ASIA-PACIFIC PARTNERSHIP on Clean Development and ClimateThis textbook has been prepared by Japanese electric power companies as a contribution to PGT-06-01: Best Practices for Power Generation one of the activities undertaken by the Power Generation and Power Distribution Task Force in the context of the ASIA-PACIFIC PARTNERSHIP on Clean Development and Climate. The textbook describes important issues associated with maintaining, and enhancing, levels of heat efficiency at a coal-fired thermal power plants, and constitutes a summary of matters of which all technicians working in power generation plants need to be aware. It would give us considerable satisfaction if this textbook provides useful guidance to technicians in the course of day-to-day operations, and in the carrying out of maintenance, at coal-fired thermal power plants. In the course of preparing this textbook, we have quoted extracts from books and Bulletins of the Thermal and Nuclear Power Engineering Society. The authors would like to extend their warmest appreciation to individual writers of these books and Bulletins, as well as to the Societies itself, for their willingness to provide such valuable information, and thus to make this textbook possible. April, 2007 The Federation of Electric Power Companies of Japan ASIA-PACIFIC PARTNERSHIP on Clean Development and ClimateList of Authors (Titles Dispensed and Omitted and Listed in Random Order) Kazuhiro Sakai: Section Manager, Affair Infrastructure Sec. Thermal Power Dept. Hokkaido Electric Power Co., Inc.Satoshi Tanishima: Manager, Planning Group, Thermal Power Department, Tokyo Electric Power Company Kenichiro Kawashima: Deputy Manager, Planning Group, Thermal Power Department, Tokyo Electric Power Company, Tatsurou Yamaoka: Manager, Overseas Project Group, Thermal Power Plant Engineering Center, Thermal Power Department, Tokyo Electric Power Company Shinichi Taniguchi: Mechanical Engineering & Asset Management Strategist, Overseas Project Group, Thermal Power Department, Tokyo Electric Power Company Terunori Kobayashi: Manager, Operations & Maintenance Section, Thermal Power Department, Chubu Electric Power Co., Inc. Noriyuki Sonoda: Assistant Manager, Thermal Power Administration Sect. Power Generation Div. The Chugoku Electric Power Co., Inc. Susumu Sakata: Staff Assistant Manager, Thermal Power Mechanical Engineering Sect. Power Generation Div. The Chugoku Electric Power Co., Inc. Shin Katayama: Assistant Manager, Technical Section, Karatsu Power Station, Kyushu Electric Power Co., Inc. Takashi Maruta: Technical Section, Karatsu Power Station, Kyushu Electric Power Co., Inc. Takashi Naganuma: Senior Research Engineer, Environment And Chemistry Engineering Group, Research Laboratory, Kyushu Electric Power Co., Inc. Yoshiaki Fukuzawa: Manager, Plant Management Group No.1, Thermal Power Dept. Electric Power Development Co., Ltd. Yoshitaka Oka: Assistant Manager, Plant Management Group No.1, Thermal Power Dept. Electric Power Development Co., Ltd. Thermal and Nuclear Power Engineering SocietyMasaru Wakao: Deputy General Manager, Thermal Power Department, Thermal And Nuclear Power Engineering Society SecretariatMasato Hasegawa: Manager, Siting and Environment, The Federation of Electric Power Companies Hirofumi Kazuno: Deputy General Manager, Siting and Environment, The Federation of Electric Power Companies Tomoaki Koga: Manager, Engineering Department, The Federation of Electric Power Companies Yasunori Eitoku: Manager, Engineering Department, The Federation of Electric Power Companies Masato Ishimura: Deputy General Manager, Engineering Department, The Federation of Electric Power Companies ASIA-PACIFIC PARTNERSHIP on Clean Development and ClimateTable of Contents Chapter 1 Summary of Thermal Power Generation in Japan 11.1 History of Electric Power Companies in Japan 1 1.2 History of the Power Plant and the Role of Thermal Power Generation in Japan 1 1.3 Movements in Thermal Efficiency of Thermal Power Plants in Japan and Outlook 7 for Thermal Power Generation Technology in the Future Chapter 2 Functional and Operational Control of Thermal Power Plants 12 2.1 Operation Control 12 2.2 Power Supply Operations 22 2.3 Start-up and Stop Operation Control 25 2.4 Performance Management 39 2.5 Example of Operation Control and Performance Management 57 (Hokkaido Electric Power Co., Inc) 2.6 Combustion of Coal 103 2.7 Examples for the Operation of Soot Blowers 133 Chapter 3 Maintenance and Efficiency Control of Thermal Power Plants 142 3.1 Maintenance and Administration of Aged Thermal Power Plants 142 3.2 Boilers and Auxiliary Machines 163 3.3 Water Quality Control of Boiler 200 3.4 Turbines and Auxiliary Machines 263 3.5 Power Generators 330 3.6 Efficiency and Operation Improvement of Thermal Power Plants 366 Chapter 4 Environmental Preservation Provision of Facilities 3764.1 Environmental Preservation Measures of Thermal Power Plants 376 4.2 Dust Precipitator 393 4.3 Desulphurization Equipment 409 4.4 Denitrification Equipment 427 4.5 Maintenance of Environmental Protection System 448 4.6 Waste Treatment and Effective Use 457 References 1. Summary of thermal power generation in Japan 1.1 History of electric power companies in Japan Electricity supply in Japan is carried out by independent regional electric power companies, which require closecommunication to operate efficiently. In 1952, the nine major electric power companies established the Federationof Electric Power Companies (FEPC) to promote smooth operations within the industry. Since then, the FEPC hasplayed an important role as a base for communication between the power companies and as a forum for exchanging ideas on the evolution of the environment in the electricity industry. The FEPC undertakes variousactivities aimed at ensuring operations of the electricity industry in keeping with the development of the countryas a whole.With the restoration of Okinawa to Japan in 1972, the Okinawa Electric Power Company resumed itsparticipation in Japan's electric power industry, becoming a full FEPC member in March 2000.Fig. 1.1-1 Service Areas by Company1.2 History of the power plant and the role of thermal power generation in JapanElectricity consumption in Japan has expanded almost consistently after the world war . Further, in recent years, the need has intensified for a comfortable life as seen in the progression of computerization and theproliferation of air conditioners, and even though the Japanese economy has entered a stable growth period,electric power demand shows no signs of slowing down. In addition, new problems are starting to appear as thedemand increases.Let consider the current situation and future of electricity consumption.Due to the betterment of people's living standards, comfortable living is sought and the role of electricity inliving starting with air conditioning is growing increasingly. Moreover, due to the progression of a highlyintelligent community as a result of IT innovation including the computer and communication, the role of electricity is increasing in all aspects of industry and living. From these facts, over the course of time, the percentage of electricity consumption among consumption of other energies (electrification ratio) is running high.Although the electric power demand is dependent on the trends in the business climate and those in politics andthe community, even in recent years when the Japanese economy has entered a stable growth period, it continuesto increase due to the progression of computerization and the proliferation of air conditioners.1Electric power in Japan is supplied mainly by thermal (oil, LNG, coal, etc.), hydro, and nuclear powergeneration. There are 1,300 or more power plants in all parts of Japan to meet the electric power demandgrowing steadily due to an upsurge in the desire to seek comfortable living, computerization, graying, etc.Ratio of electric power accounting for primary energies (electrification ratio)PJ (Petajoules=1015J)Domestic supply of primary energies(Fiscal ) denotes the percentage that electric power accounts for(Note) 1PJ equals a heating value of about 25,800 kl of crude oil. Source: Comprehensive Energy Statistics (2003 version)Fig.1.2-1: Ratio of electric power accounting for primary energies (electrification ratio) The role of electric energy, being useful and easy to use, is intensifying year after year, and the ratio of electricenergy to the consumption of all energies has now reached about 40%.2Track record and outlook of power generated by source.(Hundred million kWh)Nuclear powerOil, etc. CoalPower generated yearly Natural gas (LNG)Geothermal power generation and new Hydro3Fig.1.2-2: Track record and outlook of power generated by Source.(Fiscal)(Note) 1. Oil, etc. includes LPG, other gases and bituminous mixtures.2. Due to rounding off, there may be cases where the total valuedoes not equal 100%.3. Total of 10 electric power companies. Power received is included.The numer 4. ic values in the graph represent the segment share (%).Source: Outline of Fiscal 2005 Supply Program(March 2005) and othersPower generated increases with each passing year, and we cope with the demand for increasing electric powerwhile planning departure from the use of oil through the use of nuclear energy, natural gas (LPG), etc.As our lives become convenient and rich, the role of electricity serving in our lives continues to expand. Theamount of electricity usage varies significantly depending on the time period of the day and the season.When we look at the electric consumption on an annual basis, in recent years, the growth in the summer season is significant due to air conditioning, and when we look at it on a daily basis, the maximum consumption is marked at about 2:00 p.m. when the heat in midsummer reaches its peak. The difference between the maximumand the minimum values of electricity consumption is more and more on an increasing trend. The increase inhome air conditioners has a significant effect on this.On the other hand, electricity is an energy that is impossible to be stored. Although a plant that generateselectric power is built to the peak of demand (maximum electric power demand), when the electric power demandvaries significantly according to season and time period, efficiency in the utilization of the power plant lowers,and as a result, the cost to deliver the electricity will be comparatively high.

