&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
EPA-600/7-78-210
November 1978
SO2 Abatement for
Stationary Sources
in Japan
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide-range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-210
November 1978
SO2 Abatement
for Stationary Sources in Japan
by
Jumpei Ando
Chuo University
Tokyo, Japan
Contract No. 68-02-2161
Program Element No. 1NE624
EPA Project Officer: J. David Mobley
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ACKNOWLEDGEMENTS
The author wishes to acknowledge the assistance of
Teresa Sipes and Gary Jones of Radian Corporation, Austin, Texas
in editing this report. In addition, Radian Corporation's
typing and graphics support is gratefully acknowledged. (Radian
Corporation's work was provided by EPA under contract number
68-02-2608, Task 29.)
The project officer wishes to acknowledge the support
of R. Michael McAdams and Michael A. Maxwell of EPA's Industrial
Environmental Research Laboratory at Research Triangle Park, NC
in reviewing this report.
ii
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INTRODUCTION
This report is 4th in a series of reports on Japanese
S02 control technology authored by Dr. Jumpei Ando. Previous
reports are listed below.
EPA-R2-73-229 1973
EPA 600/2-76-013a 1976
EPA 600/7-77-103a 1977
<
Japan has stringent S02 emission and ambient air stan-
dards that have resulted in the development of S02 control tech-
nology. The primary control methods currently being practiced
in Japan are flue gas desulfurization (FGD) and burning of low
sulfur fuels. The total FGD capacity for the country exceeds
100,000,000 Nm3/hr (33,000 MW equivalent). Abouc 70 percent of
this flue gas is derived from oil-fired boilers with the remain-
der coming from iron ore sintering operations, smelters, coal-
fired boilers and other sources. Japan's program to limit S02
emissions has resulted in a significant reduction in ambient air
concentrations.
In the United States, there is similar concern over
S02 emissions. As a result, the U.S. Environmental Protection
Agency (EPA) and Congress have promulgated S02 emission regula-
tions for a variety of sources. As in Japan, the most near-term
solution is FGD. FGD technology development has proceeded in
the U.S. parallel to the development effort in Japan and is con-
tinuing in both countries.
iii
-------
The purpose of this report is to aid the U.S. develop-
ment of SO2 control technology by presenting information on the
current status and recent developments of the Japanese develop-
ment efforts. Regulations, clean fuel production technology and
flue gas treating systems are all discussed, but the emphasis is
on FGD systems. The information presented represents the most
recent information as of March 1978.
iv
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CONCLUSIONS
The recent remarkable progress of FGD in Japan was
induced by the following particular circumstances:
1) The serious air and water pollution problems
which occurred in the 1960s aroused severe pub-
lic criticisms and resulted in the most stringent
regulations on pollution.
<
2) Prefectural governments have established pollu-
tion control centers and kept an eye on emissions
using telemeter systems for major sources.
3) The central government has assisted industry in
installing pollution prevention facilities by
providing low-interest funds (6-7% per annum as
compared with the usual 8-10%) and by allowing
short-term depreciation for the facilities--?
years in most cases and two years in special
cases.
4) Most FGD plants were constructed between 1968
and 1974, when the Japanese economy was growing
rapidly at an annual rate of over 10%. Therefore,
although the total investment for S02 control,
including FGD and hydrodesulfurization of oil,
exceeded 1 trillion yen (3.7 billion dollars)
at the current value (1977), the investment did
not prove an excessive load to industry.
-------
5) Ammonia scrubbing and lime scrubbing were
already applied in the 1950s to treat tail gas
from sulfuric acid plants. Those techniques
provided the basis for the rapid development in
later years.
6) Japan had a short supply of sulfur and its com-
pounds, which created a market for most of the
FGD by-products. Use of oil as the major fuel
has favored the recovery of high purity salable
by-products.
Under such circumstances, over 1,000 commercial FGD
plants have been constructed and contributed to the abatement
of ambient SOa concentration. The rapid development, however,
involved the following problems:
1) Major power companies were inclined to use clean
fuels such as low-sulfur oil, naphtha, and LNG.
In the early years, FGD was used mainly by smaller
fuel consumers who had difficulty obtaining clean
fuels. Numerous small FGD plants were thus
installed. Fortunately most of the smaller
plants employed simple sodium scrubbing to by-
product sodium sulfite, which is useful for paper
mills. However, it would have been much more
rational for the large fuel consumers to apply
FGD and the numerous small ones to use clean
fuels.
2) The choice of clean fuels by the major power com-
panies was prompted by the following considera-
tions :
vi
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a) Doubt as to the reliability of FGD in the
early years.
b) Consideration of the increasingly stringent
regulations, which might make FGD inadequate
in future.
c) Oversupply of by-products.
Among the above considerations, a) has proved to
be groundless fears, but c) has turned out to be
the real problem because of the rapid increase
in the by-products and the limited land space
for disposal of gypsum. Consideration b) will
pose a serious problem if the plants with FGD
systems are required to add facilities for NO
removal by flue gas treatment.
3) FGD removes over 90% of SOa but not as much S03.
It is possible that the emission of "sulfate"
increases through the use of an FGD system with
a poor mist eliminator. Although the ambient
sulfate concentration in Japan has decreased
with SOa concentration, further studies are
needed to increase the SO3 removal efficiency
and to improve the mist eliminator.
4) The Japanese development efforts for FGD tech-
nology have been oriented to achieving high S02
removal efficiency and high reliability to meet
the stringent regulations. Although removal
efficiency and operability of 98-997» each have
been achieved, the plant cost is rather high
for most processes. It is necessary to develop
more economical FGD systems, particularly under
the recent economic depression.
vii
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5) So far gas reheating has been done mainly by
after-burning, which not only consumes much fuel
but also adds to pollution. Further study of
reheating, including that by steam-gas heater
or gas-gas heater, is needed.
The desulfurization efforts in Japan have almost
reached the goal. The SO ambient concentration has almost met
X
the ambient standard, a daily average of 0.04 ppm, which is
equivalent to a 0.017 ppm yearly average and is the most strin-
gent figure in the world.
In the U.S. and West Germany, FGD has been, or will
be, applied mainly for coal-fired boilers.
Although there are not many coal-fired boilers in
Japan at present, all of the FGD plants for the coal-fired
boilers have attained 90-95% S02 removal and over 97% oper-
ability.
The authors hope that the Japanese experiences will
offer useful suggestions for the global efforts for cleaner air.
viii
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CONTENTS
Acknowledgements ii
Introduction iii
Conclusions v
Figures xv
Tables xiv
Conversion Factors and Abbreviations xxiii
1. ENERGY AND ENVIRONMENT 1
1.1 Energy Supply of Japan 1
1.2 Sunshine Project 4
1.3 Sulfur Input in Japan 8
1.4 SO Standards and Regulations 10
PN
1.4.1 Ambient Standard 10
1.4.2 Emission Standards 11
1.4.3 SOV Emission Tax 16
J\
1.5 S02 and Sulfate 17
1.5.1 Ambient Sulf ate Concentration 17
1.5.2 Difference Between the U.S. and Japan in
Ambient Sulfate Levels 22
1.6 Emission and Regulation of NOX 24
1.7 Investment for Pollution Control 27
1.8 Monitoring System for Pollution Control 30
2. OIL AND COAL PROCESSING 33
2.1 Outline 33
2.2 Flexicoking 35
2.3 Eureka Process (Kureha Process) 37
2.4 Cherry Process 41
2.5 Coal-Residual Oil Hybrid Gasification Process.. 43
2.6 Low-Calorific Gasification of Coal 47
ix
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CONTENTS (Continued)
2.7 Other Coal Treating Processes 50
2.7.1 Solvolysis Liquefaction 50
2.7.2 Plasma Gasification of Coal 51
2.7.3 Coal Gasification by the Molten Salt
Lime Slurry Process 53
2.8 Fluidized Bed Combustion of Coal 56
2.8.1 Babcock Hitachi Ltd 56
2.8.2 Kawasaki Heavy Industries 57
2.8.3 Mitsui Engineering and Shipbuilding 57
GENERAL ASPECTS OF FLUE GAS DESULFURIZATION 58
3.1 Major FGD Processes and Plants 58
3.1.1 Status of FGD for Power Companies 60
3.1.2 Status of FGD for the Steel Industry .... 65
3.1.3 Status of FGD for Nonferrous Smelters.... 67
3.2 By-Products 67
3.2.1 By-Product Production and Economics 67
3.2.2 Quality and Use of FGD Gypsum 72
3.3 Wastewater and Its Treatment 74
3.3.1 Wastewater 74
3.3.2 Wastewater Treatment 77
3.4 Mist Elimination 79
3.5 Gas Reheating 82
3.5.1 Reheating by Afterburning 82
3.5.2 Steam-Gas Heating 83
3.5.3 Gas-Gas Heating 83
3.5.4 Cost Comparison of Gas-Gas Heating and
Afterburning 87
3.5.5 Commercial Application of a Ljungstrom
Heat Exchanger for FGD 88
3.6 FGD Operation and Operability 89
3.6.1 Operation of Gas Sources 89
3.6.2 Bypass Systems 90
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CONTENTS (Continued)
3.6.3 Operability 92
3.6.4 Labor Requirements 94
3.7 Economic Aspects 94
3.7.1 Investment Cost 94
3.7.2 Costs of Fuels and Desulfurization 97
4. WET LIME/LIMESTONE PROCESSES 100
4.1 General Description 100
4.1.1 Outline 100
4.1.2 Scale Prevention 107
4.1.3 Wastewater, Power Consumption and
Operability 110
4.2 Operation of FGD Plants for Coal-Fired Boilers.. 114
4.2.1 General Description 114
4.2.2 Takasago Plant, EPDC (Mitsui-Chemico
Limestone-Gypsum Process) 117
4.2.3 Isogo Plant, EPDC (Chemico-IHI Limestone-
Gypsum Process) 125
4.2.4 Takehara Plant, EPDC (Babcock-Hitachi
Limestone-Gypsum Process) 132
4.2.5 Omuta Plant, Mitsui Aluminum 138
4.2.6 Matsushima Plant, EPDC 140
4.2.7 Other Plants 140
4.3 Operation of FGD Plants with MHI Scrubbers for
Oil-Fired Utility Plants 142
4.3.1 Owase-Mita Plant, Chubu Electric (MHI Lime-
Gypsum Process)
4.3.2 Shimonoseki Plant, Chugoku Electric
(MHI Limestone-Gypsum Process) 150
4.4 Operation of FGD Plants with the Moretana
Scrubber 154
4.4.1 Characteristics of the Moretana Scrubber. 154
4.4.2 Kashima Plant, Sumitomo Metal 156
4.4.3 Takaoka Plant, Takaoka Kyodo Power 158
4.4.4 Evaluation 162
xi
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CONTENTS (Continued)
4.5 Operation of Other Major Limestone-Gypsum
Process Plants for Oil-Fired Utility Boilers... 163
4.5.1 Tamishima Plant, Chugoku Electric 163
4.5.2 Karatsu Plant, Kyushu Electric 166
4.6 Operation of the Chiyoda Jet Bubbling Process.. 166
4.6.1 Outline 166
4.6.2 Jet Bubbling Reactor 168
4.6.3 Process Flow Diagram 174
4.6.4 Economics 174
4.6.5 Evaluation 180
5. INDIRECT AND MODIFIED LIME/LIMESTONE PROCESSES 181
5.1 General Description 181
5.1.1 Outline 181
5.1.2 Operability and Economics 186
5.2 Chiyoda Thoroughbred 101 (CT-101) Process 189
5.2.1 Characteristics 189
5.2.2 Operation of Commercial Plants 192
5.2.3 Economics 194
5.2.4 Evaluation 199
5. 3 Sodium Limestone Gypsum Process 199
5.3.1 Outline 199
5.3.2 Ichihara Plant (Chiba Plant), Showa Denko 200
5.3.3 Sakaide Plant, Shikoku Electric 201
5.3.4 Anan Plant, Shikoku Electric 207
5.3.5 Buzen Plant, Kyushu Electric 207
5.3.6 Evaluation 210
5.4 Dowa Aluminum Sulfate Limestone Process 211
5.4.1 Outline 211
5.4.2 Okayama Plant, Naikai Engyo 211
5.4.3 Economics 214
5.4.4 Evaluation 214
xii
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CONTENTS (Continued)
5 .5 Kawasaki Magnesium Gypsum Process 217
5.5.1 Kawasaki Magnesium Gypsum Process 217
5.5.2 Process Description 217
5.5.3 Operation of Commercial Plants 221
5.5.4 Evaluation 223
5.6 Kobe Steel Calcium Chloride Process 226
5.6.1 Characteristics 226
5.6.2 Operation of Commercial Plants 228
5.6.3 Evaluation 233
5.7 Other Indirect Lime-Gypsum Processes 234
5.7.1 Kurabo Acidic Ammonium Sulfate Process... 234
5.7.2 Nippon Kokan Ammonia Lime Process 236
5.7.3 Kureha Sodium Acetate Process 238
6. REGENERABLE PROCESSES 241
6.1 General Description 241
6.1.1 Ammonia Scrubbing 241
6.1.2 Wellman-Lord Process 243
6.1.3 Magnesium and Zinc Scrubbing 244
6.1.4 Sodium Sulfite By-Production 245
6.1.5 Shell Process 245
6.1.6 Activated Carbon Process 246
6.1.7 Operation Parameters of Major Plants 246
6.2 NKK Ammonia Scrubbing Plants 248
6.2.1 Outline 248
6.2.2 Ogishima Plant 248
6.2.3 Fukuyama Plant 254
6.2.4 Evaluation 255
6.3 Nishinagoya Plant, Chubu Electric (Wellman-MKK
Process) 256
',6.3.1 Outline 256
6.3.2 Sulfur Balance 256
xiii
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CONTENTS (Continued)
6.3.3 Performance and Cost 259
6.3.4 Evaluation 261
6.4 Chiba Plant, Idemitsu Kosan (Mistui-Chemico
Magnesium Process 262
6.4.1 Process Description 262
6.4.2 Performance 264
6.4.3 Evaluation 266
6.5 Other Major Regenerable Processes 266
6.5.1 Sodium Scrubbing By-Producing Sodium
Sulfite 266
6.5.2 Shell Copper Oxide Process 267
6.5.3 Activated Carbon Processes 268
6.5.4 Ammonia Scrubbing by Ube Industries .... 269
7. SIMULTANEOUS REMOVAL OF SOV AND NOV 271
X XX
7.1 Outline 271
7.1.1 Problems with NOX and SOX Removal
Processes 271
7.1.2 Comparison of Simultaneous and Combined
Removal Processes 272
7.2 Dry Simultaneous Removal Using Activated Carbon 275
7.2.1 Reactions of Activated Carbon 275
7.2.2 Unitika Activated Carbon Process 278
7.2.3 Activated Carbon Process by Sumitomo
Heavy Industries 281
7.3 Other Dry Processes for Simultaneous Removal... 284
7.3.1 Shell Copper Oxide Process 284
7.3.2 Ebara Electron Beam Radiation Process... 287
7.4 Wet Simultaneous Removal Processes 288
7.4.1 Outline 288
7.4.2 Oxidation Reduction Process 290
7.4.3 Reduction Processes 293
7.5 Summary - Applicability of Simultaneous Removal
Processes 297
REFERENCES 300
xiv
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FIGURES
Number Page
1-1 Fuel mix required for a desired increase in elec-
trical generation capacity 3
1-2 Sulfur input in Japan 9
1-3 Ambient SO2 concentration in major industrial and
urban areas 10
1-4 Sulfur in fuel oil allowed by the total mass regu-
lations (for existing plants) 15
1-5 S02 and S03 in heavy oil combustion gas (02 1-27,,). 19
1-6 S02 and S03 in flue gas (heavy oil, S=l-3%) 19
1-7 S03 and dust in flue gas (heavy oil, S=l-3%) 20
1-8 Schematic figure of SO3 formation in heavy oil
combustion gas (S02 1,000 ppm, 02 1%) 21
1-9 Relative humidity and oxidation of S02 to sulfate
(June-July, 1975) 22
2-1 Simplified flow sheet of Flexicoking process 36
2-2 Material balance of crude oil treatments including
Flexicoking 38
2-3 Flow sheet of Eureka process 39
2-4 Flow sheet of Cherry process 42
2-5 Flow sheet of coal-residual oil hybrid gasification 44
2-6 Flow sheet of low calorific coal gasification 48
2-7 Flow sheet of solvolysis liquefaction 52
2-8 Flow sheet of molten salt lime slurry process 54
3-1 Production capacity of desulfurization 69
3-2 Price of by-products 69
3-3 Demand for and supply of gypsum 71
3-4 Relationship of the chloride concentration in the
purge stream to the purge rate and the chloride
content of the fuel (250 MW boiler, 1,500 ppm S02,
10% moisture in by-product gypsum) 76
xv
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FIGURES (Continued)
Number Page
3-5 Oz and Cl concentrations in solution and stress
corrosion 76
3-6 Improved types of mist eliminators 79
3-7 Gas velocity and pressure drop 80
3-8 Gas velocity and mist collection 81
3-9 Gas velocity and acceptable mist load 81
3-10 Pilot plant of Ljungstrom heat exchanger 85
3-11 Deposits on elements in the Ljungstrom heat
exchanger 86
3-12 Bypass systems (ESP: Electrostatic precipitator,
FGD: Flue gas desulfurization, F: Fan) 91
3-13 Costs of fuels and desulfurization (with 3% S oil)
($1=¥250, Aug. , 1977) 99
4-1 Typical flow sheet of wet lime/limestone gypsum
process 105
4-2 Comparison of gypsum circulation system (Japan) and
unsaturated mode lime system (U.S.) 108
4-3 Relationship of inlet SO2 concentration and oper-
ability of FGD (lime/limestone process) 113
4-4 Flow sheet of Takasago plant, EPDC (No. 2 unit).... 118
4-5 Hourly change of operation load (Takasago plant,
EPDC) 120
4-6 Flow sheet of Isogo plant, EPDC 127
4-7 Flow sheet of Takehara plant, EPDC 135
4-8 Flow sheet of Matsushima plant, EPDC 141
4-9 Flow sheet of Owase-Mita plant, Chubu Electric 144
4-10 Characteristic curves with perforated plates 155
4-11 Flow sheet of Moretana process (Kashima plant,
Sumitomo Metal) 157
4-12 Flow sheet of Takaoka plant, Takaoka Kyodo Power... 159
4-13 Flow sheet of Tamashima plant, Chugoku Electric.... 165
4-14 Jet bubbling reactor 169
4-15 Schematic drawing of gas sparger 169
4-16 Effect of gas flow rate on penetration length 170
xvi
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FIGURES (Continued)
Number Page
4-17 SO2 removal vs . pH of absorbent 170
4-18 Pressure drop and S02 removal efficiency 171
4-19 Liquid flow pattern in jet bubbling reactor 172
4-20 Effect of pH on limestone utilization 173
4-21 Effect of residence time on limestone utilization.. 173
4-22 Pilot plant process flow diagram 175
4-23 Process flow diagram of prototype plant 178
5-1 pH of scrubber liquor and performance 187
5-2 Flow sheet of CT 101 process 190
5-3 Double-cylinder type reactor 191
5-4 Maximum and minimum S02 removal efficiencies vs.
H2SOi» concentration^ as determined by test runs at a
commercial plant 192
5-5 Operation load of Fukui plant 197
5-6 Bypass system of Fukui plant 197
5-7 Flow sheet of Ichihara (Chiba) plant, Showa Denka.. 202
5-8 Flow sheet of Kureha-Kawasaki process 205
5-9 Flow sheet of Dowa process 212
5-10 Flow sheet of Japan Exlan plant 218
5-11 Absorbent pH and S02 removal 222
5-12 Relation between L/G ratio and S02 removal 222
5-13 Solubility of Ca(OH) 2 in CaCl2 solution 227
5-14 Vapor pressure on CaCl2 solution 227
5-15 CaSOu solubility in CaCl2 solution 227
5-16 Oxidation rate of CaS03 to CaSOi» (at optimum pH) . .. 227
5-17 Flow sheet of Kobe steel process 229
5-18 Flow sheet of Kurabo ammonium sulfate-gypsum
process 235
5-19 Flow sheet of Nippon Kokan ammonia-lime process.... 237
5-20 Simplified flow sheet of Kureha sodium acetate lime
process 239
6-1 Flue gas treatment system (Ogishima plant, Nippon
Kokan) 249
xvii
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FIGURES (Continued)
Number Page
6-2 SO2 and NH3 absorption system (Ogishima plant,
Nippon Kokan) 250
6-3 Scrubber and liquor flow (Ogishima plant, Nippon
Kokan) 252
6-4 Flow sheet of the Wellman-MKK process (Nishinagoya
Station, Chubu Electric Power) 257
6-5 Sulfur balance of FGD system at Nishinagoya, Chubu
Electric (Wellman-MKK process) 258
6-6 Flow sheet of Chiba plant, Idemitsu Kokan (Mitsui-
Chemico magnesium process) 263
7-1 Combined and simultaneous removal systems - control
strategy options (numbers show temperatures, °C) . . . 273
7-2 Efficiency of simultaneous removal by activated
carbon and ammonia 277
7-3 Flow sheet of Unitika process (Uji plant) 279
7-4 Flow sheet of Sumitomo activated carbon process.... 282
7-5 Performance of Shell FGD reactor at SYS. Instan-
taneous SO2 and NOX slip (92) 286
7-6 Simultaneous removal by electron beam radiator 287
7-7 Simplified flow sheet of wet-limestone simultaneous
removal process (oxidation reduction process) 291
7-8 Flow sheet of Chisso process (CEC process) 295
7-9 Flow sheet of Kureha process 296
7-10 Gas composition and suitable processes 298
xviii
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TABLES
Number Page
1-1 JAPAN'S ENERGY SUPPLY 2
1-2 1977 BUDGET FOR SUNSHINE PROJECT 6
1-3 COAL GASIFICATION AND LIQUEFACTION RESEARCH AND
DEVELOPMENT PROGRAMS 7
1-4 CONSUMPTION AND SULFUR CONTENT OF HEAVY OIL 9
1-5 AMBIENT S0x STANDARDS 10
1-6 VALUES OF K APPLICABLE TO LOCATIONS IN JAPAN 11
1-7 RELATION OF K VALUE TO MAXIMUM GROUND-LEVEL
CONCENTRATION OF S02 12
1-8 TAX RATE ON SO EMISSION 16
X
1-9 AMBIENT CONCENTRATIONS OF SULFATE AND VANADIUM (V)
IN MAJOR CITIES IN JAPAN 18
1-10 N02 AMBIENT STANDARDS 25
1-11 NOV EMISSION STANDARDS FOR STATIONARY SOURCES 26
s\
1-12 NOX EMISSION STANDARDS FOR EXISTING OIL-FIRED
BOILERS WITH AND WITHOUT FGD SYSTEM 27
1-13 INVESTMENT BY INDUSTRY FOR POLLUTION CONTROL (I) .. 28
1-14 INVESTMENT BY INDUSTRY FOR POLLUTION CONTROL (II) . 29
2-1 CAPACITY OF HEAVY OIL DESULFURIZATION 33
2-2 NEW HDS PLANTS 34
2-3 TYPICAL PRODUCT PATTERNS 40
2-4 ECONOMIC BALANCE OF RESIDUAL OIL CRACKING PROCESS . 40
2-5 S AND N CONTENTS OF PRODUCT OIL FROM THE CHERRY
PROCESS 43
2-6 PRELIMINARY RESULTS OF PLASMA GASIFICATION 53
3-1 NUMBERS AND CAPACITIES OF PLANTS BY MAJOR
CONSTRUCTORS (OPERATIONAL AT END OF 1977) 59
xix
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TABLES (Continued)
Pa
3-2 CAPACITIES OF STEAM POWER GENERATION AND FGD OF
POWER COMPANIES ................................. 61
3-3 FGD PLANTS OF POWER COMPANIES (I) ................. 63
3-4 FGD PLANTS OF POWER COMPANIES (II) ................ 64
3-5 SO 2 REMOVAL INSTALLATIONS FOR WASTE GAS FROM
IRON-ORE SINTERING MACHINES ..................... 66
3-6 MAJOR FGD PLANTS OF LEADING NONFERROUS SMELTERS ... 68
3-7 PROPERTIES OF FGD GYPSUM .......................... 73
3-8 WASTEWATER FROM FGD SYSTEMS ....................... 75
3-9 TEST RESULTS OF LJUNGSTROM HEAT EXCHANGERS ........ 86
3-10 EXAMPLES OF PARTICULATE CONTENT OF THE
LJUNGSTROM TEST FLUE GAS ........................ 87
3-11 INVESTMENT AND ANNUALIZED COSTS FOR REHEATING ..... 88
3-12 OPERATION HOURS AND FGD OPERABILITY IN RECENT
ONE YEAR* ....................................... 93
3-13 LABOR REQUIREMENTS OF FGD PLANTS .................. 95
3-14 FGD PLANT COSTS IN BATTERY LIMITS ................. 96
4-1 WET LIME/LIMESTONE PROCESS PLANTS BY MHI PROCESS . . 101
4-2 WET LIME LIMESTONE PROCESS PLANTS USING SCRUBBERS
DEVELOPED IN U. S ................................ 102
4-3 WET LIME LIMESTONE PROCESS PLANTS BY OTHER
PROCESSES ....................................... 103.
4-4 OPERATION DATA OF MAJOR LIME /LIMESTONE PROCESS
PLANTS .......................................... 106
4-5 FGD PLANTS FOR COAL-FIRED BOILERS ................. 115 .
4-6 SPECIFICATIONS OF FGD UNITS ........... , ........... 119
4-7 PERFORMANCE OF THE NO. 1 UNIT, TAKASAGO PLANT ..... 121
4-8 PERFORMANCE OF THE NO. 2 UNIT, TAKASAGO PLANT ..... 123
4-9 PLANT SPECIFICATIONS .............................. 129
4-10 MAIN EQUIPMENT .................................... 130
4-11 BOILERS AT TAKEHARA STATION ....................... 133
4-12 AIR POLLUTION CONTROL FACILITY .................... 134
4-13 OPERATION HOURS OF OMUTA PLANT MITSUI ALUMINUM ____ 139
xx
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TABLES (Continued)
Number Page
4-14 YEARLY OPERATION OF OWASE-MITA NO. 1 BOILER AND
FGD UNIT 147
4-15 YEARLY OPERATION OF OWASE-MITA NO. 2 BOILER AND
FGD UNIT 148
4-16 REGULATIONS FOR SHIMONOSEKI STATION 151
4-17 MAIN COMPONENTS OF SHIMONOSEKI PLANT 152
4-18 OPERATION HOURS (KASHIMA PLANT) 160
4-19 MAJOR COMPONENTS OF THE PLANT FOR TAKAOKA KYODO
POWER CO., LTD 161
4-20 OPERATION HOURS OF TAMASHIMA NO. 3 PLANT 164
4-21 OPERATION HOURS OF KARATSU PLANT 167
4-22 MAJOR EQUIPMENT OF PILOT PLANT 176
4-23 TYPICAL PILOT PLANT OPERATING DATA 177
4-24 GYPSUM QUALITY 177
4-25 COSTS FOR 60 MW UNIT 179
4-26 CAPITAL AND OPERATION COSTS FOR 200 MW UNIT 180
5-1 INDIRECT AND MODIFIED LIME/LIMESTONE PROCESS
INSTALLATIONS 182
5-2 OPERATION DATA OF INDIRECT AND MODIFIED LIME/
LIMESTONE PROCESS PLANTS 184
5-3 UTILITY BOILER AND FGD PERFORMANCE (1975-AUG. 1977) 193
5-4 OPERATION HOURS OF FUKUI PLANT, HOKURIKU ELECTRIC . 195
5-5 TROUBLES AT THE FUKUI PLANT AND REMEDIES 196
5-6 TYPICAL ECONOMIC DATA OF COMMERCIAL PLANTS 198
5-7 OPERATION HOURS OF ICHIHARA PLANT, SHOWA DENKO 203
5-8 FGD COST (ICHIHARA PLANT) 204
5-9 OPERATION HOURS OF SAKAIDE NO. 3 PLANT 206
5-10 RESULTS OF FGD OPERATION IN ANAN POWER STATION 208
5-11 OPERATION DATA AND COSTS (ANAN PLANT, 1977) 209
5-12 OPERATION HOURS OF NAIKAI PLANT (DOWA PROCESS) . .'. . 215
5-13 COST FIGURES (TAMANO PLANT, NAIKAI) 216
xxi
-------
TABLES (Continued)
Number Page
5-14 MAJOR EQUIPMENT LIST (SAIDAIJI PLANT,
JAPAN EXLAN CO.) ................................ 220
5-15 PERFORMANCE OF OKAZAKI PLANT, UNITIKA ............. 224
5-16 OPERATION OF AMAGASAKI PLANT, KOBE STEEL .......... 230
5-17 OPERATION HOURS OF FUNAMACHI PLANT, NAKAYAMA STEEL 232
6-1 FGD INSTALLATIONS BY-PRODUCING H2SO.,, S AND
(NHO zSO* ....................................... 242
6-2 OPERATION DATA OF REGENERABLE PROCESS PLANTS ...... 249
6-3 OPERATION HOURS SINCE START-UP .................... 253
6-4 OPERATION PARAMETERS OF FUKUYAMA PLANT ............ 255
6-5 YEARLY OPERATION OF NISHINAGOYA NO. 1 BOILER AND
FGD PLANT ....................................... 260
6-6 OPERATION HOURS (CHIBA PLANT, IDEMITSU KOSAN.
FGD TREATS FLUE GAS FROM BOILER AND GLAUS FURNACE) 265
7-1 CLASSIFICATION OF SIMULTANEOUS REMOVAL PROCESSES . . 274
7-2 EFFECT OF ADDITION OF BASE METAL COMPOUNDS TO
CARBON ON NO REDUCTION EFFICIENCY .............. 277
XX
7-3 ESTIMATED COST FOR SIMULTANEOUS REMOVAL BY
ACTIVATED CARBON ................................ 281
7-4 MAJOR WET SIMULTANEOUS REMOVAL PROCESSES .......... 289
xxii
-------
CONVERSION FACTORS AND ABBREVIATIONS
CONVERSION FACTORS
The metric system is used in this report. Following
are some factors for conversion between metric and English sys-
tems:
1 m (meter) = 3.3 feet
1 m3"(cubic meter) =35.3 cubic feet
1 t (metric ton)( = 1.1 short tons
1 kg (kilogram) = 2.2 pounds
1 liter = 0.26 gallon
1 kl (kiloliter) = 6.19 barrels
The capacity of flue gas desulfurization plants is expressed in
Nm3/hr (normal cubic meters per hour)
1 Nm3/hr = 0.59 standard cubic foot per minute
L/G ratio (liquid/gas ratio) is expressed in liters/Nm3.
1 liter/Nm3 = 7.4 galIons/thousand standard
cubic feet
ABBREVIATIONS
FGD = Flue gas desulfurization
HDS = Hydrodesulfurization
BPSD = Barrels per stream day
MW = Megawatts
L/G = Liquid/gas ratio (see above)
Nm3/hr = Normal cubic meters per hour
xxiii
-------
YEN - DOLLAR CONVERSION
The Yen/Dollar exchange rate has undergone consider-
able change in recent years. When using the cost data in this
report the following conversions should be used:
¥/$ Year
292 1974
297 1975
297 1976
267 1977
238 1978 (1st quarter)
xxiv
-------
SECTION 1
ENERGY AND ENVIRONMENT
1.1 ENERGY SUPPLY OF JAPAN
For more than 70% of its total energy, Japan now
depends upon imported oil. Most of this comes from the Middle
East (Table 1-1). Demand for oil, which was 288 million kilo-
liters in 1975, may exceed 500 million in 1985. It will be
difficult to obtain that much because of the oil supply and
demand situation in the world. Japan's per capita energy con-
sumption is less than one-half the U.S. and not much energy
saving can be expected. Therefore, it is necessary to increase
the use of energy sources other than oil.
Construction of nuclear power stations in Japan has
been delayed under circumstances similar to those in the U.S.
and West Germany. Coal mines in Japan are small and deep under-
ground. Dependence on imported LNG and coal, particularly the
latter, will have to be increased.
In the early 1960s Japan mined over 50 million tons of
domestic coal yearly. As oil imports increased, coal production
dropped below 20 million tons for economic and environmental
reasons. Although Japan has imported over 60 million tons of
coal yearly, the entire quantity has gone to coke production
for the steel industry. Much additional coal will be required
for electric power generation, as shown in Figure 1-1. An
increase in coal consumption will necessitate extensive measures
-------
TABLE 1-1. JAPAN'S ENERGY SUPPLY
1985
1975
Amount (%)
Hydro power (10e
Conventional
Pumped storage
Geo thermal (106
Domestic oil, gas
(106
Domestic coal (10s
Atomic energy (10s
LNG (106
Imported coal (10s
kW)
kW)
kl)
t)
kW)
t)
t)
for steel industry
for fuel
New energy (106
Imported oil (10s
kl)
kl)
Total (106 kl equivalent)
24.9
17.8
7.1
0.05
3.5
18.6
6.62
5.06
62.3
61.8
0.5
0.0
288.0
390.0
( 5.8)
( 0.0)
( 0.9)
( 3.3)'
( 1.7)
( 1.8)
( 13.1)
( 0.0)
( 73.4)
(100.0)
Case A*
Amount
39.0
19.5
19.5
0.5
8.0
20.0
26.0
24.0
93.0
87.0
6.0
0.0
505.0
700.0
(%
( 3
( o
( 1
( 2
( 5
( 4
( 10
( o
( 72
(100
)
.3)
.1)
.2)
.0)
.4)
.9)
.7)
.0)
.2)
.0)
Case B1
Amount
41.0
22.5
18.5
1.0
11.0
20.0
33.0
30.0
102.0
86.0
16.0
2.3
432.0
660.0
(
(
(
(
(
(
(
(
(
r
(%)
3.9)
0.3)
1.7)
2.1)
7.4)
6.4)
12.4)
0.4)
65.5)
(100.0)
1990
Case B**"
Amount
51.0
26.5
24.5
3.0
14.0
20.0
60.0
44.0
144.0
104.0
40.0
13.0
452.0
792.0
(%)
( 3.9)
( 0.7)
( 1.7)
( 1.8)
( 11-2)
( 7.7)
( 14.1)
-
( 1.6)
( 57.1)
(100.0)
When no special effort is made.
With efforts to save energy and develop energy sources other than oil.
-------
200 r-
100 -
o
a
a,
3
100 I—
3 50 -
o
a
a.
H:
T:
N:
0:
L:
C:
Hydro
Thermal
Nuclear
H
X
N
1975
Oil
LNG
Coal
0
L
<
H
T
N
1985
0
L
C
H
T
N
1990
0
L
C
1975 1985 1990
Figure 1-1. Fuel mix required for a desired
increase in electrical generation
capacity.
-------
for environmental protection in Japan, where most regions avail-
able for industry are already fairly densely populated.
1.2 SUNSHINE PROJECT1
The Sunshine Project was started in 1974 by the
Ministry of International Trade and Industry., with a view to
securing energy on a long-term, stable basis. The aim is to
supply clean energy to meet a considerable portion of the future
demand for energy by promoting research and development work on
new energy techniques.
The kinds of new energy technology to be developed
on a priority basis to attain the goals of the Sunshine Project
are solar energy technology, geothermal energy technology,
technology for the gasification and liquefaction of coal, and
hydrogen energy technology. Specific areas of interest are
listed below:
1) Solar Energy Technology
Technology for solar energy power genera-
tion systems.
Technology for solar thermal power
generation system.
- Technology for photovoltaic conversion
system.
- Others
Technology for solar cooling and heating and
solar hot water supply systems.
Technology for new applications of solar
energy.
-------
2) Geothermal Energy Technology
Technology for exploration and extraction
of geothennal energy.
Technology for power generation utilizing
hot water.
Technology for a volcanic power generating
system.
Technology for multipurpose utilization of
geothermal energy.
Technology for environmental preservation.
3) Coal Gasification and Liquefaction Technology
<
Coal gasification technology.
Technology for manufacturing synthetic
natural gas.
Technology for gasification power
generation.
Technology for plasma gasification.
Coal liquefaction technology.
4) Hydrogen Energy Technology
Techniques for manufacturing hydrogen.
Techniques for transporting and storing
hydrogen.
Techniques for utilizing hydrogen.
Techniques for safe handling of hydrogen.
Hydrogen energy system.
The budget for each project since 1974 and the work
plans for 1977 are shown in Table 1-2. Projected plans for
coal gasification and liquefaction are shown in Table 1-3.
-------
TABLE 1-2.
1977 BUDGET FOR SUNSHINE PROJECT1
(100 million yen)
Projects
1974 1975 1976 1977
Work plans for FY1977
Solar energy
Geothermal energy
Coal gasification
and liquefaction
Hydrogen energy
8.7 11.0 14.6 14.9
5.6 11.4 15.5 15.6
2.6
6.7
7.2
3.3 4.8 5.2
Supporting research 2.4 3.2 3.7
and management
Total budget
7.4
5.2
5.6
22.7 37.0 46.1 48.7
Conceptual design of 1,000 kW solar power generation
plant (2 types)
• Basic experiments of solar thermal power
generation
• System operation of solar house
• New material exploitation
• Experiments on photovoltaic power generation
Operation of 1,000 kW binary cycle power generation
plant (2 types)
• National survey on geothermal energy resources*
• Feasibility study of volcanic power generation
• R & D on new exploration methods
• Study of reinjection mechanism
Conceptual design of 7,000 m9/day gasification plant
Operation of coal liquefaction pilot plant
(Solvolysis method)
• Experiment on development of coal gasification
processes
• 5 t/day pilot plant operation for development of
low-Btu gasification process^
• Basic study of plasma gasification
• Basic research on coal liquefaction
• Manufacturing of hydrogen
• Feasibility study on new utilization of hydrogen
• Total energy system
• Exploitation of seeds technology
• Management of R & D
*...Nationwide Basic Study completed in
Resources and Energy.
t...Financed by the Special Account for
1965, and now being followed up by Agency of Natural
Coal and Petroleua, which amount is excluded froa this chart.
-------
TABLE 1-3. COAL GASIFICATION AND LIQUEFACTION RESEARCH AND DEVELOPMENT PROGRAMS1
Research items
FY 1974-1980
Term - 7 yrs.
FY 1981-1985
Term - 5 yrs.
FY 1986-1990
Term - 5 yrs.
FY 1990-1995
Term - 5 yrs.
Coal gasification
1) Conversion into high calorie
gas
• Fundamental research
• Gasification plant
2) Conversion into low calorie
gas & power generation
• Gasification plant for
power generation
• Gas/steam turbine com-
bined power plant
3) Plasma gasification
• Fundamental research
• Plasma gasification
device
Feasibility 7.000 50,000 350,000 1.000,000
study m /daym3/day m3/day m /day „
20,000 kW combined cycle
power plant system ^
2,000 kW furnace 5,000 kW furnace
Coal liquefaction
1) Fundamental research
2) Coal refining plant
3) Liquefaction plant
2 t/day 30 t/day 300 t/day 3.000 t/day
100 bbl/day 1.000 bbl/day 10.000 bbl/day
-------
Japan has certain limitations in its search for new,
clean energy sources. The small amount of land space available
limits the use of solar energy. Geothermal energy may be more
promising, but environmental pollution and corrosion of equip-
ment may present problems. Thermochemical studies of the pro-
duction of hydrogen from water indicate that nuclear energy will
have to be relied on to supply the energy required for hydrogen
production. Coal treating is the most practical technology, but
most of Japan's coal has to be imported.
1.3 SULFUR INPUT IN JAPAN
Figure 1-2 shows yearly sulfur inputs since 1966. In
1976, 3.5 million tons of sulfur were derived from imported oil,
1.7 million tons from metal sulfides, and 1.3 million tons from
other sources. Virtually all of the sulfur from the metal sul-
fides is converted to sulfuric acid (amounting to 7 million tons
yearly). Therefore, the sulfur in oil is the major source of
S02- Efforts have been made since 1966 for desulfurization of
both oil and flue gas. Table 1-4 shows that the average sulfur
content of heavy oil, the major fuel in Japan, has decreased
considerably. The sulfur content of heavy oil for electric
power plants has been less than the average for total heavy oil
because more stringent regulations have been applied to larger
consumers. Most power plants burn oil with less than 0.3% sul-
fur, while others use oil with more than 1% sulfur and apply
flue gas desulfurization.
8
-------
c
o
AJ
10 C.
o 6
3
cx
<4-l
iH
3
Other
1 1 1
Coal + Iron or<
Imported oil
I I I I
1965
1970
1975
Figure 1-2. Sulfur input in Japan.
TABLE 1-4. CONSUMPTION AND SULFUR CONTENT OF HEAVY OIL
Grade C heavy oil
For electric power
1968
1969
1970
1971
1972
1973
1974
1975
1976
Amount
(106 kl)
19.2
24.0
29.2
30.8
33.0
34.9
33.1
31.5
33.9
S
(%)
2.02
1.89
1.66
1.47
1.22
1.01
1.00
0.99
0.99
Total
Amount
(10s kl)
62.3
65.0
83.2
85.8
91.6
92.4
91.4
85.4
90.5
S
(%)
2.49
2.18
2.05
1.86
1.66
1.53
1.52
1.52
1.51
Total heavy oil
Amount
(106 kl)
79.3
82.6
105.8
109.3
118.2
112.9
121.2
114.8
120.7
S
(%)
2.32
2.06
1.93
1.74
1.56
1.43
1.43
1.42
1.41
-------
1.4 S0x STANDARDS AND REGULATIONS
1.4.1 Ambient Standard
The current Japanese SOV ambient standard requires
/\
that the hourly average should not exceed 0.1 ppm and the daily
average 0.04 ppm. The standard is much more stringent than that
in the U.S.A. and West Germany (Table 1-5). The stringent stan-
dard has been almost met as shown in Figure 1-3.
AMBIENT SOX STANDARDS
TABLE 1-5.
(Converted to ppm)
Hourly
Daily
Yearly
Japan
United States
West Germany
0.1
0.04
(0.016)
0.03
0.05
0.06
0.04
O
CO
0.02
S02
-Ambient Standard (Yearly Average)
I I I I
I .
I I I
1965
Figure 1-3.
1970
1975
Ambient SO2 concentration in major
industrial and urban areas.
(Average for 15 stations)
10
-------
1.4.2 Emission Standards
The reduction in the ambient S02 concentration illus-
trated in Figure 1-3 is a result of emission standards employed
by the Japanese Central Government's Environment Agency. The
standards are keyed to local air quality and environmental con-
ditions using what is known as a "K-value" system. Under this
system, the specific allowable quantity of SO emissions for
X
each emitting source within a given geographical area is cal-
culated by the following equation:
Q = K x 10~3 He2 (1-1)
i
Q: Allowable emissions of sulfur oxides,
Nm3/hr
K: The constant specified for each of the
geographical regions as shown in Table 1-6
He: Effective height of stack, meters
(He = Actual stack height plus plume
ascent distance)
TABLE 1-6. VALUES OF K APPLICABLE TO LOCATIONS IN JAPAN
(For Existing Plants)
3.0
Tokyo
Yokohama
Kawasaki
Yokkaichi
Osaka
3.5
Chiba
Fuji
Handa
Himeji
Mizushlma
4.0-4.5
Sapporo
Kashima
Shimizu
Tokuyama
Omuta
6.0-7.0
Hachinohe
Sendai
Niigata
Okayama
Fukuoka
11.5-14.5
Hakodate
Miyako
Mobara
Sasebo
Kagoshima
(For New Plants)
1.17 1.75 2.34
Tokyo, Yokohama Chiba, Fuji Kashima, Omuta
Kawasaki, Nagoya Kitakyushu Ube, Oita
Yokkaichi, Osaka Handa, Himeji Shimizu, Kyoto
11
-------
The relationship between the value of K and the maximum ground-
level concentration of SOz is shown in Table 1-7. A given K-
value results in the ground-level SO2 concentration shown in the
table.
TABLE 1-7. RELATION OF K VALUE TO MAXIMUM GROUND-LEVEL
CONCENTRATION OF S02 (ppm)
K
SO 2
1.17
0.002
1.75
0.003
2.34
0.004
3.50
0.006
4.67
0.008
8.76
0.015
14.6
0.025
For example, for the following conditions
He = 450m
K = 1.17
the allowable sulfur emissions are calculated to be 237 Nm3/hr.
A 500 MW boiler typically emits flue gas at a rate of l.SxlO6
Nm3/hr. The SOX concentration that corresponds to this flow
rate is 158 ppm. This corresponds to 0.3% sulfur fuel since
these fuels typically emit about 150 ppm of SOX. Therefore, in
order to meet the emission standard, a new plant in the Tokyo or
Osaka area with a capacity of 500 MW and an effective stack
height of 450 meters (actual stack height of 200 meters) cannot
use oil with a sulfur content greater than 0.3 percent. This
emission standard, however, has proven insufficient to attain
the ambient standard in certain districts. More stringent emis-
sion regulations have recently been applied to those districts.
These are the total mass regulations. In other districts more
stringent regulations have been applied by agreement with local
authorities.
12
-------
Total Mass Regulation of SO^--
X
With the aim of attaining the ambient standard by
March 1978, the Japanese central government promulgated a new
regulation in November 1974 to restrict the total mass of S02
emissions in the following eleven polluted areas: 1) Tokyo,
2) Chiba, 3) Yokohama, Kawasaki, 4) Fuji, 5) Nagoya, 6) Handa,
7) Yokkaichi, 8) Osaka, Sakai, 9) Kobe, Amagasaki, 10) Kurashiki,
Mizushima, and 11) Kitakyushu. Later 13 more areas were added.
The new regulation applies to plants using from 0.1 to 1.0 kilo-
liter of oil per hour (0.4 to 4.0 MW equivalent). Within this
range, the specific minimum consumption rate for regulation is
assigned to each prefecture4by the governor. The amount of
allowable S0x is calculated from one of the following formulas,
to be selected by each prefecture:
Q = a x VT (1-2)
Q: Amount of allowable SOV
X
a: A constant to ensure SOX abatement
W: Rate of fuel consumption by each plant
b: A constant between 1.00 and 0.80 to be
selected by the prefectural governor
Q = QQ x Cm/Cm (1-3)
o
Q: Amount of allowable SOV
/\
Q : Amount of S0x being emitted
C : Maximum ground-level concentration to
m ensure S0_ abatement
X
C :Maximum ground-level concentration due
mo to each plant
As an example, the regulations of Kanagawa Prefecture,
in which Yokohama and Kawasaki cities are located, are shown
below. Equations l-4a (applied to the most polluted districts
13
-------
in Yokohama and Kawasaki) and l-4b (applied to the remainder of
Kanagawa) are employed for plants that consume more than 1 kl
of oil per hour.
Q = 1.5 W°'865 +0.5 W^-865 d-4a)
Q = 2.5 W°'865 + 0.8 w.0-865 d-4b)
Q: Amount of allowable SOX, Nm3/hr
W: Rate of fuel consumption by existing
plants, kl/hr
W.: Rate of fuel consumption by new plants,
1 kl/hr
The relationship between fuel consumption by existing
plants and the allowable sulfur content of fuel oil for each
district is shown in Figure 1-4. A 450 MW plant in the Yokohama
or Kawasaki district is allowed to use oil with a maximum of
0.117% sulfur. If the plant has two 225 MW boilers and one of
them uses LNG that has no sulfur, however, the other unit may
use oil with 0.248% sulfur.
Fuels with much lower sulfur content are required for
new plants to be constructed in these districts; the stringent
regulations virtually prevent the construction of new plants in
the area. Plants which use fuel with higher sulfur content have
to install FGD units to reduce SOX emission to the regulated
amount.
Agreement With Local Authorities—
For regions where total mass regulations have not been
applied, S0x emission is controlled by the K-value system of the
central government (Equation 1-1). However, most larger plants,
particularly new ones, are controlled by agreements with
14
-------
0.25
0.20
o 0.15
e
3
WJ
0.10
0.05
_( f
' > I
Boiler Capacity (MW equivalent)
100 1000
I
I
Nagoya
owntown)
I
10 100
Fuel Oil Consumption (kl/hr)
Figure 1-4. Sulfur in fuel oil allowed by the total
mass regulations (for existing plants).
15
-------
prefectural or city authorities for pollution prevention. The
controls by these agreements are usually much more stringent
than those by the central government. For example, many power
plants, even though they are distant from large cities, have to
use an oil with below 0.3% sulfur or apply FGD to attain the S0x
emission levels mandated by local authorities.
1.4.3 SOy Emission Tax
An SOX emission tax system has been in force since
1974. Plants in polluted regions emitting more than 5,000
Nm3/hr of flue gas and those in other regions emitting more than
10,000 Nm3/hr have to pay the tax even though they may have
satisfied the emission regulations. The tax, based on the
amount of SO emitted, is charged at a rate shown in Table 1-8.
