EPA 450 9 73 001
FLUE GAS
DESULFURIZATION
Answers
to
Basic Questions
US ENVIRONMENTAL PROTfCTION AGfNCY
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EPA-450/9-73-001
FLUE GAS DESULFURIZATION
Answers to Basic Questions
Emission Standards and Engineering Division
ENVIRONMENTAL PROTECTION AGENCY
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
October 1973
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This report is published by the Environmental Protection
Agency to report information of general interest in the field
of air pollution. Copies are available free of charge to
Federal employees, current contractors and grantees, and
nonprofit organizations - as supplies permit - from the Air
Pollution Technical Information Center, Environmental
Protection Agency, Research Triangle Park, North Carolina
27711.
Publication No. EPA-450/9-73-001
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FLUE GAS DESULFURIZATION
Answers to Basic Questions
INTRODUCTION
In the late 1960's, many state and local jurisdictions
enacted regulations to curb 5)0*2 emissions from coal- and
oil-burning power plants. The effect of such regulations
was a trend toward the use of low-sulfur oil and coal, and,
where possible, of the cleanest fuel, natural gas.
With the Clean Air Act of 1970, limits for SO2 emis-
sions from fuel-burning sources became more widespread
as state plans were adopted to achieve national ambient
air quality standards. At the Federal level, new-source
performance standards were enacted to limit S02 emissions
from new steam generators of power plant size. Because
of shortages of natural gas arid of low-sulfur coal and oil,
these limitations cannot be met solely by switching to low-
sulfur fuels. It is apparent that coal of medium-to-high
sulfur content will have to be burned in increasing quan-
tities by power plants to meet growth requirements and to
safeguard an adequate supply of clean fuels for residential,
commercial, and industrial use.
The burning of such sulfur-bearing fuels in steam-
electric power plants causes appreciable SO2 air pollution.
Generation of electricity in 1970 produced about 20 million
tons of SO2, which was approximately 55 percent of the man-
made SO2 emissions to the nation's atmosphere in 1970. If
not controlled, annual SO2 emissions from power plants
could rise to as high as 80 million tons in the year 2000.
In the next 10 years, the principal alternative to the com-
bustion of low-sulfur fuels will be the use of flue gas desul-
furization (FGD) systems. Such systems can be used in con-
junction with all types of fuels but they are particularly
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appropriate for cleaning gases from the combustion of
medium-to-high-sulfur coals, which constitute the largest
segment of the nation's fuel reserves. The power industry,
with some exceptions, has been slow to install FGD systems,
maintaining that their effectiveness and applicability have
not been proved. This contention has been the principal
basis on which standards have been challenged in the courts.
A recent opinion of the U.S. Court of Appeals, however, up-
held EPA's new-source performance standard for coal-fired
steam generators of power plant size. In so doing, the Court
found that FGD technology has been adequately demonstrated
and that the promulgated standards are achievable.
The purpose of this publication is to provide a better
understanding of flue gas desulfurization and to
answer questions raised throughout the country concerning
its applicability, cost, effectiveness, and operation.
More detailed technical discussions are available in such
publications as the Federal interagency (SOCTAP) report,
Projected Utilization of Stack Gas Cleaning Systems by
Steam-Electric Plants~"(APTD-l"569) . Copies of the latter
report are available from:
National Technical Information Service
5285 Port Royal Road
Springfield, Virginia 22151
Price $4.85
Further publications on this subject are listed in "Air
Pollution Technical Publications of the U.S. Environmental
Protection Agency," which is available, along with the publi-
cations, from:
Air Pollution Technical Information Center
Research Triangle Park, North Carolina 27711
IV
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FLUE GAS DESULFURIZATION
Answers to Basic Questions
Q. What is a flue gas desulfurization (FGD) system?
A. FGD systems selectively remove sulfur dioxide (SO2)
from gas streams through physical and/or chemical
action. Most present-day FGD systems use wet scrub-
bers as the S02 removal device. Alkaline materials in
the aqueous media react chemically with 502 to form
salts, primarily sulfites and sulfates.