(Merging of 10 electric power companies)(Million kW)Movements in how electricity is used over one day in midsummerJuly 20, 2004 August 25, 1995July 24, 2001 August 7, 1990August 29, 1995July 31, 1975 4Fig. 1.2-3 Movements in how the electricity is used over one day in midsummerSurvey conducted by the Federation of Electric PowerCompanies of Japan(Time)(Note) Merging of 9 electric power companies only in 1975 For electric power demand, there is a significant difference between daytime and nighttime in one day. Thisreflects the fact that while a good amount of electricity is used by plants and offices in the daytime, industrialactivities are not performed much at night. In addition, even in the daytime, the amount of electricity useddecreases from 12:00 to 13:00 p.m. when plants and offices are in a lunch break.During the day on a hot summer day, electric power demand for air conditioning increases. The consumption atthe peak in the daytime reaches about 2 times that in the time period in a day when the consumption is lowest.

(Merging of 10 electric power companies) (Million kW)Movements in how the electricity is used over one year (All-time maximum)Fiscal 2001Fiscal 2004Fiscal 1995Fiscal 1985Fiscal 1990Fiscal 1975Fiscal 1968Fiscal 1967(Month)5

(Note) Merging of 9 electric power companies before1975Survey conducted by the Federation of Electric PowerCompanies of JapanFig.1.2-4: Movements in how the electricity is used over one yearWhen we look at electric power demand on a month-by-month basis, there is a big change in how the electricityis used even through one year. Electricity demand registered its peak during the summer season of fiscal 1968,and currently, there are 2 peaks in the summer and the winter in conjunction with the upsurge in electric powerdemand used for heating in winter. In particular, the increase in the peak in summer is remarkable, showing a biggap compared with spring and autumn when there is low demand for air conditioning. The gap in electric powerdemand due to the season will cause the efficiency of the utilization rate of plant to lower together with scale-upof the gap due to the time period, and will contribute to increasing the cost to deliver the electricity to theconsumer.[Combination in response to the characteristics of the source]Although the amount of electricity usage varies, as it is impossible to store the electricity, and it is necessary to adjust the amount of electricity to be generated with reference to the electric power demand. Electric powercompanies combine a variety of electric power generation systems for the purpose of meeting electric powerdemand that varies every moment.c Efforts to cope with peak electric power demandDuring the day when electricity is used in large amounts, a power plant must generate high-volume electricity.Provision for peak electric power demand is made by an oil-fired thermal power and pumped-storagehydroelectric power generation, which are excellent in coping with electric power demand that can vary.c Supplying base electric power demandOn the other hand, base electric power demand is supplied by nuclear power generation and hydro powergeneration (run-off river type) taking the power generation cost and environment load into account.c Combined use of sourcesFurther, in Japan, most energy resources rely on imports from abroad. To supply electricity with stability in thefuture as well, taking the limited fossil resources, global environmental issues, further economics, etc. intoaccount, we intend to combine the resources in well-balanced way making use of characteristics of each type of power generation including hydro, thermal, and nuclear, thereby dispersing the risk by not relying on one source.Electricity demand varies during the day or at night even in one day. In electric utilities, the features of hydro,thermal, and nuclear power generation such as operation characteristics, economics, and efforts to cope withglobal environmental issues are judged comprehensively to combine various kinds of sources in an optimumbalance.Pumped-storagehydroelectric powerEqualizing pool-typehydroWater reservoir-typehydroSupply capacity to copewith peak electric powerdemandOilSupply capacity to copewith middle electricpower demandLNG, LPG, and other gasesCoalNuclear powerSupply capacity to copewith base electric powerdemandRun-off river-type hydro/geothermal power generation(Time)Fig.1.2-5: Combination of sources for electric power demandTable 1.2-1: Characteristics of respective sources and optimum combinationPower generationsystemSupply capacity CharacteristicsPumped-storagehydroelectric power Supply capacity to cope with peak electric power demandFinds application as a supply capacity to cope with suddenfluctuation in demand and peak demand because it copes veryeasily with fluctuation in electric power demand.Equalizing pool-typehydroWater reservoir-typehydroSupply capacity to cope with peak electric power demandAlthough the initial cost is high, this is excellenteconomically from the viewpoint of average service life, and because it copes extremely easily with fluctuation in electric power demand, this type finds application as a supplycapacity for peak demand.Oil-fired thermalpowerSupply capacity to cope with peak electric power demandAlthough the running cost is relatively high, the capital cost islow and it is excellent in coping with fluctuation in electric power demand, thereby finding application as a supplycapacity for peak demand.LNG, LPG, and other gas-fired thermalpowerSupply capacity to cope with middleelectric power demandThe running cost is low, and with respect to the capital cost aswell, it is cheaper than a coal-fired thermal power and it is excellent in coping with fluctuation in electric power demand,thereby finding application as a supply capacity for middledemand.Coal-fired thermalpowerSupply capacity to cope with base and middle electric powerdemandsAlthough the capital cost is high, it copes more easily than nuclear power with fluctuation in electric power demand,thereby finding application as a supply capacity forintermediate demand between that for base demand and that for middle demand.67Nuclear power Supply capacity to cope with base electric power demand Although the capital cost is high, the running cost is low, whereby this can perform the operation at a high utilization rate as a supply capacity for base demand. Run-off river-type hydro power generationSupply capacity to cope with base electric power demand Although the initial cost is high, it is excellent economically from the viewpoint of average service life, and it finds application as a supply capacity for base demand. Supply capacity for peak demand: A source whose amount of electricity to be generated can easily be adjusted Supply capacity for middle demand: A source that has the two features of peak electric power demand and base electric power demand Supply capacity for base demand: A source that supplies a constant volume of electricity 1.3 Movements in thermal efficiency of thermal power plants in Japan and outlook for thermal power generation technology in the future Since the first Rankine cycle-based thermal (steam) power generation plant (Steam pressure: 0.59MPa (gage) (6atg), 7.5kW (10HP) was manufactured by Charles A. Persons in 1884, the thermal efficiency of steam power generation plants has improved significantly together with improvement of steam conditions (higher temperature/higher pressure) and larger capacity. In Japan as well, LNG-fired supercritical pressure (SC) plants whose main steam pressure was 24.3 MPa (gage) (246 atg) and whose main/reheat steam temperature was 538/566 qC came into operation in the form of Tokyo Electric Power Company's Anegasaki thermal plant Unit No.1 in 1967. Subsequently, similar steam conditions were adopted for coal-fired plants, and in 1989, 2-stage reheat LNG-fired Ultra Supercritical pressure (USC) thermal power generation whose main steam pressure was 31.0 MPa (gage) (316atg) and whose ultra-supercritical-pressure/high-pressure/middle-pressure steam temperature was 566/566/566 qC came into operation at CHUBU Electric Power Company's Kawagoe thermal power plant Unit No.1. As described earlier, improvement of steam conditions has been planned steadily. However, in recent years, the growth of steam conditions has become relatively slow, and as shown in the figure, the thermal efficiency of steam power generation moves at little over 40%. Slowdown trends in rise of thermal efficiency of thermal (steam) power generation achieved a significant change through the introduction of LNG combined cycle power generation using a full-scale exhaust heat recovery system with a turbine inlet temperature (TIT) of the 1100-qC-class gas turbine as a core at TOHOKU Electric Power Company's Higashi Niigata Unit group No.3 in 1984. As shown in the figure, through the adoption of combined cycle power generation system combining the Brayton cycle (gas turbine) and the Rankine cycle (steam turbine), the thermal efficiency of the thermal power plant rose in a stroke to about 44%. TIT of gas turbines for commercial use has risen at a rate of about 20qC/year on average due to progression of cooling technology and development of heat-resistant materials. In November 1999, the advanced combined cycle power generation cycle (ACC) consisting mainly of a 1,450-qC-class gas turbine begun commercial operation at TOHOKU Electric Power Company's Higashi Niigata Unit group No.4-1, and 50% thermal efficiency, having which had been a dream for a long time in the thermal power generation sector, was attained. During this period, a number of LNG combined cycle power generation plants were introduced one after another, and attained an excellent track record of operation with high thermal efficiency, load change, etc. The installed capacity of LNG combined cycle power generation at the end of 2001 reached 22 million kW in total across the 6 Electric Power Companies & 21 groups, coming to account for 17% of the installed capacity of all commercial-use thermal power generation. Currently, in addition, TOKYO Electric Power Company's Futtsu thermal power plant Unit group 3 & group 4, Shinagawa thermal power plant Unit group No.1, Kawasaki thermal power plant Unit group No.1, TOHOKU Electric Power Company's Unit group No.4-2, etc. are in the advanced stage of construction, and the thermal efficiency of ACC under construction is planned to be 50 to 53%. On the other hand, with respect to coal-fired thermal power, improvement in the steam condition of coal-fired USC thermal power generation continues steadily such as at CHUBU Electric Power Company's Hekinan thermal power plant Unit No.3 (main steam pressure: 24.1 MPa (gage) (246 atg), main/reheat steam temperature: 538/593qC), Electric Power Development Company's Matsuura thermal power plant