TABLE 1-8. TAX RATE ON SOV EMISSION
/Yen \
\m3 of soxy
1974
1975
1976
1977
Polluted regions
Osaka, etc. Tokyo, etc. Chiba, etc. Kitakyushu, etc.
(A) (B) (C) (D)
15.84
37.31
209.97
536.63 381.31 344.98 306.65
Other
regions
1.76
8.59
23.33
42.59
The tax proceeds have been used in designated areas
for the medical care of patients affected by air pollution. The
number of such patients has continued to increase and is now
approaching 20,000, although S0x emission and ambient SO con-
J\
centration have continued to decrease since 1967. As a result
the tax rate has increased remarkably. Several companies are
now considering installing FGD plants even though they have
16
-------
satisfied the regulations, because the resulting decrease in the
tax may compensate for the FGD cost. Further SO reduction,
J\
however, may result in a further increase in the tax rate as
long as the number of patients does not decrease.
The recent increase in the number of pollution victims
is due largely to delayed medical examination. A large number
of people are being examined by a limited number of designated
doctors; a considerable number of people are still awaiting
examination. This time lag makes it difficult to tell whether
the number of true pollution victims is increasing or decreasing.
1.5 SO2 AND SULFATE
1.5.1 Ambient Sulfate Concentration
In the U.S.A., sulfate particulates are considered by
many as being much more hazardous to human health than gaseous
SO2 is. Sulfate particulates include sulfuric acid mists and
fine solid particulates of sulfate compounds with ammonia, cal-
cium, etc., and are often simply called sulfate.
The sulfate (S0^2~) concentrations in ambient air in
10 Japanese cities are shown in Table 1-9 together with vanadium
concentrations. SOV and vanadium (V) are mainly derived from
X
heavy oil combustion. The table shows that concentrations of
both sulfate and vanadium decreased by about a half in the four
years beginning 1970. In the same period, average ambient S02
concentrations were also halved, from 0.043 ppm (113 yg/Nm3) to
0.024 ppm (63 ug/Nm3).
17
-------
TABLE 1-9. AMBIENT CONCENTRATIONS OF SULFATE AND VANADIUM
IN MAJOR CITIES IN JAPAN (yg/Nm3)
1970
City
Sapporo
Ichihara
Tokyo
Kawasaki
Nagoya
Osaka
Amagasaki
Mat sue
Ube
Kitakyushu
Average
SO./
11.2
14.7
17.3
56.0
22.0
31.6
30.3
8.7
27.5
29.0
24.8
V
0.03
0.06
0.07
0.27
0.09
0.15
0.10
0.01
0.05
0.10
0.09
1972
SO./
8.3
15.5
16.1
24.0
25.0
27.0
18.8
10.3
20.9
17.1
18.3
V
0.03
0.07
0.08
0.14
0.12
0.13
0.11
0.02
0.07
0.07
0.08
1974
SOi/
7.0
11.8
12.0
16.8
16.7
14.6
12.6
7.3
13.4
12.5
12.5
V
0.02
0.03
0.05
0.05
0.06
0.05
0.05
0.02
0.05
0.05
0.04
Consumption of heavy oil during this period increased
by about 30% while total sulfur in the heavy oil decreased by
about 20%. This may mean that FGD contributed to the reduction
of vanadium, which is contained in fly ash, as well as S02. A
considerable portion of ambient sulfate is formed in the atmos-
phere from SO2 with the help of vanadium, which acts as an oxi-
dation catalyst. Some sulfuric acid mist is also formed within.
flue gas. Thus, although the removal ratio of sulfuric acid
mist by FGD may not be high, the reduction of S02 and vanadium
results in a decrease of atmospheric sulfate.
Formation of S03 and H2SOi» Mist in Flue Gas2--
Usually 2-5% of SOX in heavy oil combustion flue gas
(cooled to about 150°C) is in the form of S03 or H2S04 mist
(Figure 1-5). The S03 increases with oxygen concentration in
the flue gas (Figure 1-6). Since S03 causes corrosion of
18
-------
1500
a
a
a,
01
O
w
1000
500
0
100
§,
a
o
CO
50
0
0
S in Oil (%)
Figure 1-5. SOz and SOs in heavy oil
combustion gas (Oz 1-2%)2
100
50
0 30
ex
cu
-------
electrostatic precipitators, efforts have been made to decrease
SO3 by minimizing oxygen in combustion gas. Recent efforts for
N0x abatement by combustion control to reduce excess oxygen are
also helpful in S03 abatement. Low-oxygen combustion, however,
would increase particulates, as shown in Figure 1-7.
Figure 1-7.
SO3 (ppm)
SO3 and dust
in flue gas
(heavy oil,
S=l-3%).2
Figure 1-8 schematically illustrates the formation of
S03 in a gas containing S02 (1,000 ppm) and 02 (1%) at different
temperatures. Since the reaction of S02 and 02 to form SOs is
exothermic, little S03 forms at high temperatures (above
1,400°C). At 600°C, about 70% of S02 can be converted to S03,
but the reaction rate is much slower. Most of the S03 in boiler
flue gas probably forms during the several seconds when combus-
tion gas cools from 1,600-1,700°C to about 1,000°C.
On further cooling to about 200°C, S03 may combine
with moisture to form mists of concentrated H2SO.», which can be
hazardous to health.
20
-------
1000
S 100
CX
a,
o
CO
10
6nn°r.
1000°C
1400°C
0.1
0.01
o
•H
4J
-------
other sources, such as sulfuric acid plants, are not signifi-
cant. Therefore, it is assumed that most of the sulfate in
ambient air is formed in the atmosphere from S02 in the presence
of moisture. Sulfuric acid formed in the atmosphere from S02
should be far more dilute than that in flue gas and hence less
hazardous to health. However, it degrades the transparency of
air because the overall amount is far larger than that of con-
centrated acid mist. In parallel to the decrease in S02 and
sulfate concentrations, the transparency of the air in Japan has
been appreciably improved.
o
•H
4J
O
CO
I
-------
there has been no appreciable decrease in sulfate.3 For example,
the three-year average S02 concentration in New York City de-
creased from 358 ug/Nm3 in 1965-67 to 104 yg/Nm3 in 1969-71,
while sulfate decreased only slightly from 26.6 to 20.8 yg/Nm3
in the same period. In Chicago, SOz decreased from 246 to 126
yg/Nm3 while sulfate increased from 13.3 to 16.6 yg/Nm3 in the
same period. The difference in the situation between Japan and
the U.S. may arise from the following reasons:
1) In the U.S. many oil-fired boilers were con-
structed in the above period. Oil-fired boilers
usually produce less S02 but more sulfate than
do coal-fire
-------
by the precipitator. This procedure reduces
SO3 in flue gas considerably.
4) Recent extensive efforts in Japan to reduce N0x
in flue gas from oil-fired boilers have also
resulted in reduced formation of S03 in flue gas.
5) A major portion of sulfate in ambient air in
Japan is probably formed in the atmosphere from
S02, because of the relatively high humidity in
most districts in Japan and because of the above
factors which lead to the reduction of SO3 in
flue gas. Therefore, reduction of sulfate in
Japan is nearly proportional to that of SO2.
Although reduction of ambient sulfate has been more
effective in Japan than in the United States, it is possible
that the mists of concentrated HaSOtf emitted from many smaller
combustion sources in cities may still be largely responsible
for diseases attributed to pollution. Unlike utility boilers,
smaller oil-fired boilers in Japan have neither an electrosta-
tic precipitator nor good combustion control. These numerous
small boilers and diesel engines, both stationary and mobile,
are not yet well regulated. They may be the major sources of
mists of concentrated sulfuric acid, which could affect human
health. Although the acid mists may represent a relatively
small portion of total sulfates, most of the mists are emitted
in cities and are highly concentrated.
1.6 EMISSION AND REGULATION OF NO
NOX emission in Japan is estimated at about 2 million
tons yearly. More than 90% of NOX is formed by the burning of
24
-------
fuels, such as heavy oil and gasoline. About 40% of total NO
X
is derived from automotive exhausts, 20% from electric power
generation, 30% from industry, and the rest from household heat-
ing, etc. In large cities such as Tokyo and Osaka, 60-70% of
NOV is traced to automobiles.
i\
The ambient air quality standard for N02 was set forth
in 1973 at 0.02 ppm for a daily average (about 0.008 ppm yearly
average). This is the most stringent standard in the world
(Table 1-10. The present yearly average of N02 concentration
ranges from 0.02 to 0.04 ppm in many cities.
A revised standard has been applied since July 1978
which has a range of 0.04 to 0.06 ppm daily average. In regions
where the NOa concentration exceeds 0.06 ppm, the concentration
will be reduced to 0.06 ppm within seven years. In regions
where the NO2 concentration is 0.04 to 0.06 ppm, the concentra-
tion cannot appreciably exceed the present levels.
TABLE 1-10. NO2 AMBIENT STANDARDS (ppm)
1973
Japan
U.S.
West Germany
Daily
0.02
0.1
Yearly
(0.008)
0.05
0.05
1978
Daily Yearly
0.04-0.06 (0.02-0.03)
The NO emission standard for stationary sources was
X
first set up in 1973 and revised in 1975 and 1977 (Table 1-11).
Less stringent regulations are applied to existing boilers with
an FGD system (Table 1-12). New boilers, however, are subject
to uniform NOV regulations regardless of whether they are equip-
s\
ped with an FGD plant.
25
-------
TABLE 1-11. NO EMISSION STANDARDS FOR STATIONARY SOURCES (ppm)
Existing plants QZ in
Sources
Boiler
(gas-fired)
Boiler
(Coal-Fired)
Boiler
(oil-fired)
Iron ore sin-
tering machine
Alumina calciner
Metal heating
furnace
Oil heating
furnace
Cement kiln
Coke Oven
Waste
Incinerator
WtA^SW*^.^*.^
(1,000 NmVhr)
More than 500
100-500
40-100
10-40
5-10
Less than 5
More than 100
40-100
10-40
5-10
Less than 5
More than 500
100-500
40-100
10-40
5-10
Less than 5
More than 100
Less than 100
More than 10
More than 100
40-100
10-40
5-10
Less than 5
More than 100
40-100
10-40
5-10
Less than 5
More than 100
Less than 100
More than 100
Less than 100
More than 40
»^^
1977
60
100
130
130.
150J.
150T
400
400
400,
400T
400T
130
150
150
150,
180.T
180
220
230
220
100
130
130
150
180
100
100
130
150
180
250
350
170
170
250
s=^^s=:
^W» Jf «
1975
100
100
130
130
n
n
480
480
480
n
n
150
150
150
150
n
n
n
n
n
100
150
150
n
n
100
100
150
n
n
250
n
200
n
n
^=r=— !—
1973
130
130
130
n*
n
n
480
480
n
n
n
180
180
180
n
n
n
n
n
n
200
200
170
n
n
170
170
170
n
n
n
n
n
n
n
1977
130
130
130
150,
150T
n
480
600
600.
480-f
n
180
190
190
230.
250t
n
260
270
n
160
170
200
n
n
170
170
180
n
n
480
480
350
350
n
1975
130
130
130
150
n
n
600
750
750
n
n
230
230
190
n
n
n
n
n
n
220
220
200
n
n
210
210
180
n
n
n
n
n
n
n
1973
130
170
n*
n
n
n
750
n .
n
n
n
230
230
n
n
n
n
n
n
n
220
220
n
n
n
210
210
n
n
n
n
n
n
n
n
gas (%)
5
6
4
15
10
11
6
10
7
12
•L*>
* No regulation, t For plants to be constructed after September 10, 1977."
T Must be met by October 1, 1980.
26
-------
TABLE 1-12. NOX EMISSION STANDARDS (ppm) FOR EXISTING
OIL-FIRED BOILERS WITH AND WITHOUT FGD SYSTEM
Capacity (1.000 Nm3/hr)
More than
1,000 500-1,000 40-500 10-40 5-10
Without FGD 180 180 190 230 250
With FGD 180 210 210 250 280
The emission standards can be met by using advanced
technology for combustion modification or by switching fuels.
The ambient air quality standard, however, is far from being
attained even with the stringent emission standard. More strin-
gent regulations to restrict the total quantity of N0x emissions
from stationary sources will be applied in several prefectures.
The new regulations as well as local agreements require the con-
struction of many flue gas denitrification plants that remove
more than 80% of NOV.
X
1.7 INVESTMENT FOR POLLUTION CONTROL"
Table 1-13 shows the investments made by Japanese
industry for pollution control since 1974. Investments by all
industries reached a maximum (nearly 1 trillion yen) in 1975,
accounting for 17.1% of total industrial investments. This
percentage is more than double the percentage spent for pollu-
tion control in the U.S. and in European countries. Investments
decreased slightly in 1976 and substantially in 1977. A further
decrease is estimated for 1978.
Most of the antipollution investments have been spent
for air pollution control as shown in Table 1-14. A major por-
tion of the air pollution control spending has gone to FGD. The
slowdown in such investments after 1975 is due largely to a
27
-------
N>
00
TABLE 1-13. INVESTMENT BY INDUSTRY FOR POLLUTION CONTROL (I)
(109 yen)
1974
All industries
Steam power
Steel
Petroleum
Nonferrous
Chemical
Petrochemical
Mechanical
IP*
786
141
135
96
23
138
50
49
(%)T
(13.4)
(47.7)
(16.1)
(25.8)
(11.1)
(27.5)
(18.7)
( 5.0)
1975
IP
929
172
196
126
22
155
66
37
(
(17
(47
(17
(34
(15
(32
(22
( 5
%)
.1)
.4)
.9)
.4)
• 1)
.0)
.3)
.0)
1976
IP
855
227
222
109
130
85
43
34
(%)
(15.0)
(45.0)
(23.3)
(37.1)
(12.4)
(21.8)
(17.8)
( 4.0)
1977
IP
574
178
132
58
18
45
23
39
(%)
( 9.1)
(34.3)
(15.6)
(18.8)
(19.6)
(13.2)
(11.1)
( 3.5)
1978
IP
457
158
113
35
14
31
14
23
(plan)
(%)
( 7.1)
(28.4)
(13.5)
( 7.9)
(18.2)
(10.0)
(11.2)
( 2.8)
* Investments for pollution control (109 yen).
Proportion of pollution control investments in total investments by each industry.
-------
TABLE 1-14. INVESTMENT BY INDUSTRY FOR POLLUTION CONTROL (II)
(109 yen)
1976
All industries
Steam power
Steel
Petroleum
Nonferrous
Chemical
to
VO
Petrochemical
Air
560
203
167
76
7
22
25
Water
146
12
29
6
2
27
12
Solid waste
36
3
6
2
3
5
2
Air
338
144
86
29
7
17
10
1977
Water
92
7
20
3
3
13
8
Solid waste
39
5
12
2
6
4
1
Air
264
127
68
18
4
9
6
1978
Water
74
10
20
5
1
7
5
(plan)
Solid waste
30
5
5
1
7
3
1
-------
which requires relatively low investment. If the attainment of
the very stringent ambient N02 standard is forced, a hugh in-
vestment, far larger than that required for FGD, will be requir-
ed for flue gas denitrification facilities. This may have a
considerable impact on the economy. As a result, the Japanese
Environment Agency has recently reevaluated the ambient NOX
standards and reduced them to the values shown in Table 1-10.
1.8 MONITORING SYSTEM FOR POLLUTION CONTROL
In order to ensure the preservation of air and water
quality, each prefectural government has an environmental
research center. Most of the centers have a telemetering system
to record the ambient and emission concentrations of pollutants.
With these data, the centers can take necessary measures to
assure compliance with regulations. As an example, the Aichi
Environmental Research Center, one of the most advanced, is out-
lined below.
Aichi Prefecture embraces Nagoya City (population over
3 million) and various industrial regions. Included is the
Yokkaichi industrial complex, which caused serious air pollu-
tion problems over 10 years ago. The center, established in
Nagoya City in 1970, has the following organization:
Director
Vice Director
Administration Division 12 members
Air Quality Division 22
Water Quality Division 20
Industrial Microanalysis Division 6
Noise and Vibration Division 5
. Higashimikawa Branch Laboratory 7
The Air Quality Division has 71 monitoring stations
throughout the prefecture with automatic analyzers for ambient
concentrations of SOX, NOX, CO, hydrocarbons, oxidants,
30
-------
suspended solids, and other pollutants. In addition, the center
has automatic SOX analyzers to analyze the emission concentra-
tions from the stacks of 40 major SOX emission sources. These
sources account for about 88% of the total SOX emission in the
prefecture.
The analyzers are placed in a small locked house and
undergo maintenance and calibration by an instrumentation com-
pany under contract with the prefectural government. Hourly
averages of the analytical data are sent via the telemetering
system to the center, where they are recorded. The total in-
vestment for this air pollution monitoring system is about 3
billion yen.
The ambient standard for SOX concentration, a daily
average of 0.04 ppm, is equivalent to an hourly average of about
0.1 ppm. When the hourly averaged ambient SOX concentration
of any of the 71 stations exceeds 0.1 ppm for two hours, a
warning is given to the region to cut down the SOX emission
from major sources. No such warning has been issued for the
last 5 years because of the low ambient SOX concentration.
The emission concentration monitoring system shows
whether individual sources have maintained emission concentra-
tions below assigned levels. An excessive emission results in
a fine or forced shutdown of the source. Such occasions, how-
ever, have rarely occurred.
In 1976, over 80% of the region in the prefecture
attained the ambient SOX standard. It is expected that all of
the regions will attain the standard in 1978.
31
-------
In order to apply the new total mass regulation of
SOX, the measurement of gas volume is required in addition to
the measurement of SOX concentration. A telemetering system
for the gas volume is under consideration. In some other
centers, fuel consumption rates are also analyzed by the system,
32
-------
SECTION 2
OIL AND COAL PROCESSING
2.1 OUTLINE
Hydrodesulfurization (HDS) of heavy oils, as well as
flue gas desulfurization, went into commercial operation in 1968
and has since increased remarkably (Table 2-1). Two methods of
HDS have been carried out in Japan. One is topped crude HDS by
which heavy oil containing 2-470 sulfur is directly treated to
reduce sulfur to about 1%. Since 1% sulfur oil has become unfit
for use in many places, three oil companies recently constructed
new HDS process plants which reduce sulfur to 0.1-0.3% using
several reactors in series (Table 2-2). The new HDS process,
however, is applicable only to heavy oils which contain a small
amount of the metallic impurities which poison the catalyst.
Moreover, just as much hydrogen is required to decrease sulfur
from 1.0 to 0.3% as to decrease it from 2.5 to 1.0%.
TABLE 2-1. CAPACITY OF HEAVY OIL DESULFURIZATION (BPSD)
Year
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
Topped crude
40,000
67,760
112,760
152,760
190,760
194,000
239,000
364,000
394,000
424,000
Vacuum gas oil
105,500
225,000
256,000
356,500
564,500
' 667,500
728,500
910,500
956,500
956,500
Total
145,500
292,760
368,760
509,260
755,260
861,500
967,500
1,274,500
1,350,500
1,380,500
33
-------
TABLE 2-2. NEW HDS PLANTS
Refinery
Aichi Refinery
Idemitsu Kosan
Capacity
(BPSD)
50,000
Process
Gulf
Type
IV
•
S(%) in
product
0.1
Start
Nov. 1975
Yokohama Refinery 30,000 UOP-RCD-Unibon 0.3 Jan. 1976
Asia Oil
Chiba Refinery 30,000 Uni-cracking 0.3 July 1976
Maruzen Oil 30,000 0.1 July 1977
The other method is vacuum gas oil HDS by which vacuum
gas oil obtained by vacuum distillation of heavy oil is desul-
furized to 0.1-0.2% sulfur. This treatment is easy because of
the low metallic impurity content of the vacuum gas oil. How-
ever, the residual oil (asphalt) from the distillator, which
amounts to about 40% of heavy oil and contains much sulfur and
metallic impurities, is difficult to desulfurize.
Many plants for thermal decomposition of residual oil
as well as gasification of heavy oil were planned in 1972 in
order to reduce sulfur to 0.1-0.2%, but most of the plans were
abandoned because of the inflation and economic depression which
followed the oil crisis. Only two plants, a Flexicoking process
plant of Toa Oil Co. and a Eureka process plant of Eureka Indus-
try Co., have been commercially installed.
Tests on coal gasification and liquefaction have been
made since 1974, but the efforts are not as extensive as in
the U.S. These processes may not be very advantageous in Japan
which depends on imports for the majority of its coal require-
ments. Unique processes for the combined treatment of asphalt
and coal are also under investigation. These processes include
the Cherry process by Osaka Gas, hybrid gasification by Hitachi
34
-------
Ltd., and Solvolysis liquefaction by Kyushu Industrial Technology
Laboratory.
2.2 FLEXICOKING5
At its Kawasaki refinery Toa Oil Co. installed an oil
processing plant with a capacity of treating 50,000 BPSD heavy
oil by vacuum distillation and 21,000 BPSD residual oil by
Flexicoking. The plant went into operation in October 1976.
A simplified flowsheet of the Flexicoking process is
shown in Figure 2-1. The vaduum residue is fed to a reactor at
510-570°C. The temperature is maintained by circulating coke
heated to 600°C in a heater. (Heat is provided by hot gas from
a gasifier.) The by-product of the thermal decomposition in the
reactor, a mixture of LP gas, naphtha, gas oil and coke, is sent
to a cyclone at the top of the reactor in order to separate coke.
It is then sent to a scrubber for oil scrubbing to be cooled to
360-380°C and to further remove coke. The product is finally
sent to a rectifier to recover LP gas, naphtha and gas oil.
Coke from the process is sent to a heater. Most of
the heated coke is returned to the reactor; the rest is sent to
a gasifier and gasified at 960°C by air and steam. The hot gas
is introduced into the heater to heat coke and then into a steam
generator to recover excess heat. The gas is then passed through
a cyclone and venturi scrubber for coke separation, treated in
a converter to convert COS to H2S, and then treated in a wet
H2S removal system by the Stretford process. The refined coke
gas has a low heating value (1,050 kcal/Nm3) and is used for
fuel in the refinery.
35
-------
TO RECTIFIER •
HEAT RECOVERV
X^^N
CIRCULATING OIL
VACUUM
RESIDUE
SCRUBBER
REACTOR
COKE GAS
AIR
Figure 2-1. Simplified flow sheet of Flexicoking process.
-------
A material balance of the total system starting from
crude oil is shown in Figure 2-2. The main product, low sulfur
oil LSN 100, is of a good quality with 0.1% S and 0.05% N.
The investment cost reached 70 billion yen (280 mil-
lion dollars) for the vacuum distillator, Flexicoker and Gofiner
(hydrodesulfurization) including a hydrogen generator, boiler
and wastewater treatment system.
Although the process offers the advantage of producing
a high quality oil from a crude containing many metallic impuri-
ties, there is no plan yet to install another unit because of
f
the high investment cost involved and the current economic de-
pression.
2.3 EUREKA PROCESS (KUREHA PROCESS)6
The Sodeguara plant, Eureka Industry Co. has a capa-
city of treating 1 million tons of residual oil (asphalt) from
vacuum distillation of heavy oil. The plant has been in smooth
operation since its start-up in March 1976. A flowsheet of the
process is shown in Figure 2-3. Residual oil containing 4 to 5%
uslfur is treated in reactors at 500°C for several hours with
steam preheated to above 700°C. The steam carries heat and pro-
motes distillation.
Typical product patterns and an economic balance are
shown in Tables 2-3 and 2-4. The cracked naphtha and gas oil
contain few heavy metal impurities and are easily treated by
hydrodesulfurization. The gas from the reactor contains about
15% H2S, which is removed by a conventional process using amine.
The purified gas (about 1,600 kcal/Nm3) is used for fuel. The
pitch, which contains 4-8% sulfur, is used by Sumitomo Metal as
a binder for poor-coking coal for coke production.
37
-------
CRUDE 100 ,
CO
OO
-|> GASOLINE, NAPHTHA
-§> KEROSENE 11
-^ GAS Of!. 16
ATMOSPHERIC
DISTILLATION
OA8 OIL 30
HEAVY OIL SO
u
«
>
VACUUM
RESIDUE 20
VACyUMGASOIL
HYORODis'uLFURIZATION
FLEXICOKING
COKE 0.6
LOW SULFUR OIL
(LSN 100) 42
• SULFUR
HIGH CALORIE GAS 2.6
AMINE& SODIUM
SCRUBBING
HYDRODESULFURIZATION
NAPHTHA
WET H3S REMOVAL
LOW CALORIE GAS 3
-^SULFUR
Figure 2-2. Material balance of crude oil treatments including Flexicoking.
-------
Co
VO
mo (V*CUMI nuiouo
^UOHTCIUCMOail
^FOULWATH
HEAVY CMHIO Oil
(TumnriMiunii
Figure 2-3. Flow sheet of Eureka process.
-------
TABLE 2-3, TYPICAL PRODUCT PATTERNS
Khafji
vacuum residue
Products
Gas
Cracked naphtha
Cracked gas oil
Pitch
Yield
(%w)
5.2
8.3
54.7
31.8
Sulfur
content
(%w)
14.5
1.9
3.6
7.6
Sulfur
distri-
bution
(%w)
14.2
3.0
37.2
45.6
Iranian Heavy
vacuum residue
Yield
(%w)
5.4
11.3
52.9
30.4
Sulfur
content
(%w)
10.7
1.7
2.5
4.4
Sulfur
distri-
bution
(%w)
16.8
5.6
38.5
39.1
Note: 1. Sulfur content of Khafji vacuum residue and Iranian Heavy
vacuum residue is 5.30 and 3.43 (£W) , respectively.
2. Main components of gas are
paraffins and olefins.
TABLE 2-4. ECONOMIC BALANCE OF RESIDUAL OIL CRACKING PROCESS
(1 million tons of vacuum residue per year ) ($1 - ¥300, in 1976)
Quantity
(million
tons/yr)
Cost
Unit price
(yen/kg) (
-------
2.4 CHERRY PROCESS7
Osaka Gas Co., jointly with Mitsubishi Heavy Indus-
tries, has developed a new asphalt decomposition process. The
new process solves a common problem, coking on the reactor wall,
by adding a small amount of pulverized coal to asphalt. A pilot
plant with a capacity of treating 10,000 tons of asphalt yearly
started operation in August 1976. A flowsheet is shown in
Figure 2-4.
Asphalt with a small amount of coal powder is heated
in a furnace, cracked and polymerized in a reactor at 410°C
under 15 atmospheric pressure (228 psi) for 3 to 5 hours, and
then led into a flash drum, where lighter fractions are separ-
ated. The bottom product of the flash drum is centrifuged to
separate liquid and solid. The liquid is sent to a distillation
column to produce a gas, oil and pitch. A typical example of
yield with asphalt from Iranian Heavy and Candian anthracite
coal powder is 670 gas, 7% naphtha, 97» kerosene, 18% gas oil,
10% vacuum gas oil, 33% pitch for binder, and 17% solids as a
coal substitute. A portion of the solids can be recycled to
the system. No coking on the reactor wall or effluent line
has been observed.
The product gas consists of 46% methane, 2270 ethane,
8% propane, 7% butane, 3% hydrogen, about 10% H2S, and other
components. Sulfur and nitrogen contents of the by-product
oil are shown in Table 2-5.
41
-------
6AS
COAL
SLURRV MIXER
A
FURNACE
ASPHALT
FRACTIONATOR
REACTOR
FLASH
DRUM
LIGHT FRACTION
MEDIUM FRACTION
VACUUM
DRUM
BINDER COOLER
BINDER & SOLIDS
(OR BINDER)
J
|> (SOLIDS)
DECANTING
CENTRIFUGE
Figure 2-4. Flow sheet of Cherry process.
-------
TABLE 2-5. S AND N CONTENTS OF PRODUCT OIL
FROM THE CHERRY PROCESS
S
N
(wt %)
(wt %)
Light
naphtha
0.26
0.0024
Heavy
naphtha
0.68
0.0083
Kerosene
0
0
.83
.023
Gas
1.
0.
oil
35
061
Vacuum
2.
0.
gas
46
27
oil
The H2S in the gas and S in the oils can be easily
removed by conventional processes. The pitch is useful as a
binder in coke production. The solids (coal substitute) are of
a quality suitable for coke production.
f
2.5 COAL-RESIDUAL.OIL HYBRID GASIFICATION PROCESS8
This process has been tested in a small pilot plant by
Hitachi Ltd. with financial support from the Sunshine Project.
Major items being studied are as follows:
1) The gasification reaction of a coal-residual oil
slurry with steam and oxygen under high pres-
sure and high temperature.
2) The structure of a fluidized bed gasifier.
3) A uniquely designed slurry feed system which
combats rapid abrasion and offers high pres-
sure and large capacity.
In the coal-residual oil hybrid gasification process,
as shown in Figure 2-5, a coal-residual oil slurry is converted
to gas and char in the first stage fluidized bed reactor by
heat from the second stage reactor. In the second stage reactor
43
-------
STEAM
COAL
r
RESIDUAL OIL
MIXINB
in STAGE 'J'"H*
REACTOR C0* H'°
CHAR
STEAMS to
OXYGEN'
HEAT
REACTOR
•ASH
' FUEL GAS
Figure 2-5. Flow sheet of coal-residual oil
hybrid gasification
44
-------
the char produced in the first stage reactor is partially oxi-
dized with steam and oxygen.
One advantage of this process is that not only coal
but also residual oil, which is very difficult to desulfurize,
can be converted to a clean fuel gas. Another advantage is
that powdered coal mixed with residual oil can be easily charged
to the pressurized fluidized bed gasifier.
Tests and Results
Following bench scale tests, a gasifier with the fol-
lowing specifications was constructed in 1975:
1st stage (thermal cracking of slurry) 120 mm diam. ,
2,000 mm long
Gasifier:
2nd stage (partial oxidation of char) 80 mm diam.,
2,000 mm long
Max. pressure: 70 kg/cm2G (1,000 psig)
Max. feed rate: 15 kg/hr (33 Ibs/hr)
The experimental conditions and results with this
apparatus are as follows:
1) Experimental conditions
Pressure: 5-20 kg/cm2G
(1st stage: 700-800°C
Temperature }2nd 8taj|e: 900-950'C
Slurry feed rate: 1-3 kg/hr
•P^A T«o«-Q,-;Qio JCoal - Taiheiyo coal
Feed materials {Residual oil f Gach Saran
vacuum residue
Coal:Residual oil = 30:70 (wt)
45
-------
2) Results
In the first stage, thermal cracking of
coal-residual oil slurry, the main compo-
nents of the product gas are H2 and CHi»:
the higher the temperature, the greater the
yield of CH*; and the higher the pressure,
the greater the yield of C2H6 and C3H6.
In the second stage, oxidation of char, the
gases produced are mainly H2, CO and C02,
which are in equilibrium by the following
reaction:
CO + H20 + C02 + H2
The heating value of the product gas is
about 4,000 kcal/Nm3 (450 Btu/ft3). (When
H2S and C02 are removed the value reaches
6,000 kcal/ttn3 (670 Btu/ft3)).
Heat transfer from the second stage reactor
to the first stage reactor by hot char and
gas improves the overall thermal efficiency
of the process.
In order to make better use of the heat of the hot
char, Hitachi proposed a new type of gasifier in which the hot
char is circulated between the first and the second stage reac-
tors. A new plant named Equipment Development Unit with a 300
mm-diameter gasifier was constructed in March, 1977.
The Hybrid Gasification Process needs a slurry feed
system that overcomes rapid abrasion and offers a high
46
-------
pressure and a Large capacity. A unique slurry feed system
named "Hydrohoist," developed by Hitachi, was modified and
applied to the coal-residual oil slurry. A 50% (by weight)
coal slurry can be pumped at 190°C.
Tests are in progress to obtain data necessary to de-
sign (in 1978) a pilot plant with a capacity of treating 12-15
tons/day of the coal-residual oil slurry to produce 7,000 Nm3/
day of synthetic natural gas.
2.6 LOW-CALORIFIC GASIFICATION OF COAL8
<
The Coal Mining Research Center has been developing a
low calorific gasification process for electric power genera-
tion. This is one of the most forerunning of all the coal con-
version programs being conducted by the Japanese government
under the full-funded "Sunshine Project".
The process adopts a two-stage fluidized bed gasifier
(Figure 2-6). Crushed coal is fed through a lock-hopper system
into the upper stage of the gasifier, which functions as a car-
bonizer by devolatilizing feed coal with a hot gas stream flow-
ing upward from the lower stage of the gasifier. Char carried
over by crude gas is separated in cyclones and recycled to the
lower stage of the gasifier, where char is partially burned with
air to generate the heat necessary for gasifying the remaining
char with steam. Ash is withdrawn through a lock-hopper system
from the bottom or from an overflow outlet near the bottom of
the gasifier. Tar in crude gas, if any, is washed out by water
scrubbing. Before any dry gas-cleanup process becomes practi-
cal, a Benfield unit will have to be used to remove sulfur com-
pounds in the product gas.
47
-------
oo
CYCLONES
COAL ,
\
TWO STAGE
GASIFIER
STEAM
AIR
CHAR
WASH TOWERS
ASH
ASH HOPPER
COOLING
WATER
COOLING TOWER
COOLING WATER
TAR
ACCUMULATOR
FUEL GAS
I RAWWATER
WASTE WATER
AND TARS
Figure 2-6. Flow sheet of low calorific coal gasification
-------
Based upon the gasifier conception described above,
a 200 kg coal/hr gasification test plant for operation under
10 atmospheres pressure was designed and constructed in 1974.
Following a number of shakedown tests, the plant started gasi-
fication operation late in 1975. 3ince then, more than 50 runs
have been made using Taiheiyo coal, a noncaking coal produced
in Hokkaido, as feedstock. The gasification temperature and
pressure were in the ranges of from 975 to 1,095°C and up to 7
atmospheres gauge, respectively; while feed coal varied between
0.28 and 0.50 mm in mean particle size. Given below are the
main operation conditions as well as some results from one of
the long runs in the series: (
Coal feed rate 128 kg/hr
Gasification temperature 950°C
Gasification pressure 7 atm.G
Gas output rate 324 Nm3/hr
Gas composition
H2 19.4%
CO 11.2%
CH^ 1.0%
C02 16.4%
N2 49.6%
02 0.7%
Gas heating value 1,300 kcal/Nm3
During these gasification runs, some problems were en-
countered. Among them, clinker formation at the gasifier bottom
was the most troublesome. It took some time to find that the
gasification temperature should be kept considerably lower than
the melting point of the ash contained in the feedstock in order
to avoid such a trouble, and that the velocity of the gasifica-
tion reagents blown into the gasifier through the distributor
49
-------
was an important factor. Another major problem was by-product
tar, which may be diminished by temperature elevation at the
upper stage of the gasifier. However, the difficulty in sep-
arating low-carbon ash from the gasifier, a common fundamental
drawback of fluidized beds, still remains to be solved. The
Coal Mining Research Center plans to start basic research for
dry gas-cleanup and ash agglomeration methods.
Tests with a 40 ton/day gasification pilot plant are
expected to begin in 1979, and a demonstration plant including
combined cycle generators is expected to start in 1981.
2.7 OTHER COAL TREATING PROCESSES
There are a few unique coal treating processes being
tested in a small scale, funded by the Sunshine project. They
will be described below.
In addition to these processes, solvent refining of
coal has been studied by the Mitsui SRC group. A pilot plant
with a capacity of treating 5 ton/day of coal was put into oper-
ation in early 1978. The study aims at the production of a
binder for the production of coke for steel mills from non-
coking coal. No data have been published on the study.
2.7.1 Solvolysis Liquefaction8
A study was originated at the Kyushu Industrial
Technology Laboratory as an attempt to liquefy coal with as-
phalt (vacuum residue) by the "Solvolysis" reaction at about
400°C. The process is expected to have the following advantages
1) The liquefaction reaction can be carried out
at atmospheric pressure without using hydrogen.
50
-------
2) The coal ash formed by the reaction has a
special property which makes it readily
separable.
The study has been funded by the Sunshine Project.
Mitsubishi Heavy Industries has joined the project for further
development. Following these batch tests, a 1 ton/day pilot
plant is near completion. A flow sheet of the process is shown
in Figure 2-7.
By using Khafji vacuum residue with Miike coal at an
equal weight and reacting them at 370°C for 1 hour, about 4070
of the coal was liquefied. By using a pitch obtained from the
Khafji vacuum residue, much tietter liquefaction of the coal was
attained but the separation of the ash was difficult. The reac-
tivity, as well as the properties of the product, was found to
vary widely with the type of coal and asphalt or pitch. Studies
are being continued to search for suitable combinations and
optimum conditions.
2.7.2 Plasma Gasification of Coal5
Plasma gasification aims at obtaining useful gases
such as acetylene and hydrogen from coal by means of a plasma
jet.
The plasma jet is a high-temperature, dense-energy
electromagnetic fluid which is formed through a direct current
arc discharge and is ejected in a jet through a nozzle. The
temperature of plasma jets ranges between 10,000 K and 30,000 K.
Experiments have been performed to obtain useful gases
(C2H2, C2Hi», H2, CO, etc.) from various hydrocarbons, petroleum,
and coal using a plasma jet. The maximum capacity of the plasma
51
-------
Ol
NJ
COAL
ASPHALT
MIXING
HEATING
REACTION
CONDENSATION
SEPARATION
•GAS
LIGHT OIL
DISTILLATION
•OIL
SEPARATION
SOLIDS
REFINED PITCH
Figure 2-7. Flow sheet of solvolysis liquefaction,
-------
generator used for these experiments is 15 kW. Table 2-6 shows
results obtained.
TABLE 2-6. PRELIMINARY RESULTS OF PLASMA GASIFICATION
Yield of acetylene
Feedstock (g/kWh) Note
n-Paraff in
Cyclohexane
Tetraline
Gas oil
Coal
75-105
101
101
99
15
Noticeable amount of
C2Hi» is produced
Plasma gas: H2
Flow rate: 100 liters/min
Since the conversion efficiency was low with coal,
further tests have been performed to increase the efficiency
by using a special plasma generator. The generator consists of
three separate torches tilted so as to focus on one point in
order to provide better mixing of the plasma flame and coal.
A 100 kW plasma gasifier with three tilted torches has been
used.
2.7.3 Coal Gasification by the Molten Salt Lime Slurry
Process
This process has been tested by Mitsubishi Heavy
Industries with a fund of the Sunshine Project. The process
uses a gasifier and a lime regenerator with a circulating slurry
of lime in molten salts (Figure 2-8). Pulverized coal and steam
are fed into the molten salt bath at nearly 900°C to generate
H2, CO, C02, CH^, etc. Lime in the slurry readily reacts with
C02 to form CaC03. Heat released from this reaction is useful
53
-------
GASIFIER 900°C
STEAM 2. fr
Ul
SYNTHESIS OAS
CRUDE OAS
GAS/LIQUID
SEPARATOR
METHANATOR
CU
MOLTEN SALT
LIME SLURRY
AIR
WASTE GAS
LIME REOENERATOR
fOOO°C
•2. AIR
OAS CLEANINO
HEOENERATED SALT
AND CALCIUM CARBONATE
1 MAKE-UP SALT
ASH REMOVAL SYSTEM
.WATER
ASH
Figure 2-8. Flow sheet of molten salt lime slurry process.
-------
in promoting the endothermic reactions between the steam and
coal. A portion of the heat required for the gasification is
supplied by circulating the molten salts at 1,000°C. Sodium
and potassium nitrates and chlorides may be used as the salts.
The slurry containing calcium carbonate and char
formed by the reaction is withdrawn from the gasifier and sent
to the lime regenerator. Air is blown into the regenerator to
burn the char and to regenerate lime by the heat. The slurry is
then recycled to the gasifier.
The gas produced in,the gasifier is passed through
waste heat recovery, purification, and methanation steps to
produce a high calorie fuel gas.
The process has the advantage of producing a high-
calorie gas using no oxygen. Another advantage is that the
lime reacts with H2S from coal so that the gas leaving the gasi-
fier is virtually free from sulfur. The rates of the reaction
of lime with C02 and H2S are much larger in the molten salt than
in a conventional fluidized bed.
The process, however, may have the following problems
to be solved:
1) Corrosion may be caused by the molten salt and
result in the loss of molten salt.
2) Coal ash reacts with lime, resulting in an
incomplete separation of the ash.
3) The slurry may be too viscous at a high con-
centration.
4) Transportation of the molten salt slurry may
not be easy on a large scale.
55
-------
2.8 FLUIDIZED BED COMBUSTION OF COAL
Fluidized bed combustion (FBC) of coal has not been
considered as promising in Japan as in the U.S., mainly because
of the difficulty in discarding the by-product ash which con-
tains lime and calcium sulfate. However, since increasing use
of coal is desired, a few companies have started small scale
tests of FBC aiming to develop their own technology to reduce
both S0x and N0x emissions and to improve thermal efficiency.
Coal Industry Council of Ministry of International
Trade and Industry (MITI) made a recommendation in 1977 con-
cerning the use of coal in which FBC was stated as one of the
important items. In 1978 MITI has a budget of ¥56 million
to promote the study of FBC by process developers. One half
of the expense for the studies is going to be subsidized by
the fund. MITI has the following tentative plan for the develop-
ment of FBC.
1979 - 1981 Pilot plant, about 1.5 MW equivalent
1981 - 1983 Demonstration plant, about 30 MW
From 1984 Prototype plant, about 100 MW
2.8.1 Babcock Hitachi Ltd.
Following basic studies, Babcock Hitachi has carried
out bench-scale tests using a furnace 550 x 550 mm in bed size
and 5120 mm in height with a capacity of burning 100 kg/hr of
coal. Domestic coal, Miike coal (S = 2.5%) and Taiheiyo coal
(S = 0.3%) have been used for combustion at 800-900°C under at-
mospheric pressure. Granular limestone has been used to remove
about 90% of S02 and to separate the calcined limestone (a mix-
ture of calcium sulfate and lime) from fly ash.
56
-------
Actually, a considerable portion of the calcined
limestone becomes powdery and is lost with the fly ash. Babcock
Hitachi is going to use a synthetic granular absorbent which
does not break in the furnace. This absorbent can be separated
from fly ash and regenerated by heating which releases con-
centrated S02 gas. This gas may be used for sulfuric acid pro-
duction.
Two stage combustion has been used to reduce N0x to
about 150 ppm.
2.8.2 Kawasaki Heavy Industries
Kawasaki Heavy Industries started tests of FBC two
years ago, finished studies using a small furnace (100 x 100 mm
in bed size), and has started tests with a larger furnace with
a 500 x 500 mm bed capable of combusting 60 kg/hr of coal.
About 90% of S02 is removed using dolomite.
2.8.3 Mitsui Engineering and Shipbuilding
Mitsui Engineering and Shipbuilding Co. is going to
install a small test plant of FBC. The objective is to apply
FBC of coal to ship engines and to improve thermal efficiency.
S02 removal has not been considered.
57
-------
SECTION 3
GENERAL ASPECTS OF FLUE GAS DESULFURIZATION
3.1 MAJOR FGD PROCESSES AND PLANTS
Table 3-1 lists major constructors of FGD plants and
numbers and capacities of plants operational at the end of 1977.
The plants totaled nearly 600 and their combined capacity reached
89,000,000 Nm3/hr (equivalent to 29,000 MW) . About half of this
capacity is accounted for by utility boulers (mostly oil-fired).
The rest is accounted for by industrial boilers, iron-ore sin-
tering machines, nonferrous metal industry, sulfuric acid plants,
etc.
About 507o of all the plants, in terms of capacity, use
the wet lime/limestone process to by-produce gypsum, 16% use the
indirect lime/limestone process (double alkali type), 13% use
regenerable processes to by-produce sulfuric acid, ammonium sul-
fate and elemental sulfur, and 24% use sodium scrubbing to by-
produce sodium sulfite or sulfate. About 8070 of the sodium
scrubbing plants by-produce sodium sulfite for paper mills. The
rest oxidize the sulfite by air bubbling to sulfate, which is
either used in the glass industry or purged in wastewater.
The average plant capacity is 426,000 Nm3/hr for the
wet lime/limestone, 286,000 Nm3/hr for the indirect lime/
limestone, 379,000 Nm3/hr for the regenerable processes, and
61,800 Nm3/hr for the sodium scrubbing processes. In addition
to the 392 sodium scrubbing plants listed in Table 3-1, there
58
-------
TABLE 3-1. NUMBERS AND CAPACITIES (1,000 Nm /hr) of FGD PLANTS
BY MAJOR CONSTRUCTORS (OPERATIONAL AT END 1977)
Ul
vo
Plant constructor
Mitsubishi Heavy Industries (Mill)
Ishlkawaj ima H.I. (IHI)
Hitachi, Ltd.
Mitsubishi Kakokl (MKK)
Kawasaki Heavy Industries
Tsuklshima Klkal (TSK)
Chiyoda Chemical Eng. & Construe.
Ojl Koel
Fuji Kasui Engineering
Kurabo Engineering
Mitsui Miike-Chemlco
Ebara Manufacturing
Nippon Kokan (NKK)
Kureha Chemical
Showa Denko
Gadelius
Sumitomo (SCEC) -Wellman
Mitsui Metal Engineering
Kobe Steel
Japan Gasoline
Dowa Engineering
Niigata Iron Works
Mitsui Shipbuilding
Sumitomo Heavy Industries
Total
Wet lime/ Indirect lime/ H2SOu , S
limestone limestone (NIU)2SOi.
33 (18,270)
17 ( 4,445)
13 ( 6,940)* 2 ( 590)
2 ( 256) 13 (6,478)h
4 ( 756) 6 (5,450)
1 4 ( 398) 1 ( 88)
14 (4,459)
7 ( 3,954)
5 ( 413) 1 ( 18)
4 ( 2,744) 1 ( 500)
11 (1.914)
3 ( 245) 1 ( 150) 2 (1,990)
6 (1,288)
4 ( 1,006) 2 ( 130)
5 ( 1,125)
1 ( 330) 1 ( 125)
5 ( 500)
1 ( 185)
1 ( 150)
94 (40,071) 47 (13,422) 30 (11,357)
Na2SO,
Na2SO,,
3
79
15
41
7
40
57
6
106
10
6
8
5
8
1
392
( 292)
(4,351)
( 603)
( 913)
( 256)
(4,042)
(4.280)
( 270)
(3,751)
(1,167)
( 62)
(1,431)
(1.372)
(1,291)
( 160)
(24, i/t\)
3(.
96
30
56
17
/i 6
14
57
13
112
5
21
12
8
5
8
6
6
5
2
5
1
1
1
5t>t
Total
(18,562)
( 8,796)
( 8.13J)
( 7,643)
( 6,380)
( 4,528)
( '.,459)
( 4.280)
( 4,224)
( 4.182)
( 3,244)
( 3.081)
( 2,447)
( 1,431)
( 1,372;
( 1,291)
( 1,288)
( 1,136)
( 1,125)
( 455)
( 500)
( 185)
( 160)
( 150)
(84. 052)
* Babcock - Hitachi
1 Wellman - MKK
-------
are nearly 500 smaller ones operated commercially with an aver-
age capacity of about 20,000 Nm3/hr.
Flue gas desulfurization in Japan has made remarkable
progress since 1972. The rapid growth was due to both the eco-
nomic advantage of FGD over the use of low-sulfur fuels and to
the reliability of FGD plant operation. The growth, however,
is likely to slow down after 1977 for the following reasons:
1) Ambient S02 concentration in large cities and
industrial districts has decreased to 0.02-0.03
ppm, almost meeting the ambient standard.
2) The recent economic depression has prevented
industry from building new plants.
3) FGD by-products are being overproduced.
4) The cost difference between low and high sulfur
oils is decreasing.
An increase in the use of coal for power generation,
however, will result in a need for more FGD plants. At present
one FGD plant is under construction and two are to be completed
by 1979 for new coal-fired utility boilers.
3.1.1 Status of FGD for Power Companies
Table 3-2 lists power companies along with their
capacities of steam power generation and FGD. The nine major
companies (Nos. 1 to 9 in the Table) have produced about 86% of
the total steam power. They mainly use oil, but also use some
LNG and a little coal. Electric Power Development Co.
