U.S. Environmental Protection Agency Industrial Environmental Research EPA~600/7~77~103d
Off ice of Research and Development Laboratory M * 4 077
Research Triangle Park, North Carolina 27711 September 1977
SO2 ABATEMENT
FOR STATIONARY SOURC
IN JAPAN
Interagency
Energy-Environment
Research and Development
Program Report
-------
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 ENVIRONMENTAL PROTECTION TECH-
NOLOGY series. This series describes research performed to develop and dem-
onstrate instrumentation, equipment, and methodology to repair or prevent en-
vironmental degradation from point and non-point sources of pollution. This work
provides the new or improved technology required for the control and treatment
of pollution sources to meet environmental quality standards.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161,
-------
EPA-600/7-77-103a
September 1977
SO2 ABATEMENT
FOR STATIONARY SOURCES
IN JAPAN
by
Jumpei Ando and B.A. Laseke
PEDCo. Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-01-4147
Task No. 3
Program Element No. EHE624
EPA Project Officer: J. David Mobley
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
-------
FOREWORD
This report describes the status in Japan of technology
for desulfurization of flue gases and for simultaneous
removal of sulfur dioxide and nitrogen oxides from flue gas
streams. The information is current through May 1976. The
total capacity for flue gas desulfurization in Japan has
reached 70 million normal cubic meters per hour (23,000
megawatt equivalent) and is expected to exceed 100 million
cubic meters per hour (33,000 megawatt equivalent) by the
end of 1977.
Ambient concentrations of sulfur dioxide in Japan have
decreased markedly as a result of the desulfurization
efforts by industry and the increasing use of low-sulfur
fuels. The need for control of nitrogen oxides, however,
has increased; efforts are being concentrated, therefore, on
developing technologies for the simultaneous control of both
classes of pollutants.
Section 1 of the report describes fuel use patterns in
Japan, ambient concentrations of pollutants, and the current
emission regulations.
Section 2 reviews the status of hydrodesulfurization
of heavy oil, asphalt decomposition, and coal gasification
111
-------
with emphasis on the new technology of asphalt decomposi-
tion to supply low-sulfur fuels.
Section 3 analyzes the status of flue gas desulfuriza-
tion, including the major technical problems, trends, and
economics.
Sections 4 and 5 describe in detail the applications of
desulfurization technology by power companies and steel
producers and the performance of new systems.
Sections 6 and 7 describe advanced processes for flue
gas desulfurization and for simultaneous removal of the
sulfur and nitrogen oxides.
Section 8 provides a comparative evaluation of advanced
flue gas cleaning technologies in the United States and
Japan.
-------
REMARKS '
The metric system is used in this report. Some of the
conversion figures between the metric and English systems
and abbreviations are shown below:
1 m (meter) = 3.3 feet
1 m (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) =6.29 barrels
The capacity of S00 and NO removal plants is expressed
£ X.
in Nm /hr (normal cubic meters per hour).
1 Nm /hr = 0.59 standard cubic foot per minute
About 3,000 Nm /hr is equivalent to 1 megawatt.
L/G ratio (liquid/gas ratio) is expressed in liters/Nm .
1 liter/Nm =7.4 gallons/1,000 standard cubic feet.
For monetary conversions, the exchange rate of 1 dollar =
300 yen is used.
SO, and NO removal costs are expressed in $/kl oil.
• Jt
$l/kl oil is equivalent to about 0.21 mil/kWh.
One liter heavy oil gives nearly 10,000 kcal (kilo-
calories) .
v
-------
1 kcal =3.97 Btu.
Operability and availability, as referred to in the
text, are defined as follows:
Operability (index): The number of hours the FGD
system operated divided by the boiler operating hours
in the period, expressed as a percentage.
Availability (index): The number of hours the FGD
system was available for operation (whether operated or
not) divided by hours in the period, expressed as a
percentage.
ABBREVIATIONS
BPSD Barrels per stream day
FGD Flue gas desulfurization
HDS Hydrodesulfurization
kW Kilowatts
L/G Liquid/gas ratio (see above)
MW., Megawatts
Nm /hr Normal cubic meters per hour (see above)
VI
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TABLE OF CONTENTS
Page
FORWARD ii
CONVERSION FACTORS AND ABBREVIATIONS iv
LIST OF FIGURES ix
LIST OF TABLES xii
LIST OF PHOTOS XV
1. FUEL USAGE AND REGULATIONS ON SO AND NO 1-1
x x
Supply and Usage of Energy 1-1
Emission and Regulation of SO 1-6
ji
Total Mass Regulation of SO 1-11
Ji
Pollution-Related Health Damage Compensation 1-15
Law
Emission and Regulation of NO 1-18
Jt
2. HYDRODESULFURIZATION AND DECOMPOSITION OF OIL 2-1
AND GASIFICATION DESULFURIZATION
Status of Hydrodesulfurization (HDS) 2-1
Residual Oil Decomposition ahd Coal 2-4
Gasification
3. GENERAL ASPECTS OF FLUE GAS DESULFURIZATION 3-1
(FGD)
Trends 3-1
Major Processes and Systems 3-2
Wet Lime/Limestone Process 3-3
VI1
-------
TABLE OF CONTENTS (continued)
Page
Indirect Lime/Limestone Process 3-12
Other Processes (Recovery Processes) 3-16
By-Products of FGD 3-21
Wastewater and Gas Reheating 3-26
Economic Aspects of FGD Systems 3-30
4. MAJOR NEW FGD SYSTEMS FOR UTILITY BOILERS 4-1
Status of FGD by Power Companies 4-1
Plants Using the MHI Lime-Gypsum Process 4-6
(Mitsubishi-JECCO Process)
Mitsui-Chemico Limestone Gypsum Process at the 4-13
Takasago Plant, Electric Power Development Co.
Babcock-Hitachi Process at the Tamashima Plant, 4-17
Chugoku Electric
Kureha-Kawasaki Sodium-Limestone Process at the 4-23
Sakaide Plant, Shikoku Electric
Chiyoda Process at the Fukui Plant, Hokuriku 4-29
Electric
5. FLUE GAS DESULFURIZATION IN THE STEEL INDUSTRY 5-1
Introduction 5-1
MHI Process at the Mizushima Plant, Kawasaki 5-3
Steel
FGD Systems of Sumitomo Metal (Moretana Process) 5-7
Kobe Steel Calcium Chloride Process 5-13
Nippon Steel Slag Process (SSD Process) 5-17
6. NEW FGD PROCESSES 6-1
Status of New Developments 6-1
Kawasaki Magnesium-Gypsum Process 6-2
Vlll
-------
TABLE OF CONTENTS (continued)
MKK Lime-Gypsum Process Using Jet Scrubber 6-5
Dowa Aluminum Sulfate Process 6-6
Kurabo Ammonium Sulfate-Lime Process 6-15
Kureha Sodium Acetate Process 6-18
Mitsui-Chemico Magnesium Process 6-20
Hitachi-Unitika Activated Carbon Process 6-23
7. SIMULTANEOUS REMOVAL OF SO- AND NO 7-1
2 x
Outline 7-1
Chemistry and Problems of Wet Processes 7-4
Oxidation Reduction Processes 7-7
Reduction Processes 7-13
Dry Processes for Simultaneous Removal 7-25
8. COMPARATIVE EVALUATION 8-1
Differences Affecting Process Applications in the 8-1
United States and Japan
Wet Lime /Lime stone Process 8-2
Indirect Lime/Limestone Process 8-7
Other Processes (Recovery Processes) 8-9
By-Products and Wastewater 8-10
Simultaneous Removal of SO and NO 8-13
IX
-------
LIST OF FIGURES
Figure Page
1-1 Yearly Average SC>2 Concentration in 15 1-2
Major Cities and Industrial Districts
1-2 SC>2 Concentration in Kanagwa Prefecturs 1-16
(Yearly Average in 1973 and 1977, PPM)
1-3 Increase of the Designated Patients 1-17
2-1 Flowsheet of Eureka Process 2-8
2-2 Material Balance for Residual Oil Decom- 2-12
position Using Flexcoking Process
2-3 Flowsheet of Cherry Process 2-12
3-1 Schematic Flowsheet of Wet Lime/Limestone 3-9
Gypsum Process
3-2 Production Capacity of Desulfurization 3-22
3-3 Price of By-Products 3-22
3-4 Demand for and Supply of Gypsum in Japan 3-23
3-5 FGD Capacity and Amount of Wastewater6 3-28
3-6 Concentration of 0» and CL~ in Solution 3-28
and Stress Corrosion
4-1 One-Absorber System of MHI Process 4-7
4-2 Operation Data for Karita Plant, Kyushu 4-11
Electric
4-3 Water Balance (Karita Plant, MHI Process) 4-12
4-4 Flowsheet of Mitsui-Chimico Process 4-14
x
-------
LIST OF FIGURES (continued)
Figure Page
4-5 Purge Water and Chloride Concentration 4-18
4-6 Flowsheet of Babcock-Hitachi Process 4-19
4-7 Relationship of pH of Slurry in Reactor 4-24
to Solid Composition After Oxidation
4-8 Flowsheet of Kureha-Kawasaki Process 4-25
4-9 Flowsheet of Chiyoda Process 4-30
5-1 Performance of FGD Plant for No. 4 5-5
Sintering Machine
5-2 Flowsheet of Moretana Process (Kashima 5-8
Plant, Sumitomo Metal)
5-3 Operation Data of No. 1 Train, Kashima 5-11
Plant
5-4 Flowsheet of Cal Process 5-14
5-5 Flowsheet of SSD Process 5-18
6-1 Flowsheet of Kawasaki Magnesium-Gypsum 6-3
Process
6-2 Dimensions of Jet Scrubber (MM) 6-7
(120,000 Nm3/hr)
6-3 Flowsheet of MKK Jet-Scrubber Process 6-8
(Naoshima Plant)
6-4 Flowsheet of Dowa Aluminum Sulfate- 6-9
Limestone Process
6-5 Solubility Curves of SO- in BAS Solution 6-11
6-6 Solubility Curves of SO- at Various Tempera- 6-11
tures of the Solution
6-7 Soluble Range of Aluminum Compound 6-11
6-8 Relationship of Al Loss to Concentration 6-11
of Solution
XI
-------
LIST OF FIGURES (continued)
Figure Page
6-9 Operation Data of Tamano Plant, Naikai 6-14
6-10 Flowsheet of Kurabo Ammonium Sulfate- 6-16
Lime Process
6-11 Flowsheet of Kureha Sodium Acetate-Lime/ 6-19
Limestone Process
6-12 Flowsheet of Chemico-Mitsui Magnesium 6-21
Process
7-1 Models of Combination of FGD and 7-2
Denitrification
7-2 Simplified Flowsheet of Moretana Simul- 7-8
taneous Removal Process
7-3 MHI Simultaneous Removal Process 7-9
7-4 Schematic Flowsheet of IHI Simultaneous 7-11
Removal Process
7-5 Flowsheet of Kureha Simultaneous Removal 7-17
Process
7-6 Flowsheet of Mitsui Shipbuilding Process 7-17
7-7 Flowsheet of CEC Process 7-19
7-8 Flowsheet of Asahi Chemical Reduction 7-21
Process
7-9 Flowsheet of Kawasaki Magnesium Process 7-24
7-10 Schematic Diagram of S02 and NOx Removal 7-26
By Activated Carbon at Different Tempera-
tures and Space Velocities
7-11 Flowsheet of Unitika Process 7-28
XII
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LIST OF TABLES
Table page
1-1 Supplies of Primary Energies in Japan 1-2
1-2 Power Generation Capacity 1-3
1-3 Power Generated 1-3
1-4 Domestic Demand For Heavy Oil 1-4
1-5 Consumption of Fuels By Power Companies 1-4
1-6 Cost of Fuels For Power Plants 1-5
1-7 Planned Imports of Liquefied Natural Gas 1-7
1-8 Long Term Energy Supply Plan 1-8
1-9 Ambient Air Quality Standards 1-9
1-10 Values of K Applicable To Locations In Japan 1-10
1-11 Relation of K Value To Maximum Ground-level 1-10
Concentration of SO«
^
1-12 Allowable Sulfur Content of Oil - 1-14
Existing and New Plants
1-13 NO Emission Standards 1-19
J\.
2-1 Hydrodesulfurization Systems Built by 1971 2-2
2-2 Hydrodesulfurization Systems Completed 2-3
Between 1972 and 1976
2-3 Amount of Sulfur Recovered by HDS and FGD 2-5
2-4 Approximate Costs For HDS and FGD at 2-5
Various Desulfurization Efficiencies
2-5 Typical Product Patterns 2-9
Xlll
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LIST OF TABLES (continued)
Table Page
2-6 Economic Balance of Residual Oil Cracking 2-11
Process
3-1 Numbers and Capacities of FGD Systems 3-4
Expected to be Operational by End of 1977
3-2 Wet Lime/Limestone Process Units by MHI 3-5
Process
3-3 Wet Lime/Limestone Process Units Using 3-6
Scrubbers Developed in the United States
3-4 Wet Lime/Limestone Process Units Using 3-7
Other Processes
3-5 Example of Operation Parameters of FGD 3-10
Plants By-Producing Gypsum and Calcium
Sulfite
3-6 Indirect Lime/Limestone Process Installa- 3-13
tions
3-7 FGD Installations By-Producing H_SO., S 3-18
and (NH )2SO4
3-8 Wastewater From FGD Systems 3-27
3-9 Plant Cost In Battery Limits ($1 = ¥300) 3-31
3-10 Examples of FGD Cost With Wet Lime-Gypsum 3-33
Process
4-1 Capacities of Steam Power Generation and 4-2
FGD of Power Companies
4-2 FGD Systems of Power Companies 4-4
4-3 Requirements at the Karita Plant 4-8
4-4 Main Equipment at Takasago Plant 4-16
4-5 Composition of Limestone 4-21
xiv
-------
LIST OF TABLES (continued)
Table Page
5-1 S02 Removal Installation For Waste Gas 5-2
From Iron-Ore Sintering Machines
5-2 Equipment Dimensions, FGD System At 5-10
Kashima Plant
7-1 Processes For Simultaneous Removal of 7-3
SO0 and NO
2 x
xv
-------
LIST OF PHOTOS
Photos Page
2-1 Sodegaura Plant, Eureka 2-8
3-1 Handling of By-Product Gypsum (Chiba 3-23
Plant, Showa Denko)
3-2 Calcium Sulfite Sludge Disposal (Omuta 3-25
Plant, Mitsui Aluminum)
4-1 Karita Plant, Kyusha Electric (188 MW) 4-9
4-2 Owase Plant, Chubu Electric (2 Units Each 4-9
375 MW)
4-3 Takasago Plant, EPDC (250 MW) (Scrubber 4-15
and Reactors)
4-4 Takasago Plant, EPDC (250 MW) (Gypsum 4-15
Centrifuge and Storage)
4-5 Tamashima Plant, Chugoku Electric (500 MW) 4-20
4-6 Tamashima Plant, Chugoku Electric (500 MW) 4-20
4-7 Sakaide Plant, Shikoku Electric (450 MW) 4-26
(Two Scrubbers in Parallel)
4-8 Sakaide Plant, Shikoku Electric (450 MW) 4-26
(Oxidizers and Stripper)
4-9 Fukui Plant, Hokurikii Electric (350 MW) 4-32
4-10 Fukui Plant, Hokuriku Electric (350 MW) 4-32
5-1 Wakayama Plant, Sumitomo Metal 5^12
xvi
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LIST OF PHOTOS (continued)
Photos Page
6-1 Chiba Plant, Idemitsu Kosan (170 MW 6-22
Equivalent, Scrubber and Kiln)
6-2 Chiba Plant, Idemitsu Kosan 6-22
XVI1
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1. FUEL USAGE AND REGULATIONS ON SO AND NO
X X
SUPPLY AND USAGE OF ENERGY
The energy supply in Japan, after continuously growing
at a yearly rate of more than 10 percent, has leveled off
since 1974 because of economic depression caused by the
international crisis in marketing of oil (Table 1-1).
Supplies of imported oil, which accounts for more than 70
percent of Japan's total energy, decreased in 1974. Pro-
duction of electric power in 1974 was slightly less than
that in 1973, although the generating capacity increased
(Tables 1-2 and 1-3).
Consumption of heavy oil, the major fuel in Japan, also
decreased in 1974. Use of high-sulfur heavy oil (grade C)
decreased markedly, whereas use of low-sulfur heavy oil
(grade A) increased slightly (Table 1-4). Consumption of
heavy oil by power companies also dropped, but use of
sulfur-free fuels such as naphtha and LNG (liquefied natural
gas) increased (Table 1-5). The average sulfur content of
oils consumed by power companies decreased from 1.5 percent
in 1970 to 0.54 percent in 1974. The price difference
between low-sulfur and high-sulfur oils was about $30/kl in
1974 and $25/kl in 1976 (Table 1-6).
1-1
-------
Table 1-1. SUPPLIES OF PRIMARY ENERGIES IN JAPAN
Hydroelectric power, 10 MWhr
Atomic power, 10 MWhr
Coal, 106 t
Domestic
Imported
Oil, 106 kl
Domestic
Imported
9 3
Natural gas, 10 m
LNG, 106 t
Other, 10 kcal
Total, 1013 kcal
1970
80.0
4.5
40.8
50.9
0.9
234.1
2.8
0.9
1.0
310.4
1971
86.8
8.Q
33.8
46.5
0.9
248.7
2.9
1.0
1.4
320.6
1972
87.9
9.5
28.1
50.5
0.8
275.7
2.9
1.0
1.2
344.3
1973
71.6
9.7
21.7
58.0
0.8
318.6
2.9
2.3
0.6
382.5
1974
84.8
19.7
21.4
64.6
0.8
305.8
2.8
2.8
1.0
383.5
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Table 1-2. POWER GENERATION CAPACITY
(1,000 MW)1
Hydro
Thermal
Atomic
Total
1970
20.0
47.0
1.3
68.3
1971
20.1
54.9
1.3
76.3
1972
20.7
62.7
1.8
85.2
1973
22.6
70.6
2.3
95.5
1974
23.5
76.9
3.9
104.2
Table 1-3. POWER GENERATED
(106 MWhr)
Hydroelectric
Thermal
Atomic
Total
1970
80.1
274.8
4.6
359.5
1971
86.8
290.8
8.0
385.6
1972
87.9
331.1
9.5
428.5
1973
71.6
388.8
9.7
470.1
1974
84.8
354.6
19.7
459.0
1-3
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Table 1-4. DOMESTIC DEMAND FOR HEAVY OIL
(106 kl)
Grade A (3=0.1-1. 0)
Grade B (3=0.3-2. 5)
Grade C (3=0.5-4. 0)
Total
1970
11.1
12.7
90.0
113.8
1971
13.3
12.7
92.4
118.4
1972
16.2
12.9
95.6
124.7
1973
19.3
12.8
105.0
137.1
1974
19.6
11.9
86.6
118.1
Table 1-5. CONSUMPTION OF FUELS BY POWER COMPANIES1
Coal, 106 t
Heavy oil, 106 kl
Crude oil, 106 kl
Naphtha, 106 kl
LNG, 106 t
Natural gas, 106 Nm3
Blast furnace and
coke oven gases,
105 Nm3
Average sulfur content,
of oil, %
1970
18.8
34.5
7.2
0
0.7
0.07
15,6
1.50
1971
13.9
35.3
11.0
0
0.7
0.13
18.1
1.31
1972
10.7
38.1
17.8
0.2
0.6
0.17
22.9
1.03
1973
8.3
42.8
23.6
2.2
1.4
0.22
32.4
1.75
1974
7.3
34.7
23.0
3.5
2.5
0.24
32.4
0.54
1-4
-------
Table 1-6. COST OF FUELS FOR POWER PLANTS
Fuel
Naphtha
Crude oil
Heavy oil
Heavy oil
Heavy oil
Coal
s, %
0.02
0.3
0.3
1.6
3.0
1-2.5
1974
$/kl (t)
86-90
88-92
72-75
59-61
(19-29)
jzf/M Btu
210-220
220-230
180-188
148-153
108-133
1976
$/kl (1)
110-115
96-100
97-100
80-84
72-75
)Z
-------
Domestic coal has been used for fuel. Although coal is
cheaper than oil, as shown in Table 1-6, consumption will
not increase because of the limited capacity of domestic
coal mines. So far, all of the coal imported to Japan has
been used for coke production for the steel industry.
Importing of coal for fuel is expected to start in a year or
two and to increase. In recent years, great efforts have
been made to increase the imports of LNG because it causes
no emissions of SO and lower emissions of NO than other
x x
fuels. Many contracts are under way with several countries
(Table 1-7). There is considerable uncertainty with respect
to the amount and the costs of LNG to be imported.
It is expected that the Japanese economy will recover
by the end of 1976 and will gain strength slowly, with
energy consumption increasing at a rate of 5 to 6 percent
yearly (Table 1-8).
EMISSION AND REGULATION OF SO
x
Japan today depends upon imported crude oil for more
than 70 percent of its total energy supply. In 1974 and
1975, Japan imported nearly 300 million kiloliters of crude
oil, which contained nearly 3 million tons of sulfur. Most
of the sulfur in crude oil goes into heavy oil. More than
40 plants for hydrodesulfurization of heavy oil have been
completed, and in 1975 about 30 percent of the oil was
treated to produce 750,000 tons of elemental sulfur. Nearly
1-6
-------
Table 1-7. PLANNED IMPORTS OF LIQUEFIED NATURAL GAS"
(LNG, 1,000 t)
Source
Alaska
Brunei
Abu Dhabi
Indonesia
Sarawak
Iran
Other
Total
Buyer
Tokyo Electric
Tokyo Gas
Tokyo Electric
Tokyo Gas
Osaka Gas
Tokyo Electric
Kansai Electric
Chubu Electric
Kyushu Electric
Osaka Gas
Nippon Steel
Tokyo Electric
Mitsubishi Shoji
1973
720
240
580
370
350
2,260
1975
720
240
2,920
710
500
5,090
1977
720
240
3,450
1,060
630
2,800
100
500
300
380
380
10,560
1979
720
240
3,450
1,060
630
2,800
1,490
1,350
1,340
1,140
590
14,850
1981
720
240
960
1,060
630
2,800
2,400
1,TOO
1,500
1,300
600
4,000
2,000
2,500
24,900
1983
720
240
960
1,060
630
2,800
2,400
1,700
1,500
1,300
600
4,000
2,000
2,500
2,000
26,900
1985
720
240
960
1,060
630
2,800
2,400
1,700
1,500
1,300
600
4,000
2,000
2,500
7,000
31,900
-------
Table 1-8,
LONG TERM ENERGY SUPPLY PLAN'
(MITI, August 1975)
Domestic energy
c
Hydroelectric, 10 MWhr
Geothermal, 106 MWhr
Oil (gas) , 106 kl
Coal, 106 t
Atomic power, 10 MWhr
Imported energies
LNG, 106 t
Coal (for coke) , 106 t
Coal (for fuel) , 106 t
Oil, 106 kl
Total
1973
Amount
71.6
0.1
3.7
21.7
9.7
2.4
58.0
0
318.0
%
4.6
0.0
0.9
3.8
0.6
0.8
11.7
0
77.4
100.0
1980
Amount
85.5
2.1
6.4
20.0
95.4
20.6
87.3
4.7
393.0
%
4.2a
0.1
1.2
2.5
4.4
5.2
12.7
0.7
68.9
100.0
1985
Amount
100. 3a
14.7
14.0
20.0
278.3
42.0
87.8
14.6
485.0
%
3.7
0.5
1.8
1.9
9.6
7.9
9.6
1.6
63.3
100.0
I
00
Including power to be generated by pumped storage power plants.
-------
2 million tons of sulfur in heavy oil and crude oil was
burned, constituting about 75 percent of the total emission
of SC^. About one-fourth of the heavy oil was burned in
utility boilers of power companies and the rest by other
industries. The ambient standard for SO concentration was
^C
changed from 0.05 ppm (yearly average) to 0.04 ppm (daily
average) in May 1973. By the new standard, the hourly
average should not exceed 0.1 ppm and the daily average
should not exceed 0.04 ppm. The standard is much more
stringent than those in the U.S.A. and West Germany (Table
1-9). The values of K applicable to specific existing and
new plant locations in Japan are provided in Table 1-10.
The relation of K-values to maximum allowable ground-level
SO2 concentrations is presented in Table 1-11.
Table 1-9. AMBIENT AIR QUALITY STANDARDS
(Daily or yearly average, converted to ppm)
Japan
United States
West Germany
S0x
Daily
0.04
Yearly
0.016
0.03
0.05
NO2
Daily
0.02
0.13
Yearly
0.008
0.05
0.05
The emission standard is given by the following equa-
tion:
Q = K x 10
-3
He,
Q: Amount of sulfur oxides, Nm /hr
(1 NmVhr = 0.59 scfm) .
K: The value shown in Table 1-10.
He: Effective height of stack, meters
(1 meter = 3.3 ft).
1-9
-------
Table 1-10. VALUES OF K APPLICABLE TO LOCATIONS IN JAPAN
(For existing plants)
K - 3.0
Tokyo
Yokohama
Kawasaki
Yokkaichi
Osaka
K = 3.5
Chiba
Fuji
Handa
Hime ji
Mizushima
K = 4.67
Sapporo
Kashima
Shimizu
Tokuyama
Omuta
K = 8.76
Hachinohe
Sendai
Niigata
Okayama
Futuoka
K = 14.6
Hakodate
Miyako
Mobara
Sasebo
Kagoshima
(For new plants)
K = 1.17
Tokyo , Yokohama
Kawasaki , Nogoya
Yokkaichi, Osaka
K = 1.75
Chiba, Fuji
Kitakyushu
Handa, Himeji
K = 2.34
Kashima, Omuta
Ube, Oita
Shimizu, Kyoto
Table 1-11. RELATION OF K VALUE TO MAXIMUM
GROUND-LEVEL CONCENTRATION OF SO-
(ppm)
K
so2
1.17
0.002
1.75
0.003
2.34
0.004
3.50
0.006
4.67
0.008
8.76
0.05
14.6
0.025
1-10
-------
For a new plant with a capacity of 500 MW in the Tokyo
and Osaka areas, the sulfur content of oil must be below 0.3
percent, even with a 200-meter stack. Through application
of the regulations and such efforts as importing low-sulfur
fuels, hydrodesulfurization of heavy oil, and flue gas
desulfurization, ambient SO- concentrations in Japan have
decreased, as shown in Figure 1-1.