Unit No.2, HOKURIKU Electric Power Company's Nanao Ohta thermal power plant Unit No.2 (main steam pressure: 24.1 MPa (gage) (246 atg), main/reheat steam temperature: 593/593qC), TOHOKU Electric Power Company's Haramachi thermal power plant Unit No.2, CHUGOKU Electric Power Company's Misumi power plant Unit No.1 (main steam pressure: 24.5 MPa (gage) (250atg), main/reheat steam pressure: 600/600qC), Electric Power Development Company's Tachibanawan thermal power plant Unit No. 1 & No.2 (main steam pressure: 25 Mpa (gage) (255atg), main/reheat steam pressure: 600/610qC), which have started operation.In addition, pressurized fluidized bed combustion (PFBC) combined cycle generation plants combiningexpansion and steam turbines started operation at HOKKAIDO Electric Power Company's Tomatoh Atsuma UnitNo.3 in 1998, CHUGOKU Electric Power Company's Oosaki Unit No.1-1 in 2000, and KYUSHU Electric Power Company's Kanda Unit No.1 in 2001. Through these, the thermal efficiency of coal-fired thermal power plantsreached about 43%. Combined cycle power generation(Gas/Steam turbine)Higashiniigata#4KawasakiGross thermal efficiency [%] HHV Himeichi#5Higashiniigata#3Yokohama #7, 8 Kashima#5 Anesaki#1Shinkokura#2Chiba#2Chiba#1Hitachinaka#1Kawagoe#1Kanda#1Steam power generation (Boiler/Steam turbine)Fiscal yearFig.1.3-1: Developments in thermal efficiency of thermal power generation 89Table 1.3-1: Major coal-fired thermal power generation plants in Japan (1959 - 1985) Manufacturer Era No.Electric power companyPower plant UnitApproved output Steam conditions Boiler Turbine GeneratorOperation started from1Sumitomo joint electric power co., Ltd Niihamanishi Unit No.1 75 10.0MPa-538qC/538qC MHI MHI Mitsubishi Electric Corp. 1959-082 Tohoku Sendai Unit No.1 175 16.6MPa-566qC/538qCBabcock-Hitachi K.K.GE, Hitachi, Ltd.Hitachi, Ltd. 1959-103 Kyushu Minato Unit No.1 156 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp. 1960-094 Tohoku Sendai Unit No.2 175 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1960-115 Chugoku Mizushima Unit No.1 125 12.5MPa-538qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1961-116 Tohoku Sendai Unit No.3 175 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1962-067Sumitomo joint electric power co., Ltd Niihamanishi Unit No.2 75 10.0MPa-538qC/538qC MHI MHI Mitsubishi Electric Corp. 0962-078 Chugoku Mizushima Unit No.2 156 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1963-089 Kyushu Omura Unit No.2 156 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp. 1964-0810 Shikoku Saijo Unit No.1 156 16.6MPa-566qC/538qC MHI Toshiba Corp. Toshiba Corp. 1965-1111 Chugoku Shimonoseki Unit No.1 175 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp. 1967-0312 J-POWER Takehara Unit No.1 250 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1967-0713 Hokkaido Naie Unit No.1 175 16.6MPa-566qC/538qC IHI Toshiba Corp. Toshiba Corp. 1968-0614 J-POWER Takasago Unit No.1 250 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp. 1968-0715 J-POWER Takasago Unit No.2 250 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp. 1969-0116 Hokkaido Naie Unit No.2 175 16.6MPa-566qC/538qC IHI Hitachi, Ltd. Hitachi, Ltd. 1970-0217 Shikoku Saijo Unit No.2 250 16.6MPa-566qC/538qC IHI Hitachi, Ltd. Hitachi, Ltd. 1970-0618Jyoban Joint Power Co. Nakoso Unit No.7 250 16.6MPa-566qC/538qC MHI Hitachi, Ltd. Hitachi, Ltd. 1970-1019Tobata Co-operative Thermal Power Company, Inc.Tobata Co-operative Thermal Power Company, Inc.Unit No.2 156 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp. 1971-0620 Toyama Kyodo Toyamashinko Unit No.1 250 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1971-0921 Toyama Kyodo Toyamashinko Unit No.2 250 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1972-06Before 197522Sumitomo joint electric power co., Ltd Mibugawa Unit No.1 250 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp. 1975-0323 Hokkaido Sagawa Unit No.3 125 12.5MPa-538qC/538qC MHI Fuji Fuji 1977-0624Sakata kyodo power company, Ltd.Sakata kyodo power company, Ltd.Unit No.1 350 16.6MPa-566qC/538qC MHI Toshiba Corp. Toshiba Corp. 1977-1025Sakata kyodo power company, Ltd.Sakata kyodo power company, Ltd.Unit No.2 350 16.6MPa-566qC/538qC MHI Hitachi, Ltd. Hitachi, Ltd. 1978-1026 Hokkaido TomatohAtsumaUnit No.1 350 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Toshiba Corp. Toshiba Corp. 1980-1027 J-POWER Matsushima Unit No.1 500 24.1MPa-538qC/538qC MHI Hitachi, Ltd. Hitachi, Ltd. 1981-0128 J-POWER Matsushima Unit No.2 500 24.1MPa-538qC/538qC MHI Toshiba Corp. Toshiba Corp. 1981-0629 Hokkaido Sagawa Unit No.4 125 17.7MPa-538qC/538qC KHI Fuji Fuji 1982-0530 J-POWER Takehara Unit No.3 700 24.1MPa-538qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1983-0331Jyoban Joint Power Co. Nakoso Unit No.8 600 24.1MPa-538qC/566qC MHI Hitachi, Ltd. Hitachi, Ltd. 1983-0932Jyoban Joint Power Co. Nakoso Unit No.9 600 24.1MPa-538qC/566qC IHI Toshiba Corp. Toshiba Corp. 1983-12From1976 to 198533 Hokkaido TomatohAtsumaUnit No.2 600 24.1MPa-538qC/566qC IHI Hitachi, Ltd. Hitachi, Ltd. 1985-1010Table 1.3-2: Major coal-fired thermal power generation plants in Japan (1986 - 2005) Manufacturer Era No.Electric power companyPower plant UnitApproved output Steam conditions Boiler Turbine GeneratorOperation started from34 Chugoku Shinonoda Unit No.1 500 24.1MPa-538qC/566qC IHI Toshiba Corp. Toshiba Corp. 1986-0435 J-POWER Ishikawa Unit No.1 156 18.6MPa-566qC/566qC KHI Fuji Fuji 1986-1136 Chugoku Shinonoda Unit No.2 500 24.1MPa-538qC/566qC IHI Toshiba Corp. Toshiba Corp. 1987-0137 J-POWER Ishikawa Unit No.2 156 18.6MPa-566qC/566qC KHI Fuji Fuji 1987-0338 Kyushu Matsuura Unit No.1 700 24.1MPa-538qC/566qC MHI Hitachi, Ltd. Hitachi, Ltd. 1989-0639 J-POWER Matsuura Unit No.1 1000 24.1MPa-538qC/566qCBabcock-Hitachi K.K.MHI Mitsubishi Electric Corp. 1990-0640 Chubu Hekinan Unit No.1 700 24.1MPa-538qC/566qC MHI Toshiba Corp. Toshiba Corp. 1991-1041 Hokuriku Tsuruga Unit No.1 500 24.1MPa-566qC/566qC MHI Toshiba Corp. Toshiba Corp. 1991-1042 Chubu Hekinan Unit No.2 700 24.1MPa-538qC/566qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1992-0643 Chubu Hekinan Unit No.3 700 24.1MPa-538qC/593qC IHI MHI Mitsubishi Electric Corp.1993-0444 Tohoku Noshiro Unit No.1 600 24.5MPa-538qC/566qCBabcock-Hitachi K.K.Fuji Fuji 1993-0645 Okinawa Gushikawa Unit No.1 156 16.6MPa-566qC/538qC KHI Hitachi, Ltd. Hitachi, Ltd. 1994-0346 Soma Kyodo Shinchi Unit No.1 1000 24.1MPa-538qC/566qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1994-0747 Tohoku Noshiro Unit No.2 600 24.1MPa-566qC/593qC IHI Toshiba Corp. Toshiba Corp. 1994-1248 Hokuriku Nanao Ohta Unit No.1 500 24.1MPa-566qC/593qCBabcock-Hitachi K.K.MHI Mitsubishi Electric Corp.1995-0349 Okinawa Gushikawa Unit No.2 156 16.6MPa-566qC/538qCBabcock-Hitachi K.K.MHI Mitsubishi Electric Corp.1995-0350 J-POWER Takehara Unit No.2 350 16.6MPa-566qC/538qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1995-0651 Soma Kyodo Shinchi Unit No.2 1000 24.1MPa-538qC/566qC MHI Toshiba Corp. Toshiba Corp. 1995-07From1986 to 199552 Kyushu Reihoku Unit No.1 700 24.1MPa-566qC/566qC IHI Toshiba Corp. Toshiba Corp. 1995-1253 J-POWER Matsuura Unit No.2 1000 24.1MPa-593qC/593qCBabcock-Hitachi K.K.MHI Mitsubishi Electric Corp.1997-0754 Tohoku Haramachi Unit No.1 1000 24.1MPa-566qC/593qC MHI Toshiba Corp. Toshiba Corp. 1997-0755 Hokkaido TomatohAtsumaUnit No.3 85 16.6MPa-566qC/538qC MHI MHI Mitsubishi Electric Corp.1998-0356 Chugoku Misumi Unit No.1 1000 24.5MPa-600qC/600qC MHI MHI Mitsubishi Electric Corp.1998-0657 Hokuriku Nanao Ohta Unit No.2 700 24.1MPa-593qC/593qC IHI Toshiba Corp. Toshiba Corp. 1998-0758 Tohoku Haramachi Unit No.2 1000 24.1MPa-600qC/600qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 1998-0759 Shikoku Tachibana wan Unit No.1 700 24.1MPa-566qC/593qCBabcock-Hitachi K.K.Toshiba Corp. Toshiba Corp. 2000-0660 J-POWER Tachibana wan Unit No.1 1050 25.0MPa-600qC/610qC IHI Toshiba Corp., GE GE 2000-0761 Hokuriku Tsuruga Unit No.2 700 24.1MPa-593qC/593qC MHI Toshiba Corp. Toshiba Corp. 2000-0962 J-POWER Tachibana wan Unit No.2 1050 25.0MPa-600qC/610qCBabcock-Hitachi K.K.MHI Mitsubishi Electric Corp.2000-1263 Chugoku Osaki Unit No.1 250 16.6MPa-566qC/593qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 2000-1264 Kyushu KandaNew Unit No.1 360 24.1MPa-566qC/593qC IHI GT: ALSTOM ST: TOSHIBAToshiba Corp. 2001-0765 Chubu Hekinan Unit No.4 1000 24.1MPa-566qC/593qC IHI Toshiba Corp. Toshiba Corp. 2001-1166 Okinawa Kin Unit No.1 220 16.6MPa-566qC/566qC MHI Hitachi, Ltd. Hitachi, Ltd. 2002-0267 J-POWER Isogo Unit No.1 600 25.0MPa-600qC/610qC IHI FujiSIEMENSFuji 2002-0468 Hokkaido TomatohAtsumaUnit No.4 700 25.0MPa-600qC/600qC IHI Hitachi, Ltd. Hitachi, Ltd. 2002-0669 Chubu Hekinan Unit No.5 1000 24.1MPa-566qC/593qC IHI Toshiba Corp. Toshiba Corp. 2002-1170 Okinawa Kin Unit No.2 220 16.6MPa-566qC/566qC MHI Hitachi, Ltd. Hitachi, Ltd. 2003-0571 Kyushu Reihoku Unit No.2 700 24.1MPa-593qC/593qC MHI Toshiba Corp. Toshiba Corp. 2003-0672 Tokyo Hitachinaka Unit No.1 1000 24.5MPa-600qC/600qCBabcock-Hitachi K.K.Hitachi, Ltd. Hitachi, Ltd. 2003-1273 Tokyo Hirono Unit No.5 600 24.5MPa-600qC/600qC MHI MHI Mitsubishi Electric Corp.2004-07From1996 to 200574 Kansai Maizuru Unit No.1 900 24.1MPa-595qC/595qC MHI MHI Mitsubishi Electric Corp.2004-0811 Technical development, in general, aims at higher efficiency of power generation for the purpose of reducing the environmental load and CO2 emission; however, concrete issues include the following: (1) High-temperature gas turbine aiming at further improvement of thermal efficiency of combined cycle power generation (2) Making coal utilization technology starting with coal gasification combined cycle power generation system more sophisticated Thermal power plants consist of a boiler, turbine, and generator, and the efficiency of power generation was increased through the larger capacity of the configuration of the basic equipment and sophistication of running conditions (mainly higher temperature and pressure of the stem cycle system). Gross thermal efficiency was increased from about 30% 40 years ago to 40% currently. This 40% was achieved by the ultra-supercritical pressure power generation system. For the purpose of increasing the efficiency further, the development of combined cycle power generation technology is in progress. Through this development, we can aim at 50% efficiency. This technology aims, in addition to the conventional steam cycle, to combine the gas turbine cycle to improve the efficiency of power generation comprehensively through power generation from both cycles. Combined cycle power generation using natural gas is