United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-83-041 Nov. 1983
Project Summary
Status of Dry SOa Control
Systems: Fall 1982
M. E. Kelly and M. A. Palazzolo
Reported is the updated status
through the Fall of 1982 of dry SO2
control systems for coal-fired utility and
industrial boilers in the U.S. It is based
on current and recent research, research
and development, and commercial
activities. Systems addressed include:
(1) spray dryer/fabric filter or electro-
static precipitator (ESP), (2) dry injection
of alkali into flue gas followed by
collection of paniculate*, (3) combus-
tion of coal/alkali mixtures, and (4)
electron-beam (E-beam) irradiation
followed by particulate matter collec-
tion . The first two systems provide both
SO2 and particulate matter removal; the
last two provide simultaneous SO2 and
NOX control.
Of the four systems, only spray drying
has been commercialized; E-beam
irradiation has not yet been tested
beyond pilot scale. Dry injection of
nahcolite into flue gas has been suc-
cessfully demonstrated with a 22 MWe
utility unit; unavailability of nahcolite
hinders commercialization of this
technology. Tests using low NOx burners
for combustion of pulverized-coal/
limestone mixtures have indicated SO2
captures of up to 70 percent in small
scale tests; efforts to optimize SO, and
NOx removal by this technology (lime-
stone injection into a multistage burner
[LIMB]) are underway.
Including four new utility systems
sold since the last status report (Fall
1981) brings the total capacity served
by dry flue gas desulfurization (FGD) to
about 6200 MWe. Eight commercial
industrial spray dryer systems have now
been sold; two were added since last
report. Systems now on-line are meeting
guarantees. Operating experience with
these systems is given in this report.
This Project Summary was developed
by EPA's Industrial Environmental
Research Laboratory, Research Triangle
Park, NC, to announce key findings of
the research project that is fully docu-
mented in a separate report of the same
title (see Project Report ordering
information at back).
Introduction
The report described here updates the
Fall 1981 status of dry flue gas desulfur-
ization (FGD) processes in the U.S. for
both utility and industrial applications.
For this project, dry FGD is defined as any
process which involves contacting a
sulfur-containing flue gas with an
alkaline reagent and which results in a
dry waste product for disposal. This
includes (1) systems which use spray
dryers for a contactor with subsequent
baghouse or electrostatic precipitator
(ESP) collection of waste products; (2)
systems which involve dry injection of
alkaline reagent into the flue gas with
subsequent baghouse or ESP collection;
(3) other varied dry systems which are
primarily concepts that involve addition of
alkaline reagent to a fuel prior to
combustion; and (4) systems which involve
reagent injection into the flue gas
followed by electron-beam (E-beam)
irradiation. The definition excludes
several dry adsorption or "acceptance"
processes (e.g., the Shell/UOP copper
oxide process and the Bergbau-Forschung
adsorptive char process) since the status
of these processes has been documented
in previous EPA reports. Fluidized-bed
combustion is also excluded.
The regenerable Rockwell Aqueous
Carbonate Process (ACP) is also excluded.
Although the process is based on SO:
removal with a spray dryer, it does not fit
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the limitation of being a "throwaway"
system. However, the open-loop spray-
dryer contactor portion of the Rockwell
process has been adapted for a "throw-
away" system and, as such, is included in
the report.
The report is divided into five sections:
(1) the first presents generalized process
descriptions of the four technologies
covered (spray drying, dry injection,
combustion of coal/alkali mixtures, and
E-beam irradiation); (2) the second, an
overview of the current status of dry FGD
systems, summarizes recent commercial
and developmental activities for each
type of process and gives highlights of re-
cent technological developments, includ-
ing design and operating experience with
commercial systems; (3) the third gives
detailed discussions of commercial acti-
vities and current and recently completed
research work and demonstration pro-
grams, including discussions of the acti-
vities of each organization or vendor in-
volved with dry FGD processes with re-
spect to current and future research and
development programs and commercial
system sales; (4) the fourth discusses
technical results from full-scale dry FGD
operation and recent research and
development programs, focusing on re-
ported commercial system design and
operating problems and their solutions;
and (5) the fifth gives research highlights
in the area of dry FGD waste characteriza-
tion and disposal, including current and
planned disposal methods for com-
mercial-sized dry FGD systems sold to
date.