TOTAL MASS REGULATION OF SO
x
The emission standard has not succeeded in keeping the
ambient concentration below 0.04 ppm daily average (0.016
ppm yearly average) in large cities and heavy industrial
areas. With the aim of attaining the ambient standard by
March 1978, the central government promulgated a new regu-
lation in November 1974 to restrict the total mass of SO-
emissions from 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 (11) Kitakyushu. The new regula-
tion applies to plants using more than 0.1 to 1.0 kiloliter
of oil per hour (0.4 to 4.0 MW equivalent; a certain number
between 0.1 and 1.0 is to be assigned to each prefecture by
the Governor). The amount of allowable SO is calculated
.X
from one of the following formulas, to be selected by each
prefecture:
Q = a x W*5 (1)
1-11
-------
0.06
Ambient standard
1965 1967
1969 1971
Year
1973 1975
Figure 1-1. Yearly average SO- concentration in
15 major cities and industrial districts
1-12
-------
Q: Amount of allowable SOX
a: A constant to ensure SOX abatement
W: Amount of fuel used by each plant
b: A constant between 1.00 and 0.80 to be
selected by the prefectural governor.
Q = Qo x VCmo (2)
Q: Amount of allowable SOX
Cm: Maximum ground level concentration to
ensure SOX abatement
Cm : Maximum ground level concentration due to
0 each plant
Q : Amount of SOX being emitted
Two prefectures, Mie (with Yokkaichi city) and Kanagawa
(with Yokohama and Kawasaki cities), put the regulation in
force recently. The regulations of Kanagawa are shown
below.
Q= 1.5 W°'865 + 0.5 W.0'865 (I)
Q = 2.5 W°'865 + 0.8 Wi°'865 (II)
Q: Amount of allowable SO , Mm /hr
J\.
W: Fuel consumption by existing plants, kl/hr
W.: Fuel consumption by new plants, kl/hr
The equations are applied to plants that consume more
than 1 kl oil per hour. Equation (I) is for most polluted
districts in Yokohama and Kawasaki cities, and (II) is for
other districts of the cities and for all parts of Yokosuka
city. The allowable sulfur content of fuel oil, as calcu-
lated from the equations for different fuel consumptions, is
shown in Table 1-12.
1-13
-------
Table 1-12. ALLOWABLE SULFUR CONTENT OF OIL -
EXISTING AND NEW PLANTS
(Percent)
w
(MW equivalent)
Sulfur (I)
Sulfur (II)
W.
(MW equivalent)
Sulfur (I)
Sulfur (II)
1
(4.5)
0.238
0.397
1
(4.5)
0.079
0.127
10
(45)
1.174
0.290
10
(45)
0.058
0.093
100
(450)
0.124
0.207
100
(450)
0.041
0.066
1,000
(4,500)
0.094
0.155
1, 000
(4,500)
0.031
0.050
An existing 450-MW plant in district (I) is allowed to
use oil with less than 0.124 percent sulfur. If the plant
has two 225 MW units and one of them uses LNG with no
sulfur, the other unit may use oil with 0.248 percent
sulfur. New plants in district (I) need to use oil with
less than 0.079 percent sulfur. Those plants will have to
use naphtha, kerosene, or gas.
For plants consuming less than 1 kl/hr oil, sulfur
content must be below 0.3 percent in district (I) and below
0.5 percent in district (II). The sulfur contents of fuel
oils for diesel engine cars and ships are to be restricted
to 0.2 and 0.5 percent, respectively. In districts other
than (I) and (II), stationary sources are regulated by the
national K-value control.
1-14
-------
By those regulations, the total emission of SO in
A,
districts (I) and (II), which was 5,348 Nm3/hr in 1973, will
decrease to 2,078 Nm3/hr by the end of 1977; all districts
in the Kanagawa prefecture will have an SO concentration
J\.
below the national environmental standard, 0.016 ppm yearly
average (Figure 1-2).
POLLUTION-RELATED HEALTH DAMAGE COMPENSATION LAW
One of the driving forces for progress in S02 abatement
has been the "Pollution-Related Health Damage Compensation
Law" which has been in effect since 1972. By the law,
certain regions with prevalent pollution are designated as
polluted areas, and certain inhabitants who are diagnosed by
nominated doctors to have pollution-related sickness such as
chronic bronchitis are designated as pollution-related
patients. Firms which emit more than 5,000 Nm /hr of flue
gas in those regions must pay a tax according to the amount
of SO2; and tax is used to provide medical care for the
patients.
The number of designated patients increased remarkably,
as shown in Figure 1-3. Most of their illnesses are con-
sidered due to air pollution, mainly by SO.,. The total tax
paid by the firms increased from $11 million in 1974 to $52
million in 1975; most of the tax was paid for SO- emissions.
The tax rate, which changes each year, was 26<;/Nm SO., in
1975. For example, a firm with a 100-MW boiler using 0.6
1-15
-------
A.-
Tokyo Bay
Sagami River
Sagami Bay
1973
1977
Tokyo Bay
Figure 1-2. S02 concentration in Kanagwa prefecture
(yearly average in 1973 and 1977, ppm).
1-16
-------
20,000
15,000
CO
-P
a
-P
OS
•O
03
C
t>0
•H
CO
0>
-------
percent sulfur oil paid about $160,000 in 1975. The tax is
equivalent to about 1 percent of the cost of the fuel oil.
Several organizations now claim that the system may not
be working properly because the number of designated patients
has increased markedly in spite of the remarkable decrease
in ambient S0_ concentrations. It is likely that the
numbers of designated regions and patients will decrease in
the future.
EMISSION AND REGULATION OF NO
x
Total emissions of NO in Japan are estimated at about
x ^
2 million tons yearly. More than 90 percent of the NO is
X
caused by the burning of fuels, such as heavy oil and
gasoline. About 40 percent of the total NO is derived from
X
automotive exhausts, 20 percent from electric power genera-
tion, 30 percent from industry, and the rest from household
heating, etc. In large cities such as Tokyo and Osaka, 60
to 70 percent of the NO is traced to automobiles.
,x
The ambient air quality standard for N02 was set forth
in 1973 at 0.02 ppm daily average, the most stringent
standard in the world (Table 1-9). The present yearly
average NO,, concentration ranges from 0.02 to 0.03 ppm, and
the daily average often reaches 0.04 to 0.07 ppm in many
cities.
The NO emission standard for stationary sources was
H.
first set up in 1973 and revised in 1975. Table 1-13 shows
1-18
-------
the standard for boilers larger than 100,000 Nm /hr.
Similar figures have been assigned to smaller boilers
between 10,000 and 100,000 Nm3/hr since 1975. This standard
also is more stringent than those in the U.S.A. and other
countries.
Table 1-13. NO EMISSION STANDARDS
x
(ppm)
Fuel
Gas
Oil
Coal
For new boilers
1973
130
180
480
1975
100
150
480
For existing boilers
1973
170
230
750
1975
130
230
750
Even though combustion modifications and improvement of
burners have been undertaken in efforts to meet the standard,
the ambient air quality standard has not been attained, even
with the stringent emission standard. More stringent
regulations to restrict the total NO emissions from station-
5C
ary sources are to be applied in several prefectures. The
new regulations will require construction of many flue gas
denitrification plants, which remove more than 80 percent of
the NO .
x
1-19
-------
2. HYDRODESULFURIZATION AND DECOMPOSITION OF
OIL AND GASIFICATION DESULFURIZATION
STATUS OF HYDRODESULFURIZATION (HDS)
Eighteen heavy oil HDS systems have been constructed
since 1967, as shown in Tables 2-1 and 2-2. HDS is accom-
plished by two methods. One is vacuum gas-oil HDS, by which
the vacuum gas-oil obtained by vacuum distillation of heavy
oil is desulfurized to about 0.2 percent sulfur. Although
this treatment is relatively easy, it cannot desulfurize the
residual oil from the distillation, which amounts to about
40 percent of the heavy oil and is rich in sulfur and
metallic impurities. The second method is topped-crude HDS,
by which heavy oil is treated directly- It is difficult to
reduce sulfur content below 1 percent by this process.
Since 1 percent sulfur oil has become unsatisfactory for use
in many places, several oil companies, including Idemitsu
Kosan, Seibu Oil, Asia Oil, and Maruzen Oil, have constructed
new topped-crude HDS process plants to reduce sulfur to 0.3
percent or below by use of several reactors in series.
Hydrogen consumption to decrease sulfur from 1.0 to 0.3
percent is about equal to that required to reduce it from
2.5 to 1.0 percent. About 700,000 tons of elemental sulfur
2-1
-------
Table 2-1. HYDRODESULFURIZATION SYSTEMS BUILT BY 1971
Refiner
Idemitsu
Kosan
Fuji Oil
Toa Nenryo
Daikyo Oil
Nippon Oil
Showa Oil
Kyushu Oil
i Mitsubishi Oil
Maruzen Oil
Seibu Oil
Nippon Mining
Koa Oil
General Oil
Kashima Oil
Daikyo Oil
Kansai Oil
Koa Oil
Toa Nenryo
Total
Plant site
Chiba
Sodegaura
Wakayama
Umaokoshi
Negishi
Kawasaki
Oita
-Mizushima
Chiba
Yamaguchi
Mizushima
Mar if u
Sakai
Kashima
Umaokoshi
Sakai
Osaka
Kawasaki
i
Process
UOPa
CRC
ER & E
Gulf
CRC
Completed
1-967
1968
1968
1969
1969
Shell 1969
Shell 1969
UOP 1969
Union 1969
Shell
1969
Gulfa 1970
CRC 1970
ER & E 1970
UOPa
Gulf
ER & E
CRC
ER & E
1970
1970
1971
1971
1-971
Capacity, per day
Oil, BPSD
40,000
23 ,000
Sulfur, tons
265
100
25,000 180
17,500
40,000
16,000
14 ,000
30,000
35,000
4,000
27,760
8,000
31,000
45,000
17,500
20,000
12 ,000
51,000
465,260
110
190
66
55
100
165
28
165
39
73
265
77
88
55
220
2,241
Topped-crude HDS processes; all others are for vacuum gas-oil HDS.
-------
Table 2-2. HYDRODESULFURIZATION SYSTEMS COMPLETED
BETWEEN 1972 AND 1976
Refiner
Nippon Oil
Idemitsu Kosan
Kyokuto Petroleum
Toa Nenryo
Asia Kyoseki
Kyushu Oil
Showa Yokkaichi Oil
Seibu Oil
Nippon Oil
Toa Oil
Nippon Mining
Toa Oil
Kansai Oil
Showa Yokkaichi Oil
Mitsubishi Oil
Nippon Mining
Idemitsu Kosan
Idemitsu Kosan
Idemitsu Kosan
Seibu Oil
Asia Oil
Asia Oil
Toa Oil
Fuji Oil
Maruzen Oil
Total
Plant site
Negishi
Hime j i
Chiba
Kawasaki
Sakaide
Oita
Yokkaichi
Yamaguchi
Muroran
Nagoya
Mizushima
Nagoya
Sakai
Yokkaichi
Mizushima
Mizushima
Chiba
Tokuyama
Aichi
Yamaguchi
Yokohama
Sakaide
Kawasaki
Sodegaura
Chiba
Process
CRC
Gulfa
OOP
ER & E
CRC
OOP
Shell
Shell
CRC
CRC
Gulf3
ER & E
ER & E
Shell
uopa
OOP
UOP
UOP
Gulfb
Shellb
UOPb
Gulfb
ER & E
CRC
ER & Eb
Year of
completion
1972
1972
1972
1972
1972
1972
1972
1972
1973
1973
1974
1974
1974
1974
1974
1975
1975
1975
1975
1975
1975
1976
1976
1976
1976
Capacity
oil,
BPSD
28,000
40,000
60,000
9,000
15,000
25,000
35,000
1,000
40,000
30,000
3,240
37,000
2,000
5,000
45,000
60,000
34,000
45,000
50,000
45,000
30,000
28.000
46,000
35,000
60,000
839,240
a Topped-crude HDS.
New topped-crude HDS.
All others are for vacuum gas-oil HDS.
2-3
-------
was recovered in 1973 by HDS; sulfur recovery has not
increased much since then (Table 2-3), in spite of the
completion of many new HDS plants. The slowdown in sulfur
recovery was caused by economic depression; in 1975 opera-
tion of the HDS plants averaged only about 4,700 hours (54
percent of possible total of 8,760 hours).
About 25 HDS systems with a total capacity of nearly 1
million BPSD were planned for construction between 1976 and
1978. Most of the plans, however, were abandoned or post-
poned, partly because of the economic depression and partly
because a great increase in the demand for heavy oil had
become unlikely.
A rough estimate of HDS costs for heavy oil containing
3 percent sulfur at various desulfurization efficiencies is
shown in Table 2-4, with FGD cost given for comparison. HDS
is more expensive than FGD by the wet lime/limestone process
but it is advantageous in that it produces elmental sulfur,
which is a desirable by-product. The sulfur-by-producing
FGD processes developed in Japan and other countries are
more expensive, except for oil refineries that have Glaus
furnaces and hydrogen sulfide for sulfur production.
RESIDUAL OIL DECOMPOSITION AND COAL GASIFICATION
Outline
One of the major problems associated with HDS Technology
is that its application is limited to heavy oil, containing
2-4
-------
Table 2-3. AMOUNT OF SULFUR RECOVERED BY
HDS AND FGD
(1,000 tons)
HDS
FGDa
1973
700
100
1974
720
200
1975
'750
350
1976
(800)
(550)
Rough estimates including all sulfur
compounds as converted into sulfur.
Table 2-4. APPROXIMATE COSTS FOR HDS AND FGD AT
VARIOUS DESULFURIZATION EFFICIENCIES
($/kl, at 6,000 hours operation per year)
Sulfur removal, %
Hydrodesulfurization
Flue gas desulfurization3
70
16
16
80
19
17
90
23
18
97
27
19
Wet lime/limestone process by-producing gypsum.
2-5
-------
only small amounts of impurities because metallic impurities
in the oil poison the HDS catalysts. It is estimated that
only about 15 percent of the total heavy oil in Japan is
suitable for the new topped-crude HDS process to reduce
sulfur to 0.3 percent or below.
As demand for low-sulfur fuels increased, gasification
desulfurization seemed promising in 1973, and many companies
planned to construct gasification plants. Because of infla-
tion following the oil crisis, however, most of the plans
were given up. Ube Industries constructed a pilot plant to
2
gasify 50 tons per day of heavy oil. The Coal Research
Center constructed a pilot plant to gasify 5 tons per day of
coal. Activity at those works has been limited, however, by
the economic situation.
Thermal decomposition of the vacuum residue of heavy
oil (asphalt) with little gasification seems more promising.
Two commercial plants have been constructed for this pur-
pose. A plant with a capacity of treating 18,300 BPSD of
asphalt was completed recently at Sodegaura Refinery, Fuji
Oil, using the Eureka (Kureha) process. A plant capable of
treating 50,000 BPSD of heavv oil is near completion at
Kawasaki Refinery, Toa Oil, using the Flexicoking process.
Osaka Gas has developed a new process of asphalt
decomposition and is operating a pilot plant.
2-6
-------
4
Eureka Process (Kureha Process)
Kureha Chemical Industry has developed a new process to
decompose the residue from vacuum distillation of heavy oil
(asphalt) using steam to produce a cracked oil (about 65%),
gas (about 5 wt %) and pitch (about 30%) . A commercial
plant owned by Eureka Industry Co. (established by Kureha
Chemical jointly with Fuji Oil, Arabia Oil, and Sumitomo
Metal) with a capacity of treating about 1 million tons of
the residual oil yearly was completed in February 1976 at
Sodegaura, Chiba Prefecture, and has been operating smoothly
since March 1976 (Photo 2-1).
A flowsheet of the process is shown in Figure 2-1. The
residual oil containing 4 to 5 percent sulfur is treated
with steam heated to above 700°C in reactors at 500°C for
several hours. The steam carries heat and promotes distil-
lation.
Typical product patterns are shown in Table 2-5. The
cracked naphtha and gas oil contain few heavy metal impuri-
ties and are easily treated by hydrodesulfurization. The
gas from the reactor contains about 15 percent H2S, which is
removed by a conventional process using an amine. The
purified gas (about 16,000 kcal/m ) is used for fuel. The
pitch, which contains 4 to 8 percent sulfur, is used by
Sumitomo Metal as a binder for poor-coking coal in coke
2-7
-------
•: ,r v^.- v-ti i ;-
! .'! •'•*l-i^.'*,
Photo 2-1. Sodegaura plant, Eureka.
f£ED (VACUUM RESIDUE)
FRACTIONATOR
H3S
O (!) " pN-
BELT FLAKcR
FLAKED PITCH
STEAM SUPERHEATER
PITCH PUMP
[•'iquro 2-1. Flowsheet of Eureka process.
2-8
-------
Table 2-5. TYPICAL PRODUCT PATTERNS
(Values in percent by weight)
Products
Gas
Cracked naphtha
Cracked gas oil
Pitch
Khaf ji vacuum residue
Yield
5.2
8.3
54.7
31.8
Sulfur
content
14.5
1.9
3.6
7.6
Sulfur
distribution
14.2
3.0
37.2
45.6
Iranian Heavy vacuum residue
Yield
5.4
11.3
52.9
30.4
Sulfur
content
10.7
1.7
2.5
4.4
Sulfur
distribution
16.8
5.6
38.5
39.1
to
I
NOTE: 1. Sulfur contents of Khafji vacuum residue and Iranian Heavy vacuum
residue are 5.30 and 3.43 (% w), respectively.
2. Main components of gas are C-i-Cr paraffins and olefins.
-------
production. Kureha recently developed a process to produce
a spherical activated carbon with the pitch.
The economic balance of the residual oil cracking
process is shown in Table 2-6.
Flexicoking
A commercial plant with a capacity of treating 50,000
bbl/day heavy oil by vacuum distillation and 21,000 bbl/day
residual oil from the distillator (asphalt) by Flexicoking
is under construction and scheduled to be completed by
summer 1976 at Kawasaki refinery, Toa Oil. A rough material
balance is shown in Figure 2-2. Vacuum gas oil from the
distillator and gas oil from the Flexicoker will be treated
by HDS (Gofiner). High-calorie gas will be sold to an
adjacent steel producer, low-calorie gas will be consumed by
Toa Oil, and the coke will be sold.
Cherry Process
Osaka Gas Co., jointly with Mitsubishi Heavy Industries,
has developed a new asphalt decomposition process to solve a
common problem--coking on the reactor walls—by adding a
small amount of pulverized coal to the asphalt. A pilot
plant with a capacity of treating 26 t/day of asphalt was
completed recently. A flowsheet is shown in Figure 2-3.
Asphalt with a small amount of coal powder is heated to
400°C in a furnace, cracked and polymerized in a reactor,
2-10
-------
Table 2-6. ECONOMIC BALANCE OF RESIDUAL OIL CRACKING PROCESS
(1 million tons of vacuum residue per year)
Raw material
Vacuum residue, 1 million ton/yr
Processing cost
Utilities
Fixed cost (30% of investment)
Products cost
Cracked oils 654 million ton/yr
Pitch 300 million ton/yr
Unit price
(yen/kg)
13.2
19.8
14.3
(«/lb)
2
3
2.17
Cost
(million
yen/year)
13,200
930
3,087
17,217
12,930
4,287
17,217
(million
$/year)
44
3.1
10.3
57.4
43.1
14.3
57.4
to
I
NOTE: 1. Investment including off-site is 10,290 million yen in Japan, 1975.
2. The price of coal tar pitch is considered between 3C/lb and 5C/lb
in Japan, 1975.
-------
Vacuum
distillation
Hydrodesulfurization
Heavy oil
100
58
,_ ' riexico
I
Coke 1
Gofiner
ker
/
)
X
V
^ Low-Kill fu
" *> Sulfur
22
» High-calorie gas 5
• Low-calorie gas 6
Naphtha 8
Figure 2-2. Material balance for residual oil
decomposition using Flexcoking process.
SOLID-LIQUID
SEPARATOR
Figure 2-3. Flowsheet of Cherry Process,
2-12
-------
then led into a flash drum, where lighter fractions are
separated. The bottom product of the flash drum is centri-
fuged to separate liquids and solids. The liquid is sent to
a distillation column to produce an oil and a pitch, which
is used as a binder. The yield is 30 percent naphtha, 5
percent kerosene, 11 percent heavy fuel oil, 34 percent
pitch binder, and 20 percent solids. The solid product is
used as a coal substitute. A portion of the solids can be
recycled to the system. No coking on the reactor walls
has been observed.
Coal Gasification
The Coal Research Center has continued tests on coal
gasification with a 5-t/day pilot plant at Yubari, Hokkaido.
Coal is gasified in a fluidized bed under 10 atmospheres
pressure at 800 to 900°C with air and steam to produce a
low-calorie gas (1,200 to 1,500 cal/m ). A unit to desul-
furize the gas by the Benfield process (a U.S. process) is
under construction and is to start operation by the end of
1976. A plan to construct a 40-t/day test plant has been
postponed.
Electric Power Development Co., which 2 years ago
planned to construct a pilot plant for coal gasification,
has postponed the plan and has joined the Coal Research
Center in the development project.
2-13
-------
3. GENERAL ASPECTS OF FLUE GAS DE SULFUR I Z AT ION (FGD)
TRENDS
Japan has made remarkable progress in flue gas desul-
furization since 1972. About 100 systems, including several
large ones with a capacity of 250 to 500 MW, went into
operation in 1975. The total FGD capacity, which was about
40 million Nm /hr (13,000 MW equivalent) at the end of 1974,
will exceed 80 million Nm /hr by the end of 1976. The rapid
growth is due to the economic advantage of FGD over the use
of low-sulfur fuels and to the reliability of process and
operation. The growth rate may decline after 1977, however,
for the following reasons:
(1) Ambient S02 concentrations in large cities and
industrial districts have decreased to a range of
0.02 to 0.03 ppm, almost meeting the ambient
standard.
(2) The recent economic depression has prevented
industry from building new plants.
(3) Overproduction of FGD by-products and a decrease
in the price difference between high- sulfur and
low-sulfur oils (Table 1-6) have started an
industry trend toward the use of low-sulfur fuels,
because Japan has limited landspace available for
discarding of useless by-products.
(4) The stringent NOx regulation is forcing industry
toward flue gas desulfurization. Several proc-
esses for simultaneous removal of NOX and S02 have
been developed, and industry is waiting for the
new technology.
3-1
-------
MAJOR PROCESSES AND SYSTEMS
Table 3-1 lists major constructors of FGD units and
numbers and capacities of the units to be operational by the
end of 1977. The total number of the units will exceed 500
and the total capacity will reach 85,000,000 Nm /hr, which
is equivalent to 28,000 MW. About 80 percent of the units
are completed (as of April 1976). About half of the total
capacity is for utility boilers (mostly oil-fired) and the
rest for industrial boilers, iron-ore sintering machines,
nonferrous metals plants, sulfuric acid plants, and similar
operations.
About half of the total capacity uses the wet lime/
limestone process to by-produce gypsum; 16 percent use the
indirect lime/limestone process (double alkali type); 13
percent use regenerable processes to by-produce sulfuric
acid, ammonium sulfate and elemental sulfur; and 24 percent
use sodium scrubbing to by-produce sodium sulfite or sulfate.
The average system capacities are 427,000 Nm /hr for wet
lime/limestone, 291,000 Nm /hr for indirect lime/limestone,
378,000 Nm /hr for the regenerable processes, 59,600 Nm /hr
for the sodium scrubbing processes. About 80 percent of the
sodium scrubbing units by-produce sodium sulfite for paper
mills, and the rest oxidize the sulfite by air bubbling to
by-produce sulfate, which is either used in the glass in-
dustry or purged in wastewater.
3-2
-------
A recent survey by the Heavy Industry Newspaper Co. has
revealed that in addition to the 335 sodium scrubbing units
listed in Table 3-1, there are nearly 500 small commercial
sodium scrubbing systems with an average capacity of about
20,000 Nm /hr. The sodium scrubbing process is the least
costly, and its operation is relatively easy.
WET LIME/LIMESTONE PROCESS
Outline
Wet lime/limestone process systems with a capacity
larger than 60,000 Nm3/hr (20 MW) are listed in Tables 3-2,
3-3, and 3-4. The first commercial system using a wet lime-
gypsum process was constructed in 1964 by Mitsubishi Heavy
Industries (MHI), licensed by Japan Engineering Consulting
Co. to treat 62,500 Nm /hr of tail gas from a sulfuric acid
plant, containing 2,200 ppm SO,,. Several problems, including
scaling and corrosion, were encountered at the beginning of
the operation. The problems have been gradually solved, and
many FGD systems using wet lime/limestone processes have
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., while the Chemico-Mitsui, Mitsui-Chemico, and
Chemico-IHI processes have been applied to coal-fired
boilers. Six other processes also have been used, mainly
3-3
-------
Table 3-1. NUMBERS AND CAPACITIES OF FGD SYSTEMS EXPECTED TO BE
OPERATIONAL BY END OF 1977
Plant constructor
Mitsubishi Heavy Industries (MHI)
Ishikawajima H.I. (IHI)
Hitachi - Babcock
Mitsubishi Kakoki (MKK) -Wellman
Kawasaki Heavy Industries
Tsukishima Kikai (TSK)
Chiyoda Chemical Eng. and Const.
Oji Koei
Fuji Kasui Engineering
Kurabo Engineering
Mitsui Miike-Chemico
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
limestone
33
17
13
2
4
1
7
4
3
4
5
1
94
(18,270)
(4,445)
(6,940)
(256)
(756)
(80)
(3,954)
(2,744)
(245)
(1,006)
(1,125)
(330)
(40,181)
Indirect lime
limestone
6
4
14
5
11
1
4
1
46
(5,450)
(398)
(4,459)
(413)
(1,914)
(150)
(423)
(185)
(13,392)
•Regenerable
2
13
1
1
1
2
6
2
1
1
30
(590)
(6,478)
(88)
(18)
(500)
(1,990)
(1,288)
(130)
(125)
(150)
(11,357)
Sodium scrubbing
3
79
15
41
7
40
57
6
106
10
6
8
5
8
1
335
(292)
(4,351)
(603)
(913)
(256)
(4,042)
(4,280)
(270)
(3,751)
(1,167)
(62)
(1,431)
(1,372)
(1,291)
(160)
(19,961)
Total
36
96
30
56
17
45
14
57
13
112
5
21
12
8
5
8
6
6
5
2
4
1
1
1
505
(18,562)
(8,796)
(8,133)
(7,643)
(6,380)
(4,608)
(4,459)
(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)
(423)
(185)
(160)
(150)
(84,891)
u>
I
Number of units followed by total capacity in parentheses; capacities are in thousands Nm3/Hr.