becoming mainstream in new thermal power generation technology as combined cycle power generation. Further, the development of a ceramic turbine blade is in progress to improve the efficiency by causing higher temperature. With respect to the use of coal related to the reduction of CO2 emission, although the pulverized coal combustion system has been adopted in recent years for the purpose of improving efficiency, the integrated coal gratification combined cycle (IGCC) is the target of development to improve efficiency further. The fluidized bed generation system is a generation system that uses fluidized bed combustion. The commercialization of fluidized bed combustion was propelled as a combustion system of flame-resistant materials. However, in recent years, the excellent environmental characteristics of fluidized bed combustion, such as desulfurization in furnace and low NOx combustion, are receiving attention. From the viewpoint of improving efficiency, the development and commercialization of the pressurized fluidized bed combined cycle generation system (PFBC) are in progress. In light of its intrinsic characteristics, it is also considered that it will pave the way for mixed fuel power generation with coal and biomass (especially waste). I.2 Functional and Operational Control of Thermal Power Plants 2.1.1 Operation controlSince safe and economical operation is carried out at thermal power stations while carefully checking environmental problems, there are many points that operators must judge to takeappropriate measures. Therefore, a large load is applied to operators in case of an emergency.Therefore, it is necessary to automate emergency manual operations to be taken against faults, aswell as to automate normal manual operations in order to minimize operators judgments. To keepthe final protection of the plant, it is absolutely required to take appropriate measures for the plantfacilities.A unit protection device is installed to protect each unit if a fault occurs in any unit and itbecomes difficult to continue safe operation of the unit. This unit protection device is called theunit trip interlock. Basically, the unit trip interlock is classified into the boiler protectioninterlock (MFT), turbine protection interlock (MTS), and generator protection interlock (86G). These interlock systems may vary depending on the manufacturers design. In principle,however, the once-through unit boiler, turbine, and generator are mutually interlocked. Figure 35shows an example of the trip interlock system. 2.1.1.1 Boiler protection interlock (MFT) This boiler protection interlock is intended to shut down the fuel supply to stop the boiler if itbecomes difficult to continue stable combustion of the boiler. The conditions for tripping of thisinterlock may vary slightly depending on the type of boiler, that is, whether it is drum boiler or a once-through unit boiler. Generally, these conditions are fuel pressure drop, high furnace pressure,stopping of two ventilating fans, protection of the reheating unit, supply water flow rate drop, anddrum level drop. In addition to these conditions, unit emergency stop and turbine/generator tripconditions are interlocked. According to the boiler model, further conditions are interlocked. 2.1.1.2 Turbine protection interlock (MTS) If it becomes difficult to continue stable operation of the turbine, the solenoid is operated to stopthe turbine. The conditions for tripping of this interlock are turbine overspeed, thrust error,bearing hydraulic pressure drop, and degree of vacuum drop, etc. In addition to these conditions,the unit emergency stop, turbine manual stop, and generator trip conditions are interlocked. Basic interlock circuitProblem on generator sideProblem on turbine sideGenerator tripTurbine tripFire extinguishingof boilerA type DescriptionIf a problem occurs on theturbine side and the turbine istripped (each turbine valve is opened), the generator and boilerare stopped conditionally. Thissystem is that the T-G and T-B arenot tripped if the conditions arenot satisfied. This system is mainly used forunits designed by Ebasco.A-type interlock circuitProblem on generatorsideProblem on turbinesideProblem on boiler sideGenerator tripTurbine tripFire extinguishing ofboilerAny of the thrust, hydraulicpressure, or exhaust speed is faulty.Conditions for protection ofthe reheaterDescriptionIf a problem occurs on the turbine side and the turbine is tripped (each turbine valve isopened), the generator and boilerare stopped immediately.In this group, a circuit to immediately extinguish fire in the boiler if a problem occurs on the generator side is added.B-type interlock circuitProblem on generatorsideProblem on turbinesideProblem on boiler sideGenerator tripTurbine tripFire extinguishing ofboilerDescriptionIf a problem occurs in any of theboiler, turbine, or generator,mutual interlock is activated to trip the unit completely.This interlock where the turbineis tripped immediately if a problem occurs in the boiler is acharacteristic feature, whichcannot be seen in the A type or Btype.C-type interlock circuitProblem on generatorsideProblem on turbinesideProblem on boiler sideGenerator tripTurbine tripFire extinguishing ofboilerB type C type Problem on boiler side Fig. 35 Examples of trip interlock systems12132.1.1.3 Generator protection interlock (86G) A status where stable operation of the generator or transformer is difficult is detected by the protective device or protective relay. After this, the generator is disconnected from the system and the turbine is tripped to stop the generator at the same time. The conditions for detection of the protection are ratio differentiation of the generator, loss of excitation, ratio differentiation of the ground fault or transformer, impulse hydraulic pressure, overexcitation, etc. In addition to these conditions, the high/low frequency of the system and the protection of the bus-bar are interlocked. 2.1.1.4 Protection device tests during operation The important point during plant operation is that the plant can be stopped safely in case of an emergency. To maintain this safety, it is necessary to periodically check the operation status of various safety prevention apparatus installed for protection of the plant. Table 3 shows examples of the protection device tests. Table 3 Examples of protection device tests Inspection test item Frequency Contents of test Valve tests (1) Main steam stop valve Twice/week The valves are manually opened or closed one by one from the central control room to check the valve operation and open/closed indication lamp operation.(2) Intercept valve, reheated steam stop valve, combined reheat valve Twice/week The valves of each system are manually opened or closed from the central control room to check the valve operation and open/closed indication lamp operation. Protection device tests (1) Lock-out (Oil trip) Once/week After the operation of the emergency shutdown device has been removed, the test handle is operated to check the operation of the oil trip mechanism. (2) Thrust failure protection trip Once/week After the operation of the thrust failure protection device has been removed, the test handle is operated to check the operation of the thrust bearing wear trip mechanism. Extraction check valve test Twice/week Valves are manually opened or closed with the test handle or switch to check the valve operation and open/closed indication lamp operation. Oil pump automatic starting test Once/week The hydraulic pressure is decreased using the testing equipment in the simulated mode to check the automatic startup at the set hydraulic pressure levels of the auxiliary oil pump, emergency oil pump, and turning oil pump. Main turbine Main oil tank oil level alarm test Once/week The indication rod of the oil gauge is moved up or down to check the alarm operation. Valve test Once/week The high-pressure and low-pressure steam stop valves are opened or closed manually to check the operation of the valve and open/close unit. Protection device tests (1) Overspeed trip Once/month After the trip circuit has been removed, the RPM is increased in the simulated mode to check the overspeed trip set hydraulic pressure level. (2) Bearing hydraulic pressure drop trip Once/month After the trip circuit has been removed, the bearing oil pressure is decreased in the simulated mode to check the trip set hydraulic pressure level. (3) Thrust failure protection trip Once/month After the trip circuit has been removed, the thrust position is moved in the simulated mode to check the trip set hydraulic pressure level. Oil pump auto starting test Once/month The hydraulic pressure is decreased using the testing equipment in the simulated mode to check the automatic startup at the set hydraulic pressure levels of the extra main oil pump and emergency oil pump. Turbine driven feed pump Spare feed water pump (motor drive) starting test Once/month The pump is manually started at the work site, and a load is applied to check the operation of the auxiliary oil pump and minimum flow recirculating valve.Emergency pump automatic starting test (Seal oil discharge pressure, low differential pressure alarm test) Once/week The discharge pressure and differential pressure of the seal oil are decreased using the testing equipment in the simulated mode to check the alarm operation and auto startup at the set hydraulic pressure level. Seal oil equipment Vacuum drop alarm test of vacuum tank Once/month The vacuum level is decreased using the testing equipment in the simulated mode to check the alarm operation. I.142.1.2 Boiler operation control during normal operation It must be strongly attempted to find the error status early and to prevent problems during normal unit operation in order to maintain stable operation status. The actions to be actually taken are basically classified into the inspection at the work field, and the sampling and evaluation of the operation records. It is important to take these actions daily in order to check status change in the early phase, and this leads to appropriate actions and measures being taken in a timely manner. 