4 5 Injection velocity, 150 Inspection, 429, 431 Insurance, 431 433 Integrated coal gasification fuel cell (IGFC), 468, 471t Integrated coal-gasification combined cycle (IGCC), 111, 311 312, 410 422, 468, 471t. See also Gas turbine combined cycle (GTCC)

Index

air-blown IGCC, 331 benefits of, 328 char recycle system, 336 337 combined cycle system, 341 343 development in world, 326 327 environmental advantage, 329 330 gas clean-up system, 338 341 gasifier, 334 336 facilities, 332 334 GTCC, 327 oxygen-blown IGCC, 332 plant environmental performance, 328f system configuration, 328f Intermediate pressure (IP), 317 318 International Energy Agency (IEA), 7 Iron refinery process, 72 73 J Jack-up construction method, 412 Japan, power generation boilers in, 99 Japanese Industrial Standards (JIS), 5 Jet effect, 152 John and Frederick Howards’ boiler, 66, 68f Jukes’ chain-grate stoker, 73f K Karita PFBC plant, 406 410 Kerosene, 5 quality requirements of, 9t L LaMont boiler, 84 86, 86f Lancashire boiler, 65, 66f Large eddy simulation (LES), 124f Legal regulations in Japan, 117 118 Lignite, 4 Lignite-fired boilers, 188 189 Limestone gypsum process, 41 42, 186 187 Limestone gypsum wet desulfurization equipment, 187 189, 188f Linz Donawitz converter gas (LDG), 29 Liptinite, 4 5 Liquid, 126 combustion, 27 fuels, 23, 27 28 Liquid-to-gas ratio (L/G ratio), 42 Low pressure (LP), 310 Low signal selector (LS selector), 272

487

Low-NOx firing burner for circular firing system, 154 for opposed firing system, 154 Low-quality solid fuel, 186 Low-SO2 oxidation catalyst for low-quality solid fuel, 186 Lower heating value (LHV), 349 350 Low excess air ratio, 271 272 Low pressure turbine (LP turbine), 108 M Magnetic particle testing (MT), 448 Main STC, 273 274, 275f, 276 278 reheat STC, 278 Main steam temperature, 264, 265f MARBN steel, 377 378 Marquis of Worcester’s Engine, 57 59 Mass velocity against heat absorption deviation, 199 200 Massachusetts rule, 439 440 Master fuel trip reset (MFT reset), 292 Material development, 346 Maximum continuous rating (MCR), 110, 289 290 Membrane wall, 146 149 manufacturing furnace wall in workshop, 148f typical drawing of buckstay system, 149f Merchant Shipping Act, 437 Mercury, 44 emission control technology, 36 37, 44 45, 45f oxidation catalyst, 183 184, 184f Mercury and Air Toxics Standards (MATS), 183 Metallic titanium/aluminum, 48 49 Metalliferous Mines Regulation Act, 436 Metallurgy and stress analysis, 370 384 corrosion resistance properties, 384 creep-rupture properties, 370 384 Methane, 28 29 fermentation gasification, 32 34 Methyldiethanolamine (MDEA), 411 Mill zone, 261 Ministry of Economy, Trade and Industry (METI), 360 Missouri-Kansas coal, 71 Mitsubishi Hitachi Power Systems, Ltd. (MHPS), 193, 331, 391

488

Modular construction method, 321 323, 323f Module construction method, 259 261 boiler split module method, 260 coil module for boiler pressure parts method, 260 zone module construction method, 260 261 Motor-driven BFP (M-BFP), 289 Moving electrode electrostatic precipitator (MEEP), 192 193, 193f Multiaxial stress field, 380 381 Multishaft combined cycle, 314 315 N Nakoso 250 MW air-blown IGCC demonstration plant, 410 418 advanced installation method, 412 413 construction, 411 412 EAGLE project, 418 420 Fukushima IGCC project, 413 418 jack-up construction method, 412 operation, 413 Osaki CoolGen project, 418, 420 422 National Board of Boiler and Pressure Vessel Inspectors (NBBI), 440 Natural circulation characteristic, 206 207 Natural gas (NG), 12 13, 32 natural gas fired combustion, 28 29, 29t typical properties of BFG, COG, 30f typical properties of gas-fired burners, 30f Natural-circulation boilers, 61, 84 86, 98 concept, 68 Net calorific value of coal. See Lower heating value (LHV) Net heat input and furnace plan area (NHI/ PA), 156 New Energy and Industrial Technology Development Organization (NEDO), 331, 360 Newcomen boilers, 98 Newcomen’s steam engine, 59 60, 59f, 60f Next-generation thermal power generation, 464 472 CCUS technology, 470 472 characteristics of, 466t future outlook for, 468 469