Summary of Project Findings
Interest in dry SOzcontrol has remained
strong during the 1-1/2 years since the
last survey was published. Four new
utility and two new industrial spray
drying systems have been sold, and
operating experience with a number of
full-scale commercial systems has been
reported. Information has been published
on the use of spray drying for high sulfur
coal applications, an area that is the focus
of several current or recently completed
pilot- and demonstration-scale test
programs. New data are reported for both
dry injection and limestone injection in a
multistage burner (LIMB) technologies.
The Department of Energy (DOE) program
for the development of electrdn-beam IE-
beam) irradiation techniques for combined
SOz and NO, removal is also discussed.
Work is also continuing in the waste
disposal area. Studies focus on character-
izing solid waste properties as a function
of coal type and FGD process conditions
and on defining suitable waste disposal
or utilization methods.
Highlights of New
Developments
Spray drying continues to be the only
dry SO2 control process commercially
applied to utility or industrial boilers. Four
new utility systems have been awarded
since the last survey, bringing the total
utility spray drying FGD capacity to about
6200 MWe, including a 110 MWe system
at Northern States Power Co.'s Riverside
Station and a 100 MWe system at Pacific
Power and Light Co.'s Jim Bridger
Station.-Both systems have been retrofit
to existing boilers and are currently
operated by the respective system
vendors as demonstration units. The
utilities may, however, commercially
operate the systems after the demonstra-
tion programs are complete.
Two new industrial awards have been
made since late 1981, making a total of
eight spray drying systems applied to
industrial boilers.
Performance and compliance test
results were recently reported for two
utility systems (Montana-Dakota Utilities'
Coyote Station and the Jim Bridger
system) and three industrial systems
(Argonne, Strathmore, and Container
Corporation). Data from tests at the
Riverside system and results of pilot-
scale testing funded by EPA and DOE
have also been published. In general, the
performance test results show that the
commercial systems have met or exceeded
SO2 and particulate matter removal
guarantees. Recently published data also
indicate that 90 percent or greater SO2
removal is achievable for high sulfur coal
applications (3-3.5 percent sulfur coal
with a corresponding inlet SO2 concen-
tration of 2000-2500 ppmv).
Several commercial spray drying
systems are in the initial start-up stages
or entering the final phase of construction.
Four utility and two industrial systems
should have been in start-up or perfor-
mance test stages by the end of 1982.
Three more utility and two additional
industrial systems are scheduled to be
operating by the end of 1983.
Vendors report having several utility
system bids under evaluation. The market
outlook for industrial boiler spray drying
systems has been clouded by delays in
the proposal of new source performance
standards (NSPS). However, market
opportunities may still be generated in
situations where SO2 or combined S02
and particulate control is required by
state or local regulations or for prevention
of significant deterioration (PSD) permits.
A major development in spray drying
has been the recent successful application
of the technology to higher sulfur coal-
fired boilers. Data have been made
available from two full-scale industrial
systems (Argonne and Strathmore), the
Riverside demonstration tests, EPA-
funded tests at Martin Drake, and DOE-
funded tests at the Pittsburgh Energy
Technology Center. All of these results
were obtained at flue gas inlet SO2
concentrations of greater than 2000
ppmv. The data generally indicate that, at
a relatively close approach to saturation
of 18-25°F*, reagent ratios of at least
1.35 are required to achieve 90 percent
SO2 removal.
Operating experience with full-scale
commercial systems has been reported
as relatively trouble-free, although some
systems experienced problems with
atomization and buildup of wet solids on
the dryer walls during initial operation.