Q. Why is flue gas desulfurization important?
A. FGD systems provide an immediate, proved method for
controlling SO2 emissions from the burning of high-
sulfur coal, which is the nation's most abundant natural
fuel resource. Oil and natural gas are in short supply,
coal gasification is still under development, and alterna-
tive energy sources offer only long-range solutions.
Hence, flue gas desulfurization is the only readily avail-
able alternative to the use of low-sulfur fuels, which
are scarce, costly, and often available only from foreign
sources.
Q. Has the Clean Air Act of 1970 imposed hardships on the
power generating industry in terms of time required to
develop, finance, and install FGD systems?
A. While the widespread adoption of regulations by states
under the 1970 Act has required appreciably increased
pollution control action by utilities, the need to control
SO2 did not come as a surprise to anyone. Projections
made by the power industry (1964, 1966, and 1970) have
indicated a continuing and increasing dependency on
coal-generated electricity.
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Q. Have electric utilities in the United States had much
experience with FGD systems?
A. Pilot plant studies were conducted over 20 years ago at
Tennessee Valley Authority plants and have been con-
ducted more recently by Detroit Edison and Wisconsin
Electric. Operation of full-scale FCD systems was initi-
ated in 1967 and 1968 by the Union Electric Company at
a station in St. Louis, Missouri, and by the Kansas
Power and Light Company (KPL) at its Lawrence, Kan-
sas, station. Both of these companies installed limestone
scrubbing systems on steam electric generators of
greater than 100-megawatt capacity. KPL, and the
designers of the system, have incorporated many im-
provements into the Lawrence station and most of the
process problems have been solved. During 1972 and
1973, several additional systems have begun operation.
The attached table lists 37 FGD systems that either have
been installed or ordered in the United States. They
represent a total of about 14,000 megawatts, or about
9 percent of the current U.S. coal-fired electricity-
generating capacity.
Q. What other countries besides the United States have been
investigating flue gas desulfurization?
A. The first FGD systems were operated in England prior
to World War II and some of these are still in operation.
More recently, pilot and prototype installations have
been operated in Japan and in Sweden and other Euro-
pean countries. The greatest effort has been in Japan,
where successful systems are in operation and more
are being installed. A lime system has been success-
fully used in Sweden since 1969 and has achieved high
SO2-removal efficiency together with reliable operation.
Q. What FGD methods are available?
A. Many processes are available, but only four are con-
sidered sufficiently developed to make a potentially
significant contribution to the control of S02 from power
plants within the next 5 years: wet lime/limestone
scrubbing; magnesium oxide scrubbing with regenera-
tion; catalytic oxidation; and sodium sulfite scrubbing
with regeneration. Most scrubbers that have been in-
stalled in the United States and abroad have utilized
lime or limestone base slurries that react with SO2 in
stack gases to form manageable residues (slurries) .
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Q. Is the technology of FGD more complex than that of most
industrial chemical processes?
A. No. FGD systems employ relatively simple process
operations requiring far fewer interrelationships than
most chemical processes. They include some of the
same unit operations that have been used for years in
the chemical industry. Problems that have been en-
countered in the application of FGD systems to power
plants are similar to problems routinely solved by the
chemical industry.
Q. How much of the sulfur dioxide in flue gases can be
removed with available FGD systems?
A. Most of the systems being installed in the United States
and abroad are designed to achieve 70 to 90 percent or
greater SO- removal. Though almost any efficiency can
be achieved, economics dictates a cutoff. Reasonable
S02~removal efficiencies of the four developed FGD
processes are: 80 to 90 percent for wet lime/limestone
scrubbing; 90 percent for magnesium oxide scrubbing;
85 to 90 percent for catalytic oxidation; and 90 percent
for regenerable sodium sulfite scrubbing. The above
efficiencies have been achieved on a long-term basis at
the Mitsui Aluminum plant near Omuta, Japan, and at
the Japan Synthetic Rubber plant near Chiba, Japan,
with the lime and regenerable sodium sulfite processes,
respectively. An efficiency of 90 percent has been
achieved with a prototype magnesium oxide system at
Boston Edison's Mystic plant (Massachusetts) .