60
-------
TABLE 3-2. CAPACITIES OF STEAM POWER GENERATION AND FGD OF POWER COMPANIES
Power generation (MW)
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Under
Power company Existing construction* Total (A)
Hokkaido
Tohoku
Tokyo
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Kyushu
EPDC
Niigata
Showa
Toyama
Mizushima
Sumitomo
Sakata
Fukui
Others
Total
1,270
3,925
19,167
9,933
1,412
10,672
3,777
2,687
4,500
1,430
350
550
750
462
368
0
0
5,512
66,765
1,225
1,200
4,400
3,800
1,000
1,200
1,800
450
2,700
1,000
350
0
0
0
250
700
250
375
20,700
2,495
5,125
23,567
13,733
2,412
11,872
5,777
3,137
7,200
2,430
700
550
750
462
618
700
250
5,887
87,665
FGD (MW)
Under
Existing construction* Total(B)
0
550
283
970
600
930
1,350
900
1,376
1,280
175
400 -
250
156
156
700
0
0
10,076
525
350
0
0
500
0
700
0
250
1,000
175
0
0
0
0
0
250
0
3,750
525
900
283
970
1,100
930
2,050
900
1,626
2,280
350
400
250
156
156
700
250
0
13,826
B/A
21.0
17.6
1.2
7.1
45.6
7.8
35.5
28.7
22.6
93.8
50.0
72.7
33.3
33.8
25.2
100.0
100.0
0.0
15.8
* Including those decided to be constructed
-------
(EPDC, No. 10 in the Table), which was established by the nine
major companies and the Central Government, has been the major
consumer of domestic coal for power generation. Other power
suppliers, which have relatively small capacities, mainly burn
oil. The total capacity of the power generation plants, includ-
ing those under construction and those scheduled to be con-
structed, is 87,665 MW. The capacity of FGD plants in operation
is 10,076 MW. The capacity of plants under construction and
being designed is 3,750 MW.
Tokyo Electric, Kansai Electric, and Chubu Electric
are the major power companies in Japan. These three companies
supply power to the largest cities and industrial complexes
in Japan, but have FGD plants of relatively small capacities,
with an FGD/power generation ratio of only 1-8%. In polluted
areas, these companies prefer to use a clean fuel such as LNG
instead of using heavy oil and applying FGD. This is because
the regulations on SOz and NOX emissions for these areas may
become too stringent to be met by FGD and combustion control in
plants using heavy oil. On the other hand, Hokuriku Electric
and Chugoku Electric, which have power plants distant from big
cities, have larger FGD/power generation ratios.
FGD installations of power companies are listed in
Tables 3-3 and 3-4. Before 1973, power companies were not
confident about the reliability of FGD. Between 1973 and 1976
they constructed many full-scale FGD plants for utility boilers
ranging from 250 to 500 MW, burning high (2.5-3%) sulfur fuel,
and using processes which by-produce gypsum. The growth in FGD
use was stimulated by the large cost difference between high-
and low-sulfur oils and by a shortage of gypsum.
The recent oversupply of gypsum and relatively low
cost of low-sulfur fuel oil due to economic depression has
62
-------
TABLE 3-3. FGD PLANTS OF POWER COMPANIES (I) (FOR OIL-FIRED BOILERS)
u>
Power
company
Tohoku
Tokyo
Chubu
Hokuriku
Kansai
Chugoku
Boiler
Power station
Shinsendai
Hachinohe
Niigata
Niigata H.
Akita
Kashima
Yokosuka
Nishinagoya
Owase
Owase
Toyama
Fukui
Nanao
Sakai
Amagasaki
Amagasaki
Osaka
Osaka
Osaka
Kainan
Mizushima
Tamashima
Tamashima
Shimonoseki
No.
2
4
4
1
3
3
1
1
1
2
1
1
1
8
2
1
3
2
4
4
2
3
2
2
MW
600
250
250
600
350
600
265
220
375
375
500
350
500
250
156
156
156
156
156
600
156
500
350
400
FGD
MW
150
125
125
150
350
150
133
220
375
375
250
350
500
63
( 35
\121
156
156
156
156
150
100
500
350
400
Process
developer
Kureha -Kawasaki
Mitsubishi H.I.
Wellman-MKK
Mitsubishi H.I.
Kureha -Kawasaki
Hitachi-Tokyo
Mitsubishi H.I.
Wellman-MKK
Mitsubishi H.I.
Mitsubishi H.I.
Chiyoda
Chiyoda
Not decided
Sumitomo H.I.
Mitsubishi H.I.
Mitsubishi H.I.
Mitsubishi H.I.
Babcock-Hitachi
Babcock-Hitachi
Babcock-Hitachi
Mitsubishi H.I.
Babcock-Hitachi
Babcock-Hitachi
Babcock-Hitachi
Mitsubishi H.I.
Absorbent,
precipitant
Na2S03, CaC03
CaO
Na2S03
CaC03
Na2S03 , CaC03
Carbon, CaC03
CaC03
Na2S03
CaO
CaO
H2SOi», CaC03
H2SOi», CaC03
Carbon
CaO
CaO
CaO
CaC03
CaC03
CaC03
CaO
CaC03
CaC03
CaC03
CaC03
By-product
Gypsum
Gypsum
R2SQ*
Gypsum
Gypsum
Gypsum
Gypsum
H2S04
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
H2SO,,
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Year of
completion
1974
1974
1976
1976
1977
1972
1974
1973
1976
1976
1974
1975
1978
1972
1973
1975
1976
1975
1975
1976
1974
1974
1975
1976
1976
-------
TABLE 3-4.
FGD PLANTS OF POWER COMPANIES (II)
-J'IRED BOILERS)
Power
company
Shikoku
Kyushu
EPDC
Niigata
Showa
Toyama
Mlzushlma
Sumitomo
Sakata
Fukui
Power
station
Anan
Sakaide
Karita
Karatsu
Karatsu
Ainoura
Alnoura
Buzen
Buzen
Takasago
Isogo
Takehara
Hatsushima
Matsushlma
Niigata
Ichihara
Ichihara
Toyama
Mizushima
Nilhama
Sakata
Sakata
Fukui
Boiler
No.
3
3
2
2
3
1
2
1
2
1
2
1
2
1
1
1
1
1
5
1
5
3
1
2
1
MW
450
450
375
375
500
375
500
500
500
250*
250*
265*
265*
250*
500
500
350
150
250
250
156
156
350
350
250
FGU
MW
450
450
188
188
250
250
250
250
250
250
250
265
265
250
500
500
175
150
250
250
156
156
350
350
250
Process
developer
Kureha-Knwasaki
Kureha-Kawnsaki
Mitsubishi II. I.
Mitsubishi II. I.
Mitsubishi II. I.
Mitsubishi II. T.
Mitsubishi II. 1.
Kureha-Kawasaki
Kureha-Kawasakl
Mitsul-Chemlco
Mitsui-Chemlco
Cheraico-IHI
Cheraico-IHI
Babcock-Hitachi
Not decided
Not decided
MHI
Showa Denko
Babcock-Hitachi
Chiyoda
Mitsubishi H.I.
IHI
Mitsubishi II. I.
Mitsubishi H.I.
Not decided
Absorbent,
precipitant
Na?S03, CaCOj
Nn2S03, CaCO 3
CaO
CaCOj
CaCO 3
CaCO 3
CaC03
Na2S03, CaCO]
NazS03> CaCOj
CaCOi
CaCO]
CaCO]
CaCO)
CaCO)
CaCO 3
CaCOj
CaCO 3
Na2SOj, CaCO 3
CaCO,
H2SOi,, CaCO 3
CaO
CaCO 3
CaCO 3
CaCO}
CaCO 3
By-prod UCL
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
GypHutn
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Year nf
complct l
1975
1974
1976
1976
1976
1976
1977
1978
1975
1976
1976
1976
1977
1980
1980
1975
1973
1976
1975
1975
1975
1976
1977
1977
*Coal-fired boilers. Others are for oil-fired boilers.
-------
restricted further construction of FGD plants. However, in-
creased use of coal for power generation will necessitate more
FGD plants. A plant for a new 175 MW coal-fired utility boiler
is to be completed in 1978; two plants, each for a new 500 MW
coal-fired utility boiler, will be completed in 1979. All three
use the lime/limestone-gypsum process.
3.1.2 Status of FGD for the Steel Industry
In Japan, iron ore sintering machines are collectively
one of the largest S02 sources'other than boilers. Many desul-
furization units have been installed since 1971 to treat steel
industry flue gas (Table 3-5). The absorbents used in the FGD
units are a lime slurry, used by Kawasaki Steel (MHI process);
a limestone slurry, used by Sumitomo Metal (Sumitomo-Fugikasui
Moretana process); a slurry of pulverized converter slag, used
by Nippon Steel (SSD process); and a calcium chloride solution
dissolving lime, used by Kobe Steel (Cal process). All of these
plants by-produce gypsum. Nippon Kokan uses ammonia scrubbing
to by-produce either ammonium sulfate or gypsum by reacting
lime with the sulfate.
By 1977, 22 FGD plants had gone into operation with a
total capacity of treating 13,800,000 Nm3/hr (8,120,000 scfm)
of flue gas. This is about one-half the total flue gas from
all sintering plants in Japan.
Flue gas from sintering plants is characterized by a
high 02 concentration (12-16%), relatively low S02 concentration
(200-1,000 ppm) , and a dust content rich in ferric oxide.
Oxidation of sulfite into sulfate occurs in the scrubbers much
more readily than with flue gas from a boiler, because the oxi-
dation is promoted by the high 02/S02 ratio and also by the
catalytic action of the ferric oxide.
65
-------
TABLE 3-5. S02 REMOVAL INSTALLATIONS FOR WASTE GAS FROM IRON-ORE SINTERING MACHINES
ON
ON
Steelmaker
Kawasaki Steel
Sumitomo Metal
Kobe Steel
Nakayama Steel
Nippon Steel
Nippon Kokan
Plant site
Chiba
Chiba
Chiba
Mizushima
Mizushima
Mizushima
Kashima
Kashima
Kashima
Wakayama
Kokura
Amagasaki
Kobe
Kakogawa
Osaka
Tobata
Wakamatsu
Keihin
Fukuyama
Ogishima
Gas treated
(1,000 Nra3/hr)
120
320
650
750
900
750
880
1,000
1,000
370
720
175x2
375
1,000x2
375
200
1,000
150
760
1,230
Process
MHI
MHI
MHI
MHI
MHI
MHI
Moretana
Moretana
Moretana
Moretana
Moretana
Cal
Cal
Cal
Cal
SSD
SSD
NKK
NKK
NKK
Absorbent
CaO
CaO
CaO
CaO
CaO
CaO
CaCOa
CaCOs
CaCOa
CaCOs
CaCOa
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
Slag
Slag
NH3, CaO
NH3*
NH3*
Year of
completion
1973
1975
1976
1974
1975
1977
1975
1976
1977
1975
1976
1976
1976
1977
1976
1974
1976
1971
1976
1977
Gypsum (t/year)
3,600
13,200
26,500
27,600
32,400
27,600
32,400
40,500
40,500
14,400
26,500
12,600
12,600
72,000
13,500
7,200
32,400
7,200,
12,OOOT
20,000
* Ammonia in coke oven gas
Ammonium sulfate
-------
3.1.3 Status of FGD for Nonferrous Smelters
Major FGD plants at nonferrous metal smelters (copper,
zinc, and lead) are listed in Table 3-6. In these smelters,
dilute S02 gas (1-3% in concentration) is circulated to the
sintering machine or roaster to give concentrated S02 which is
used for sulfuric acid production. More dilute S02 streams and
sulfuric acid plant tail gas containing 400-2,000 ppm S02 are
treated by FGD.
FGD plants constructed in 1970 and 1971 use sodium
s-crubbing to by-produce sodium'sulfite for paper mills. Other
processes have been used since 1972 because of oversupply of the
sulfite. In 1972 and 1973, three plants using magnesium and
zinc scrubbing were constructed to recover S02 in a concentrated
form which is sent to sulfuric acid plants. Most of the plants
constructed recently use the wet lime/limestone process to by-
produce gypsum.
At most smelters, overall S02 recovery by sulfuric
acid production and FGD reaches 99%.
3.2 BY-PRODUCTS
3.2.1 By-Product Production and Economics
Desulfurization efforts in Japan have been oriented
toward processes that yield salable by-products (Figures 3-1
and 3-2), because Japan is subject to limitations in domestic
supply of natural sulfur and its compounds and to limitations in
land space available for disposal of useless by-products. About
60% of the SO2 is converted into salable gypsum, 20% into sodium
67
-------
TABLE 3-6. MAJOR FGD PLANTS OF LEADING NONFERROUS SMELTERS
Plant owner
Shlmuru Kako
Sumlko ISP
Sumitomo Mining
Dowa Seiko
Nippon Mining
Furukawa Mining
Onahama Smelting
Mitsui Mining
00
Hachinohe Smelting
Hlbe Kyodo Smelting
Dowa Mining
Kowa Seiko
Mitsubishi Cominco
Plant site
Muroran
Kakogawa
Niihama
Toyo
Amagasaki
Saganoseki
Saganoseki
Ashio
Onahama
Onahama
Onahama
Onahama
Hibi
Kamioka
Hibi
Hachinohe
Hibi
Okayama
Tobata
Naoshima
Gas source
Nickel converter
Sintering furnace
Nickel smelter
HjiSOi, plant
Pellet iz ing
H2SOi, plant
H2SOi, plant
H2SO<, plant
Reverberatory
Reverberatory
Reverberatory
H2SOi» plant
Copper smelter
H2SOi» plant
H2SOi» plant
Zinc smelter
Smelter
H2SOi» plant
Copper remover
Lead Smelter
Gas treated
(Nm3/hr)
20,000
60,000
150,000
125,000
47,000
126,000
120,000
60,000
92,000
120,000
110,000
203,000
90,000
48,000
300,000
60,000
200,000
300,000
50,000
13,000
Process
developer
TSK
Sumitomo
TSK
IHI
Dowa Seiko
IHI
Showa Denko
IHI
MHI
IHI
TSK
IHI
Mitsui Mining
Mitsui Mining
Mitsui Mining
Mitsui Mining
Mitsui Mining
Absorbent
NaOH
NaOH
NaOH
NaOH
NaOH-CaC03
CaO
CaO
CaO
MgO
CaO
MgO
ZnO
CaO
ZnO
CaO
Dowa Al2(SOi»)3-CaC03
IHI
CaO
CaO
By-product
Na2S03
Na2S03
Na2S03
Na2S03
Gypsum
Gypsum
Gypsum
Gypsum
H2SO,»
Gypsum
H2SO<,
H2SOi,
Gypsum
H2SO.,
Gypsum
Gypsum
Gypsum
Gypsum
Year of
completion
1970
1970
1970
1971
1970
1970
1971
1972
1972
1972
1972
1972
1972
1972
1973
1973
1975
1974
1975
1976
-------
10,000
o
4-1
O
CO
O (!)
iH
C cd
o o
•H CO
3 00
•o o
O iH
M >-^
eu
1,000
100
10
desulfurization
1969
1971
1973
1975
1977
Figure 3-1. Production capacity of desulfurization.
c
o
o
•H
20
15
10
1969
1971
1973
1975
1977
Figure 3-2. Price of by-products.
69
-------
sulfite, 15% into sulfuric acid, and the rest into waste calcium
sulfite and sodium and ammonium sulfates.
Sodium scrubbing to by-produce sodium sulfite for
paper mills is the process which first became popular because
it is the easiest method of FGD. By-production of sodium sul-
fate will not increase much in the future because the supply
has already filled the demand and because sodium hydroxide,
which is used by this method, has become expensive.
By-product gypsum can be grown into fairly large
crystals and is useful for wallboard production and as a
retarder of cement setting (Figure 3-3). Since 1975, gypsum
has been in oversupply due to a decrease in demand by economic
depression and to a rapid increase in FGD plants producing
gypsum. The selling price of most by-product gypsum, including
gypsum from phosphoric acid production and other sources as
well as FGD, has dropped to zero. The phosphogypsum was sold
for about 3,000 yen/ton before 1974. It compensated for the
relatively high cost of sulfuric acid used in the Japanese phos-
phoric acid industry. As a result of the drop in the price of
gypsum, import of phosphoric acid has begun and a few smaller
plants have been shut down.
Sulfuric acid has been produced by the Wellman-Lord,
magnesium and zinc scrubbing processes. The production will
not increase much because demand for sulfuric acid has leveled
off due to the decrease in wet process phosphoric acid produc-
tion caused by the oversupply of gypsum.
Elemental sulfur has been produced at four oil refin-
eries by introducing recovered S02 into existing Glaus furnaces.
For SO2 recovery, the Wellman-Lord, Shell and magnesium
70
-------
scrubbing processes have been used. Since large quantities of
elemental sulfur are recovered by hydrodesulfurization of heavy
oil, production of elemental sulfur at power plants by FGD may
not be competitive unless an economical process is developed.
6
^•n U.
r* "
)-i
O
4J
§ 2
•H
iH
iH
g
n
-
OU
B
C
OS
F
P
OU
B
C
OS
F
P
OU
B
C
OS
F
P
OU
B
C
OS
F
P
1973
1975
1977
1979
Demand: C: Cement B: Board OU: Other uses
Supply: P: Phosphogypsum F: FGD OS: Other sources
Figure 3-3. Demand for and supply of gypsum.
The production of ammonium sulfate increased consider-
ably in a recent year due to the completion of two ammonia
scrubbing plants of Nippon Kokan.
Throwaway calcium sulfite sludge has been produced at
the Omuta plant, Mitsui Aluminum. The sulfite slurry is dis-
charged into a big pond and the supernatant is recycled to the
scrubber. In two other smaller plants, the slurry is filtered
and discarded.
71
-------
3.2.2 Quality and Use of FGD Gypsum
The FGD by-product gypsum has a crystal size of 50-200
microns in length, 20-50 microns in width, and 10-20 microns in
thickness, and is easily centrifuged to less than 10% moisture.
It is useful for wallboard and as a cement setting retarder.
Examples of the composition of the gypsum and the strength of
the calcined product (0 form hemihydrate) are shown in Table
3-7. The gypsum is strong enough not only for wallboard but
also for plaster. However, except for a few products derived
from flue gases from oil-fired boilers equipped with high-
efficiency electrostatic precipitators, the gypsum is not
usually used for plaster because of a dark color due to fly
ash and unburned carbon. A product from the tail gas of a
sulfuric acid plant of Dowa Mining Co. has been sold as gypsum
for molding at ¥3,000/ton. By-product gypsum from most other
sources has been given away, sometimes with the delivery charge
paid by the FGD plant owner.
Unlike phosphogypsum, a by-product of wet process
phosphoric acid, FGD gypsum does not contain impurities which
affect quality such as fluorine and phosphoric acid. Gypsum
containing less than about 5% fly ash is useful for wallboard.
Gypsum containing 10-20% fly ash from coal such as the product
at the Isogo plant, EPDC, is still useful for cement setting
retarder.
Gypsum by some of the indirect or modified lime/
limestone processes contains a relatively large amount of
sodium, magnesium, or chlorine, but these impurities are within
0.5% in most cases and do not affect quality. This gypsum is
usually filtered and water-washed in a centrifuge to reduce the
impurities.
72
-------
TABLE 3-7. PROPERTIES OF FGD GYPSUM
(OIL-FIRED BOILERS WITH ELECTROSTATIC PRECIPITATOR)
Chemical composition of
dried gypsum (%)
Si02
A1203
CaO
MgO
S03
Water of crystallization
Properties of calcined product
Fineness (cm2/gram)
Setting time (min.)
Start
End
Mortar strengh (kg/cm2)
Bending strength
3 days
7 days
28 days
Compressive strength
3 days
7 days
28 days
A
0.4
0.1
32.2
0.1
46.0
20.6
/
3,020
176
252
33.5
48.5
68.9
138
227
423
B
0.6
0.2
32.2
0.1
46.1
19.9
3,030
161
259
36.2
52.2
73.2
142
250
443
C
0.6
0.2
30.7
0.2
46.1
19.7
3,020
108
176
36.7
49.5
70.8
149
241
428
D
0.4
0.2
32.6
0.2
45.9
19.8
3,020
144
207
33.4
47.4
70.4
136
237
420
E
0.2
0.1
32.5
0.1
46.1
19.6
3,040
175
226
26.1
50.2
72.0
152
254
429
F
0.7
0.2
32.4
0.1
46.0
18.9
3,020
168
235
34.0
51.9
71.5
131
237
399
73
-------
It is desirable that the gypsum contain less than
about 107o moisture so that it will flow smoothly from a hopper
to a cement mill or so that it will require less energy for
drying when used for wallboard or plaster. Gypsum containing
a considerable amount of calcium sulfite has much moisture after
being centrifuged and is not suitable for these uses. Calcium
sulfite itself, however, if it has a low moisture content, is
useful as a retarder of cement setting.
Since gypsum is now in oversupply, tests have been
made to develop new uses. Tests are also in progress to pro-
duce new forms of gypsum, such as fiber-like crystals or a-form
hemihydrate produced by oxidation of calcium sulfite in the
presence of a catalyst such as a surface active agent.
3.3 WASTEWATER AND ITS TREATMENT
3.3.1 Wastewater
Most Japanese FGD processes purge wastewater, as shown
in Table 3-8. The water is purged to prevent the accumulation
of impurities, especially chloride, in the circulating liquor.
The removal of chloride in the purge stream is illustrated in
Figure 3-4. Chlorine is derived from fuel and process water.
It promotes stress corrosion of steel when the liquor contains
more than 1 ppm of oxygen, as shown in Figure 3-5. Because of
the higher chloride concentration in coal, FGD systems for coal-
fired boilers normally purge larger amounts of wastewater than
do those for oil-fired boilers.
Plants using the Kureha-Kawasaki process do not nor-
mally purge any water because the scrubber liquor is very low
in oxygen and, therefore, does not promote stress corrosion.
74
-------
TABLE 3-8. WASTEWATER FROM FGD SYSTEMS
Process
Mitsubishi H.I.
Babcock-Hitachi
Mitsui-Chemico
Babcock-Hitachi
IHI-Chemico
Kureha-Kawasaki
Showa Denko
Chiyoda
Dowa
Kurabo
Kobe Steel
Kawasaki H.I.
Nippon Kokan
Wellman-MKK
Chemico-Mitsui
User
Chubu Elec.
Chugoku Elec.
EPDC
EPDC
EPDC
Shikoku Elec.
Showa Denko
Hokuriku Elec.
Naikai
Nakayama Steel
Unitika
Nippon Kokan
Chubu Elec.
Idemitsu Kosan
Plant site
Owase
Tamashima
Takasago
Takehara
Isogo
Sakaide
Ichihara
Fukui
Tamano
Funamachi
Okazaki
Ogishima
Nishinagoya
Chiba
MW
375
500
500
250*
530
450
170
350
28
40
(130)
68
(380)
220
160
Inlet Waste
SOa water
ppm t/hr(A)
1,600
1,480
1,500
1,700
400
1,270
1,400
1,800
1,500
1,480
200
1,400
350
1,600
2,850
3
4
15
12
20
0
5
15 ,
0.03
0
0
0
10
4
0.1
Gypsum, t/hr
Solid
(B)
15.0
19.0
17.4
1.1.2
9.0
14.5
5.5
15.5
1.1
1.5
0.7
2.4
-
-
—
Moisture
(C)
1.5
1.9
1.7
1.1
0.9
1.3
0.5
1.5
0.1
0.15
0.08
0.26
-
-
—
Water ratio
A+C
A+B+C
0.23
0.24
0.49
0.54
0.71
0.08
0.50
0.51
0.11
0.09
0.10
0.10
-
-
—
kg
MWhr
11
11
30
48
36
3
29
43
4
3
1
3
24
17
1
* Coal-fired system
-------
1-1
45
O
0)
0)
00
n
3
0.
M
0)
4-1
CO
15
10
ppm
400 800
Chloride in fuel (ppm)
1200
Figure 3-4. Relationship of the chloride concentration
in the purge stream to the purge rate and the
chloride content of the fuel (250 MW boiler,
1,500 ppm S02, 10% moisture in by-product gypsum).
1000
100
10
e
(X
(X
01
O
0.1
0.01
Crack
No crack
0.1 1 10 100 1000
Cl~ (ppm)
Figure 3-5. 02 and Cl concentrations in solution
and stress corrosion.
76
-------
Chloride concentration of the liquor in these plants has reached
4,000 ppm, and the amount of chloride leaving the system as part
of the liquid content of gypsum which contains 6-8% moisture has
become equal to the amount going into the system. Other pro-
cesses free from wastewater include the Kobe Steel process,
which uses a calcium chloride solution dissolving lime as the
absorbent, and the Kawasaki magnesium gypsum process. Both use
corrosion-resistant materials for construction.
Even the dry processes are not free from wastewater.
The Tokyo Electric, Hitachi, and the Shell processes produce
relatively large amounts of wastewater because they use wet
treatment in the regeneration steps.
Many states in the U.S.A. prohibit the discharge of
wastewater but allow the discarding of calcium sulfite sludge,
which usually contains 50-607«, water after filtration (water
ratio 0.5-0.6).
Although most Japanese processes purge some waste-
water, the amount is about equal to or less than the amount
purged in the U.S. with sludge disposal. The Chiyoda process,
however, normally purges a relatively large amount of water to
prevent corrosion because Chiyoda uses sulfuric acid saturated
with oxygen as the absorbent. It is possible to reduce the
wastewater from this process by using construction materials
having greater corrosion resistances.
3.3.2 Wastewater Treatment
Wastewater is treated to meet the regulations. The
treatment in most processes is simple, consisting principally
of neutralization and filtration. The Wellman-Lord process,
77
-------
however, requires extensive treatment including ozone oxidation
to decompose polythionates, such as NaaSaOs , formed in the
process. After being treated, the wastewater normally has a pH
of 6-8.5, contains 5-20 mg/ liter of suspended solids (SS) and
less than 10 mg/liter of chemical oxygen demand (COD) . It does
not adversely affect the environment.
The formation of a considerable amount of polythio-
nates in the Wellman-Lord process is due to the thermal treat-
ment of the absorbing liquor. It has been found, however, that
a detectable amount of dithionate Na2S206 also forms in some FGD
processes which do not include thermal treatment. The dithio-
nate does not produce a biological oxygen demand (BOD) , and
therefore, may not adversely affect the environment. It does,
however, produce a COD consuming potassium permanganate. In a
few FGD plants, therefore, wastewater is treated by means of ion
exchange to remove the dithionate in order to maintain COD at
a limited level.
FGD scrubber liquors from oil-fired utility boilers
usually contain small amounts of ammonia. Ammonia is added to
flue gas exiting from an air preheater in order to prevent
corrosion of the electrostatic precipitator. Normally 2 to 2.5
moles of NHs are added per mole of SOa . Powdery ammonium sul-
fate, which is caught by the precipitator, is formed. The gas
leaving the precipitator contains less than 10 ppm NH3 . This
is absorbed in the scrubbing liquor.
Ammonia concentration of the scrubber liquor is
usually below 1,000 ppm. The ammonia is purged with wastewater.
In the Owase plant, Chubu Electric, the wastewater is treated
with lime and air stripping to remove ammonia before it is
purged to the sea, because regulations on wastewater in the area
are quite stringent.
78
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3.4 MIST ELIMINATION
The chevron type mist eliminator has been the most
widely used device for mist elimination. However, this elimi-
nator normally causes a 30-40 mm HaO pressure drop and functions
poorly with mists smaller than 30 microns. Eliminators with a
smaller pressure drop, such as the pipe with fin type and the
Tellerette packing type, have been used but their mist removal
efficiency may not be better.
To attain better efficiency, the Lamellar and Euroform
types (Figure 3-6) were recently introduced. These can remove
mist as small as 12 microns at a relatively low pressure drop
(Figures 3-7 - 3-9). However, they are more costly and more
vulnerable to plugging and scaling than is the chevron type and,
thus, require better washing. In the Owase plant, Chubu Elec-
tric, the chevron type eliminator is used in the first stage to
remove most of the mist and the Euroform type is used in the
second stage to collect smaller particles.
pressure
Plus
pressure
(a) Lamellar(200) 0>) Euroform(T120)
Figure 3-6. Improved types of mist eliminators
79
-------
o
«M
CX.
o
n
0)
VJ
CO
CO
cu
30 -
20 •
10
8
6
5
4
3
j I
3 456 8 10
Gas velocity (m/sec)
15 20
Figure 3-7. Gas velocity and pressure drop.
80
-------
40
a
o
n
o
•H
0
0)
iH
•s
4J
U
O
O
0)
N
•H
00
30
20
10
i
I
0 2
Figure 3-8.
10
468
Gas velocity (m/sec)
Gas velocity and mist collection.
12
B
0)
4J
•rl
•a
o
tH
0)
iS
•s
4J
O,
0)
O
0.4
0.3
0.2
0.1
Lamellar
Euroform
Figure 3-9
4 6 8 10
Gas velocity (m/sec)
Gas velocity and acceptable mist load
81
-------
S03, usually present in a cooled flue gas in the form
of very fine H2SCK mist, is not easily caught by a scrubber or
a mist eliminator. The S03 removal efficiency by a usual FGD
system is estimated at 40-70%. Tests with a mist eliminator
using a glass fiber cloth filtef have shown that more than 90%
of the S03 can be removed. An associated high pressure drop,
however, prevents large-scale commercial applications.
Recently, Nippon Kokan began operating a large ammonia
scrubbing plant with a wet type electrostatic precipitator after
the scrubber. The precipitator eliminates virtually all of the
particulates (dust and mists) and prevents the formation of a
visible plume (see Section 6.2).
3.5 GAS REHEATING
3.5.1 Reheating by Afterburning
The temperature of boiler flue gas which has passed
through an air preheater and electrostatic precipitator normally
ranges from 140 to 160°C. After scrubbing in the wet FGD pro-
cesses, the gas temperature usually drops to 55-60°C. In most
plants, flue gas is reheated to 90-140°C by afterburning low-
sulfur oil.
In the U.S. flue gas is usually reheated to about 80°C
to prevent the condensation of acidic liquor, which causes stack
corrosion and an occasional acid rain. A higher reheating
temperature is used in Japan mainly to eliminate the formation
of a visible plume. Another reason is that the K-value control
of the Central Government (see Section 1.4.2) allows a larger
amount of S02 to be emitted at a higher gas temperature (higher
effective stack height).
82
-------
Although afterburning is the easiest method of reheat-
ing, the oil requirement reaches 3-47» of that used for the
boiler. Afterburning not only is fairly costly but adds S02,
NOX and dust to the cleaned gas. Moreover, recent total mass
regulations restrict the amount of S02 regardless of the gas
temperature. In such a situation, the reheating temperature at
many plants has been lowered to 90-110°C, resulting in a con-
siderable energy saving.
3.5.2 Steam-Gas Heating
/
A few companies have made tests on reheating the gas
by using a gas-steam heat exchanger. Corrosion of the heat
exchanger tubes is a major problem, particularly when the
scrubber liquor is rich in chlorine. The first commercial
steam-gas heater was constructed recently by Mitsubishi Heavy
Industries at the Shimonoseki plant, Chugoku Electric, with
steam tubes made of a high nickel alloy.
3.5.3 Gas-Gas Heating
In principle, a gas-gas heat exchanger, as shown
below, is very useful because it not only saves energy but also
reduces the consumption of cooling water by lowering inlet gas
temperature. Commercial use of the heat exchanger, however, has
been difficult because of the corrosion of the exchanger and the
deposition of solids within it. To cope with the problems,
it is necessary to use a corrosion resistant material and to
minimize the mist from the FGD system by using a highly effi-
cient mist eliminator.
83
-------
148° 15fl°C^
^|
""*100°.110°C
HEAT EXCHANGER
W-lWC ^
"" 58°.B«°C
FGO
ra-nni
Tests with a Ljungstrom type heat exchanger with a
capacity of treating 10,000 Nm3/hr gas have been carried out
since January 1975 by Gadelius Co. (Japan) jointly with Tohoku
Electric at the Shinsendai plant and with Electric Power
Development Co. at the Takasago plant. The Shinsendai plant
treats flue gas from an oil-fired boiler by the Kureha-Kawasaki
sodium-limestone gypsum process. The Takasago plant treats
flue gas from a coal-fired boiler by the Mitsui-Chemico
limestone-gypsum process.
A flowsheet of the test plant at Shinsendai plant is
shown in Figure 3-10. A portion of gas, about 10,000 Nm3/hr,
is passed through a rotating type heat exchanger (Ljungstrom) .
Results of tests at the Shinsendai plant with two kinds of heat
exchange elements, NF-6 and NF-3.5, are shown in Table 3-9 and
Figure 3-11. Both elements are enamel-coated for corrosion pre-
vention. The element NF-3.5 has a finer structure and operates
with a better heat exchange efficiency and a larger pressure
drop.
The amount of particulates in the test facility flue
gas was small, as shown in Table 3-10. A soot blow was applied
intermittently from both the high and low temperature sides.
After 4,000-6,100 hour tests, slight deposits were observed,
mainly in the intermediate zone where the soot blow was not
effective (Figure 3-11). The deposit was slight and did not
increase the pressure drop appreciably. The smooth surface of
the enamel coating and the soot blow were fairly effective for
84
-------
AIRPREHEATER
CO
Ln
Figure 3-10. Pilot plant of Ljungstrom heat exchanger,
(10,000 Nm'/hr)
-------
TABLE 3-9. TEST RESULTS OF LJUNGSTROM HEAT EXCHANGERS
NF-6
Gas flow rate (Nm3/hr)
B+B1
Gas temperature (°C)
A
A1
B
B1
Pressure drop (mmH20)
A*A'
B+B1
(4,000 hr)
Designed
10,000
10,000
134
82
56
103
45
40
0.1 -
1
Actual
7,340
9,890
137
81
65
104
25
36
0.2 mm
NF-3.5
Designed
10,000
10,000
134
74
56
111
100
95
Actual
9,505
10,415
136
79
64
110
90
95
p^-600 mm-»«1
High
Temperature
Zone
•*-600 imu »•
Medium
Temperature
Zone
•^-600 mm**
Low
Temperature
Zone
NF-3.5 t
(6,100 hr)
0.3 - 0.5 mm
Figure 3-11. Deposits on elements in the
Ljungstrom heat exchanger.
86
-------
reducing the deposit. Corrosion was not observed. The deposit
could be removed by a water wash.
TABLE 3-10. EXAMPLES OF PARTICULATE CONTENT OF THE
LJUNGSTROM TEST FLUE GAS (mg/Nm3)
Measuring
point
A
A'
B
B1
During
1
2.9
2.2
2.5
2.6
normal run
2
3.6
3.8
4.0
2.2
(
During
1
2.7
8.7
2.6
4.1
soot blow
2
3.0
11.3
3.1
4.2
3.5.4 Cost Comparison of Gas-Gas Heating and Afterburning9
Based on the above results, comparisons were made of
the costs for reheating flue gas from a 350 MW oil-fired boiler
to 140°C. Three methods were compared:
1) Afterburning using 0.6% sulfur oil.
2) Heating by the Ljungstrom heat exchanger to
100°C (pressure drop 111 mmH20) and then by
afterburning.
3) Heating by the Ljungstrom heat exchanger to
110°C (pressure drop 124 mmH20) and then by
afterburning.
The annualized costs are compared in Table 3-11. The
table indicates that a considerable saving is achieved with a
Ljungstrom heat exchanger, particularly in case (2). It also
implies that if flue gas is reheated to 100°C, use of a
87
-------
Ljungstrom heat exchanger alone can be much more economical than
a f t e rburn ing.
TABLE 3-11. INVESTMENT AND ANNUALIZED COSTS FOR REHEATING
(Millions of Yen)
Investment cost
Annual! zed cost
Fixed cost*
Fuel cost
Utility cost
Maintenance
Other
Total annual cost
(1)
234
42
751
0
7
13
813
Method of f cheat
(2)
1,350
244
302
53
41
21
661
(3)
1,837
332
229
62
55
25
703
* 7 years depreciation, 8% Interest
3.5.5 Commercial Application of a Ljungstrom Heat Exchanger
for FGD
Although the tests have shown good results, it is
possible that considerable corrosion and deposition may occur
in a commercial heat exchanger when the inlet hot gas is rich in
S03 and the cold gas after FGD is rich in mist. The first com-
mercial Ljungstrom heat exchanger has been in operation at the
Ogishima plant, Nippon Kokan. It is installed in an ammonia
scrubbing FGD system with a capacity of treating 1,120,000
Nm3/hr flue gas from an iron ore sintering machine. At this
plant, the FGD outlet gas is first passed through a wet elec-
trostatic precipitator to eliminate ammonium sulfate-sulfite
plume. Virtually all of the mist and dust in the gas are
removed before the heat exchanger. The Ljungstrom unit has had
trouble-free operation (see Section 6.2).
88
-------
There is no definite plan yet to install a Ljungstrom
on a commercial FGD system for flue gas from an oil-fired boiler.
On the other hand, it has been decided to use Ljungstrom heat
exchangers for new wet lime/limestone-gypsum process plants for
three coal-fired boilers to be constructed in 1979 and 1981
(Table 4-5). Comparisons of test results with flue gases from
oil- and coal-fired boilers have shown that the solid deposit
with flue gas from coal is much softer than that with flue gas
from oil and can be removed by soot blowing. The flue gas from
coal contained 100-200 mg/Nm3 of fly ash when introduced into
the Ljungstrom while the gas from oil contained less than 10
mg/Nm3. The fly ash from coaj. seems to make the deposit soft
and easy to remove. The corrosion problem may also be less
serious with coal because the flue gas usually contains less S03
than does that from oil.
3.6 FGD OPERATION AND OPERABILITY
3.6.1 Operation of Gas Sources
Most of the utility and industrial boilers are oper-
ated for 11 months and then undergo maintenance for about a
month. During the 11 months, some of them stop a few times for
short durations. Utility boilers operate at full load in the
daytime and about half load at night, while industrial boilers
are operated at a constant load. Many of the FGD systems for
utility boilers are equipped with an automatic control system
to meet the load fluctuation.
Sintering machines of steel producers and nonferrous
smelters operate continuously for one or two months and then
stop for a few days for maintenance. The gas volume does not
fluctuate much during operation, while the SOX concentration
sometimes varies considerably.
89
-------
SOV concentration of the gas from boilers to be
X
treated by FGD is usually between 600 and 2,000 ppm, while that
of a gas from iron ore sintering machines ranges from 300-500
ppm. The gas for FGD at smelters ranges in SOX concentration
from 400 to 20,000 ppm.
When an FGD system has to be shut down because of
serious problems, oil-fired boilers immediately change to a low-
sulfur oil and bypass the flue gas. This allows them to operate
continuously. Other gas sources usually have to be shut down if
the scrubber operation stops for longer than a certain period of
time.
3.6.2 Bypass Systems
Configurations of three gas bypass systems are shown
in Figure 3-12. Some plants have an open bypass system, no
damper in the bypass duct. During normal FGD operation with
these systems, a small portion of gas discharged from the FGD
system is recycled to the FGD system. If the FGD system is shut
down, the damper to the FGD system is closed and flue gas is
passed through the bypass without delay.
Other plants have a damper in the bypass. Many plants,
however, keep these dampers open. The resulting system operates
the same as the open bypass system. If the dampers in a bypass
are kept closed, they cool on one side and are apt to corrode
due to the condensation of an acidic liquor. Corrosion causes
gas leakage or prevents smooth movement in the event of an
emergency.
90
-------
AIR PREHEATER
VDAMTER
FOD
STACK
AIR PREHEATER ESP
Y DAMPER
STACK
DAMPER
DAMPER
AIR PREHEATER
Y DAMPER
?
STACK
Figure 3-12.
Bypass systems (ESP: Electrostatic
precipitator, FGD: Flue gas
desulfurization, F: Fan).
91
-------
3.6.3 Operability
Operability is defined as the percent of desired FGD
operation time in which the FGD system is operable. As shown
in Table 3-12, most FGD plants have an Operability of over 97%.
The data presented as operability in Table 3-12 is an approxima-
tion based on the percent of boiler operation time in which the
FGD system is operating. This number may be equal to or greater
than the true operability. For gas sources in which the boiler
operation time is equal to the desired FGD operation time, the
operability presented in Table 3-12 is equal to the true oper-
ability. This is the case for oil-fired boilers, which can
operate continuously, in spite of FGD system problems, by switch-
ing to a low-sulfur fuel. Other gas sources, such as coal-fired
boilers and sintering machines, however, may have to shut down
when their FGD system is shut down. Boiler operation times for
these sources are less than the desired FGD system operation
times. Therefore, the operabilities as presented in Table 3-12
for these gas sources are greater than the true operabilities.
For example, the operability as presented in Table 3-12 for the
Takasago plant, Electric Power Development Company, is 97.9%,
while the true operability is 97.0%.
Three plants in the table have an operability of 100%.
This does not mean the plants have had no problem at all. Minor
problems can be solved without stopping FGD system operation.
For example, most of the plants have a standby pump. A pump can
be replaced during the FGD operation. Corrosion, scaling, plug-
ging, and so on can occur to some extent. If those are con-
trolled under a certain level, however, the FGD plant can be
operated continuously until the scheduled shutdown of the gas
source.
92
-------
TABLE 3-12. OPERATION HOURS AND FGD OPERABILITY IN PERIOD OF OPERATION
VO
to
Plant owner
Gas
Plant site source
FGD capacity
Process (MW)
Operation
Boiler(A)
(hr/yr) Operabillty
FGD(B) (B/A) x 100
Inlet SO 2 Year
(ppm) completed
Lime-limestone process
Chubu Electric
Chubu Electric
Kyushu Electric
Kyushu Electric
Electric P.D.C.
Mitsui Aluminum
Mitsui Aluminum
Sumitomo Metal
Indirect or modified
Shikoku Electric
Hokuriku Electric
Shows Denko
Unitlka
Naikai Salt
Nippon Kokan
Nakayama Steel
Regenerable process
Idemitsu Kosan
Chubu Electric
Showa Y.S.
Nippon Kokan
Owase (1)
Owase (2)
Kanda
Kara tail
Takasagor
Omuta
Omuta
Kashima
lime-limestone
Sakaide
Fukui
Ichihara
Okazaki
Tamano
Keihin
Kobe
Chiba
Nishlnagoya
Yokkalchi
Fukuyama
iral"
UB!
UB!
ml
UBt
»I
IB1
SM**
process
UB!
UB!
IB?
"!
IB'
SM**
SM**
IB?
UB;
IB*
SM**
MHI
MHI
MHI
MHI
Mitsul-Chemlco
Chemlco-Mitsul
Hitsui-Cheraico
Suni tomo-Fu j ikasui
Kureha-Kawasaki
Chiyoda
Showa Denko
Kawasaki
Dowa
Nippon Kokan
Kobe Steel
Chemlco-Mltsui
WeUman-MKK
Shell
Nippon Kokan
375
375
188
240
250
156
175
(330)
450
350
150
67
28
(50)
(125)
170
220
40
(253)
7,320
7,565
7,420
7,271
8,180
8,244
8,040
8,285
7,441
7/044
7,885
8,232
8,001
8,202
8,419
8,016
7,247
7,019..
4.263H
7,171
7,485
7,390
7,246
8,010
8,232
8,040
8,285
7,336
7,044
7,775
8,160
7,969
8.098
8,259
7,887
7.090.,
2,13lTT
4,263ff
98.0
98.9
99.6
99.7,.
97.9
99.9
100.0
100.0
98.6
100.0
98.6
99.1
99.6
98.7
98.1
98.4
97.8
30.4TT
100.0
1,600
1,600
800
530
1,500
2,300
2,300
500
1,270
1,800
1,400
1,400
1,500
350
200
2,850
1,500
1,250
350
1976
1976
1974
1976
1975
1972
1975
1976
1975
1975
1973
1975
1976
1972
1976
1975
1973
1973
1976
* Operabillty data are for a continuous 12 months between
July 1976 and December 1977.
* Utility boiler.
T Coal-fired; other boilers are oil-fired.
6
True operability is 97.OK because boiler stopped for hours
due to FGD trouble.
Industrial boiler.
**Sintering machine.
Modification of FGD system was made. Continuous operation has
been achieved for the period July 1977 through May 1978.
TTDue to production control.
-------
Until a few years ago, most FGD plants had start-up
problems which took a few months to be solved. Many recent
plants have operated smoothly since start-up. For example, the
Owase plant, Chubu Electric; the Kashima plant, Sumitomo Metal;
the Tamano plant, Naikai Salt; and the Fukuyama plant, Nippon
Kokan, have had over 98% operability since start-up (Table 3-12).
There is no appreciable difference in the operability between
the lime/limestone process, indirect or modified lime/limestone
process, and regenerable process, as will be discussed later
(see Section 5.1).
3.6.4 Labor Requirements
Most larger plants in Japan are operated by 2-4 per-
sons per shift who also carry out minor maintenance work. For
annual maintenance or to solve serious problems of an FGD system,
the skilled maintenance staffs that take care of the whole power
plant (or steel plant, etc.) look after the FGD system.
Typical labor requirements are shown in Table 3-13.
The Fukui plant, Hokuriku Electric, which uses the Chiyoda pro-
cess, shows the least labor needs, indicating trouble-free oper-
ation. On the other hand, the Sakaide plant, Shikoku Electric,
shows the largest man-hour requirements, although the operabil-
ity of the FGD system is relatively high. The extra labor may
be required because of the complexity of the FGD process.
3.7 ECONOMIC ASPECTS
3.7.1 Investment Cost
Some FGD plant costs are shown in Table 3-14. The
cost of most plants went up from 8,000-15,000 yen/kW before 1973
94
-------
vo
Ol
TABLE 3-13. LABOR REQUIREMENTS OF FGD PLANTS
(Recent One Year)
Plant owner
(plant site)
Shikoku Electric
(Sakaide)
Mitsui Aluminum*
(Omuta)
Chugoku Electric
(Tamashima)
Chubu Electric
(Nishinagoya)
Chubu Electric
(Owase-Mita)
Hokuriku Electric
(Fukui)
Process FGD capacity Operation personnel (man-hours/year) Operability
(Absorbent) (MW)
Kureha-Kawasaki
(Na2S03-CaC03)
Chemico -Mitsui
(Carbide lime)
Babcock-Hitachi
(CaC03)
Wellman-MKK
(Na2S03)
CaO
Chiyoda
(HaSO^-CaCOs)
450
156
500
220
375
350
Skilled Unskilled
33,000 16,000
8,040 8,040
17,520 17,520
17,000
17,000 -
20,800
Maintenance
19,900
15,360
not clear
14,000
14,000
3,300
Total
68,900
31,440
31,000
31,000
24,100
(%)
98.6
100
98
97.8
98.5
100
* Coal-fired; others are oil-fired.
Has three scrubbers and a stand-by scrubber; others have no stand-by.
-------
TABLE 3-14. FGD PLANT COSTS IN BATTERY LIMITS
Plant cost
Process
Wellman-MKK
Sumitomo S.B.*
Chemico-Mitsui
Hitachi-Tokyo
E.P.*
Wellman-MKK
Shell*
Showa Denko
Chubu-MKK
Chemico-Mitsui
Mitsui-Chemico
Mitsubishi (MHI)
Kureha -Kawasaki
Chiyoda
Babcock-Hitachi
Wellman-MKK
Mitsubishi (MHI)
Mitsubishi (MHI)
Dowa
Chemico-IHI
Absorbent
Na2S03
Carbon
Ca(OH)2
Carbon
Na2S03
CuO
Na2S03
CaC03
MgO
CaC03
CaO
Na2S03
H2SO,,
CaC03
Na2S03
CaO
CaCOs
A12(S01»)3
CaC03
By-product
H2SO^
H2SO,»
Sludge
Gypsum
H2SO.»
S02
Gypsum
Gypsum
SO 2
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
H2SOi»
Gypsum
Gypsum
Gypsum
Gypsum
Capacity
(MW)
70
55
128
150
220
40
170
89
180
250
188
450
350
500
160
375
250
28
265
(109yen)
0.8
0.9
1.0
1.7
1.8
1.0
2.0
0.7
4.3*
4.8
3.5
9.6
7.8
10.5
6.0
8.0
3.8
0.4
5.5
.,10* yen.
A kW '
11
15
8
11
8
25
12
8
24
19
19
21
22
21
38
21
15
15
21
Year
completed
1971
1971
1972
1972
1973
1973
1973
1973
1974
1974
1974
1975
1975
1975
1975
1976
1976
1976
1977
* Dry processes
Excluding Claus furnace
96
-------
to 15,000-24,000 yen/kW in 1974. This increase was affected by
the oil crisis. Dry process plants, which are much more costly
than wet process plants, have not been constructed since 1974.
Recent costs of lime/limestone gypsum process plants
range from 15,000-21,000 yen/kW ($60-80/kW at $ = ¥250). Most
indirect lime/limestone gypsum process plants currently cost
¥21,000-23,000/kW. A plant using the Dowa process costs
¥15,000/kW.
A Wellman-MKK process plant was constructed in 1973
at an unusually low cost (¥8,000/kW) but another plant by that
process constructed in 1975 cost ¥38,000/kW. One of the reasons
for the increase in cost is the recent requirement of an exten-
sive wastewater treatment system.