Spray drying demonstration and pilot-
scale testing and research continues to
focus on refinement of spray dryer design
and operation, comparison of rotary and
nozzle atomizers, and investigation of the
mechanisms and benefits of solids
recycle for lime systems. Other areas of
spray drying research and development
include optimization of lime slaking and
investigation of alternate reagents such
as limestone, dolomitic lime, adipic-acid-
enhanced lime and limestone, and MgO.
Dry injection technology has not yet
been commercially applied to utility or
industrial boilers. However, EPRI recently
published data from a demonstration
test of the process on a 22 MWe system at
Public Service Company of Colorado's
Cameo Station. SO2 removals of 75-83
percent were demonstrated with nahcolite
at a reagent ratio of 1.0 mole NazO per
mole of inlet SO2 and an inlet SO2
concentration of about 450 ppmv.
The commercial application of dry
injection continues to be constrained by
uncertainties regarding reagent cost and
reagent availability and waste disposal
concerns related to the undesirable
solubility and teachability properties of
the sodium-based waste products. Nah-
colite, generally found associated with oil
shale deposits, is not currently mined in
commercial quantities. Multi Mineral
Corporation of Grand Junction, CO, is the
only firm that has publicly announced
intentions to develop a commercial
nahcolite mining operation.
The LIMB process is still in the
relatively early stages of development.
(*) Although EPA policy is to use metric units, certain
nonmetric units are used in this summary for
convenience. Readers more familiar with the
metric system may use the conversion factors at
the back.
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EPA plans to continue evaluating the
technology on laboratory burners as well
as on commercial boilers of various
designs. At least two U.S. boiler manu-
facturers are reported to be conducting
pilot-scale tests of the LIMB concept. One
of the companies, Baocock and Wilcox
(B&W), has investigated furnace lime-
stone injection followed by spray drying.
Additional testing of this concept is to be
performed by B&W under DOE sponsor-
ship. Furnace limestone injection has
also been investigated at DOE's Grand
Forks Energy Technology Center.
Considerable development work re-
mains before the LIMB concept or other
technologies involving furnace limestone
injection are commercially applicable.
However, a number of factors are
providing impetus for continued develop-
ment of such technologies, including:
desirability of combined SOz/NOx con-
trol, incentives for developing lower cost
SO2 control techniques, and the potential
for acid rain legislation requiring retrofit
SOa control. A key factor in determining
the applicability of UMB technologies for
specific boilers will be the minimization of
potential adverse effects on boiler
operation (e.g., fouling or slagging caused
by firing a mixture of coal and limestone).
EPA recently provided funding for a
program designed to investigate the
effects of LIMB on the design and opera-
tion of the boiler and downstream pollu-
tion control equipment.
The E-beam irradiation process is also
aimed at achieving simultaneous SOz
and NO, control. The primary activities
being funded by DOE in this area are
pilot-scale tests of two process concepts
and kinetic studies. DOE sees the
potential for increased emphasis on
stationary source N0« control as provid-
ing a major incentive for developing a
technology with the potential for achieving
combined SOz and NO. control in the 70-
90 percent removal range.
Spray Drying—Commercial
Activities
Tables 1 -4 present the key features of
the utility and industrial boiler spray
drying FGD systems sold to date. Utility
systems are covered in Tables 1 and 2,
and Tables 3 and 4 provide similar
information for industrial boiler systems.
Utility Systems
Table 1 shows the 17 utility systems
sold to date. The applications range in
Tablet.
Summary of Utility Spray Drying Systems Sold (November 1982)
Station/ Size
System Purchaser
Northern States
Power Co."
Pacific Power and Light'
Otter Tail Power Co.
(Montana-Dakota Utilities)
United Power Assoc.
Marquette Board of Light
and Power
Basin Electric Power Coop.
Colorado Ute Electric
Assoc.
Basin Electric Power
Coop.
Basin Electric Power
Coop.