Q. What is the cost of installing and operating an FGD
system?
A. Capital costs for new or retrofit installations generally
range from $30 to $65 per kilowatt as compared with the
capital cost of a coal-fired steam electric plant of approx-
imately $250 per kilowatt. Capital costs for retrofitting
systems to existing generating plants in most cases are
expected to be in the range of $45 to $65 per kilowatt.
For some retrofitted plants, installation costs have been
estimated as high as $80 per kilowatt or more. Some
contractor estimates are: $63 for TVA (Alabama); $27
for Northern States Power (Minnesota); $40 for Kansas
City Power and Light (Missouri); and $39 for Boston
Edison (Massachusetts) .
The estimated annual costs for FGD range from 1.2 to
3.2 mills per kilowatt-hour, with a mean of about 2.0
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mills per kilowatt-hour. By comparison, the average
national consumer cost for power is about 18 mills per
kilowatt-hour. Assuming FGD costs are passed on, con-
sumer rates for electricity would increase by about 11
percent for that portion of the utility system for which
FCD is required. Few utilities will be required to equip
their entire network of steam generators with FCD sys-
tems.
Q. Why is the cost of retrofitting existing plants greater
than the cost of installing FCD systems on new plants?
A In general, it is more expensive to retrofit FGD systems
than to include them in new construction because of
limited space at existing sites and the need to move
existing facilities (railroad sidings, tanks, etc.) to
install extraordinarily strong footings and other ancil-
lary equipment. Some utilities have reported retrofit
costs in excess of $100 per kilowatt. These generally
represent very difficult installations and should be
considered atypical.
Q. Do rate structures set by public utility commissions
affect the installation of FGD systems?
A. Besides installing FGD systems, utilities can meet SO2
standards by converting coal-fired plants to low-sulfur
oil or by securing low-sulfur coal. To many utilities,
low-sulfur fuel alternatives appear more attractive than
FGD systems because they involve relatively small capi-
tal investments and shift a potential capital cost to an
operating cost. In a number of states, utilities are now
able to pass on to the consumer most of the incremental
operating costs of higher priced fuels by means of "fuel
adjustment" provisions. The fuel adjustment charges
may be passed directly to the consumer via the monthly
bill without further action by the regulatory commission.
On the other hand, increases in generating costs result-
ing from the acquisition of capital equipment and the
higher operating costs of FGD systems usually can be
compensated for only by rate increases that require
action by utility commissions. Not only do utilities
have to wait for this compensation until the regulatory
commissions act, but they sometimes have to "absorb"
a portion of the additional costs. Presently, many
commissions treat capital expenditures and operating
costs incurred for pollution abatement devices in the
same manner.
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Recent legislation in some jurisdictions provides incen-
tives for the use of air pollution control equipment
by allowing for automatic rate adjustments that compen-
sate for pollution control equipment as well as for the
cost of fuel changes.
Q. Has the utility industry supported or conducted research
on air pollution control in general and sulfur dioxide
control in particular?
A. The utility industry has not given a high priority to
research and development (R & D), but will be required
to spend considerably more on R S D in the future. For
the past decade,electric utilities have been supporting
R S D at a level estimated to be equivalent to approxi-
mately 0.25 percent of gross electrical revenues. In
1971, the utility industry reportedly spent $99 million
for R S D. Approximately $40 million was spent for air
pollution control, of which at least $23 million was allo-
cated for the control of SC>2 emissions.
The Electric Research Council Task Force on R & D
estimated that R S D expenditures by utilities, manu-
facturers, and the Federal government will rise to
$1. 209 billion in 1977. Roughly 75 percent of the pro-
jected R S D will be for improved energy conversion,
about 15 percent for transmission and distribution, and
only 9 percent for environmental needs.
Q. Have designers solved the principal difficulties experi-
enced with lime/limestone systems?