Index

hydrogen power generation technology, 470 472 in Japan, 470f Nitrogen (N2), 29 31 Nitrogen oxides (NOx), 2 emissions, 7 formation, 20 22 effects of two-stage combustion ratio on, 22f history and basic technique, 181 technology lineup high-performance catalyst in case of high NO2 ratio, 185 high-performance/low-SO2 oxidation catalyst, 183 high-temperature selective catalytic reduction catalyst, 185 low-SO2 oxidation catalyst for lowquality solid fuel, 186 mercury oxidation catalyst, 183 184 recycling of catalyst, 185 SCR system application, 181 183 Noise Regulation Act, 118 Nondestructive examination (NDE), 367 Nondestructive inspection technology, 443 453 Nondestructive testing (NDT), 381 384 Nondimensional droplet separation, 26 27 Normal shutdown, 297 298, 298f Notice of Accidents Acts, 437 Nuclear fission process, 61 Nusselt number (Nu), 121 O Oil, 1, 5 11, 107 108 changes in energy resource prices, 12f combustion of fuels, 23 27 alternative fuel gas fired combustion, 34 36 BFG fired combustion, 29 32 biogas-fired combustion, 32 34 correlation between viscosity and temperature of fossil fuels, 25f four group combustion modes of droplet cloud, 26f group combustion region diagram, 27f natural gas fired combustion, 28 29 predicted NOx emission levels, 28f electricity generation

Index

capacity in Japan, 11f composition by resource in Japan, 11f oil/gas cofiring burner technology, 29 sales of petroleum products in Japan, 12f Once-through boilers, 87 98, 213 223, 251t, 263, 391 400. See also Coalfired boiler; Power boiler control, 275 280 main STC, 276 278 recirculation flow control system, 278 280 dynamic characteristics of, 264 267, 265f, 266f step increase in feedwater flow rate, 266 267 step increase in fuel flow rate, 266 step increase in spray water flow rate, 267 heat transfer deterioration near pseudocritical region, 97f partial load operation of sliding pressure, 299 301, 300t Philo 6 supercritical pressure boiler, 95f powdered-scale deposition in OT operation in, 248 250 pressure, temperature, and mass flow rate, 95f pulverized coal-fired supercritical slidingpressure once-through Benson boiler, 97f share of boiler in Germany, 92t steam pressure and temperature, 99f steam properties near pseudo-critical temperature, 222f subcritical pressure once-through boiler, 216 219 Sulzer monotube boiler, 90f supercritical pressure once-through boiler, 219 223 supercritical pressure unit in United States and United Kingdom, 94t in West Germany, 93t supercritical sliding pressure operation once-through boiler, 223 240 transition of power generation efficiency, 96f types, 92f Once-through operation zone, 279 280

489

Operation of power boiler, 262 302 Organic matter, 4 Osaki CoolGen project, 418, 420 422 Over firing air (OFA), 286 Oxygen (O), 17, 420 421 oxygen-blown gasifier, 336 oxygen-blown IGCC, 332 Oxygenated treatment (OT), 243 P Papin’s steam engine, 57 59, 58f Paris Agreement, 462 Partial combustion gasification, 32 33 Partial load operation/sliding pressure operation, 299 301 challenges of sliding pressure operation, 301 once-through boiler, 299 301 Particulate matter reduction (PM reduction), 2, 190 history and basic technique, 190 technology lineup dry-type ESP, 190 192 MEEP, 192 193 wet-type electrostatic precipitator, 193 194 Passage sidewall, 128 134 Pencil eddy current testing, 448 450 Penetrant testing (PT), 448 Petroleum coke (PC), 167 168 Petukhov’s correlation, 221 Phased-array ultrasonic testing, 451 452 Phosphate treatment (PT), 243, 247t Plain-jet and pressure-swirl atomizer, 23, 23f Plant efficiency, 114 Plate-type catalyst, 181 Porous filter, 337 Port and Harbor Act, 117 Powdered-scale deposition in OT operation in once-through boiler, 248 250 Power boiler, 443 458. See also Oncethrough boilers; Water tube boiler construction, 110 design boiler gas side performance for furnace design, 125 194 deposition, erosion, and corrosion and water treatment, 240 251 heat transfer in boiler, 120 125