Tucson Electric Power
Tucson Electric Power
Plane River Power
Authority
Sunflower Electric
Sierra Pacific Power
Grand River Dam
Authority-State of
Oklahoma
Northern States
Power Company
Cajun Electric
Location
Riverside. Units 6 and
7 (Minneapolis. MN)
Jim Bridger. Unit 2,
(Rock Springs. WY)
Coyote, Unit 1
(Beulah. NO)
Stanton. Unit 1A
fStanton. NO)
Shiras, Unit 3
(Marquette. Ml)
Laramie River,
Unit3
(Wheat/and. WY)
Craig, Unit 3
(Craig. CO)
Antelope Valley.
Unitl
(Beulah. NO)
Antelope Valley.
Unit 2
(Beulah. NO)
Springerville, Unit 1
(Springe/villa. AZ)
Springerville. Unit 2
(Springerville. AZ)
Rawhide. Unit 1
(Fort Collins. CO)
Holcomb, Unit 1
(Holcomb. KS)
North Valmy
(Valmy. NV)
Pryor. Unit 2
Pryor. OK
Sherburne County.
Unit 3 (Becker. MN)
Oxbow. Unit 1
(Coushoutta. LA)
Gross MWe
110
100
440
60
44
575
447
440
440
370
370
280
319
270
520
860
S6S
scfm
640.000 @ 350°F
389,000 €> 230-240°F
1.890,000 @ 28S°F
324.500 @ 323°F
t
226,000 @ 227-265°F
2,300,000 @ 286°F
1,770,000 @ 245°F
2.055,000 @ 318°F
2.055,000 @ 318°F
1.660.000 @ 256"F
1.600.000 ® 2S6°F
1.206.000 @ 270°F
1,340,OOO @ 26O°F
1.200.OOO 9 NA"
1,850.000 @ 250-300°F
NA
NA
Status
Operated for 9 mo. in
1981 and for last half
of 1982 by vendor. Utility
to operate complete system
after demo, program.
Being operated as a demo.
unit by vendor until
early 1983.
Performance tests completed.
Final acceptance and compli-
ance tests scheduled for
Fall 1982.
September 1982 start-up
Start-up scheduled for
November 1982.
Low electric demand delayed
performance tests, expected
in late 1982.
Initial operator! in November
1982. Commercial operation
in April 1983.
Under construction. May
1983 start-up.
April 1985 start-up.
June 1985 start-up.
June 1986 start-up.
December 1983 start-up.
Under construction.
June 1983 start-up.
Under construction
3 mo. ahead of schedule.
1984 start-up.
March 1985 start-up.
August 1985 commercial
operation.
Awarded in Fall 1987
Awarded in Fall 1987.
Vendor'
Joy/Niro
Flakt
Rockwell/
Wheelabrator-Frye
Cottrell Environmental/
Kowline-Sanderson
G.E. Environmental
Services
Babcock and Wilcox
Babcock and Wilcox
Joy/Niro
Joy/Niro
Joy/Niro
Joy/Niro
Joy/Niro
Joy/Niro
Rockwell
Flakt
Joy/Niro
Joy/Niro
'Rockwell/Wheelabrator-Frye is no longer a joint venture, but both are offering spray drying systems. Joy/Niro: Joy takes the lead in utility sales, while Niro takes the lead in
industrial sales. C.E. Environmental Services: Formerly Buell Emission Control Division. Envirotech Corp. Spray dryer supplied by Anhydro A/S.
Cottrell Environmental Sciences supplies fabric filter. Kowline-Sanderson supplies spray dryer.
''Retrofit system currently being operated as a demonstration unit. Utility has purchased fabric filter; was to purchase spray dryer in late 1982.
'Currently being operated by vendor, but utility has purchased this retrofit system.
"NA = Information not available.
3
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size from 44 to 860 M We (gross electrical
output) and total about 6200 MWe in FGD
system capacity. Two retrofit systems, at
Northern States Power Co.'s Riverside
Station and Pacific Power and Light Co.'s
Jim Bridger Station, are currently being
operated as demonstration systems by
their respective vendors. Joy/Niro oper-
ated the Riverside system for 9 months in
1981 and conducted tests for the last half
of 1982, after which Northern States
Power will operate the spray dryer and
fabric filter. Flakt is conducting a 1-year
demonstration program at the Jim
Bridger Station. The tests are scheduled
to be completed in early 1983.