-------
Table 3-2. WET LIME/LIMESTONE PROCESS UNITS BY MHI PROCESS
(larger than 60,000 Nm3/hr)
User
Nippon Kokan
Kansai Electric
Onahama Refining
Kawasaki Steel
Kansai Electric
Tokyo Electric
Tohoku Electric
Kyushu Electric
Kawasaki Steel
Kansai Electric
Niigata Power
Kawasaki Steel
Kawasaki Steel
Tei jin
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
Chugoku Electric
Confidential
Confidential
Confidential
Plant site
Koyasu
Amagasaki
Onahama
Chiba
Kainan
Yokosuka
Hachinohe
Karita
Mizushima
Amagasaki
Niigata
Mizushima
Chiba
Ehime
Mizushima
Niigata
Owase
Owase
Mizushima
Iwakuni
Kashima
Karatsu
Karatsu
Ainoura
'Ainoura
Sakata
Sakata
Shimonoseki
Capacity,
1,000 Nm3/hra
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
1,200
475
1,200
530
Source of gas
H2SO4 plant
Utility boiler"
Copper smelter
Sintering plant
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Sintering plant
Utility boiler
Utility boiler
Sintering plant
Sintering plant
Industrial boiler^
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Sintering plant
Industrial boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
SOy, ppm
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
500
550
Outlet
200
70
100
60
60
40
85
75
40
50
70
40
60
60
40
55
35
35
40
50
100
70
70
110
110
50
50
50
65
65
Absorbent
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
CaC03
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
CaCO3
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH)2
CaC03
CaC03
CaC03
CaC03
CaC03
CaC03
CaC03
CaCO3
Ca(OH)2
Ca(OH)2
CaC03
Year of
completion
1964
1972
1972
1973
1974
1974
1974
1974
1974
1975
1975
1975
1975
1975
1975
1976
1976 (March)
1976 (June)
1976
1976
1976
1976
1976
1976
1976
1976
1976
1976
1976
1976
1976
I
en
a 1,000 Nm3/hr = 590 scfm = 320 kW.
All boilers are oil-fired.
-------
Table 3-3. WET LIME/LIMESTONE PROCESS UNITS USING SCRUBBERS DEVELOPED
IN THE UNITED STATES
(larger than 60,000 Nm /hr)
User
Babcock-Hitachi Process
Chugoku Electric
Asahi Chemical
Kansai Electric
Chugoku Electric
Kansai Electric
Chugoku Electric
Showa Power
Showa Power
Maruzumi Paper
Confidential
Electric Power Dev.
Plant site
Mizushima
Mizushima
Osaka
Tamashima
Osaka
Tamashima
Ichihara
Ichihara
Kawanoe
Takehara
Ishikawajima Harima (IHI) - TCA Pro
Chichibu Cement
Onahama Smeltery
Furukawa Mining
Chichibu Cement
Hibi Smeltery
Tokuyama Soda
Sumitomo Power
Mitsui Alumina
Chemico - Mitsui and Mi
Mitsui Aluminum
Mitsui Aluminum
Electric Power Dev.
Electric Power Dev.
Ishikawajima Harima (IH
Electric Power Dev.
Kumagaya
Onahama
Ashio
Kumagaya
Hibi
Tokuyama
Niihama
Hakainatsu
:sui - Chemii
Omuta
Omuta
Takasago
Takasago
[) - Chemico.
Isogo
Capacity,
1,000 Nm3/hra
310
481
500
1,460
500
1,000
249
480
342
500
852
:ess
104
120
60
106
300
550 x 2
450
300
2al Processes
512
552
840
840
Process
900 x 2
Source of gas
Utility boiler
Industrial boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Utility boiler
Industrial boiler
Industrial boiler
Utility boilerb
Diesel engine
Converter
H2S04 plant
Diesel engine
Smelter
Industrial boiler
Utility boiler
Boiler, kiln
Industrial boilerb
Industrial boiler
Utility boilerb
Utility boilerb
Utility boilerb
SO2, ppm
Inlet
1,500
700
2,000
1,500
1,500
1,500
500
Outlet
60
50
200
150
150
150
70
Absorbent
CaCO3
CaC03
CaC03
CaC03
CaC03
CaC03
CaC03
CaC03
CaCO3
CaCO3
CaC03
CaO
CaO
CaO
CaO
CaO
CaC03
CaC03
Ca(OH) 2°
CaC03
CaC03
CaCO3
CaCO3
Year of
completion
1974
1975
1975
1975
1975
1976
1976
1976
1976
1976
1977
1972
1972
1972
1973
1974
1975
1975
1975
1972
1975
1975
1976
1976
a 1,000 Nm3/hr
b
590 scfm = 320 kW.
Coal-fired boilers. Other boilers are oil-fired.
Carbide sludge to by-produce throwaway calcium sulfite. Other plants by-produce gypsum.
-------
Table 3-4. WET LIME/LIMESTONE PROCESS UNITS USING OTHER PROCESSES
(larger than 60,000 Nm /hr)
User
Fvjjikasui-Sumitomo proc
Ide Paper
Sanyo Kokusaku Pulp
Sumitomo Metal
Sumitomo Metal
Sumitomo Metal
Sumitomo Kainan
Kokan
Sumitomo Metal
Sumitomo Metal
Plant site
ess (Moretana
Fuji
Onomichi
Wakayama
Kokura
Kashima
Wakayama
Kashima
Kokura
Nippon Kokan process (Spray tower ab
Nippon Sheet Glass
Nippon Sheet Glass
Nippon Kokan
Kobe Steel process (Cal
Kobe Steel
Kobe Steel
Nakayama Steel
Yokkaichi
Maizuru
Fukuyama
process)
Amagasaki
Kobe
Osaka
Chubu - MKK process (CM process)
Ishihara Chemical
Mitsubishi Gas Chem.
Kawasaki Heavy Industry
Jujo Paper
Jujo Paper
Unitika
Nippon Exlan
Yokkaichi
Yokkaichi
process
Akita
Akita
Okazaki
Saidai ji
Nippon Steel process (SSD process)
Nippon Steel
Nippon Steel
Tobata
Wakamatsu
Capacity
1,000 Nm3/hra
scrubber)
60
140
370
92
880
182
1,000 x 2
750
>orber)
120
107
175 x 2
350
375
250
60
84
90
200
300
200
1,000
Source of gas
Industrial boiler .
Recovery boiler
Sintering machine
Heating furnace
Sintering machine
Heating furnace
Sintering furnace
Sintering furnace
Glass furnace
Glass furnace
Incinerator
Sintering machine
Sintering machine
Sintering machine
Industrial boiler
Industrial boiler
Recovery boiler
Recovery boiler
Industrial boiler
Industrial boiler
Sintering machine
Sintering machine
S0?, ppm
Inlet
1,340
4,000
650
820
650
680
650
650
1,000
1,550
28,000
500
500
500
1,600
1,300
Outlet
20
40
20
40
30
35
30
20
100
200
200
30
30
30
150
100
Absorbent
CaCOs
CaCOs
CaCOa
CaCOa
CaC03
CaC03
CaC03
CaC03
Ca(OH)2
CaCO3
CaO
Ca(OH)2
Ca(OH)2
Ca(OH)2
CaC03
Ca(OH)2
CaC03
CaC03
CaO(MgO)
CaCO3 (MgO)
Slag
Slag
Year of
completion
1974
1975
1975
1975
1975
1975
1976
1976
1974
1976
1976
1976
1976
1976
1974
1974
1973
1975
1975
1975
1974
1976
u>
I
a 1,000 Nm3/hr = 590 scfm
320 kW.
-------
for flue gas from oil-firing boilers, and three others for
sintering plants.
Many of the plants constructed before 1974 use lime at
a stoichiometry of 0.95 to 1.0 to remove 93 to 98 percent of
the S02. Most of the plants constructed later use limestone
ground to pass about 325-mesh screen at a stoichiometry of
1.0 to 1.05 to remove 90 to 96 percent of the SO-. Virtually
all of the plants by-produce salable gypsum.
A schematic flowsheet common to most processes, except
the Chemico-Mitsui and Mitsui-Chemico processes which use no
cooler (prescrubber), is shown in Figure 3-1. Flue gas
passes through an electrostatic precipitator, a cooler, a
scrubber, a mist eliminator, and a reheater, before being
emitted from a stack. Types of scrubbers and examples of
operation parameters are listed in Table 3-5. Calcium
sulfite formed by the reaction of S0~ with lime or limestone
slurry is oxidized by air bubbles into gypsum, which is then
centrifuged.
The Omuta plant of Mitsui Aluminum is the only plant
that produces a throwaway calcium sulfite sludge on a large
scale. The plant uses a two-stage Chemico venturi scrubber
and a carbide sludge as the absorbent. The plant has been
operated in an unsaturated mode; gypsum is not formed,
although about 10 percent of the calcium sulfite is oxidized
in the scrubber. Operation has been trouble-free since
3-8
-------
Flue
gas
130° c
Water
Cooler
Scrubber
60° C •
Water Direct-fired
(occasional) reheater
130°0
Electrostatic
precipitator
Sludge
<
Filter
Waste-
water
60° C
CaO
Deraister
-----3-—H
130° c
Oxidizer
Stack
CaO.CaCO, pH,. ....
', * controller
yfk
I
Neutralizer
Centri-
fuge
Water(with
or without)
Gypsum
Figure 3-1. Schematic flowsheet of wet lime/limestone
gypsum process.
3-9
-------
Table 3-5. EXAMPLE OF OPERATION PARAMETERS OF FGD PLANTS
BY-PRODUCING GYPSUM AND CALCIUM SULFITE
Process developer
Wet lime-limestone proc
MHI (Mitsubishi-JECCO)
MHI 'Mitsubishi-JECCO)
Chemico-Mitsui
"itsui-Cner-ico
E = bcock-:-:itachi
Fuji Kasui-Sumitorao
Chubu-?',rCK
Ishikawaj inta-TCA
Kob? Cte&i
Indirect lime-limestone
Kureha- Kawasaki
Shews ~enko
Nippon Kokan
Chiyoda
Kurabo
Dow a
Kureha
Absorbent,
precipitant
(stoichioir.etry)
ess
CaO 1
CaC03 1
Ca(OH)2 1-1.05
CaCO3 1.0-1.05
CaC03 1. "5-1. 15
CaC03 1.05-1.15
CaC03
CaO
CaOf 1.05
process
"a2S03, CaCO3
Ka2SO3, CaCO3
(NH4)2S03, CaO
dil.H2S04, CaC03
(NH4)2S04, CaO
Al 2(304)5, CaC03
CH3COONa, CaC03
Capacity,
1,000 Nm3/hr
l,200d
750
385
840
1,460C
800
250
100
350
l,260d
50QC
150
Type of
absorber
GPa
GPa
venturi
venturi
ppb
PPb
screen
TCA
spray
GPa
cone
screen
1,050 ITellerette
100 ITellerette
150
5
Tellerette
Ppb
Slurry or
solution,
pH
6.6
6
7
6
6.1
6
6
6-8
6.2
6.8
6
1
4
4
5.5
cone. %
10
10
3-5
5
20
5-6
10
2
30
20
25
30
2-4
10
10
20
L/G,
liter/
Mm 3
10
10
10-15
10-15
10
5
10
7
3
Space
velocity,
in/sec
Pressure
drop, *
mm H20
3.5
3.5
3.2
4.5
4
3
3
200
150
400
200
850
200
120
S02,
In
1,600
1,000
2,000
1,500
1,500
500
1,500
70C
190
300
I |
10
2
2
55-60
6-10
3e
7-89
2.5
3
150 1,070
250
250
1,400
700
1 1,600
2
1.5
2-2.5
100 I 1,500
100 ! 600
280 1,400
ppm
Out
40
80
150
130
60
20
150
50
20
5
40
30
60
80
20
1-3
Moisture ,
% of
gypsum
8-10
8-10
CaSO3
10-15
S-10
10-12
10-15
10
6-8
S-10
8-10
7-9
8-10
10-12
6-7
00
I
H-
o
Grid packed.
Perforated plate.
Four scrubbers in parallel.
Two scrubbers in parallel.
e For tail gas at 25°C. L/G 6-10 for flue gas.
f Ir. CaCl2 solution.
^ Including limestone scrubbing.
* Including cooler, absorber, and mist eliminator.
-------
start-up. For the recent FGD installations, Mitsui Aluminum
selected a modified Mitsui-Chemico process to by-produce
gypsum using limestone—because carbide sludge is getting
short and the calcium sulfite sludge pond is becoming full.
Scale Prevention
In many of the plants by-producing gypsum, more than 20
percent oxidation of calcium sulfite occurs, resulting in
formation of gypsum in the scrubber. Gypsum crystals are
usually recycled to the scrubber as seed crystals to elimi-
nate the formation of gypsum on the surface of structural
materials, which tends to cause scaling. Maintaining a
smooth surface on the materials and a continuous flow of
slurry in all parts of the scrubbers and pipings also aids
in scale prevention.
Mist eliminators are most susceptible to scaling.
Washing the eliminator with fresh water dissolves the scale
but increases the volume of wastewater. A recent trend is
to wash eliminators with circulating liquor and only occasion-
ally with fresh water when some scale forms.
Scaling of the mist eliminator apparently is much more
serious in the United States than in Japan. In the U.S.A. a
large excess of limestone is often used to remove 80 to 90
percent of the SO2. A mist containing a considerable amount
of unreacted limestone adheres to the eliminator; passage of
the gas containing 200 to 400 ppm of S02 and 2 to 4 percent
3-11
-------
0 results in formation of gypsum on the mist eliminator.
In Japan the excess of limestone is not so great, and the
S02 concentration of the gas passing through the eliminator
usually ranges from 20 to 150 ppm. Good reaction of lime-
stone in the scrubber is attained by fine grinding and use
of a higher L/G ratio.
INDIRECT LIME/LIMESTONE PROCESS
Outline
Processes developed to ensure scale-free stable
operation, include double-alkali processes that use .alkaline
solutions for absorption and lime or limestone for precipitation,
and also similar processes using acidic solutions for absorp-
tion. All of these processes are classified under the
category of "indirect lime/limestone process." Operating
parameters are shown in Table 3-5; major installations are
listed in Table 3-6.
The scrubbing liquors are as follows: sodium sulfite
for Kureha-Kawasaki, Showa Denko, and Tsukishima; ammonium
sulfite for Nippon Kokan; dilute sulfuric acid containing
ferric sulfate for Chiyoda; aluminum sulfate for Dowa;
acidic ammonium sulfate for Kurabo; and sodium acetate for
Kureha.
The pH values of the liquors are 6 to 7 for ammonium
and sodium sulfites, 5 for sodium acetate, 3 to 4 for
3-12
-------
Table 3-6. INDIRECT LIME/LIMESTONE PROCESS INSTALLATIONS
Process developer
Chiyod=
Showa Denko
Shovra Denko-Ebara
Kureha-Kawasaki
Nippon Kokan
Tsukishima
Kurab:> Eng.
Dews Mir.ing
Kureha Chemical
Absorbent,
precipitant
E S0d, CaCC
£. *i J
1
User
Nippon Mining
Fuji Kosan
Mitsubishi Rayon
Daicel
Tchcku Cil
Mitsuois'ii Chem.
toacasaki Cok3
Kohuriku Electric
Kitsrbishi Pet.
Mitsucishi Pet.
Gulf Pov.er
Denki Kagaku
Na^SO,, CaCO,
*i J J
Na,SO,, CaCO,
i O J
Na-SO,, CaCO,
(NH5)_SO3, CaCOj
Na2SO.,, CaO
(;JH . 1 ,SO. , CaO
^
A12(S04)3, CaCC,
J
CH3COONa, CaC03
Eckuriku Electric
Tcyama Power
Showa Denko
Kanegafuchi Cher-..
Showa Pet. Chen.
Nippon Mining
Yokohama Rubber
Ivisshin Oil
Foly Plastics
Ajinohoto
Kyowa Pet. Chem.
Japan Food
Yokohama Rubber
Asia Oil
Tohoku Electric
Shikoku Electric
Shikoku Electric
Kyushu Electric
Tohoku Electric
Nippon Kokan
Kinuura Utility
Daishowa Paper
Kurarcy
Puicel
Bridges cone Tire
Bridgeston^ Tire
Jujc Paper
Tae^aka Mining
Dcwa Mining
KjiHai Eng/o
Y.ih-^c-'i Iron
Kureha Chem.
Plant site
Mizushima
Kainan
Otake
Aboshi
Ser.dai
Yc-kk^ichi
Kakogawa
Yokkaichi
Yokkaichi
Florida
Chiba
Fukui
Toyama
Chiba
Takasago
Kaw?.saki
Sagancseki
Kiratsuka
Isogo
Fuji
Yokkaichi
Yokkaichi
Yckkaichi
Mie
Yokohana
Shinsendai
Sakaide
Anan
Buzen
Akita
Keihin
Nagoya
Fuji
Trr.ashima
Abo sh i
Tcsu
Tochigi
Ishinoir.aki
Ko'oara
Okay.iT-a
Oksyar.a
Kagoya
Nishiki
Capacity,
1,000 NmJ/hr
34
ISO
9C
99
14
4?0
36
750
150
750
85
122
1,050
750
500
300
200
120
105
100
212
82
150
100
100
243
420
1,260
1,260
730
1,050
150
185
264
100
153
50
80
200
3,500
300
70
50
5
Source of gas
Claus furnace
Industrial boiler
Industrial boiler
Industrial boiler
Claus furnace
Industrial boiler
Incinerator
"utility boiler
Industrial boilsr
Industrial boiler
Utility boiler
Industrial boiler
Utility boiler
Utility boiler
Industrial boiler
Industrial bciler
Industrial boiler
H2S04 plant
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
UtiJity 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
Ki]n
H2SOj plant
Utility boiler
Sintering plant
Utility boiler
Inlet
SO2 , ppn
9,300
770
1,600
1,400
7,100
1,200
11,300
SCO
1,200
1,200
1,700
1,400
1,500
1,500
1,500
1.500
1,400
420
1,500
1,500
1,500
1,500
400
1,500
1,300
1,200
7 ,500
650
1,500
1,500
Year of
completion
1972
1972
1972
1973
1973
1974
1974
1974
1974
1974
1975
1975
1975
1975
1973
1?74
1974
1973
1974
1974
1974
197-
1974
1975
1975
1975
1974
1975
1975
1977
1977
1972
1974
1975
1974
1975
1975
1975
1976
1972
19~4
1975
197S
1975
u>
-------
ammonium and aluminum sulfates, and 1 for sulfuric acid.
The L/G ratios are 1/2 (7 to 14 gal/1,000 scf) for the
solutions of pH 6 to 7, 3/10 for the solutions of pH 3 to 5,
and 30/50 for the acid at pH 1. As acidity of the solution
increases, the SO absorption capacity and scaling are
reduced and the reaction with limestone becomes easier.
Limestone can be reacted with a sodium bisulfite solution,
as in the Showa Denko and Kureha-Kawasaki processes, but the
reaction occurs slowly and requires large reaction vessels.
Lime is used for the Tsukishima, NKK, and Kurabo processes.
For the Chiyoda, Dowa, Kureha, and Kurabo processes,
the liquors that absorb S0~ are contacted with air to
oxidize SO- into SO. . Limestone or lime is then added
to precipitate gypsum. For other processes, limestone or
lime is added first to precipitate calcium sulfite, which is
then oxidized into gypsum. In the double alkali type
process, gypsum usually grows in larger crystals than in the
wet lime-limestone process. Moisture content of the by-
product gypsum after centrifugalization ranges from 6 to 12
percent as compared with 8 to 15 percent for the wet lime-
limestone process.
The liquor from the gypsum centrifuge is returned
mainly to the scrubber system. Softening of the liquor,
which is usually needed to prevent scaling, is not required
when pH of the acidic solution is below 5.
3-14
-------
At most plants, a small portion of the liquor is purged
to maintain the concentrations of chloride, magnesium, and
other impurities under a certain level.
Sodium scrubbing provides high SO- recovery but involves
sodium sulfate formation because of the oxidation of sodium
sulfite. The sulfate must be decomposed because it does not
absorb S0_.
£*
Compared with sodium scrubbing, ammonia scrubbing is
less expensive because ammonia is cheaper than sodium
hydroxide and ammonium sulfate is readily decomposed by
lime. Plume formation is the major problem in ammonia
scrubbing.
Costs and Trends
Generally speaking, scale-free, stable operation is
more easily attained by indirect lime/limestone processes
than by the wet lime/limestone process, but the capital and
operating costs are 5 to 10 percent higher (Table 3-9).
As successful operation of wet lime/limestone process
units continues, the indirect processes are losing their
advantage. Sodium-based indirect processes may be used,
however, when more than 98 percent S0~ removal is required,
even though the processes are fairly expensive. Other
indirect processes may be used at plants where the operation
is not readily controlled to prevent scaling with a wet
lime/limestone process.
3-15
-------
OTHER PROCESSES (RECOVERY PROCESSES)
Sodium Sulfite By-production
There are 335 sodium scrubbing systems with an average
capacity of treating 60,000 Nm /hr of flue gas (Table 3-1)
and about 500 smaller units with an average capacity of
3
20,000 Nm /hr, by-producing mainly sodium sulfite, with some
sulfate. As sodium hydroxide absorbs not only SO- but also
C02, sodium sulfite is generally used to absorb S02 only.
The product sodium bisulfite is neutralized with sodium
hydroxide to produce the sulfite solution, half of which is
returned to the scrubber and the rest to a concentration
step. The by-product sulfite, in the form of either a
concentrated solution or crystal, is sold to paper mills.
Na2SO3 + S02 + HO = 2NaHS03
NaHS03 + NaOH = Na2S03 + H2O
The process is simple and the system costs are low;
demand for the sulfite, however, is limited. In several
units the sulfite in solution is air-oxidized into sulfate,
which is used for glass production, etc. From some smaller
units, the sodium sulfite solution is purged. The number of
sodium sulfite scrubbing systems will not increase signifi-
cantly because of the oversupply of the by-products and the
increase in cost of the sodium hydroxide.
3-16
-------
Wellman-Lord Process
Many Wellman-Lord process units have been constructed
by Mitsubishi Kakoki Kaisha (MKK) and Sumitomo Chemical
Engineering Co. (SCEC) (Table 3-7). The processes and the
2
units were described in an earlier report. Unit operation
i
has been smooth. The major problem with the process has
been treatment of wastewater to decompose reducing compounds.
In addition to sodium thiosulfate Na2S2O~, dithionate
Na2S.Og is formed during heating of the sodium bisulfite
solution, and the dithionate is not easily decomposed. MKK
has succeeded in decomposing it by ozone oxidation at a pH
below 1.5. The chemical oxygen demand (COD) is reduced
enough to meet the regulation, but the treatment adds cost
to the process. Most of the Wellman-Lord process units by-
produce sulfuric acid; three units of oil companies by-
produce elemental sulfur by feeding the recovered S02 into
a Glaus furnace.
Magnesium and Zinc Scrubbing
There are two magnesium scrubbing units in operation
(Table 3-7). Onahama plant, Onahama Smelting Co., sends the
2 3
recovered SC- to a sulfuric acid plant, as reported earlier. '
Chiba plant, Idenitsu Kosan, using the Chemico-Mitsui process,
started operation recently, as described in Section 6.
3-17
-------
Table 3-7. FGD INSTALLATIONS BY-PRODUCING
, S AND (NH4) 2SC>4
Process developer
Wellman-MKK
Wellman-SCEC
Onahama-Tsukishima
Chimico-Mitsui
Mitsui Mining
Shell
Sumitomo H.I.
Hitachi Ltd.
Nippon Kokan
Kurabo Engineering
MHI-IFP
TEC- IFF
Absorbent
Na0SO-
£ J
Na^SO,
^ J
MgO
MgO
MgO
ZnO
CuO
Carbon
Carbon
Carbon
(NH4)2S03
(•NH4)2S03
(NH4)2S04
(NH4)2S03
(NH4)2S03
User
Japan S.R.
Chubu Electric
Kashima Oil
Japan S.R.
Toyo Rayon
J.N. Railways
Mitsubishi Chem.
Kuraray
Shindaikyowa Oil
Mitsubishi Chem.
Mitsubishi Chem.
Tohoku Electric
Toa Nenryo
Sumitomo Chem.
Toa Nenryo
Fuji Film
Sumitomo Chem.
Sumitomo Chem.
Onahama Smelting
Idemitsu Kosan
Mitsui Mining
Mitsui Mining
Showa Y.S.
Kansai Electric
Tokyo Electric
Unitika
Nippon Kokan
Nippon Kokan
Taki Chemical
Maruzen Oil
Fuji Oil
Plant site
Chiba
Nishinagoya
Kashima
Yokkaichi
Nagoya
Kawasaki
Mizushima
Okayama
Yokkaichi
Mizushima
Kurosaki
Niigata
Kawasaki
Sodegaura
Wakayama
Fujinomiya
Niihama
Sodegaura
Onahama
Chiba
Hibi
Kamioka
Yokkaichi
Sakai
Kashima
Oji
Fukuyama
Ogishima
Befu
Shimozu
Chiba
1,000 Nm3/hra
200
620
30
450
330
700
628
410
400
628
530
380
67
360
17
150
155
540
84
500
80
50
120
160
420
171
760
1,140
15
42
6
Source of gas
Industrial boiler
Utility boiler
Glaus furnace
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Industrial boiler
Utility boiler
Claus furnace
Industrial boiler
Claus furnace
Industrial boiler
Industrial boiler
Industrial boiler
Copper smelter
Claus and boiler
H2S04 plant
H2S04 plant
Industrial boiler
Utility boiler
Utility boiler
Industrial boiler
Sintering plant
Sintering plant
Industrial boiler
Claus furnace
Claus furnace
Inlet
S02, ppm
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
1,500
1,500
400
400
1,500
Year of
completion
1971
1973
1973
1973
1974
1975
1975
1975
1975
1976
1976
1977
1971
1973
1974
1974
1975
1975
1972
1975
1971
1975
1973
1971
1972
1975
1976
1977
1976
1974
1974
By-product
H2S04
H2S04
S
H2S04
H2S04
H2S04
H2SO4
H2SO4
H2SO4
H2S04
H2SO4
H2SO4
S
H2SO4
S
S02
H2SO4
H2S04
H2S04
S
H2SO4
H,SO4
S
H2S04
H2S04
H2SO4
(NH4)2S04
(NH4)2S04
(NH4)2S04
S
S
oo
I
M
OO
3 1,000 Nm3/hr = 590 scfm = 320 MW.