490

Power boiler (Continued) water circulation design, 194 240 by drones, 453 458 nondestructive inspection technology, 443 453 operation and control of, 262 302 boiler control system, 267 288 boiler start-up and shut-down operation, 289 299 dynamic behavior of power boiler and control system, 262 267 partial load operation/sliding pressure operation, 299 301 Power generation boilers in Japan, 99 boiler type and steam generation rate, 100f unit output and type of fuels, 100f Power generation process, 59 Power-to-Fuel, 476 477 Power-to-Gas, 476 477 Power-to-Power, 476 477 Power-to-X, 476 477 Pressure drop in single-phase flow region, 233 in two-phase flow region, 233 234 Pressurized fluidized-bed combustion boiler, 325 326 flow model of, 325f scale-up of, 326t Pressurized fluidized-bed boiler combined cycle plants (PFBC), 316 Primary reheater (1ry RH), 139 140, 141f Primary superheater (1ry SH), 134 136, 137f Process development unit (PDU), 332 Propane, 28 29 gas, 28 29 Properties of coal, oil, and gas, 4 16 Proportional integrator controller (PI controller), 272 273 Pseudo-DNB, 221 222 Pulverized coal (PC), 38 40, 72 73, 74f, 395 boiler system, 18 19 combustion, 149 152, 167 boilers, 112 corrosion and erosion, 160 167 firing system, 152 154 method, 19f

Index

pulverizer performance, 155 156 slagging and fouling, 156 160 system, 19 feeding system, 334 firing boilers, 122 firing system, 152, 152f flow pattern, 150 pulverized coal-fired boiler, 126 Q Quarry Act, 437 R R&D process, 103 Radiant boiler, 81 Radiant heat transfer, 120 Radiation, 120 Railway Employment Act, 437 Railway Regulation Act, 436 Ramzin boiler, 91, 91f Rankin Cycle, 113 Recirculation flow control system, 278 280 once-through operation zone, 279 280 recirculation operation zone, 278 279 Recirculation operation zone, 278 279 Recycling of catalyst, 185 Refused paper and plastic fuel (RPF), 167 168 Regenerative cycle, 113 116 Reheat cycle, 113 116 condenser vacuum, 113 114 example of heat balance, 114 feedwater temperature, 114 steam pressure, 113 steam temperature, 113 Reheat STC, 274 275, 276f, 278 Reheater (RH), 123 125, 138 140, 140f, 263 1ry RH, 139 140 2ry RH, 140 Remote monitoring center (RMC), 417 418 Reverse-acting type grate, 178 Rifled tubes, 133, 133f River Act, 117 Rosin Rammler distribution, 23 24, 25f S Safety valve, 427 428, 430, 439 440 SAVE12AD steel, 378

Index

Savery’s The Miner’s Friend, 57 59, 58f Scotch boiler, 66, 67f Seawater desulfurization equipment, 189 190, 189f temperature, 113 114 Secondary pass zone, 261 Secondary reheater (2ry RH), 125, 140, 142f, 287 288 2ry SH desuperheater, 138 pass wall tubes and roof tubes, 128 134 Secondary superheater (2ry SH), 137, 138f Sector coupling, 477 Select Committee, 428, 430, 434 435 Selective catalytic/catalyst reduction (SCR), 40 41, 40f, 181 186, 182f, 261, 316 catalyst, 321f system, 320 application, 181 186, 182f Selective noncatalytic reduction (SNCR), 40 41 Selenium, 43f, 44f, 45, 47 49, 48f Semiwet-type ESP, 38 40 Separation principles, 211 213 suppress steam carryunder to water, 212 213 suppression of water carryover to steam, 211 212 Shaft configuration, GTCC classification by, 314 315 Shale gas, 13 14 Shut-down mode after desynchronization, 298 299 boiler forced cooling shutdown, 298 299 boiler hot banking shutdown, 298 Siemens-Schuckert cable factory, 89 Similarity law in boiler furnace, 99 103 deterioration of power boiler, 102f volume density of furnace heat release rate and boiler capacity, 101f Single-phase flow region, 233 Single-shaft combined cycle, 315 Site location, 110 Slagging, 156 160, 158f ash deposition on tube surface, 159f coal ash characterization, 160 indices to correlate with slagging and fouling characteristics, 162t Sliding pressure, 391 400 operation, 301