Final acceptance and compliance tests
at Montana-Dakota Utilities' Coyote
Station were scheduled for the Fall of
1982. This sodium-based system has
been operating since the Spring of 1981.
Four utility systems were scheduled to
be operational before the end of 1982:
Marquette Board of Light and Power's
Shiras Unit 3, Basin Electric's Laramie
River Unit 3, Colorado Ute Electric's Craig
Unit 3, and United Power's Stanton Unit
1A. Construction is in progress on three
other utility systems scheduled for 1983
start-up.
Four new utility systems were sold
since mid-1981. Rockwell International
was awarded a contract for a lime-based
spray dryer/fabric filter system in late
1981, to serve a 270 MWe unit at Sierra
Pacific Power's North Valmy Station in
Valmy, NV. Three parallel dryers, each
with three rotary atomizers, will treat
1,200,000 acfm of flue gas from a boiler
firing western subbituminous coal. The
system will be designed for coal sulfur
contents of 0.4-1.5 percent. The system
will have solids recycle and warm gas
bypass. The SOa removal guarantee is 76
percent.
Irt May 1982, Flakt announced it had
received a contract for a spray dryer/ESP
system to serve a Grand River Dam
Authority's (State of Oklahoma) 520
MWe coal-fired boiler near Pryor, OK. The
lime-based system will treat 1,850,000
acfm of flue gas in four parallel reactors
(one spare), each with three rotary
atomizers. Provisions for warm gas
bypass and solids recycle will be included.
The boiler will fire a western subbitu-
minous coal with a sulfur content of
0.4-1.5 percent. The S02 removal guar-
antee is 85 percent. System start-up is
scheduled for March 1985.
Joy/Niro was awarded the Cajun
Electric Oxbow and Northern States
Power Sherburne County systems in the
Fall of 1982. No details on these systems
are available. The 860 MWe Sherburne
County system is the largest spray drying
system sold to date.
Table 2 summarizes the design features
of the utility spray drying systems. All are
designed for low to moderate sulfur coal
(1.5 percent sulfur or less), except for a
maximum design value of 1.94 percent
sulfur lignite at United Power's Stanton
Station. S02 removal guarantees range
from 61 to 91 percent. Lime will be used
in all of the systems except Coyote and
Jim Bridger, although tests with lime will
be conducted at Jim Bridger. Warm or
hot gas bypass is used on a site-specific
basis. Solids recycle is included in all but
one of the 13 lime-based systems. (In
addition to providing the opportunity for
reuse of unreacted lime or available fly
ash alkalinity to reduce fresh lime
requirements, solids repycle improves
the operability of rotary atomizers.)
The dry product solids/fly ash mixture
generated by the spray drying systems
will be disposed of in landfills at most of
the utility locations. Available information
indicates that for some of the landfill
operations the solids will be wetted
before transfer to the landif II, presumably
to reduce dust problems. Most of the
vendors' utility system contracts do not
include responsibility for waste solids
disposal operations. An exception is
Joy/Niro's contract with Sunflower
Electric. In this case, Joy/Niro will design
and supply the equipment for a fixated
solids disposal process.
Industrial Boilers
Table 3 shows the eight industrial
boiler commercial spray drying systems
sold to date. (A few vendors have also sold
spray drying systems for incinerators or
kilns, but these applications are not
covered in detail in this report.) Table 3
shows that the industrial systems range
in size from one 85,000 Ib steam/hr
boiler at Strathmore Paper Co.'s Woron-
oco, MA,planttotwo40MWeboilersthat
are part of a cogeneration system at the
University of Minnesota in Minneapolis.
Four of the industrial boiler systems are
operational. All of these systems have
been reported to have achieved their
performance guarantees. The Celanese
and Strathmore systems are being
operated by their respective purchasers.