3.7.2 Costs of Fuels and Desulfurization
Figure 3-13 illustrates the relationship of sulfur
content to the cost of fuels. Also included is the additional
cost for desulfurization of 37o sulfur oil to various sulfur
levels by vacuum gas oil (VGO) hydrodesulfurization, topped
crude (TC) hydrodesulfurization, FGD, and gasification. The
desulfurization cost is based on 7,000 hours annual operation
with 7 years depreciation. The current price difference between
3% and 0.2% sulfur oils is nearly $1.0/million Btu. The cost of
reducing sulfur in heavy oil from 3 to 0.2% by supertopped crude
hydrodesulfurization is also about $1.0/million Btu while the
equivalent cost for FGD is a little lower. The recent over-
supply of FGD by-products, however, has adversely affected FGD
economics. Although elemental sulfur is still a desirable by-
product which can be exported, sulfur by-production from FGD
systems so far developed seems more costly than sulfur by-
production from hydrodesulfurization. Oil refineries which have
97
-------
a Glaus furnace to which the recovered SO2 can be charged for
sulfur production are an exception.
98
-------
VO
3 3
o a
o o
8
o a
T3d
a o
Heavy oil
I Sulfur margin* I crude
Low S
High S
coal Mediuin S coal
Gasification
Hydrodesulfurization
of heavy oil
I
V.G.O.t
0.03 0.05 0.1 0.2 0.3 0.5
Sulfur (Z)
1.0
2.0 3.0
* Price difference between low S fuels and high S heavy oil
T T.C. - Topped Crude Hydrodesulfurization
T V.G.O." Vacuum Gas Oil Hydrodesulfurization
Figure 3-13. Costs of fuels and desulfurization (with 3% S Oil)
($1=¥250, Aug., 1977).
-------
SECTION 4
WET LIME/LIMESTONE PROCESSES
4.1 GENERAL DESCRIPTION
4.1.1 Outline
Wet lime/limestone process plants with a capacity
larger than 60,000 Nm3/hr (20 MW) are listed in Tables 4-1 - 4-3.
The first commercial plant using a wet lime-gypsum process was
constructed in 1964 by Mitsubishi Heavy Industries (MHI) and
licensed by Japan Engineering Consulting Co. It was built to
treat 62,500 Nm3/hr of a sulfuric acid plant tail gas containing
2,200 ppm SO2. The FGD plant, which used a spray scrubber, en-
countered several problems, including plugging, scaling and
corrosion, at the beginning of operation. The problems were
gradually solved, and many FGD plants using wet lime/limestone
processes have since been constructed by MHI and other companies
The MHI (or Mitsubishi-JECCO) process has been used
most widely for oil-fired boilers, iron-ore sintering plants,
etc. The Chemico-Mitsui, Mitsui-Chemico, Chemico-IHI and
Babcock-Hitachi processes have been applied to coal-fired
boilers because they use a venturi which is suitable for dust
removal and they use scrubbers which have been developed for
coal-fired boilers in the U.S. Six other processes have also
been used mainly for flue gas from oil-fired boilers, while
three others have been used for sintering plants.
100
-------
TABLE 4-1.
WET LIME/LIMESTONE PROCESS PLANTS BY MHI PROCESS
(LARGER THAN 60,000 Nm3/hr)
User
Nippon Kokan
Kansai Electric
Onahatna Refining
Kawasaki Steel
Kansai Electric
Tokyo Electric
Tohoku Electric
Kyushu Electric
Kawasaki Steel
Kansai Electric
Niigata Power
Kawasaki Steel
Kawasaki Steel
Teijin
Mizushima Power
Tohoku Electric
Chubu Electric
Chubu Electric
Kawasaki Steel
Toyobo
Kashima Power
Kyushu Electric
Kyushu Electric
Kyushu Electric
Kyushu Electric
Sakata Power
Sakata Power
Kansai Electric
Niigata Power
Chugoku Electric
Fukul Power
* 1.000 Nm'/hr
t All boilers
Plant Site
Koyasu
Amagaaaki
Onahama
Chiba
Kainan
Yokosuka
Hachinohe
Karita
Mizushima
Amagaaaki
Niigata
Mizushima
Chiba
Ehime
Mizushima
Niigata
Owase
Owase
Mizushima
Iwakuni
Kashima
Karatsu
Karatsu
Ainoura
Ainoura
Sakata
Sakata
Amagasaki
Niigata
Shimonoseki
Mlkuni
- 590 scfm - 320 kW
are oil-fired.
Capacity
(1,000 Nm'/hr)*
62.5
100
92
120
400
400
380
550
750
375
530
900
320
270
611
420
1.200
1,200
750
200
431
730
570
730
730
1.100
1.100
475
530
1,200
750
Source of Gas
HjSO.. plant
Utility boiler ^
Copper smelter
Sintering plant
Utility boiler
it
i
i
Sintering plant
Utility boiler
1
Sintering plant
Industrial boiler'''
Utility boiler
1
Sintering plant
Industrial boiler
Utility boiler
i
i
•
ii
!•)
SO 2 I
Inlet
2,200
700
20.000
600
550
250
850
800
830
500
700
500
800
1.700
1.050
550
1,500
1.500
550
1.400
1.000
550
550
880
880
950
950
1.600
(Ppm)
Outlet Absorbent
200 Ca(OH)2
70
100
60
60
40 CaCO ,
85 Ca(OH)2
75
40
50
70 CaCO,
40 Ca(OH)2
60
60
40
55 CaCO,
35 Ca(OH)2
35
40
50
100 CaCO,
70
70
110
110
50
50
Ca(OH)2
CaCOj
50
Year of
Completion
1964
1972
1972
1973
1974
1974
1974
1974
1974
1975
n
1976
1
1
1
1977
1978
-------
TABLE 4-2.
o
ro
WET LIME/LIMESTONE PROCESS PLANTS USING SCRUBBERS DEVELOPED IN U.S.
(LARGER THAN 60,000 Nm3/hr)
User
Babcock-Hltachi process
Chugoku Electric
Asahi Chemical
Kansai Electric
Chugoku Electric
Kansai Electric
Chugoku Electric
Shows Power
Showa Power
Maruzumi Paper
Electric Power Dev.
lahikawajima Harima (IHI)
Chichibu Cement
Onahama Smeltery
Furukawa Mining
Chichibu Cement
Hibi Smeltery
Tokuyama Soda
Sumitomo Power
Mitsui Alumina
Plant Site (1,
Mizushima
Mizushima
Osaka
Tamashima
Osaka
Tamashima
Ichihara
Ichihara
Kawanoe
Takehara
- TCA process
Kumagaya
Onahama
Ashio
Kumagaya
Hibi
Tokuyama
Niihama
Wakamatsu
Capacity
000 NtnVhr)*
310
481
500
1,460
500
1,000
249
480
342
852
104
120
60
106
300
500 x 2
450
300
Source of Gas
Utility boiler
Industrial boiler
Utility boiler
i
M
Industrial boiler
Utility boiler*
Diesel engine
Converter
H2SOi, plant
Diesel engine
Smelter
Industrial boiler
Utility boiler
Boiler, Kiln
S0a (ppm) Year of
Inlet Outlet Absorbent Completion
CaCO, 1974
1975
1,500 60 " '
t 1
1976
t 1
I i
1977
700 50 CaO 1972
1 II
* 11
1973
" 1974
1975
CaCO,
Chemico - Mitsui and Mitsui - Chemico processes
Mitsui Aluminum
Mitsui Aluminum
Electric Power Dev.
Electric Power Dev.
Ishikawajima Harima (IHI)
Electric Power Dev.
Omuta
Omuta
Takasago
Takasago
- Chemico process
Isogo
512
552
840
849
900 x 2
Industrial boiler1'
Utility boiler1"
1
Utility boiler*
2,000 200 Ca(OH)2 1972
1,500 150 CaCO, 1975
1,500 150
1,500 150 " 1976
500 70 CaCO, 1976
* 1,000 Nm'/hr - 599 8cfm " 32° kw
t Coal-fired boilers. Other boilers are oil-fired.
§ Carbide sludge to by-produce throwaway calcium sulfite.
Other plants by-produce gypsum.
-------
TABLE 4-3.
WET LIME/LIMESTONE PROCESS PLANTS BY OTHER PROCESSES
(LARGER THAN 60,000 Nm3/hr)
User
Plant Site (1
Capacity
.000 Nm'/hr)*
Source of Gas
S0» (ppm)
Inlet
Outlet Absorbent
Year of
Completion
Fujikasui-Sumitomo process (Mo ret ana scrubber)
Ide Paper
Sanyo Kokuaaku Pulp
Sumitomo Metal
Sumitomo Metal
Sumitomo Metal
Fuji
Onomichl
Wakayama
Kokura
Kashina
Sumitomo Kalnan Kokan Wakayama
Sumitomo Metal
Sumitomo Metal
Takaoka Power
Nippon Kokan process
Nippon Sheet Glass
Nippon Sheet Glass
Nippon Kokan
Kashima
Kokura
Takaoka
(spray tower absorber)
Yokkaichi
Maizuru
Fukuyama
60
140
370
92
880
'182
1.000 x 2
750
350
120
107
Industrial boiler
Recovery boiler
Sintering machine
Heating furnace
Sintering machine
Heating furnace
Sintering furnace
1
Utility boiler
Glass furnace
Incinerator
1.340
4,000
650
820
650
680
650
650
1.220
1,000
1.550
28,000
20 CaCO,
40
20
40
30
35
30
20
50
100 Ca(OH)2
200 CaCO,
200 CaO
1974
1975
t
1976
i
1977
1974
1976
t
Chubu - MKK process (CM process)
Ishihara Chemical
Mitsubishi Gas Chem
Yokkaichi
Yokkaichi
250
60
Industrial boiler
'
1,600
1.300
150 CaCO,
100 Ca(OH),
1974
Kawasaki Heavy Industry process
Jujo Paper
Jujo Paper
Nippon Steel process
Nippon Steel
Nippon Steel
* 1.000 Nm'/hr - 590
Akita
Akita
(SSD process)
Tobata
Wakamatsu
scfm - 320 kW
84
90
200
1.000
Recovery boiler
1
Sintering machine
CaCO,
Slag
1
1973
1975
1974
1976
-------
Many of the plants constructed before 1974 use lime at
a stoichiometry of 0.95 - 1.0 to remove 93 - 98% of S02. Most
of the plants constructed later use limestone (ground so that
95% of it passes a 325 mesh screen) at a stoichiometry of 1.0 -
1.05 to remove 90 - 98% of S02- Virtually all of the plants
by-produce salable gypsum.
A schematic flowsheet common to most processes, except
those with the Chemico scrubber, is shown in Figure 4-1. Flue
gas from an electrostatic precipitator is passed through a
cooler or prescrubber, a scrubber, a mist eliminator, a reheater
and then a stack.
The cooler has the following three functions:
1) It removes particulates and improves the
purity of the by-product.
2) It cools the gas to protect the plastic
coatings and packings in the scrubber.
3) It prevents partial dry-up in the scrubber
to help prevent scaling.
The Chemico-Mitsui, Mitsui-Chemico and Chemico-IHI processes do
not use a cooler. In these processes, which use two scrubbers,
a large L/G ratio is used in the first scrubber.
Types of scrubbers and examples of operation param-
eters are listed in Table 4-4. In most plants, calcium sulfite
formed by the reaction of SO2 with lime or limestone slurry is
oxidized to gypsum by air bubbling. Various types of bubbling
systems, either under pressure or at atmospheric pressure, have
been used.
104
-------
AIR PHEHEATEH
r~
|1N°C
I
DAMPER
-1X1-
WATER
f—
I IOO°.IM°C
STACK
ESP
•4M°C
DAMPER
BOILER
o
Oi
SLUDGE*
WASTEWATER <
WATER
M°C_/
"W.
COOLER
(PRESCRUBBER)
CfO
-
\7
I
A/SA
OIL
M°C FURNACE
DEMISTER
Cio
SCRUBBER "•• '- PH CONTROLLER
CiC03
NEUTRALIZER
X
OXIDIZER
AIR
GYPSUM •
M
CENTRIFUGE
THICKENER
Figure 4-1. Typical flow sheet of wet lime/limestone gypsum process
-------
TABLE 4-4. OPERATION DATA OF MAJOR LIME/LIMESTONE PROCESS PLANTS
Process
Process developer
Plant owner
Plant site
Fuel
FGD capacity (MW)
FGD capacity (1.000 Nm'/hr)
Inlet SOt (ppm)
Inlet dust (mg/Nm1)
Inlet gas temperature (*C)
CaO/SOt stoichiometry
Number of scrubbers in parallel
P.rescrubber (first scrubber)
LTG^diters/Nm1)
Scrubber (second scrubber)
Type
Slurry pH
Slurry concentration (X)
L/G (liters/Nm1)
Gas velocity (in/sec)
Outlet SOi (ppm)
Outlet dust (mg/Nm1)
SOt removal efficiency (%)
Mist eliminator type
„ Prescrubber
Pressure Scrubber
""P. n. Mist eliminator
(mmHjO) Total 8y8tem
Wastewater purged (t/hr)
Energy requirement (design)
Pump (kW)
Fan (kW)
Total FGD system (kW)
Percent of power generated
Operability (%)
* Coal- fired systems
t Throw-away process. Others
Lime scrubbing
Mitsubishi Chemico-
H.I. Mitsui
Chubu
Electric
Owase
Oil
375
1.200
1.600
15
150
1.0
2
Sprajr
Packed
6.5-7
10
7
3.4
120
8
93
CEtt
30
150
25
375
3
7,500
2.0
98, 99
by-produce
Mitsui
Aluminum
Omutat
Coal
156
510
2,300
630
135
1.05
2
Venturi
5-8
Venturi
7.5
5
5-8
220
40
90
Chevron
}O Art
4 00
30
1,320
2,000
3,867
2.5
100
gypsum.
Mitsubishi
H.I.
Kyushu
Electric
Karatsu
Oil
250
730
530
25
150
1
Sprajr
Packed
6.2
12
3.0
50
6
90
Chevron
60
35
65
185
5.070
2.0
99.7
Babcock-
Hitachi*
Chugoku
Electric
Tamashima
Oil
500
1,480
1,460
40
140
A
3+1*
Venturi
10
PP**
6.6
12.5
10
60
96
Pwfft
225
505
25
1,080
4
4.100
11,500
17,600
3.5
97.4
Limestone
Babcock-
Hitachi
Electric
Power D.C.
Takehara
Coal
250
850
1,550
600
150
1.05
1
Venturi
2.4
PP**
6-6.5
9
7
100
30
98
Pwftt
230
375
10
950
12
1,400
5,500
8,200
3.3
97.4
acrubblnR
Mitsul-
Chemico*
Power D.C.
Takasago
Coal +
250?
850
1.500
100
140
1.0
1
Venturi
6
Venturi
6.2
5-6
6
100
50
93
Chevron
150
150
25
525
7.5
2,800
4,200
8,000
3.2
97. 98
IHI-
Chemico*
Electric
Power D.C.
Isogo
Coal +
265+
900
450
1,500
170
1.0-1.05
1
Venturi
7
Venturi
5-6
7
7
3.0
40
50
93
Chevron
150
150
50
600
10
2,000
4,800
7,800
2.9
100
Sumitomo-
Fuj ikasul
Siimi t*niTOT
Metal
Kaahtma
Coke .
(630)s
2,000
400-600
100-200
150
1.05
2
PP**
7
PP**
6.7
7-8
8
4.4
30
20
93-95
Implnger
180
130
30
530
60
4,400
8.170
13,230
2.1
100
f Capacity. of each of two units.
S Iron-ore sintering plant. Others are utility boilers.
f Stand-by
** Perforated plate.
tt Chevron and Euroform
ft Pipe with fin.
-------
For perfect oxidation to obtain good-quality gypsum,
the pH of the sulfite slurry should be maintained below 4.5.
Since the pH of the slurry discharged from the scrubber is 5.5 -
6.5 in most plants, sulfuric acid is added to lower the pH. In
two plants, however, perfect oxidation has been attained without
using sulfuric acid. One of these is the Owase-Mita plant,
Chubu Electric, using the MHI two-tower system with lime (see
Section 4.2) and the other is the Takasago plant, EPDC, using
the Mitsui-Chemico limestone scrubbing process with reactors.
Both plants lower the pH using S02 in flue gas; a high S02
concentration is favorable to lowering the pH.
The only plant in Japan using the calcium sulfite
sludge ponding system is the Omuta plant, Mitsui Aluminum. The
plant uses a two-stage Chemico venturi scrubber and a carbide
sludge absorbent. The plant has been operated in an unsaturated
mode. Gypsum is not formed, although about 10% oxidation of
calcium sulfite occurs in the scrubber. For more recently con-
structed FGD installations, Mitsui Aluminum has selected a mod-
ified process, the Mitsui-Chemico process, to by-produce gypsum
using limestone. The modified process was selected because of a
shortage in the supply of carbide sludge and because of limited
capacity in the calcium sulfite sludge pond.
4.1.2 Scale Prevention
In most plants by-producing gypsum, more than 2070 oxi-
dation of calcium sulfite occurs, resulting in the formation of
gypsum in the scrubber. Gypsum crystals are usually recycled to
the scrubber as seed crystals to eliminate the formation of gyp-
sum on the surface of structural materials which tends to cause
scaling (Figure 4-2). Smooth structural material surfaces and
continuous flow of slurry in all parts of the scrubbers and
piping are also keys to scale prevention.
107
-------
Gypsum seed
3 urn
Fresh water
S02
600-1,600 ppm ^
02 1-3%
Scrubber
pH 6-7
S02
50-100 ppm ^
02 1-3%
Mist
eliminator
Lov degree of
supersaturation
Unsaturated
Typical Japanese system (Forced oxidation, CaO/S02 = 1.0-1.1)
Circulating liquor
i
S02
2,500-3,500 ppm
02 5-7%
Scrubber
pH 7-7.5
S02
200-400 ppm ^
02 5-7%
Mist
eliminator
Unsaturated
Supersaturated
U.S. unsaturated lime system (Throw-away sludge, CaO/S02 = 1.1-1.2)
Figure 4-2. Comparison of gypsum circulation system (Japan)
and unsaturated mode lime system,(U.S.).
108
-------
Some of the U.S. plants such as Paddy's Run and Cane
Run, Louisville Gas and Electric, and a Japanese plant of Mitsui
Aluminum in Omuta have been operated in the unsaturated mode by
keeping the oxidation of calcium sulfite below 10%. Below this
level of oxidation, gypsum is not formed in the slurry, and,
therefore, scale formation is prevented. Most of the plants
have been operated successfully using a high slurry pH of about
7 with a high concentration of S02. Both factors lower the oxi-
dation ratio (see Figure 4-2).
The unsaturated mode, however, is not applicable to
flue gas from a low-sulfur fuel because of a high 02/S02 ratio
which results in over 20% oxdiation. At this oxidation level
gypsum is formed, and tends to cause scaling. Even with a high-
sulfur fuel, gypsum may form at a mist eliminator by the reac-
tion of lime or limestone in the mist with SO2 and 02 at a high
02/S02 ratio (see Figure 4-2).
As is generally experienced, mist eliminators are most
susceptible to scaling. It seems that the scaling problem is
less serious in Japan than in the U.S. This may be attributable
to the following reasons:
1) A low concentration of lime or limestone is
in the mist due to high utilization (over 90%)
of lime or limestone. A CaO/S02 mole ratio of
1.0 - 1.05 is used to remove 90 - 98% of S02.
The high utilization and removal efficiency
is attained by finely grinding the lime or
limestone and by having good gas-liquid contact
in the scrubber. Usually limestone is ground
so that over 95% passes 325 mesh screen.
109
-------
2) A low concentration of S02 is in the gas
passing through the eliminator. This is due
mainly to the high S02 removal ratio.
3) Mist and wash liquor contain a considerable
amount of gypsum which works as crystal seed
to prevent scaling.
4) When an appreciable amount of scale is
formed, it is washed with fresh water to
dissolve the scale. In some of the plants,
the eliminator is washed with fresh water
only, although this tends to increase the
amount of wastewater.
4.1.3 Wastewater, Power Consumption and Operability
At the plants listed in Table 4-4 (and Table 3-8),
wastewater is purged at the rate of 3 - 60 tons/hr or 7 - 87
kg/MWh. The wastewater is purged to prevent the accumulation
of chlorine in the scrubber liquor because chlorine increases
corrosion. The plants of Electric Power Development Co. pro-
duce high levels of wastewater (48 kg/MWh) because they use
coal which contains a considerable amount of chlorine. As may
be seen in Table 3-8, two oil-fired plants purge only 8 kg/MWh.
The ratio of wastewater to by-product gypsum for these plants
is about 0.2. The ratios for three typical coal-fired plants
are 0.8 to 2.0. Since by-product gypsum contains about 10%
moisture, the total amount of water removed from a system with
a wastewater to by-product ratio of 1.0 is almost equal to the
total amount of water removed from a throw-away process with a
40% solid sludge and no wastewater purge. This means that in
total the gypsum by-production processes for oil-fired flue gas
purge much less water and those for coal-fired flue gas purge a
little more water than do throw-away processes.
110
-------
SO2 removal efficiencies of the plants shown in Table
4-4 range from 90 - 98%. Power required for a total FGD system
ranges from 2.0 - 3.570 of the power generated. The power con-
sumption is larger with the Chemico and Babcock processes, which
use a venturi, than with the MHI and Fujikasui-Sumitomo process-
es because of the larger pressure drop required in order to pro-
vide an adequate dust removal efficiency.
Table 4-4 shows that the operability of the plants are
over 97%. Operability is the percent of desired operating hours
in which an FGD plant is actually operating. Utility and indus-
trial boilers are normally operated for 11 months almost contin-
/
uously and shutdown for about a month for maintenance while
iron-ore sintering machines are operated continuously for a
month or two and shutdown for several days for maintenance. FGD
operation is desired for all of the operation hours of the gas
sources.
Some FGD plants encountered start-up problems, but
these were solved in a few months. A few plants have an opera-
bility of 100%, but this does not mean that they have no prob-
lem. Rather, it means that problems such as plugging, scaling,
corrosion, erosion, etc. can be controlled to a minor degree so
that they do not hinder operation and can be taken care of
during shutdown of the gas source.
The FGD plants have spare pumps and centrifuges. None
currently have a standby scrubber, however, except for the
Tamashima plant, Chugoku Electric, which has four scrubbers in-
cluding a standby unit. In 1972, Mitsui Aluminum installed two
scrubbers at Omuta; one was to treat 70% of the flue gas, while
the other was for standby. The operability had been 100% with
the one scrubber, and the standby scrubber was not used. Since
111
-------
a few years ago, however, 100% of the flue gas has been treated
by using the two scrubbers in parallel.
Figure 4-3 illustrates the relationship of inlet S02
concentration to operability of the major lime/limestone process
plants shown in Tables 3-12 and 4-4. The operability of all
plants is higher than 97%. In general, the operability is lower
with a higher S02 concentration, which imposes a larger load on
the scrubber and mist eliminators. Operability is also lower
with utility boilers which are subject to a frequent load fluc-
tuation than with industrial boilers with a constant load.
For utility boilers, the operability with coal tends
to be a little lower than with oil, but the difference is
smaller than 1% and may not be significant. Major differences
between coal and oil are in the content of fly ash, which in-
creases erosion, and the content of chlorine, which tends to
promote corrosion. As long as these are maintained under a
certain level by using an electrostatic precipitator and by
purging some wastewater, as is done in all of the plants for
utility boilers, the difference between coal and oil may not be
significant.
Two plants treating flue gas from coal-fired indus-
trial boilers containing 2,300 ppm S02 have virtually 100%
operability. These plants are at Omuta, Mitsui Aluminum. The
first plant is operated in the unsaturated mode using carbide
lime as the absorbent. X-ray tests have shown that gypsum is
absent in the scrubber slurry.10 A recent study has shown that
carbide lime contains an ingredient which may depress oxidation
and promote unsaturated mode operation.11 It may be possible to
use usual lime and operate a plant successfully in the unsatu-
rated mode. However, the attainment of high operability may not
be as easy as with carbide lime. Therefore, saturated mode
112
-------
100
99
98
97
eg
^
-------
operation with forced oxidation and gypsum circulation may be
safer and more widely applicable as long as usual lime or lime-
stone is used.
The second plant of Mitsui Aluminum at Omuta, which
has 100% operability, uses a limestone-gypsum process. FGD for
utility boilers is not as easy as FGD for industrial boilers,
such as at Mitsui Aluminum. By improving operation control,
however, the operability of FGD plants for utility boilers may
be further increased to approach that for industrial boilers.
4.2 OPERATION OF FGD PLANTS FOR COAL-FIRED-BOILERS
4.2.1 General Description
FGD plants for coal-fired boilers are listed in Table
4-5. Seven plants are in operation and three are to be com-
pleted by 1981. All of them use a wet lime/limestone process.
Five more coal-fired boilers (total 390 MW) are planned for
completion in 1982 and 1983.
The first FGD plant, the Omuta plant of Mitsui Alumi-
num, has been operated quite well since 1972, by-producing a
sulfite sludge using carbide lime. Since land space for sludge
disposal and supply of carbide lime are limited, Mitsui Alumi-
num's second plant at Omuta uses a limestone-gypsum process.
All FGD plants constructed later for coal-fired boilers use a
limestone gypsum process. The by-product gypsum contains 2-5%
fly ash and 10 - 12% moisture except for the gypsum at the Isogo
plant, which contains 15 - 20% fly ash and 15% moisture. All of
the gypsum has been sold for cement, wallboard, and other con-
struction material.
114
-------
TABLE 4-5. FGD PLANTS FOR COAL-FIRED BOILERS
Plant Owner
Mitsui Aluminum
EPDC
1
ii
•
1
Chugoku Electric
Hokkaido Electric
Plant Site
Omuta
Takasago
i.
Isogo
II
Takehara
Matsushlma
Shimonoseki
Tomakomai
* Industrial boiler; others are utility
t Carbide lime to
Capacity
(MW)
156*
156*
250
250
265
265
250
500
175
250
boilers .
by-produce calcium sulfite sludge;
Process
Chemico -Mitsui
Mitsui -Chemico
Mitsui -Chemico
Mitsui-Chemico
IHI -Chemico
IHI-Cheraico
Babcock-Hitachi
--
Mitsubishi H.I.
--
others by-produce
SO 2
Inlet
2,000
1.500
1.500
1.500
5QO
500
1.700
800
1,200
--
gypsum.
(ppm")
Outlet
200
150
150
150
50
50
100
--
50
--
Year of
Absorbent Completion
Ca(OH)2f 1972
CaCO, 1975
1975
" 1976
1976
1976
1977
1981
1979
1981
-------
The seven plants in operation use U.S. scrubbers—
Chemico and Babcock with a venturi efficient for particulate
removal. (The plants also have electrostatic precipitators for
particulate removal.) The scrubbers, with a venturi, give a
large pressure drop and the FGD systems consume over 2.5% of the
power generated. New plants to be constructed may use a low
pressure drop scrubber with a highly efficient electrostatic
precipitator. Gas-gas heat exchangers of the Ljungstrom type
will be used for the gas reheating as stated in Section 3.5.5.
The power cost using coal of 10,000 yen/ton (6,200
kcal/kg) and FGD is estimated at 8.6 - 8.9 yen/kWh. Of this
total, FGD cost accounts for 1.2 - 1.5 yen/kWh including 7 years
depreciation and reheating to 90 - 120PC.
Generally speaking, FGD plants for coal-fired boilers
are not appreciably different in performance from FGD plants
for oil-fired boilers except for the following factors.
1) When the electrostatic precipitator is not
highly efficient, fly ash from coal increases
erosion of the construction materials and
also lowers the filterability of gypsum.
2) Usually a larger amount of chlorine tends
to accumulate in the scrubber liquor of
FGD plants for coal-fired boilers.
116
-------
4.2.2 Takasago Plant, EPDC (Mitsui-Chemico Limestone-
Gypsum Process)
Process Description--
Takasago Power Station, EPDC, is located in a
relatively small industrial region facing the Seto Inland Sea.
It has two 250 MW coal-fired boilers, each with an FGD unit
using the Mitsui-Chemico limestone-gypsum process. A flowsheet
of the No. 2 unit is shown in Figure 4-4. The process is char-
acterized by the use of a pH controlling tower and a reactor to
lower the pH of the calcium sulfite slurry to about 4.0. At
this low pH, SO2 in flue gas' can be oxidized without using sul-
furic acid.
About 70% of the flue gas, which contains 1,400 -
1,600 ppm S02 is fed to the 1st scrubber and then to the 2nd
scrubber. Both scrubbers are of the Chemico venturi type. The
rest of the gas is fed through the pH controller and the reactor
to the 2nd scrubber. A limestone slurry is also fed to the 2nd
scrubber. The reacted slurry flows through the 1st scrubber
and the pH controller to the reactor, where air bubbles are
introduced for the oxidation of calcium sulfite to gypsum. The
gypsum slurry is centrifuged to by-product gypsum containing
about 10% moisture and is sold for cement and wallboard. The
filtrate discharged from the centrifuge is used to prepare the
limestone slurry. A limestone powder, 95% under 325 mesh, is
purchased as the absorbent. Details of the process are avail-
able in published literature.16)
The No. 1 unit is similar to the No. 2 unit except
that it has two reactors. The operation parameters are shown
in Tables 4-4 and 4-6. The boilers burn a blend of domestic
coals with an average sulfur content of 2.0%. Over 90% S02
117
-------
run on
00
AFTIMUMM
CLIAigUITACK
Figure 4-4. Flow sheet of Takasago plant, KPDC (No. 2 unit)
-------
removal efficiency has been attained at a total pressure drop
of 525 minHaO. The actual power consumption of the FGD unit is
6,500 kW, which is equivalent to 2.6% of the power generated by
the boiler. Initially, a catalyst was added to the scrubber
slurry to increase the S02 removal efficiency and to promote
the oxidation, but the catalyst is no longer used.
TABLE 4-6. SPECIFICATIONS OF FGD UNITS
Designed
Actual
Power generating capacity (MW)
Fuel consumption (tons/hr)
Inlet gas volume (dry)
(103 Nm3/hr)
02 in gas (%)
Gas temperature (°C)
SO 2 inlet concentration (ppm)
SO2 (scrubber outlet) (ppm)
SO2 removal efficiency (%)
Inlet dust (mg/Nm3)
Outlet dust (mg/Nm3)
250
89.4
743
4.7
140
1,500
below 100*
93.3
100
below 50*
799
5.5 - 6.0
150 - 160
1,400 - 1,600
70 - 80
95
80
20
Requirement s
Water (ton/hr)
Limestone (ton/hr)
Power (kW)
46
5.1
8,000
52
6,500
*Guaranteed by Mitsui Miike
The plant has a wastewater treatment system similar
to that in Isogo (see Section 4.3) to remove dithionate to
reduce COD.
119
-------
Performance--
The No. 1 and No. 2 FGD units went into operation in
February 1975 and in March 1976, respectively. The boiler load
varies within a day as shown in Figure 4-5.
250
200
-------
TABLE 4-7. PERFORMANCE OF THE NO. 1 UNIT, TAKASAGO PLANT
Hours
Month
Feb. 1975
Mar.
Apr.
May
June
July
Aug.
Sept.
Oct.
Nov.
Dec.
Jan. 1976
Feb.
Mar.
Apr.
May
June
July
Total
(A)
672
744
720
744
720
744
744
720
744
720
744
744
672
744
720
744
720
744
Boiler oper-
ation (B)
616
360
318
717
720
743
744
690
744
720
715
744
664
687
219
744
720
744
FGD
atop (C)*
19
0
0
0
15
15
15
30
36
11
29
0
32
0
0
0
0
0
Boiler
avail-
ability (X)t
91.7
48.4
44.1
96.4
100
99.9
100
95.9
100
100
96.1
100
95.4
92.3
30.0
100
100
100
FGD oper-
ability (*)'
97.0
100
100
100
97.9
98.0
98.0
95.7
9.5.2
98.4
100
100
95.3
100
100
100
100
100
Remarks
Piping flange leak
| Annual shutdown
Mist eliminator
Mist eliminator
Mist eliminator
Mist eliminator
Fan vibration
Mist eliminator
Mist eliminator
of boiler
wash
wash
wash
wash
wash
wash
* Due to troubles of FGD unit.
t B/A «>
S (B-O/B <*>
Continued
-------
TABLE 4-7 (CONTINUED). PERFORMANCE OF THE NO. 1 UNIT, TAKASAGO PLANT
Hours
Month
Aug. 1976
Sept.
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
£ May
10 June
July
Aug.
Sept.
Oct.
Nov.
Dec.
Jan. 1978
* Due to
t B/A (%)
S (B.-O/B
Total Boner oper-
(A) atlon (B)
744
720
744
720
744
744
672
744
720
744
720
744
744
720
744
720
744
744
troubles of FGD unit.
(I)
744
720
744
720
744
744
672
0
513
744
720
717
744
720
744
720
744
744
FGD
atop (C)*
0
0
62
5
8
5
0
0
0
10
0
0
0
0
43
0
0
0
Boiler
avail-
ability (Z)t
100
100
100
100
100
100
100
0
71.3
100
100
96.2
100
100
100
100
100
100
FGD oper-
abillty (*)*
100
100
91.7
99.3
98.9
99.7
100
Remarks
Cleaning of 1st
Repair of duct
Repair of spray
Cleaning of 1st
scrubber
pipe
scrubber
Annual maintenance of boiler
100
98.2
100
100
100
100
94.3
100
100
100
Fan vibration
Cleaning of 1st
scrubber
Cleaning of scrubbers & reactors
Cleaning of 1st
reactor
-------
TABLE 4-8. PERFORMANCE OF THE NO. 2 UNIT, TAKASAGO PLANT
Hours
I-1
N>
CO
Month
Mar. 1976
Apr.
May
June
July
Aug.
Sept.
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
Oct.
Nov.
Dec.
Jan. 1978
Total
(A)
744
720
744
720
744
744
720
744
720
744
744
672
744
720
744
720
744
744
720
744
720
744
744
Boiler oper-
ation (B)
744
720
216
632
744
744
720
744
720
744
744
672
744
720
384
24
744
744
720
744
720
744
744
FGD
stop (C)*
0
0
0
0
0
0
0
43
0
5
0
79
10
0
0
0
0
0
0
0
78
0
0
Boiler
avail-
ability (%)f
100
100
29
88
100
100
100
100
100
100
100
100
100
100
51.6
32.9
100
100
100
100
100
100
100
FGD oper-
100
100
100
100
100
100
100
94.2
100
"99.3
100
88.3
98.7
100
100
100
100
100
100
100
89.1
100
100
Remarks
Annual maintenance of boiler
Duct cleaning
Repair of gypsum conveyor
Cleaning of pH controller
Cleaning of duct & pH controller
Cleaning of pH controller and
reactor
* Due to FGD troubles.
t B/A (!)
5 (B-C)/B «)
-------
deposited in the duct between the first and second scrubbers.
Recently, a new mist eliminator was installed in the No. 1
scrubber. This mist eliminator is currently being washed with
fresh water and circulating liquor as is the mist eliminator in
the No. 2 unit.
The No. 1 unit purges 5 tons/hr of wastewater to main-
tain the chlorine concentration in the circulating liquor below
8,000 ppm. Both units purge 10 tons/hr of wastewater due to the
use of fresh water for washing the mist eliminators.
Emission of SO from the station is restricted within
X
400 Nm3/hr by an agreement with the local authorities. The
amount is equivalent to about 220 ppm of SO in flue gas at a
X
full load of the two boilers. By the total mass regulation
which is to be applied from April 1978, the amount will be re-
duced to 243 Nm3/hr, or about 136 ppm, at full load.
When one of the FGD units was shutdown, the boiler
was operated at half load without FGD if the other FGD unit was
in operation. The SO regulation could still be met in this
X
way. Only on two occasions--in September 1975 and February
1976--the No. 1 boiler had to be shut down for about 30 hours
each due to FGD trouble. After April 1978, however, the boiler
will have to be shut down whenever the scrubber is not in oper-
ation .
Economics—
The capital cost for the two units was 9.3 billion
yen. The units are operated by 3 persons per shift plus three
persons working in the daytime for maintenance. The operation
cost including 7 years depreciation and gas reheating to 85°C
124
-------
is 1.19 yen/kWh, while the power cost is 6.86 yen/kWh including
15 years depreciation excluding FGD.
Evaluation--
The process is characterized by the production of
high-purity gypsum by limestone scrubbing without using sulfuric
acid. The slurry pH is reduced as the slurry passes through
four towers, contacting flue gas. When perfect oxidation is
not required as it is not in the U.S., two or three towers may
be sufficient and no catalyst may be needed.
The pressure drop through the system is sharp result-
ing in a relatively large power consumption, because a venturi
is used to attain a high particulate removal efficiency. For a
new coal-fired boiler, it may be preferable to install a highly
efficient ESP with an FGD system with a smaller pressure drop.
4.2.3 Isogo Plant, EPDC (Chemico-IHI Limestone-gypsum Process
Characteristics--
Isogo Power Station of Electric Power Development Co.
(EPDC) has two 265 MW coal-fired boilers and is located in the
heavily populated Yokohama/Tokyo area. Because of the unusual
situation, the most stringent controls for pollution prevention
have been required. Since several years ago, the station has
used coals with a sulfur content as low as 0.3%, and electro-
static precipitators. Since further reduction of S0x and par-
ticulates has been required, an FGD plant using the Chemico-IHI
limestone-gypsum process was completed in March 1976 for the
No. 1 boiler. Another was completed in May 1976 for the No. 2
boiler. The units were installed by Ishikawajima-Harima Heavy
125
-------
Industries (IHI). After the plants were installed, coals with
0.6 - 1.0% sulfur have been used.
The Chemico Venturi scrubber was selected because of
the high particulate removal efficiency; the electrostatic pre-
cipitator is not quite effective for a low sulfur coal and the
particulate content of the flue gas reaches 1.5 g/Nm3.
Two single-stage Chemico scrubbers were installed in
series to reduce S02 from about 500 to 30 ppm and particulates
to below 0.1 g/Nm3.
A gypsum by-producing process was chosen because there
is no space to throw away sulfite sludge. To lower the slurry
pH to about 3.5 in order to promote the oxidation, the standard
process in Japan, addition of sulfuric acid, has been used.
This method was chosen partly because of its simplicity and
partly because of the low inlet concentration of SO 2, which
makes it difficult to reduce the pH by installing additional
reactors as in the Mitsui-Chemico process.
Process Description--
A flowsheet of the process is shown in Figure 4-6.
Operation parameters are shown in Table 4-4. A limestone slurry
is prepared with powdered limestone (325 mesh pass) using fresh
water. The use of circulating liquor was found to lower the
reactivity of limestone. The slurry is fed to the second
scrubber, where the pH of the circulating slurry is maintained
at 6.0. A portion of the circulating slurry is sent to the
first scrubber, where the pH is kept at 4.5. Flue gas is first
fed to the first scrubber, where 40 - 60% of the S02 is absorbed,
and then to the second scrubber, where 50 - 30% of the S02 is
absorbed. The overall S02 removal efficiency reaches 90%.
126
-------
WATER t
f CiC03
to
AFTER BURNER
WASTE
WATER
Figure 4-6. Flow sheet of Isogo plant, EPDC.
-------
The slurry discharged from the first scrubber is sent
to a pH adjusting tank, where the pH is lowered to about 3.5 by
addition of H2SO^; unreacted limestone is entirely decomposed
here. The acidulated slurry is fed to an oxidizer, where cal-
cium sulfite is oxidized to gypsum by air bubbles generated by
the 'Smoke Atomizer' invented by IHI.
The gypsum slurry is sent to separators (superdecantor,
a continuous type centrifuge) through a thickener. The by-
produced gypsum contains about 15% moisture and 15 - 20% fly
ash. It has been sold for construction material production.
Although it has a fairly low purity, the gypsum is still useful
as long as the composition does not fluctuate appreciably.
Most of the liquor discharged from the thickener and
decanters is sent to the first stage absorber, while a portion
(10 tons/hr/unit) is purged to prevent the accumulation of
chlorine in the circulating liquor; the chlorine concentration
is kept at 5,000 ppm.
The wastewater first undergoes standard treatments:
raising the pH, followed by precipitation, filtration, and
neutralization. Since the liquor contains a small amount of
dithionate ion (S206), which causes COD, the liquor is passed
through two towers in series containing a resin which absorbs
the dithionate. This treatment reduces the COD of the liquor
to below 10 ppm, conforming to regulations.
The plant specifications and main components are
listed in Tables 4-9 and 4-10.
128
-------
TABLE 4-9. PLANT SPECIFICATIONS
Boiler
FW Single Drum radiation reheat,
natural circulation and indoor
Evaporation rate 840 T/hr each
Flue gas volume 879,100 Nm3/hr (MCR) each
Fuel Coal
Flue gas temperature 143 °C (AH outlet)
Draft control Balanced draft
Manufacturer Ishikawajima-Harima Heavy
' Industries Co., Ltd.
Flue Gas Desulfurization system
Type IHI-CHEMICO type, Limestone
liquid scrubbing /gyp sum recovery
Gas volume 900,000 Nm3/hr (MCR) -
450,000 Nm3/hr (night hours) each
Efficiency of S02 removal 90%
Efficiency of dust removal 96.7%
Coal composition Inherent water 4.2%
Ash content 16.0%
Calorific value 6,200 kcal/kg
Sulfur content 0.2 - 0.6%
Absorbent Limestone 50 T/D each
By-product Gypsum Approx. 120 T/D each
Gas reheating system After-burning
Total area of installation Approx. 8,000 m2
Manufacturer Ishikawajima-Harima Heavy
Industries Co., Ltd.
129
-------
TABLE 4-10. MAIN EQUIPMENT
Absorbent supply proce_ss_
Limestone silo
Make-up pump
Absorption process
1st stage absorber
2nd stage absorber
Boost up fan
Gas volume
Draft
Motor power
Circulation pump
Gygsum production process^
Oxidation tower feed tank
Oxidation tower
Oxidation blower
Air volume
Draft
Motor power
Thickener
Dehydrator
Solid content
Gas reheater
After-burning furnace
1,000 tons (common use for No. 1
and No. 2 boilers)
3 sets
1 stage Venturi Scrubber 1 set
1 stage Venturi Scrubber 1 set
Dual suction turbo-fan direct
coupled to motor shaft
13,400 m3/min each
820 mm H20
2,400 kW x 2 sets/unit
210 kW x 5/unit 195 kW x 5/unit
Vertical cylindrical type made
of carbon steel - 1 set
Vertical cylindrical type made
of carbon steel - 2 sets/unit
Roots blower
50 Nm3/min each
20,000 mm H20
200 kW x 3 sets/2 units
Sedimentation and Concentration
type - 1 set
Screw decanter type
1.05 T/hr x 4 sets/unit
Horizontal cylindrical type
2,600 kg/hr - 1 set
130
-------
Performances and Economics--
The FGD plant with two units has been operated by 3
persons per shift. In the daytime, one more person is assigned
to each unit for chemical analysis and maintenance work. The
superdecantors have often had troubles requiring frequent ser-
vicing. The slurry circulation pumps need repair every few
months. Since the maintenance work can be done while the FGD
plant is in operation, operability has been kept at 100%.
The plant cost ¥11 billion in 1976. The boilers have
been operated at full load in the daytime and at about half load
at night. The two units daily consume about 100 tons of CaC03
and produce 240 tons of gypsum. In addition, the plant consumes
about 7 tons/day of 35% NaOH liquor and 0.7 ton/day of 98% HaSCU.
Evaluation--
Operability of the plant has been 100%, proving that
over 90% removal of S02 in gas from a low-sulfur coal can be
carried out quite well by a suitable design and operation of an
FGD plant. The superdecantor seems troublesome; a batch type
centrifuge may be more reliable.
The reduced reactivity of limestone discovered when
circulating liquor was used for slurry preparation has not been
experienced in other plants for coal-fired boilers, including
the Takasago and Takehara plants. Impurities, such as fluorine,
which reduce the reactivity may be present in a considerable
amount in the liquor because of the relatively large fly ash
content or due to the type of coal.
131
-------
4.2.4 Takehara Plant, EPDC (Babcock-Hitachi Limestone-
Gypsum Process)
Outline--
Takehara Station, EPDC, with a 250 MW coal-fired
boiler and a 350 MW oil-fired boiler, faces the Seto Inland Sea
in an area with no large cities and with mild regulations. SOX
emissions are restricted by the Central Government below 468 and
503 Nm3/hr for the No. 1 and No. 2 boilers, which are equivalent
to 600 and 620 ppm, respectively, at full load. By an agreement
with the local government, emission from the No. 1 boiler is
restricted below 195 Nm3/hr or 240 ppm. The performance and
regulations are listed in Table 4-11.
The No. 2 boiler burns 1%-sulfur oil and has no FGD
system. The No. 1 boiler uses a blend of domestic coals with
a sulfur content of 2% and gives a flue gas with 1,550 - 1,650
ppm S0x- An FGD system using the Babcock-Hitachi limestone-
gypsum process went into operation in February 1977 to treat
flue gas from the No. 1 boiler. Specifications of the electro-
static precipitator and the FGD unit for the No. 1 boiler are
shown in Table 4-12.
A flowsheet of the FGD unit is shown in Figure 4-7-
The unit has two trains of scrubber systems, a reactor for
adjusting pH by adding sulfuric acid, oxidizers, a thickener,
and gypsum centrifuges. The process is similar to that of the
Tamashima plant, Chugoku Electric.16) The operation parameters
are shown in Table 4-4. Over 93% of S02 and dust are removed
with a total pressure drop of 950 mmH20 and power consumption
of 3.3% of the power generated by the boiler. The by-product
gypsum contains about 10% moisture after being centrifuged, and
is sold for cement and wallboard.
132
-------
TABLE 4-11. BOILERS AT TAKEHARA STATION
(PERFORMANCE AND REGULATIONS)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
Installed unit capacity
Initial year of operation
Fuel
Annual plant factor
Annual plant efficiency
Design fuel analysis
Heating value (high, dry)
Surface moisture
Inherent moisture (dry)
Hydrogen ( " )
Sulfur ( " )
Nitrogen ( " )
Ash ( " )
Plant efficiency (gross)
Fuel consumption (as fired)
Flue gas
Volume (wet)
Volume (dry)
Excess air
Air pollutants
Sulfur oxides
Nitrogen oxides
Farticulate matter
Wastewater
pH
C.O.D.
S.S.
Oil
No. 1 Boiler
250 MM
1967
Coal
75Z
37. 2Z
6,000 kcal/kg
7.0Z
2.4Z
4.1Z
( 2.0Z
l.OZ
23. OZ
38. 5Z
100,100 kg/hr
809,000 NmVhr
755,000 NmVhr
29Z
468 (195) NmVhr
600 (240) ppm
345 NmVhr
420 ppm
302 (76) kg/hr
0.4 (0.1) gram/Nm3
6.5 - 8.5
10 ppm
10 ppm
1 ppm
No. 2 Boiler
350 MW
1974
Oil
70Z
38. 1Z
10,650 kcal/kg
12. 5Z
l.OZ
39. 3Z
71,900 kg/hr
917,000 NmVhr
815,000 NmVhr
16Z
503 NmVhr
620 ppm
156 NmVhr
180 ppm
41 kg/hr
0.05 gram/Nm3
Condenser cooling water temperature rise 7°C
Noise
At boundary limit
6:00 a.m. 10:00 a.m.
Midnight
60 phon (A)
50 phon (A)
133
-------
TABLE 4-12. AIR POLLUTION CONTROL FACILITY
(NO. 1 BOILER, TAKEHARA STATION)
1. Dust collector
Type
Capacity (at 250 MW)
Gas volume
Gas temperature
Dust load (entering E.P.)
Dust load (leaving E.P.)
Efficiency
Electrostatic precipitator
793,300 NmVhr
140°C
18 grams/Nm
0.36 grams/Nm3
98%
2. SOa temoval and recovery system
Type
Scrubbing and absorbing
liquid
Crystallizer
Capacity
Gas volume (wet)
Gas volume (dry)
Gas temperature
S02 (inlet)
S02 (outlet)
Dust (inlet)
Dust (outlet)
Raw water consumption
Limestone consumption
Venturi wet scrubber, B. & W. type
Multi-stage absorbing tower
Limestone slurry
Sulfuric acid injection and air
blowing
852,000 Nm3/nr
795,000 Nm3/hr
150°C
1,730 Nm3/hr
100 Nm3/hr
600 Nm3/hr
50 Nm3/hr
1,350 tons/day
6,140 kg/hr
134
-------
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ir
s
THIUIIEK
P
CEtTRIFUClU-
.
£
T
^
Figure 4-7. Flow sheet of Takehara plant, EPDC.
-------
Performance of FGD System--
The No. 1 boiler has been operated at full load except
at night when the load is reduced to 100 - 160 MW. The major
problem with the FGD system was the plugging of a strainer in
the slurry circulation tank placed at the bottom of the scrubber.
The mist eliminator is of the pipe-with-fin type with a small
pressure drop and is easily washed; however, it does not seem to
be highly efficient. Scaling problems were eliminated with the
mist eliminator, but were experienced at the gas reheating sec-
tion due to the mist.