491

supercritical pressure boiler, 96 Sliding spacers, 135 136 Small-capacity natural-circulation boiler, 99 Smoke-tube boiler, 66 Solid, 126 fuels, 27 28 Souders Brown expression, 211 Space for complete combustion, 127 boiler design and coal properties, 127f effect of coal particle size, 128f Spherical bumper mounted drone, 457 Spray dry absorber (SDA), 42 43 Spray water flow step increasing change, 264, 267 Stability of mass velocity against heat absorption deviation, 199 200 forced circulation characteristic, 207 208 natural circulation characteristic, 206 207 Stainless-steel tubes, 137 Star-up bypass valve, 294 Steam application to pumping water, 57 59 coal, 4 condition, 113 boilers, 392 drum, 208 213 reasons for separation performance, 209 210 separation principles, 211 213 generation rate, 100 101 power dawn of, 59 60 generation, 309 plant, 107 108 pressure, 70, 113 control, 268 271, 271f temperature, 113 Steam Boiler Assurance Co., 431 Steam temperature control (STC), 262, 273 275, 274f main STC, 273 274 method of once-through boiler, 276f reheat STC, 274 275 Steam turbine (ST), 342 343, 400 cycle, 305 generators, 110 M501J, 403 405 Steamboat Act, 439 Steam water separator, 90 91

492

Steelworks by-product gases, 29 31 Stefan Boltzmann constant, 120 Stem water mixture, 235 236 Stoker, 177 178 furnace, 18 19 grate diagram, 178f stoker-type combustion incineration configuration incinerator types, 178 measures for increased durability, 179 waste feeder, 176 177 stoker-type combustion incinerators, 179 stoker-type incinerators, 176 Stoker combustion, 167 boiler, 112 characteristics of waste as fuel, 175 combustion control technology for stokertype combustion incinerators, 179 configuration of stoker-type incinerators and waste combustion process, 176 history of, 173 175 stoker-type combustion incineration configuration, 176 179 technology, 179 180 exhaust gas recirculation system, 180f sample of operating data with exhaust gas recirculation system, 181f Storage batteries, 476 477 Storage tank level control, 293 294 Subbituminous coal, 4 Subcritical pressure once-through boiler, 216 219 Submerged cylindrical type, 195 197 Submergence principle, 98 Sulfide attack, 163, 164f corrosion, 160 163, 163f Sulfur (S), 17 Sulfur dioxide (SO2), 17 Sulfur oxides (SOx), 2 history and basic technique, 186 187 spray tower scrubber, 188f technology lineup heavy oil-fired boilers, 189 lignite-fired boilers, 188 189 limestone gypsum wet desulfurization equipment, 187 188 seawater desulfurization equipment, 189 190

Index

Sulzer boiler, 90 91, 218f Sulzer Monotube, 214 215 Supercritical boiler, 97 98 Supercritical pressure boiler, 116, 117t once-through boiler, 219 223 heat transfer consideration, 220 222 hydrodynamic consideration, 223 Supercritical sliding pressure operation, 225f once-through boiler, 223 240 heat transfer and hydrodynamic consideration, 226 236 merit and effectiveness of supercritical sliding pressure operation, 224 226 Superheater (SH), 123 125, 134 138, 136f, 262, 279f 1ry SH, 135 136 2ry SH, 137 3ry SH, 138 tubes, 122 123 Superheating zone, 262 263 Supplemental firing HRSG, 318 320 Supplementary fired heat recovery combined cycle, 314 Supply and demand, 13 15 Suppression of water carryover to steam, 211 212 Surface defect detection technology, 448 450 Surface heat flux density, 101 102 Swirling effect, 152 Synchronization/load up, 294 296 Syngas cooler (SGC), 335, 412 Synthesis gas (syngas), 341 System frequency, 282 T Tachibana-Wan thermal power station, 391 400 achievements in commissioning, 398 399 advanced steam condition boilers, 392 construction, 395 398 design features of boiler, 393 395 Unit No. 2 boiler, 394f Taylor-type underfeed inclined stoker, 73f Temperature rise/pressure rise, 294 Tertiary SH (3ry SH), 125, 128, 138, 287 288 Thermal decomposition temperature, 16 17

Index

Thermal efficiency, 305 307, 307f, 327 Thermal power generation, 4, 462 carbon recycling, 476f future outlook for, 472 477 IGCC system with CCS, 473f next-generation, 464 472 plant, 257 258 reducing GHG emissions, 462 464 technological development stages, 469t Thermal power plants, 108, 108f, 242 243 efficiency, 349 351 enthalpy pressure diagram along steam generating tube, 116 117 high-performance plant, 110 113 legal regulations in Japan, 117 118 planning and factors, 109 110 reheat cycle and regenerative cycle, 110 steam power plant, 107 108 water quality control in, 241 242 water treatment methods for, 242 243 Thermal power station Himeji No. 2 power plant, 400 406 incineration firing, 422 424 Karita PFBC plant, 406 410 Nakoso 250 MW air-blown IGCC demonstration plant, 410 422 Tachibana-Wan Unit No. 2, 391 400 Thermohydraulic behavior, 109 Thickness-monitoring technique, 452 453 Thin film ultrasonic testing, 452 453 Third-party inspection, 437 438 Top girder and pressure parts integrated block jack-up method, 259 Transport fuel, 1 Traveling stoker, 71 Trevithick engine, 63, 64f Tube-inserted eddy current testing, 448 Turbine generator, 110 master control, 282 283, 282f start-up, acceleration, and synchronization preparation, 294 Turbine cooling air (TCA), 401 Himeji No. 2 Power Plant, 405 Turbine inlet temperature (TIT), 402 Turbine-driven BFP (T-BFP), 296 Turbo-separator, 211 Two-phase flow region, 233 234