The Argonne system was to have been
turned over after final 60-day performance
tests scheduled for the Fall of 1982, and
the Container Corporation system is in
the final stages of acceptance testing.
The University of Minnesota and AusteU
Box Board systems were both scheduled
to start up before the end of 1982.
The two new industrial boiler systems
sold since late 1981 were both awarded
to Niro/Joy. The lime-based systems are
identical to previous Niro/Joy designs,
incorporating spray dryers with single
rotary atomizers and solids recycle. Both
of the systems will use pulse-jet fabric
filters. The General Motors' 450,000 Ib
steam/hr boiler will fire an Indiana
bituminous coal with a sulfur content of
between 1 and 3 percent. A 1 percent
sulfur western subbituminous coal will
fuel the three 110,000 Ib steam/hr
boilers at Fairchild Air Force Base. Each
boiler will be equipped with a separate
spray dryer/fabric filter system.
Table 4 summarizes the design features
of the industrial boiler systems. The
design coal sulfur contents in the
industrial applications, all of which will
use lime, range from 0.6 to 3.5 percent.
S02 removal guarantees range from 70 to
90 percent, with at least four of the
systems designed to meet a 1.2 Ib SOz/
million Btu (heat input) emission limit.
Five of the eight systems include solids
recycle. Only one of the systems, Cel-
anese, has gas bypass, and all will have
fabric filters. Only the larger University of
Minnesota systems will employ a reverse-
air fabric filter. Since pulse-jet fabric
filters generally operate at higher air-to-
cloth ratios, they are less expensive than
reverse-air filters up to a certain size
(generally below 100,000 acfm) and are
normally used in industrial spray dryer
systems. Above the cutoff, a function of
site-specific factors, pressure drop costs
• begin to pffset the savings associated
with the higher air-to-cloth ratios of
pulse-jet designs.
Off-site landfill disposal of the waste
solids will be used -in most of the
industrial applications since there is
typically little land area available for on-
site disposal.
Spray Drying System Vendors
Table 5 shows the firms currently
offering utility and/or industrial boiler
spray drying systems. Since the last
survey was updated in the Fall of 1981,
several changes have occurred within
this group of vendors:
• Flakt, Inc. purchased the Kennecott
Environmental Products Division of
Carborundum, Inc. and with it acquired
the University of Minnesota system
Kennecott had sold.
• Mikropul, Inc. and Koch Engineering
are now offering spray drying systems
in a joint venture.
• General Electric purchased the Buell
Emission Control Division of Enviro-
tech Corporation; this group is now
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Tablt2. Design Features Summary For Utility Commercial Spray Dryer Systems*
Design Coal Data
System' (Vendor)
Riverside, Units 6
& 7 (Joy/Niro)
Jim Bridget. Unit
2 (Flakt)
Coyote, Unit 1
(Rockwell/
Wheelabrator-Frye)
Stanton, Unit 1A
(Cottrell/
Kowline-Sanderson)
Shiras. Unit 3
(G.E. Environmental
Services)
Laramie River,
Unit 3
(BabcockandWilcox)
Craig, Unit 3
(Babcock and Wilcox)
Antelope Valley.
Unit 1 (Joy/Niro)
Antelope Valley,
Unit 2 (Joy/Niro)
Springerville, Unit
1 (Joy/Niro)
Springerville, Unit
2 (Joy/Niro)
Rawhide. Unit 1
(Joy/Niro)
Holcomb' Unit 1
(Joy/Niro)
North Valmy
(Rockwell)
Pryor, Unit 2
(Flakt)
Description
1 spray dryer with rotary
atomizer; lime reagent; re-
verse air fabric filter.
Reactor with 10 dual-fluid
nozzle atomizers; ESP; testing
both lime and soda ash.
4 parallel spray dryers, with 3
rotary atomizers each; initially
will use commercial soda ash;
reverse-air fabric filter.
1 spray dryer with 3 rotary
atomizers; lime reagent, re-
verse-air fabric fitter.