A. The problems with existing systems can be grouped into
process and materials problems. The process problems
include scaling (formation of calcium salts on scrubber
surfaces), and plugging of boiler passages, scrubbers,
packing, demisters, and reheaters. Materials problems
are mainly corrosion and erosion of principal equipment.
Some materials problems are inherently connected with
process problems. For instance, in some systems it has
been difficult to control pH, so that the solution becomes
highly acidic, causing considerable corrosion. Refine-
ment of the process to the point that pH can be kept with-
in the noncorrosive range will prevent much of the mate-
rial damage. The continuing development of corrosion-
resistant materials is diminishing the importance of acid
corrosion.
Solutions to both materials and process problems have
been found although all process parameters have not been
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optimized. In spite of difficulties encountered with them,
lime/limestone systems will probably be the primary
scrubbing system used in the immediate future. For the
longer term, regenerable systems producing marketable
byproducts may predominate.
Q. How long does it take to design and install an FGD system?
A. Commercial units have generally taken less than 2 years
to install but in the future may take somewhat longer if
demands exceed the production capacities of vendors.
A magnesium oxide scrubber at Boston Edison's Mystic
Station took 21 months from issuance of contract to start-
up. A lime scrubber installed at Mitsui Aluminum in
Japan needed only 10 months from completion of specifi-
cations to completion of construction. A difficult retrofit
of a limestone scrubber at Commonwealth Edison's Will
County Station (Illinois) took just under 2 years from the
time scrubbing was first considered to time of startup.
Q. How long is a boiler out of operation when a scrubber is
being installed?
A. A period of 4 to 6 weeks is normally required to tie in a
scrubber to a utility power boiler. In some cases, the
period may be somewhat longer. Everything but the
final connecting duct is completed; then the boiler is
shut down and final duct connections are made as
quickly as feasible.
Each boiler has a normal maintenance downtime of at
least 2 weeks every 12 to 18 months. Maintenance down-
time can be used to tie in the scrubber, holding the net
boiler firing time loss to about 3 to 4 weeks.
Q. What kind of guarantees are offered by vendors of FGD
systems?
A. In general, vendors will guarantee S02 removal under
specified conditions agreed upon with the operator, and
they will guarantee the mechanical parts of the system
for 1 year. These conditions are consistent with guaran-
tees offered on boilers, steam turbines, and other equip-
ment purchased by the electric utility industry. Not
only do they offer written guarantees, but these com-
panies have reputations to uphold and expect to derive a
significant portion of their revenue in the future from
the installation of FGD systems.
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Q. How much sludge is produced from lime/limestone
systems?
A. Ten pounds of coal containing 3 percent sulfur will pro-
duce 2 to 3 pounds of sludge, excluding fly ash, assum-
ing that the sludge contains 25 to 50 percent water.
Q. What can be done with the solid wastes from lime/lime-
stone scrubbing processes?
A. Most of the presently operating lime/limestone systems
dispose of sludge materials in ponds on the site. If
sufficient land is available, the pond is designed to store
wet sludge material over the lifetime of the power plant.
When land is not available at a plant site, the solids can
be dewatered with clarifiers, filters, or centrifuges and
transported, as sludges, by barge, truck, train, or
pipeline to a landfill site.
Chemical fixation processes are available that will re-
lieve problems that can result from the nonsettling of
some sludges, although the costs of such fixation are not
well established at this time. Such processes generally
involve pozzolanic (cementitious) chemical reactions
with fly ash and an additive such as lime; these reactions
lead to the formation of a dry, solid, chemically inert
material that is acceptable for landfill purposes.
Q. What potential water pollution problems are associated
with FCD systems?
A. Liquids in alkaline scrubbing systems contain dissolved
and suspended salts, some of which are reducing com-
pounds, i.e. , they remove oxygen from the liquid. The
resultant liquid has an appreciable chemical oxygen
demand (COD) and is deleterious to aquatic plant and
animal life if allowed to enter rivers, lakes, etc. In
addition, ground water and watercourses could be
contaminated by seepage from sludge ponds. The possi-
bility of water pol lution is more apparent with lime/
limestone systems than with regenerable sodium and
magnesium base systems. There is little potential water
pollution from dry processes and from the catalytic oxi-
dation process.