493

nozzle, 23, 23f U Ultrasonic testing (UT), 443 Ultrasupercritical power plant (USC power plant), 345, 391 400. See also Advanced ultra-supercritical power plant (A-USC power plant) development programs for, 356 369 in Japan, 358 359, 361t efficiency improvement, 346 351 pragmatic approach, 347 349 thermal power plant efficiency, 349 351 elevating steam condition, 352 356 metallurgy and stress analysis, 370 384 Unburned carbon (UBC), 20, 398 Unburned char, 19 Unconventional natural gas, 13 14 Unit capacity, 112 113 Unit output command control AFC, 280 282 boiler master control, 283 turbine master control, 282 283 unit output signal, 280 Unit output signal, 280, 280f Universal pressure (UP), 96 V Vanadium attack, 5 7, 163, 165f Variable pressure, 299 301 Variable renewable energy (VRE), 468 Velox boiler, 86, 88f Vertical oscillating type grate, 178 Vitrinite, 4 5 Volatiles, 16 17 Volume-density of heat release rate, 100 101 W Wagon-type boiler, 59, 60f Wall firing, 153 154 low-NOx firing burner for opposed firing system, 154f low-NOx pulverized coal burner, 153f Waste combustion process, 176 feeder, 176 177 pusher waste feeder, 177f

494

Waste (Continued) as fuel, 175 Wastewater treatment, 45 49 boron, 45 47 selenium, 47 49 Water carryover to steam, 211 212 circulation design, 194 240 once-through boiler, 213 223 steam drum, 208 213 submerged cylindrical type, 195 197 system principle, 194 195 water tube type, 197 208 methods for thermal power plants, 242 243 quality control in thermal power plants, 241 242 separator, 133 134, 134f drain tank, 133 134, 135f and steam system HRSG, 317 318, 319f for thermal power plants measures against flow-accelerated corrosion, 244 248 measures against powdered-scale deposition, 248 250 treatment, 240 251 water quality control in thermal power plants, 241 242 water-soluble gas components, 42 water fuel ratio control, 276, 277f, 284 286 airflow control, 286 air fuel ratio control, 285 fuel flow control, 285 furnace pressure control, 286 Water Pollution Prevention Act, 118 Water tube boiler, 197 208, 198f. See also Power boiler Babcock Boiler gently inclined singledrum sectional boiler, 81f boiler tube deterioration, 80f boiler water trouble and countermeasure, 78t circulation velocity and exit quality by Mu¨nzinger model, 84f

Index

combustion engineering’s pulverized coal combustion double Stirling boiler, 82f cooling principle in water tube, 199 206 development in, 87 98 development of waterwall, 80f Foster Wheeler’s pulverized coal-fired single-drum radiant boiler, 83f history of furnace design, 72f effect of scale on heat transfer, 79f stability of mass velocity against heat absorption deviation, 199 200 steam generation rate per tube, 85f transition of number of published papers, 79f tube arrangement until (1910), 75t two-phase flow and heat transfer researches, 85f typical incrustation, 78f Yarrow’s experimental setup for natural circulation, 83f Water-Commanding Engine, 57 59 Waterwall, 197 198 Watt’s boilers, 98 Wet flue gas desulfurization, 186 190 Wet scrubbers, 41 42, 43f Wet-type electrostatic precipitator, 193 194 Wheeled bumper mounted drone, 456 William Fairbairn’s Lancashire boiler, 65 Wind-and/or water mills, 57 World natural gas supply and demand, 13 15 Wrought-iron boiler, 64 Z Zeldovich mechanism, 27 Zone module construction method, 260 261 bunker zone, 261 eco hopper zone, 261 furnace lower zone, 261 furnace upper zone, 261 mill zone, 261 SCR and AH zone, 261 secondary pass zone, 261 side, front, and rear zone, 260