1 spray dryer with a single
rotary atomizer; lime reagent;
reverse-air fabric filter: 3
percent hot gas bypass
around dryer.
4 parallel reactors (1 spare)
with 12 "y-jet" nozzle atom-
izers each; lime reagent each
reactor followed by an ESP;
5 percent gas bypass
around dryer.
4 parallel reactors (1 spare)
with 12 "y-jet" nozzle atom-
izers each: lime reagent; re-
verse-air fabric filter.
5 parallel spray dryers (1 spare);
single rotary atomizer per
dryer; lime reagent; reverse-
air fabric filter; 3.2 percent
hot gas bypass around dryer.
Same as Antelope 1 above.
except no bypass.
3 parallel spray dryers (no
spare); single rotary atomizer
per dryer; lime reagent; re-
verse-air fabric filter: 17.5
percent gas bypass
around dryer.
Same as Springerville 1
3 parallel spray dryers (1
spare); single rotary atomizer
per dryer; lime reagent; re-
verse-air fabric filter; 10
percent gas bypass
around dryer.
3 parallel spray dryers (1
spare); single rotary atomizer
per dryer: lime reagent; re-
verse-air fabric filter.
3 parallel spray dryers (no
spare); 3 rotary atomizers per
dryer; lime reagent; reverse-
air fabric filter, gas bypass.
4 reactors in parallel (1 spare).
each with 3 rotary atomizers;
lime reagent ESPs;
gas bypass.
Type
HHV; Ash"
SOt Removal Guarantee*
Sulfur
Varies with test series.
Western
subbhum-
inous
North Dakota
lignite
North Dakota
lignite
Western
subbitum-
inous
Wyoming
subbitum-
inous
Western
subbitum-
inous
North Dakota
lignite
New Mexico
subbitum-
inous
11. 600 Btu/lb;
10.0% ash
7046 Btu/lb;
7.0% ash
7000 Btu/lb;
6.9% ash
8654 Btu/lb;
10.25% ash
81 40 Btu/lb:
8% ash
8950 Btu/lb;
14% ash
6600 Btu/lb;
7.8% ash
Same as Antelope 1
8500 Btu/lb;
20% ash
0.56% avg.
0.8% max.
0.78% avg.
0.77% avg.
1.94% max.
1.5% max.
0.54% avg;
0.81% max.
0.7%
design coal
0.68% avg.
1.22% max.
0.69% avg.
Same as Springerville 1
Western
subbitum-
inous
Wyoming
subMum-
inous
Western
subbitum-
inous
Western
subbitum-
inous
8500 Btu/lb;
6.0% ash
8313 Btu/lb;
5.6% ash
Nff
8000-9600 Btu/
Ib: 7% ash
0.3% avg.
0.44% max.
0.34% avg.
0.4
to 1.0%
0.4
to 1.5%
Removal Outlet (lb/10'Btu)
Varies with test series
Lime: 62-74% 0.3
Soda ash:
74-86%;
70% for 1.2
all fuels
70% or 0.6
lb/10'Btu:'
whichever
is lower)
80% design 0.94
removal
82% for avg; 0.20
78% for max.
Scoal
87% for 0.20
design coal
62% for avg.; 0.78
78% for max.
Scoal
89% for max. 0.39
S coal
61% 0.6
Same as Springerville 1
80% 0.18
8O% 0.27
76% for 0.4
all coal
85% for NR
all coal
Solids
Recycle ?
Yes
Variable
with test-
provisions
exist.
No
No
Yes
Yes
Yes
Yes
Yes
Yes
•
Yes
Yes
Yes
Yes
Provision
will exist.
Solids
Disposal
Trucked to
landfill.
Possible
mine-mouth
disposal.
Clay-lined
landfill.
Clay-lined
pond; water
sluice.
Landfill.
Lined land-
fill.
Dry landfill.
Wetted trans-
port to lined
landfill.
Same as
Antelope 1.