-------
Operation of a magnesium scrubbing system (80,000
3 2
Nm /hr) at Hibi Works, Mitsui Mining was discontinued. A
lime scrubbing system of larger capacity (300,000 Nm /hr)
was constructed to replace it and is now in operation.
Kamioka plant, Mitsui Mining, started operation in 1975
to recover SO from tail gas (50,000 Nm /hr) in a sulfuric
acid plant by zinc oxide scrubbing. Zinc sulfite formed by
the reaction is calcined to regenerate zinc oxide and S0»;
the latter is returned to the sulfuric acid plant. The
process is similar to the magnesium scrubbing process.
Although the calcination temperature is much lower with zinc
(about 350°C) than with magnesia (about 950°C), zinc is
expensive and entails some environmental hazards.
Activated Carbon Process
Tokyo Electric Power operates an activated carbon
process plant at Kashima (420,000 Nm /hr). The S02
absorbed on carbon is washed with water to produce a weak
sulfuric acid, which is treated with limestone to produce
good-quality gypsum. The system has been operated without
trouble for over 2 years. Virtually no carbon has been lost
during the period.
Unitika Co. recently constructed a carbon process
system to by-produce a stronger sulfuric acid (Section 6).
Operation continues at the dry carbon process plant of
Kansai Electric at Sakai, using a moving bed designed by
3-19
-------
2
Sumitomo Heavy Industry (formerly Sumitomo Shipbuilding).
After S0_ absorption, the carbon is heated in a reducing gas
^
to recover a concentrated S02 gas, which is used for sulfuric
acid production. Consumption of the carbon is fairly high
and there is no plan to construct a new system with the
process. Sumitomo has been testing simultaneous removal of
SO., and NO in the process using ammonia (Section 7) .
£* X
Ammonia Scrubbing
Nippon Kokan has developed a process to by-produce
ammonium sulfate from S0» in flue gas and ammonia in coke
2
oven gas and is constructing two commercial plants (Table
3-7). To reduce formation of plume from the scrubber, which
is a common problem with ammonia scrubbing processes, Nippon
Kokan will use an afterburner to raise the temperature of
the treated gas at its Fukuyama plant and a wet electro-
static precipitator at its Ogishima plant.
A small commercial plant to by-produce ammonium sulfate
was completed recently by Kurabo Engineering for a fertilizer
producer (Table 3-7, and Section 6).
Two relatively small units, with ammonia scrubbing,
thermal decomposition of ammonium sulfate, and an IFF
reactor to by-produce elemental sulfur, were constructed by
Mitsubishi Heavy Industries and Toyo Engineering. Both have
had problems, mainly in the decomposition step.
3-20
-------
Shell Process
The SYS system using the Shell copper oxide process has
continued operation (Table 3-7). Tests have been performed
for simultaneous removal of NO by ammonia injection
(Section 7).
BY-PRODUCTS OF FGD
Desulfurization efforts in Japan are oriented toward
processes that yield salable by-products (Figures 3-2 and 3-
3). The reasons are that domestic supplies of sulfur and
its compounds are limited in Japan, as is land for disposal
of useless by-products. About 60 percent of the S0_ is
converted into salable gypsum, 20 percent into sodium
sulfite, 15 percent into sulfuric acid, and the rest into
waste calcium sulfite and sodium and ammonium sulfates.
x
The process that first became popular is sodium scrub-
bing to by-produce sodium sulfite for paper mills. Although
this is the easiest FGD process, by-production of sodium
sulfite will not increase greatly because the supply has
filled the demand and because sodium hydroxide has become
expensive.
The by-product gypsum can be grown into fairly large
crystals useful for wallboard production and as a retarder
of cement setting (Figure 3-4, Photo 3-1). Although the
demand for gypsum decreased last year because of the economic
depression, gypsum will continue to be the major by-product
of FGD.
3-21
-------
10,000
tO
•d
4->
X
4->
•H
O
cd
O 0)
rH
C nj
o o
•H to
-p
O bO
3 O
T) r-l
o »
1,000
100
S(oil desulfurization)
10
1969
1971
1973
1975
1977
Figure 3-2. Production capacity of desulfurization.
80
60
<
0*
o>
o
•H
t-,
20
0
1969
1971
1973
1975
Figure 3-3. Price of by-products.
3-22
-------
Quantity( millions of tons)
o ru ; -P~ <^
-
Demand
ou'
1 B
C
Supply
OS
R
P
"C
c
OS
Fi
(D
Cl
OU
B
C
>>
i-H
fi
O,
T!
to
OS
R
P
-a
i~
05
t:-
U)
«
OU
B
C
>>
r-l
P.
Pi
y
CO
OS
R
o
1970
1973
1975
Demand: C;Cement B:Board OU:Other uses
Supply: P:Phosphogypsum R:Recovered OS;Other sources
Figure 3-4. Demand for and supply of gypsum in Japan
Photo 3-1. Handling of by-product gypsum
(Chiba plant, Showa Denko).
3-23
-------
Sulfuric acid has been produced by the Wellman-Lord and
magnesium scrubbing processes. Elemental sulfur has been
produced in relatively small units in oil refineries by the
Wellman-Lord, Shell, and magnesium scrubbing processes using
Glaus furnaces.
Since FGD has developed rapidly and there is already a
tendency toward oversupply of the by-products, it is desired
to develop new applications. Efforts have been concentrated
on establishing new uses of gypsum, mainly for new construc-
tion materials.
Throwaway calcium sulfite sludge has been produced at
the Omuta plant, Mitsui Aluminum (385,000 Nm3/hr, Photo 3-
2), where the sulfite slurry is discharged into a large pond
and the supernatant is recycled to the scrubber. In two
other smaller plants, the slurry is filtered and discarded.
Even for discarding into a pond, gypsum might be a
better choice than calcium sulfite because it grows into
much larger crystals and readily settles into a much smaller
volume. The Omura plant, Mitsui Aluminum, that has been in
operation since 1972 is going to change the process to by-
produce gypsum because the pond is nearly full. The Wakamatsu
plant, Nippon Steel, and Isogo plant, EPDC, are going to
produce throwaway gypsum.
3-24
-------
Photo 3-2. Calcium sulfite sludge disposal
(Omuta plant, Mitsui Aluminum).
3-25
-------
WASTEWATER AND GAS REHEATING
Wastewater
Most Japanese FGD processes purge wastewater, as shown
in Table 3-8 and Figure 3-5, mainly to prevent the accumu-
lation of impurities, especially chloride, in the circulating
liquor. Chloride, which is derived from fuel and process
water, promotes corrosion, particularly when the liquor
contains more than 1 ppm of oxygen, as shown in Figure 3-6.
Plants using the Kureha-Kawasaki process (Section 4) do
not normally purge any water because the scrubber liquor is
very low in oxygen. Chloride concentrations in the liquor
at those plants has reached 4,000 ppm; the amount of chloride
leaving the system with gypsum which contains 6 to 8 percent
moisture has become equal to that going into the system.
Another process free from wastewater is the Kobe Steel
process (Section 5), which uses a calcium chloride solution
dissolving lime as the absorbent and uses highly corrosion-
resistant materials for construction of system components.
The dry processes are not free from wastewater, except
for the Sumitomo Heavy Industry process, which uses carbon
absorption and thermal regeneration. The Tokyo Electric -
Hitachi and the Shell processes give relatively large
amounts of wastewater because they use wet treatment in the
regeneration steps.
3-26
-------
Table 3-8. WASTEWATER FROM FGD SYSTEMS
Process
Mitsubishi (MHI)
Mitsui-Chemico
Babcock-Hitachi
Chubu-MKK
Showa Denko
Chiyoda
Wellman-MKK
User
Kansai Electric
Kyushu Electric
Chubu Electric
EPDC
Chugoku Electric
Chugoku Electric
Ishihara Chemical
Showa Denko
Hokuriku Electric
Hokuriku Electric
Chubu Electric
Plant site
Hainan
Karita
Owasea
Takasago
' Mizushima
Tamashima
Yokkaichi
Chiba
Toyama
Fukui
Nishinagoya
MW
150
188
750
250
105
500
85
150
250
350
220
Inlet
S02,
ppm
270
600
1,480
1,500
400
1,500
1,300
1,400
610
1,540
1,800
Wastewater
t/hr (A)
1.5
3.7
14.0
5.0
1.5
5.0
3.5
3.5
15.0
24.0
3.0
Gypsum, t/hr
Solid (B)
0.9
2.2
29.0
10.0
0.9
19.5
2.2
5.2
7.5
14.0
Moisture (C)
0.1
0.2
2.9
1.1
0.1
1.9
0.2
0.5
0.7
1.4
Water
ratio
(A+C)
(A+B+C)
0.64
0.64
0.37
0.38
0.64
0.26
0.62
0.45
0.73
0.64
Wastewater
kg/MWhr
10
20
19
20
14
10
41
23
60
68
14
u>
I
NJ
Designed value; the plant has just
Coal-fired boiler. All others are
started operation.
for oil-fired boilers.
-------
600
500
_ 400
a 300 -
£
«/>
I
200
100
0 100 200 300 400 500
FGD Capacity (MW)
Figure 3-5. FGD capacity and amount of wastewater.
1000
100
10
I
0.1
0.01
Crack
No crack
0.1 1 10 100 TOOO
Cl- (ppm)
Figure 3-6. Concentration of O» and Cl~ in solution
and stress corrosion.
3-28
-------
Many states in the United States prohibit the discharge
of wastewater but allow the discarding of calcium sulfite
sludge after filtration; the sludge usually contains 50 to
60 percent water (water ratio 0.5 to 0.6). Although most
Japanese processes purge some wastewater, the amount is
about equal to or even less than that purged by sludge
disposal. The Chiyoda process normally purges a larger
amount of water to prevent corrosion because Chiyoda uses
sulfuric acid saturated with oxygen as the absorbent. The
volume of wastewater can be reduced by using a material with
greater corrosion resistance.
Wastewater is treated to meet regulations. The treat-
ment in most processes is simple, consisting principally of
neutralization and filtration. Some processes, such as the
Wellman-Lord process, require extensive treatment including
ozone oxidation to decompose reducing compounds formed in
the process. After being treated, the wastewater normally
has a pH of 6 to 8.5, contains 5 to 20 mg/liter of SS
(suspended solids), contains less than 10 mg/liter of COD
(chemical oxygen demand), and does not adversely affect the
environment.
Reheating
The temperature of boiler flue gas that has passed
through an air preheater and electrostatic precipitator
normally ranges from 130 to 150°C. Scrubbing in the wet
3-29
-------
processes usually reduces the gas temperature to 50 to 60°C.
In most systems the gas is heated to 110 to 150°C by after-
burning of low-sulfur oil. Although afterburning is the
easiest way to reheat stack gas, the oil requirement reaches
3 to 5 percent of that used for the boiler. Afterburning
not only is somewhat costly but adds SO- and dust to the
cleaned gas.
A few companies have made tests on reheating the gas
using a gas-steam heat exchanger. Corrosion of the heat
exchanger tubes is the major problem, particularly when the
scrubber liquor is rich in chloride. Commercial use of such
heat exchangers will start soon.
ECONOMIC ASPECTS OF FGD SYSTEMS
Among the various FGD processes, the sodium scrubbing
process that by-produces sodium sulfite is the simplest and
also the least expensive. The second cheapest, the throw-
away wet-lime process, requires a large disposal pond. A
system based on the wet lime-gypsum process costs about 25
percent more than one using the throwaway process, but does
not require a pond.
Examples of plant cost in battery limits are shown in
Table 3-9. The cost rose sharply until the middle of 1975
because of inflation and the active demand for FGD units,
but has since lowered considerably. Generally speaking, a
3-30
-------
U)
I
U)
Table 3-9. PLANT COST IN BATTERY LIMITS ($1 = ¥300)
(The cost nearly tripled in late 1973 and has decreased considerably since late 1975)
Process
Wellman-MKK
Sumitomo S.B.
Chemico-Mitsui
Hitachi-Tokyo E.P.
Wellman-MKK
Shell
Chubu-MKK
Chemico-Mitsui
Mitsui-Chemico
Mitsubishi (MHI)
Kureha-Kawasaki
Chiyoda
Babcock-Hitachi
Wellman-MKK
Absorbent
Na2S03
'Carbon
Ca(OH)2
Carbon
Na2S03
CuO
CaC03
MgO
CaC03
CaO
Na2S03
H2S04
CaCO3
Na2S03
By-product
H2S04
H2S04
Sludge
Gypsum
H2S04
S02
Gypsum
S02
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
H2S04
Capacity,
MW
70
55
128
150
220
40
89
180
250
188
450
350
500
160
Plant cost
M $
2.6
2.8
3.3
5.6
7.0
3.3
2.6
13
16
11.5
32
26
35
20
$/kW
37
51
26
39
32
83
29
72
64
61
71
74
70
125
Year
completed
1971
1971
1972
1972
1973
1973
1973
1974
1974
1974
1975
1975
1975
1975
-------
wet lime-gypsum process unit (200-300 MW) now costs $45 to
$60/kW in batterly limits; system based on the indirect
lime/limestone process costs 5 to 30 percent more, and one
using sulfuric acid by~production processes costs 30 to 70
percent more than the wet lime-gypsum process.
Examples of FGD costs for removal of 90 to 95 percent
of the SO,, by the wet lime-gypsum process are shown in Table
3-10. The cost is about $14 to $17/kl oil or 3.0 to 3.6
mil/kWh for different sizes of unit, based on 7 years
depreciation and 7,000 hours yearly operation. As the fixed
cost is greater than the running cost, the FGD cost is
largely influenced by years of depreciation and by operating
hours.
Capital cost of the wet limestone-gypsum process may be
slightly higher than those of the lime-gypsum process, but
operating costs are slightly lower. Indirect lime/limestone
processes usually cost 5 to 20 percent more than does the
lime-gypsum process. Sulfuric acid by-producing processes
cost 20 to 30 percent more.
The current per-kiloliter price of heavy oil is about
$75 for high-sulfur oil (S=3%) and $100 for low-sulfur oil
(S=0.3%). Therefore, FGD is more economical than the use of
low-sulfur oil (Table 1-6).
3-32
-------
Table 3-10. EXAMPLES OF FGD COST WITH WET
LIME-GYPSUM PROCESS
(7 years depreciation, 7,000 hours full-load operation
per year. Oil consumption: 150,000 kl/100 MW/year,
S: 2.8%, 90% removal. Reheating to 110°C).
Investment cost, $1,000
Fixed cost, $l,000/year
Depreciation
Interest, Insurance
Total
Running cost, $l,000/year
Lime (at $30/t)
Oil for reheating (at $100/kl)
Power (at 3C/kWh)
Labor
Maintenance
Other requirements
Gypsum (at $5/t)
Total
Total annual cost, $1,000
Desulfurization cost, $/kl
Desulfurization cost, mills/kWhr
100 MW
6,600
940
470
1,410
230
450
400
50
100
20
-120
1,130
2,540
16.9
3.6
500 MW
27,000
3,860
1,930
5,790
1,140
2,230
1,840
50
300
60
-610
5,010
10,800
14.4
3.0
3-33
-------
Flue gas desulfurization (FGD) is less expensive than
hydrodesulfurization (HDS) at higher sulfur removal ratios
(Table 2-4), but HDS is advantageous in that it produces
elemental sulfur, which is a desirable by-product. In Japan
and elsewhere, other processes yielding sulfur as a by-
product seem much more expensive than HDS, except for oil
refineries that have Glaus furnaces for sulfur production.
3-34
-------
4. MAJOR NEW FGD SYSTEMS FOR UTILITY BOILERS
STATUS OF FGD BY POWER COMPANIES
Table 4-1 lists power companies and their capacities
for steam power generation and FGD. The nine major com-
panies (Nos. 1 to 9 in the Table) have produced about 70
percent of the total steam power using mainly oil, with some
LNG and a little coal. Electric Power Development Co.
(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 have relatively small capacities,
burning mainly oil. Total capacity of the power generation
plants, including those under construction and planned for
construction, is 86,457 MW. The capacity of FGD systems in
operation is 6,040 MW and that of systems under construction
and being designed is 6,755 MW.
Among the major power companies, Tokyo Electric, Kansai
Electric, and Chubu Electric, which supply power to the
largest cities and industrial complexes in Japan, have
relatively small capacities of FGD, with a B/A ratio (see
Table 4-1) of only 1 to 7 percent. Those companies prefer
4-1
-------
Table 4-1. CAPACITIES OF STEAM POWER GENERATION AND FGD OF POWER COMPANIES
No.
1
2
3
4
5
6
-
8
S
10
11
12
13
14
15
16
17
18
Power generation, MW
Under
Pcwei company Existing ! construction3
Hokkaido
Tocal (A)
1,270 1,225 2,495
•''ohoku 3,925
FGD, MW
Under
Existing construction3
0
1,200 5,125 275
Tokyo ! 19,167 4,490 23,567 ' 283
525
625
0
i ' 1
Chubu ?,933
"okuriku 1,412
Kar.sai
Cnugoku
Shikoku
10,672
3,300 13,733 970
1,000
1,200
3,777 1,300
2,687 450
Kyushu I 4,500 2,700
2,412 600
11,872
362
Q
500
469
5,777 950 1,100
3,137 ! 900 0
7,200 183
EPDC I 1,430 0 1,430
Kiigata ! 350 350 700
Shcwa
Toydima
550 0 550
750
0
Kizushiina 462 0
i
Suni-toTno j 363
Sakata 0
Fukui 0
Others
Total
5,512
780
175
150
1
750 250
462
156
1,438
500
175
250
0
0
250 : 618 0 i 218
700 700
0 j 700
1 ;
250
375
66,775 19,700
250 0 ' 250
5,887
85,475
0 0
6,040
6,755
Total (B)
525
900
0
Q "* 0
1,100
838
2,050
900
1,526
1,230
350
400
250
156
21S
700
250
0
: 12,795
3/Ab
21.0
17.6
1.2
7.1
45.6
7.1
36.8
12.5
22.6
89.5
50.0
72.7
33.3
33.8
! 35.3
100.0
100.0
0.0
14.8
Ir.clucing those decided to be constructed.
0 Capacity being scrubbed over total capacity.
-------
use of low-sulfur fuels such as naphtha and LNG in polluted
areas, because they believe that the regulation on S0_
emission for those areas may become too stringent to be
achieved by FGD. According to the recent regulation restric-
ting total mass emissions of S02, large power plants in the
designated regions are required to keep S02 in flue gas
below about 50 ppm, as described in Section 1. Although it
is not difficult to reduce SO- from 1,500 ppm to 50 ppm by
FGD, sulfur-free fuel is needed to reheat the treated gas.
For plants to be constructed in regions to which much more
stringent restriction is applied, FGD may entail some
difficulty. On the other hand, Hokuriku Electric and
Chugoku Electric, which have power plants remote from big
cities, have larger B/A ratios (refer to Table 4-1).
FGD installations of power companies are listed in
Table 4-2. Before 1973 power companies were not yet con-
fident about the usefulness of FGD and therefore constructed
test units to treat one-third to one-fourth of the gas from
a boiler burning low-sulfur fuel; other industries that had
difficulty in obtaining low-sulfur fuel constructed many FGD
systems and demonstrated their reliability. The first
commercial-scale FGD system for a utility boiler burning
high-sulfur fuel was the Nishinagoya plant, Chubu Electric
Power (200 MW, 620,000 Nm /hr) based on the Wellman-Lord
4-3
-------
Table 4-2. FGD SYSTEMS OF POWER COMPANIES
(Oil-fired boilers unless otherwise indicated)
Power
company
Tohoku
Toky<3
Chubu
Hokuriku
Kansai
Chugoku
Shikoku
Power station
Boiler
No . 1 MW
Sinsendai \ 2
FGD
MW
Process developer
600 150 : Kureha-Kawasaki
Hachinohe i 4 j 250 125
Niiaata 4 | 250
\iigata H.
Akita
Kashima
Vokcsuka
Nishinagoya
Ow? 3 e
Owase
Toyarna
Fukui
Nanao
Sakai
Amagasaki
Amagasaki
Amagasaki
Osaka
Osaka
Osaka
Kainan
Mizushina
Tamashiraa
Tamashiraa
Snimor.oseki
Anan
Sakaide
1 600
3 350
Mitsubishi H.I.
125 Kellr-.ar.-MKK
150
Mitsubishi H.I.
Absorbent,
precipitant
By-product
Xa2S03, C?.C03 i Gypsum
CaO Gypsum
Nc2SC>3 H2SO£
CaC03 Gypsum
350 Kureha-Kawasaki i N32S03, CaCOi
Gypsum
3 '! 600 ' 350 i Kitachi-Tokyo Caxbcr. , CaC03 Gypsum
i 265 • 133 Mitsubishi H.I.
1 ! 220
1 375
2 375
220
375
375
1 500 250
Wellman-KKK
Mitsubishi H.I.
Mitsubishi H.I.
Chiyoda
C?.C03 Gypsum
Na2S03 K2S04
CaO Gvpsum
CaO
Gypsum
H2SO4 , CaC03 Gypsum
1 350 350 Chiyoda | H2S04, CaC03
l
500
500 Not decided
8 250 63
2
1
3
2
4
4
2
3
2
2
3
3
156
156
156
35
121
156
Gypsum
Gypsum
Sumitomo H.I. Carbon
Mitsubishi H.I.
Mitsubishi H.I.
Mitsubishi H.I.
156 Babcock-Hitachi
156 156 Babcock-Fitachi
156 : 156
600 150
156
500
350
400
450
450
100
500
350
400
Babcock-Hitachi
Mitsubishi K.I.
Babccck-Hitachi
Babcock-Hitachi
Babcock-Hitachi
Mitsubishi H.I,
450 Kureha-Kawasaki
450
Kureha-Kawasaki
CaO
CaO
CaO
CaC03
CaC03
H2S04
Gypsur,
Gypsum
Gypsum
Gypsum
Gypsum
CaC03 Gypsum
CaO
Gypsum
CaC03 i Gypsum
CaC03 i GvDSUm
CaC03
CaCC3
Na2S03( CaC03
Gypsum
Gypsum
Gypsum
Na2S03, CaC03 Gypsur.
Year of
coir.pletion
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
1975
1975
-------
I
U1
Table 4-2 (continued). FGD SYSTEMS OF POWER COMPANIES
(Oil-fired boilers unless otherwise indicatedl
Power
conpany
Kyushu
E?DC
Niigata
Showa
Toyarna
Mizushima
Sumitomo
Sakata
Fukui
Power station
Karita
Karatsu
Karatsu
Ainoura
Air.oura
3u22n
3uzen
Takasago
Takasago
Isogo
Isogo
Takehara
Niigata
Ichihara
Ichihara
Toyama
Mizushima
Niihama
Sakata
Fukui
Boiler
No . MW
2 375
2 375
2 500
1 375
2 500
1 500
2 500
1 250a
2 2503
1 265a
2 265a
1 250a
1 350
1 150
5 250
1 250
5 156
3 156
1 350
2 350
1 250
FGD
MW
138
183
230
250
250
250
250
250
250
265
265
250
175
150
250
250
156
156
350
350
250
Process developer
Mitsubishi H.I.
Mitsubishi
Mitsubishi
Mitsubishi
Mitsubishi
Kure'na- Kawasaki
Kureha-Xawasaki
Mitsui-Chemico
Mitsui-Chemico
Chenico-IHI
Cheniico-IHI
Babcock-Hitachi
MKI
Showa Denko
Babcock-Hitachi
Chiyoda
Mitsubishi H.I.
IHI
Mitsubishi H.I.
Mitsubishi H.I.
Not decided
Absorbent,
precipitant
CaO
CaCC>3
CaC03
CaC03
CaC03
Na2SOT, CaC03
Xa2S03, CaC03
CaC03
CaC03
CaC03
CaC03
CaC03
CaC03
Na2S03, CaC03
CaC03
H2S04 , CaCO3
CaO
CaC03
CaC03
CaC03
CaC03
By-product
Gypsum
Gypsum
Gyp sura
Gypsum
Gypsum
Gyp sun
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Gypsum
Year of
completion
1974
1976
1976
1976
1976
1S77
1978
1975
1976
1976
1976
1977
1975
1973
1976
1975
1975
1975
1976
1977
1977
Coal-fired boilers.
-------
process. The system has been operated smoothly at more than
97 percent operability- As regulations on wastewater have
become increasingly stringent, however, wastewater treatment
has posed a serious problem in the Wellman-Lord process.
Since 1973, power companies have constructed many full-
scale FGD systems for utility boilers (250-500 MW) burning
high-sulfur fuel (2.5 to 3 percent sulfur) using processes
that produce gypsum. Processes and performance of several
new FGD systems are described below.
In addition to the systems described in this section
two units at Isogo Station, Electric Power Development Co.,
started operation very recently. These systems have a unit
capacity of treating 900,000 Nm /hr of flue gas from a coal-
fired boiler using the Chemico-IHI process; no additional
details are available.
PLANTS USING THE MHI LIME-GYPSUM PROCESS (MITSUBISHI-JECCO
PROCESS)
g
Karita Plant, Kyushu Electric
The Karita plant, with a capacity of treating 550,000
Nm /hr of flue gas from an oil-fired boiler (188 MW equiva-
lent) , went into operation in November 1974. The plant is
based on the single-absorber system (Figure 4-1, Photo 4-1) and
uses lime. Flue gas is first cooled to 55 to 60°C in a
cooler and led into the plastic-grid-packed absorber. S02
concentration at the absorber inlet ranges from 400 to 600
4-6
-------
E.P.
COOLER
WATER—
LIME
WASTEWATER
TREATMENT SYSTEM
ABSORBER
MIST
ELIMINATOR
REHEATER
STACK
FAN
Q TT
FAN FUEL
H2SO<,.
w
T
AIR
CENTRIFUGE
MILL LIME SLURRY
pH
ADJUSTING
GYPSUM FILTRATE
Figure 4-1. One-absorber system of MHI process.