2.1.2.1 Inspection at the work field As a rule, the inspection interval must be every work shift. Walkaround inspection of the boiler main unit parts and boiler auxiliary devices is carried out. The inspection results must be kept. If any problem symptom is observed, it is necessary to grasp any status change as time elapses. Generally, walkaround inspection is carried out according to the checklist. In addition to this inspection, further inspection points, such as unusual noise, unusual odor, or discoloration must also be inspected. The combustion status inside the furnace must also be checked during walkaround inspection. However, if the type of coal to be used is changed, the inspection must be carried out with special attention.One of the points to inspect the status of clinker and ash sticking to each heat transfer surface inside the furnace is to check whether or not excessive development or accumulation exists. The other point is that the contamination status of each heat transfer surface is checked with the secular change in the operation data stated on the next page to appropriately operate the soot blower or wall deslagger. When the type of coal to be used is changed, these points become particularly important. 2.1.2.2 Sampling and evaluation of operation records To grasp the secular change in the boiler static characteristics and to evaluate performance, records of the boiler operated at its rated output are sampled periodically. In daily operation, it is basically checked whether or not the balance among the feed water flow rate, fuel flow rate, and air flow rate is correct. As deviation of the boiler input command to the output command and deviation of the water/fuel ratio and air/fuel ratio are checked, it is possible to judge whether or not the balance is correct. Additionally, it must be strongly attempted to check changes in the make-up water quantity in order to find any boiler tube leak in the early phase. In the coal-fired boiler, the characteristics of the boiler may change greatly according to the coal properties. The heat absorption distribution of the furnace, SH, and RH is changed according to the combustibility of the coal or slagging/fouling ability. According to the contamination degree of the heat transfer surface, the exhaust gas temperature increases and it adversely affects the boiler efficiency. Therefore, the heat absorption status of each heat transfer surface is grasped by checking the following points. x Changes in control parameters using the RH temperature control or SH temperature control x Changes in the gas temperature of each part of the rear gas duct including the gas temperature at the outlet of the ECO. The soot blower and wall deslagger can be operated at efficient intervals. Since changes in coal properties may affect the characteristics of the exhaust gas (NOx, unburned matter in ash, etc.), it is necessary to grasp the characteristics if the type of coal to be used is changed. If an imbalance occurs in the metal temperature distribution of each part of the furnace, SH, and RH or in the steam temperature distribution of each part of the SH and RH, it is thought that changes in combustion status may be the cause. Therefore, it is necessary to check the damper opening of the wind box at the work field. Since an increase in the AH differential pressure may greatly affect the drive power of the ventilating equipment or the operation tolerance, it is important to grasp the secular change. Normally, the AH soot blower is operated at intervals of work shifts (three times/day). If the AH differential pressure increases, appropriate measures to shorten the interval are taken. 15If the AH differential pressure becomes excessively large (normally, the reference level is the planned value multiplied by 1.5) or if the ventilating equipment capacity reaches its limit, it must be investigated whether to water wash the AH. For the pressure loss of the water and steam systems (particularly pressure loss of the furnace), the increased speed caused by the secular change is grasped and it is used as a factor to judge the chemical washing timing, etc. 2.1.2.3 Others It is important to strictly control the water quality during boiler operation including startup according to the standard for water treatment. 2.1.3 Auxiliary units of the boiler Generally, the auxiliary units of the boiler are the feed water, ventilation, and fuel systems. This section describes the ventilating equipment, air preheater, and coal pulverizer of the coal-fired boiler plant. 2.1.3.1 Ventilating equipment In the coal-fired boiler, a balanced air ventilation system is generally utilized to achieve the following purposes. 1) The furnace pressure is maintained at a constant level to maintain combustion stability. 2) The furnace pressure is maintained at atmospheric pressure or lower in order to prevent coal ash from leaking outside. A centrifugal type or an axial flow type ventilating equipment (fan) is utilized. The control system of the centrifugal ventilating equipment is the inlet damper control, inlet vane control, RPM control, or a combination of them. The control system of the axial-flow ventilating equipment is the moving blade variable control, inlet vane control, RPM control, etc. With these controls, the process values for an object are controlled. The following lists up cautions operation. Axial flow type: According to the characteristics of the ventilating equipment, there is a surging area. If the operation point enters this surging area, the pressure and gas volume are changed rapidly accompanied by vibration, causing damage to the unit. Centrifugal type: There is no clear operation impossible area as described for the axial flow type. However, the operation may become unstable in a low-load area, causing vibration or noise of the duct. (1) Induced draft fan (IDF) This fan is intended to keep the furnace pressure at a constant level of atmospheric pressure or lower. To prevent wear caused by coal ash, a dust removal equipment (EP, etc.) is installed downstream. Basically, the PID control is used to control the furnace pressure. In many induced draft fans, the air flow rate signal is used as an advance signal. (2) Forced draft fan (FDF) This fan is intended to feed the combustion air (secondary air) to the boiler. The air flow rate for combustion is controlled by the combustion volume command from the boiler control unit and the correction signal from the O2 control of the exhaust gas at the outlet of the boiler. When two systems, that is, the ventilation system and air pre-heater, are installed in the boiler, the IDF is interlocked with the FDF in the same system. There are many examples where the other fans are also stopped if one fan is stopped. This interlock is intended to prevent overheating of the gas temperature at the outlet of the air pre-heater and decreasing in the air temperature at the outlet since an imbalance occurs between the air volume and gas volume passing through the air pre-heater if the IDF or FDF is stopped. (3) Primary air fan (PAF) This fan is intended to feed the air (primary air) used to transfer the coal from the coal-pulverizing machine to the burner. I.16Fig. 9 Cold primary air systemFig. 10 Hot primary air systemBoilerBoilerGasSecondaryairMillPrimary airMillMoving vane autooperation commandof B-induction fanA-air pre-heaterstartupB-air pre-heaterstartupMoving vane ofA-induction fan fullyclosedA-induction fan startupAuto operation ofmoving vane ofA-induction fanMoving vane ofA-induction fan fullyclosedMoving vane autooperation commandof A-induction fanA-forced draft fanstartupAuto operation ofmoving vane ofA-forced draft fanMoving vane ofB-induction fan fullyclosedMoving vane autooperation commandof A-forced draft fanB-induction fan startup60s 60sAuto operation ofmoving vane ofB-induction fan Moving vane ofB-forced draft fanfully closedMoving vane autooperation commandof B-forced draft fanB-forced draft fanstartupAuto operation ofmoving vane ofB-forced draft fanVentilation systemstartup completion60sFig. 11 Example of ventilation system startup sequenceMoving vane ofA-induction fan fullyclosedA-inductionfan stopA-forced draft fanstop30sMoving vane ofB-induction fan fullyclosedMoving vane ofB-forced draft fanfully closedB-inductionfan stopVentilation systemstop completionB-forced draft fanstopMoving vane ofA-forced draft fanfully closedFig. 12 Example of ventilation system stop sequenceThe primary air also has the purpose of drying raw coal to allow easy pulverizing of raw coal to be loaded into the coal-pulverizing machine in addition to the purpose of transferring the pulverizedcoal.The primary air temperature at the inlet of the coal-pulverizing machine is 180qC to 250qC. Thefan installation places and the number of fans to be installed in the cold primary air system are different from those of the hot primary air system. In the cold primary air system, one or two fans are installed on the upstream side of the airpre-heater regardless of the number of coal-pulverizing machines. This fan is intended to controlthe primary air duct pressure. On the other hand, in the hot primary air system, one fan specificto one coal-pulverizing machine is installed on the downstream side of the air pre-heater. This fanis intended to control the primary air flow rate. Figures 9 and 10 show an outline of each system. Additionally, Figs. 11 and 12 show examples ofthe startup sequence and stop sequence of the ventilation system, respectively.2.1.3.2 Air pre-heater (GAH)This air pre-heater is intended to increase the combustion air temperature and to collect the heat of the exhaust gas at the outlet of the boiler. Generally, a regeneration-type air pre-heater isutilized where hot gas and air are alternately made to contact the heat transfer materials calledelements to exchange the heat. There are two kinds of systems available: the Ljungstrom systemin which the elements are rotated, and the Rothemuhle system in which the elements are fixed and an air duct called a hood is rotated. Figures 13 and 14 each show GAH, respectively. Normally, the GAH is separated into two sections, that is, thehot gas-passing section and the combustion air-passing section.In the coal-burning boiler with the cold primary air system, the air side is separated into the primary and secondary sections. The following describes cautions on operation of the regeneration-type air pre-heater.1) Air leakCenter section onhigh-temperature side 17In the regenerative air pre-heater, air leaking to the gas side cannot be avoided due to its structure.Fig.13 Example of Ljungstrom-type GAH Fig. 14 Example of Rothemuhle-type GHA Sector plate on high-temperature side Primary air outletGas inlet Guide bearing Secondary air outletLubricant circulationunitSoot blower on high-temperature side Sensor drive unitRotor drive unitHeating elementSoot blower on low-temperature sideMain pedestalSide pedestalConnecting ductRotorPin rack GasoutletCenter section on low-temperature sideRotor post Secondary air inletPrimary airinletSupport bearingSecondary air outletGas inletPrimary air outletCollar