Q. How can ground water and watercourse contamination
from lime/limestone sludge disposal ponds be prevented?
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A. Water contamination can be prevented by operating lime/
limestone wet scrubbing systems in a closed loop.
Closed loop means that all liquor entering the pond is
recycled to the scrubber circuit; no sludge liquid is
released to any watercourse.
To avoid seepage of liquor through the walls and floors
of the disposal ponds, a sealant such as clay, tar, or
plastic can be used if necessary. Present information
indicates that ponds tend to seal themselves as sludge
builds up.
Q. Why can't we use nuclear power and eliminate the incon-
venience of FCD systems?
A. There have been numerous delays in the siting and con-
struction of nuclear plants. In addition, there are un-
resolved environmental problems involved in these
operations. Although it is expected that nuclear plants
eventually will replace fossil fuel plants, no resultant
reduction in SO2 emissions is expected until after the
year 2000.
Q. Don't FGD systems intensify the fuel shortage?
A. FCD will, in fact, lessen the fuel crisis by enabling us to
employ high-sulfur coals and thus to utilize more of our
very large coal reserves while conserving oil and gas,
which are in short supply. Furthermore, it is estimated
that, because clean fuels are in short supply, FCD sys-
tems will have to be applied to some 50,000 megawatts
of existing electric generator capacity if air quality
standards are to be met by 1977.
Q. Have any power plants achieved particular success in
operating an FGD system?
A. The lime scrubbing system at the Mitsui Aluminum plant
in Omuta, Japan, has demonstrated an enviable record
since it was first put into operation in March 1972. Other
systems installed on oil-fired boilers in Sweden and
Japan have been as successful, but the Mitsui system is
significant inasmuch as it has been operated continuously
for more than 1 year on a coal-fired unit. The Mitsui
scrubber was designed by an American chemical engi-
neering firm that markets the same process in the
United States. It serves a 156-megawatt coal-fired instal-
lation that generates electricity for a primary aluminum
plant and also sells electricity to a neighboring utility.
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Q. Can the Mitsui scrubbing system be used on U.S. power
plants?
A. The system is considered applicable to U.S. power
plants for the following reasons:
1. The inlet SO2 concentrations in the Mitsui scrub-
bing system are quite similar to those found in
plants throughout the U.S.
2. Carbide sludge (calcium hydroxide) used at the
Mitsui plant and various grades of U .S . lime
react similarly in scrubbing systems.
3. The Mitsui plant operates with a nearly constant
electrical output, but has been subjected to
enough variations in demand and flue-gas SO2
concentration to demonstrate that the scrubbing
system can handle varying stack-gas volumes.
The majority of the newer and larger U.S. power
plants are not subjected to widely fluctuating
loads.
Most future American applications of lime scrub-
bing systems should involve steam generators as
large or larger than the 156-megawatt Mitsui in-
stallation. These can use multiple scrubbing
units (modules) . It does not appear than any
modules with greater than about 150-megawatt
capacity will be utilized.
5. Fly ash removal at the Mitsui plant is accompli-
shed with a relatively efficient, previously exist-
ing electrostatic precipitator . Similar equip-
ment already exists at many U.S. power plants.
The Mitsui calcium sulfite/calcium sulfate efflu-
ent bleed disposal system is designed to operate,
and has operated, as a closed recycle loop be-
tween the scrubbers and the disposal ponds.
The recycle liquor has been totally saturated
with sulfate for extended periods of time (months)
without the occurrence of significant scale build-
up or other deposition in the scrubbers.
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Q. Has the Mitsui type of flue gas desulfurization system
been installed at any U.S. plants?
A. Similar systems are being installed at utility plants in
two Pennsylvania locations. The first of these will be
put into operation in late 1973 at the Philips station of
the Duquesne Light Company.