-------
ppm and at the outlet from 10 to 30 ppra. A lime slurry, at
pH 6.4, 10 percent concentration is fed to the scrubber at
an L/G ratio of 10. About 1,05 stoichiometry of lime is
used. Space velocity (superficial gas velocity) of gas in
the scrubber is 3.5 m/sec. Pressure drop through the cooler,
absorber, and mist eliminator is 120 mm H~0. Utility
3
requirements at full load (550,000 Nm /hr) are shown in
Table 4-3.
Table 4-3. REQUIREMENTS AT THE KARITA PLANT
Power , kW
Steam, t/hr
Industrial water, t/hr
Oil for reheating, t/hr
Lime, t/hr
Sulfuric acid, t/hr
Wastewater, t/hr
By-product gypsum, t/hr
Sulfur in fuel, %
1.2
3,200
1.5
3.0
2.0
1.1
0.2
3.5
2.9
0.8
3,200
1.5
3.0
2.0
0.8
0.13
3.5
2.0
As a little excess of lime is used to ensure high SO-
removal efficiency by a single absorber, a considerable
amount of sulfuric acid is needed to lower the pH of the
calcium sulfite slurry to promote the oxidation of gypsum.
4-8
-------
Photo 4-1. Karita plant, Kyusha Electric (188P4W) .
Photo 4-2. Owase Plant, Chubu Electric
(2 units each 375 MW).
4-9
-------
The load fluctuates between 550,000 and 300,000 Nm /hr
every day- The flow rate of the slurry is kept constant,
while the amount of lime is adjusted with the load.
The plant has been operated at 100 percent availability
since start-up, except for a scheduled shutdown of the
boiler from April 1 to May 14, 1975 (Figure 4-2). On
February 24, 1975, a flow-rate-adjusting bulb was stopped up
but was repaired without interrupting scrubber operation.
In the inspection of April 1975, considerable scaling was
found on the mist eliminators. The eliminators had been
washed with circulating liquor; since May 1975, in an effort
to reduce scaling, they have been washed alternately with
the liquor and fresh water. Water balance is shown in
Figure 4-3.
Other Plants
Two new units (175 and 250 MW) using the MHI process
with limestone have started operation recently at the
Karatsu station, Kyushu Electric, and two new units (375 MW
each) using lime have started at the Owase station, Chubu
Electric (Photo 4-2). Operating parameters are shown in
Table 3-5.
2
The units at Owase have a two-tower system. S02
concentration is reduced from- 1,600 ppm to 30 ppm using
slightly less than the stoichiometric amount of lime (Table
4-10
-------
Jt 600
P<
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o
_j
•n
2 500
-p
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o
a
o
„ 400
100
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- 2 so
(M
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to
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20
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H
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PQ
-
-
_
-
1974
Dec.
f
x"6 oiler
load
A-
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^'
wt
1975
Jan.
SO 2
"^^"V^r-
(#) \
-*•*:*
Inlet
S02(ppm
_ JK
^*N ,
V
Outlet
S02(ppm
Feb.
removal
M- • — •-
/ \
* i-
\ /
\ /
\ i
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Mar.
(°5-*— *•
^--^
-X'
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"X
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•"•^
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shutdown
- —
May
-~-« — •-
^
i
1
i
• /A
-^^^ /
^7--*;
^ 1
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.1
1 *
^•"*^
June
SO 2
Boiler
N -X
^* ~
X \
\
1
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v v
* V
Xv
'X ^
V-'
July
removal
~>^ »-
load(^)x
r*-
*
/
i
*
^'' >"
^
••*.'
t
t
V
.-«-
— *" v»-
Outlet
S02(ppm)
Aug.
(#>
^ — •
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A. X
» *
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AV
\
V^
A— -A
Inlet
S02(ppm)
.-« — •
Average
95.8
87.3
X---
503
A —
20
Figure 4-2. Operation data fo Karita plant, Kyushu Electric.
-------
Industrial
water
(19.67mVhr)
Cooling
Pump seal
Mist eliminator
Pump seal
i.JflmVhr)
Filtered
water
(6.71mVhr)
Fan cooling
" Evaporation
(21.21mVhr)
' Wastewater
(3.71mVhr)
To gypsum
•^ x
(0.l6mVhr)
Evaporation
(.30mVhr)
Figure 4-3. Water balance (Karita plant, MHI process)
4-12
-------
3-5) at a pressure drop of 200 mm HO. No sulfuric acid is
required because about 99 percent of the lime reacts and the
pH of the calcium sulfite solution is lowered considerably
by the use of two absorbers and also by the high concentra-
tion of S02 at the inlet.
MITSUI-CHEMICO LIMESTONE-GYPSUM PROCESS AT THE TAKASAGO
PLANT, ELECTRIC POWER DEVELOPMENT CO.2
Process and Plant Design
This plant is based on the Mitsui-Chemico process
developed by Mitsui Miike Machinery Co. It is the first
Mitsui-Chemico process unit to be used commercially for a
coal-fired utility boiler, and has a capacity of treating
840,000 Nm /hr flue gas from a 250 MW boiler. The plant
consists of two single-stage Chemico scrubbers placed in
series, a pH controller to reduce the pH of the calcium
sulfite slurry by introducing the flue gas, and two reactors
for oxidation of the sulfite to gypsum by air (Figure 4-4,
Photos 4-3 and 4-4). A catalyst is used to promote both SO-
removal and oxidation. The flue gas containing 1,500 ppm
S0~ and 80 mg/Nm dust is passed through an electrostatic
precipitator and the FGD unit to remove 90 percent of the
SO- and 75 percent of the dust. Limestone, 95 percent under
325 mesh, is the absorbent. The operating parameters are
shown in Table 3-5. Specifications of the principal equip-
ment are shown in Table 4-4.
4-13
-------
i
h-
y .
REH EATER
JT
0 u -i IJ
li
r
!ti li
U
li
H II
A
FAN FAN
ABSORBER
-S-
CH
CaC05
V
f» — m
WATER
l-o
i-o
ABSORBER
THICKENER
AIR
pH ADJUSTING REACT0^-o REACTOR
BLOWER
-------
Photo 4-3. Takasago plant, EPDC (250 MW)
(scrubber and reactors).
Photo 4-4. Takasago plant, EPDC (250 MW)
(Gypsum centrifuge and storage).
4-15
-------
Table 4-4. MAIN EQUIPMENT AT TAKASAGO PLANT
Equipment
Type and dimensions
Limestone tanks
Absorber (1st)
Absorber (2nd)
Forced draft fans
Circulation pumps
For 1st absorber
For 2nd absorber
pH adjusting tower
Reactors (oxidizers)
Blowers for oxidizers
Centrifuges
Reheating furnaces
1,000 t x 2
Venturi 11.5 m 0 x 20 m
Venturi (double throat)
14 m 0 x 23 m
(12,300 m3/min, 1,900 kW) x 2
135 kW x 4
200 kW x 5
Venturi 6 m 0 x 16 m
6 m 0 x 18 m, 2 units
(110 Nm3/hr, 1,000 mm H2O,
250 kW) x 3
(solid 1.5 t/hr) x 7
(oil 625 liter/hr) x 4
Performance
The plant started up in January 1975 and has since
operated well except for several brief shutdowns to clean
the mist eliminators. The eliminators are washed with the
circulating liquor and fresh water. System availability
reaches 98 percent. The load fluctuates between 170 and
250 MW daily. The slurry flow rate in the scrubbers is
kept constant.
4-16
-------
The daily requirements for operation are as follows:
CaCO., - 118 tons
Power - 136,000 kWh
Oil - 41 liters (reheating)
Steam - 13 tons (heating of oil)
Industrial water - 1,200 tons
Catalyst - $350
The coal contains about 500 ppm chloride. To keep the
chloride concentration of the scrubber liquor below 7,000
ppm, about 5 ton/hr of wastewater is purged. The relation-
ship between the amount of purge water and the chloride
concentration of coal and equilibrated scrubber liquor is
shown in Figure 4-5.
To prevent promotion of corrosion by chloride, a plastic
or rubber lining and a high-grade stainless steel are used.
Another plant with the same capacity is near completion
v
at Takasago. The new plant has one reactor instead of two,
as at the plant just described.
BABCOCK-HITACHI PROCESS AT THE TAMASHIMA PLANT, CHUGOKU
ELECTRIC8
2
Process Description
Hitachi Ltd. constructed a plant (500 MW full scale)
using Babcock-Wilcox scrubbers and an oxidizing system to
by-produce gypsum (Figure 4-6, Photos 4-5 and 4-6). Lime-
stone, more than 95 percent under 325 mesh as shown in Table
4-17
-------
15
10
0)
to
fn
3,000ppm
5,000ppm
8,000ppm
12,000ppm
WO 800
Chloride in coal (ppm)
1,200
Figure 4-5. Purge water and chloride concentration,
4-18
-------
MILL
1: COOLER 2: ABSORBER 3: MIST ELIMINATOR
Figure 4-6. Flowsheet of Babcock-Hitachi process.
-------
Photo 4-5. Tamashi^a Plant, Chugoku Electric (500 MW,
Photo 4
-6. Tamashima Plant, Chugoku Electric (500 MW)
4-20
-------
4-5, is used as the absorbent at a stoichiometry of 1.05 to
1.10. Four scrubbers were installed, of which three are in
use and one is for standby- Flue gas from an oil-fired
boiler, with an S02 concentration of 1,500 ppm, is first
cooled to 55°C in venturi scrubbers and then led into ab-
sorbers with six stages of perforated plates, which remove
about 95% of the SO,,.
£t
The L/G ratio is 2.1 (liters/Nm ) in the venturi and 10
in the absorber. The pH of the slurry is 5.5 in the venturi
and 6 to 6.2 in the absorber. The pressure drop is fairly
heavy 230 mm H-O in the venturi and 600 mm in the absorber.
A calculation indicates that 99 percent S0~ removal efficiency
may be achieved at a total pressure drop of 1,300 ppm in the
venturi and the absorber. Mist eliminators are of a new
type designed by Hitachi for easy washing.
Table 4-5. COMPOSITION OF LIMESTONE
(Percent)
Specification
Actual
CaO
>55
55
Si02
<0.3
0.3
A1203
<0.1
0.1
Fe203
<0.1
0.1
MgO
<0.6
0.5
The calcium sulfite sludge discharged from the bottom
of the venturi at pH 5.5 is sent to a reactor, where sulfuric
acid is added to decompose the unreacted limestone and to
lower the pH to 4.7. The slurry is sent to three oxidizers
4-21
-------
in parallel and is oxidized by air bubbles generated by
rotary atomizers. More than 97 percent of the calcium
sulfite is oxidized to gypsum. The gypsum contains 7 to 8
percent moisture after being centrifuged and is used in the
manufacture of wallboard and cement.
Performance
The plant came on-stream in July 1975 and has been used
for base-load operation. Power consumption reaches 3.6
percent of the power generated. Small amounts of scale tend
to form in some parts of the scrubber, which occasionally
becomes dislodged and plugs the spray nozzles. The strainers
of the circulation pumps have been improved, and operability
(percentage of FGD operation hours to boiler operation
hours) has reached 97 percent.
About 93 t/hr of industrial water is used, of which 13
tons are used for washing the mist eliminator. At the
beginning of the operation., about 5 t/hr wastewater was
purged to keep the chloride concentration of the circulating
liquor below 1,000 ppm. Use of wastewater has been sub-
stantially reduced recently.
Composition of Slurry
Solids in the slurry in the absorber circulating tank
consist of calcium sulfite, 50 to 60 percent; gypsum, 40 to
50 percent; and limestone 5 percent. The relation between
4-22
-------
the pH of the slurry in the reactor (pH adjusting tank) and
the composition of solids in the slurry after the oxidation
is shown in Figure 4-7. When a slurry at pH 5.5 was oxi-
dized without adding sulfuric acid, the oxidation ratio was
about 80 percent. The product, consisting of about 80
percent gypsum and 20 percent calcium sulfite, has proved
useful as a retarder of cement setting.
KUREHA-KAWASAKI SODIUM-LIMESTONE PROCESS AT THE SAKAIDE
PLANT, SHIKOKU ELECTRIC
Process
The Sakaide plant went in operation in August 1975 with
a capacity of treating 1,260,000 Nm /hr of flue gas con-
taining 1,050 ppm SO2 from a 450 MW oil-fired boiler (Photos
4-7 and 4-8). The process is similar to that for Shinsendai
plant, Tohoku Electric (Figure 4-8). Flue gas from the 450
MW oil-fired boiler, passed through an electrostatic precipi-
tator by a forced-draft fan, is fed into a venturi-type
precooler and then into a grid-packed-type scrubber, where
the gas is washed with a sodium sulfite solution (about 20%)
at pH 7.0 and an L/G ratio of nearly 10 (about 70 gal/1,000
scf). The gas is then passed through a mist eliminator,
reheated by an afterburner, and ducted into a stack.
The liquor discharged from the scrubber at pH 6.5 is
passed through a series of five reactors, where powdered
limestone, ground in a vertical tower mill to pass 325 mesh,
is reacted to precipitate calcium sulfite and regenerate
sodium sulfite.
4-23
-------
o
•H
4J
•H
to
O
ft
B
O
o
•H
rH
O
100 .
80
60
20
0 L
Gypsum
Calcium
4.7 5.0
pH (reactor)
/Limestone
5.5
Figure 4-7 Relationship of pH of slurry in reactor to
solid composition after oxidation
4-24
-------
CENTRIFUGE
Figure 4-8. Flowsheet of Kureha-Kawasaki process.
-------
Photo 4-7. Sakaide plant, Shikoku Electric (450 MW)
(two scrubbers in parallel)
Photo 4-8. Sakaide plant, Shikoku Electric (450 MW)
(Oxidizers and stripper)
-------
2NaHSO3 + CaC03 - Na2S03 + CaSC>3 +
The pH of the slurry at the outlet is 7.3. The calcium
sulfite (50% slurry) is separated on a vacuum filter and
washed to remove sodium sulfite. The filter cake (about 60%
water) is repulped to 10 percent slurry, treated with
sulfuric acid to reduce pH, and oxidized by air bubbles in
an oxidizer (at 2 atmospheres of pressure) developed by
Kureha and Kawasaki. The gypsum slurry is centrifuged to
less than 8 percent moisture; the separated liquid is
recycled to repulp the calcium sulfite.
A portion of sodium sulfite is oxidized to sulfate in
the scrubber by oxygen in the flue gas. A side stream of
liquor from the scrubber is treated to decompose the
sulfate by reaction with sulfuric acid and calcium sulfite.
Na2SO4 + 2CaS03 + H2S04 + 4H20 = 2 (CaS04 • 2H20) + 2NaHSC>3
The slurry from the desulfation unit is filtered, and
the gypsum is sent to the oxidizer as seed to obtain well-
grown gypsum crystals; the separated sodium bisulfite
solution is passed through a steam-heated stripper to
generate SO-, which is recycled to the desulfation step to
reduce sulfuric acid consumption and then sent to the reactor,
A main difference from the Shinsendai plant is that
the Sakaide plant incorporates a unit to remove magnesium
from the circulating liquor. Magnesium derived from lime-
stone tends to accumulate in the circulating liquor and
4-27
-------
delay the reaction of limestone with sodium bisulfite. A
portion of the liquor from the gypsum centrifuge is reacted
with sodium sulfite solution from the stripper to precipitate
magnesium sulfite, which is filtered off. The filtrate is
mixed with the liquor discharged from the scrubber.
MgS04 + Na2SO3 + 6H2<3 -> Mg^O^ei^Q + Ha2SC>4
Another difference in the two plant operations is that
here the gypsum is washed with water to reduce the sodium
content as needed for use in wallboard production.
p
Performance
Operation parameters are shown in Table 3-5. More than
99 percent of the S0» is removed by sodium sulfite scrubbing.
Operation has been smooth since start-up. The load fluctu-
ates daily between 1,260,000 and 534,000 Nm3/hr. The sodium
sulfate concentration of the circulating liquor has reached
11 to 12 percent, exceeding the design value of 8 percent,
but a high S02 recovery ratio has been attained. This unit
is characterized by the absence of water purging from the
system. At full-load operation, 63.5 t/hr water is charged,
of which 29.9 tons is used for gypsum wash. The same amount,
63.5 tons, leaves the system, of which 62.0 tons is evapo-
rated and the rest is contained in the by-product gypsum.
Chloride concentration of the circulating liquor has reached
3,500 ppm but has caused no corrosion problem because the
4-28
-------
liquor contains little oxygen, which tends to cause stress
corrosion in the presence of excess chloride. In the
Kureha-Kawasaki process, oxidation is carried out with the
calcium sulfite separated from the mother liquor, and there-
fore the oxygen content of the liquor is kept low. The
chloride input from fuel and water and the output with
gypsum containing 7 to 9 percent moisture appear to have
equalized at the 3,500 ppm concentration level.
CHIYODA PROCESS AT THE FUKUI PLANT, HOKURIKU ELECTRIC
Process Description
A flowsheet of the Chiyoda process is shown in Figure
4-9. Flue gas is first treated by a prescrubber to eliminate
dust and to cool the gas to 50°C. The cooled gas is led
into a packed tower absorber containing 2-inch Tellerette.
Dilute sulfuric acid (2 to 5% H-SO.), which contains ferric
ion as a catalyst and is nearly saturated with oxygen, is fed
to the packed tower. About 90 percent of the S02 is
absorbed and partly oxidized into sulfuric acid.
The product acid is led to the oxidizing tower, into
which air is bubbled from the bottom to complete the oxida-
tion. Most of the acid at 50 to 60°C, saturated with
oxygen, is returned to the absorber. Part of the acid is
treated with powdered limestone (74% under 200 mesh) to
produce gypsum. A special type of crystallizer has been
4-29
-------
I
U)
O
Crystal-
Figure 4-9. Flowsheet of Chiyoda process.
-------
developed to obtain good gypsum with crystals ranging from
100 to 500 microns. The gypsum is centrifuged from the
mother liquor and washed with water. The product gypsum is
of good quality and salable.
The mother liquor and wash water are sent to the
scrubber. A small amount of wastewater is discharged in
order to prevent corrosion caused by the accumulation of
chloride in the circulating liquor.
Performance
The Fukui plant (Photos 4-9 and 4-10) has operated
smoothly since its start-up in the summer of 1975, treating
1,050,000 Nm /hr of flue gas from a 350 MW oil-fired boiler.
The plant has a double-cylinder-type absorber-oxidizer.
Operating parameters are listed in Table 3-5. The require-
ments are 150 t/day of limestone, 3.8 m /hr of oil for
reheating, 11.8 MW of electric power, and 2,000 t/day of
industrial water. About 580 t/day of wastewater is purged
after being treated to keep the pH at 7.9, suspended solids
below 5 mg/liter, and COD below 10 mg/liter. Plant opera-
tion requires only two operators per shift.
4-31
-------
Photo 4-9. Fukui plant, Hokuriku Electric (350 MWl
Photo 4-10. Fukui plant, Flokuri ku Electric (350 MW)
4-3,2
-------
5. FLUE GAS DESULFURIZATION IN THE STEEL INDUSTRY
INTRODUCTION
Many desulfurization units have been installed since
1971 to treat flue gas from iron-ore sintering plants, which
constitute the major source of S02 emissions in the steel
industry (Table 5-1) . As the absorbent, a lime slurry is
used by Kawasaki Steel (MHI process), a limestone slurry by
Sumitomo Metal (Sumitomo-Fujikasui Moretana process), slurry
of pulverized converter slag by Nippon Steel (SSD process),
and a calcium chloride solution dissolving lime by Kobe
Steel (Cal process). All of these systems by-produce gypsum.
Nippon Kokan uses ammonia scrubbing to by-produce ammonium
2
sulfate or gypsum by reacting lime with the sulfate.
By 1977, 22 FGD systems will be in operation, with a
total capacity of treating 13,800,000 Nm /hr (8,120,000 scfm)
of flue gas, which is about half the total gas from all
sintering plants in Japan.
Flue gas from sintering plants is characterized by a
high 02 concentration (12 to 16%) , a relatively low SO-
concentration (200 to 1,000 ppm), and a dust rich in ferric
oxide. Oxidation of sulfite into sulfate occurs in the
scrubbers much more readily than with flue gas from a boiler,
5-1
-------
Table 5-1. SO0 REMOVAL INSTALLATION FOR WASTE GAS FROM IRON-ORE SINTERING MACHINES
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 Nm3/hr
120
320
650
750
900
750
880
1,000
1,000
370
720
175 x 2
375
1,000 x 2
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
CaC03
CaC03
CaC03
CaC03
CaCO3
Ca(OH)2
Ca(OH)2
Ca(OH)2
Ca(OH>2
Slag
Slag
NH3, CaO
NH3a
NH3a
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
12,000b
20,000b
Ul
Ammonia in coke oven gas.
Ammonium sulfate.
-------
because the oxidation is promoted by the high 0~/SO~ ratio
and also by the catalytic action of the ferric oxide.
This section will describe mainly the lime and limestone
processes, discussing the dimensions and performance of the
FGD systems.
MHI PROCESS AT THE MIZUSHIMA PLANT, KAWASAKI STEEL
FGD System For No. 4 Sintering Machine
Kawasaki Steel installed FGD systems first at its Chiba
Works, using the lime-gypsum process developed by Mitsubishi
Heavy Industries. Satisfied with operation of these systems,
Kawasaki Steel introduced larger FGD systems at its Mizushima
Works, where they operate four iron-ore sintering machines
with a unit capacity of 8,000 to 15,000 t/day. The No. 4
machine gives 350,000 to 750,000 Nm /hr of waste gas at
about 150°C containing 500 to 1,000 ppm SO_ and about 13.5
percent O2-
The flowsheet of the FGD system is similar to that
shown in Figure 4-1. The gas is first cooled to 57°C in a
cooler with water sprays and led into a plastic-grid-packed
absorber, where it is treated with a lime slurry at pH 6.4
3
to 7.5 at an L/G ratio of 7 liters/Nm (about 50 gallons/
1,000 scf) to remove more than 90 percent of the S02- The
treated gas passes through a mist eliminator, is heated to
about 140°C by afterburning, and sent to a stack. A calcium
5-3
-------
sulfite slurry discharged from the absorber is acidified to
pH 4 by addition of sulfuric acid, then is led into an
oxidizer and oxidized into gypsum by air bubbles generated
by a rotary atomizer. The gypsum slurry is sent to a thick-
ener and then is centrifuged to less than 10 percent moisture.
The by-product gypsum is sold as a retarder of cement
setting. The liquor from the centrifuge is returned to the
thickener; the thickener overflow is returned to the absor-
ber after lime is added.
A portion of the circulating liquor of the cooler is
neutralized with lime to recover low-grade gypsum. The
liquor from the centrifuge is sent to a wastewater treatment
system and reused.
As the calcium sulfite is oxidized to a considerable
extent in the absorber because of high concentration of
oxygen in the gas, the gypsum is recycled to the absorber as
crystal seed in order to prevent scaling. An automatic
system has been installed to shut down and restart the FGD
unit with the sintering machine.
Performance
The FGD system for the $o. 4 machine went into opera-
tion in November 1974. Performance characteristics are
shown in Figure 5-1. The gas volume fluctuated from 350,000
to 850,000 Nm /hr and inlet SQ2 concentrations ranged from
5-4,
-------
^^ ^^
•p ^
s) o
O fJ
TJ »->.
rt\
^*a
•p »
A
A vail a- Gas
bility(^) (10<
S£
removal
IciencyC'
W«M
If) 0
100
50
0
60
50
40
30
:
100
90
80
^
100
90
80
-
; ^— — . — ^— -. — .
r ^^
^ 0- °''' \
tr~~~ N>
»
_^ ^ fl ^
x'*""" ****N>'-^0.-.-K'"*"'
• *
1 1 1 t 1 1 1
Nov. Dec. Jan. Feb. Mar. Apr. May
1974 1975
Figure 5-1. Performance of FGD plant for
No. 4 sintering machine.
5-5
-------
400 to 1,100 ppm. The SC>2 removal efficiency was 91 to
98 percent and the S02 concentration at scrubber outlet
ranged from 20 to 50 ppm. Availability (FGD operation
hours as percent of total hours) was about 90 percent for
the first 3 months because of several minor troubles,
such as corrosion of the impeller of the cooler circulation
pump, plugging of the lime-slurry pump, and breakage of a
fire-brick in the furnace. Following the repairs, nearly
100 percent availability was obtained in the next 3 months.
The low availability in May 1975 (about 90%) was due to
a shutdown of the sintering machine.
On the average, the gas velocity in the scrubber is
about 2.5 m/sec and the total pressure drop in the cooler,
absorber, and mist eliminator is about 120 mm H2O. Lime
with less than 1 percent MgO has been used. The by-product
gypsum contains about 7 percent moisture after being
centrifuged and has an average crystal size of 40 microns.
At the beginning of the operation, use of an excessive amount
of lime to ensure high SG>2 removal efficiency (over 97%)
resulted in consumption of a considerable amount of sulfuric
acid. In later operation, slightly less than 1 mole lime to
1 mole inlet SO2 has been used to obtain about 95 percent
removal, and thus the consumption of sulfuric acid has been
reduced.
5-6
-------
FGD SYSTEMS OF SUMITOMO METAL (MORETANA PROCESS)
M6retana Process
Sumitomo Metal is operating two FGD systems and con-
structing three more (Table 5-1), all using the Moretana
process developed by Sumitomo jointly with Fujikasui
Engineering Co. The process is characterized by use of the
Moretana scrubber fitted with four perforated plates made
of stainless steel. The holes range from 6 to 12 mm diameter
and the plate thickness from 6 to 20 mm. Both dimensions
are varied depending on the specific scrubbing conditions.
Free space in the cross section ranges from 25 to 50 percent.
The bottom tray serves mainly as a gas distributor, and the
upper three serve as absorbers. The gas and liquid flows
are adjusted to maintain a liquor head of 10 to 15 mm on
each plate. Gas velocity is higher than in usual scrubbers.
The design gives extreme turbulence, producing foam layers
400 to 500 mm thick, and thus ensures a high ratio of S02
and dust removal. The mist eliminator is a set of vertical
chevron sections mounted in a horizontal duct after the
scrubber.
A flowsheet of the process is shown in Figure 5-2. Gas
from a sintering machine is first treated with water in a
Moretana scrubber for cooling and removal of more than 90
percent of the dust. Removal of ferric oxide dust is useful
5-7
-------
Sintering
machine
00
After-
burner
From No.2 train
pH adjusting
tank
Oxidiaer fank
Waste- ^vx'
water y
Figure 5-2. Flowsheet of Moretana process CKashlitia plant, Sumitomo Metal)".