Since the start-up in February 1977, the FGD plant was
operated for 5,396 hours until the end of September 30 when the
boiler was shut down for annual maintenance. During the above
period, the scrubber operation was stopped three times, while
the boiler was operated at half load using a mixture of coal and
a low-sulfur oil in order to meet the emission standards. On
two occasions, one of the scrubber trains was shut down for a
total of 70 hours to clean up the strainer. On the other occa-
sion, both of the scrubbers were shut down to remove the scale
in the reheating section. The operability of the FGD system was
97.4% for two-scrubber operation and 98.6% including one-
scrubber operation hours.
In order to eliminate the strainer plugging problem,
modifications were made during the boiler shutdown period. A
gypsum circulation line was installed to reduce scale formation.
The strainers were moved and placed outside the scrubber for
easy cleaning. An increase in operability is expected from
these modifications.
136
-------
The mist eliminator is washed with fresh water.
Chlorine in circulating liquor is maintained at 3,500 ppm by
purging 10 tons/hr of wastewater.
Economics--
The total investment for the FGD unit was 7.2 billion
yen. The unit is operated by two persons per shift plus three
persons per shift for maintenance. Each month it consumes 3,200
- 3,900 tons of limestone ground so that over 95% passes 325
mesh screen, 70 - 107 kiloliters of 98% sulfuric acid, and
40,000 - 46,000 tons of water, and it by-produces 6,140 - 6,860
tons of gypsum. '
The FGD operation cost is 1.73 yen/kWh including 7
years depreciation and reheating to 130°C. The power cost in-
cluding FGD is estimated at 8.82 yen/kWh. The power cost for
the No. 2 boiler is estimated at 7.92 yen/kWh. The No. 2 boiler
burns medium-sulfur oil. By using low-sulfur oil, the cost will
approach that by the No. 1 boiler with FGD. The FGD operation
cost based on 15 years depreciation and reheating to 80°C, as in
the U.S., is estimated at 1.1 - 1.2 yen/kWh, which may be less
than the difference between the use of low and high sulfur fuels.
Evaluation--
The FGD unit is well designed. The operability is
expected to exceed 99% by the modification of the system. Power
consumption, however, is pretty high. For new coal-fired boil-
ers, it may be preferable to install an electrostatic precipi-
tator with higher efficiency and a scrubber with a lower
pressure drop and smaller power consumption.
137
-------
4.2.5 Omuta Plant, Mitsui Aluminum
The Omuta plant has two FGD units constructed by
Mitsui Miike using the Chemico Scrubbers. The first unit was
completed in 1972 to by-produce a throw-away sludge using car-
bide lime. The second unit uses a limestone-gypsum process
because the supply of carbide lime is getting short and the
sludge pond is almost full.
The first unit has two two-stage Chemico scrubbers in
parallel. In the past, 70% of the flue gas from a 156 MW coal-
fired industrial boiler was treated by using one of the scrub-
bers. The other scrubber, a standby, was not used because the
plant operated smoothly without any appreciable scaling problem.
Since a few years ago, however, as regulations were tightened,
both scrubbers have been in use in parallel to treat the entire
quantity of gas from the boiler. The plant is famous and has
been described by many authors.10'11*'15) Recent operation
parameters and operation hours of the boiler and FGD plant are
shown in Tables 4-4 and 4-13, respectively.
The FGD operability and availability have been kept at
100% except during the short period of boiler shutdown. The
smooth operation is attributable to a large extent to an unsatu-
rated mode of operation, which prevents the formation of scale-
causing gypsum. It is possible that some ingredient in the
carbide lime works as an oxidation inhibitor to prevent the
formation of gypsum, as was observed with the carbide lime used
by Louisville Gas and Electric, U.S.
The second unit, which treats gas from a 175 MW coal-
fired industrial boiler, is similar to the Takasago plant, EPDC,
(see Section 4.2.2) except that a catalyst is used to increase
SO2 removal efficiency and to promote oxidation. The unit has
138
-------
operated at 100% operability since the start-up in July 1975,
except for 10 days of shutdown in the fall of the year. During
the shutdown, gypsum deposits formed due to mist carry over are
cleaned out of the stack. The boiler as well as the FGD unit
has been operated continuously for 11 months at the constant
load and then shut down for a month for maintenance.
SO2 in the flue gas is reduced from 2,200 - 2,500 ppm
to about 200 ppm to meet the regulations. The total investment
for the second unit was 4.0 billion yen including civil works.
TABLE 4-13. OPERATION HOURS OF OMUTA PLANT
MITSUI ALUMINUM (1st Unit)
Sept. 1976
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
Total
(A)
720
744
720
744
744
672
744
720
744
720
744
744
Hours
Boiler
Operation
(B)
204*
744
720
744
744
672
744
720
744
720
744
744
FGD
Operation
(C)
191.6*
744
720
744
744
672
744
720
744
720
744
744
Availability (%)
Boiler FGD
(B/A) (C/A)
28.3*
100
100
100
100
100
100
100
100
100
100
100
26.6*
100
100
100
100
100
100
100
100
100
100
100
Operability
(c/B) a)
93.4
100
100
100
100
100
100
100
100
100
100
100
*The short operation hours are due to annual shutdown of the boiler.
139-
-------
4.2.6 Matsushima Plant, EPDC
A basic flowsheet for the FGD unit of the Matsushima
plant, EPDC, to be constructed in 1979 is shown in Figure 4-8.
The FGD unit will treat flue gas from a 500 MW coal-fired boiler
which will mainly burn imported coal with about 1.6% sulfur.
The plant will be equipped with a hot electrostatic precipitator,
which is suitable for the coal. In case flue gas denitrifica-
tion becomes necessary in the future, the hot precipitator will
facilitate the application of selective catalytic reduction.
Gas leaving the air preheater at about 150°C will pass
through gas-gas heat exchangers, as was described in Section
3.5, and then into a tower for further dust removal and cooling
by a wet system. The liquor leaving the tower, which contains
fly ash, will be treated separately from the scrubber liquor in
order to obtain high purity gypsum. A limestone slurry will be
used in the scrubber. The pH of the slurry discharged from the
scrubber will be lowered by adding sulfuric acid.
A similar system may be used for two other FGD plants
for coal-fired boilers. Negotiations with vendors are in pro-
gress. It is likely that the Chemico type spray scrubber will
be used at the Matsushima plant.
4.2.7 Other Plants
An FGD plant using the MHI limestone-gypsum process
will be completed in 1979 at Shimonoseki Station, Chugoku Elec-
tric, to treat flue gas from a coal-fired boiler (see Section
4.3.2).
Hokkaido Electric will install a 500 MW coal-fired
boiler at Higashitomakomai, which will burn a local low-sulfur
140
-------
WATER
BOILER
AIR PREHEATER
HOT ESP
PURGE
WATER
WASTEWATER
COO REMOVAL TREATMENT
*{
f
SLUDGE
AIR
MIXING
TANK
Figure 4-8. Flow sheet of Matsushima plant, EPDC.
-------
coal. Half of the flue gas from the boiler will be treated by
a limestone-gypsum process after being subjected to NOX removal
by selective catalytic reduction.
Several other coal-fired boilers with a unit capacity
of 700 - 1,000 MW are planned, all of which will need FGD.
4.3 OPERATION OF FGD PLANTS WITH MHI SCRUBBERS FOR
OIL-FIRED UTILITY PLANTS
4.3.1 Owase-Mita Plant, Chubu Electric (MHI Lime-Gypsum
Process12-13)
Characteristics--
Owase is a small pretty town with a population of
about 30,000. One side faces Owase Bay and three sides are
surrounded by hills. The power station, with two 375 MW oil-
fired boilers, was constructed on reclaimed land on the bay
under a pollution control agreement with the town authorities.
For FGD, the lime-gypsum process was adopted because
lime can be brought in by special dump trucks and gypsum can be
shipped out by boat. Lime was preferred to limestone because
of the smaller weight. The two-absorber system of Mitsubishi
Heavy Industries (MHI) was chosen in order to obtain a high S02
removal efficiency and to eliminate the use of sulfuric acid,
which is required in most other lime-limestone gypsum processes
to lower the pH of calcium sulfite slurry prior to oxidation.
The above choices were made due to the inconvenience of trans-
portation around the plant. The plant's siting conditions are
different from those of most FGD plants in Japan, which are
located in and around large industrial districts.
142
-------
Another characteristic of the FGD system is the
installation of a unit to remove ammonia from wastewater. The
unit was installed for the following reason:
Japanese utility power companies inject a
small amount of ammonia into 140 - 150°C
flue gas from an oil-fired boiler in order
to protect the electrostatic precipitator
from corrosion. Ammonia reacts with SO3
and H20 in the gas to form fine crystals
of ammonium sulfate which are caught by
the precipitator. The gas leaving the
precipitator contains less than 10 ppm
ammonia, which is caught by an FGD system
and accumulates in scrubber liquor.
Usually the ammonia is purged with waste-
water because the amount is not large.
In the case of Owase-Mita station, the
FGD capacity is fairly large, and moreover,
the wastewater regulations are quite
stringent. Therefore, an ammonia stripping
unit was installed.
Process—
There are two equal FGD units for No. 1 and No. 2
boilers with a capacity of 375 MW each. The No. 1 FGD unit
went into operation in April and the No. 2 in June 1976. A
flowsheet of a unit is shown in Figure 4-9. Flue gas
(1,200,000 Nm3/hr) from a 375 MW oil-fired boiler containing
1,600 ppm S02 is treated by two trains of scrubber systems.
Lime slurry preparation, gas reheating, gypsum handling, waste-
water treating, etc. are all in one train. Each of the scrubber
trains includes a cooler and the first scrubber in one tower,
143
-------
ESP
f
I
f
•OILER
AIR
PHEHEATER
4 ^ TO
I No. 1 TRAIN
I
I
AFTER BURNER j \
FROM No. 1 TRAIN J 1
FROM NO. 1 TRAIN
OXIOIZER
~\ \ 0X10
I S T '
1 M I _l
THICKENER
-STACK
CENTRIFUGE
GYPSUM
No. 1 TRAIN
WASTE WATER
AMMONIA STRIPPER
Figure 4-9. Flow sheet of Owase-Mita plant, Chubu Electric.
-------
the second scrubber in a separate tower, and a mist eliminator.
Both scrubbers are of standard MHI type with plastic grid
packings.
The operation parameters are shown in Table 4-4. A
lime slurry is fed to the second absorber in which the gas and
the slurry flow in parallel. The slurry discharged from the
second scrubber is fed to the first scrubber where the reaction
between lime and S02 goes to completion and the pH of the slurry
is lowered to about 4; this pH is suitable for the oxidation of
calcium sulfite.
The slurry discharged from the first scrubber is sent
to an oxidizer, where calcium sulfite is oxidized to gypsum by
air bubbles generated by JECCO rotary atomizers. The oxidizer
has a facility for sulfuric acid addition but it has not been
used so far because the pH of the slurry has been low enough.
The gypsum slurry is sent to a thickener. The slurry discharged
from the thickener with a concentration of 25% is centrifuged to
by-produce gypsum with over 98% purity containing less than 1070
moisture, which is shipped for wallboard and cement production.
The filtrate from the centrifuge is fed to the thickener; the
thickener overflow is used to prepare a lime slurry which is
fed to the scrubber.
Virtually all of the ammonia and chlorine and a con-
siderable portion of the dust in the flue gas are caught in the
cooler by a water spray. The liquor discharged from the cooler
is treated with sodium hydroxide to raise the pH and then fed
to an ammonia stripping tower. The liquor, after ammonia re-
moval, is neutralized with sulfuric acid, filtered and purged.
About 3 tons/hr/unit of wastewater, containing about 15 ppm COD,
1 ppm SS with a pH of about 6.6, are purged.
145
-------
The gas discharged from the second scrubber passes
through a mist eliminator with Chevron type elements in the
first stage and Euroform type elements in the second stage.
Most of the mist is caught in the first stage and smaller par-
ticles are caught in the second stage. The Chevron elements
are washed with a circulating liquor and the Euroform elements,
which have higher efficiency but are more vulnerable to scaling,
are washed with fresh water.
Operation--
Each FGD unit was designed to treat flue gas ranging
from 450,000 to 1,200,000 Nm3/hr (from 125 to 375 MW) and to
follow the change of operation load at a rate of 10 MW/minute.
The boilers are operated normally at full load and occasionally
at 300 MW load at night.
The two FGD units (total 750 MW) are operated by 4
persons per shift (Table 3-13). Tables 4-14 and 4-15 show
boiler and FGD operation hours and troubles encountered in a
recent year. Operability of the FGD units was 98% for No. 1
and 98.9% for No. 2. Scaling of the mist eliminator has been
a problem common to the two units and has required several
hours of cleaning once in about 3 months. In addition, the
scrubber of the No. 1 unit tends to scale slightly and under-
goes cleaning once in about 6 months. For cleaning, one of
the scrubber trains is shut down for several hours for water
wash while boiler load is reduced to about a half.
The plant is fully automated and is easy to operate.
After operating the FGD units for over 1 year, the power plant
people found the FGD system easier to operate than the boiler.
146
-------
TABLE 4-14. YEARLY OPERATION OF OWASE-MITA NO. 1 BOILER AND FGD UNIT
Oct.
Nov.
Dec.
Jan.
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
Total
(A)
1976 744
720
744
1977 744
672
744
720
744
720
744
744
720
TOTAL - 8.760
Hours
Boiler oper-
ation (B)
20
345
717
744
6/2
701
637
597
720
744
744
679
7.320
FGD oper-
ation (C)
20
263
717
744
622
701
626
597
720
738
744
679
7.171
Availability (%)
Boiler FGD
B/A C/A
2.7
47.9
96.4
100
100
94.2
88.5
80.2
100
100
100
94.3
83.5
2.7
36.5
96.4
100
92.6
94.2
86.5
80.2
100
99.2
100
94.3
81.9
Opera-
bility
100
76.2
100
100
92.6
100
98.3
100
100
99.2
100
100
98.0
Remarks
Scheduled maintenance of boiler
Low sulfur oil was used at boiler
start-up
Maintenance of FGD power system
Erosion of slurry circulation pipe
Mist eliminator cleaning
-------
TABLE 4-15. YEARLY OPERATION OF OWASE-MITA NO. 2 BOILER AND FGD UNIT
•p*
oo
Oct. 1976
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
TOTAL -
Total
(A)
744
720
744
744
672
744
720
744
720
744
744
720
8,760
Hours
Boiler oper-
ation (B)
694
720
744
309
0
712
720
744
714
744
744
720
7,565
FGD oper-
ation (C)
670
720
742
309
0
658
720
744
714
744
744
720
7,485
Availability (%)
Boiler FGD
B/A C/A
93.3
100
100
41.5
0
95.7
100
100
99.2
100
100
100
86.4
90.1
100
99.7
41.5
0
88.4
100
100
99.2
100
100
100
85.4
Opera-
blllty
<*>
96.5
100
99.7
100
0
92.4
100
100
100
100
100
100
98.9
Remarks
Mist eliminator cleaning
Repair of supernatant
system
Scheduled maintenance
Scheduled maintenance
Use of low-sulfur oil
start-up. Erosion of
circulating
of boiler
of boiler
at boiler
conveyor .
-
-------
Economics--
The total cost of the two units was 16 billion yen in
1976 in battery limits. The relatively high cost, 21,000 yen/
kW, is due to special considerations for pollution prevention--
over 95% S02 removal, two stage mist elimination, ammonia
stripping, installation of noisy equipment indoors — and is also
due to having a fully automated system to ensure smooth opera-
tion.
The plant (two units) consumes about 60,000 tons/year
of lime and 3,500 tons/day of water to by-produce 180,000 tons/
year of gypsum. Power consumption is 15,000 kW which is equiv-
alent to 2% of the power generated, and is relatively low as
shown in Table 4-4. The low power consumption is due mainly to
the small pressure drop of the scrubber system by the use of a
simple rough packing which is sufficient to ensure the high S02
removal efficiency. The S02 removal rate is determined by the
dissolving rate of lime or limestone rather than by the absorp-
tion rate of S02- The total variable cost is about 2.5 billion
yen/year. About half of the cost is for low-sulfur oil to re-
heat the gas to 140°C.
Evaluation--
The plant cost is relatively high because of the elab-
orate design. Operation has been carried out very well with a
low man-hour requirement, achieving over 93% S02 removal and
by-producing good-quality gypsum without using sulfuric acid.
The plant indicates that when dry N0x removal of flue
gas by ammonia (with or without catalyst) and wet lime/limestone
FGD is combined, leak ammonia from the N0v removal reactor will
X
149
-------
be caught by a cooler (prescrubber) and may not appreciably
affect the FGD system. So far the dilute ammonia gas obtained
from the wastewater has been purged to air but it may be possi-
ble to recover it in a more concentrated form so that it can be
recycled back to the flue gas.
4.3.2 Shimonoseki Plant, Chugoku Electric (MHI Limestone-
Gypsum Process)
Shimonoseki Station, Chugoku Electric, has two boilers
—No. 1 (175 MW) burning a mixture of 20% coal containing 0.7%
sulfur and 80% heavy oil containing 1.2% sulfur, and No. 2
(400 MW) burning 2.7% sulfur heavy oil. The No. 2 boiler flue
gas is treated by an FGD plant using the MHI limestone-gypsum
process.
The station faces a straits between Honshu and Kyushu
Islands, is not close to large cities and industrial regions,
and is subject to relatively mild regulations by the Central
Government and prefecture and city authorities as shown in
Table 4-16.
FGD Plant--
The basic design of the FGD plant is similar to that
of the Owase plant, Chugoku Electric (Section 4.3.1) except that
the Shimonoseki plant uses limestone. The plant consists of two
trains of scrubber systems, each of which has a cooler and two
absorbers in series in order to attain over 98% SO2 removal
efficiency and to minimize sulfuric acid consumption. Major
components are listed in Table 4-17. Operation parameters are
shown below:
150
-------
L/G 10.4 liters/Nm3 (No. 1 and No. 2 absorbers each)
pH About 4.0 at No. 1 absorber outlet, 5-6 in No. 2
absorber
Slurry concentration 10% in absorbers
Pressure drop in total (actual) 240 mmH20
Power consumption (actual) 8,600 kW (2.15% of power
generated)
Sulfuric acid consumption 0.1 ton/hr
The SOX concentration, 1,500 ppm at the inlet, is re-
duced to 15 ppm by the scrubbing. The treated gas is heated to
140°C by a multitube type steam-gas heat exchanger. The tubes
are made of stainless steel, have a heat transfer area of 4,000
m2, and are equipped with soot blowers.
TABLE 4-16. REGULATIONS FOR SHIMONOSEKI STATION
Air Pollution Control
k Value
SOX
Particulates
No. 1 boiler
No. 2 boiler
N0x
No. 1 boiler
No. 2 boiler
Floating particulates
Water Pollution Control
2.7 (Ground level concentration 0.0047 ppm)
Below 412 Nm3/hr
Below 130 kg/hr
Below 200 mg/Nm3
Below 40 mg/Nm3
Below 330 Nm3/hr
Below 350 ppm
Below 170 ppm
Below 0.2 mg/Nm3
PH
Suspended solids
5.8 - 8.6
Below 12 kg/day
Below 15 mg/liter
Normal hexane soluble material
Chemical oxygen demand
Below 0.8 kg/day
Below 1 mg/liter
Below 12 kg/day
Below 15 mg/liter
151
-------
TABLE 4-17. MAIN COMPONENTS OF SHIMONOSEKI PLANT
1. Flue gas fan: (Radian type) 2 Capacity: 700,000 Nm3/hr
Pressure drop: 500 mm HzO
2,100 kW (10 pole)
2. Cooler: 2 12,000 W x 8,000 L x 30,500 H
3. No. 1 absorber: 2 12,000 W x 6,000 L x 31,500 H
8 m grid packings
4. No. 2 absorber: 2 12,000 W x 9,000 L x 33,500 H
4 m grid packings with demister on the top
A
5. Steam gas heater: 2 Heating area: 4,000 m
Tube: Bare, stainless steel with soot blowers
Outlet gas temperature: 140°C
6. Cooler circulation pump: 2 x (2 + 1) 660 m3/h x 35 mH
Rubber lined
132 kW x 6 p
7. No. 1 absorber circulation pump: 2x4 1,820 m3/h x 30 mH
R.L. casing, stainless
steel impeller
270 kW (6 pole)
8. No. 2 absorber circulation pump: 2x4
same as above except head 25 mH,
250 kW (6 pole)
9. Oxidation tower: 2 Capacity: 160 m3
3,600 x 17,000 L
W/3 Rotary atomizers
10. Oxidation air compressor: 2 Screw type
7,000 Nm3/hr x 7 kg/cm2G
900 kW
11. Gypsum thickener: 1 Capacity: 550 m3
Diameter: 14,000
Rubber lined
12. Centrifuges: 9+1 Capacity: 2,000 kg/hr
Basket dimensions 1,520 <|> x 650 H
Main motor 37 kW x 6 p (12 p), pole change
152
-------
Performance and Cost--
The FGD plant cost 11 billion yen (7.8 billion yen in
battery limits including about 800 million yen for the gas re-
heater) while the total investment for the No. 2 boiler and the
FGD plant was 44 billion yen. The plant went into operation in
September 1977 after three months test run and has since been
operated at 100% operability (at least until February 1978 when
visited). The plant is operated by 4 persons per shift plus 3
persons in the daytime for handling limestone and gypsum.
The FGD operation cost is estimated at about 1.7 yen/
kWh at a 70% load factor including 7 years depreciation and re-
heating to 140°C. Since the power cost without FGD is estimated
at 9.9 yen/kWh with 0.12%-sulfur oil and 8.4 yen/kWh with 3%-
sulfur oil, FGD does not give an economical advantage under the
present situation with the relatively small cost difference of
oils and the oversupply of gypsum. However, the operation cost
based on 15 years depreciation and reheating to about 80°C, as
in the U.S., is substantially less and is smaller than the cost
difference of the oils.
FGD Plant to be Installed for the No. 1 Boiler--
Chugoku Electric has decided to install a limestone-
gypsum process FGD plant using the MHI process for the No. 1
boiler. Construction will commence in early 1978, with com-
missioning scheduled for 1979. After completion of the plant,
2%-sulfur coal will be used for the boiler without mixing with
heavy oil. Specifications for the FGD plant are as follows:
Inlet SOX 1,700 ppm; Dust 1,000 mg/Nm3;
HC1 100 ppm; HF 18 ppm
SO2 removal efficiency 96%
153
-------
A Ljungstrom type gas-gas heat exchanger is to be
installed to reheat the gas to 105°C. Considerable savings of
industrial water for cooling will also be attained by the use
of the heat exchanger.
Evaluation--
The two scrubbing trains on the No. 2 boiler remove
about 99% of SOX using a limestone slurry and the plant has been
operated at 100% operability. The plant has a standby each for
the cooler circulation pump and for the centrifuge but no stand-
by for the absorber or the absorber pump. The Karatsu plant
(Section 4.9) has also been operated very smoothly with virtu-
ally 100% operability since start-up. MHI has been continuing
extensive pilot plant tests with flue gases from various sources,
including a coal-fired boiler, in comparison with operation data
of the 34 commercial plants constructed by MHI. They seem to
have established know-how for the high reliability of a system
with high SO2 removal efficiency at low power consumption.
4.4 OPERATION OF FGD PLANTS WITH THE MORETANA SCRUBBER
4.4.1 Characteristics of the Moretana Scrubber
The Moretana scrubber developed by Fujikasui Engineer-
ing Co. jointly with Sumitomo Metal has perforated plates with-
out a weir and downcomer. They have a free space ratio of 0.25
- 0.6, which is larger than that of conventional perforated
plates (about 0.2). Figure 4-10 compares the relationships of
pressure drop and superficial gas velocity for a conventional
perforated plant (curve a) and a Moretana plate with a free
space ratio of 0.35 (curve b). With the conventional plate,
pressure drop increases remarkably when gas velocity exceeds B,
the flooding point, while with the Moretana plates, the increase
154
-------
is mild above B until the velocity reaches the flooding point, C.
The reason for the occurrence of Point B with the Moretana plate,
however, is not clear. The range between B and C is called the
"undulation region" and is suitable for scrubbing because good
gas-liquid contact occurs in a state similar to boiling.
100
o
-------
Patents have been issued in several countries
including the U.S. JGC Corp. (Japan Gasoline Co.) and Toyo
Engineering have been licensed to construct plants with the
Moretana scrubber. Twelve FGD plants, including 9 larger ones
(Table 4-3), 7 relatively small plants for simultaneous removal
of SOV and NOV (12,000 - 100,000 Nm3/hr), and 6 small plants
XX /N
(5,000 - 60,000 Nm3/hr) for particulate removal, are in opera-
tion with the Moretana scrubber. Toyo Engineering will be
constructing particulate removal units in the USSR.
4.4.2 Kashima Plant, Sumitomo Metal
Two of the largest Moretana scrubbers (unit capacity
1,000,000 Nm3/hr) are in use at the Kashima Works, Sumitomo
Metal, to treat flue gas from an iron-ore sintering machine. A
flowsheet of the FGD plant is shown in Figure 4-11.
The flue gas from the sintering machine is relatively
poor in S02 and rich in 02 and ferric oxide dust. Ferric oxide
catalyzes the oxidation of calcium sulfite in the scrubber and
promotes the tendency of gypsum scale formation. Removal of
ferric oxide dust at high efficiency by a cooler (prescrubber)
with Moretana plates lowers the degree of oxidation and helps
prevent scaling.
Operation parameters are shown in Table 4-4. A lime-
stone slurry of about 7% concentration at a pH of 6.7 and with
a stoichiometry of 1.05 is used to remove 93 - 95% of S02 and
nearly 90% of dust. The calcium sulfite slurry discharged from
the scrubber is sent to a clarifier and then to a pH adjusting
tank, where the pH is adjusted to 4 by adding a small amount of
H2SCU. The slurry is then sent to a Fujisawa-developed oxidizer,
where the sulfite is converted to gypsum. The gypsum slurry is
156
-------
STACK
Cn
SINTERING MACHINE
CHINE I I
T"l_r
O. 2 TRAIN.
.MO. 2 T
I
I 1
PRESCRUBBER
I I (COOLER) I
INO. 1_THAIN_ .} I
^1—I 1 I
WATER 2
^r^
THICKENER
WASTEWATER
AFTER-BURNER
OXIDIZER CENTRIFUGE
pH ADJUSTING TANK
Figure 4-11. Flow sheet of Moretana process (Kashima plant, Sxomitomo Metal)
-------
centrifuged, and the filtrate is returned to the scrubber
system. The by-product gypsum is sold for cement and wall-
board production.
The discharge from the cooler is sent to a thickener.
The overflow is returned to the cooler; the underflow is fil-
tered. The filter cake is returned to the sintering machine,
and the filtrate, about 60 tons/hr, is sent to a wastewater
treatment system.
The operation hours of the sintering machine and the
FGD plant in a recent year are shown in Table 4-18. The sin-
tering machine has stopped operation for a few days a month.
The FGD plants have been almost trouble-free. Although minor
problems may occur, they can be solved during the shutdown of
the sintering machine. The FGD plant normally continues to
operate for several hours after the shutdown of the sintering
machine, to prevent any S02 leakage from the machine. There-
fore, the FGD operation hours always exceed the sintering
machine operation hours. FGD availability (FGD operation hours
percent of total hours) reaches 97%.
4.4.3 Takaoka Plant, Takaoka Kyodo Power
The Takaoka plant was constructed by JGC Corp., a
licensee of the Sumitomo-Fujikasui process. The plant has a
capacity of treating 330,000 Nm3/hr of flue gas from an oil-
fired utility boiler containing about 1,200 ppm SO2. It went
into operation in July 1976. A flowsheet of the process is
shown in Figure 4-12. Major equipment is listed in Table 4-19.
In the first year of operation, scale formed on the
Moretana plates and scrubber walls. This increased the pressure
158
-------
Ul
VD
C02 10.3X
023.9%
SOjtOppiu
HjO 16.6%
OUST 0.04 g/Nm^
MAKE-UP WATER
21 TON/HR
330,000 Nm3/hr.
16S°C
COjII.IX
024.1X
S02 1,220 ppm
H20 10.3S
OUST 0.06 i/Nm3
DUST CAKE
O.S TON/OAV
GYPSUM
16.5 TON/DAY
Figure 4-12. Flow sheet of Takaoka plant, Takaoka Kyodo Power.
-------
TABLE 4-18. OPERATION HOURS (KASHIMA PLANT)
-------
TABLE 4-19. MAJOR COMPONENTS OF THE PLANT
FOR TAKAOKA KYODO POWER CO., LTD.
No.
Item
Quantity
Description
1 Cooling tower
2 Absorber
3 Mist eliminator 1
4 Flue gas fan
5 Air blower
6 Absorbent pump 2*
7 Oxidizer
8 Centrifuge
4*
9 Soot filter 1
10 Gypsum thickener 1
11 Clarifier 1
12 Dust thickener 1
4.55 m dia. x 16.4 m ht.
spray tower with carbon steel lining
5.6 m dia. x 10.4 m ht.
Moretana plate tower with 3 plates of
AISI 304L S.S.
Horizontal flow type
carbon steel casings with lining
and polypropyrene elements
Turbo-fan 376,000 Nm3/hr,
600 mmHaO; 1,100 kW
'Casing: carbon steel with rubber lining
Runner: AISI 316L S.S.
Turbo-blower, 5,280 Nm3/hr
2,000 mmH20, 75 kW,
carbon steel
Centrifugal type, 1,970 m3/hr
20 m head, 200 kW
Casing: cast iron with rubber lining
Impeller: AISI 316L S.S.
7.3 m dia. x 4.5 m ht.
carbon steel with lining
V-flow type, 4 units of air blowers
Vertical type, fully automatic,
37 kW each
Super-decanter, 15 kW
6.2 m dia. x 3 m ht.
carbon steel with lining
15.5 m dia. x 3 m ht.
reinforced concrete with lining
5.3 m dia. x 3 m ht.
carbon steel with lining
*Includes one spare unit.
161
-------
drop of the gas, caused plugging of spray nozzles, and
prevented long-term stable continuous operation. S02 removal
efficiency fluctuated between 88 and 94%. To cope with the
problems, a strainer was installed in a slurry circulation line
and gypsum seed was added to the slurry. During a month's shut-
down of the boiler for annual maintenance in June 1977, the
following modifications were made:
1) Changing the design of the tray.
2) Adding one tray.
3) Increasing the L/G ratio from 8 to 10.
4) Improving the washing effect of the scrubber walls
Operation was resumed in July 1977 and has been
carried out continuously with 95% S02 removal efficiency with-
out the tendency of increased pressure drop. The particulates
content of the treated gas is well below 50 mg/Nm3, the guaran-
teed figure.
A gas velocity in the scrubber of 3-4 m/sec has been
used. When the boiler load goes down, a portion of the treated
gas is recycled to the scrubber system to maintain the gas
velocity in the scrubber.
The mist eliminator has been washed with circulated
liquor diluted with water. In order to prevent accumulation of
impurities in the scrubber liquor, 1.8 tons/hr of liquor dis-
charged from the cooler has been purged after being treated.
4.4.4 Evaluat ion
The Sumitomo-Fujikasui process has been successfully
applied for flue gas from iron ore sintering machines with a
162
-------
low SO2 concentration. The Takaoka plant is the first
application for a utility boiler with a relatively high S02
concentration. Although the plant experienced scaling, it seems
that the problem has been solved and the process has proved
applicable to utility boilers.
The Moretana scrubber features a high removal effi-
ciency with a moderate pressure drop. Because of the good gas-
liquid contact, it may be particularly suited for absorption of
NOX, which has a much smaller absorption rate than does S02.
4.5 OPERATION OF OTHER MAJOR LIMESTONE-GYPSUM PROCESS
PLANTS FOR OIL-FIRED UTILITY BOILERS
4.5.1 Tamashima Plant. Chugoku Electric
The Tamashima plant was constructed by Hitachi Ltd.
using Babcock and Wilcox's scrubber and an oxidation system to
by-produce gypsum to treat flue gas from a 500 MW oil-fired
boiler (Figure 4-13).16 Operation parameters are shown in
Table 4-4.
The boiler is for base load and undergoes little load
fluctuation; it is reduced to 450 MW at night. Four scrubbers
were installed, one of which is for stand-by. Operation of the
plant started in July 1975. In the early period of operation,
spray nozzle plugging was encountered, which was solved by im-
proving the strainer of the circulation pump.
The operation hours in a recent year are shown in
Table 4-20. The major problem has been the scaling at the
afterburner, which may be caused by the calcium sulfate in the
mist. The plant has a pipe-and-fin type mist eliminator which
163
-------
TABLE 4-20. OPERATION HOURS OF TAMASHIMA NO. 3 PLANT
Oct. 1976
Ho.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
TOTAL -
Total
(A)
744
720
744
744
672
744
720
744
720
744
744
720
8,760
Houra
Boner oper-
ation (B)
744
720
234
9
669
744
720
744
624
744
645
720
7,317
FGD oper-
ation (C)
744
675
234
0
661
717
644
744
596
744
645
720
7,124
Availability (%)
Boiler FGD
(B/A) (C/A)
100
100
31.
1.
99.
100
100
100
86.
100
86.
100
83.
5
2
6
7
7
5
100
93.
31.
0
98.
96.
89.
100
82.
100
86.
100
81.
8
5
4
4
4
8
7
3
Oper-
ability
(C/B) «)
100
93
100
0
98
96
89
100
95
100
100
100
97
.8
.8
.4
.4
.5
.4
Remarks
After-burner scaling
(Annual maintenance of
I (Dec. 11 through Feb.
Repair of impeller
After-burner scaling
After-burner scaling
Shutdown of boiler
boiler
1)
-------
Ln
r
TO STACK
BOILER | ESP
MIST ELIMINATOR
! 1
r
PRESCRUBBER
AFTER BURNER
1
WATER I V^>
CH n-
SCRUBBER
LIMESTONE
MILL
AIR
H2S04
6VPSUM
Figure 4-13. Flow sheet of Tamashima plant, Chugoku Electric.
-------
gives a small pressure drop. Presumably, the mist eliminator
is not highly efficient. Operability of the plant has reached
9770.
The plant uses limestone ground so that 95% passes a
325 mesh screen, and by-produces 93,000 tons/year of gypsum
containing about 10% moisture. The gypsum has been sold for
wallboard and cement. The plant removes about 96% of SO2 (about
1,500 ppm). The pressure drop is fairly heavy and the plant
requires 3.5% of the power generated by the boiler.
4.5.2 Karatsu Plant, Kyushu Electric
The Karatsu plant, Kyushu Electric, with a capacity of
treating half of 720,000 Nm3/hr flue gas from a 500 MW oil-fired
boiler using the MHI limestone-gypsum process has been in smooth
operation as shown in Table 4-21. The operability is 100% ex-
cept during the use of a low-sulfur oil at the start-up of the
boiler.
The operation parameters are shown in Table 4-4. The
plant, as well as other plants by the MHI process, is character-
ized by a slight pressure drop of gas and a low consumption of
power.
4.6 OPERATION OF THE CHIYODA JET BUBBLING PROCESS17'18
4.6.1 Outline
Chiyoda Chemical Engineering and Construction Co. has
developed a new limestone scrubbing process using a jet bubbling
reactor and has operated a pilot plant with a capacity of treat-
ing 1,000 Nm3/hr of flue gas from an oil-fired boiler. The
166
-------
TABLE 4-21. OPERATION HOURS OF KARATSU PLANT
Sept. 1976
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
TOTAL -
Total
(A)
720
744
720
744
744
672
744
720
744
720
744
744
8,760
Hours
Boiler oper-
ation (B)
720
744
720
744
744
191
159
720
744
297
744
744
7,271
FGD oper-
ation (C)
720
744
720
743
739
187
150
720
744
291
744
744
7,246
Availability <%)
Boiler PGo
(B/A) (C/A)
100
100
100
100
100
28.4
21.4
100
100
41.3
100
100
83.0
100
100
100
99.9
99.3
27.8
20.2
100
100
40.4
100
100
83.5
Oper-
ability
(C/B) (%) Remarks
100
100
100
99.9
"99.3
47 9 /
(Annual maintenance of boiler
94.3 i
100
100
98.0 Boiler shutdown
100
100
99.7
-------
process is simple and uses a reactor to which flue gas,
limestone, and air for oxidation are introduced. Gypsum slurry
is discharged from the reactor. Since the slurry is circulated
in the reactor by agitation, no circulation pump is needed.
Construction is now under way on a 20 MW demonstration plant at
Gulf Power Company's Scholz plant. The unit is expected to be
operational in June 1978.
4.6.2 Jet Bubbling Reactor
A jet reactor is shown in Figure 4-14. The reactor
consists of two zones, a jet bubbling zone for SO 2 absorption
and a reaction zone for gypsum formation. Flue gas is dispersed
from many spargers with open ends 100 - 400 mm below the liquid
surface as shown in Figure 4-15. The diameter of the bubbles
ranges from 3 to 20 mm. The bubble penetration length is re-
lated to the gas sparging velocity and the submergence depth as
shown in Figure 4-16. The contact time of a gas bubble with
liquid ranges from 0.5 to 1.5 seconds.
The large gas- liquid contact area and the turbulent
motion of the liquid provide efficient SO 2 removal as shown in
Figures 4-17 and 4-18. A computer program was developed to re-
late measured operating variables with SO 2 removal efficiency.
Good agreement with the measured S02 removal efficiency was
obtained by equations (1) , (2) , and (3) below. The correlation
is shown by the solid lines in Figures 4-17 and 4-18.
nso2 = l " exp z1
where Ni = 28.5 U (AP/400)"1 (10~PH)
x (XS02/1, 000) a*™ (x02/3)-°-"2 (2)
N2 = 3.77 (U)-°'22 (AP/400)1-25 (3)
168
-------
Water
Clean gas
Flue gas
vo
Limestone
slurry
Gas out Gas out
Gas In
t
t
" I T
t
•> . . • . . . . .
Initial
liquid
Q V level
oQ,
Jet
Bubbling
Air
•
n I
Submergence
depth
i
Gypsum Slurry
Figure 4-14. Jet bubbling reactor.
Figure 4-15. Schematic drawing
of gas sparger.
-------
0)
a
5
•u
cd
M
4J
s
0)
a.
-------
U
X
Superficial gas velocity, Nm3/m2-sec
Concentration in gas, ppm by volume
100
I
CM
o
90
80
S02 1,000 ppm
O Measured
— Calculated
200 300 400
AP (mm H20)
500
Figure 4-18. Pressure drop and S02
removal efficiency.
The reaction zone is at the lower part of the reactor,
where air bubbles are introduced to oxidize calcium sulfite to
gypsum. The slurry in the reaction zone is moderately stirred
by both air bubbling and mechanical agitation (Figure 4-19).
The slurry retention time ranges from 1 to 4 hours to ensure
over 99% limestone utilization (Figures 4-20 and 4-21). The
long reaction time allows gypsum crystals to grow to a desired
size.
Scaling problems can be eliminated by keeping the gyp-
sum concentration in the slurry at 10-20% and securing a suffi-
cient liquid volume; newly formed gypsum will deposit on the
171
-------
surface of gypsum crystals in the slurry and not on reactor
walls and internals.
A series of experiments in fluid mechanics and dynam-
ics was conducted with a water-air system using Lucite vessels,
which were 500, 800, 1,000 and 3,000 mm in diameter and 3,000 mm
in height, and in which air was made to flow at 1,000 - 20,000
m3/hr.
Chiyoda claims that a large reactor using one agitator
can be designed with a capacity of treating flue gas from a 250
MW boiler.
Jet
bubbling
zone
Reaction
zone
Figure 4-19. Liquid flow pattern in
jet bubbling reactor.
172
-------
c
o
N
cu
e
o
w
CO
0)
1.0
0.8
0.6
0.4
0.2
0
Particle size
A - 325 mesh 98%
B - 325 mesh 86%
C - 325 mesh 65%
Temp. 122°F
Residence time 1 hr.
4567
pH of liquor
Figure 4-20. Effect of pH on limestone utilization
1.0
c
o
N
T-l
8
o
4J
CO
0)
S
A pH 5.49
B pH 5.65
Particle size
A - 325 mesh 98%
B - 325 mesh 86%
Temp. 122°F
1 2
Residence time, hrs.
Figure 4-21. Effect of residence time on limestone
utilization.
173
-------
4.6.3 Process Flow Diagram
A flowsheet of the pilot plant is shown in Figure
4-22. Major components are listed in Table 4-22. Flue gas is
first treated in a prescrubber to remove particulates in order
to obtain high-purity gypsum. A purge would be required to re-
move particulates and chlorides from the prescrubber loop. The
gypsum slurry discharged from the reactor is centrifuged and
the mother liquor is returned to the reactor. The pilot plant
has a line to circulate a portion of the gypsum slurry to the
scrubber, but tests have shown that this line is unneeded.
Typical operation data and gypsum quality are shown in Tables
4-23 and 4-24. A schematic flow diagram of a plant to by-
produce throw-away gypsum is shown in Figure 4-23. The process
is simple, without a prescrubber or a slurry circulation line.
Gypsum slurry discharged from the reactor is sent to a waste
disposal pond and the supernatant is circulated to the scrub-
bing system. In application to a coal-fired system, a small
portion of the filtrate from the gypsum centrifuge or of the
supernatant liquor from the pond may have to be purged to limit
the chloride concentration in the system. The gypsum may be
suitable for landfill disposal.
4.6.4 Economics
Table 4-25 compares the cost of the jet bubbling pro-
cess with two conventional lime scrubbing processes — suitite
sludge by-production and forced oxidation to by-produce gypsum.
Capital cost for the jet bubbling process is estimated at
$31.2/kW, which is less than half that for other processes.
The annualized cost is also considerably lower. This includes
fuel oil for reheating the gas to 140°C (280°F), which accounts
for more than 50% of the operation cost. Annualized cost for a
174
-------
TREATED OAS
MIST AA
ELIMINATOR ' '
CENTRIFUGE
WATER
r
Ln
PRESCRUBBER AIR
JET
BUBBLING
REACTOR
LIMESTONE
W
FLUE GAS
<, 1
GYPSUM
MOTHER LIQUOR
TANK
Figure 4-22. Pilot plant process flow diagram.
-------
TABLE 4-22. MAJOR EQUIPMENT OF PILOT PLANT
Equipment
Type
Size
Material
Precooler
Jet bubbling reactor
Mother liquor tank
Flue gas blower
Spray column
Turbo
Cooling water circulation pump Centrifugal
Gypsum slurry pump
Mother liquor pump
Centrifuge
Centrifugal
Centrifugal
Screw decanter
0.7m dia. x 3.2 m ht
0.5m dia. x 4.0 m ht
1.5 m dia. x 2.6 m ht
1,000 Nm3/hr
at 700 mm H20
1 m3/hr at 20 m H20
5 m3/hr at 20 m H20
3 m3/hr at 20 m H20
316L S.S.
316L S.S.
FRP
C.S.
Rubber
lining
Rubber
lining
Rubber
lining
Stellite
316L S.S.
-------
TABLE 4-23. TYPICAL PILOT PLANT OPERATING DATA
Conditions
Flue gas flowrate
to precooler scfm on wet basis
Flue gas temperature °F
Flue gas composition
S02 ppm on wet basis
02 % on wet basis
C02 % on wet basis
H20 % on wet basis
S02 loading at
JBR outlet ppm on 'wet basis
S02 removal %
Temperature of
JBR liquid °F
Oxidation air scfm
Pressure drop in JBR in. H20
Limestone utilization %
Typical Values for
low-sulfur gas high-sulfur gas
585
135-140
1,000-1,100
2.9-3.2
11.0-11.5
16.5-19.0
77-85
92
135-140
12.4
13.8-15.8
99.3
585
135-140
2,900-3,000
2.9-3.2
11.0-11.5
16.5-19.0
360-380
87
135-140
31.0
13.8-15.8
99.1
TABLE 4-24. GYPSUM QUALITY
Particle size:
Average Stokes' diameter
Chemical composition (wt %, dry basis):
as CaSOit-2H20
CaSOa (sulfite)
CaC03
PH
Free water (wt %, wet basis)
Mortar strength (psi):
Tensile
Compression
Bending
60 microns
98.02
undetectable
0.41
6.8
13.5
135
640
384
177
-------
00
WATER
.<^UT" v"- • --x< -""
- ^;vSKS^\---~ -X
^/ S • — «^»
Figure 4-23. Process flow diagram of prototype plant
-------
TABLE 4-25. COSTS FOR 60 MW UNIT
Design bases:
70% load factor; 3% sulfur In coal; 90% SOa removal efficiency;
280°F reheat temperature
Unit
Limestone scrubbing
Jet Bubbling Limestone followed by
FGD Scrubbing oxidation
vo
Capital cost
Annual operating cost
Electricity
Process water
Cooling water
Limestone*
Fuel oil
Low pressure steamt
Labor
Maintenance
Subtotal
Capital charge
Overhead
Total
Capital cost per kW
Annualized cost
$0.01/kWh
$0.1/1,000 gal
$0.05/1,000 gal
$10/ton
$70/kl
$5/ton
$15,000/man-year
3% of capital cost
17.5% of capital cost
10% of direct cost
1,870,000 3,800,000
$/year
85,148
4,417
" 2,103
106,271
417,222
11,431
11 120,000
" 56,100
11 802,692
" 327,250
80,269
1,210,211
$/kW 31.2
mills/kWh 3.29
89,090
4,859
1,000
148,779
417,222
11,431
120,000
114,000
906,381
665,000
90,638
1,662,019
63.3
4.52
4,500,000
110,377
4,417
2,103
116,898
417,222
11,431
120,000
135.000
917,448
787,500
91.745
1,796,693
75.0
4.88
#90% through 325 mesh as 100% pure
atomizing reheater fuel
-------
200 MW plant without gas reheating is estimated at 1.87 mils/
kWh (Table 4-26).
4.6.5 Evaluation
The process is based on a new concept and has a few
advantages. It is simple and requires low investment and oper-
ation costs. Plant operation seems easy, being free from
scaling problems. Although gas pressure drop in the reactor is
not small, total power consumption seems low because slurry
circulation pumps are not needed.
A possible disadvantage is that it may not be easy to
attain a very high SO 2 removal efficiency, say above 95%, with
a gas rich in S02. Gulf Power's Scholtz plant will give further
information.
TABLE 4-26. CAPITAL AND OPERATION COSTS FOR 200 MW UNIT
Design bases:
70% load factor; 3% sulfur in coal; 90% S02
removal efficiency.
Item
Capital cost
Annual operating cost:
Electricity
Process water
Cooling water
Limestone
Labor
Maintenance
Subtotal
Capital charge
Overhead
Total
Capital cost per kW
Annualized cost
$0.02/kWh
$0.1/1,000 gal
$0.05/1,000 gal.
$10/ton
$7 . 8 5 /man-hour
3% of capital cost
Unit
$
$/year
ii
ii
17.5% of capital cost "
10% of direct cost
11
11
$/kW
mills/kWh
Jet Bubbling FGD
6,200,000
418,200
8,700
7,000
360,000
120,000
186,000
1,099,900
1,085,000
109,990
2,294,890
31.00
1.87
180
-------
SECTION 5
INDIRECT AND MODIFIED LIME/LIMESTONE PROCESSES
5.1 GENERAL DESCRIPTION
5.1.1 Outline
Indirect lime/limestone processes have been developed
to ensure scale-free stable operation. Included in this cate-
gory are the so-called double-alkali processes, which use alka-
line solutions for absorption and lime or limestone for precipi-
tation, and other similar processes which use acidic solutions
for absorption. Major installations are shown in Table 5-1 and
operation parameters in Table 5-2.
The scrubbing liquors consist of sodium sulfite for
Kureha-Kawasaki, Showa Denko, and Tsukishima; ammonium sulfite
for Nippon Kokan; dilute sulfuric acid containing ferric sul-
fate for Chiyoda; aluminum sulfate for Dowa; acidic ammonium
sulfate for Kurabo; and sodium acetate for Kureha.
The pH of the liquors is 6 to 7 for ammonium and sodium
sulfites; 5 for sodium acetate; 3 to 4 for ammonium and alu-
minum sulfates; and 1 for sulfuric acid. The L/G ratio is 1-2
(7-14 gal/1,000 scf) for the solutions of pH 6-7; 3-10 for the
solutions of pH 3-5; 30-50 for the acid at pH 1. The more
acidic the solution is, the smaller the S02 absorption capacity
and the easier the reaction with limestone. The problem of
scaling may also be less at lower pH, as it is for limestone
181
-------
TABLE 5-1. INDIRECT AND MODIFIED LIME/LIMESTONE PROCESS INSTALLATIONS
oo
ro
Proceaa
developer
Chlyoda
n
"
it
11
•t
ii
n
n
it
n
n;
It
I
It
Showa Danko
n
n
Show* Denko-
Ebara
n
n
n
n
n
n
n
n
Absorbent,
precipitant Uaer
HaSO*. CaCOi Nippon Mining
11 Fuji Koaan
Mitsubishi Rayon
Daicel
" Blectrochem. Ind.