sealSoot blowerPrimary air hoodSealing frameSecondary air hoodStator Hood drive unitHeat transfer surfacePin rack Main shaftSecondary gas outletPrimary gas outletPrimary air inletSecondary air inletRotation unitI.18lement diameter also becomes large. Additionally, ssively narrow, the seal mechanism may make 2) -temperature part of the element decreases to a level close to the sulfuric acid 3) terials (used cables at the factory, wood chips, soot including unburned matter, etc.) ntion should be taken since past cases also occurred while these two timings. ment. . ures if a fire occurs in the GAH. 2.1.3.3 Coal-pulverizer (Mill) igned to pulverize coal to a fine particle size diameter necessary to burn itr mal mills. The mill is composed of a duct, damper, prolume is adjusted by changing the feed coal volume to be loaded into th cycle, after the temperature inside the mill has been lowered, the coal feed is Therefore, it is required to adjust the seal appropriately. Recently, as the capacity of the unit becomes large, the ethe thermal deformation volume becomes large. The leak volume cannot be suppressed by the fixed seal. Therefore, an automatic seal adjustment unit is installed. If the air leak volume is too large, its necessary to be cautious that the FDF, PAF, and IDF are overloaded. Additionally, if the gap of the seal mechanism is made excecontacts, causing current value hunting or overload of the GAH motor. GAH differential pressure If the temperature at the lowdew point, ash and SO3 chemical compounds are accumulated and the element is blocked. Additionally, as the operation time elapses, the GAH differential pressure increases. It is difficult to remove the ash andSO3 chemical compounds by the soot blow. Therefore, water washing is needed. It is very important to always keep the temperature of the low-temperature part over appropriate temperature level or more. (The temperature is controlled by the steam type air pre-heater.) Fire of GAH element If any combustible maexist on the GAH element, a fire may occur due to the oxygen concentration and atmospheric temperature. The risk of fire is the highest when a boiler with high oxygen concentration is started up or during boiler banking. Great atteThe following describes fire prevention measures. 1) No combustible materials shall be put on the ele2) The element shall always be kept clean by the soot blowAdditionally, it is also important to establish operation procedThis coal-pulverizer is des by the burner. Generally, this machine is called mill. In the coal-burning boiler, this mill is one of the important auxiliary units that greatly affect the operation characteristics of the plant. The mill is classified into two types of the coal-pulverizing method, that is, the vertical mill (rolleill, etc.) and the horizontal mill (tube mill, etc.). Figures15 and 16 show overall diagrams of typicimary air chamber, seal unit, pulverizing unit, separator, pyrite emission unit, and pulverized fuel pipe. In any mill, raw coal is dried, pulverized, coarse grain is separated, and transferred continuously inside the mill. Generally, the combustion ve mill in the vertical mill. Additionally, the combustion volume is controlled by changing the primary air flow rate passing through the mill in the horizontal mill. In the horizontal mill, the feed coal volume is controlled to keep the coal seam level inside the mill drum at a constant level. The following describes cautions on operation. 1) Remaining coal stop In the normal mill stopstopped and the coal remaining inside the mill is purged in that order. 19Pulverized coal outletCoalfeedportMotor for rotary classifierRotary classifierHousingReject chuteCoal feed pipeRoller pressurizing unitRollerTable segmentPrimary air portTablePrimary air inletMotorSpeed reducerFig. 15 Example of vertical mill (Roller mill)Fig. 16 Example of horizontal mill (Tube mill)If the mill is stopped in case of an emergency, the above steps cannot be performed correctly. Pulverizedcoal and raw coal exist inside the mill in relatively high-temperature status. Therefore, great caution shallbe taken since nature conservation or mill explosion may occur. This risk increases as the volatilecomponents included in the raw coal are large.To prevent a fire inside the mill or to extinguish a fire, inert gas (inert steam) injection equipment orfire-extinguishing water injection equipment are often installed. It is necessary to establish procedures if the mill is stopped in case of an emergency.2) Mill motor overloadWhen using coal (coal with low HGI) with poor grindability in the roller mill, the mill motor may be Primary air inletPulverized fuel pipeCoal feed pipePulverized fuel pipeCoal feedpipe Pulverizedcoal outletCoarse grain separatorMotorMill drumI.overloaded. In this case, the coal feed volume needs to be limited.3) Temperature at mill outletIf surface moisture of raw coal that is stored in an outdoor coal yard is high due to rain or other factors, raw coal drying, pulverizing, and transfering processes are not performed smoothly. As a result, an accidentoccurs which the inside of the mill is filled with coal. This phenomenon occurs if the mill differentialpressure increases. (In the tube mill, the current value of the mill motor is lowered.)In the initial indication, it is shown that the temperature at the mill output is decreased.If the temperature at the mill output decreases excessively and it cannot be maintained, appropriatemeasures are needed to limit to the coal feed volume.4) A/CThe weight ratio of the primary air volume that is the air for transfer of the pulverized coal to thepulverized coal volume is called A/C (Air/Coal). Generally, the mill is operated at an A/C range of approximately 1.8 to 3.0. If the A/C becomes high (the concentration of the pulverized coal is thin), thenaturalness of the pulverized coal is lost, causing an accidental fire.Recently, a burner that allows stable combustion even though the A/C is high is put into practice.However, if the A/C becomes high when using a burner other than such a burner, it is necessary to performcombustion aid using the pilot ignition burner.5) Flow velocity inside the pulverized coal pipeThe flow velocity inside the pulverized coal pipe from the mill to the burner shall satisfy the followingconditions.1. This flow velocity shall be the flame propagation velocity. (The flame propagation velocity is determined by the A/C and the volatile components included in the coal.)2. This flow velocity shall be faster than the level at which pulverized coal is not subsided or accumulatedinside the pipe.3. This flow velocity shall be slower than the level at which the inside of the pipe wears out.Therefore, a velocity ranging from 18 to 30 m/s is generally used. The flow velocity inside the pipe isalmost determined by the primary air flow rate. However, the primary air flow rate shall not beexcessively decreased.20Pilot ignitionburner ignitionCool air damper openHot air damper closedAll mill outlet dampers open/Mill seal air damper openPrimary air shut-off/Regulation damper openMill warningSeal differential pressure/Primary air volume/Waiting for milltemperature conditions satisfiedMill motor startupCoal supplyvolume abovespecified valueCoal feeder startupMill outlettemperature abovespecified valueInitial coal feed completionPilot ignition burnerfire-extinguishing commandLubricant unit startupRotary classifier startupRoller pressurizing unitstartupCoal gate openMill systemstartupMill system startupconditions satisfiedAuto operation of coal feederSSMill stop coal feed volumePilot ignition burnerignitionCoal gate close/Coal feeder stop Mill purgeMill motor/roller pressurizing unit/rotary classifier stopPrimary air shutoff/Regulation damper close All mill outlet damperscloseMill inlet seal air damper closeCool air damper openHot air damper closedMill inlet temperaturebelow specified valueMill outlet temperaturebelow specified valuePilot ignition burner OFFMill system stopFig. 17 Example of vertical mill startup Fig. 18 Example of vertical mill stop Since the combustion volume rather than the primary air volume is controlled in the horizontal mill, theauxiliary air damper is opened to keep the minimum flow velocity inside the pipe if the flow velocitydecreases.6) Coal feed volume and coal consumption volumeWhen the mill is operated at a constant load, a relationship is established in which the coal feed volume is equivalent to the coal consumption volume (combustion volume). However, this relationship is notestablished when the mill is started or stopped or when the mill load varies.Precise grasping of the combustion volume is an essential condition for boiler control. In particular, it is21absolutely necessary to control the steam temperature in the once-through boiler. Generally, the combustion volume is measured by the coal supply machine. However, when the mill is started up, the coal supply start does not meet the coal consumption start. In the control system, when the mill is started up or stopped, the simulated coal consumption signal is used as combustion volume in order to adjust the coal consumption close to the coal consumption characteristics suitable for actual conditions. The coal consumption characteristics may vary depending on the type of coal. Changes in steam temperature and exhaust gas O2 may occur when the mill is started up or stopped. Therefore, these points must be taken into consideration. 7) Mill pyrite Rocks or other foreign objects other than the raw coal supplied to the mill are discharged to the outside of the mill without being pulverized. These discharged foreign objects are called pyrites. In the horizontal mill, such foreign objects are not discharged to the outside and they are accumulated as materials for pulverizing. In the vertical mill, pyrites are snapped from the primary air port inside the mill to the primary air chamber, and then they are discharged to the outside. If this processing unit malfunctions, pyrites and coal are accumulated in the primary air chamber. As a result, a fire may occur by the hot primary air. Therefore, it is important to check that the pyrite-processing unit functions correctly. According to the circumstances, the mill needs to be stopped. Figures 17 and 18 show examples of the vertical mill startup sequence and stop sequence. 