-------
in that it reduces oxidation in the absorber to allow scale-
free operation. The gas is then treated with a limestone
slurry (or a mixed slurry of lime and limestone), 10 to 20
percent in excess of stoichiometric amount, in a second
Moretana scrubber to remove more than 95 percent of the SO-.
The limestone contains less than 1 percent MgO and is ground
to pass 325 mesh. 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 about 4.0 by
adding a small amount of H2S04. The slurry is then sent
to an oxidizer developed by Fujikasui to convert calcium
sulfite to gypsum. The gypsum slurry is centrifuged, and
the filtrate is returned to the absorber.
The discharge from the cooler is sent to a thickener.
The overflow is returned to the cooler; the underflow is
filtered. The filter cake is returned to the sintering
machine, and the filtrate is sent to a wastewater treatment
system.
Kashima Plant, Sumitomo Metal
An FGD system at the Kashima plant, with capacity of
treating 880,000 Nm /hr of gas, was started up in September
1975 and has been in stable operation. All the gas from
a sintering machine is treated, flow rates ranging from
350,000 to 880,000 Nm /hr. The gas contains 200 to 450 ppm
SO2, 14 to 15 percent O2/ 6 to 8 percent C02, 1 to 1.5
5-9
-------
percent CO, 4 to 10 percent H20, and 0.15 to 0.23 g/Nm of
dust at about 150°C, The scrubbing units consist of two
trains, each with a capacity of treating 440,000 Mm /hr of
gas. The Moretana scrubber works normally with a gas
velocity between 3 and 5 m/sec. When the gas flow rate is
low, only one train is used. Equipment dimensions are shown
in Table 5-2. Operational data on No. 1 train only are
shown on Figure 5-3.
Table 5-2. EQUIPMENT DIMENSIONS, PGD SYSTEM
AT KASHIMA PLANT
Facility
Cooler
Absorber
Mist eliminator
Oxidizer
Centrifuge
Number
2
2
2
2
4
Size (Specification)
6.5 m (dia.) 24.5 m (height)
6.5 m (dia.) 20.5 m (height)
6 x 6 m, 2.4 m (length)
2.8 m (dia.) 5.4 m (height)
500 kg/hr each
Wakayama Plant, Sumitomo Metal
An FGD plant at Wakayama (Photo 5-1), with capacity of
3
treating 375,000 Nm /hr of waste gas from a sintering machine,
started operation in May 1975 and has since operated well
except for a defect in the plastic lining of a cooler, which
was found early in the operation and was repaired. Operabil-
ity of the plant has been about 98 percent. A scheduled
shutdown of the sintering plant normally occurs every 2
5-10
-------
Sept. 10
300
P<
I 200
o>
b
CO
g 100
m
I
Oct. 1
Oct. 25
Mist eliminator
500
300
200
30
20
10
0
Failure of
meter
Inlet
Outlet
Figure 5-3. Operation data of No. 1 train, Kashima plant.
-------
I
,H
N:
Photo 5-1. Wakayama plant, Sumitomo Metal (Absorber left, cooler right)
-------
months. The mist eliminator is washed every 30 minutes with
circulating liquor or fresh water. The pressure drop in the
mist eliminator, which is 30 mm H_0 at start-up, gradually
increases while the unit is washed with the circulating
liquor. When the pressure drop reaches 50 mm, fresh water
is used in place of the liquor until the pressure drop
returns to 30 mm. The ratio of liquor to fresh water usage
is about 80 to 20.
KOBE STEEL CALCIUM CHLORIDE PROCESS
Process Description
Kobe Steel has developed a new process using a 30 per-
cent calcium chloride solution dissolving lime as the
absorbent. A pilot plant (50,000 Nm /hr) has been operated,
and two commercial systems (Table 5-1) have just come
on-stream to treat waste gas from iron ore sintering plants.
Calcium chloride solution dissolves 6 to 7 times as
much lime as does water. High SO., recovery is attained at
a low L/G ratio of 3 liters/Nm . The flowsheet is shown in
Figure 5-4.
Waste gas is first cooled in a cooler to which a
calcium chloride solution (about 5%, from a gypsum centri-
fuge) is fed to cool the gas to 70°C and to remove most of
the dust. The solution is concentrated here to about 30
percent and is sent to a scrubber system after dust removal
5-13
-------
Cooler
Absorber
Flue gas
eliminator Centrifuge
Figure 5-4. Flowsheet of Cal process.
-------
by filtration. The gas then enters an absorber, in which
a calcium chloride solution (about 30%, at pH 7 dissolving
lime) is sprayed to remove more than 90 percent of the SC^.
The gas is then passed through a mist eliminator to a stack.
The liquor discharged from the absorber at pH 5.5 containing
calcium sulfite is sent through a thickener to a centrifuge
to separate most of the solution, which is sent to a tank
where calcium hydroxide is dissolved to raise the pH to 7.
The calcium sulfite sludge from the centrifuge is repulped
with water and some sulfuric acid to produce a slurry at
pH 4. The slurry is oxidized by air bubbles into gypsum,
which is then centrifuged. The liquor from the centrifuge,
containing about 5 percent calcium chloride, is returned to
the cooler. The system gives no wastewater.
Since vapor pressure of the liquor is low, the
temperature of the gas after the scrubbing reaches 70°C.
Thus less energy is required for reheating than in the
usual wet processes with gas temperatures of 55 to 60°C at
the scrubber exit. The mist eliminator is washed with the
circulating liquor. The solubility of gypsum in the liquor
is very low (nearly 1/100 of that in water), and evaporation
of the liquor does not cause( scaling.
In continuous operation of the pilot plant for about
6 months, a soft deposit formed on the wall of the absorber
5-15
-------
when the L/G ratio was less than 1; the deposit could be
removed by use of an L/G ratio greater than 2. A highly
corrosion-resistant material is required for the cooler;
the lower part at the hot gas inlet is made of titanium.
Amagasaki Plant
The FGD system at the Amagasaki plant has two trains,
each with a capacity of treating 175,000 Nm /hr of flue
gas at 120°C containing 240 to 400 ppm SO2, 0.05 to 0.2 g/Nm
dust and 14 to 16 percent O». The plant began test opera-
tion in February 1976. The following problems were encountered
during a 2-month test run:
Unusual vibration of a centrifuge.
Wearing of a control valve.
Scaling of pH meter electrode.
Breakage of rubber lining in a reducer.
Those problems have been solved, and the system went into
commercial operation in April 1976. SO- removal efficiency
ranges from 91 to 94 percent. Dust removal efficiency is
about 50 percent. Gas velocity in the absorber is 3 m/sec.
Total pressure drop in the cooler, absorber, and mist elimi-
nator is 190 mm H20. The L/G ratios are 4.0 in the cooler
and 3.0 in the absorber. More than 50 percent of the calcium
sulfite is oxidized in the absorber. The by-product gypsum
has an average crystal size of 40 microns and contains about
8 percent moisture and 0.1 percent chloride after being
centrifuged.
5-16
-------
NIPPON STEEL SLAG PROCESS (SSD PROCESS)
Nippon Steel has developed an FGD process that uses
converter slag as the absorbent (Figure 5-5). The slag
contains about 40 percent CaO, 16 percent Si02, 3 percent
MgO, 3 percent A1203, and 35 percent FeO and Fe203; the slag
is otherwise useless. Nippon Steel has operated a prototype
system with a capacity of treating 200,000 Nm /hr of waste
gas from a sintering plant since 1974. A commercial unit
(1,000,000 Nm /hr) has just started operation.
The process is similar to other lime/limestone-gypsum
processes except that it uses no oxidizer. The gas is
cooled and led into two absorbers in series to remove 95
percent of the S02- The slag is fed to the second absorber
to produce a calcium sulfite slurry; the slurry then goes to
the first scrubber, where it is entirely oxidized into
gypsum due to a low pH and large amounts of iron compounds,
which act as a catalyst. The by-product gypsum contains
about 40 percent impurities and is discarded. Scaling
encountered in the prototype system must be reduced to
ensure long-term continuous operation. The system may be
useful for steel processes that normally yield large amounts
of useless slag.
5-17
-------
I
M1
co
-ft
$-1
1
— r>
i—i
*s /
J
p
k
Mi!
-A
I
J
— n
L
Ji
f\
ft
J
C?T « ^
Oil
Wastewater
pit
Compressor
Gypsum
Figure 5-5. Flowsheet of SSD process.
-------
6. NEW FGD PROCESSES
STATUS OF NEW DEVELOPMENTS
Since 1974 several FGD systems have been newly developed
in order to improve the wet lime/limestone process (Kawasaki
magnesium-gypsum process and MKK jet scrubber process), to
ensure stable operation at low cost (Dowa aluminum sulfate
process), to attain more than 99 percent SO- removal (Kureha
sodium acetate process), or to obtain as by-products elemental
sulfur (Chemico-Mitsui process in combination with Glaus
furnace), sulfuric acid (Hitachi-Unitika activated carbon
process), or ammonium sulfate (Kurabo process). These
processes are described in this section.
Mitsubishi Heavy Industries and Toyo Engineering have
operated pilot plants for ammonia scrubbing followed by
thermal decomposition of ammonium sulfate and production of
elemental sulfur using the IFP reactor. These operations
may be abandoned, however, because of problems encountered,
mainly in the decomposition step. A few other companies
have made small-scale tests on wet processes that yield
elemental sulfur, but the results have not yet been dis-
closed.
6-1
-------
KAWASAKI MAGNESIUM-GYPSUM PROCESS
Process Description
Kawasaki Heavy Industries completed a lime-gypsum
process plant in 1973. Scaling occurred in the early
operations but was reduced by addition of magnesium.
Recently Kawasaki constructed two commercial plants using
a magnesium-gypsum process, both of which went into opera-
tion in January 1976. A flowsheet of the process is shown
in Figure 6-1. Flue gas is treated in a multi-venturi type
scrubber with a slurry containing calcium and magnesium
sulfites. More than 90 percent of the SO« is absorbed to
form bisulfites. A portion of the sulfite-bisulfite slurry
is sent to an oxidizer and oxidized by air bubbling to
produce gypsum and magnesium sulfate.
The gypsum slurry is treated in a thickener and then
centrifuged. The filtrate is returned to the thickener.
Most of the thickener overflow, containing about 5 percent
magnesium sulfate, is returned to the absorber. A portion
of the overflow is sent to a reactor and reacted with lime
to precipitate gypsum and magnesium hydroxide. The resulting
slurry is sent to the absorbfer; gypsum in the slurry works as
seed crystal.
The pH of the slurry in the scrubber ranges from 5 to
5.5, lower than that in usual lime/limestone scrubbing.
6-2
-------
FLUE GAS
en
I
u>
FAN
TO STACK
ABSORBER
MIST
ELIMINATOR
AFTERBURNER
CENTRIFUGE
Figure 6-1. Flowsheet of Kawasaki magnesium-gypsum process.
-------
Scale-free operation may be achieved more easily at the low
•
pH, but the S02 removal ratio is fairly high because of the
effect of magnesium.
Plant Operation
The Saidaiji plant, Nippon Exlan, with a capacity of
treating 200,000 Nm /hr of flue gas from an oil-fired boiler,
started operation on January 17, 1976. Formation of soft
scale in a pipe from the reactor forced a plant shutdown on
January 28 for four days. An additional pipe was installed
for use during cleaning of the original pipe. A 10-day
shutdown, starting February 26, 1976, was carried out to
clean build-up scale from a mist eliminator, which had been
washed with a circulating liquor. Fresh water wash has been
used since then to eliminate scaling. Because a large
amount of water is evaporated in the scrubber, no wastewater
has been discharged from the plant, even with the use of
fresh water for washing. Nearly trouble-free operation has
been achieved since April 1976. S02 concentration of the
gas is about 1,400 ppm at the inlet and 100 ppm at the
outlet. The by-product gypsum contains 9 to 12 percent
moisture after being centrifuged.
The Okazaki plant, Unitika Co., with a capacity of
3
treating 220,000 Nm /hr of flue gas from an oil-fired boiler,
went into operation on January 6, 1976. In this plant,
6-4
-------
limestone is added to the scrubber and less lime is added to
the reactor. The ratio of limestone to lime is 3.5 to 1.
Problems similar to those at the Saidaiji plant were encoun-
tered at the beginning of the operation but were solved
fairly easily. Operability of the plant (FGD system opera-
ting hours as a percent of boiler operating hours) from
start-up until the beginning of May 1976 was 95 percent.
SO2 concentration is about 1,300 ppm at the inlet and 100
ppm at the outlet.
In both plants, small amounts of sulfuric acid have
been added to the slurry prior to the oxidation to adjust
the pH of the slurry to 5. Sulfuric acid may not be needed
when the SO2 concentration is over 2,000 ppm at the inlet
and over 200 ppm at the outlet (as in the U.S.), because the
slurry pH can be reduced to below 5 by the scrubbing. The
multi-venturi scrubber has limited application. For a plant
3
larger than 400,000 Nm /hr, Kawasaki may use the Bischoff
scrubber developed in Germany.
MKK LIME-GYPSUM PROCESS USING JET SCRUBBER
Mitsubishi Kakoki Kaisha (MKK) has constructed two
lime-gypsum process systems using a screen-type scrubber.
Operation is not yet completely successful. MKK recently
completed a new lime-gypsum process system at Naoshima
Smeltery, Mitsubishi Metal, with a capacity of treating
6-5
-------
120,000 Nm /hr of tail gas from a sulfuric acid plant using
a jet scrubber, which is a simple structure, as shown in
Figure 6-2. The inside wall is kept washed with the absor-
bent slurry so that no scaling takes place. The tail gas,
containing 1,000 to 3,500 ppm SO-, is cooled in a cooler and
led to the scrubber. A lime slurry is sprayed from the top
by a specially designed nozzle at an L/G ratio of 12 to 15
liters/Nm ; the slurry removes 90 to 95 percent of the SO-.
Calcium sulfite formed by the reaction is oxidized to gypsum
in the scrubber by oxygen in the gas; therefore, there is no
need for an oxidizer. Gypsum is centrifuged. Most of the
filtrate is returned to the scrubber after lime is added. A
small portion of the filtrate is sent to a wastewater treat-
ment system together with the discharge from the cooler.
The pressure drop in the scrubber is about 80 mm H9O. A flow-
£
sheet of the MKK lime-gypsum jet-scrubber process installed
at the Naoshima Smeltery is provided in Figure 6-3.
DOWA ALUMINUM SULFATE PROCESS
9
Process Description
Dowa Mining Co. has developed an indirect limestone
process using an aluminum sulfate solution at about pH 4 as
the absorbent. A flowsheet of the process used at the
Okayama plant, Dowa Mining, is shown in Figure 6-4. The
plant has two units to treat tail gas from two sulfuric acid
plants. The capacity of each unit is 150,000 Nm /hr.
6-6
-------
Figure 6-2 Dimensions of jet scrubber(mm)
(120,000 NmVhr)
6-7
-------
I
00
MIST ELIMINATOR
CENTRIFUGE
LIME
COOLER
SCRUBBER
LIME SLURRY
Figure 6-3 Flowsheet of MKK jet-scrubber process (Naoshima plant)
-------
vo
MIST
TO STACK
CaCO-
AFTERBURNER
FLUE GAS
TOR
ER
iS
JH
-------
Waste gas is led into a packed- tower absorber. SO,, is
absorbed in a solution of basic aluminum sulfate,
A12(S04)3-A1203, of pH 3 to 4 to form A12 (SO4 ) 3 'A12 (SO3) 3 .
The liquor is oxidized with air into A12(S04)3, which is
then treated with powdered limestone to precipitate gypsum
and to regenerate the basic aluminum sulfate solution. The
gypsum is centrifuged, and the liquor and wash water is
returned to the absorber.
Absorption: A12 (S04) 3'A12O3 + 3SO2 = A12 (SO4) 3
Oxidation: A12 (S04 ) 3' A12 (SO3) 3 + 3/202
= A12(S04)3-A12(S04)3
Neutralization: Al2 (SO4> 3 'Al2 (SO4) 3 + 3CaC02
+ 3 (CaSO.^H.O) + 3CO
'4
«^» »•* / * —t ^f^s A
The nature of the absorbing liquor is indicated in
Figures 6-5 to 6-8. The basicity is the ratio of uncombined
A1203 to total A12O3. An optimum concentration as well as
basicity of the absorbing liquor is selected according to
the S02 concentration of the gas and the removal efficiency
required. Four plants are in operation (Table 3-6).
6-10
-------
A. Al 378 ^ Botlclty 193%
B. Al 1 1.9 01 * W.9%
C. Al 5.7 ty * '«9%
0. Wofer
2O
^ M
S "
%••
£
*
ol
(
/
L
/^
K
^
s
•-1
^
• j
o
1 A
1
Te
^-
\ e
l 1
mp. 2
»^
o-
\ — i
Q«C
3
D
i '
SO, Content In GQS(*\&PPH)
Figure 6-5 Solubility curves
of SO in BAS solutions
A. AI 17.3 % (20«C)
B. AI 10.8 *j (20'C)
C, Al 1733/1 (5O°C)
0. Al IQ8 g/| (50»C)
10 ao 30
Basicity (%)
Figure 6-6 Solubility curves
of S02 at various temperatures
of the solution
1.0
20 S5 *r
Basiclty (%)
Figure 6-7 Soluble range of
aluminum compound
Ql
O
_c
«
I
QOI
Basicity 4O %
O B 10 B 20 2B
Al Content In the Solution(^,)
Figure 6-8 Relationship of
Al loss to concentration of
solution
6-11
-------
Okayama Plant
The operation parameters of the Okayama plant are shown
in Table 3-5. An L/G ratio of 2.5 to 3 is used to reduce
S02 from 500 to 600 to 10 to 20 ppm with a packed height of
2 to 4 meters. The plant has been in continuous operation
since its start-up in 1974, except for the period of shut-
down of the acid plant.
No wastewater was purged for over a year and magnesium
accumulated in the liquor. Although magnesium does not
interfere with S0_ removal, its concentration should be kept
£+
below a certain level to yield good-quality gypsum for
wallboard production. A small additional unit has been
installed to eliminate the magnesium. A small portion of
the absorbing liquor is neutralized with an excessive amount
of limestone to precipitate aluminum hydroxide and is then
sent to a settler. Overflow from the settler, containing
the magnesium, is discarded. The underflow, containing
aluminum hydroxide and limestone, is sent to the reactor.
Requirements for the Okayama plant for treating 280,000
Nm /hr of tail gas containing 650 ppm SO- are as follows:
CaC03 0.81 t/hr
A12(SO4)3 solution (A1203 8%) 15 kg/hr
Water 7 t/hr
Electric power 1,000 kW
Operator One per shift
6-12
-------
A small amount of aluminum is contained in the gypsum
but this does not affect the quality of wallboard or cement
produced from the gypsum. Consumption of aluminum is about
0.5 kg (as Al) for every ton of gypsum.
Tamano Plant/ Naikai Salt Production Co.
The Tamano plant, Naikai Salt Production Co., has a
capacity of treating 80,000 Nm /hr of flue gas from an oil
fired boiler containing 1,500 ppm SO,,. This plant went into
operation in March 1976 and has been in trouble-free continuous
operation since then. The system has a gas cooler before
the absorber. A portion of the liquor discharged from the
absorber is sprayed in the cooler. It has been found that
about 70 percent of the SO~ is removed in the cooler. Opera-
tion data for the first month are shown in Figure 6-9.
At the beginning of operation, the SO- removal ratio
ranged from 83 to 93 percent. A small amount of a soluble
metallic catalyst was then added to improve the removal
ratio. Since two weeks after start-up, when the gas volume
increased to nearly full load and the SO- concentration to
nearly 1,500 ppm, the removal ratio has been kept above
95 percent. The L/G ratio has been 10 for the scrubber.
Pressure at the cooler inlet was about 100 mm H-0 at full
load.
No wastewater has been purged. In case of wastewater
purge, the catalyst can be recovered by neutralizing the
liquor.
6-13
-------
,, , ,-.
oas Volume ^
• ::. Catalyst Addition'. !'l , I:.
.the 'precooler '•
• . •' • • I :.,'-.
Cutlet from - •'.-' '•
the 'absorber!---.
SO2 Removal (
150
Iniet to the precooler
50
Outlet from
the precooler
Outlet from
the absorber
Pressure at ir.let to the ISO
precooler .(mm H2O) 100
SO
-•^^TVT
12 5 4 JT 6 78 "I 10 II I* 13 14 if lt> '7 l» 'I « 31 32 33 i4 Jf at *7
Figure 6-9. Operation data of Tamano plant, Naikai.
-------
KURABO AMMONIUM SULFATE-LIME PROCESS2
In order to prevent plume formation, which is a common
problem in ammonia scrubbing, Kurabo Industries has developed
a process using as the absorbent a slightly acidic ammonium
sulfate solution at pH 3 to 4. Plume formation can be
eliminated by the use of the acidic absorbing liquor because
the vapor pressure of NH., is less than 1 ppm equivalent with
a solution at a pH lower than 4. The acidic ammonium sulfate
solution has a greater capacity for SO~ absorption than plain
water or a saturated calcium sulfate solution because of the
smaller pH drop due to the following equilibrium in ammonium
sulfate solution:
H+ + S04~~ £ HS04~
A flowsheet of the process is shown in Figure 6-10.
Flue gas is first led into a KBCA scrubber and then into a
packed tower absorber. The main function of the KBCA
scrubber is to cool the gas to 60°C and to concentrate the
absorbing liquor (ammonium sulfate solution). More than
90 percent of the SO~ is removed. The liquor from the
packed tower absorber is sent to the KBCA unit, concentrated,
and then led into an oxidizer. The pH of the liquor in the
oxidizer is adjusted to 3 or 4 by adding dilute aqua ammonia;
the sulfite in the liquor is oxidized to sulfate by small
bubbles of air formed by introducing a jet stream of cir-
culating liquor accompany air into a pool of the liquor.
6-15
-------
I
•J!
Figure 6-10 Flowsheet of Kurabo ammonium sulfate-lime process
-------
About five times the stoichiometric amount of air is used.
Most of the liquor from the oxidizer is returned to the
absorber, and a portion is sent to a set of three reactors,
in which the liquor is treated with milk of lime to precipi-
tate gypsum. The liquor from the centrifuge and the wash
water are sent to an aqua ammonia tank, and the aqua ammonia
is sent to the oxidizer.
Five commercial plants are in operation (Table 3-6).
Operation parameters are shown in Table 3-5. The plume is
almost invisible.
Ammonium sulfate solution (about 15% concentration) has
been produced in the small commercial plant of Taki Chemical
and used as the promoter of gypsum hardening for wallboard
production. The plant has a capacity of treating 15,000
Nm /hr of flue gas containing 1,000 ppm S02 from an oil-
fired boiler. More than 98 percent S02 removal has been
attained with a 4.5 m packed height and an L/G ratio of
about 10. The plant has been in operation since early April
1976 with 100 percent operability.
In by-production of solid ammonium sulfate, a 1.0 to
1.5 mole/liter solution may be used for absorption and con-
centrated in the KBCA scrubber to about a 3 mole/liter
solution (nearly saturation).
6-17
-------
KUREHA SODIUM ACETATE PROCESS10
Kureha Chemical has developed an indirect lime/limestone
process using a sodium acetate solution as the absorbent and
has operated a pilot plant with a capacity of treating 5,000
Nm3/hr of flue gas from an oil-fired boiler. The reason for
the use of the acetate is to eliminate the problem of sodium
sulfate, an undesirable compound that forms in sodium scrub-
bing processes and must be treated. In this process the
acetic acid reacts with calcium to form calcium acetate,
which is soluble and readily reacts with sodium sulfate to
precipitate gypsum and to regenerate sodium acetate. A flow-
sheet of the process is shown in Figure 6-11.
SO2 in flue gas is absorbed by a sodium acetate solu-
tion to form sodium bisulfite and acetic acid. Acetic
acid is vaporized and caught, together with the remaining
SO2/ by a limestone slurry at the upper part of the absorber
to form a calcium acetate solution. Sodium sulfite is
oxidized by air into sodium sulfate, which is then reacted
with calcium acetate as mentioned above. Operation para-
meters are shown in Table 3-5.
Plant operation is easy; with more than 99 percent
S02 recovery. Losses of acetic acid and sodium can be
kept very small. On the other hand, the absorber and
reactors are large, and the L/G ratio is fairly high.
6-1*
-------
REHEATER
ACETIC
ACID
RECOVERY
SECTION
SO 2
RECOVERY
SECTION
I
-ix—
&
CALCIUM ACETATE
4" \y
A
r?
/\
OXIDATION
TOWER
REACTOR
v
CaO OR
CaC03
•WATER
0-
SEPARATOR
^ GYPSUM
SODIUM ACETATE TANK
AIR
Figure 6-11. Flowsheet of Kureha sodium acetate-lime/limestone process
-------
Kureha recently started to use lime in place of limestone in
order to reduce the size requirements and the L/G ratio
substantially. Process economy is improved by the use of
lime. For plants which do not need very high S02 removal
efficiencies, 70 to 80 percent of the gas may be treated by
the process and then mixed with the untreated hot gas to
eliminate reheating of the gas. The sodium acetate process
is useful also for simultaneous removal of NO (Section 7).
IX.
MITSUI-CHEMICO MAGNESIUM PROCESS
Mitsui Miike Machinery Co. constructed a magnesium
3
scrubbing system with a capacity of treating 500,000 Nm /hr
of waste gas from industrial boilers and Claus furnaces at
Chiba refinery, Idemitsu Kosan. The unit went into opera-
tion in late 1974. The flowsheet is shown in Figure 6-12.
Two Chemico venturi scrubbers in the same shell are
used (Photo 6-1) as at the Omuta plant, Mitsui Aluminum.
The magnesium sulfite slurry discharged from the scrubber
is pH-adjusted and filtered. The sulfite cake is dried
in a rotary drier with countercurrent flow. The dried
sulfite is calcined in an oil-fired rotary kiln (Photo 6-2).