" Tohoku Oil
" Mitaublahi Chem.
" Anagaaaki Coke
" Hokuriku Electric
" Mitsubishi Pet.
" Mitaublahi Pet.
" Gulf Power
" Denki Kagaku
" Hokuriku Electric
' Toyama Power
NajSOi, CaCOi Showa Denko
" Kanegafuchi Chem.
" Showa Pet. Chem.
" Nippon Mining
" Yokohama Rubber
" Niaahin Oil
" Poly Plastics
" Ajinomoto
1 Kyowa Pet. Chem.
" " Japan Food
" Yokohama Rubber
" Asia Oil
Plant site
Mlzuahima
Kainan
Otnke
Aboahi
Chiba
Sendai
Yokkalchi
Kakogawa
Toyama
Yokkaichi
Yokkaichi
Florida
Chiba
Fukul
Toyama
Chiba
Takaaago
Kawasaki
Saganoaeki
Hlratauka
laogo
Fuji
Yokkaichi
Yokkalchi
Yokkaichi
Mie
Yokohama
Capacity
(1,000
Nm»/hr)
34
160
90
99
75
14
420
36
750
150
750
85
122
1,050
750
500
300
200
120
105
100
212
82
150
100
100
243
Source of gas
Clous furnace
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Claua furnace
Industrial boiler
Incinerator
Utility boiler
Industrial boiler
Industrial boiler
Utility boiler
Industrial boiler
Utility boiler
Utility boiler
Industrial boiler
Industrial boiler
Industrial boiler
H2SOS plant
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Inlet
SOi (ppm)
9,300
770
1,600
1,400
7,100
1,200
11,300
600
1,300
1,200
1,700
1,400
1,500
1,500
1,500
1,500
1,400
Year of
completion
1972
1972
1972
1973
1973
1973
1974
1974
1974
1974
1974
1975
1975
1975
1975
1973
1974
1974
1973
1974
1974
1974
1974
1974
1975
1975
1975
{Continued)
-------
TABLE 5-1. (Continued)
00
u>
Process
developer
Kureha- Kawasaki
KI
ti
it
ii
Nippon Kokan
Tsukishina
'-'
Kurabo Eng.
n
ii
11
"
Dova Mining
i
'
i
"
"
n
Kureha
Cheaical
Kobe Steel
"
11
"
Kawasaki H.I.
"
Abaorbent,
precipitant User
NaiSOj, CaCOj Tohoku Electric
Shlkoku Electric
1 Shlkoku Electric
1 Kyushu Electric
' Tohoku Electric
(NHi,)iSO), CaO Nippon Kokan
NajSOj, CaO Klnuura Utility
' Daishowa Paper
(HHi,)jSOi,, CaO Kuraray
' Daicel
' Brldgestone Tire
' Bridgestone Tire
Jujo Paper
Ali(SO»),, CaCOi Taenaka Mining
1 Dowa Mining
" Nalkal Engyo
1 Yahagi Iron
" Nlhon Seiko
Kowa Seiko
" Mitsubishi Metal
CH,COONa Kureha Chemical
CaCl2l CaO Kobe Steel
' Kobe Steel
Nakayama Steel
Kobe Steel
MgO, CaCOj Unltlka
MgO, CaO Nippon Ex Ian
Plant site
Shinsendai
Sakaide
A nan
Buzen
Aklta
Keihln
Nagoya
Fuji
Tamashima
Aboahl
Tosu
Tochigi
Ishlnomaki
Mobara
Okayama
Okayama
Nagoya
Nakase
Tobata
Nlshiki
Amagasakl
Kobe
Osaka
Kakogawa
Okazaki
Saidaiji
Capacity
(1,000
Nm'/hr)
420
1,260
1,260
730
1,050
150
185
264
100
163
60
80
200
3.5
150 x 2
70
50
30
72
140
5
175 x 2
350 x 2
375
1,000
200
300
Source of gas
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Sintering plant
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Kiln
HJ SO* plant
Industrial boiler
Sintering plant
Sintering plant
H2SOi, plant
Smelting furnace
Industrial boiler
Sintering plant
Sintering plant
Sintering plant
Sintering plant
Industrial boiler
Industrial boiler
Inlet
S02 (ppm)
420
1,500
1,500
1.5UO
1,500
400
1.500
1,300
1,200
7,500
650
1,500
2,500
5,000
750
4,000
1,500
500
500
500
500
1,600
1,400
Year of
completion
1974
1975
1975
1977
1977
1972
1974
1975
1974
1975
1975
1975
1976
1972
1974
1976
1976
1976
1978
1978
1975
1976
1976
1976
1978
1975
1975
-------
TABLE 5-2. OPERATION DATA OF INDIRECT AND MODIFIED LIME/LIMESTONE PROCESS PLAN]
oo
•P-
Process developer
Absorbent
Precipitant
Plant Owner
Plant site
Fuel
FGD capacity (1,000 Nn'/hr)
FGD capacity (MM)
Inlet S0» (ppm)
Inlet dust (mg/tta')
Inlet gaa temperature (*C)
Number of scrubber* in parallel
Prescrubber type
L/C (liter s/Nm1)
Scrubber type
Liquor pR
Concentration
L/C (liter e/Nm5)
Gas velocity (m/sec)
Outlet SOj (ppm)
Outlet dust (ng/Nm1)
S02 removal efficiency (X)
Mist eliminator type
Prescrubber
saure Scrubber
(mmH20) Mist eliminator
Total system
Haatewater purged (t/hr)
Energy requirements (Design)
Pump (kW)
Fan (kW)
Total system (kW)
Per cent of power generated
Operabllity (X)
Kureha-
Kawasakl
NaOH
CaCOt
Shikoku
Electric
Sakalde
Oil
1,270
450
1,270
20
135
2
None
Packed
6.2
20
1.2
2
70
10
95
Terellette
115
25
310
None
7,900
1.8
98.6
* Iron-ore sintering plant tvertical cone
Showa
Denko
NaOH
CaCOi
Showa
Denko
Chlba
Oil
500
150
1,400
100-200
140
4
None
vet
6.8
25
0.5-1
50-90
Below 50
93-96
300-500
30-50
400-700
4-6
3,500
2.3
98.7
Chlyoda
Hi SO*
CaCOi
Hokurlku
Electric
Fukul
Oil
980
350
1,800
30
140
1
Venturl
Packed
1
1-2
40-60
80
96
Euro form
680
7-24
5,300
5,500
12,300
3.5
100
tHultl-venturl §30X
Down
A12(SO»)J
CaCOj
Nalkal
Engyo
Okayama
Oil
72
(25)
1,500
200
170
1
Spray
2.5
Packed
3.5
10
1.2
100
50
93
Wire nesh
10-20
70-80
20-30
170
0.3
150
300
580
2.3
99.6
CaClj -I- 61
Kurnbo
NHj
CaO
Oil
115
(40)
1,480
150
170
1
1.4
Packed
3.8
10
8
2
130
Below 50
91
Euroform
130
120
300
None
470
190
880
2.2
99.3
CaO
Nippon
Kokan
NHi
CaO
Nippon
Kokan
Keillln
Coke*
150
(50)
350
80
120
1
Spray
1.0
Screen
6.0
30
2
2
10-20
300
2
Above 95
Kobe
Steel
CaO-CaClj
Nakayama
Steel
Funamachi
Coke*
375
(125)
150-250
300-400
140-155
1
Spray
3.5
Venturl
5-5.5
30+6§
3
3
15-25
40-50
90
Euroform
15
120
35
220
None
1,200
1,000
2,600
2.1
98.1
Kawasaki
II. 1.
Mg(OH)2
CaO, CaCOj
Unltika
Okazakl
Oil
200
68
1,400
200
170
1
None
MVt
5-6
6
3
Below 140
Below 100
Above 90
Louver
115
50
230
None
430
370
1,160
1.7
99
-------
scrubbing processes. Limestone can be reacted with a sodium
bisulfite solution, as in the Showa Denko and Kureha-Kawasaki
processes, but the reaction occurs slowly, requiring large reac-
tion vessels. Lime is used for the Tsukishima, NKK, and Kurabo
processes.
In the Chiyoda, Dowa, Kureha, and Kurabo processes, the
liquors which have absorbed S02 to form SO" are contacted with
air to oxidize the SO" into SO". Limestone or lime is then
added to precipitate gypsum. In the other processes, limestone
or lime is added before oxidation to precipitate calcium sulfite.
The calcium sulfite is then
-------
and ammonium sulfate is readily decomposed by lime. Plume forma-
tion, however, is a major problem with ammonia scrubbing.
Recently, two modified lime/limestone processes have
been developed aiming at scale prevention. They are the Kobe
Steel process which uses a 30% CaCl2 solution dissolving lime as
the absorbent, and the Kawasaki Magnesium Gypsum process which
uses a magnesium hydroxide slurry containing lime or limestone
as the absorbent. Plants using these processes are listed in
Table 5-1 and their operation parameters are given in Table 5-2.
5.1.2 Operability and Economics
Figure 5-1 illustrates the relationship of scrubber
liquor pH to operability, L/G ratio, and energy requirement (%).
The data apply to FGD plants listed in Table 5-2 treating flue
gas containing over 1,200 ppm S02 from oil-fired boilers to by-
produce gypsum. The figure clearly shows that the lower the pH,
the larger the L/G ratio and the higher the operability. The
energy requirement, however, is also generally larger with a
lower pH, because of the energy needed to circulate a larger
amount of liquor.
The decrease in operability at a higher pH is appar-
ently caused mainly by scaling. Circulation of a large amount
of liquor in a scrubber helps prevent scaling. In addition,
there may be some chemical reasons for the lower tendency of
scaling at lower pH levels. The reason for this tendency, how-
ever, which has generally been experienced with limestone scrub-
bing systems, has not yet been clarified.
Figure 5-1 also shows data from two wet lime/limestone
process plants (Owase-Mita plant, Chubu Electric; and Tamashima
186
-------
pH
100
6*8
4-1
•H
iH
CO
1-1
OJ
99
98
97 «-
4 r
cr
0)
t>0
p
1
Energy requirement
Q ^ Q Indirect lime/limestone process
Wet lime/limestone process
0
-i 4
10
345
pH of scrubber liquor
Figure 5-1. pH of scrubber liquor and performance,
187
-------
plant, Chugoku Electric) which treat flue gas containing about
1,500 ppm S02 from oil-fired boilers. The pH of the slurry
ranges from 6.5-7.0 and operability is a little over 98%. These
figures are close to those for sodium-limestone double alkali
processes. A distinct difference between the double alkali and
wet lime/limestone processes is seen in the L/G ratio, which is
about 1 for the former and 7-10 for the latter. A much larger
L/G is needed for the lime/limestone process for two reasons:
1) S02 absorption rate is slow because it is controlled by the
dissolving rate of lime or limestone, and 2) a large amount of
slurry flow is needed to prevent scaling and plugging.
A sodium-limestone process plant (pH 6.2) costs about
207o more than a wet lime/limestone process plant but requires
less energy due to the small L/G. Moreover, it is capable of
removing 997,, of SOa when required. A Chiyoda 101 process plant
costs more than a wet lime/limestone process plant because of
the requirement of a large scrubber. It also consumes more en-
ergy because of the large L/G ratio. The plant, however, is
easy to operate and requires little labor as shown in Table 3-13
The plant cost and operation cost of indirect lime/
limestone processes using a liquor with an intermediate pH, the
Dowa, Kurabo, and Kawasaki (magnesium gypsum) processes, seem
much the same as those of wet lime/limestone processes. The
processes using a low-pH liquor may suit plants whose operation
is not easy to control precisely to prevent scaling when a wet
lime/limestone process is used.
188
-------
5.2 CHIYODA THOROUGHBRED 101 (CT 101) PROCESS
5.2.1 Characteristics
The CT 101 process is characterized by the use of di-
lute sulfuric acid containing a ferric sulfate catalyst as the
absorbent. A flowsheet of the process is shown in Figure 5-2.
Absorption and oxidation take place in a double-cylinder vessel,
with the oxidizer inside and the absorber outside. A diagram
of this vessel is shown in Figure 5-3. The absorbing liquor
discharged from the scrubber is oxidized by air to convert the
absorbed S02 to H2SO.». Most of the liquor is returned to the
absorber and a portion is neutralized with limestone to preci-
pitate gypsum. The gypsum slurry is centrifuged and the mother
liquor is returned to the absorber. Gypsum is sold for wall-
board and cement. Details of the process are available in pub-
lished literature. x°. 16- 19
Commercial plants using the process are listed in
Table 5-1. Operation parameters of the Fukui plant, Hokuriku
Electric, are shown in Table 5-2. Maximum and minimum S02 re-
moval efficiencies obtained in test runs at a commercial plant
for variations in H2SO.» concentration are shown in Figure 5-4.
Since the S02 absorbing capacity of sulfuric acid is not high,
a dilute acid (2-3% in concentration, normally about 2.5%) is
used (Figure 5-4) at a large L/G ratio of 40-60 (Table 5-2).
The large L/G results in the consumption of a fairly large amount
of energy (Figure 5-1). On the other hand, plant operation is
easy and requires little labor (Table 3-13).
189
-------
TO STACK
VO
O
r
WASTE DISPOSAL
Figure 5-2. Flow sheet of CT 101 process.
-------
Liquor
Distri-
butor
Gas
Inlet
Liquor
Outlet
« H
t
Gas Outlet
DDDDDt
v/vx v/v/
Liquor Outlet
Air
Inlet
Liquor
Inlet
Figure 5-3. Double-cylinder type reactor.
191
-------
100
o>
o
CO
43
CO
l-l
0)
CO
g
cu
•H
O
•H
W
CO
o
3
0)
CM
O
CO
90
80
70
1.5
Figure 5-4.
vs H2
Operating Condition
1) Flue gas rate 750,000 Nm3/H
2) 02 cone, in flue gas 2.5-6.8 vol%
3) Sulfur cone, in fuel oil 1.0 wt%
2.0
3.0
3.5
2.5
H2SO,»(%)
Maximum and minimum S02 removal efficiencies
concentration as determined by test
runs at a commercial plant.
5.2.2 Operation of Commercial Plants
The performance of 3 plants for utility boilers is
shown in Table 5-3. The Toyama plant, Hokuriku Electric, which
treats half of the flue gas from a 500 MW boiler burning 1%-
sulfur oil, went into operation in October 1974. In January
1975 the plant experienced mist eliminator breakage due to unu-
sual vibration. The operability has been 100% since April 1975.
The Fukui plant, Hokuriku Electric, treats all the flue gas from
a 350 MW oil-fired boiler burning 3%-sulfur oil. The plant,
put into operation in June 1975, had problems with a stirrer
192
-------
TABLE 5-3. UTILITY BOILER AND FGD PERFORMANCE (1975 - AUG. 1977)
Power FGD
company capacity
(Plant) (MW)
Hokuriku
Electric 250
(Toyama)*
Hokuriku
Electric 350
(Fukui)t
VO
°* Toyama
Coop. 250
(Toyama) T
Operation period
Apr.
Apr.
Apr.
June
Apr.
Apr.
Oct.
Apr.
Apr.
75
76
77
75
76
77
75
76
77
- Mar.
- Mar.
- Aug.
- Mar.
- Mar.
- Aug.
- Mar.
- Mar.
- Aug.
76
77
77
76
77
77
76
77
78
Total
hours
8,760
8,760
3,672
7,296
8,760
3,672
4,368
8,760
3,672
Boiler
operation
hours
6,281
6,670
2,594
5,336
7,141
3,565
3,076
5,647
3,132
FGD
operation
hours
6,
6,
2,
5,
7,
3,
3,
5,
3,
281
670
594
217
141
565
039
647
132
Boiler
availa-
bility (%)
71.
,7
76.1
70.
73.
81.
97.
70.
64.
85.
6
1
5
1
4
4
3
FGD
opera-
bility (%)
100
100
100
98
100
100
99
100
100
*Started Oct. 1974. Sulfur in oil: 1%
tStarted June 1975. Sulfur in oil: 3%
^Started Oct. 1975. Sulfur in oil: 3%
-------
due to improper design and misoperation in June and July of the
year. The operability has been 100% since August 1975. The
Toyama plant, Toyama Cooperative, treats all of the flue gas
from a 250 MW oil boiler burning 3%-sulfur oil. The plant went
into operation in October 1975 and soon encountered abrasion of
the sludge mixer, which required repairing in February 1976.
The operability has been 100% since.
All three plants have had an operability of 100% since
1976, but this does not mean they have been trouble-free. Al-
though several problems were encountered, these were solved
without stopping plant operation. The operation hours and prob-
lems of the Fukui plant in a recent one-year period are shown
in detail in Tables 5-4 and 5-5, respectively.
The boiler of the Fukui plant is for base load opera-
ted at 350 MW on weekdays and at a reduced load Sunday and
holiday nights (Figure 5-5). As shown in Figure 5-6, a by-pass
damper is kept open so that a small portion of the gas treated
by FGD is circulated to the scrubber.
5.2.3 Economics
Typical economic data of two plants for 250 and 350 MW
boilers burning 3%-sulfur fuel are shown in Table 5-6. A con-
version rate of $1 = ¥300 was used for the calculation. The
table indicates annualized operation costs of 3.2 and 3.0 mills/
kWhr for the two plants, assuming 8,000 hours annual operation,
gas reheating to 290°F (143°C), and fixed costs equivalent to
17.5% of capital. For most utility boilers in the U.S., the
annual operation hours may be fewer and the gas reheating temp-
erature is much lower. For 7,000 hours annual operation with
194
-------
TABLE 5-4. OPERATION HOURS OF FUKUI PLANT, HOKURIKU ELECTRIC
Oct. 1976
Nov.
Dec.
Jan. 1977
Feb.
Mar.
to Apr.
Ul
May
June
July
Aug.
Sept.
TOTAL
Total
(A)
744
720
744
744
672
744
720
744
720
744
744
720
8,760
Hours
Boiler oper-
ation (B)
197*
535
694
703
672
685
720
668
720
717
744
385*
7,440
Availability (7d
FGD oper-
ation (C)
197*
535
694
703
672
685
720
668
720
717
744
385*
7,440
Boiler
(B/A)
26.5*
74.3
93.2
94.5
100
92:0
100
89.7
100
96.3
100
53.4*
84.9
FGD
(C/A)
26.5*
74.3
93.2
94.5
100
92.0
100
89.7
100
96.3
100
53.4*
84.9
Opera-
bility
(C/B) (%)
100
100
100
100
100
100
100
100
100
100
100
100
100
*The short operation hours are due to annual shutdown of the plant.
-------
TABLE 5-5. TROUBLES AT THE FUKUI PLANT AND REMEDIES
No.
1
Date
Oct. 22, 1976
Trouble
One of two motors of air blower of
oxidizer burned out.
Remedy
Operated with one motor and
removal was maintained.
90% SO 2
Feb. 19. 1977
Leakage of liquor from prescrubber
due to ruined packing. For an hour
while packing was replaced, flue gas
was sent directly to main scrubber
bypassing the prescrubber.
During the one-hour repair work,
fuel oil with less sulfur was
burned and 55% of flue gas was
treated by FGD system avoiding
overheating of scrubber and meeting
emission standard.
Mar. 8, 1977 A pump had trouble with rubber lining. A spare pump was used.
V£>
July 24, 1977
Gypsum lump formed on upper inside
wall of crystallizer fell off and
bent stirrer.
Remaining three crystallizers were
used for 3 months while stirrer was
under repair.
Three times
Minor problems with reheater firing,
FGD plant operation was not affected,
-------
Week days 350 MW (Constant)
Sundays and holidays (Case 1)
350 MW
6 a.m.
3:30 p.m. 350 MW
150 MW
(Case 2)
350 MW
12 midnight
5:30 p.m. 350 MW
7:30 a.m. 150 MW
^100 MW /
4 a.m. 7 a.m.
5 p.m.
Figure 5-5. Operation load of Fukui plant.
DAMPER
(OPEN)
BOILER
•STACK
I
KEHEATINO FURNACE
Figure 5-6. Bypass system of Fukui plant.
197
-------
TABLE 5-6. TYPICAL ECONOMIC DATA OF COMMERCIAL PLANTS ($1 = ¥300, 1976)
VO
00
Item
1) Gas Source & Capacity
2) Inlet Gas
Capacity
SO i Content
Grain Loading
Temperature
3) SOj Removal Efficiency
4) Utility
Limestone
Electric Power
Industrial Hater
Catalyat (as 39Z aqueous
Fuel for Reheating (No.
5) By-product GypauB
6) GypsuB Specification
Average Sice
Hater Content
solution)
6 oil)
Unit
scfn
ppn
gr/acf
*F
Z
ton/d
kW
gP"
Ib/d
10* Btu/h
ton/d
V
Z
7) Number of Operating Personnel
8) Land Area Requirement
9) Construction Coat**
10) Annual Operating Cost***
Limestone Powder
Industrial Hater
Electric Power
Catalyat
Labor & Supervision
Payroll & Plant Overhead
Maintenance
Capital Charge
By-Product Credit
Sub-Total
Fuel Oil (No. 6)
Total
($4/Ton)****
(0.02$/1,000 gal)****
(O.OlS/kHh)****
(0.062$/lb)
(8$/manhr)****
(140Z of Labor &
Supervision)
(2Z of Capital)
(17. 5Z of Capital)
(IS/Ton)
(0.23$/Ral)****
ft2
$
$/y
$/y
5/y
$/y
$/y
$/y
$/y
$/y
$/y
S/y
•llla/kWh
$/y
$/y
mllls/kWh
Case I
Boiler (3Z sulfur),
2SO MW equivalent
466,000
1,630
0.012
287
92.6
125
7.100
185
900
103*
230
100
7
2 men x 4 shifts
103,000
16,000,000
167,000 (2.6Z)
1,800 (O.OZ)
568,000 (9.0Z)
18,500 (0.3Z)
512,000 (8.1Z)
716,800 (11.41)
320,000 (5.1Z)
2,800.000 (44. 3Z)
-77.000 (-1.2Z)
5,027,100
2.5
1.288.000 (20. 4*)
6,315,100 (100. OZ)
3.2
Case II
Boiler (3Z sulfur),
350 MW equivalent
650,000
1,630
0.012
285
96.5
180
11,000
277
1,300
147*
330
100
10
2 men x 4 shifts
142,000
22,300,000
240,000 (2.8Z)
2,700 (O.OZ)
880,000 (10. 4Z)
26,900 (0.3Z)
512,000 (6.1Z)
716,800 (8.5Z)
446,000 (5.3Z)
3,902,500 (46. 2Z)
-110.000 (-1.3Z)
6,616,900
2.4
1.830.000 (21. 7Z)
8,446,900 (100. OZ)
3.0
Remarks
*The reheating
temperature Is
taken as 290*F.
**Baaed on ac-
tual cost re-
quired in 1975.
***8,000 hr/yr
operation
****Based on the
TV A report at
6th EPA FGD
symposium,
March 1976
-------
gas reheating to 172°F (78°C), the annualized costs are about
3.0 and 2.8 mills/kWhr for the 250 and 350 MW plants, respec-
tively.
5.2.4 Evaluation
The plant cost is 10-30% higher than for the usual
lime/limes tone process because a larger scrubber and larger
crystallizers are needed. Power consumption is larger because a
higher L/G ratio is used. The process, however, is highly reli-
able and plant operation is very easy. The actual annualized
operation cost may not be higher than for other processes be-
cause of the stable operation which requires little labor and
maintenance. The process would be suitable where no skilled
plant operators are available and a very high S02 removal effi-
ciency is not required.
5.3 SODIUM LIMESTONE GYPSUM PROCESS
5.3.1 Outline
Sodium-limestone double alkali processes by-producing
gypsum have been developed by Showa Denko jointly with Ebara
Manufacturing Co. and by Kureha Chemical jointly with Kawasaki
Heavy Industries. Many plants have been constructed by the
processes as shown in Table 5-1.
Both processes use a Na2S03-NaHS03 liquor at pH 6.2-
6.8 as the absorbent (Reaction 5-1). Liquor discharged from the
absorber is reacted with CaC03 to regenerate the Na2S03 (Reac-
tion 5-2) .
199
-------
Na2S03 + S02 + H20 = 2NaHS03 (5-1)
2NaHS03 + CaC03 = Na2S03 + CaS03 + H20 + C02 (5-2)
The resulting slurry containing CaS03 is filtered;
Na2S03 liquor is returned to the absorber and the CaS03 sludge
is repulped and oxidized by air to produce gypsum.
Since a portion of the Na2S03 is oxidized by 02 in
flue gas to form Na2SO^, which is incapable of absorbing S02 ,
the Na2S04 is decomposed by the following reaction (Reaction
5-3):
NazSO,, + CaS03 + S02 + H20 = 2NaHS03 + CaSO,, (5-3)
There is a difference between the two processes in
the method of obtaining S02 to be used for Reaction 5-3. In
the Showa Denko process, the S02 is obtained by treating CaS03
with H2SO.»; while, in the Kureha-Kawasaki process a considerable
portion of S02 is produced in a stripper by heating the NaHS03
liquor obtained by Reaction 5-3.
Recently. Kawasaki Heavy Industries constructed the
Buzen plant, Kyushu Electric, in which an electrolytic cell
developed by Ionics, U.S., is used to decompose the Na2SO.» to
NaOH and H2SOi». NaOH is returned to the absorber and H2SOi, is
used for acidulation of the calcium sulfite slurry to promote
oxidation.
5.3.2 Ichihara Plant (Chiba Plant), Showa Denko
The plant has a capacity of treating 500,000 Nm3/hr of
flue gas from two 75 MW oil-fired boilers burning 370-sulfur oil.
Four vertical-cone type scrubbers in parallel are used as shown
200
-------
in Figure 5-7. Details of the process are available in pub-
lished literature.10 Operation parameters are shown in Table
5-2.
The plant was completed in 1973 at a cost of 2 billion
yen and has been operated by 2 unskilled persons per shift plus
a skilled person and a maintenance specialist in the daytime.
The operability in a recent year reached 98.7%, although minor
troubles were encountered as shown in Table 5-7.
The annual cost is shown in Table 5-8. The FGD cost
was 1.13 yen/kWhr last year-including 8 years depreciation and
fuel cost for reheating the gas to 130-140°C. A calculation
based on inflated plant cost - double the 1973 cost in 1978 -
and 15 years depreciation with reheating to 80°C indicates a
cost of about 1.1 yen/kWhr.
5.3.3 Sakaide Plant. Shikoku Electric
The Sakide plant, Shikoku Electric, has a capacity
of treating flue gas from a 450 MW oil-fired boiler by the
Kureha-Kawasaki process by using two scrubbers in parallel.16
Operation parameters are shown in Table 5-2. A flowsheet is
shown in Figure 5-8.
The plant went into operation in October 1976 and had
troubles mainly with separators, piping, and valves of the
regeneration step. The problems have been gradually solved and
operability in a recent year reached 98.5% (Table 5-9).
The plant normally purges no wastewater. To prevent
the accumulation of magnesium derived from limestone, a magne-
sium removal step is incorporated. Chlorine concentration in
201
-------
runiM I-
..PrrL
ro
o
to
nmiu t-
:*?-
'E
ciniivnii
«mt-
\
MO.
1
MATIXOIMtn
•MOM
mtitn com nmi
Figure 5-7. Flow sheet of Ichihara (Chiba) plant, Showa Denko.
-------
TABLE 5-7. OPERATION HOURS OF ICHIHARA PLANT, SHOWA DENKO
Hours
Total Boiler oper-
(A) ation (B)
Sept. 1976
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
Jul*
0 Aug.
720
744
720
744
744
672
744
720
744
720
744
744
720
744
490
175
744
672
740
717
722
720
744
695
Availability
FGD oper-
ation (C)
718
737
490
175
744
640
721
717
717
.683
744
697
Boiler
B/A(Z)
100
100
68.0
23.5
100
100
99.4
99.7
97.1
100
100
93.4
FGD
C/A(%)
99.7
99.1
68.0
23.5
100
95.3
96.9
99.7
96. 4^
94.8
100
91.1
Opera-
bility
C/B(%)
99.7
99.1
100 |
100 (
100
95.3
97.5
100
99.3
94 ."8
100
97.5
Remarks
Repair of pump
Annual maintenance of boiler
Erosion of regeneration
Scaling in regeneration
Inspection of blower
Scaling
Repair of control valve
system
system
TOTAL
8,760
7,883
7,783
90.0
88.8
98.7
-------
TABLE 5-8. FGD COST (ICHIHARA PLANT)
Millions
of yen
Plant cost 2,000
Annual cost
Depreciation 256
Interest 114
Insurance & tax 48
Labor and overhead 30
Maintenance 60
NaOH (23,000 yen/ton) 79.5
H2S04 (10,000 yen/ton) 57.6
CaC03 (4,500 yen/ton) 103.7
Electricity (5.9 yen/kWh) 172.8
Water (18 yen/ton) 8.3
Steam (1,900 yen/ton) 8.7
Fuel (30,000 yen/kl) 345.6
Total Annual Cost 1,284
(1.13 yen/kWhr at 7,580 hours annual operation)
204
-------
o
Ln
FUEL
STACK ^-i 1
RECYCLE.
LIQUOR T
FLUE GAS
CiS04 • 2H28
dC03
Figure 5-8. Flow sheet of Kureha-Kawasaki process.
-------
TABLE 5-9. OPERATION HOURS OF SAKAIDE NO. 3 PLANT
Oct. 1976
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
TOTAL
Total
(A)
744
720
744
744
672
744
720
744
720
744
744
720
8,760
Hours
Availability
Boiler oper- FGD oper-
ation (B) ation (C)*
744
359
135
744
672
744
450
744
720
744
665
720
7,445
738
358
60
744
672
744
440
744
720
744
660
712
7,326
Boiler
B/A(X)
100
49.9
18.1
100
100
100
62.5
100
100
100
89.4
100
84.9
FGD
C/A(%)
99.2
49.7
8.1
100
100
100
61.1
100
100
100
88.7
98.9
83.6
Opera-
bility
C/B (X)
99.2
99.7 }
44.4)
100
100
100
97.8
100
100
100
99.2
98.9
98.5
Remarks
Leakage from liquor circula-
tion pipe of scrubber.
Scheduled annual maintenance
of boiler. FGD start-up was
delayed after boiler start-up,
Boiler stopped by trouble.
FGD started up 10 hours after
boiler started.
Boiler operation stopped.
One scrubber operation test
was carried out.
*0peration hours when both of the two parallel scrubbers were in use.
-------
the scrubber liquor has reached about 4,000 ppm but has had no
adverse effect on the system. By-product gypsum is of good
quality and has been sold for wallboard and cement.
5.3.4 Anan Plant. Shikdku Electric
The Anan plant, Shikoku Electric, has a capacity of
treating flue gas from a 450 MW oil-fired boiler and is similar
to the Sakaide plant mentioned above. The plant went into oper-
ation in August 1975. The operability in a recent year was
close to 100% (Table 5-10). The monthly operation data and
costs are shown in Table 5-
-------
TABLE 5-10. RESULTS OF FGD OPERATION IN ANAN POWER STATION
NJ
O
00
Process :
Capacity :
Start-up :
July 1976
Aug.
Sept.
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
Kurefea-Kawasaki Sodium Sulfite/Gypsum Process
450 MW, 625,
August, 1975
Scrubber
No. 1
245.2
90.2
4.7
0
0
37.7
5.0
0
0
0
312
680.5
000 x 2 Nm3 /hr
shutdown hours
No. 2
248.1
96.1
0
0
15.7
0
0
16.5
19.8
0
312
686
Reasons for shutdown
Periodical maintenance & boiler minor
servicing
Stack cleaning
Spray nozzle plugging
110 MW minimum load test run
110 MW minimum load test run
Nozzle plugging in the inlet cooling
zone
Nozzle maintenance in the inlet cooling
zone
Air heater cleaning
" Annual maintenance of boiler and FGD
Annual maintenance of boiler and FGD
FGD operabilitv %
No. 1 No. 2
100
100
99.4
100
100
100
99.4
100
100
100
100
100
99.9
100
100
100
100
100
100
100
97.7
100
100
100
100
99.7
-------
TABLE 5-11. OPERATION DATA AND COSTS (ANAN PLANT, 1977)
1. Generated Power
2. Power Factor
3. Delivered Raw Material
CaC03
NaOH
H2SO,
Stean
Oil
Proceaa water
Electricity
Gyp Bum production
(dellv. baae)
pf 4. Total Expenses*
5. Operation Coat
MWhr
X
T
T
T
T
to.
T
MWhr
T
10* yen
Yen/kMhr
Apr.
239.452
73.9
5,506
275
2,656
13,791
1,813
44,055
4,589
9,656
380,320
1.59
May
103,139
56.2
2,290
210
1,255
7,691
841
27,133
2,623
4,481
188.800
1.83
June
20,225
41.6
43
288
19
1,481
82
12,811
876.3
0
16,340
1.81
July
243
5
2
13
1
42
42
8
,334
72.7
,302
534
,365
,270
,686
,723
,667
,657
373,710
1.54
Aug.
225,493
67.3
5,423
163
2,581
15,45
-------
The plant has been operated since November 1977. The
electrolytic cell has had a corrosion problem due to chlorine
and other impurities. Studies are under way to prevent the cor-
rosion. About 20-407o of the energy required for FGD is used
by the cell.
An additional FGD unit to treat the remaining half of
the gas from the boiler will be installed by 1980. Use of the
cell substantially reduces the requirement for make-up NaOH and
eliminates the consumption of sulfuric acid; however, it in-
creases power consumption and makes the process even more com-
plex.
5.3.6 Evaluation
Compared with the sodium-lime double alkali processes
developed in the U.S., the limestone sodium-limestone gypsum
processes have the following advantages and disadvantages:
Advantages:
1) Limestone is used.
2) Sodium consumption is less because gypsum con-
tains much less liquor than does sulfite sludge.
3) The properties of gypsum are much better than
the sludge.
Disadvantages:
1) The process is complex and the plant is costly.
2) Sulfuric acid is required.
Although the Kureha Kawasaki process consumes less sul-
furic acid, the process is more complex than the Showa Denko
210
-------
process. The use of the electrolytic cell may eliminate the
need for sulfuric acid but may add to the complexity.
Since lime/limestone gypsum processes have been im-
proved and can attain a high operability, the sodium-limestone
gypsum process may not be attractive, unless substantial im-
provements are made to render it simpler and less costly.
5.4 DOWA ALUMINUM SULFATE LIMESTONE PROCESS
5.4.1 Outline
Dowa Mining Co. has developed a process which uses a
basic aluminum sulfate solution at a pH of 3.5 as the absorbent
and limestone as the precipitant. They have constructed 7 plants
as shown in Table 5-1. In addition, a pilot plant with a capa-
city of treating 30,000 Nm3/hr of flue gas from a coal-fired
boiler will be constructed at the Tennessee Valley Authority,
U.S., and a commercial plant with a capacity of treating 52,000
Nm3/hr of flue gas from a pelletizing plant will be erected in
Mainland China by 1980. Details of the process are available
in published literature.
5.4.2 Okayama Plant (Tamanb Plant). Naikai Engyo
A flowsheet of the plant is shown in Figure 5-9. The
plant has a capacity of treating 72,000 Nm3/hr of flue gas from
an oil-fired industrial boiler which has no electrostatic pre-
cipitator. Operation parameters are shown in Table 5-2.
Flue gas at 170°C containing, 1,500 ppm of S02 and
about 200 mg/Nm3 of dust is first introduced in a cooler, in
which it is cooled to 57°C with a spray of dilute aluminum
211
-------
FLUE GAS £
PRESCRUBIER
MAKE-UP
ALUMINUM
IULFATE
DUST FILTER
(OPTIONAL)
REACTOR
>4X
CENTRIFUGE
GYPSUM
Figure 5-9. Flow sheet of Dowa process.
-------
sulfate liquor. The gas is then sent to a packed absorber.
The scrubber liquor contains a small amount of soluble inor-
ganic catalyst to increase the S02 removal efficiency. Over
90% of the S02 is absorbed in the cooler and the absorber. A
wire-mesh type demist er is placed in an upper part of the ab-
sorber and is washed with 2.5 tons/hr of water. The aluminum
sulfate-sulfite liquor discharged from the absorber is sent to
an oxidizer, where the sulfite is oxidized to sulfate by air
bubbles. The oxidized liquor is treated with limestone to pre-
cipitate gypsum, which is then centrifuged and washed with 1 ton/
hr of water.
/
Chemical reactions for the process are listed below:
Absorption: A12 (SOJ 3-Al203 + 3S02 = A12 (SOO 3 -A12 (S03) 3 (5-4)
Oxidation: A12 (SOOa -A12 (S03) 3 + 3/202 = 2Al2(SOOa (5-5)
Precipitation: 2Al2(SO,t)3 + 3CaC03 + 6H20 (5-6)
= A12(SOO3'A1203 + 3(CaSO,,-2H20) + 3C02
About 0.44 ton/hr of limestone, ground so that 80%
passes through a 200 mesh screen, is consumed to by-produce 0.8
ton/hr of gypsum containing 8-10% of moisture and 0.1-0.2%
A1203. The plant went into operation in March 1976 and has been
operated smoothly. No wastewater was purged during the first
year of operation, resulting in an increase in the impurity con-
centrations in the scrubber liquor: Cl reached 2,000 ppm and Mg
20,000 ppm. Since then, about 8 tons/day of wastewater have
been purged to prevent further accumulation of impurities. To
purge the water, a portion of the liquor discharged from the
gypsum centrifuge is neutralized to PH 6 with limestone and a
small amount of lime. This precipitates Al and the catalyst,
213
-------
which are then returned to the scrubber system. The residual
water, containing Cl and Mg, is then purged.
The operation hours in a recent year are shown in
Table 5-12. The boiler was operated for over 8,000 hours and
the FGD operability reached 99.6%, indicating smooth operation
of the plant. Pressure drop of gas through the scrubber in-
creased appreciably during the operation for a year due to soft
deposits of solids on the packing. Therefore, the packing
(plastic ball type) was removed from the scrubber and washed
with water during the annual shutdown of the boiler for main-
tenance.
5.4.3 Economics
The plant cost 400 million yen in 1976. Operation
cost figures are shown in Table 5-13. The plant consumes alumi-
num sulfate and a catalyst but the amount and cost are small.
The annualized cost of desulfurization including 7 years depre-
ciation without gas reheating is ¥3,850/kl oil ($13.73 at $1
= ¥280) which is equivalent to ¥0.96/kWhr. The cost should
be lower for a larger plant due to scale merits.
5.4.4 Evaluation
The process is simple and operation is easy. Aluminum
sulfate has been used widely for wastewater treatment, is read-
ily available, and does not affect the environment. Due to the
low pH of the scrubber liquor, the L/G ratio is fairly high but
the liquor readily reacts with limestone. The plant cost as
well as operation cost is low. The pilot plant test at TVA
will give information on the applicability for coal-fired
boilers.
214
-------
TABLE 5-12. OPERATION HOURS OF NAIKAI PLANT (DOWA PROCESS)
CO
Aug. 1976
Sept.
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
TOTAL
Total
(A)
744
720
744
720
744
744
672
744
720
744
720
744
8,760
Hours
Boiler oper-
ation (B)
744
608
744
720
680
623
584
515
720
743
577
744
8,002
FGD oper-
ation (C)
741
602
721
720
680
623
584
515
720
743
577
744
7,970
Availability (Z)
Boiler FGD
•(B/A) (C/A)
100
84.4
100
100
91.4
83.7
86.9
69.2
100
99.9
80.1
100
91.3
99.6
83.5
96.9
100
91.4
83.7
86.9
69.2
100
99.9
80.1
100
91.0
Opera-
bility
99.6
99.0
96.9
100
100
100
100 \
100 /
100
100
100
100
99.6
Remarks
FGD stop due to boiler shutdown
Repair of oxidizer nozzle
Scheduled boiler shutdown
Scheduled boiler shutdown
-------
TABLE 5-13. COST FIGURES (OKAYAMA PLANT, NAIKAI)
Note: $1 = ¥280
Gas volume 72,
Removal of S02 92Z
Plant area 20
Plant cost $1,
Item
1 Depreciation
Kate of
interest
Fixed prop-
erty tax
TOTAL
2 Labor cost
Repair cost
TOTAL
3 Electric
power rates
Process
water cost
Aluninun
sulfate
Catalyse
cost
CaCO, con-
sumption
TOTAL
It Cost of
production
5 Total
indirect
accounts
6 Cost
7 Income of
by-produce
8 Balance
9 Total oil
consumption/
year for
boiler
000 Nm3/hr Sulfur
Rate of
In oil 31 S02 1,500 ppm
operation 9SZ, 347 days/year
m x '30 m By-product CaSO»-2HiO, 0.8 t/hr
357,143 (Plant, $1,178
Calculation method
Plane cost x 0.9 x
1/7 year
Plant cose x O.SS x
0.06
Plane cost x 0.014
x 0.4 x O.SS
$14,2B6/year x
(4 men)
Plant cose x 0.03
480 kWh/hr
e$0.043/kUh
5.5 e/hr, e$0.21/mj
9 kg/hr. e$0. OS/kg
1 kg/hr, 8$0.43/kg
0.44 e/hr, @$17.86/
ton
1 + 2 + 3
(2 + 3) x 0.12
4 + 5
6 - 7
5.4 kl/hr
.571; Civil, $178,571)
Calculation ($) Amount
$1,357,143 x 0.9 x $174,
1/7
$1,357,143 x 0.55 x 44,
0.06
$1,357,143 x 0.014 4,
x 0.4 x 0.55
$223,
$ 57,
$1,357,143 x 0.03 40,
$ 97,
480 x 8,328 hr x 0.043 $171,
5.5 x 8,328 x 0.21 9,
9 x 8.328 x 0.05 3,
1 x 8,328 x 0.43 3,
0.44 x 8,328 x 17.86 65,
$253,
223,455 + 97,858 $575,
+ 253,879
(97,858 + 253,879) $ 42,
x 0.12
575,192 + 42,257 $617.
$617,
5.4 x 8,328
44,971 Id/year
($)
490
786
179
455
144
714
858
318
814
748
581
445
879
192
257
449
0
449
10 All total
cost/kl oil
617,^49/44,971
$13.73/kl
216
-------
5.5 KAWASAKI MAGNESIUM GYPSUM PROCESS
5.5.1 Characteristics
The process is characterized by the use of a lime/
limestone slurry to which a fairly high concentration of Mg
(about 5% as MgSOO is added in order to prevent scaling and to
increase S02 removal efficiency. Kawasaki Heavy Industries ex-
perienced a scaling problem with a lime process plant completed
in 1973, discovered the effects of the magnesium, and subse-
quently constructed two commercial plants with the magnesium
gypsum process (Table 5-1)rf.
A lime slurry containing Mg has also been used for
scale prevention in the U.S. in throw-away sludge processes.
The Kawasaki process uses a much higher concentration of mag-
nesium so that the major absorbent is magnesium hydroxide and
sulfite. It also by-produces gypsum salable for wallboard and
cement. The process may be classified as one of the double-
alkali processes.
5.5.2 Process Description
A flowsheet of the Saidaiji plant, Japan Exlan Co.,
is shown in Figure 5-10. The plant has a capacity of treating
300,000 Nm3/hr of flue gas from an industrial boiler burning
2.8%-sulfur oil. The boiler is often operated at about 50%
load. Two scrubbers were installed in parallel. Only one of
them is operated when the boiler is at half load. The boiler
has no electrostatic precipitator; therefore, two-stage multi-
venturi type scrubbers are used to remove particulates at high
efficiency.
217
-------
00
FLUE GAS ?
WATER
Ci(OH»j
MrfOH), REGENERATION
REACTOR
TO STACK
AFTERBURNER ^
I
i r"
ALKALI
SLURRY TANK
Figure 5-10. Flow sheet of Japan Exlan plant.
-------
The plant has a regeneration reactor in which mother
liquor from a gypsum centrifuge, containing MgSO,,, is reacted
with Ca(OH)2 to precipitate Mg(OH)2 and gypsum.
MgSO,, + Ca(OH)2 + 2H20 = Mg(OH)2 + CaS(V2H20 (5-7)
The slurry containing Mg(OH)2 and gypsum is then fed
to the absorber, where the Mg(OH)2 reacts as the absorbent and
the gypsum works as crystal seed to prevent scaling.
Mg(OH)2 + S02 = MgS03 + H20 (5-8)
MgS03 + H26 + S02 = Mg(HS03)2 (5-9)
Slurry discharged from the scrubber is sent to an
oxidizer, where magnesium sulfite and bisulfite are oxidized
by air to form magnesium sulfate. The slurry is sent through
a thickener to a centrifuge. The solids are washed with water
in the centrifuge, to reduce the magnesium content to 0.1-0.270
and to produce gypsum which is useful for wallboard and cement.
The mother liquor and wash water are returned to the reactor.
The process has no cooler and a large amount of water
is evaporated in the scrubber. The plant is operated without
any wastewater production. If the process is applied to a coal-
fired system, however, a prescrubber may be needed to remove
chlorine and fly ash. Major equipment in the plant is listed
in Table 5-14.
The S02 concentration of the flue gas is reduced from
1,400 to 100 ppm by scrubbing with the slurry, which has a pH
of 5-6. Since the boiler has no electrostatic precipitator,
flue gas contains nearly 200 mg/Nm3 of dust. This is reduced
to about 50 mg/Nm3 after scrubbing and reheating. The gypsum
219
-------
TABLE 5-14. MAJOR EQUIPMENT LIST (SAIDAIJI PLANT, JAPAN EXLAN CO.)
Item
Type
Capacity
N>
ls>
o
No. 1 Absorber
No. 2 Absorber
No. 1 Forced draft fan
No. 2 Forced draft fan
No. 1 Absorbent circulation
pump
No. 2 Absorbent circulation
pump
No. 1
Oxidizer
No. 2
Air compressor for oxidizer
Regeneration tank
Alkali slurry tank
Mother liquor tank
Sulfuric acid tank
Gypsum centrifuge
Mist eliminator
Two stage multi-venturi
Two stage multi-venturi
Turbo, with double suction
Turbo, with double suction
Centrifugal
Centrifugal
Cylindrical bubbling tower
2-stage turbo compressor
Cylindrical vertical
Cylindrical vertical
Cylindrycal vertical
Cone roof
Basket type centrifuge
Louver
160,000 Nm3/h
140,000 Nm3/h
160,000 Nm3/h x 350 mmH20
140,000 Nm3/h x 350 mmH20
530 m3/h x 55 m x 3
(2 out of 3 in operation)
530 m3/h x 55 m x 3
(2 out of 3 in operation)
3.3 m3
58 m3
180 m3
12 m3
-------
product is dark colored because of the dust, but is still use-
ful. The particulates reportedly cause no other problems in the
system. The plant consumes 953 kg/hr of Ca(OH)2 and 6 kg/hr
of Mg(OH)2 and by-produces 2,214 kg/hr of gypsum.
The relations between absorbent slurry pH and L/G to
the S02 removal efficiency are shown in Figures 5-11 and 5-12.
Another commercial plant, the Okazaki plant, Unitika
Co., is similar to the Saidaiji plant, except that it uses a
single scrubber train, and it uses limestone in addition to
lime. Lime is added to the? reactor and limestone is added to
the absorber; the ratio of limestone to lime is about 5 to 1.
Operation parameters of the plant are shown in Table 5-2. The
Okazaki plant consumes 920 kg/hr of CaC03, 200 kg/hr of Ca(OH)2,
120 kg/hr of H2SO.», and 10.9 tons/hr of industrial water; it
by-produces 2,280 kg/hr of gypsum containing 1070 water. It
also operated without any wastewater production.
5.5.3 Operation of Commercial Plants
The Saidaiji plant was put into operation in January
1976. Formation of soft scale in a pipe from the reactor
forced a 4-day plant shutdown later in the month to install an
additional pipe for use during cleaning of the original pipe.
The plant was shut down again for 10 days in February 1976 to
remove scale in mist eliminators, which had been washed with a
circulating liquor. Both fresh water and circulating liquor
have been used since to prevent scaling. The wash water has
been discharged to the scrubber. Since a large amount of water
is evaporated in the scrubber, no wastewater is discharged from
the plant. The boiler has been shut down twice a year for main-
tenance. The operability of the FGD plant since start-up has
221
-------
100
5 90
§
»-i
CM
O
CO
80
5.0
5.5
6.0
6.5
Figure 5-11. Absorbent pH and S02 removal.