2.2 Power Supply Operations Electric power demand is not always constant and it varies greatly depending on the season or time zone. Since the daily electric power demand varies as time elapses as shown in the daily load curves stated in Fig. 27,it is necessary to supply electric power corresponding to the demand that varies every moment.Additionally, since the economy and followingness of each power generation method differ from each other, it is also necessary to generate electric power with an appropriate combination of power generation methods bytaking their features into consideration. When the daily load is classified into the base load, middle load, andpeak load, each load is classified into the relevant power generation method as described below.Pumping-up hydraulic powerAdjustablehydraulicpowerPeakPumping-uphydraulicpower(Electric power)Oil fired power(Energy)MiddleLNG fired powerBase22Fig. 27 Example of daily load curves and combination of power generation methods by time zone(1) Base load Since the variation in load is small and the utilization factor is high, large capacity thermal power, nuclearpower, and run-off-river hydraulic power, which can be operated continuously for an extended period of time and has an excellent efficiency, are operated.(2) Middle load This middle load has intermediate characteristics between the base load and peak load. Since electric energylarger than that of the peak load is required, the middle capacity thermal power, which is relatively economicaland has excellent start/stop characteristics, is used.(3) Peak load Since the load varies greatly in the peak load range, the excellent adjustment capability of electric power generation and frequent start/stop ability are required.Additionally, it is necessary that the operation time is short and the utilization factor is small.Therefore, even though the efficiency is slightly sacrificed, pondage type hydraulic power or reservoir typehydraulic power having less construction cost, or pumping-up hydraulic power or gas turbine having excellentpeak characteristics can be operated.The following describes the typical operation method of a thermal power plant during daytime and nighttime.2.2.1 Output adjustment by load dispatching operation Since the electric power demand is changed every moment as described previously, it is necessary to supplyelectric power corresponding to this demand. Since changes in electric power demand cannot be adjusted byhydraulic power alone, it is also necessary to adjust the output using the thermal power generation plant. Theoperation is performed using the following auto control together with the output adjustment based on the powersupply command.(1) Automatic frequency control (AFC) The system frequency varies due to an unbalance between electric power generation and demand. Therefore,the generator output is adjusted so that the frequency of the electric power system is kept within the specifiedvalue.(2) Economical load dispatching control (ELD or EDC) The load is dispatched so that the general power generation cost for each power generation unit becomes the (Time)Run-off-riverhydraulic powerCoal fired powerNuclear power23lowest price. 2.2.2 Minimum load operation As nuclear power generation is used for the base load operation to the daily electric power demand, the minimum load operation of the thermal power plants is conducted to adjust the supply capacity to the electric power demand during daytime and nighttime. Therefore, this minimum load operation becomes important, as well as stop operation during nighttime. In particular, it is required to enable lower minimum load operation of a large capacity plant and to improve the power generation efficiency in a low load area. The minimum load may vary depending on the fuel, capacity, main machine, and/or auxiliary machines of the plant. However, the minimum load is generally 10 to 40% of the rated output. The following describes the typical subjects and considerations related to the turbine during minimum load operation. (1) Steam flow rate If the steam flow rate decreases, a local overheating problem occurs due to an unbalance of the flow rate between the boiler overheating unit and reheater. Therefore, the steam temperature, gas temperature, and evaporation tube wall temperature need to be considered. In the case of a once-through boiler, it is necessary to keep a supply water volume of 25 to 30% or more of the maximum evaporation volume in order to ensure the stable flow inside the evaporation tube constituting the water wall of the furnace. (2) Wetness of turbine exhaust chamber If the reheating steam temperature drops or the vacuum degree of the condenser increases during low-load operation, the wetness of the exhaust chamber may increase. Since this wetness may corrode the vane in the final stage of the low-pressure turbine, it is absolutely necessary to conduct the operation by taking the wetness into consideration. (3) Temperature of turbine exhaust chamber The vacuum degree of the condenser tends to be high during low-load operation. This may cause the temperature of the exhaust chamber to lower and adversely affect the vibration and differential expansion. Furthermore, the steam flow rate may decrease at an extremely low output ranging from 5 to 10% of the rated output. Therefore, the temperature of the turbine exhaust chamber may increase due to windage loss. Generally, to prevent this problem, the water is continuously sprayed into the exhaust chamber to decrease the temperature. However, the continuous water spray may corrode the vane at the final stage. Therefore, great care should be taken for this point. (4) Drain control of feed water heater The drain from the feed water heater must be collected to the feed water heater at the lower stage as much as possible in order to improve the thermal efficiency. Therefore, the pressure inside the feed water heater decreases in the low-load operation area and the pressure difference inside each feed water heater decreases. If the pressure difference inside the unit among the feed water heaters decreases, it becomes difficult to discharge the drain to the feed water heater at the lower stage. To prevent such a problem, great care should be taken, such as switching of the collection destination to the condenser, etc. (5) Control of boiler feed water pump Since the supply water flow rate decreases during low load operation, the discharge flow rate of the boiler feed water pump also decreases. If the supply water flow rate of the boiler becomes less than the re-circulation flow rate of the pump, the operation enters a status whereby the minimum flow rate of the pump is maintained by the re-circulation control valve. Therefore, great care should be taken since the control valve is damaged if the pump is operated for an extended period of time in the above status. Additionally, when using the turbine driven feed water pump, great care should be exerted so that the pump is not operated at a speed close to its critical speed.2.2.3 Leading power factor operation In recent power systems, as the capacity of the extra-high voltage power transmission line or power transmission line increases and the difference in generated power during daytime greatly differs from that during nighttime, the leading power factor operation of the reactive power control is conducted so that the operation is performed by changing the tap of the inductive phase modifying equipment (reactor or synchronous phase modifier) or by operating the synchronous generator using the advancing power factor. The leading power factor operation of the generator means that the field current of the generator decreases by utilizing the characteristics of the synchronous machine and the operation is performed using the advancing power factor to absorb the reactive power of the power system. The following describes the problems and notes when performing the leading power factor operation of the generator.(1) Stability drop due to low excitation When the leading power factor operation is performed, the internal induced voltage becomes small.As a result, the internal phase angle increases and synchronizing power decreases, causing the stability to lower.The stability is determined by the terminal voltage and reactance of the generator, as well as the externalimpedance. Therefore, when performing the leading power factor operation, it is necessary that the underexcitation limit (UEL) of the automatic voltage regulator (AVR) is set at a position where both the allowable limitby the possible output curve of the generator and the static stability limit of the system are satisfied to prevent theloss of synchronism.(2) Temperature increase of iron core and mechanical part If the leak magnetic flux entering the iron core end part of the stator increases, the temperature increases due tothe eddy current induced by the elements making up the iron core end part. Therefore, even though the statorend part of the turbine generator uses a structure that suppresses the temperature increase, it is necessary toconduct the operation with the possible output curve area of the generator by taking changes in the stator iron coretemperature, stator coil temperature, and cooling gas temperature into consideration.Figure 29 shows an example of the generator output curve.24Curve AB: Limited by magnetic field temperature. Curve BC: Limited by armature temperature.Curve CC: Limited by armature iron core end temperature.DelayReactive power [pu]Active power (pu)Under excitation limit (UEL)AdvanceFig. 29 Generator output curve2.3 Start-up and Stop Operation Control2.3.1 Start pattern Electric power demand changes not only throughout the year, but also weekly and daily.A thermal power unit start or stop in order to adjust its output to flexibly correspond to changes in power demand.The unit has the following start patterns from unit stop to unit start.(1) Cold start The unit is started after it has been stopped for an extended period of time, such as for periodic inspection.(2) Weekly start and stop (WSS)In WSS, the unit is stopped at nighttime on a Friday or on a Saturday when the electric power demanddecreases, and then it is started early on Monday morning when the electric power demand starts increasing. The stop time is 12 to 36 hrs. Figure 2 shows an example of this schedule.OutputMain steamtemperatureMain steampressure25Fig. 3 Daily start and stop scheduleFig. 