As 10 to 15 percent oxidation
-------
SCRUBBER
SCRUBBER'
en
I
to
PH
ADJUSTING
Figure 6-12 Flowsheet of Chemico-Mitsui magnesium process
-------
I
NJ
Photo 6-1. Chiba plant, Idemitsu Kosan
(170 MW equivalent, scrubber and kiln)
Photo 6-2. Chiba plant, Idemitsu Kosan
(View from the top of the scrubber,
drier at right, kiln at left)
-------
Gas from the kiln goes through a cyclone, wet venturi, and
wet precipitator. The cleaned gas containing 10 to 12 per-
cent SO- is fed to the Glaus furnace, where H-S recovered in
the refinery is reacted with S02 to produce elemental
sulfur. SO- concentration at the scrubber inlet is about
2,500 ppm, and the removal efficiency is 95 to 97 percent.
The form of magnesium sulfite, trihydrate or hexahydrate,
is an important key to plant operation. Usually hexahydrate
is preferred because it grows in much larger crystals than
does trihydrate. Mitsui Miike has found that mixing the two
forms gives the best results. There has been no problem
with drier operation. The major problem was dislodging of
the firebricks in the rotary kiln, caused possibly by the
cooling of the kiln by rain. To prevent corrosion, the
chloride concentration in the liquor is maintained below
2,300 ppm. Usually no wastewater is purged because the
inlet chloride concentration is low.
HITACHI-UNITIKA ACTIVATED CARBON PROCESS
Unitika Co. has installed at Uji an activated carbon
process with a capacity of treating 170,000 Nm /hr of flue
gas from an industrial boiler buring oil with 2.5 percent
sulfur. The adsorption-desorption unit was designed by
Hitachi Ltd, which had constructed a larger unit at Kashima
Station, Tokyo Electric, where the dilute sulfuric acid
obtained by water wash of the carbon is reacted with limestone
6-23
-------
to produce gypsum of good quality. The Kashima plant is
fairly costly, but operation has been trouble-free for 3
years with virtually no loss of carbon.
At the Uji plant, Unitika, which went into operation in
December 1975, dilute sulfuric acid (6 to 7 percent H-SO.)
is sprayed into the incoming hot flue gas at 170°C. The gas
is cooled to 80 to 90°C, and the acid is concentrated to
about 60 percent. The acid is somewhat dirty and too dilute
for commercial use. Unitika has used the acid in its own
chemical plant and hopes to sell it locally for wastewater
treatment. The acid concentration unit was designed by
Unitika. There is no mist eliminator between the concentra-
tor and the absorber. The acid mist is caught by the carbon
in a fixed bed.
6-24
-------
7. SIMULTANEOUS REMOVAL OF S02 AND NO
OUTLINE
In Japan, NO removal technology has developed rapidly
since 1973, when a stringent ambient standard for N02 (0.02
ppm in daily average) was set forth. Among many processes,
selective catalytic reduction of NO by ammonia at about
X
400°C has been considered a most feasible means to remove 85
to 95 percent of the NO in flue gas. Several commercial
A.
plants are treating flue gas from oil-fired industrial
boilers (200,000-450,000 Nm /hr), and many plants are under
construction using the reduction process. This dry
denitrification process, however, is not suited for use in
conjunction with FGD (for which a wet process is economical),
because it requires a large heat exchanger and a consider-
able amount of energy for heating (No. 3, Figure 7-1) or an
expensive hot electrostatic precipitator (No. 4, Figure
7-1). Moreover, many existing boilers have not enough space
for installation of both FGD and dentrification units. For
these reasons, many dry and wet processes have been developed
for simultaneous removal of S0_ and NO (No. 1 and 2, Figure
7-1), and many plants are in operation, as shown in Table
7-1.
7-1
-------
No.l
No. 2
No. 3
400
AH
150
hP
150
DDS
DON
150
B
400
AH
150
EP
150 ^
WDS
WDN
60 ,J
H
120
1
160
B
400 '
AH
150
. . s.
S
EP
150
V
400
•t
WDS
DDN .
bO
y
400
t
1 >
HI E
/ k
H
^ 300
No.4
B
4UU
v
EP
4UU
\
DDN
q-uu
AH
.LOU
\
WDS
60
H
120
No. 5
No.6
40.0
DDN
AH
-LOU
—9
EP
160
(With, or
without)
WDS
ou
r
H
120
B
400
EP
400
DDS
DDN
400
AH
160
^>
Boiler
Air heater
Electrostatic
precipitator
DDS
Dry
FGD
Wet
FGD
Dry denitrification
TON
Wet
denitrification
Heater
Heat
exchanger
Figure y-1 Models of combination of FGD and denitrification
( Figures show gas temperature) r
7 2
-------
Table 7-1. PROCESSES FOR SIMULTANEOUS REMOVAL
OF SO- AND NO
2 x
Process
developer
(Sumitomo Metal
Fujikasui)
(Sumitomo Metal
Fujikasui)
(Sumitomo Metal
Fujikasui)
Osaka Soda
Shirogane
Chiyoda
Mitsubishi H.I.
Ishikawajima H.I.
Kureha Chemical
Chisso Eng.
Mitsui S.B.
Asahi Chemical
Kawasaki H.I.
Unitika Co.
Sumitomo H.I.
Shell
Ebara-JAERI
Type of process
Oxidation reduction
Oxidation reduction
Oxidation reduction
Oxidation reduction
Oxidation reduction
Oxidation reduction
Oxidation reduction
Oxidation reduction
Reduction
Reduction
Reduction
Reduction
Magnesium
Carbon0
Carbon0
Copper0
Electron beam0
Plant owner
Sumitomo Metal
Toshin Steel
Sumitomo Metal
Osaka Soda
Mitsui Sugar
Chiyoda
Mitsubishi H.I.
Ishikawajima
Kureha Chem.
Chisso P.C.
Mitsui S.B.
Asahi Chem.
EPDC
Union Glass
Sumitomo Metal
Showa Y.S.
Ebara
Plant site
Amagasaki
Fuji
Osaka
Amagasaki
Kawasaki
Kawasaki
Hiroshima
Yokohama
Nishiki
Goi
Chiba
Mizushima
Takehara
Hirakata
Kokura
Yokkaichi
Fujisawa
Capacity,
Nm3/hr
62,000
100,000
39,000
60,000
48,000
1,000
2,000
5,000
5,000
300
150
600
5,000
5,000
150
120,000
1,000
Source
of gas
Boiler3
Furnace
Boiler3
Boiler3
Boiler3
Boiler3
Boiler3
Boiler3
Boiler3
Boiler3
Boiler3
Boiler3
Boilerb
Furnace
Furnace
Boiler3
Boiler3
Completion
1973
1974
1974
1976
1976
1973
1974
1975
1975
1974
1974
1974
1975
1975
1975
1975
1974
By-product
(NaN03, NaCl,
Na2S04)
(NaN03, NaCl,
Na2S04)
(NaNO3, NaCl,
{NaN03, NaCl,
Na2S04)
(NaN03, NaCl,
Gypsum, Ca(NO,)2
Gypsum, NH,
Gypsum, N2
Gypsum, N2
(NH4)2S04
Gypsum, N2
Gypsum, Mg(NO3)-
Conc. S02, N2
Cone . S02 , N2
Cone. S02, N2
Mist, dust
I
OJ
3 Oil-fired boiler.
Coal-fired boiler.
° Dry process.
-------
CHEMISTRY AND PROBLEMS OF WET PROCESSES
Most of the NO in combustion gas is in the form of NO,
X
which has little reactivity and does not readily dissolve in
solutions. NO can be absorbed in a solution containing an
oxidizing agent such as potassium permanganate, hydrogen
peroxide, or calcium hypochlorite; an absorption oxidation
process may be too expensive for commercial use on a large
scale, however, particularly when the gas contains much SO2,
which consumes the oxidizing agent. Moreover, treatment of
the by-product liquor containing a nitrate, nitrite, and
sulfate will present a problem.
NO is slowly oxidized into NO2 in air. Gaseous oxidi-
zing agents, ozone and chlorine dioxide, oxidize NO very
rapidly, within 1 second, but they hardly oxidize SO_ into
SO.,. Since 1972 several oxidation reduction processes have
been developed in Japan, by which NO is first oxidized to
NO~ by the oxidizing agent and is absorbed in a solution or
slurry together with S02. Various reactions occur in the
solution or slurry as shown below, resulting in the reduc-
tion of NO by S00 (or sulfite) to N0 or NH.,.12
HONO
(HO)~NH
£\dAUV
* U J- Wll
rlUNri^
t
HONHSO3H ^
V^ .
t ^
^HON(S03H)2
7-i
I
r
— ^ JNrl^
I
H2NSO3H Hydrolvsis
^ t 1
HN(SO3H)2
t
H(S03H)3
\
-------
The reactions to form N2 are more complex but may be
described as in equation (1) or more simply as in equation
(2).
03H + NO2~ -> N2 + HSO4~ + H2O (1)
+ 4S03 -> N2 + 4S04 (2)
In some of the processes a considerable portion of NO
remains in the resulting liquor as a nitrite and nitrate.
For a large-scale operation, it is desirable not to have
those nitrogen compounds in solution because they present
problems in wastewater treatment.
In addition to the oxidation reduction processes,
several reduction processes have been developed using
solutions containing ferrous ion and EDTA (ethylenediamine-
tetraacetic acid, a chelating compound whose present cost in
Japan is about $2,700/t), which absorbs NO fairly well. The
absorbed NO reacts with sulfite and is converted to N~ or
(NHA)0SO.. Otherwise, the NO can be regenerated in a
4t £• TX
concentrated form.
The wet simultaneous processes have not yet been
commercialized on a large scale; five relatively small
commercial plants are in operation, as shown in Table 7-1.
The major problem for the oxidation reduction processes has
been the high cost of ozone ($1.2 to $1.4/kg). Although
chloride dioxide is less expensive, it brings chloride into
the system and complicates the process. Another problem has
7-5
-------
been the formation of considerable amounts of nitrate and
nitrite in the absorbing liquor. Improvements have been
made to prevent the nitrogen compounds from remaining in
the liquor as well as to produce ozone at lower cost. The
major problems for the reduction process have been the
requirements of expensive EDTA, a large absorber, and a high
L/G ratio. Efforts have been made to minimize the consump-
tion of EDTA.
On the positive side, the wet processes offer the
following advantages: (1) They are not affected by particu-
lates in the gas as are the dry processes using a catalyst.
(2) Their NO removal efficiency exceeds 80 percent, whereas
JC
that of the ammonia injection process without catalyst may
not reach 70 percent on a large scale. (3) The wet pro-
cesses do not consume ammonia. Some of the processes can
produce ammonia from NO . For future worldwide use, the wet
X
processes may be practicable if the process economy can be
considerably improved, because the dry processes consume
large amounts of ammonia and may cause shortages of nitrogen
fertilizers and foods. (4) A high S0?/N0 ratio is favor-
£• X
i
able to the reduction of NO to N or NH_. The wet pro-
X & j
cesses may be useful for treatment of flue gas burning of
high-sulfur coal.
7-6
-------
OXIDATION REDUCTION PROCESSES
Fujikasui-Sumitomo Process (Moretana Process)
Fujikasui Engineering, jointly with Sumitomo Metal
Industries, has developed a sodium scrubbing process for
removal of S0_ and NO (Figure 7-2) and has constructed
^ X
three plants (Table 7-1). Gaseous C102 is added to the gas
just before the scrubber and oxidizes NO into N0» within 0.5
second. The gas is then introduced into a Moretana scrubber
and is reacted with a sodium hydroxide solution. More than
98 percent of the SO- is absorbed to produce sodium sulfite.
About 90 percent of the NO in the gas is removed. About
X
half of the removed NO is converted into N9 by the reaction
X £•
with sodium sulfite and the rest into sodium nitrate and
nitrite.
Capital cost is in the range of $60 to $90/kW. Operating
cost including depreciation (7 years) is roughly $32/kl oil
or 7 mil/kWh.
The liquor from the scrubber, which contains sodium
sulfate, chloride, nitrate, and nitrite, is concentrated to
separate most of the sodium sulfate in a crystal form. The
remaining liquor is sent to a wastewater treatment system.
Fujikasui recently started tests on ozone oxidation
followed by lime scrubbing to reduce NO to N9 or NEU and
X £* J
to by-produce gypsum.
7-7
-------
OXIDIZING
AGENT
1: BOILER 2: COOLER
3: SCRUBBER 4: MIST ELIMINATOR
5: AFTERBURNER 6: STACK
Figure 7<~2. Simplified flowsheet of Moretana
simultaneous removal process.
7-5
-------
Jr
Limestone
V V
A A
-( H2SQ4)
Witter
\/
I8
*.
• ———v
)
10
f — s.
^. x
^v_r\pi.un
(™L)
^T~^c
\*-
V
• >» 1
{Ca(OH);
1 Fan
5 Reheater
8 Thickener
11 Neutralizer
2 Cooling Tower 3 Scrubber 4 Mist Eliminato:jj
6 Ozonator 7 Absorbent Make-up
9 Centrifuge 10 Decomposition
Figure 7-3. MHI simultaneous removal process
7-9
-------
MHI Process
Mitsubishi Heavy Industries (MHI) has modified the wet
lime/ lime stone FGD process for simultaneous removal of NO
X
and has operated a pilot plant (Table 7-1, Figure 7-3).
Ozone is introduced into the flue gas prior to scrubbing.
A water-soluble inorganic catalyst is added to a lime/lime-
stone slurry to promote the reaction of N0« . About 80
percent of the NO is removed with more than 90 percent of
the S0« when more than 3 moles of SO_ per mole of NO are
2 2 ^ x
present in the gas. The scrubber liquor contains essentially
no nitrate or nitrite. A portion of the liquor is treated
to decompose N-S compounds to NH.HSO. , which is treated with
lime to generate ammonia. The pilot plant has been operated
smoothly- Cost of the simultaneous removal is estimated at
about 40 percent higher than that of desulfurization only.
2N02 + Ca(OH)2 + CaSO3l/2H2O + Aq ->
Ca(N02)2 + CaS04-2H20 (1)
Ca(N02)2 + 4(CaS03-l/2H20) + Aq -»•
2CaNOH(S03)2 + 3Ca(OH)2 (2)
CaNOH(S03)2 + CaS03-l/2H20 + Aq ->
CaNH(S03) 2 + CaS04-2H20 (3)
CaNH(S03)2 + H20 -»• NH2S03H + CaS04 (4)
Ca(OH)2
(5)
(6)
7-10
-------
I
I-1
CLEANED GAS
A
COOLER
(DUST REMOVAL)
OXIDIZER
CENTRIFUGE
V
fa *
\^ AIR GYPSUM
Figure 7-4 Schematic flowsheet of IHI simultaneous removal process
-------
IHI Process
Ishikawajima-Harima Heavy Industries (IHI) has been
testing an oxidation reduction process at a pilot plant with
a capacity of treating 5,000 Nm /hr of flue gas from an oil-
fired boiler containing about 1,000 ppm SO0 and 200 ppm NO
£* X
(Figure 7-4).
The flue gas is cooled, injected with ozone to oxidize
NO to NO?, and treated in a scrubber with a lime/limestone
slurry at pH 5 to 6, containing small amounts of CuCl2 and
NaCl as catalysts for NO absorption. A lower pH is favor-
it
able to NO absorption. More than 80 percent of the NO and
X X
90 percent of the S02 are absorbed, resulting in various
reactions in the liquor. The following reactions are assumed
to take place:
2N02 + 4CaS03 -> N2 + 4CaS04
4NO2 + 4CaS03 + 2H20 ->• Ca(NO2)2 + C
2N02 + 3CaSO3 -> N20 + SCaSO.
2N02 + 5CaSO3 + Ca(HSO3>2 + H20 -»• C
N205 + 2CaSO3 + H20 -> Ca(N03)2 + Ca
About a half of the NO is reduced to N9, and the rest
J\. £f
stays in the liquor as nitrate and other compounds. Tests
are in process to achieve further reduction of NO to N».
e x 2
7-12
-------
Chiyoda Thoroughbred 102 Process
Chiyoda has made a simple modification of the Thorough-
bred 101 process to remove NO . Ozone is added to the gas
prior to scrubbing. More than 60 percent of the NO is
A,
removed along with about 90 percent of the S02. A portion
of the removed NO is converted into nitric acid, which
jC
forms calcium nitrate, and the rest is converted into N» and
N~0. Wastewater treatment is required to remove the nitrate.
Other Oxidation-Reduction Processes
Osaka Soda, a chemical company, has developed a process
similar to the Fujikasui-Sumitomo process and has constructed
a prototype unit (Table 7-1). Tests on wastewater treatment
are in progress.
Shirogane Co., an engineering company, has built a unit
(Table 7-1) using a process similar to the Fujikasui-Sumi-
tomo process except that ozone is substituted for chloride
dioxide. The wastewater containing sodium sulfate and nit-
rate is sent to a wastewater treatment system along with
other wastewaters.
REDUCTION PROCESSES
Kureha Process
Kureha Chemical has developed a process to remove NO
J\
in combination with the sodium acetate FGD process (Section
6) (Figure 7-5).
7-13
-------
S02 is absorbed by a sodium acetate solution to produce
sodium sulfite and acetic acid. NO is absorbed by a sodium
sulfite solution in the presence of acetic acid and a soluble
metallic catalyst to produce sodium imidodisulfonate [reaction
(2)].
S02 + 2CH3COONa + H20 + Na2S03 + 2CH3COOH (1)
2NO + 5NaS03 + 4CH3COOH -> 2NH(SO3Na)2
+ Na2S04 + 4CH3COONa + H20 (2)
The remaining sodium sulfite is air-oxidized into sulfate.
The sulfate is treated with calcium acetate, as in the FGD
process.
Sodium imidodisulfonate is reacted with slaked lime to
precipitate and separate sodium calcium imidodisulfonate
[reaction (3) ] , which is then hydralized in the presence of
sulfuric acid into sulfamic acid [reaction (4) ] . The
sulfamic acid is treated with calcium nitrite to release
nitrogen [reaction (5)].
NH(S03Na)2 + Ca(OH)2 + CI^COOH
-> NNa(S03)2Ca + CH3COONa + 2H20 (3)
2NNa(S03)Ca
4- 2CaSO4 (4)
CaS04 + H2S04 + 2H2O (5)
7-14
-------
Kureha has been operating a pilot plant with a capacity
of treating 5,000 Nm /hr of flue gas from an oil-fired
boiler. The process seems fairly complicated, since it
includes many reaction steps. Recently the sodium imidodi-
sulfonate has been found useful as a builder of detergents
to replace sodium tripolyphosphate, which has been causing
eutrophication problems. Tests have been in progress on the
effect of the disulfonate on the environment. Possible
commercial use of the disulfonate will make the process
useful.
7-15
-------
Mitsui Shipbuilding Process
Mitsui Shipbuilding, one of the largest engineering
and construction companies, has developed a simultaneous
removal process which by-produces concentrated SC>2 which
can be used in sulfuric acid production (Figure 7-6).
Flue gas is treated with a ferrous compound solution
containing ethylenediaminetetraacetate, which absorbs
both S02 and NO.
A portion of the ferrous ion is converted to ferric
ion by the oxygen in the flue gas. The absorbed liquor is
sent to a reduction step, where the ferric ion is reduced
to ferrous ion by electrolysis.
The liquor is then sent to a stripper, where it releases
concentrated S02 and NO by steam distillation. The NO is
reduced to N2; the S02 is used in sulfuric acid production.
The liquor from the scrubber is returned to the absorber.
In tests with a pilot plant (150 Nm3/hr) about 95% of the
SO- and 85 percent of the NO were removed at an L/G ratio
£* J£
of 1 liter/Nm .
It is estimated that the cost is $80 million for a 67
MW system, EDTA consumption per year is 300 to 400 tons
($500,000 to 600,000), and simultaneous removal cost is
$34/kl oil, including fixed costs.
By use of H2S in the reduction step, elemental sulfur
may be produced. Tests with a larger plant are required
for further evaluation.
7-16
-------
TREATED GAS
CaO
(CaCO,)
ACETIC
ACID
RECOVERY
S02,NOX
REMOVAL
FLUE GAS
WATER
CaO
(CaCO3)
Figure 7-5 Flowsheet of Kureha simultaneous removal
process
CLEANED GAS
ABSORBER
COOLER
FLUE GAS
REDUCTION
WASTE-
WATER
COOLING WATER
STRIPPER
Figure 7-6 Flowsheet of Mitsui Shipbuilding process
7-17
-------
Chisso Engineering Process (CEC Process)
Chisso Engineering, a subsidiary of Chisso Corporation,
has developed a process for simultaneous removal of S02 and
NO from flue gas by ammonia scrubbing using a catalyst
X
(chelating compound) to by-produce ammonium sulfate. A
pilot plant (300 Nm3/hr of flue gas from an oil-fired boiler)
has been operated (Figure 7-7) .
Flue gas containing S02 and NO is absorbed with an
ammoniacal solution containing a soluble catalyst to reduce
the absorbed NO into NH-, by ammonium sulfite and bisulfite,
X ~j
which are formed from S0? and ammonia. Most of the catalyst
is separated from the product solution containing ammonium
sulfate and sulfite and intermediate compounds. The solu-
tion is oxidized by air and then heated to convert the
intermediate compounds into ammonium sulfate. The product
solution is concentrated in an evaporator to crystallize
ammonium sulfate, which is separated by a centrifuge. The
mother liquor, which contains a small amount of the catalyst,
is returned to the catalyst separation step. The overall
reaction may be expressed simply in the following way:
2NO + 5S0
2
In order to recover 80 percent of 300 ppm NO it is desirable
^c
to have more than 1,200 ppm SO9 in the flue gas.
7-18
-------
TO STACK
SO 2
^ WATER
s
GAS
A
i
i
ABSOR-
BER
COOLER
i
NH
, I
i
<-J
: i
i
J
H2
OXIDIZING
t
i
i
AIR
J
^
NH3
SO*
CATALYST DECOM- NEUTRALI- CRYSTALLI
RECOVERY POSITION ZATION ZATION
» L- >•
L
i • 1 ' U
1 p
^ (NH^^SO^
Figure 7-7 Flowsheet of CEC process
-------
Reaction of NO with the sulfite liquor is not rapid,
X
and the removal ratio has ranged from 70 to 80 percent. The
use of a dilute liquor is favorable for the absorption but
necessitates much evaporation for ammonium sulfate recovery.
Therefore, NO removal of about 70 percent by use of a mod-
j\.
erate concentration may be suitable. The catalyst is not
affected by nickel and vanadium derived from flue gas.
Chisso estimates the cost for simultaneous removal of SO~
and NO to be about 40 percent more than for SO9 removal
2*L ^
only.
The process has the advantage of producing ammonium
sulfate, utilizing both S0~ and NO . Plume formation common
^ j£.
to ammonia scrubbing processes might be a problem for this
process.
Asahi Chemical Process
Asahi Chemical Co. has been testing a reduction process
with a pilot plant (600 Nm /hr). A flowsheet of the process
is shown in Figure 7-8. A flue gas containing 1,250 ppm
S00, 3 to 4 percent 09, and 200 ppm NO is led to a sieve-
^ ^ X
tray absorber and treated with a sodium sulfite solution at
pH 6.3 containing EDTA and ferrous ion. More than 80 percent
of the NO is absorbed, forming an adduct with ferrous ion
H
and EDTA, while more than 90 percent of the S02 is absorbed
reacting with the sulfite. The NO adduct reacts with the
sulfite to form sodium sulfate and nitrogen by the following
reaction:
7-20
-------
i
N)
I—1
ABSOR-
BER
FLUE
GAS
FILTER
DUST
CRYSTAL-
LIZER
Na2S206
-------
Fe++-EDTA-NO + Na2SO3 ->- Fe-EDTA +
Most of the resulting liquor is returned to the
absorber. A portion is sent to a crystallizer, where sodium
dithionate Na-S-O,. = 2H9O is crystallized. The dithionate is
£ £* O ^
separated and heated at 300°C to be decomposed to Na2S04
and SO2, both of which are sent to a reactor and reacted
with calcium sulfite to precipitate gypsum.
Na2S2°6"2H2° "*" Na2S04 + S02 + 2H2°
Na2S04 + S02 + CaS03 + H20 -> 2NaHS03 + CaS04
2N HSO., + Ca(OH) -> Na-SO- + CaSO-
3. -J £ £3 -3
Sodium bisulfite solution formed by the reaction is
treated with lime to precipitate calcium sulfite and to
regenerate sodium sulfite; the former is sent to the
reactor and the latter is recycled to the absorbing system.
Chloride, which is derived from the fuel and accumulates
in the scrubbing liquor, can be eliminated by ion exchange,
with which Asahi Chemical has had much experience.
Asahi Chemical estimates that the cost for a 500,000
Nm /hr unit (160 MW equivalent) is $16 million and that
requirements for treatment of 10,000 Nm of gas containing
2,000 ppm SO are as follows:
Ca(OH)2 6.7 kg
FeS04-7H20 1.0 kg
EDTA 1.0 kg
7-22
-------
NaOH 4.2 kg
Oil (gas reheating) 30 kg
Oil (thermal decomposition) 5 kg
Steam 60 kg
Cooling water 6 tons
Power 15 kWh
The system is not simple but represents a combination
of feasible unit processes. Operation data of a larger
pilot plant may be needed for a reliable evaluation of
commercial feasiblity.
Kawasaki Magnesium Process
Kawasaki Heavy Industries has been operating a pilot
plant with magnesium scrubbing with a capacity of treating
5,000 Nm /hr of flue gas from a coal-fired boiler (Table
7-1, Figure 7-9).
The gas, containing about 1,000 ppm SO,, and 400 ppm
NO , is mixed with NO9 gas to adjust the NO.-/NO ratio to
Jt JLf £m
1 and is treated with a magnesium hydroxide slurry to form
magnesium sulfite and nitrite. The nitrite is separated
and decomposed by adding sulfuric acid to produce NO,
which is oxidized to NO- and returned to the absorber. The
magnesium sulfite is oxidized into sulfate and reacted with
calcium nitrate to precipitate gypsum, which is centrifuged,
The separated magnesium nitrate solution is reacted with
7-23
-------
FLUE GAS
ABSORBER
Nl
.CLEANED_GAS.^.
Hg(OH)2
Mgso|
MgSO.
Ca(NOJ
3'2
Ca(OH)2
AIR
r
GYPSUM
T
Ca(NOJ
3'2
Figure 7-9. Flowsheet of Kawasaki magnesium process,
-------
calcium nitrate to precipitate gypsum, which is centrifuged.
The separated magnesium nitrate solution is reacted with
calcium hydroxide to precipitate magnesium hydroxide, which
is returned to the absorber. Part of the calcium nitrate
liquor formed by the reaction is returned to the system for
the reaction with magnesium sulfate and the rest is obtained
as by-product.