100
s-s
tfl
o
CO
90-
80
Absorbent pH: 5.5
Gas Load : 100%
4567
L/G ratio (liter/Nm3)
Figure 5-12. Relation between L/G ratio and S02 removal
222
-------
reached over 98%. The plant is operated by one person per
shift.
9
Operation of the Okazaki plant (200,000 Nm3/hr) was
started in January 1976. Problems similar to those at the
Saidaiji plant were encountered at the beginning of operation
but were solved fairly easily. The performance of the plant
in a recent year is shown in Table 5-15. Operability in this
year exceeds 99%. Repair work was made during the scheduled
shutdown of the boiler.
Tests With Flue Gas from Co-al-Fired Boilers--
Kawasaki has conducted pilot plant tests with flue
gas (5,000 Nm3/hr) from a coal-fired utility boiler containing
500-1,000 ppm of S02 and 40 ppm of Cl at 130°C using a single
stage mono-venturi scrubber and Ca(OH)2 -Mg(OH)2 slurry. The
tests also have shown the effects of magnesium to increase S02
removal efficiency and to reduce the tendency for scaling.
There has been no plan yet to construct a commercial plant for
flue gas from a coal-fired boiler using the process.
5.5.4 Evaluation
The process is fairly simple and plant operation seems
easy. Power consumption is low - 1.7% of the power generated -
because of the relatively low L/G ratio and the slight pressure
drop involved. These attractive features are due to the use of
magnesium as the absorbent. No-wastewater operation is another
advantage. Although chlorine accumulates in the scrubber liquor,
adverse effects are reduced by the presence of magnesium.
223
-------
TABLE 5-15. PERFORMANCE OF OKAZAKI PLANT, UNITIKA
Sept. 1976
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
to June
CO
*" July
Aug.
TOTAL
Total
(A)
720
744
720
744
744
672
744
720
744
720
744
744
8,760
Hours
Boiler oper-
ation (B)
720
744
720
744
744
672
744
192
744
720
744
744
8,232
FGD oper-
ation (C)
720
672
720
744
744
672
744
192
744
720
744
744
8,160
Availability (X)
Boiler FGD
(B/A) (C/A)
100
100
100
100
100
100
100
26.7
100
100
100
100
94.0
100
90.3
100
100
100
100
100
26.7
100
100
100
100
93.1
Opera-
bility
(C/B) (X) Remarks
100
90.3 Inspection of absorber. Repair
of agitator sealing.
100
100
100
100
100
100 Scheduled boiler shutdown*
100
100
100
100
99.1
*Spray piping in absorber and mist eliminator was repaired during the period.
-------
Oxidation of the magnesium salts occurs much more
readily than oxidation of calcium sulfite. The plants have used
small amounts of sulfuric acid to lower the slurry pH from 5.5
to 5.0 in order to promote the oxidation. However, the acid
may not be needed when inlet and outlet S02 concentrations are
higher, as in most plants in the U.S., because the slurry pH
can easily be reduced to 5.0 by scrubbing. No make-up magne-
sium hydroxide is needed when an MgO-rich lime is used.
Another advantage of the process is the negligible
formation of dithionate ion S20". This ion can cause COD
problems with wastewater. 'It is known that S20" increases
when SO" ion is oxidized at a low pH. The pH of the slurry
at the oxidation step is about 5, which is higher than the usual
oxidation pH of 3.5-4.0 in lime/limestone processes.
Magnesium tends to prevent the crystal growth of
gypsum. However, Kawasaki Heavy Industries has succeeded in
by-producing gypsum which has a good crystal size, can be cen-
trifuged to about 10% moisture, and is useful for wallboard
and cement.
On the other hand, the process has a few minor dis-
advantages. The process requires lime, which is much more ex-
pensive than limestone. Although the Okazaki plant has used
limestone, lime should give better play to the advantages of
the process. Need for a reactor may not be an appreciable dis-
advantage, because the reactor is simple and is not much more
costly than the lime slurry preparation tank for the lime/lime-
stone process. The scrubber contains over 300 small Venturis
made of plastic and is highly efficient for particulate re-
moval, but this design may not be adequate for a large size
scrubber.
225
-------
5.6 KOBE STEEL CALCIUM CHLORIDE PROCESS
5.6.1 Characteristics
Accumulation of chlorine in the scrubber liquor of
lime/limestone processes tends to reduce S02 removal efficiency
and to increase scaling. Kobe Steel Co. has found that a much
higher chlorine concentration can have beneficial effects on
FGD. They have developed a process using a 30% calcium chloride
solution dissolving lime as the absorbent. The solution has the
following advantages over the conventional lime slurry:
1) Solubility of lime in the solution is 7 times
better than in water (Figure 5-13), reportedly
allowing the use of a much smaller L/G ratio
than with the standard lime process. (3 ver-
sus 10).
2) Since the vapor pressure of the solution is
low (Figure 5-14), the scrubber outlet gas
temperature can be high (70°C versus 55-60°C).
The process therefore, requires less reheating
and less cooling water.
3) The oxidation rate is small and therefore less
gypsum is formed in the cooler and scrubber
(Figure 5-16). This helps scale prevention.
4) Calcium chloride is highly hygroscopic and
neither the solution nor the slurry dries up
in any part of the cooler, scrubber, or
demister. This prevents the formation of hard
scale.
226
-------
0.8
,0
3
iH
O
0.4
0 20 40
CaCl2 (weight %)
oo
x
-------
A flowsheet of the process is shown in Figure 5-17.
Flue gas is first cooled to about 70°C in the cooler. The
cooling liquor is weak calcium chloride solution (about 5%)
from the gypsum centrifuge which is concentrated to 3070 in the
cooler. The cooled gas is then scrubbed in the Sanabs Scrubber,
a kind of spray tower with a parallel gas-liquid flow. The
scrubbing liquor is a 30% calcium chloride solution dissolving
lime which contains about 6% solids (calcium sulfite and gyp-
sum) . Operation parameters are shown in Table 5-2.
The slurry leaving the scrubber is thickened and cen-
trifuged. Most of the liquor is returned to the scrubber. This
separation is needed to promote the oxidation of the sulfite
to gypsum, since the oxidation occurs slowly in a concentrated
calcium chloride solution. The calcium sulfite sludge is re-
pulped with water and a small amount of sulfuric acid. It is
then oxidized by air to form gypsum. The gypsum slurry is cen-
trifuged and the liquor from the centrifuge, a solution of
about 5% CaCl2, is returned to the cooler. The by-product gyp-
sum contains about 10% moisture and 0.5% CaCl2 and is useful
for wallboard and cement production. Normally, no wastewater
is purged.
Five commercial plants are in operation. One is under
construction to treat flue gas from an iron-ore sintering
machine (Table 5-1). The process was recently licensed to Uhde,
West Germany.
5.6.2 Operation of Commercial Plants
Table 5-16 shows the operation hours in a recent year
of the Amagasaki plant, Kobe Steel, which has a capacity of
treating 175,000 Nm3/hr of flue gas from an iron-ore sintering
228
-------
OEMISTER
VO
r
SCRUBBER
AA
AA
rFMTRIFIIRF I
CENTRIFUGE
PRESCRUBBER
I
I
FLUE GAS
i
CENTRIFUGE
DUST
J_L
I r—I c.(OH)2
11 i r*—
Ci(OHI2
r
I^H MIXING
II TANK
T
THICKENER
WATER
M2S04
T
> STACK
AFTERBURNER
OXIDIZER
AIR
CENTRIFUGE
CilOHIj
35
GYPSUM
Figure 5-17. Flow sheet of Kobe steel process.
-------
TABLE 5-16. OPERATION OF AMAGASAKI PLANT, KOBE STEEL (SM = SINTERING MACHINE)
Apr. 1976
May
June
July
Aug.
Sept.
Oct.
Nov.
NJ
g Dec.
Jan. 1977
Feb.
Mar.
Total
(A)
720
744
720
744
744
720
744
720
744
744
672
744
Hours
SM oper-
ation (B)
686
698
648
650
698
672
709
615
708
599
657
0
FGD oper-
ation (C)
622
667
624
637
696
653
709
615
708
599
"657
0
Availability (%) Opera-
SM FGD bility
(B/A) (C/A) (C/B)(%)
95.3 86.4 90.7
93.9 89.7 95.5
90.0 86.7 96.3
87.4 85.6 98.0
93.8 93.6 99.8
93.4 90.8 97.2
95.3 95.3 100
85.5 85.5 100
95.2 95.2 100
80.6 80.6 100
97.7 97.7 100
00 0
Remarks
Start-up problems
Scrubber scaling
Shutdown for 4 days*
Shutdown of SM
Modification of plantt
*To change piping to use slurry instead of clear liquid as absorbent.
tRepair of stack, cooler lining, and mist eliminator.
-------
machine. The plant, the first commercial plant by the pro-
cess, went into operation in January 1976, and had minor start-
up problems. The operability was 90-96% in April through June
and gradually approached 100% as the problems were solved.
At the beginning, the absorbent used in the system was a clear
liquor, a 30% CaCl2 solution with dissolved lime. A tendency
for scale formation was observed. In November 1976, the plant
was shut down for four days to modify the system in order to
use a slurry containing about 6% solids as the absorbent so
that gypsum crystals could be circulated as seeds. The scaling
problem was thus solved. Operation parameters of the plant are
similar to those of the Nakayama Steel plant shown in Table 5-2.
In March 1977 the plant was shut down for 3 months to
repair a stack, the cooler lining, and a mist eliminator. Oper-
ation resumed in June 1977 and has since been carried out at
nearly 9970 operability.
Table 5-17 shows the operation hours in the first year
after start-up of the Funamachi plant, Nakayama Steel, which has
a capacity of treating 375,000 Nm3/hr of flue gas from an iron-
ore sintering machine. From the beginning, the absorbent used
in the plant has been a calcium chloride liquor containing dis-
solved lime and solids. The scrubbers have had no scaling prob-
lem. A Euroform demister is used which has higher efficiency
but is more vulnerable to scaling than the conventional Chevron
type demister. The demister had minor plugging problems and
required occasional cleaning. The demister system was modified
in December 1976 and the problem has been nearly solved. The
average operability in the first year after start-up was 97.4%.
The operability after January 1977 exceeded 98%.
231
-------
TABLE 5-17. OPERATION HOURS OF FUNAMACHI PLANT, NAKAYAMA STEEL
(SM = SINTERING MACHINE)
ts>
June 1976
July
Aug.
Sept.
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
TOTAL
Total
(A)
720
744
744
720
744
720
744
744
672
744
720
744
8,760
Hours
SM oper-
ation (B)
696
720
720
696
720
696
720
720
643
720
588
732
8,371
FGD oper-
ation (C)
651
716
714
696
720
692
576
720
635
720
588
732
8,160
Availability (%)
SM FGD
(B/A) (C/A)
96.
96.
96.
96.
96.
96.
96.
96.
95.
96.
81.
98.
95.
7
8
8
7
8
7
8
8
7
8
7
4
6
90
96
96
96
96
96
77
96
94
96
81
98
93
.4
.2
.0
.7
.8
.1
.4
.8
.5
.8
.7
.4
.1
Opera-
bility
(C/B) (%)
93.
99.
99.
100
100
99.
80.
100
98.
100
100
100
97.
5
4
2
4
0
8
4
Remarks
Start-up troubles
Mist eliminator
plugging
Repair of rubber lining
Mist eliminator
Modification of
eliminator
plugging
mist
Unusual vibration
Maintenance of
SM
-------
5.6.3 Evaluation
The process has advantages over usual lime scrubbing
processes in that it has a smaller tendency to form hard scale,
reportedly uses a lower L/G ratio, gives a higher outlet gas
temperature, and produces no wastewater. On the other hand, an
additional centrifuge and highly corrosion-resistant materials
are needed. Titanium was used at the hot zone in the cooler of
the first commercial plant. Plants constructed later use pumice
stone instead of the expensive titanium.
/
The plants have a cooler separate from the scrubber in
order to remove dust and to obtain good quality gypsum. For
the purpose of producing throw-away gypsum, the cooler and the
scrubber can be put together, eliminating the dust removal step.
The Kobe Steel process is of particular interest for
treating chlorine-rich flue gases, such as flue gas from burning
coal. If this flue gas were to be treated by a standard lime
scrubbing process by-producing gypsum with about 1070 moisture
and without a wastewater purge, chlorine would accumulate in
the scrubber liquor to about 20-35% CaCl2. This is the level
at which the amount of chlorine entering the system with the
flue gas would equal that leaving the system with the gypsum.
In other words, any lime-gypsum process treating flue gas from
coal and purging no wastewater will naturally be operated in
the range of the Kobe process. No makeup calcium chloride will
be needed when the Kobe Steel process is used.
The process is similar to the Hoelter process of West
Germany. Kobe Steel is ahead of Hoelter in patent application
and commercial application, while Hoelter seems to use an addi-
tive which is said to improve the process.
233
-------
5.7 OTHER INDIRECT LIME-GYPSUM PROCESSES
5.7.1 Kurabo Acidic Ammonium Sulfate Process
Kurabo Engineering Co. has developed a process which
uses an acidic ammonium sulfate liquor at a pH of 3.5-4.0 as
the absorbent and lime as the precipitant. Plume formation, a
major problem with ammonia scrubbing processes, is eliminated
by using the acidic liquor, because the NHa vapor pressure of
the liquor is less than 1 ppm equivalent.
A flowsheet of the process is shown in Figure 5-18.
After S02 absorption, the scrubbing liquor is oxidized by air
bubbles to convert ammonium sulfite into sulfate. Most of the
liquor leaving the oxidizer is returned to the absorber; a por-
tion, however, is sent to three reactors in series and treated
with lime to precipitate gypsum. The gypsum is then centrifuged
The liquor and wash water discharged from the centrifuge are
sent to an aqueous ammonia tank. The aqueous ammonia is then
sent back to the oxidizer.
Kurabo constructed 5 commercial plants, as shown in
Table 5-1. The operation parameters of one of the plants are
shown in Table 5-2. The operability of the plant in a recent
year reached 99.37». The plant normally purges no wastewater.
However, to prevent the accumulation of chlorine and magnesium
in the scrubber liquor, it may be necessary to purge some waste-
water occasionally after removing ammonia. Such a purge has
been required in commercial operation.
The pH of the scrubber liquor is much lower and con-
sequently the L/G ratio much larger than in the conventional
ammonia-lime process, but the Kurabo process has no plume
234
-------
TO STACK
to
U>
Ul
GYPSUM
Figure 5-18. Flow sheet of Kurabo ammonium sulfate-gypsum process
-------
problem; plume is virtually invisible. In comparison with the
Dowa and Chiyoda (101) processes, the pH is higher and the L/G
is smaller, but limestone cannot be used.
5.7.2 Nippon Kokan Ammonia Lime Process
Nippon Kokan, at the Keihin Works, has continued tests
with a pilot plant of an ammonia-lime gypsum process with a
capacity of treating 150,000 Nm3/hr of flue gas from an iron-ore
sintering machine. The process is characterized by the use of a
screen type absorber and by treating an ammonium sulfite-sulfate
liquor with lime to recover gaseous ammonia followed by the oxi-
dation of calcium sulfite to obtain gypsum. Details of the pro-
cess are available in published literature.10 Recent operation
parameters are shown in Table 5-2. A flow sheet of the process
is given in Figure 5-19.
In a recent year, the sintering machine was operated
for 8,202 hours (availability 93.6%) and the FGD plant for 8,098
hours (operability 98.770). In each month, the sintering machine
was operated 28 to 30 days and was shut down for 1 to 3 days for
maintenance. Although the FGD plant also required some servic-
ing, such as cleaning the lime slurry tank, repairing the
absorber and oxidizer lining, etc., most of the work could be
done during the shutdown of the sintering machine. The high
availability and operability indicate good performance of the
plant.
The plant is only used for testing purposes. The
treated gas is emitted from a stack without reheating, resulting
in an appreciable plume.
236
-------
bo
WMTIIAI
f
I
i
pH»oju»Tino onoizin HIUTIIALUCR 1
10, maVIIIV HCTUUi
, MCOVIDY HCTIOI
• M, RIIEIIIUTIOI KCTIOII
I I
I I
I GmimmooucTio«licrio« | HATIBMCOV
I I
I I
Figure 5-19. Flow sheet of Nippon Kokan ammonia-lime process.
-------
5.7.3 Kureha Sodium Acetate Process
Kureha Chemical has continued tests of the sodium
acetate-limestone process with a pilot plant (5,000 Nm3/hr).
The process has been improved by the substitution of lime for
limestone. A flowsheet of the improved process is shown in
Figure 5-20. S02 is absorbed in a sodium acetate liquor at a
pH of 6.8-7.0. The liquor discharged from the scrubber is sent
to a reactor in which it is oxidized by air and reacted with
lime to precipitate gypsum. The presence of acetic acid pro-
motes the reactions of sodium sulfate with lime to precipitate
gypsum and regenerate sodium acetate, as shown below:
2CH3COONa + S02 + H20 = Na2S03 + 2CH3COOH (5-10)
Na2S03 + %02 = NazSO,, (5-11)
Ca(OH)2 + 2CH3COOH = (CH3COO)2Ca + 2H20 (5-12)
(CH3COO)2Ca + NazSO,, -I- 2H20 = 2CH3COONa + CaSO,»-2H20 (5-13)
By the substitution of lime for limestone, with the
resulting higher pH of the scrubber liquor, the size of the
scrubber and the reactor as well as the evaporation of acetic
acid in the scrubber has been substantially reduced. No acetic
acid recovery section is needed because the acid is sufficiently
recovered in a mist eliminator. Air blown into the reaction
tank eliminates the need for a separate oxidation tower. The
overall FGD cost was considerably lowered even though lime is
used.
Kureha claims that the total investment including
land cost, etc. for a plant with a capacity of treating 8-10,000
Nm3/hr of flue gas from a coal-fired boiler (250 MW equivalent,
sulfur content of coal about 1.2%) will be about 3 billion yen.
238
-------
WATIR
1
DEMISTER
AAAA
SCRUBBER
GAS?
CO
vo
i> CLEANED GAS
.CaO
-2_CH3COOH
CENTRIFUGE
AIR "i
NiOH
il
GYPSUM
Figure 5-20. Simplified flow sheet of Kureha sodium acetate lime process
-------
The estimated requirements and products of the operation are
as follows: (in tons/hr)
Ca(OH)2 2.34 NaOH 0.051 CH3COOH 0.117
Steam 1.8 Water 66 Wastewater 9
Gypsum 5.07 (dry
basis)
About 99% of S02 can be removed without difficulty.
Wastewater should be treated to remove acetic acid, which can
be readily decomposed by a biological method used widely for
wastewater treatment ("activated sludge").
Kureha conducted pilot plant tests with a coal-fired
boiler flue gas (300 Nm3/hr) before and after particulate re-
moval by an electrostatic precipitator. No appreciable differ-
ence in process chemistry was observed in tests with a flue gas
from an oil-fired boiler, except that a larger amount of chlo-
rine accumulated in the scrubber liquor and that fly ash in-
creased erosion. About 2% chlorine in the liquor was tolerable
for the process.
The process can be used for simultaneous removal of
S02 and NO by adding catalysts to the scrubbing liquor.
s\
240
-------
SECTION 6
REGENERABLE PROCESSES
6.1 GENERAL DESCRIPTION
6.1.1 Ammonia Scrubbing
1
Nippon Kokan has developed a process to by-produce
ammonium sulfate from S02 in flue gas and ammonia in coke oven
gas. Two commercial plants based on the process (Table 6-1)
have been constructed. To diminish plume from the scrubber,
which is a common problem with ammonia scrubbing processes,
Nippon Kokan uses an after-burner to raise the temperature of
the treated gas at its Fukuyama plant and a wet electrostatic
precipitator for its Ogishima plant.
A small commercial plant to by-produce ammonium
sulfate was completed by Kurabo Engineering for a fertilizer
producer (Table 6-1). The plant has been operated smoothly
but the oversupply of ammonium sulfate has made the process
less attractive.
Two relatively small plants, with ammonia scrubbing,
thermal decomposition of ammonium sulfate, and an IFP reactor
to by-produce elemental sulfur, were constructed by Mitsubishi
Heavy Industries and Toyo Engineering. Both had problems
mainly with the decomposition step and were given up.
241
-------
TABLE 6-1. FGD INSTALLATIONS BY-PRODUCING H2SO.», S AND
NJ
Process
Developer
VelUan-MOC
II
n
it
n
it
n
ii
n
n
M
n
VallBan-SCEC
f*
H
N
n
H
Onahaoa-TauklahiBa
Mltiui-Choilco
Klteul Mining
M
n
Hachlnohe Soieltlag
Shell
Sualtoao B.I.
Hitachi Ltd.
n
Nippon Kokan
H
Kurebo Engineering
ni-irp
TEC-IPP
Ube Industrie*
Absorbent
KaaSOt
tl
I
n
M
H
tl
tl
1
II
n
n
ti
tl
M
t
fl
tt
MgO
1 1
"
ZnO
it
i
CuO
Carbon
i
"
(NHOlSO,
II
(NHOlSO^
(NHOtSO,
It
Uaer
Japan S.R.
Chubu Electric
Kashlna Oil
Japan S.R.
Toyo Rayon
J.N. Railway*
Mlteublahl Chen.
Kuraray
Shlndaikyowa Oil
Hlteublshl Chen.
i
Tohoku Electric
Toa Ncnryo
Sumltono Chen.
Toa Nenryo
Fuji Plln
Sumltono Chen.
Ll
Onahaoa Smelting
Idenltau Kosan
Mitsui Mining
i
ti
Bachinohe Smelting
Show. Y.S.
Kansal Electric
Tokyo Electric
Unltlka
Nippon Kokan
t
Takl Chemical
Maruzen Oil
Fuji Oil
Ube Induatrlea
Plant Site
Chlba
Nlahlnagoya
Kaehlma
Yokkalchl
Nagoya
Kawaaakl
Hliuahlma
Okayama
Yokkalchl
Miiushima
Kuboaakl
Nllgata
Kawasaki
Sodegaura
HakayaM
Fu j Inonlya
Nllhama
Sodegaura
Onahana
Chlba
Hibl
Konloka
Rliioahlma
Hachlnohe
Yokkalchl
Sakal
Kashlna
OJ1
Fukuyama
Oglahlna
Befu
Shlnoiu
Chlba
Ube
Capacity
(1.000
Jta'/hr)
200
620
30
450
330
700
600
410
400
628
530
380
67
360
17
150
155
540
84
500
80
48
25
60
120
160
420
170
760
1,140
15
42
6
110 x 2
Source of Gas
Industrial boiler
Utility boiler
Claua furnace
Industrial boiler
i
"
i
i
i
t
Utility boiler
Claua furnace
Indua trial boiler
Claua furnace
Industrial boiler
ii
i
Copper amelter
Claua and boiler
H]SOn plant
i
Sintering machine
Industrial boiler
Utility boiler
n
Industrial boiler
Sintering plant
ii
Industrial boiler
Claua furnace
i
Industrial boiler
Inlet
80] (ppra)
2,000
1,600
11.000
1,000
1,500
1,500
1,500
1,500
1,500
1,500
1,500
1,000
6,500
1,550
19,000
1,300
1,600
1,600
20,000
1,200
1.200
2,400
1,500
1,500
400
400
1,500
1,000
Year of
Completion
1971
1973
1973
1973
1974
1975
1975
1975
1975
1976
1976
1977
1971
1973
1974
1974
1975
1975
1972
1975
1971
1972
1972
1973
1973
1971
1972
1975
1976
1977
1976
1974
1974
1974
By-Product
HiSO»
i
S
Hi SO*
1
tt
'.'I
II
It
n
S
Hz SO*
S
SOi
H2SO*
i
S
HiSOt
n
ii
s
HiSO*
HlSOt**
HjSO»
(NHOlSO,
n
tt
s
H
SO»
• 1.000 ItaVhr - 590
•* Reacted with llaw*
scfsj - 320 MU
to produce gyps
-------
Ube industries recently constructed two units to
by-produce ammonium sulfate to be used for caprolactam pro-
duction.
6.1.2 Wellman-Lord Process
Many Wellman-Lord process plants have been
constructed by Mitsubishi Kakoki Kaisha (MKK) and Sumitomo
Chemical Engineering Co. (SCEC) (Table 6-1). As is well known,
the process uses sodium sulfite as the absorbent to obtain so-
dium bisulfite, which is heated to regenerate sodium sulfite
and S02 in a concentrated form. Plant operation has been car-
ried out smoothly.
The major problem with the process has been the for-
mation of undesirable compounds: sodium sulfate, which re-
sults in the consumption of sodium, and polythionates, such as
dithionate Na2S^06/ which cause an increase in chemical oxygen
demand (COD) of wastewater. The sulfate is formed by oxidation
and the polythionates are produced mainly during the regenera-
tion step. MKK has succeeded in decomposing the polythionates
by ozone oxidation at a pH below 1.5, but the treatment in-
creased capital and operating costs. SCEC has used an oxidation
inhibitor to reduce the formation of the sulfate, but the inhib-
itor may make the decomposition of the polythionates more dif-
ficult.
Most of the Wellman-Lord process plants by-produce
sulfuric acid, while three plants of oil companies by-produce
elemental sulfur by feeding the recovered S02 into a Glaus
furnace.
243
-------
6.1.3 Magnesium and Zinc Scrubbing
Three magnesium scrubbing plants have been
constructed. These are the Onahama plant, Onahama Smelting
Co., the Hibi plant, Mitsui Mining & Smelting, and the Chiba
plant, Idemitsu Kosan (Table 6-1). By the magnesium scrubbing
processes, SOa is absorbed in a magnesium hydroxide-sulfite
slurry to by-produce magnesium sulfite, which is then filtered,
dried, and calcined to regenerate the magnesium hydroxide and
to recover SOa at about 770 concentration. The S02 is used for
sulfuric acid production (Onahama plant and Hibi plant) or is
charged to a Glaus furnace to by-product elemental sulfur
(Chiba plant).
The Onahama plant and the Hibi plant were shut down
a few years ago and have since remained inoperative because of
the overproduction of sulfuric acid and the large energy con-
sumption for the drying and calcination. Both plants have been
replaced by lime scrubbing plants to by-produce gypsum. Only
the Chiba plant is in operation at present.
Zinc scrubbing has been used in three zinc smelters.
At Kamioka and Hikoshima of Mitsui Mining and Smelting Co., it
is used to treat the tail gas of sulfuric acid plants producing
48,000 and 25,000 Nm3/hr, respectively. At Hachinohe Smelter, it
is used to treat 60,000 Nm3/hr of weak and fugitive gases from a
sintering plant. All of the zinc scrubbing plants were contruc-
ted by MESCO, the Engineering Division of Mitsui Mining and
Smelting Co.
ZnO-rich dust caught by cyclones and electrostatic
precipitators at the smelters is used for the scrubbing. The
by-product, zinc sulfite with a small amount of zinc sulfate,
244
-------
can be treated in different ways. Until a few years ago, the
sulfite was filtered, dried, and calcined to regenerate ZnO
and to release concentrated S02 which was sent to the sulfuric
acid plant. The process, however, requires a considerable
amount of energy for the drying and calcination. In recent op-
eration, zinc sulfite slurry is treated with sulfuric acid to
produce concentrated S02 gas, which is sent to the acid plant,
and to recover zinc sulfate liquor, which is used to prepare
a feed slurry to the roaster or to produce refined zinc sulfate.
The zinc scrubbing is useful for zinc smelters but
may not be for other plant's because of the difficulty in ob-
taining zinc oxide and because of environmental considerations.
6.1.4 Sodium Sulfite By-Production
There are over 800 sodium scrubbing plants with an
average capacity of treating 40,000 Nm3/hr of flue gas. The
processes by-produce mainly sodium sulfite and some sulfate.
The process is simple, the plant is easy to operate,
and the plant cost is low, but demand for the sulfite is lim-
ited. In a number of plants the sulfite in solution is air-
oxidized into sulfate which is used for glass production, etc.
or is purged. Use of such sodium sulfite scrubbing plants will
not increase much because of the oversupply of the by-products
and the increase in the cost of sodium hydroxide, which is re-
quired for the process.
6.1.5 Shell Process
The SYS plant, which uses the Shell copper oxide
process, has continued operation (Table 6-1). Tests for
245
-------
simultaneous removal of NOV by ammonia injection have been
X
carried out (see Section 7).
6.1.6 Activated Carbon Process
Tokyo Electric Power has been operating an activated
carbon process plant at Kashima (420,000 Nm3/hr) to produce a
weak sulfuric acid which is treated with limestone to produce
good-quality gypsum.
Unitika Co. has constructed a carbon process plant
to by-produce a stronger sulfuric acid.
The dry carbon process plant of Kansai Electric at
Sakai, using a moving bed designed by Sumitomo Heavy Industry
(former Sumitomo Shipbuilding), has been given up after 5 years
of operation.
6.1.7 Operation Parameters of Major Plants
Table 6-2 shows operation parameters of major
regenerable process plants. Most of the plants have over 9270
operability. An exception is the SYS plant using the Shell
process, which has been occasionally modified for improvement.
Investment costs for the sulfuric acid and sulfur
by-producing plants excluding the Glaus furnace range from
$80-130/kW in battery limits at current prices.
Although most of the regenerable process plants as
well as plants by other processes have achieved a high opera-
bility, not many new FGD plants will be constructed due to the
oversupply of by-products.
246
-------
TABLE 6-2. OPERATION DATA OF REGENERABLE PROCESS PLANTS
to
Process Developer
Absorbent
By-product
Plant owner
Plant site
Fuel
FGD capacity (1.000 Nm'/hr)
FGD capacity (HO
Inlet SOj (ppm)
Inlet dust (mg/Nm1)
Inlet gas temperature (*C)
Number of scrubbers in parallel
Pr esc rubber type
L/G (liters/Urn')
Scrubber type
Liquor pH
L/C (liters/Ha1)
Gas velocity (m/sec)
Outlet SOZ (ppm)
Outlet dust (mg/Nm1)
SO] removal efficiency (Z)
Mist eliminator type
_ Prescrubber
Pressure „ . ,
. Scrubber
?-.ii n\ met eliminator
IBonzu; Total system
Wastewater purged (t/hr)
Energy requirements (Design)
Pump (kW)
Fan (kW)
Total FGD system (kW)
Percent of power generated
Operablllty (Z)
t Iron ore sintering plant
A From oil burner and Glaus furnace
* Dry process
f Two reactors are used alternately
+ Parallel passage reactor
V Excluding Glaus furnace
t For pump and fan
tt Excluding steam requirements
Nippon
Kokan
NHj
(NH,,),SO»
Nippon
Kokan
Oglshlroa
Cokef
1,120
(380)
350
50
120
2
Spray
1.0
Screen
6.0
1.0
1.6
10-20
10
94-97
Wet EP
250
10
100
for SO 2 absorption
Wcllman-
MKK
NaOH
S02 -*• HjSOi,
Chubu
Electric
Niahlnagoya
Oil
620
220
1,600
140
1
Sieve tray
0.6
1.8
120
35
92
400
50
550
4
840
2,350
1.3»
99.5
and regeneration
Wellman-
SCEC
NaOH
SOj > H2SOi,
Sumitomo
Chemical
Sodegaura
Oil
370
130
1,500
100
160
Below 150
Below 50
Over 90
Some
Over 95
Ml t Bill -
Chemico
MgO
S02 -* S
Idem It flu
Kosan
Chlba
Oil
460*
(160)
2,850
185
1
Venturl
Veflturi
120
95
Chemico
5007
0.1
1,960
3.400
3.4»
98
Kureha
NnOH
NnjSO)
HUflui
Toatsu
Nngoyn
Oil
190
65
1,400
200-300
170
Packed
6.5
1.2
Below 2.0
6
165
40
250
Some
560
0.9
100
Shell*
CuO
S02 + S
Showa
Y.S.
Yokkalcht
Oil
116
38
1,250
Below 50
1*
PP
125
Below 50
90
200
400-500V
Some
140
2.r
TEPCO- *
Hitachi
Carbon
IfeSO* * CnSO
Tokyo
Electric
Kashlmn
Oil
420
150
150
130
Packed
30
80
630
870
13
280
2,700
3,245
2.2
92
-------
6.2 NKK AMMONIA SCRUBBING PLANTS
6.2.1 Outline
Nippon Kokan Kabushiki Kaisha (NKK) recently
completed two large FGD plants to treat flue gas from iron-ore
sintering plants. By using ammonia in coke oven gas ammonium
sulfate is produced as a by-product. One of these plants, the
Ogishima plant, has a capacity of treating 1,120,000 Nm3/hr of
flue gas (370 MW equivalent) and the other, the Fukuyama plant,
has a capacity of 760,000 Nm3/hr (250 MW equivalent). The for-
mer has wet electrostatic precipitators (ESPs) after the scrub-
ber which almost entirely eliminate the plume, while the latter
has an after-burner to reheat the gas to 120°C and produces
appreciable plume.
6.2.2 Ogishima Plant
Flowsheets of the flue gas treating system of the
Ogishima plant are shown in Figures 6-1 and 6-2. The flue gas,
1,120,000 Nm3/hr at 150°C, containing about 300 ppm S02 and
about 500 mg/Nm3 dust, is first treated by two trains of
the FGD system, each of which has two ESPs to reduce dust to
about 20 mg/Nm3. The gas is then passed through a Ljungstrom
type heat exchanger to be cooled to 90°C, and is then subjected
to ammonia scrubbing to have over 90% of S02 removed. Next,
the gas is passed through wet ESPs specially designed by NKK,
heated in the heat exchanger to 110°C, and then discharged.
The stack gas contains 2-5 mg/Nm3 dust, about 10 ppm S02, and
2-20 ppm NHa, and is virtually invisible. A very slight plume
is observed when the NH3 concentration exceeds 10 ppm.
248
-------
VO
LJUNGSTROM
HEAT
EXCHANGER
LJUNGSTROM
HEAT
EXCHANGER
ESP
Figure 6-1. Flue gas treatment system (Ogishima plant, Nippon Kokan).
-------
to
Ln
O
LJUNOSTHOM HEAT
EXCHANGER
S0210ppm
NH3 2-20 ppm
SINTERING
— •*
1.120.000 Nm3
SO, 300 ppra
DUST BOB M/Nn3
ESP
^
^
7 V"
V~7
^-
^
* /
/ /
DUST 1 2 m|/Nm3
WFT FfiP
OXIOIZER
04iX
(NH4»j S04 29%
NH3 ABSORBER
(S. NH«H$, NH4SGN)
CLEANED COKE
OVEN GAS
CRVSTALLIZER
(NH4)2S04,(NH4CL)
Figure 6-2. S02 and NH3 absorption system (Ogishima plant, Nippon Kokan)
-------
The scrubber has five stages of screens, as shown in
Figure 6-3, and consists of three sections: the gas refining
section (top), absorbing section (middle), and cooling section
(bottom). Water is fed to the wet ESPs. The liquor discharged
from the wet ESPs, with a specific gravity of 1.02 and a pH of
6.5, is first sent to the refining section. It flows through
two stages of screens, forming liquid films that remove most of
the SOX and NH3 which have not been absorbed in the absorbing
section. The liquor is then sent to the cooling section and
sprayed into the gas. The specific gravity increases to 1.10
and the pH is lowered to 5.8. The liquor is then sent to the
absorbing section where there are three stages of screens. A
portion of the liquor circulating in the absorbing section is
sent to an ammonia absorber, where the liquor absorbs ammonia
from coke oven gas. The liquor is then returned to the absor-
bing section. The coke oven gas is pretreated by the Takahax
process to remove H2S.
The liquor in the S02 absorbing section has a speci-
fic gravity of 1.18 and a pH of 5.9 and contains ammonium sul-
fate, bisulfate, sulfite, and bisulfite with small amounts of
chloride and thiosulfate. The ratio of (sulfate + bisulfate):
(sulfite + bisulfite):(other compounds) is approximately
70:25:5. The high oxidation ratio is due to the high 02 con-
centration (over 15%) and low S02 concentration (300 ppm) in
the flue gas. Ammonium chloride is derived from chlorine in
the flue gas (about 50 ppm) and the thiosulfate mostly from
H2S.
A portion of the liquor is sent to an oxidizer to-
gether with the liquor discharged from the Takahax unit, which
contains S, NH.HS, and NH.SCN. There it is oxidized by air at
280°C under 20 atmospheres of pressure. The product of the oxi-
dation, a mixed solution of ammonium sulfate and sulfuric acid
251
-------
FROMNH,-
ABSORBER ^"
TONH3 ,
ABSORBER
GAS
*
1
1
1
pH 6.5
tj. 1.02
pH 5.9
vj. 1.1 S
GAS
OEMISTER
-*-!-=. ^rm^=fTfr
X|\
^ X,>
pH 5.8
1.10
REFINING
SECTION
ABSORBING
SECTION
COOLING
SECTION
TO OXIOIZER
Figure 6-3. Scrubber and liquor flow (Ogishima plant,
Nippon Kokan) (s.g.: specific gravity).
252
-------
with a small amount of chloride, is sent to the second ammonia
scrubber and then to a crystallizer, where solid ammonium sul-
fate (with a small amount of chloride) is produced.
Performance of Ogishima Plant--
Operation parameters of the Ogishima plant are shown
in Table 6-2. The screen scrubber gives a high S02 removal ef-
ficiency with a low pressure drop. The L/G ratio is low as
well, resulting in a relatively small power requirement. The
operation hours in each month since the start-up of the plant
/
in November 1976 are shown in Table 6-3.
TABLE 6-3. OPERATION HOURS SINCE START-UP
Nov. 1976
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
Sept.
TOTAL
Total
hours (A)
720
744
744
672
744
720
744
720
744
744
720
= 8,760
Operation
Machine (B)
401
667
668
527
733
681
704
684
697
725
702
7,189
Hours
FGD (C)
401
667
668
527
733
681
704
684
697
725
702
7,189
B/A
(%)
55.7
89.7
89.8
78.4
98.5
94.6
94.6
95.0
93.7
97.4
97.5
82.1
C/B
(%)
100
100
100
100
100
100
100
100
100
100
100
100
The sintering machine is stopped for a few days each
month for maintenance. Maintenance work on the FGD system is
done during that period. The sintering machine has never been
253
-------
shut down because of problems with the FGD system. The plant
has no flue gas bypass because the stringent S02 regulations
do not allow sintering machines to be operated without FGD.
Economics--
The total FGD plant cost was ¥7.24 billion in 1976,
excluding the Takahax unit but including ¥1.24 billion for the
wet ESPs and ¥0.24 billion for the heat exchangers. The an-
nualized cost including 7 years depreciation is ¥4.5 billion,
which is equivalent to ¥l,950/ton of sintered ore or ¥562/
1,000 Nm3 of flue gas. The plant was designed for a capacity
of 1,230,000 Nm3/hr, which is equivalent to 410 MW. Therefore,
the plant cost works out as $71/kW, of which the wet ESPs and
heat exchangers account for $12 and $7.1, respectively. The
annualized cost is equivalent to 7.6 mills/kWhr including 7
years depreciation.
The costs of the wet ESPs and heat exchangers are
fairly high, but a calculation by NKK indicates that the an-
nualized cost is less than the annualized cost for fuel to
reheat flue gas to 110°C, which is required when wet ESPs and
heat exchangers are not installed. The ESPs not only eliminate
plume but also protect the heat exchanger from corrosion.
6.2.3 Fukuyama Plant
The Fukuyama plant uses one scrubber and has a
capacity of treating 760,000 Nm3/nr of flue gas from an iron-
ore sintering machine. The process is similar to that of the
Ogishima plant except that after FGD the flue gas is reheated
by an after-burner to 120°C without wet ESPs or heat exchangers
A noticeable plume is formed. The operation data are shown in
Table 6-4.
254
-------
TABLE 6-4. OPERATION PARAMETERS OF FUKUYAMA PLANT
FGD capacity (1,000 Nm3/hr) 760
Inlet S02 (ppm) 250
Inlet gas temperature (°C) 125
Inlet dust (mg/Nm3) 30
L/G (liters/Nm3) 1>5
Liquor pH 6>0
Gas velocity (m/sec) 1.2
Outlet SO2 (ppm) 10 - 20
Pressure drop, total (mmH20) 230
Energy requirement,, total (kW) 13
The monthly operation hours are smaller than those
of the Ogishima plant due to the planned cutback of iron pro-
duction. Maintenance of the FGD system can be performed during
the shutdown of the sintering machine, and therefore, the FGD
operability has been kept at 100%.
6.2.4 Evaluation
The Ogishima plant may be the world's first large-
scale commercial ammonia scrubbing plant free from plume prob-
lems. The process has the following advantages: 1) It by-
produces ammonium sulfate using S02 and NH3 in waste gases;
2) Use of the wet ESP prevents plume formation and protects
the heat exchanger from corrosion; 3) The screen type scrubber
has a high S02 removal efficiency with a small pressure drop
and a low L/G ratio, thus requiring small power consumption.
On the other hand, the process is not simple because
of the use of coke oven gas containing H2S. The wet ESP is
fairly costly. Advantages, however, may compensate for the
disadvantages.
255
-------
6.3 NISHINAGOYA PLANT, CHUBU ELECTRIC (WELLMAN-MKK PROCESS)
6.3.1 Outline
The FGD plant at Nishinagoya station, Chubu Electric,
was constructed by MKK (Mitsubishi Kakoki Kaisha) using the
Wellman-Lord process to treat the gas from the No. 1 oil-fired
boiler (220 MW). It has been in operation since 1972. S02 in
the flue gas is absorbed in an Na2S03 liquor to form NaHS03,
which is heated to regenerate Na2S03 and to produce concentra-
ted S02 for sulfuric acid production. A flowsheet of the pro-
cess is given in Figure 6-4. Details of the process are avail-
able in published literature.10 Recent operation parameters
are shown in Table 6-2. In addition to the energy requirements
given in Table 6-2, 24 tons/hr of steam are required for regen-
eration (14 ton/hr for evaporation).
The process requires extensive wastewater treatment
to remove Na2SOl| and polythionates, such as dithionate (NaitS206),
formed by oxidation of Na2S03. A purge stream from the absorp-
tion-regeneration loop is first treated with ozone to decompose
the polythionates, and is then cooled to 0°C to crystallize
Na2SOi», which is centrifugally separated from the mother liquor.
The liquor is returned to the scrubber system. Since the sep-
arated Na2SOi» contains a considerable amount of Na2S03, which
has a chemical oxygen demand (COD), it is treated with H2SO«» to
convert the Na2S03 to Na2SOit and S02. The S02 is sent to the
scrubber, and the product Na2SOi» solution is purged.
6.3.2 Sulfur Balance
The sulfur balance of the system is shown in Figure
6-5. One hundred parts of S with 6.3 parts of recycle S, both
in the form of dilute S0x, are fed to the absorber. The
256
-------
Ul
luirumCAcioncnn
Figure 6-4. Flow sheet of the Wellman-MKK process
(Nishinagoya Station, Chubu Electric Power).
-------
TO STACK
to
Ln
00
WASTE Ni,S04
Figure 6-5 Sulfur balance of FGD system at Nishinagoya,
Figure b :>. w^ Electric (Wellman-MKK process).
-------
regenerator yields 90.5 parts of S in the form of concentrated
S02> while 11.8 parts of S—mainly Na2SO,, some NaitS206, and
Na2S03--are sent to the wastewater treatment system. Sulfuric
acid (8.8 parts of S) is added to the wastewater treatment sys-
tem to produce concentrated S02 (3.6 parts of S), which is sent
to an E2SOk plant, and dilute S02 (1.1 parts of S), which is
returned to the absorber together with the H2S04 plant tail
gas (5.2 parts of S).
Thus, of the 100 parts of inlet S, 4.0 parts leave
the scrubber unabsorbed, 80.1 parts are produced as H2SO,», and
15.9 parts are discarded in wastewater. Actually, the plant
requires 7 tons/day of NaOH (as 100%) and by-produces 80 tons/
day of HzSO^ (98%) at full load operation to treat 620,000 Nm3/
hr of flue gas containing 1,500 ppm S02.
6.3.3 Performance and Cost
The plant, including the sulfuric acid plant, is
fully automated and is operated by 2 persons per shift with 5
persons for maintenance in the daytime. The operation hours
of the boiler and FGD plant are shown in Table 6-5. The yearly
average operability was 96.5%. Excluding March, when low-sulfur
oil was used to start up the boiler after the annual maintenance
work on it, average operability was 98.9%. Major problems in-
volved the evaporator (regenerator).
The pH and the composition of the liquor regenerated
to return to the scrubber are as follows:
PH 7.3 - 7.4
Na2S03 15 - 18% NaaSO, 7 - 9%
NaHS03 1% NaC1 0.6-0.7%
259
-------
TABLE 6-5. YEARLY OPERATION OF NISHINAGOYA NO. 1
BOILER AND FGD PLANT
to
o>
o
Hours
Total Boiler oper-
(A) ation (B)
Oct. 1976
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May.
June
July
Aug.
Sept.
744
720
744
744
672
744
720
744
720
744
744
720
732
665
744
339
0
744
710
738
674
744
680
720
FGD oper-
ation (C)
732
655
740
339
0
501
710
738
674
744
680
717
Availability (Z)
Boiler FGD
(B/A) C/A
98.4
92.4
100
45.6
0
67.3
98.6
99.2
93.6
100
91.4
100
98.4
91.0
99.5
45.6
0
48.5
98.6
99.2
93.6
100
91.4
99.6
Opera-
bility
(C/B) (Z)
100
98.5
99.5
100
72.1
100
100
100
100
100
99.6
Remarks
Maintenance of evaporator
circulation pump
Servicing of evaporator
vacuum pump
Scheduled maintenance
on boiler
Scheduled maintenance
on boiler
Use of low-sulfur oil
boiler start-up
Leakage of evaporator
work
work
at
TOTAL • 8,760 7,490
7,230 85.5 82.5
96.5
(excluding 8,016 6,819
March)
6,746
85.1
84.1
98.9
-------
The plant requires a high-quality corrosion resistant material
in the regeneration section; 316 stainless steel has proved
unsatisfactory. Another problem is the crystallization of
Na2S04 on the tubes of the heat exchanger resulting in the de-
crease of cooling efficiency. The tubes are occasionally
washed with the scrubber liquor at 40°C to dissolve the Na2SOtt.
The plant cost 1.6 billion yen in 1972. About 100
million yen was spent later for the wastewater treatment sys-
tem.
6.3.4 Evaluation
The plant cost in 1972, viz., 7,300 yen/kW, was
unusually low. New plants by the Wellman-MKK process cost
considerably more due to the need for a highly corrosion-
resistant material and an extensive wastewater treatment sys-
tem.
The Wellman process would suit a plant which has a
good market for sulfuric acid or a Glaus furnace to convert
the recovered S02 to sulfur. Compared with a magnesium scrub-
bing process, the Wellman process has no calciner, but it has
a regenerator, which also consumes much energy and often causes
problems. The Wellman process requires an extensive wastewater
treatment system while magnesium scrubbing normally produces no
wastewater.
261
-------
6.4 CHIBA PLANT, IDEMITSU KOSAN (MISTUI-CHEMICO MAGNESIUM)
PROCESS
6.4.1 Process Description
The plant has a capacity of treating 500,000 Nm3/hr
of flue gas containing 3,000 ppm S02 from two industrial boilers
burning 370-sulfur oil and four Glaus furnaces. It uses the
Mitsui-Chemico magnesium scrubbing process. A flowsheet of the
process is shown in Figure 6-6. The actual plant has a tower
with two-stage venturi scrubbers.
The flue gas is passed through the 1st to the 2nd
scrubber while Mg(OH)2 is fed to the 2nd scrubber. Slurry from
the second scrubber is sent to the 1st scrubber through a pH
controller and a thickener. The pH of the slurry is 6.5 - 7 in
the second scrubber, where the major component is MgS03. Since
the slurry temperature is 68°C, the MgS03 is present mostly in
the form of trihydrate (with a small crystal size of 2 - 5
microns), and partly in the form of hexahydrate (with much lar-
ger crystal size, up to about 100 microns). The pH is lower
in the first scrubber, where the major compound is Mg(HS03)2.
A portion of the circulating slurry from the first scrubber is
cooled to 40°C and sent to the pH controller, where it is
treated with Mg(OH)2 to adjust the pH to 6.5 - 7. The Mg(HS03)2
then reacts with Mg(OH)2 to form mostly MgS03-6H20 with a large
crystal size of 50 - 100 microns.
The slurry from the pH controller and the second
scrubber is treated in a thickener to separate the hexahydrate
and trihydrate by crystal size. The trihydrate is returned to
the 1st scrubber. The hexahydrate discharged from the bottom
of the thickener is filtered by a centrifugal separator (super-
decantor), dried in a co-current dryer, and then calcined with
262
-------
rim BAI 'L-
10
«MORIE«T
ITORAOE I»IH
Figure 6-6. Flow sheet of Chiba plant, Idemitsu Kokan
(Mitsui-Chemico magnesium process).