2 Weekly start and stop schedule(3) Daily start and stop The unit is stopped at midnight, and then started the next morning so that the power generation corresponds todifferences in electric power demand between daytime and nighttime. The stop time is from 6 to 12 hrs. Figure3 shows an example of the daily start and stop schedule.This daily start and stop is necessary because efficient operation of the power system is achieved by increasingthe base load units, such as nuclear or large capacity thermal power generation.In this daily start and stop operation, the adverse effects on the unit service life and supply reliability should beconsidered. In the first case, thermal stress on the turbine rotor is a particularly problem.IgnitionParallel-offStartParallelOutputMain steamtemperatureMain steampressureParallel-offParallelIgnitionStart26(This thermal stress is caused by d es eam and turbine rotor when the unitisroblems, it is necessary to take appropriate measures, such as improvement of the unitre used to restart the unit after it has been stopped for a short time (about less than 6 hrs.) due tosydiately before the trip. However, sinceth.3.2 Starting of unit tline of the start steps of the coal burning supercritical pressure voltage transformationonhe unit is determined by the boiler or turbine status. As described inTaed on the start timereifferenc in temperature between the ststarted. Normally, this temperature difference is called mismatch temperature.) According to the low cyclefatigue index (LCFI) of the turbine rotor, the number of yearly start and stop cycles is limited to take measuresagainst this problem. In the second case, the start and stop time is short and the operation reliability needs to bekept at a high level.To solve these pliability, omission of operation steps, and/or review of standards.(4) Quick start This quick start isstem problems or power control. Normally, the quick start is called very hot start.In this case, the thermal stress of the turbine requires special attention.The metal temperature of each part meets the steam temperature immee boiler and piping after restarting are cooled as the stop time elapses, the steam temperature is mismatched with the metal temperature due to decrease of the steam temperature and throttle of the control valve. Therefore, it ispreferable that the steam temperature is increased to a high temperature level and the speed is increased rapidly,and the parallel and load are increased.2Figure 4 shows an ouce-through plant. The following describes the operating procedures and provides notes on each start step.(1) Determination of start schedule The period of time required to start tble 1, the unit start mode is determined by the metal temperature at the first stage of the turbine. As the timerequired for each event is added, the overall time required for the start process is calculated.In the start schedule, the parallel schedule time is determined to the base point. Basquired described above, the schedule time, such as boiler ignition, turbine start, and full load achievement isdetermined.Fig. 4 Unit start steps (Cold start)Water quality check Main steam pressureRPMOutputPreparations for unitstartCondensed water cleanupand vacuum increaseLow-pressure cleanupHigh-pressure cleanupBoiler cold cleanupPreparationsfor boiler ignitionBoiler ignitionBoiler hot cleanupTemperature increase/pressure increasePreparations for turbine startTurbine start/speed upPreparations forparallelCoal charging startBFP M/T change-overWet/dry change-overParallel/outputincrease 1Outputincrease IIOutputincrease IIIVoltage transformation startCoal single fuel firingWater quality checkPower supplydistribution27Table 1 Example of start modes Start type Item UnitVery hot start (Stopped for 2 hrs.) Hot start (Stopped for 8 hrs.) Warm 2 start (Stopped for 32 hrs.)Warm 1 start (Stopped for 56 hrs.) Cold start (Stopped for 150 hrs.) Metal temperature at 1st stage qC 460 - 390 460 340 390 230 340 - 230 Main steam pressure MPa 8.5 8.5 8.5 8.5 8.5 Main steam temperature qC 510 470 410 410 400 Reheating steam temperature qC 505 480 377 289 200 Steam temperature at 1st stage qC 438 391 315 315 301 Metal temperature at 1st stage qC 494 453 368 326 216 Planned values at start Mismatch temperature qC -56 -62 -53 -11 +85 Turbine speed up ratio rpm/min. 300 300 150 150 100 Low-speed heat soak time min. 0 0 0 0 20 High-speed heat soak time min. 0 0 0 0 55 Initial load volume % 3 3 3 3 3 Initial load holding time min. 0 0 15 15 60 The boiler start mode is determined by the fluid temperature at the inlet of the water separator, and it is then used for the fuel program for start or start by-pass valve control. (2) Preparations for unit start Inspect and check each part so that the work during unit stop is completed and there is no obstacle hindering the start.Confirm that units related to common facilities are being operated correctly or that they are ready for operation. Confirm that the interlock, alarm device, and monitoring instrument function correctly, and that the fuel and demineralized water necessary to start are maintained. (3) Pre-boiler cleanup In the once-through boiler, it is necessary to supply high purity water from the start. Therefore, cleanup is carried out to remove impurities (particularly, iron content) from each system prior to the ignition. In the pre-boiler cleanup, the vacuum in the condenser is increased, and then the condenser system, low-pressure supply water system, and high-pressure supply water system are cleaned up from the upstream side in order. In each system, the circulation operation is carried out through the condensate demineralizer so that the water quality becomes the standard value or less after the standard to pass the water to the condensate demineralizer has been satisfied using the blow outside the system. Additionally, the turning operation of the turbine is performed to prevent deflection of the turbine rotor before increasing the vacuum. (4) Boiler cold cleanup When the water quality in the pre-boiler satisfies the boiler passing water standard, the water is fed to the boiler to perform the cleanup at a normal temperature. Table 2 shows the water quality standard when the once-through boiler is started. After the boiler has been filled with water (this work is not needed when the boiler filled with water has been stored), the blow outside the system is performed through the drain system of the water separator. After the water quality of the blow water has satisfied the standard for the water passed to the condensate demineralizer, the circulation operation is performed until the water quality is the standard value or less through the condensate demineralizer. (5) Preparations for boiler ignition The supply water system is changed from the cleanup status to the boiler ignition status. The ventilation system is started to purge the furnace. The remaining unburnt gas is purged at a specified air flow rate for a specified period of time in order to prevent explosion in the boiler furnace. (Example, 30% MCR flow rate for 5 min.) The fuel system for start (oil or gas) is started up to check the system for leak. Generally, light oil is used for the start. (Note) Cleanup is essential for a cold start. The cleanup is usually omitted for the WSS or DSS start. The operation often enters the ignition preparations from the low-pressure cleanup circulation status during unit stop. (6) Boiler ignition and hot cleanup After the boiler has been ignited, the temperature is increased to the target temperature of the hot cleanup (fluid temperature at the outlet of the furnace is approx. 150qC.). The temperature is kept at this cleanup target 28temperature. If the water quality becomes the standard value or less, the temperature increase is restarted. (7) Temperature increase and pressure increase The temperature increase and pressure increase of the boiler are performed to achieve the steam conditions at turbine start determined by the turbine start mode. By adjusting the fuel charging volume, the start bypass valve and drain valve in the steam system, the temperature increase and pressure increase are completed within the target time. The feed water flow rate and air flow rate are controlled to their minimum flow rates. At this time, the re-heater protection (prevention of burning) and the thick wall part protection (relaxing of thermal stress) exist as limitation items when started. The former is limited by the gas temperature at the outlet of the furnace, as well as the fuel charging volume. The latter is limited by the temperature increase ratio at the inlet of the water separator and the outlet of the super heater. (8) Preparations for turbine start In the cold start, the metal temperature of each turbine part decreases to a level close to room temperature. When starting the turbine in this status, thermal stress occurs as a result of the difference in temperature when compared to the steam. Table 2 Water quality at starting of once-through boiler (When the volatile substance process applies.) Process Circulation before ignition (Boiler cold cleanup) Temperature increase/pressure increase circulation (Boiler hot cleanup) Load operation [1/2MCR (42) or less] Class Max. operating pressure (MPa) Greater than 15 and 20 or lessGreater than 20Greater than 15 and 20 or lessGreater than 20Greater than 15 and 20 or lessGreater than 20pH (at 25qC) 8.5 9.6 (19) 9.0 9.6 8.5 9.6 (19) 9.0 9.6 8.5 9.6 (19) 9.0 9.6 Electric conductivity (mS/m) (11)(19) (at 25qC)(PS/m) (11)(19) (at 25qC)0.1 or less 100 or less 0.1 or less 100 or less 0.1 or less 100 or less 0.1 or less 100 or less 0.1 or less 100 or less 0.1 or less 100 or lessDissolved oxygen (PgO/l) 40 or less (36) 20 or less (38) 10 or less 10 or less 7 or less 7 or less Iron (PgFe/l) 200 or less 100 or less 100 or less 50 or less 30 or less 30 or less Copper (PgCl/l) 20 or less 20 or less 20 or less 10 or less 5 or less 5 or less Hydrazine (PgN2H4/l) 20 or more (38) 20 or more (38) 20 or more 20 or more 10 or more 10 or more Economizer inlet Silica (PgSiO2/l) 30 or less 30 or less 30 or less 30 or less 30 or less 30 or less Electric conductivity (mS/m) (11)(19) (at 25qC)(PS/m) (11)(19) (at 25qC)0.1 or less 100 or less 0.1 or less 100 or less 0.1 or less 100 or less 0.1 or less 100 or less ----Feed water Furnace water wall outlet Iron (PgFe/l) 300 or less 300 or less 200 or less (40) 100 or less (41) - -Note (38) This value becomes the target according to the boiler shape. (39) When starting the unit after it has been stopped for a long period of time, it is preferable to adjust the hydrazine concentration to a higher level in order to promote forming of a protective coat inside the system. At this time, the hydrazine is dissociated in the water and it exists as the hydrazinium ion (N2H5+). (40) The target concentration of the iron is 100PgFe/l or less. (41) The target concentration of the iron is 50PgFe/l or less. (42) This shows an abbreviation of the maximum continuous rating that means the maximum continuous load. To reduce this thermal stress, the