The process has the advantage of removing both SO,, and
NO while by-producing gypsum and calcium nitrate. The
X
process is not simple, however, and the demand for by-
product calcium nitrate is limited.
DRY PROCESSES FOR SIMULTANEOUS REMOVAL
Reaction of Activated Carbon
Activated carbon has been used commercially as the
absorbent of SO0. Although it also absorbs NO , the ab-
^ X
sorbing capacity is not sufficient to treat a large amount
of gas. Takeda Chemical has produced an activated carbon
containing metallic components or with a special structure
to promote the reaction of NO with ammonia to form N~.
X ^-
Hiaher temperature is favorable to the reaction but decreases
the S0~ absorbing capacity (Figure 7-10). Optimum tempera-
ture for simultaneous removal by this process is about
250°C.
2NH3 + 2NO + 1/202 = 2N2 + 3H20
7-25
-------
100
90
o
2 80
rt
>
i 70
0)
K
60
100
150 200 250
Temperature (°C)
300
350
Figure 7-10. Schematic diagram of SO- and NQ .removal
^ j .X
by activated carbon at different temperatures and
space velocities.
7-26
-------
Carbon for simultaneous removal of SO- and NO costs
£ X
about 8,000/t, whereas carbon used commercially for FGD
costs $3,000/t. Simultaneous removal for flue gas from a
300 MW boiler will require about 1,000 t of the carbon,
which may be too expensive. The price will be substantially
lowered through mass production.
Unitika Activated Carbon Process
Unitika Co. recently started operating a pilot plant
with a capacity of treating 4,500 Nm /hr of flue gas from
a glass melting furnace; the gas contains about 400 ppm
SO- and 500 ppm NO (Figure 7-11). The plant has a tower
^ X
with four compartments, all of which have a fixed carbon
bed. About 600 ppm NH3 is added to the gas at about 230°C,
and the mixed gas is led into three compartments. About 90
percent of the NO and SO- is removed. The carbon that has
X ^
absorbed SO- is heated to 350°C in a reducing hot gas to
release concentrated S02 for sulfuric acid production.
Ammonium sulfate and sulfite, which tend to form on the
carbon, are decomposed to S0_ and N~ in the regeneration
step.
Design and operating parameters are as follows:
Tower height 17 m
Carbon bed thickness 1 m
Pressure drop 100 mm H0
7-27
-------
i
K)
00
STACK
NHi
'FLUE
GAS
TO
S02
PLANT
FUEL
INERT GAS
PRODUCER
Figure 7-11 Flowsheet of Unitika process
-------
Absorption time for one cycle 3 days
Regeneration time for one cycle 12 hours
SO- in gas from regeneration step 5-10%
A superficial gas velocity of about 700 is used. The carbon
consumption is estimated to be less than 10 percent of a
charge per year. In the 6-month operation, the loss has
been only 1 to 2 percent. The gas from the regeneration
step, containing 5 to 10 percent SO_, may be used for
sulfuric acid production.
Other Activated Carbon Processes
Sumitomo Heavy Industries has constructed a prototype
FGD system (175,000 Nm /hr) using moving beds of absorbent
activated carbon, which is regenerated by heating a
2
reducing gas. With this unit they have studied simultaneous
removal and are constructing a test unit with a capacity of
treating 1,500 Nm /hr flue gas using moving beds.
Hitachi Ltd. has found that activated carbon treated
with ammonium bromide is effective even at 100°C for NO
X
14
reduction by ammonia. The low-temperature activity may
result in energy saving (Figure 7-1, No. 4), but deposition
of ammonium sulfate and bisulfate on the carbon may present
a problem.
7-29
-------
Shell Copper Oxide Process
Copper oxide used as an absorbent of S0~ in the Shell
process works as catalyst in the reaction of NO with
.X.
ammonia. The Yokkaichi plant, SYS, treating 120,000 Mm /hr
of flue gas from an oil-fired boiler by the Shell process,
has introduced ammonia into a reactor at 400°C since 1975.
Up to about 70 percent of the NO can be removed. Copper
J\.
sulfate formed by SO2 absorption is reacted with hydrogen
to generate concentrated S02, which is sent to a Glaus
furnace to produce sulfur.
Ebara Electron Beam Process
Ebara Manufacturing Co. has developed a unique process
for simultaneous removal by electron beam radiation. Flue
gas is introduced into a reactor and exposed to the beam.
About 80 percent of the S00 and 90 percent of the NO can
^ c x
be removed, forming a sulfuric acid mist and a powdery
product containing S, N, 0, and H, which are caught by an
electrostatic precipitator. A pilot plant (1,000 Nm3/hr)
has been operated and a larger plant (3,000 Nm3/hr) is to
be constructed. Investment cost and power consumption seem
high.
7-30
-------
8. COMPARATIVE EVALUATION
DIFFERENCES AFFECTING PROCESS APPLICATIONS IN THE UNITED
STATES AND JAPAN
Significant differences in circumstances in the United
States and Japan can affect the selection of an FGD process
and unit design. The major differences are as follows:
(1) In the United States, gypsum and sulfur from
natural sources are plentiful and inexpensive,
whereas these are limited in Japan. By-products
from desulfurization, including sodium sulfite and
gypsum, can be sold in Japan, a fact conducive to
the development of recovery processes.
(2) In the United States, most plants have enough
space for disposal of waste products, whereas in
Japan space limitations necessitate maximum
utilization of by-products.
(3) In the United States, about 60 percent of the
electric power is generated by burning coal, which
gives much fly ash. In Japan, most power plants
burn oil, which gives little dust--an advantage in
recovering by-products with high purity.
(4) In the United States, many power plants are
located far from chemical plants. In Japan, power
and chemical plants are usually close to each
other; hence it is easy for chemical plants to
utilize desulfurization by-products and for power
plants to use chemicals.
(5) S02 concentration of flue gas usually ranges from
400 to 1,500 ppm in Japan, whereas it reaches
2,000 to 3,000 ppm in the United States.
8-1
-------
(6) In Japan, many plants are close to cities. More
than 90 percent removal of S02 or less than 100
ppm S02 in emitted gas is usually required. In
the United States, about 85 percent desulfuriza-
tion or 300 ppm S02 in the gas is usually accep-
table.
(7) Regulations of the purge of wastewater in many
states in the United States are more stringent
than in Japan.
(8) Compared with flue gas from oil burning, that from
coal is richer in NOX and dust. It is not easy
to reduce NOX concentration in flue gas from coal
combustion to less than 400 ppm; moreover, the
dust contaminates the catalyst for NOX removal.
Simultaneous removal of SC>2 and NOX by wet
processes may be useful for treatment of flue gas
from coal combustion.
WET LIME/LIMESTONE PROCESS
System Cost and Operation
The plant cost for the Japanese lime/limestone-gypsum
process is considerably higher than that for the United
States throwaway sludge process because of the requirement
of a pH controller (or additional absorber), oxidizer, and
centrifuge, which account for about 30 percent of the plant
cost. Where there is enough space for sludge discarding,
the throwaway process may be most economical.
Most of the lime/limestone-gypsum process systems have
a gas cooler before the scrubber, and the scrubber is
designed to ensure high SO- removal efficiency as well as
high utilization of the absorbent, both above 95 percent
in many cases. These factors make the system more costly
8-2
-------
but free from serious scaling problems. The gas cooler
humidifies the gas and prevents local drying in the scrubber,
thus helping to prevent formation of scale. The high SO-
removal and absorbent utilization in the scrubber may reduce
scaling of the mist eliminator, as will be discussed below.
Japanese units are usually provided with spare pumps
but seldom with a standby scrubber because long-term
continuous operation can be carried out without severe
scaling problems.
Saturated or Unsaturated
"Unsaturated mode operation" has been carried out
successfully at the Paddy's Run plant, Louisville Power and
Electric, and at the Omuta plant, Mitsui Aluminum. The
operation prevents gypsum formation by keeping the oxidation
of calcium sulfite below 20 percent and thus permits
scale-free operation.
Japanese processes producing gypsum are usually operated
in the "saturated mode", circulating a slurry containing
gypsum as a crystal seed, and might be more widely applicable
to various gas compositions. Unsaturated mode operation
is not suitable for gases with a low S02/02 ratio such as
that from a low-sulfur coal, because the low ratio encourages
oxidation. Even with a gas from high-sulfur coal, which
normally contains 2,000 to 3,000 ppm SO- and 4 to 5 percent
8-3
-------
09, there is a possibility of scaling in the scrubber
^
because of gypsum formation due to a temporary increase in
the 09 concentration and a temporary decrease in pH of the
slurry as the operation load fluctuates.
Scaling on Mist Eliminator
Scaling tends to occur most readily on mist eliminators
where, in addition to wetting and drying, lime or limestone
from the mist reacts with SO2. The gas passing through the
eliminator usually contains 200 to 400 ppm S02 and 4 to 5 O2
in the U.S. and 20 to 100 ppm SO0 and 1 to 2 percent 09 in
^ £
Japan. In both cases gypsum would form by the reaction with
lime or limestone because of the low SO2/O2 ratio. Washing
the eliminator with fresh water can dissolve the gypsum but
will increase the wastewater load. The scaling may be
reduced by washing with a supernatant of gypsum slurry
containing fine crystals of gypsum, which can serve as
crystal seed, as has been done in Japan.
It has been argued that scale-free operation of wet
lime/limestone process systems in Japan may be due largely
to the low S02 concentration of inlet gas, which is below
600 ppm in many units. However, the inlet S02 concentration
may not be very important because new full-scale systems for
oil- or coal-fired utility boilers (250-500 MW) with SO.-,
concentrations of 1,500 to 1,800 ppm in the gas have been in
8-4
-------
scale-free operation even with frequent changes of operation
load. For prevention of scale on the mist eliminator, the
SO~ concentration in the scrubber outlet gas and the utiliza-
tion of lime or limestone in the scrubber may be important.
The presence of much unreacted lime or limestone in the
mist and much S02 in the gas flowing through the eliminator
would increase formation of gypsum on the eliminator.
In Japan, the outlet SO2 concentration is low because
of the stringent regulation, and the utilization of lime
or limestone usually exceeds 95 percent or 90 percent
because of the necessity to produce high-quality gypsum.
Such a situation may have reduced the scaling on the mist
eliminator. The high utilization of lime or limestone is
obtained by a good gas-liquid contact resulting from suitable
scrubber design, by increasing the liquid/gas ratio, and by
the fine grinding of limestone in a wet mill to pass 325
mesh. The high utilization of lime and limestone tends to
reduce the pH of the slurry, increase the oxidation, and
encourage the formation of gypsum.
Many of the Japanese companies once used a zigzag
baffle-type mist eliminator placed horizontally at the top
of the scrubber, such as is widely used in the United
States, because it is relatively inexpensive; now they
seldom use this type because performance is poor. Many now
8-5
-------
place the mist eliminator vertically in a separate vessel
in the exit duct outside the scrubber because this configura-
tion provides better drainage and better over-all performance.
Effect on Fly Ash and Wastewater on Scaling
The effect of fly ash on scaling is not yet clear.
The ash from coal consists of fine, spherical, glassy
particles having little reactivity. The ash would increase
erosion when present in large amounts in the slurry but not
always increase scaling. It might help prevent scaling
because of its nonreactive, erosive nature, as pointed out by
R.H. Borgwardt, EPA. At present, six FGD systems for coal-
fired utility boilers (160 to 300 MW) are in operation in
Japan. One of them uses the unsaturated mode and the
others use the saturated mode. Operation of all six plants
is virtually trouble-free. They are equipped with
electrostatic precipitators which remove most of the fly
ash, and thus the effect of fly ash has not been clearly
demonstrated.
It has been stated that Japanese FGD units purge waste-
water to add large amounts of fresh water to the system and
thus help to reduce scaling. This view may not be correct,
because the sum of wastewater and moisture in the by-product
gypsum is no larger than in the United States practice, where
the sludge normally contains 60 percent or more water. As
shown in Table 3-8, the water ratio or the equivalent water
8-6
-------
ranges from 26 to 64 percent for the plants using wet
lime/limestone processes.
INDIRECT LIME/LIMESTONE PROCESS
Sodium Scrubbing
In the United States the sodium scrubbing double
alkali processes are simple, as they use lime and by-produce
calcium sulfite sludge; in Japan the processes are fairly
complex, as they use limestone and are equipped with sulfate
decomposition and gypsum recovery units. Limestone is
cheaper than lime but limestone processes require larger
reactors.
In both processes a portion of the sodium sulfite is
oxidized to form sulfate ion, which must be removed from the
system. In the U.S. systems, sulfate ion is removed in two
ways: (1) by entering calcium sulfite crystals replacing
sulfite ion and (2) as sodium sulfate solution contained
in the sludge. The oxidation of the sulfite must be main-
tained under a certain level to prevent accumulation of
sodium sulfate in the liquor. The process suits high-sulfur
coal but may not suit low-sulfur coal, because it needs a
flue gas with a relatively high S02/02 ratio.
The Japanese processes, Kureha-Kawasaki and Showa
Denko,'incorporate a sulfate decomposition unit. This makes
them costly, but they are applicable to any kind of gas.
8-7
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Gypsum grows into much larger crystals than does calcium
sulfite and is washed well. Sodium content in the by-
product gypsum is less than 0.1 percent, whereas in the U.S.
systems the content in the sulfite sludge usually exceeds 2
percent.
Other Indirect Processes
The Chiyoda and Dowa processes are much simpler than
the above-mentioned Japanese processes. Compared with the
U.S. systems, they are more complex because of the require-
ment for an oxidizer; moreover, they need higher L/G ratios
because of the low pH of the absorbing liquor. They do,
however, offer the following advantages: (1) use of lime-
stone, (2) much smaller sizes of thickener and filter, (3)
smaller loss of absorbent, (4) less possibility of scaling,
and (5) applicability to any kind of gas, including that from
low-sulfur coal. They may be most applicable at plants that
do not require very high S02 removal efficiency.
The Kurabo ammonium sulfate and Kureha sodium acetate
processes use lime, as do the U.S. processes. Although they
are less simple than the U.S. processes, they provide some
advantages. The Kurabo process gives virtually no plume,
which has been a common problem for ammonia scrubbing pro-
cesses. The Kureha process can recover more than 99 percent
of the SCL. Although such a high removal ratio is not
8-8
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usually needed, in certain districts it may be a good idea
to treat 70 to 80 percent of flue gas by this process and
then mix the treated gas with untreated hot gas to eliminate
reheating.
OTHER PROCESSES (RECOVERY PROCESSES)
Four types of FGD processes are in commercial use in
Japan to by-produce concentrated S0», which is used to
produce sulfuric acid or is sent to a Glaus furnace to produce
elemental sulfur. These are the Wellman-Lord, magnesium
(or zinc) scrubbing, activated carbon, and the Shell processes.
The Wellman-Lord process has been most widely used
because of smooth operation of the systems and recovery of
virtually all of the SO-, which permits substantial
reduction of the size of the sulfuric acid plant relative
to a conventional plant using 7 to 9 percent SO- gas
obtained by burning pyrite or sulfur. The process, however,
is becoming increasingly costly as regulations concerning
wastewater become increasingly stringent.
The magnesium scrubbing process has the advantage of
giving virtually no wastewater. But operation of a rotary
kiln may not be willingly accepted by power companies. The
recovered S0~, having a low concentration of 7 to 8 percent,
can be used in producing sulfuric acid or in charging into a
Glaus furnace; it is not suitable for reduction to H2S to
produce elemental sulfur. It may be said that magnesium
8-9
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scrubbing better suits chemical plants and oil refineries,
and the Wellman-Lord process better suits power plants.
Carbon absorption with thermal regeneration gives a
moderate concentration of the recovered S02 (about 20 percent)
which can be used for production of both sulfuric acid and
sulfur. Consumption of carbon increases when a moving bed
is used and makes the process costly, particularly in
Japan where good-quality and expensive (about $2,700/t)
carbon is used. Cheaper carbon is useful but has a lower
absorbing capacity and tends to burn during the operation.
The carbon process using a fixed bed and water wash
has proved to consume very little carbon. Although the by-
produced sulfuric acid is weak, it can be concentrated to
about 60 percent by the heat of flue gas, as has been done
by Unitika. The process may be suitable for certain
chemical plants that can use the acid.
The Shell process seems more costly than the other
recovery processes because hydrogen is needed for regenera-
tion. The process is advantageous in that it can effect
simultaneous removal of NO up to about 70 percent.
A.
BY-PRODUCT AND WASTEWATER
Gypsum and Calcium Sulfite
Oversupply of gypsum has presented a problem in Japan
where land for disposal is scarce. Because per capita
8-10
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consumption of gypsum in Japan is still about half of that
in the United States, a considerable increase in future
demand for construction material is expected. Some over-
supply may continue, however. Gypsum is not suitable for
land filling of ground to support large buildings because
it has a little water solubility. A stabilized calcium
sulfite sludge, which has been produced in the United
States, may be better for land filling. Because fly ash
is scarce in Japan, industrial slags may be used instead.
In contrast with current practice, gypsum may be
produced in the future in certain districts in the United
States. Gypsum by-produced from desulfurization of flue gas
from coal has proved useful for cement and wallboard produc-
tion, as recently practiced in Japan. It may be possible to
substitute the gypsum for a portion of that now imported to
the United States which amounts to 7 million tons yearly.
Gypsum can be piled up to heights of more than 100 feet, as
is done at phosphoric acid plants in Florida, thus allowing a
great saving of land space as compared with the use of
calcium sulfite sludge ponds.
Elemental Sulfur
Generally speaking, less effort has been made in Japan
than in the United States to develop FGD processes that
yield elemental sulfur as a by-product. Several oil refineries
8-11
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have installed FGD units to recover concentrated SC>2, which
is sent to an existing Glaus furnace to recover sulfur.
Ammonia scrubbing with the IFF reactor to by-produce sulfur
has been tested by Mitsubishi Heavy Industries and Toyo
Engineering; this effort will be abandoned, however, because
of operational problems including the sulfate decomposition
step. Except for these, active research to develop new
processes has not been made.
This may be due largely to the use of oil as the major
fuel in Japan. Elemental sulfur can be recovered from oil
at lower cost by hydrodesulfurization than by FGD. An
economical process to by-produce sulfur is being sought,
however, for the following two reasons: (1) all other
by-products of FGD are in oversupply, and (2) heavy oil
suitable for hydrodesulfurization to reduce sulfur below
0.5 percent is limited by the content of metallic impuri-
ties that poison the catalyst.
Chloride and Wastewater
When no wastewater purge is allowed, chloride in the
flue gas accumulates in the scrubber liquor and tends to
increase corrosion and decrease SO,, removal efficiency.
In the throwaway sludge process, the chloride concentration
in the liquor may be kept within an acceptable level because
a considerable amount of water is removed from the system
8-12
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with the sludge, which normally contains more than 60 percent
water. In a process by-producing gypsum, which normally
contains less than 10 percent moisture, chloride concentra-
tion in the liquor will exceed 5 percent when the coal burned
is relatively rich in chloride. Plant cost will be increased
by the need for highly corrosion-resistant material, such
as in the Kobe Steel calcium chloride process.
Chloride may be removed in a prescrubber by water wash
of the gas; the liquor from the prescrubber may be neutra-
lized with lime or limestone, and the resulting sludge may
be discarded. In a sodium scrubbing process, a portion of
the scrubber liquor may be concentrated to crystallize and
separate sodium chloride. All such treatments add consider-
ably to the cost of the process. The author believes that
regulations should permit purging of a limited amount of
wastewater after treating it thoroughly to remove any
impurities that may be harmful to the environment.
SIMULTANEOUS REMOVAL OF SO AND NO
X X
The present denitrification efforts in Japan have
been motivated by the quite stringent regulation. NO
X
concentrations in large cities in the United States, such
as Los Angeles and Chicago, are much higher than those in
Tokyo, Osaka, and other Japanese cities. Although a larger
portion of NO in crowded cities is derived from automobiles,
8-13
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NO from coal-fired boilers will become significant as con-
x
sumption of coal increases, because the flue gas is relatively
rich in NO (from 500 ppm to 1,000 ppm) and it is not easy
}t
to reduce the concentration below 400 ppm by combustion
control.
Among the denitrification processes, the Exxon process
injecting ammonia into flue gas at about 800°C without
catalyst would require the least cost. The process has a
narrow range of optimum reaction temperatures, and for
large-scale applications about 50 percent NO removal is
j\.
expected. Catalytic reduction processes using ammonia
can attain over 90 percent removal but entail the problem
of catalyst contamination by dust in the gas. The activated
carbon process can remove about 90 percent of the SO,, and
NO simultaneously but requires a large amount of carbon
X
and also involves a dust problem. The Shell process can
remove about 70 percent of the NO together with about 90
X
percent of the S02 with a smaller dust problem due to the
use of the parallel passage reactor. Selection of a process
should be decided according to the NO removal ratio
X
required.
The dry processes using ammonia entail some common
problems: (1) Formation of ammonium bisulfate in the gas,
which condenses anywhere at lower temperature, for example,
in heat exchangers. (2) Possibility of secondary pollution
8-14
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by emission of ammonia, which may occur to a considerable
extent when the operation load fluctuates. (3) Widespread
use of the ammonia processes on a large scale could cause a
worldwide shortage of nitrogen fertilizer.
For these reasons, it is desired to develop not only
ammonia-using processes but also wet processes for simul-
taneous control. The wet process by-producing ammonia or
ammonium sulfate is desirable from the standpoint of fer-
tilizer supply and will possibly be used extensively in the
future if the process economy can be substantially improved.
For plants where the transportation of ammonia or ammonium
sulfate may be inconvenient, a combination of the Exxon
process with a wet process by-producing ammonia might be
useful. The by-produced ammonia may be returned to the
boiler to reduce a portion of the NO to N_ and thus promote
Ji £
simultaneous removal, for which a low NO /S00 ratio is
X /-
favorable.
8-15
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REFERENCES
The process descriptions in this report are based
primarily on Ando's visits to the desulfurization plants,
his discussions with the users and developers of each pro-
cess, and data made available by them. In addition, the
following publications were used and are cited as refer-
ences.
1. Energy Statistics (1975) Tsushosangyo Kenkyusha (in
Japanese) .
2. Ando, J. , Isaacs, G.A. S02 Abatement for Stationary
Sources in Japan EPA-600/2-76-013a January 1976, Office
of Research and Development. U.S. Environmental Pro-
tection Agency, Cincinnati, Ohio (in English).
3. Hollinden, G.A. and F.T. Princiotta. Sulfur Oxide
Control Technology, Visits in Japan — March 1974. U.S.
Government Interagency Report (October 1974) .
4. Gomi, S., R. Takahashi, et al. Thermal Cracking of
Residual Oils Using Superheated Steam and Application
of the Products. Proceedings of 9th World Petroleum
Congress (1975) (in English) .
5. SOx, NOX Removal Data. Jukogyo Shinbunsha (1975) (in
Japanese) .
6. Morita, T. Pollution Control Engineering Conference.
Japan Management Association (June 1975) (in Japanese) .
7. Williams, W.L. J. Amer. , Soc. Naval Eng. 93, 68 (1956)
(in English) .
8. Chemical Technology Research Meeting, Central Research
Institute for Electric Power Industry (Nov. 5-6, 1975)
(in Japanese) .
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9. Yamamichi, Y. and J. Nagao. Dowa's Basic Aluminum
Sulf ate- Gypsum Flue Gas Desulfurization Process, EPA
FGD Symposium (March 1976) (in English) .
10. Saito, S. , T. Morita, and S. Suzuki. Kureha Flue Gas
Desulfurization Sodium Acetate-Gypsum Process, EPA FGD
Symposium (March 1976) (in English) .
11. Ando, J. SC>2 and NOx Removal Technology in Japan -
1976. Japan Management Association (in English) .
12. Audrieth, L.F. , et al. Sulfamic Acid, Sulfamide, and
Related Aquo-Ammonosulfuric Acids. Symposium on the
Chemistry of Liquid Ammonia Solutions (Milwaukee,
September 1938) (in English) .
13. Yamada, S., T. Watanabe, and H. Uchiyama. Bench-Scale
Tests on Simultaneous Removal of SO? and NOX by Wet
Lime and Gypsum Process. Ishikawajima-Harima Engi-
neering Review, (January 1976) (in Japanese) .
14. Seki, M. and K. Yoshida. Ammonium Ha lide- Activated
Carbon Catalyst to Decompose NOX in Stack Gas at Low
Temperatures around 100 °C. American Chemical Society
(August 1975, Chicago) (in English).
15. Kawakami, W. and K. Kawamura. Treatment of Oil-Fir ed
Flue Gas by Electron Beam. Denkikyokai Zasshi, 29
(December 1973) (in Japanese) .
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1. REPORT NO.
EPA-600/7-77-103a
4. TITLE AND SUBTITLE
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
3. RECIPIENT'S ACCESSION-NO.
». I I [ LE AND SUBTITLE
SO2 Abatement for Stationary Sources in Japan
5. REPORT DATE
September 1977
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Jumpei Ando (Chuo University) and B. A. Laseke
S. PERFORMING ORGAC
noi
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo. Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-01-4147, Task 3
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 3/76-8/77
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES
Mail Drop 61, 919/541-2915.
project officer for this report is J. David Mobley,
16. ABSTRACT
The report describes the status of SO2 abatement technology for stationary
sources in Japan as of June 1976. It presents the current status of desulfurization
technologies including hydrodesulfurization of oil, decomposition of residual oil, gasi-
fication of coal and oil, and flue gas desulfurization (FGD). It examines the major
Japanese FGD processes with respect to their applications, performance, economics,
major technical problems, developmental status, byproducts, and raw materials. It
also contains background information on energy usage, fuel resources, ambient con-
centration of pollutants, and emission regulations in Japan. It describes processes
for the simultaneous removal of SOx and NOx from flue gases. It presents a com-
parative evaluation of flue gas cleaning technologies in the U.S. and Japan.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS-
c. COSATl Field/Group
Air Pollution
Sulfur Dioxide
Flue Gases
Desulfurization
Fuel Oil
Residual Oils
Coal Gasification
Nitrogen Oxides
Energy
Regulations
Air Pollution Control
Stationary Sources
Japan
Hydrodesulfurization
Oil Gasification
13B
07B
21B
07A,07D
2 ID
13H
05D
3. DISTRIBUTION STATEMEN1
Unlimited
19. SECURITY CLASS (ThisReport)'
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
.—I
EPA Form 2220-1 (9-73)
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