-------
petroleum coke in a rotary kiln at about 900°C to regenerate
MgO and to produce about 1070 S02 gas. The S02 gas is sent to
the Glaus furnace to by-produce sulfur. The MgO is slaked to
form a Mg(OH)2 slurry, which is fed to the second absorber and
the pH controller.
6.4.2 Performance
Operation parameters are shown in Table 6-2. About
95% of S02 is removed at a pressure drop of 500 mmH20. Since
the reactivity of MgO gradually decreases by the repeated cal-
cination, a portion of the MgO is replaced by fresh Mg(OH)2
obtained from sea water. The old MgO is discarded. The re-
quirement of MgO amounts to 300 tons/year. The operation hours
of the boiler and scrubber in a recent year are shown in Table
6-6. Operation of the scrubbing section has been almost
trouble-free except that pumps have had to be replaced oc-
casionally. Since a stand-by pump is provided, replacement
can be done without interfering with scrubber operation.
On the other hand, the regeneration steps sometimes
encounter problems. During the first year after the start-up
in August 1974, many troubles were encountered, including the
wearing of the super-decantor, falling off of the refractories,
and build-up of solids in the kiln. The problems have been re-
duced but the kiln still has to be shut down occasionally.
The plant has a magnesium sulfite silo with a capacity to store
the dried sulfite produced in 20 hours of operation, so that
the other steps in the process can remain in operation while
the kiln is shutdown for up to 20 hours. For longer shutdowns
of the kiln, low-sulfur oil is burned to reduce the production
rate of sulfite. The ratio of high-sulfur and low-sulfur oils
consumed in a recent year is 80 to 20.
264
-------
ts»
in
TABLE 6-6. OPERATION HOURS (CHIBA PLANT, IDEMITSU KOSAN,
FGD TREATS FLUE GAS FROM BOILER AND CLAUS FURNACE.)
Hours
Total Boiler oper-
(A) atlon (B)
Sept. 1976
Oct.
Nov.
Dec.
Jan. 1977
Feb.
Mar.
Apr.
May
June
July
Aug.
TOTAL -
720
744
720
744
744
672
744
720
744
720
744
744
8,760
720
442
528
456
744
672
744
720
384
336
744
744
6,514
Availability (Z)
Scrubber op- Boiler
eratlon (C)* B/A
720
744
720
744
744
672
744
720
329
301
724
725
7,887
100
59
73
61
100
100
100
100
52
47
100
100
74.3
FGD
C/A
100
100
100
100
100
100
100
100
44
42
97
97
90.0
Opera-
bility
(C/B) (Z) Remarks
100
100
100 Scheduled maintenance work
on boiler (Claus furnaces
were in operation)
100
100
100
100
100 ~
86 Scheduled maintenance work
on boiler and FGD
90
97 Accident of power source
97 Cleaning of slurry nozzle
(97.5)
* Calciner sometimes stops while scrubber is in operation.
-------
The life of the refractories is estimated at 3 years.
The FGD plant normally purges no wastewater.
6.4.3 Evaluation
The process has been improved by the joint efforts of
Idemitsu and Mitsui Miike, resulting in high operability. One
of the important improvements is the use of the pH controller
to produce well-grown crystals of MgS03-6H20, which is easily
filtered and dried. A patent has been applied for by Idemitsu
and Mitsui Miike for the use of the pH controller. The cal-
ciner still has problems, but the operation experience will
further reduce them.
The process is suitable for a refinery which has a
Glaus furnace to by-produce sulfur and for a plant which has a
market for sulfuric acid. No-wastewater operation is another
advantage for the process.
For application to a coal-fired boiler, the accumula-
tion of chlorine and fly ash in the slurry may increase corro-
sion and erosion. It may be preferable to remove chlorine and
fly ash by installing a prescrubber. Since the switching to a
low-sulfur fuel is not as easy with coal as with oil, a larger
magnesium sulfite silo may be needed.
6.5 OTHER MAJOR REGENERABLE PROCESSES
6.5.1 Sodium Scrubbing By-Producing Sodium Sulfite
Over 800 sodium scrubbing plants are in operation
by-producing sodium sulfite and sulfate. Most of the plants
use sodium sulfite liquor at pH 6 - 7 rather than NaOH as the
266
-------
S02 absorbent because sodium hydroxide also absorbs C02. Ab-
sorbed S02 reacts with sodium sulfite to produce sodium bisul-
fite (reaction 6-1). The sodium bisulfite is then neutralized
with sodium hydroxide to regenerate a sulfite solution (reaction
6-2), half of which is returned to the scrubber and the rest of
which is sent to a concentration step. The by-product sulfite,
in the form of either a concentrated solution or crystal, is
sold to paper mills. Reactions in a sodium sulfite system are
listed below:
Na2S03 + S02 + H20 = 2NaHS03 (6-1)
<
2NaHS03 + 2NaOH = 2Na2S03 + 2H20 (6-2)
As an example, operation parameters of the Nagoya
plant, Mitsui Toatsu, which uses the Kureha process, are shown
in Table 6-2. Over 99% of S02 in the flue gas is recovered
with a low L/G ratio and a small power consumption.
In several plants, including those of Jujo Paper Co.,
a sodium hydroxide solution is sprayed in a reactor to obtain
a powdery product consisting of sodium sulfite, sulfate, and
carbonate (for example, 60% Na2S03, 20% NajSCU, and 20% Na2C03)
which is caught by a multicyclone, electrostatic precipitator,
or baghouse. The product is usable for Kraft pulp production.
6.5.2 Shell Copper Oxide Process
The Yokkaichi plant, Showa Yokkaichi Sekiyu (SYS),
using the Shell copper oxide process, has treated 120,000 Nm3/
hr of flue gas from an oil-fired industrial boiler to reduce
SO from 1,250 ppm to 90 ppm. Operation parameters are shown
inXTable 6-2. The process has been described in published
267
-------
literature. 10'21 Since the start-up in 1972, the plant has
occasionally been shut down for modifications to improve opera-
bility. In February 1977, the acceptor (granular alumina impreg-
nated with copper oxide) was renewed. The previous replacement
was made three years ago. Since 1975 ammonia has been added to
the reactor in order to simultaneously reduce NOX, as will be
described in Section 7.2.
The FGD plant was started up in May 1977 and shut down
in June because of a boiler shutdown. Operation resumed in
August and the SOa and NOX removal efficiencies were kept at
80-85% and 40-45%, respectively. Higher removal efficiencies
were not attempted as these values were sufficient to meet local
and federal regulations.
6.5.3 Activated Carbon Processes
Tokyo Electric has been operating an activated carbon
process plant at Kashima with a capacity of treating one-fourth
the quantity of gas from a 600 MW oil-fired boiler. The SOV
X
adsorbed on the carbon is washed with water to by-produce a weak
sulfuric acid, which is then treated with limestone to produce
good-quality gypsum. The plant has been operated for over 5
years without any serious problem. Loss of carbon has been less
than 2% per year. Although the process is costly,, requiring
large adsorbers with a large amount of carbon (about 500 tons),
stable operation and small consumption of carbon are attractive
features.
In 1975, Unitika Co. installed an activated carbon
process plant at Uji with a capacity of treating 170,000 Nm3/hr
of flue gas from an industrial boiler burning 2.5%-sulfur oil.
Dilute H2SOi» (5-7% concentration) is obtained by washing the
268
-------
carbon with water. The dilute acide is then sprayed into the
incoming flue gas at 170°C. The gas is then cooled to 80-90°C,
and the acid is concentrated to about 60%. Unitika has used
the acid in its own chemical plant. The process may be useful
where there is a demand for the product acid, which is a little
dirty and too dilute for general commercial uses.
The dry carbon process plant of Kansai Electric at
Sakai, which had a capacity of treating 150,000 Nms/hr of flue
gas from an oil-fired boiler by using a moving bed, has been
given up after 5 years of operation. After adsorbing S02, the
carbon was heated in a reducing atmosphere to recover concen-
trated S02 gas, which was then used for sulfuric acid production.
The consumption of carbon in the process was too high. Activa-
ted carbon used for FGD in Japan is of high quality and ensures
smooth operation but is expensive (800,000 yen/ton) .
Tests have been made by Unitika and also by Sumitomo
Heavy Industries on simultaneous removal of SOX and NOX using
activated carbon (Section 7.2).
6.5.4 Ammonia Scrubbing by Ube Industries
Ube Industries has developed an ammonia scrubbing pro-
cess and constructed two commercial units in 1977, each with a
capacity of treating 120,000 Nm3/hr of flue gas from an indus-
trial boiler burning 2.5%-sulfur oil. Ammonium sulfite is by-
produced and is used for caprolactum production. The total
investment cost was nearly 1.2 billion yen.
Each FGD unit consists of a gas-cooler and two absorb-
ers in series. About 20% solution of ammonium compounds, mainly
sulfite with small amounts of bisulfite and sulfate, is formed
269
-------
in the scrubber and concentrated in the gas-cooler to 357» solu-
tion. The solution is purified by filtration, absorption by
activated carbon, and by chlating agent.
A plume problem, common to ammonia scrubbing processes,
has been encountered. Tests are in progress to reduce the plume.
270
-------
SECTION 7
SIMULTANEOUS REMOVAL OF SO AND NO
X X
7.1 OUTLINE
7.1.1 Problems with NOX and SOX Removal Processes
NOX removal from flue gas is increasing in importance
with the growing consumption of fossil fuels, particularly coal.
Selective catalytic reduction (SCR), in which NOX is catalytic-
ally reacted with ammonia to produce N2 and H20, has been
considered most promising in Japan and has been applied to about
40 commercial plants. In those plants 85-95% of NOX in flue gas
is removed at 300-400° C with an NH3/NOX mole ratio of 1.0-1.2
and a space velocity of 5,000-10,000 hr"1. Plant operation is
easy with clean gas but not with dirty gases containing dust and
SOX because of the following problems:
1) Plugging of catalyst with dust.
2) Poisoning of catalyst by SOX, especially by S03.
3) Formation of N1UHSO* in the air heater resulting
in corrosion and plugging.
4) Consumption of large amounts of ammonia.
5) Oxidation of a portion of S02 to S03 by some
of the catalysts.
271
-------
Selective noncatalytic reduction (SNR) which uses
1.5-2 moles NH3 to 1 mole NOX at 950-1, 000° C has been tested in
several large-scale plants. In those plants, 40-5070 of NOX has
been removed at a relatively low cost but problems 3) and 4) are
larger than in SCR.
Further problems, as shown below, are encountered when
the ammonia reduction processes (dry processes) are used in
combination with FGD (predominantly wet processes) :
6) Large energy requirement for gas heating when
SCR is applied after wet FGD.
7) Accumulation of NHa in the FGD scrubber liquor
when SCR is applied ahead of FGD.
8) A large space requirement for the installation
of both units.
Simultaneous SOX and NOX removal processes, either dry
or wet, have been studied aiming at removal with less difficulty
and lower cost than by the combinations of SOX and NOX removal
processes.
7.1.2 Comparison of Simultaneous and Combined Removal
Processes
Major simultaneous removal processes are classified in
Table 7-1. The reaction temperatures and heat loss of simul-
taneous processes are shown schematically in Figure 7-1 (No. 6-
No. 9) in comparison with the combined processes (No. 3-No. 5).
272
-------
Option
•o. 1
•o. i
No. J
Ho. 7
cr
BoUir
Figure 7-1.
150 ,
:
150
\
/
-L.
\
' 1
" "I 1 "
L^J
400
—
150
-p—P
\
/
/
\
55
400
—
160
\
/
\
1 i
55
OO
75
160
-_
\
/
N
55
OO
75
400
230
230
OO
150
400 _ I I 150 _
100
100
Ho. 8 400
400 , .150
150
1 150
^J
ISO
\
/
-L
/
\
J.
53
OO
75
Air
Hutu
SlMttotutic
Prtciplotor
\/
A
ScniEbi
Kxcuagvr
Combined and simultaneous removal systems
control strategy options (numbers show
temperatures, °C).
273
-------
TABLE 7-1. CLASSIFICATION OF SIMULTANEOUS REMOVAL PROCESSES
Process Process Developer
Dry Metallic oxide Shell, others
Activated carbon Unitika, Sumitomo Heavy Industries
Electron beam Ebara
Wet Oxidation reduction Sumitomo Metal-Fujikasui, IHI, MHI
Reduction Kureha, Chisso, Asahi Chemical
Equimolecular absorption Kawasaki H.I.
No. 1 of Figure 7-1 shows gas temperatures at regular
boiler operation, which is taken as a standard (no heat loss).
No. 2 illustrates the application of FGD with gas reheating
from 55 to 75°C, which accounts for a heat loss of about 1%
(equivalent to about 1% of boiler input).
No. 3 of Figure 7-1 shows the application of FGD ahead
of SCR to clean the gas to avoid problems 1) and 2) mentioned
in Section 7.1.1. The combination causes much heat loss (about
5%), and yet is not entirely free from problems 1), 2), and 3).
Moreover, mist from FGD aggravates the problems. Use of a high-
efficiency wet electrostatic precipitator after FGD (ahead of a
heat exchanger) can solve the problems as has been done at the
Chiba plant, Kawasaki Steel, which treats 800,000 Nm3/hr flue
gas from an iron-ore sintering plant. But such a system is very
expensive and may not be applicable to other plants.
No. 4 in Figure 7-1 illustrates a recent trend in Japan
to treat gas at 350-400°C from a boiler economizer by SCR and
then by FGD. Catalysts based on Ti02 resistant to SOx have been
produced. Present efforts are concentrated on developing
reactors and catalysts free from dust plugging. Use of parallel
274
-------
flow by a parallel passage reactor or use of a honeycomb, tube,
or plate type catalyst seem promising. Nevertheless, problems
3) and 4) (in Section 7.1.1) remain unsolved and 7) is added.
About 0.5% heat loss may be caused by problem 3) in addition to
about 1% for reheating after FGD.
Selective noncatalytic reduction (No. 5 in Figure 7-1)
gives a heat loss similar to No. 4. and has problems 3), 4), and
7) to a greater extent than No. 4. Both systems require a
device to cope with the fluctuation of boiler load to maintain
an optimum reaction temperature.
Systems No. 6-No. *9 show dry simultaneous removal
processes which are expected to have no heat loss, although
considerable energy is required for plant operation. All major
dry processes developed so far in Japan use ammonia and are not
free from problem 4). In addition, carbon and metal oxide
processes have problems 1) and 3) .
The wet simultaneous removal process (No. 9) has a heat
loss similar to FGD but is expected to be free from all problems
from 1) to 8). The process, however, has other problems to be
solved, as will be mentioned later.
7.2 DRY SIMULTANEOUS REMOVAL USING ACTIVATED CARBON
7.2.1 Reactions of Activated Carbon
Activated carbon absorbs not only SOX but also NOX.
The adsorption capacity is smaller at higher temperature and
the adsorption rate of NO is much smaller than that of N02 and
S02.22 Moreover, regeneration of the carbon gives off NOX-
containing gas, which is useless and requires further treatment.
275
-------
Thus, it is not practical to remove NOX in a large amount of
flue gas by using activated carbon.
Activated carbon impregnated with metal compounds
serves as a catalyst for the following reaction above 100 °C:
4NO + 4NH3 + 02 = 4N2 + 6H20 (7-1)
The effects of metal compounds are shown in Table
7-2. 22 Copper and vanadium have high catalytic reactivities
at 100°C. Ammonium bromide also has a high catalytic reacti-
vity at 100°C.23 At temperatures below 200°C, however, the
treatment of flue gas containing SOV and NOV with ammonia re-
J /N X
suits in the formation of ammonium bisulfate, which deposits
on : the carbon and lowers the reactivity. Therefore, a tempera-
ture above 200 °C is preferred. Since SO removal efficiency
j ?\
tends to be lowered at higher temperature (Figure 7-2) , a
temperature between 220 and 250 °C is used for simultaneous
removal by activated carbon. S02 adsorbed by the carbon is
converted mainly to HaSOi* and partly to NH^HSOi*, while the
adsorbed NOX is converted to N2.
The process has the advantages of a dry simultaneous
removal process, but has disadvantages as well. Because a
moderate reaction temperature is used, two heat exchangers are
needed for heat recovery, as shown in No. 6 of Figure 7-1. One
is needed before the reactor and the other is needed after.
Activated carbon is also costly (over 1 million yen per ton)
and is needed in a large amount because of the small space
velocity of 500-1,000 hr"1 required to attain over 90% NOX and
SOX removal efficiencies. Some of the activated carbon is
lost during the regeneration process. If the reacted carbon
were washed with water, a weak solution of HaSO^, which is
276
-------
'"TO
O rSn
<2>000 Ppm
°F MSE 11ETAL COMPOUNDS
x REDUCTION EFFICIENCY
NH, . 3,000 hr'1 SV)
Metal
None
Ti
Cr
Mn
Fe
Co
Ni
Cu
V
Mo
W
110°C
38
55
50
52
63
91
80
<
NOx reduction efficiency, %
150°C
44
65
70
67
67
75
67
99
88
70
65
250°C
78
95
88
90
98
100
100
100
90
o
•H
4-1
CO
I
80
70
60
100
150
200 250 300
Temperature (°C)
350
Figure 7-2. Efficiency of simultaneous removal by
activated carbon and ammonia.
277
-------
difficult to treat, would be produced. Moreover, wet carbon
adsorbs SOV but not NOV. Therefore, the reacted carbon is
X f^
usually regenerated by being heated at about 400°C to convert
H2SCU and NiUHSCU to S02, N2, NH3, and H20. A considerable
portion of the carbon is consumed by the thermal reactions as
shown below:
H2SCK + C = S02 + CO + H20 (7-2)
NIUHSO., + C = NH3 + H20 + S02 + CO (7-3)
The carbon consumption increases with the SOX con-
centration of the gas and the SOV removal efficiency. Ammonia
XX
consumption increases not only with N0x but also with S02, be-
cause a portion of the S02 forms NHi»HS03 . Therefore, the carbon
process may be too costly for a gas containing over 500 ppm SOX-
Less expensive carbon with a high efficiency and yet without a
tendency to burn is desired.
7.2.2 Unitika Activated Carbon Process
Since November 1975, Unitika Co. has operated a pilot
plant with a capacity of treating 4,500 Nm3/hr of flue gas from
a glass melting furnace containing about 300 ppm S02, 200 ppm
NOx, and 5-10 mg/Nm3 dust (Figure 7-3). The adsorption tower
has four compartments, all of which have a fixed carbon bed.
About 400 ppm NHa is added to the incoming flue gas at about
230°C and the gas mixture is led into three compartments. (The
fourth compartment undergoes simultaneous regeneration.) About
90% of NOX and S02 is removed. The carbon that has adsorbed
SOa is regenerated by being heated to 350°C in an inert gas
produced by incomplete combustion of propane. The inert gas
contains about 1-1.5% CO, 9.5-10% C02, 0.8% H20, and 0.5% 02.
The recovered concentrated S02 gas can be used for sulfuric
278
-------
REACTOR
fO
A
HEATER
M°C
FLUE GAS t-*
250°C
• ABSORPTION
REGENERATION
TO STACK
fl INERT GAS
PRODUCER
Figure 7-3. Flow sheet of Unitika process (Uji plant).
-------
acid production or other purposes. Ammonium sulfate and bisul-
fate which tend to form on the carbon are decomposed to SOa and
N2 in the regeneration step.
The main design and operating parameters are as
follows:
Tower height 17 m
Carbon bed thickness 1 m
Pressure drop 100 nmiHzO (reactor)
250 mmH20 (total)
Absorption time for 1 cycle 3 days
Regeneration time for 1 cycle 12 hours
SO2 in gas from regeneration 5-10%
step
Space velocity (SV) 700-1,500
Superficial gas velocity 0.1-0.2 m/sec
The activated carbon, produced by Takeda Chemical for the
simultaneous removal, is in the form of cylinders with a 5 mm
diameter and 8-10 mm length. Carbon consumption is estimated
to be about 507» of the charge per year.
At an early stage of operation, when the reaction
temperature was about 180°C, a large amount of ammonium bisul-
fate and sulfate formed on the carbon and caused plugging. Use
of a 230°C temperature solved the problem.
Unitika's cost estimates for plants of three sizes,
30,000-500,000 Nm3/hr (10-160 MW) , are shown in Table 7-3. For
the calculation, the carbon consumption was assumed to be 100%
of the charge yearly.
280
-------
™IT T^n^?0 CAPITAL AND OPERATING COST FOR
SIMULTANEOUS REMOVAL BY ACTIVATED CARBON
(1,000 ppm SOV, 300 ppm NO )
^^j— — _ A * f. V '
Total plant cost (106 yen)
Major units
Accessories
H2SOn plant
Operation cost (yen/kl oil)
Depreciation and interest
Electric power
Fuel
Ammonia
Other (carbon, etc.)
Total
Capacity
30
400
249
41
111
3,700
650
2,500
1,200
1,500
9,550
(1,000 Nm3/hr)
100
900
587
87
226
2,890
650
2,500
1,200
1,400
8,640
500
3,000
2,048
252
700
2,440
650
2,500
1,200
1,400
8,190
Since the process uses a fixed bed, carbon consumption
is relatively small. The dust content of the gas at the pilot
plant is very low and does not contaminate the catalyst. For
dust-rich gas, a moving bed is needed which will increase the
attrition of the carbon. For such a case, the carbon consump-
tion might exceed 100% of the charge per year.
7 2.3 Activated Carbon Process by Sumitomo Heavy Industries
Sumitomo Heavy Industries (former Sumitomo Shipbuild-
ing) tested a simultaneous removal process using a moving bed
of activated carbon (Figure 7-4). Flue gases from an iron-ore
sintering plant and also from an oil-fired boiler were used.
281
-------
to
CO
Ni
FLUE GAS
REGENERATOR
HEAT I
EXCHANGER
INERT GAS PRODUCER
Figure 7-4. Flow sheet of Sumitomo activated carbon process
-------
Tests with a gas (2,000 Nm3 /hr) containing 500 ppm of SOX, 200
ppm of NOX and about 100 mg/Nm3 of dust indicated that 95% of
SOX , 90% of NOX and 60% of dust were removed by reaction at
230° C with a space velocity of 1,000 hr'1 and a total pressure
drop of 150-200 mmH20. The carbon discharged from the reactor
at 230° C containing S03 and NHi»HSO^ was heated in an inert gas
to produce concentrated S02. The inert gas contains 1.57. CO,
12.57o C02, 0.05% 02 , and 0.8% H2. The ammonium bisulfate was
decomposed to S02, N2 , NH3 and H20.
The operation was carried out fairly smoothly but the
consumption of carbon was fairly high; the consumption was due
both to attrition and to chemical consumption.
Sumitomo estimates that a plant with a capacity of
treating flue gas from a 500 MW coal-fired boiler containing
500 ppm SO2 and 600 ppm NOX would cost about 5 billion yen plus
about 2 billion yen for the initial charge of activated carbon.
In addition, a hot electrostatic precipitator is needed.
Roughly 3,000 tons/year of activated carbon, 3,100 kW of power,
1,050 kg/hr of NH3, 470 kg/hr of LPG for inert gas production,
and 1 ton/hr of steam would be consumed.
The plant cost is low but carbon consumption is very
high. Since the consumption of activated carbon increases with
the SO2 concentration of flue gas, the process may only be
useful for a gas with a relatively low S02 concentration, say
below about 500 ppm. The SCR process using the moving bed
tolerates about 200 mg/Nm3 dust. An electrostatic precipitator,
therefore, would be needed to treat flue gas from a coal-fired
boiler.
283
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7.3 OTHER DRY PROCESSES FOR SIMULTANEOUS REMOVAL
7.3.1 Shell Copper Oxide Process
The Shell process uses copper oxide supported on
granular alumina placed in two parallel passage reactors.
Originally the process was used for SOX removal only. Flue
gas at 400° C is introduced into one of the reactors, where SOX
reacts with copper oxide to form copper sulfate (reaction 7-4) .
Then hydrogen is introduced into the reactor to reduce the
sulfate to metallic copper and to generate concentrated S02
which is used for sulfur or sulfuric acid production (reaction
7-5) . The two reactors are used alternately for acceptance and
regeneration. At the beginning of the acceptance flow, copper
is oxidized by oxygen in flue gas before reacting with S02
(reaction 7-6) . Prior to the introduction of flue gas or
hydrogen, steam is introduced into the reactors to purge remain-
ing gases and to prevent explosions.
CuO + SO 2 + %02 = CuSOi* (acceptance) (7-4)
CuSO* + 2H2 = Cu + S02 + 2H20 (regeneration) (7-5)
Cu + %02 = CuO (oxidation) (7-6)
The Yokkaichi plant, Showa Yokkaichi Sekiyu (SYS),
has treated flue gas (120,000 Nm3/hr) from an oil-fired boiler
since 1973, reducing S0x from about 1,200 to 120 ppm. Since
1975 ammonia has been introduced into the reactor during the
acceptance period, to reduce N0x by using the CuO and CuSOi,
as the catalyst for the following selective reduction:
4NO + 4NH3 + 02 = 4N2 + 6H20 (7-7)
284 .
-------
Performance of the reactor is shown in Figure 7-5.2*
At the beginning of acceptance, the copper is present as a metal
which is not effective for the removal of either SOX or NOX.
Reactor outlet SOX concentration is lowered rapidly as copper
is oxidized. Ammonia is injected as the oxidation proceeds.
The S02 removal efficiency reaches a maximum in about 20
minutes and then decreases as most of CuO is converted to
CuSO.,; while NOX removal efficiency keeps increasing because
CuSOi* is a better catalyst than CuO. With an acceptance time
of about 120 minutes, the overall removal efficiency reaches
88% for SOX, and 50% for NOX with an NH3/NO mole ratio of 0.71
or 657o for NOX with a ratio, of 0.99.
The Yokkaichi plant has removed about 90% of S02 and
40% of NOX to meet local regulations. Leak ammonia present in
the treated gas is only about 1 ppm at 40% removal. Operability
of the plant has not been high but has increased recently due
to process improvements. Continuous operation has been achieved
for the period July 1977 through May 1978.
The process has a desirable feature as a dry simultan-
eous removal process although it consumes considerable amounts
of hydrogen and steam. Nearly 70% NOX removal with about 90%
S02 removal is achieved by using an NH3/NO mole ratio of 0.99.
To obtain a higher N0x removal efficiency, some extra device
may be needed. A prolonged acceptance time would increase the
N0x removal efficiency but would lower the SOX removal effi-
ciency, and the use of excessive ammonia would increase the
leak ammonia.
The process may suit flue gas with a moderate S02
concentration. An S02-rich gas would require frequent switch-
ing between acceptance and regeneration, resulting in the
285
-------
450
400 -
At reactor inlet:
Flow = 137,000 NmJ/h
S02 = 1260 ppmv
NO = 293 ppmv
Reactor bed length = 4 meter
20
40 60 80
Acceptance Time, Min
100
120
Figure 7-5. Performance of Shell FGD reactor at SYS.
Instantaneous S02 and NO slip (92).
286
-------
consumption of a large amount of hydrogen and steam and in a
decrease in NOX removal efficiency.
7.3.2 Ebara Electron Beam Radiation Process
The process has been developed by Ebara Manufacturing
Co. jointly with the Japan Atomic Energy Research Institute. It
will be tested by Nippon Steel in a pilot plant with a capacity
of treating 3,000 Nm3/hr flue gas. A flue gas at about 100°C
to which a small amount of ammonia is added is exposed to
electron beam radiation. A powdery product consisting of
ammonium nitrate and sulfat,e is formed and is caught by an
electrostatic precipitator. Over 907o of NOX is removed with
70-80% of S02 (Figure 7-6).
100
80
g 60
§
40 -
20
Intensity
(10s rad/sec)
• 4.31
A 1.46
& 8.61
O 4-31
0
1 2 3
Total beam (Mrad)
Figure 7-6. Simultaneous removal by electron
beam radiator.
287
-------
Energy consumption is claimed to be no greater than
in other simultaneous removal processes, but the investment cost
seems high. Many large electron beam generators are needed for
a large-scale plant because the electron beam has a limited
range. Another drawback of the process is the requirement of
cooling the gas to about 100°C, which is necessary because the
removal efficiency is less at 150°C, the usual flue gas tempera-
ture. The process may suit gases produced at moderate rates
that are relatively rich in NOX and low in SOz. The by-product
may be useful for fertilizer. To treat flue gas from a coal-
fired boiler, fly ash should be removed in advance to make the
by-product ammonium salts useful for fertilizer.
7.4 WET SIMULTANEOUS REMOVAL PROCESSES
7.4.1 Outline
To remove N0x by wet processes, sodium scrubbing and
magnesium scrubbing (equimolecular absorption) have been applied
in Japan in pilot and small commercial plants. These processes,
however, are not suitable for large plants because they by-
produce sodium and magnesium nitrates, which have little use.
For large-scale application, NOV should be converted
/\
to N2 or NH3. This can be achieved by using the reducing effect
of S02 in flue gas. Processes based on this principle are shown
in Table 7-4. In the oxidation reduction process, NO, which is
fairly inactive, is first oxidized to N02- It is then absorbed
in a limestone slurry containing a small amount of catalyst.
In the reduction process, NO is absorbed in a solution of a
sodium or ammonium compound containing ferrous sulfate and a
chelating compound such as EDTA (ethylenediamine tetraacetic
acid), which forms an adduct with NO to promote absorption.
288
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TABLE 7-4. MAJOR WET SIMULTANEOUS REMOVAL PROCESSES
Process
developer
Oxidizing
(Complex) Absorbent
agent (Precipitant)
By-product
Plant
capacity
(Nm3/hr)
Oxidation reduction
process
Mitsubishi H.I.
Ishikawaj ima H.I.
Sumitomo-Fuj ikasui
Reduction process
Chisso Engineering
Kureha Chemical
Asahi Chemical
03
03
C102
CaC03
CaC03
CaC03
EDTA, Fe2+ NH3
EDTA, Fe2+ CH3COONa
CaO
EDTA, Fe2+, NaOH
CaC03
Gypsum, NH3
Gypsum, N2
Gypsum, nitrate,
N2 , chloride
Gypsum, NH3, (N2)
Gypsum, N2
2,000
5,000
500
500
5,000
600
Various reactions occur in the scrubber liquor. Most
of the absorbed NOx forms an imidodisulfonate NH(S03M>2 or a
sulfamate NH2S03M (M = NH* , Na, or %Ca) by reactions (7-8),
(7-9) and (7-10).
2 NO + 5 S02 + 6MOH = 2NH(S03M)2 + M2SO.» + 2H20 (7-8)
2N0
7S02 + 10MOH = 2NH(S03M)2 + 3M2S(K + 4H20 (7-9)
NH(S03M)2 + H20 = NH2S03M + MHSO.,
(7-10)
Those equations indicate that 2.5 or 3.5 moles of SOX
are needed to each mole of NO or N02. Since a portion of S02
is oxidized by 02 in the liquor, 3.5-4.5 moles of S02 are
required to attain about 90% NOX removal.
The imododisulfonate and sulfamate are decomposed in
different ways depending on the process. In the Mitsubishi
Chisso, and Kureha processes, NH3 or (MU),SO, is produced by
289
-------
reactions (7-10) to (7-13), while in the Asahi and Ishikawajima
processes, N2 is formed by reactions (7-14) and (7-15).
NH2S03M + MHSCU + H20 = NH^HSCK + M2SOn (7-11)
NH»HSO» + NH3 = (NHOaSCH (7-12)
ITCUHSO., + CaO = CaSO., + NH3 + H20 (7-13)
2NH(S03M)2 + %02 heat*2M2S(K + 2S02 + N2 + H20 (7-14)
2NH2S03M + 2M(OH)2 + 02 heat»N2 + 2M2SCK + 4H20 (7-15)
7.4.2 Oxidation Reduction Process
A simplified flowsheet of the Mitsubishi (MHI) and
Ishikawajima (IHI) processes is shown in Figure 7-7. Flue gas
to which ozone is added is treated in a system similar to the
wet FGD system by a limestone slurry containing catalysts
(small amounts of NaCL and CuCl2 in the IHI process) . 5 By
using 1 mole ozone to 1 mole NO, about 907» of NOX is removed
together with over 95% of S02 . An oxidation step of calcium
sulfite is virtually unneeded because of the oxidizing effect
of N02 . A portion of the liquor from a gypsum centrifuge
containing calcium imidodisulfonate and sulfamate, which are
both water-soluble, is treated in different ways. In the MHI
process, the compounds are hydralized to ammonium bisulfate,
which is treated with lime to produce NH3 and gypsum (reactions
(7-10), (7-11), and (7-13)), while by the IHI process the liquor
is evaporated and the solids are calcined to produce calcium
sulfate and N2 (reaction 7-15) . IHI also has a process to by-
product NH3 in a way similar to that of MHI. Details of the
processes are available in published literature.25'27
290
-------
r
H20 I *
PRESCRUBBER
FLUE GAS 2 -*
CLEANED GAS
SCRUBBER
Ni
VO
CENTRIFUGE
CiC03
Figure 7-7. Simplified flow sheet of wet-limestone simultaneous
removal process (oxidation reduction process).
-------
The overall reactions of the two processes may be
simply expressed by equations (7-16) and (7-17).
2N02 + 7S02 + 7CaO + 3H20 = 7CaSCU + 2NH3 (7-16)
2N02 + 5S02 + 5CaO + %02 = SCaSCU + N2 (7-17)
The equimolar proportion of ozone to NO required to
achieve 90% removal results in the formation of a small amount
of nitrate which would accumulate in the liquor. For 80% NOX
removal, less ozone is used and the nitrate formation is vir-
tually avoided.
A great advantage of the processes is that they can be
carried out in conventional wet lime/limestone scrubbing plants
by adding a small liquor treatment system. On the other hand,
a major drawback is the consumption of ozone. For flue gas
containing more than 200 ppm NO, ozone oxidation is too expen-
sive. The ammonia by-production process may be useful for flue
gas from coal if the NO content is reduced to 250 ppm by com-
bustion modification and to 150 ppm by injecting the by-product
NH3 into the boiler.
Sumitomo Metal jointly with Fujikasui has developed a
process that uses C102, which is less expensive than ozone. By
that process, about half of NOX in the gas is converted to N2
while the rest goes into a scrubber liquor as calcium nitrate.
In addition, the liquor contains a considerable amount of cal-
cium chloride. The process may be useful if the by-product
liquor, a mixture of calcium chloride and nitrate, can be used.
One possible use is as an antifreeze agent for roads (the freez-
ing point of water is substantially lowered by the calcium
salts). Otherwise, the liquor may be treated with ammonium
292
-------
sulfate to precipitate gypsum and to recover ammonium chloride
and nitrate liquors which may be used as fertilizer.
Both investment and operation costs are roughly esti-
mated at 40% more than FGD only for flue gas containing 150-200
ppm NOX.
7.4.3 Reduction Processes
Reduction processes (Chisso, Kureha and Asahi) use a
sulfite solution containing ferrous ion and EDTA, which promote
the absorption of NO by forming an adduct. EDTA is fairly
expensive (about $3,000/metric ton) but is consumed in a very
small amount. It is often used for wastewater treatment and
does not affect the environment. A small portion of the
absorbed NO may be converted to N2 by reaction (7-18) shown
below, but a major portion forms an imidodisulfonate. A large
portion of absorbed S02 forms a dithionate, (NHt,)2S206 or
Na2S206, by the effect of ferrous ion and EDTA. Therefore, a
decomposition step of those compounds is needed in addition to
a standard FGD process.
The Chisso process uses ammonia scrubbing while the
Kureha process uses a sodium acetate-lime double alkali system.
In those processes imidodisulfonate and dithionate undergo
hydrolysis at 120-140°C under pressure to form a bisulfate and
sulfate by reactions (7-10), (7-11). (7-19) and (7-20). The
overall reactions of the Chisso and Kureha processes may be
expressed by equations (7-21) and (7-22), respectively.
Fe - EDTA NO + SOs2' >Fe EDTA + SO*2' + %2N2 (7-18)
M2S206 + H20 + %02 = 2MHSO, (7
293
-------
M2S206 MzSCU + S02 (7-20)
2NO + 5S02 + 8NH3 + 8H20 = 5(NH^)2SO^ (7-21)
2NO + 5S02 -I- 5CaO + 3H20 = SCaSO^ + 2NH3 (7-22)
(M = Na+, NH +, or '~ "^
A simplified flow sheet of the Chisso process is shown
in Figure 7-8. SOX and NOX are absorbed in an ammonia liquor
containing EDTA and ferrous ion at pH 6. Since a considerable
portion of EDTA would be decomposed at the above-mentioned
hydrolysis (decomposition) step, most of the EDTA is separated
ahead of this step. Separation is achieved by crystallization
by cooling in an acidic liquor. This catalyst recovery step
reduces the EDTA consumption but makes the process complex.
A simplified flow sheet of the Kureha process is shown
in Figure 7-9. The process uses sodium acetate scrubbing and
gypsum is precipitated from the liquor by lime addition.
Ammonia formed by the hydrolysis is stripped by lime addition
and is either recovered or decomposed. The process has no EDTA
recovery step as does the Chisso process. A considerable amount
of EDTA, therefore, may be decomposed at the hydrolysis step.
The Asahi process is a combination of a sodium-
limestone FGD process and thermal decomposition of imidodisul-
fonate and dithionate (reactions (7-14) and (7-20)). S02 re-
leased by the decomposition is used to decompose Na2SOi» to
NaHS03 and CaSOi* in the same manner as in the above FGD process.
The by-products of the Asahi process are gypsum and N2 with a
small amount of Na2S04.
294
-------
VO
TO STACK
SO,
1 1
SCRUBBER
«
HjSO.,
OXIDATION
CATALYST
RECOVERY
RECVCLED CATALYST
DECOMPOSITION
NEUTRALIZATION
CRYSTALLIZATION
I
WH4)2S04
PRESCRUBBER
FLUE GAS•£-— |
J L
Figure 7-8. Flow sheet of Chisso process (CEC process)
-------
CLEAN GAS
4
Ca(OH),
AIRfc-
PROCESS WATER fc •>
to
VO
ACETIC
ACID
RECOVERY
SOj&NO.
SCRUBBER
GYPSUM REACTOR
1 FLUE GAS
CENTRIFUGE
r?1
'PSUM T
HYDROLYSIS
GYPSUM
Figure 7-9. Flow sheet of Kureha process.
-------
These reduction processes do not require an oxidizing
agent and may suit N0x-rich gases provided that more than about
4 moles of S02 are contained for each mole of NO for flue gas
containing less than 4% 02. With a higher 02 concentration, a
larger S02/N0x mole ratio will be required in order to attain a
high NOX removal ratio. Since the absorption of NO occurs
slowly and its solubility is small, the scrubber requires many
stages with a heavy pressure drop and a large L/G ratio.
Although 90% NOX removal can be attained, 70-80% removal may be
a more practical target. The costs of the investment as well
as the operation are roughly estimated at 50% more than those
for FGD only.
/
7.5 SUMMARY - APPLICABILITY OF SIMULTANEOUS REMOVAL PROCESSES
Relationships of SOX and NOX concentrations in gas to
suitable processes for treatment are illustrated in Figure 7-10.
Wet simultaneous removal processes suit a gas rich in S02 and
relatively low in NOx because an S02 /NOX mole ratio of over 4
is required to achieve 90% NOX removal. Moreover, equipment
required to convert FGD units for NOX removal are smaller and
less costly with a low NOX concentration. Application of the
oxidation-reduction process may be limited to gases containing
less than 200 ppm of NO because of the cost of the oxidizing
agent. Reduction processes should be used for gases with
relatively high NOX concentrations. Although 90% NOX removal
can be achieved by the wet processes, 70-80% removal may be more
practical. Ninety percent removal requires a large L/G ratio
or an excessive amount of oxidizing agent, which tends to form
a hard-to-treat nitrate.
On the other hand, dry simultaneous processes suit
gases with a relatively small SOX/NOX ratio for the following
reasons:
297
-------
1) For the carbon process, carbon consumption
increases with SOX concentration.
2) For the electron beam process, SOX removal
is much more difficult than NOX removal.
3) For the Shell process, a high SOX concentration
increases hydrogen and steam consumption and
tends to lower NOX removal efficiency.
600
1
a.
400
200
i
SCR
SNR
SCR + FGD or
Dry simultaneous/removal
Metal oxides
o>
,0
g C
.0 O
CO 4J
o u
0)
SCR + FGD or
Wet simultaneous removal
Reduction
Oxidation reduction
FGD
500 1000 1500 2000
SO (mainly S02) (ppm)
2500
3000
Figure 7-10. Gas composition and suitable processes.
(SCR: Selective catalytic reduction)
(SNR: Selective non-catalytic reduction)
298
-------
Use of the carbon and electron beam processes may be
restricted to gases containing less than about 500 ppm SOX.
For the Shell process, 70-8070 NOX removal may be a practical
limit unless a special device is used, while for the electron
beam process, 70-8070 removal may be a practical limit for SOX.
All of the simultaneous removal processes would
require further tests and improvements before they become
commercially applicable.
299
-------
REFERENCES
Descriptions in this report are based primarily on Dr.
Ando's visits to the FGD and denitrification plants, his dis-
cussions with the users and developers of each process, and
data made available by them. In addition, the following pub-
lications were used as references (the publications are writ-
ten in English unless otherwise noted).
1. Japan's Sunshine Project, Sunshine Project Promotion
Headquarters, Agency of Industrial Science and Technology,
MITI (July, 1977).
2. J. Ando, Fundamental Problems of Sulfur Oxides and Flue
Gas Desulfurication, Industrial Pollution Control
Vol. 12 (September, 1976). (in Japanese).
3. A. P. Altschuller, Regional Transport and Transformation
of Sulfur Dioxide to Sulfates in the U.S., J. Air Pollution
Control Assoc. 26, 318-324 (April, 1976).
4. Trends of Pollution Control Investment by Private Companies,
Industrial Pollution Control Assoc. of Japan (December,
1977). (in Japanese).
5. M. Shimane, New Desulfurization Technology and Residual
Oil. Mol, 30-36 (October, 1977). (in Japanese).
300
-------
6. S. Gomi, R. Takahashi, et al., Thermal Cracking of
Residual Oils Using Superheated Steam and Application of
the Products, Proceedings of 9th World Petroleum Congress
(1975).
7. T. Mori, Cherry-P Process, 2nd PACHEC Meeting, (Denver,
Colorado, August, 1977).
8. Japan's Sunshine Project, Summary of Coal Gasification and
Liquefaction, Sunshine Project Promotion Headquarters,
Agency of Industrial Science and Technology, MITI (August,
1977).
9 . Y. Sudo, et al. , Commercialization Study of Gas Heater
for Wet Sodium Gypsum Process FGD, Karyoku Genshiryoku
Hatsuden, 535-545, Vol. 28, No. 6 (June, 1977). (in
Japanese).
10. J. Ando and G. A. Isaacs, S02 Abatement for Stationary
Sources in Japan, Contract No. 21ACX-130, US EPA (January,
1976).
11. 0. W. Hargrove, Jr., and W. E. Corbett, Results of EPA-
Sponsored Characterization Tests of Louisville Gas and
Electric's Paddy's Run Flue Gas Desulfurization System,
PACHEC 1977 (Denver, Colorado, August, 1977).
12. M. Miyajima, Flue Gas Desulfurization Plant at Owase-Mita
Power Station, EPA-JMA Forum, Hollywood, Florida (November,
1977).
13. Y. Takehana, Flue Gas Desulfurization Plant at Owase-Mita
Power Station, Hikari to Netsu, 11-15, Vol. 27, No. 8
(August, 1976). (in Japanese).
301
-------
14. H. W. Elder, F. T. Princiotta, G. A. Hollinden and
S. J. Gage, Sulfur Dioxide Control Technology, Visits in
Japan, Interagency Technical Committee (August, 1972).
15. J. Sakanishi and R. H. Quig, One Year's Performance and
Operability of the Chemico/Mitsui Carbide Sludge (Lime)
Additive S02 Scrubbing System, Proceedings of EPA FGD
Symposium - 1973 (December, 1973).
16. J. Ando and B. A. Laseke, S02 Abatement for Stationary
Sources in Japan, EPA 600/7-77-103a (September, 1977).
17 H. Idemura, T. Kanai and H. Yanagioka, Jet Bubbling Flue
Gas Desulfurization Process, Proceedings of PACHEC Sym-
posium (Denver, Colorado, August, 1977).
18. D. D. Clasen and H. Idemura, Limestone/Gypsum Jet Bubbling
Scrubbing System, EPA FGD Symposium (November, 1977).
19. M. Noguchi, Status Report on Chiyoda Thoroughbred 101
Process, Proceedings of EPA FGD Symposium Vol. II (November,
1974).
20. Y. Yamamichi and J. Nagao, Dowa's Basic Aluminum Sulfate-
Gypsum Flue Gas Desulfurization Process, EPA FGD Symposium
(March, 1976).
21. J. B. Pohlenz, The Shell Flue Gas Desulfurization Process,
EPA FGD Symposium (November, 1974).
22. N. Ninomiya, Simultaneous Removal of NOV and S02 by Acti-
X
vated Carbon, Report of Takeda Chemical (1975). (in Jap-
anese) .
302
-------
23. M. Seki, et al. , Ammonium Halide Activated Carbon Catalyst
to Decompose N0x in Stack Gas at Low Temperatures Around
100°C, American Chemical Society, Chicago (August, 1975).
24. F. M. Nooy and J. B. Pohlenz, Nitrogen Oxides Reduction
with the Shell Flue Gas Desulfurization Process, Proceed-
ings of PACHEC Symposium (Denver, Colorado, August, 1977).
25. J. Ando, H. Tohata, K. Nagata and B. A. Laseke, NCv Abate-
X
ment for Stationary Sources in Japan, EPA 600/7-77-1036,
(September, 1977).
26. K. Sawai and T. Gorai, Simultaneous Removal of S02 and
NO from Stack Gas by Scrubbing (CEC Process) Proceedings
X
of PACHEC Symposium (Denver, Colorado, August, 1977).
27. H. L. Faucett, J. D. Maxwell, and T. A. Burnett, Technical
Assessment of NC- Removal Processes for Utility Application,
X
EPA 600/7-77-127 (November, 1977).
28. W. Kawakami and K. Kawamura, Treatment of Oil-fired Flue
Gas by Electron Beam, Denkikyokai Zasshi, 29 (December,
1973) . (in Japanese).
303
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-210
2.
4. TITLE AND SUBTITLE
SO2 Abatement for Stationary Sources in Japan
7. AUTHOR(S)
Jumpei Ando
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Chuo University
Tokyo
Japan
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
November 1978
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO
10. PROGRAM ELEMENT NO.
1NE624
11. CONTRACT/GRANT NO.
68-02-2161
13. TYPE OF REPORT AND PERIOD COVERED
Final: 9/77 - 10/78
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES JERL-RTP project officer is J. David Mobley, Mail Drop 61, 919/
541-2915.
*
16. ABSTRACT The Tep()rt g^g reSUltS Of B. Stud
late SOx emissions: the efforts were prom pi
Japan during the 1960s. Several technologies
of low sulfur gas from coal, fuel desulfurizj
ever, predominant methods currently used :
sulfur fuels and flue gas desulfurization (FC
technology in Japan has preceded similar de
in a significant reduction in ambient SO2 lev
standard of 0. 014 ppm has almost been achi<
currently in use in Japan, including wet Urn
limestone, regenerable, and simultaneous 1
operated satisfactorily on a commercial scs
typically over 90%. Removals and operabilii
costs.
17.
y of Japanese
ced by seriou
5 are being d
ition, and flu
IOT SO2 contr
JD). Develop]
svelopment in
re Is. The sir
sved. Severa
e /limestone ,
*Ox/SOx. Th
lie. Both SOS
ties of 98-99(
5 government efforts to regu-
s air pollution problems in
eve loped including production
lidized bed combustion. How-
•ol in Japan are burning low
nient and application of FGD
L other countries , resulting
ingent, daily average ambient
1 types of FGD systems are
indirect and modified lime/
ese processes have been
. removal and operability are
Jo can be achieved at higher
KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Air Pollution Limestone
Sulfur Oxides Coal Gasification
Flue Gases Fossil Fuels
Desulfurization Combustion
Scrubbers Fluidized Bed Pro-
Calcium Oxides ceasing
Nitroeen Oxides
18. DISTRIBUTION STATEMENT
Unlimited
b.lDENTIFIERS/OPEN ENDED TERMS C. COSAT I Field/Group
Air Pollution Control 13B 08G
Stationary Sources 07B 13H
Flue Gas Desulfurization 2 IB 2 ID
Lime 07A,07D
Japan 131
19. SECURITY CLASS (This Report) 21. NO. OF PAGES
Unclassified 328
20. SECURITY CLASS (This page) 22. PRICE
Unclassified
EPA Form 2220-1 (9-73)
304
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