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SULFUR DIOXIDE STACK GAS CLEANING SYSTEMS INSTALLED AT
OR ON ORDER FOR U.S. ELECTRIC GENERATING STATIONS
Plant
1. Kansas Power and Light
Lawrence #4
2. Kansas Power and Light
Lawrence #5
3. City of Key West
Stock Island #1
4. Kansas City Power and Light
Hawthorne #3
5. Kansas City Power and Light
Hawthorne #4
6. Louisville Gas and Electric
Paddy's Run #6
7. Commonwealth Edison
Will County #1
8. Boston Edison, Mystic #6
9. Illinois Power, Wood River
10. Kansas City Power and Light
La Cygne
11. Detroit Edison Company
St. Clair #6
12. Arizona Public Service
Cholla
13. Duquesne Light Company
Philips
14. Northern States Power
Company
Sherburne Company #1
15. Northern States Power
Company
Sherburne Company #2
16. Nevada Power Company
Reid Gardner #1
17. Nevada Power Company
Reid Gardner #2
18. Nevada Power Company
Reid Gardner #3
19. Philadelphia Electric
Company
Eddystone #1
20. Potomac Electric and Power
Dickerson #3
21. TVA, Widow's Creek #8
22. N. Indiana Public Service
Company
D. H. Mitchell #11
Processa
L
L
L
L
L
L
L
M
C
L
L
L
L
L
L
S
S
S
M
M
L
S
Capacity,
MW
125
430
37
130
130
70
175
150
100
820
180
115
100
680
680
125
125
125
120
100
550
115
Start-up
date
12/68
11/71
10/72
11/72
8/72
4/73
2/72
4/72
10/72
5/73
12/73
4/73
6/73
5/76
5/77
6/73
6/73
75
6/73
7/73
5/75
7/74
Fuel
Coal
Coal
Oil
Coal
Coal
Coal
Coal
Oil
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
% Sulfur
in fuel
3.5
3.5
2.8
3.5
3.5
3.5
3.5
2.5
3.3
5.3
3.8
1
2
1.2
1.2
1
1
0.8
2.5
3
3.7
3.5
11
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SULFUR DIOXIDE STACK GAS CLEANING SYSTEMS INSTALLED AT
OR ON ORDER FOR U.S. ELECTRIC GENERATING STATIONS
(Continued)
Plant
23. S. California Edison and
S. W. Utilities
Mohave #1
24. S. California Edison and
S. W. Utilities
Mohave #2
25. Indiana and Michigan
Electric
Tanners Creek
26. Ohio Edison and Others
Bruce Mansfield #1
27. Ohio Edison and Others
Bruce Mansfield #2
28. Public Service of Indiana
Gibson Company
29. Potomac Electric and Power
Dickerson #4
30. Potomac Electric and Power
Dickerson #5
31. Potomac Electric and Power
Chalk Point #3
32. Potomac Electric and Power
Chalk Point #4
33. S. California Edison and
S. W. Utilities
Navajo #1
34. S. California Edison and
S. W. Utilities
Navajo #2
35. S. California Edison and
S. W. Utilities
Navajo #3
36. Montana Power Company
Colstrip #1
37. Montana Power Company
Colstrip #2
Process^
L
L
D
L
L
L
L
L
M
M
L
L
L
L
Capacity,
MW
160
160
150
880
880
650
850
850
630
630
750
750
750
720
Start-up
date
73
74
74
75
76
76
76
77
75
76
3/76
to
3/77
3/76
to
3/77
3/76
to
3/77
6/75
Fuel
Coal
Coal
_
Coal
Coal
Coal
Coal
Coal
Oil
Oil
Coal
Coal
Coal
Coal
% Sulfur
in fuel
0.5
0.5
-
4.3
4.3
1.5
2
2
_
_
0.8
0.8
0.8
0.8
al_ - Limestone/lime scrubbing.
M - MgO scrubbing.
C - Catalytic oxidation.
S - Sodium-base scrubbing.
D - CuO adsorption, dry process.
12
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