Natural
clay-lined
landfill.
Same as
Springer-
ville 1.
Dry land-
fill.
Landfill
with fixation.
Not reported.
Landfill.
"Some of the information contained in the table, particularly on gas bypass percentage, outlet SOt levels, and solids disposal was obtained from a recent report on the status
of utility spray drying applications.
'Referred to by generating station name as given in Table 1. Information forSherburne County and Oxbow was not available since these systems were only recently awarded.
"HHV = high heating value: HHV, % ash reported as average for the design coal.
"Where guarantee information was not available, design values are reported.
*P^/5 netr/nit fttr Hfttrt - -
'NR = Not Reported.
-------
Tables. Summary of Industrial Boiler Spray Drying Systems Sold (November 1982)
Size
System Purchaser/
Location
Argonne National Laboratory
Argonne. IL
Strathmore Paper Company
Woronoco, MA
Celanese Fibers Company
Cumberland. MD
Container Corporation
Philadelphia. PA
University of Minnesota: Units
1 & 2 Minneapolis. MN
Austell Box Board Co.
Austell. GA
General Motors Buick Division
Flint. Ml
fairchild Air Force Base, Units
1, 2. and 3; Spokane. WA
scfm
75.000®
3OO°F
40.OOO®
330°F
65.000®
350-370°F
94.300®
350°F
120.000
@ 375°F
171.000®
350°F
NFf
NFt
Ib steam/
hr
170.000
85.000
110.OOO
770.000
40MWe"
each
250.000
450,000
110.000 each
Status
Operational. Passed inital
performance tests. Undergoing
60-day reliability and
performance tests.
Operational. Turned over to
system purchaser. Has
achieved removal guarantee.
Operational. Turned over to
system purchaser. Has
achieved removal guarantee.
Achieved 90% removal guar-
antee. Final stages
of acceptance testing.
Start-up scheduled for
late 1982.
Under construction. Start-up
scheduled for November 1982.
Under construction. Start-up
date not set.
Under fabrication. Start-up
scheduled for late 1983.
Vendor*
Niro/Joy
Mikropul/Koch
Rockwell/Wheelabrator-
Frye
Ecolaire. Inc.
Flakf
Wheelabrator-Frye
Niro/Joy
Niro/Joy
*Niro/Joy: Niro takes the lead in industrial sales, while Joy takes the lead in utility sales.
Mikropul/Koch: Mikropul originally sold the Strathmore system, but now operates with Koch Engineering in a joint venture for future spray dryer sales.
Rockwell/Wheelabrator-Frye: (see note. Table 1).
"Part of cogeneration system.
"Originally sold by Kennecott Development Co.. which was purchased by Flakt in early 1982.
"NFt = not reported.
Table 4. Design Features Summary For Industrial Boiler Spray Drying Systems
Design Coal Data
SO2 Removal Guarantee"
System' (Vendor)
Argonne National
Labs (Niro/Joy)
Strathmore Paper Co.
(Mikropul/Koch)
Celanese Fiber Co.
(Rockwell/Wheela-
brator-Fryel
Container Corp.
(Ecolaire)
University of
Minnesota
Units 1. 2 (Flakt)
Austell Box Board Co.
(Wheelabrator-Frye)
General Motors
(Niro/Joy)
Fairchild AFB; Units
1, 2. 3 (Niro/Joy)
Description
One spray dryer with single
rotary atomizer; lime re-
agent; pulse-jet fabric filter.
One spray dryer with four
nozzle atomizers; lime re-
agent; pulse-jet fabric filter.
One spray dryer with single
rotary atomizer; lime re-
agent; pulse-jet fabric filter;
warm gas bypass.
One spray dryer with single
rotary atomizer; lime re-
agent; pulse-jet fabric filter.
Two spray dryers, one has
single rotary atomizer, the
second has three rotary
atomizers; lime reagent; re-
verse-air fabric filter.
One spray dryer with 12
nozzle atomizers; lime re-
agent; pulse-jet fabric filter.
One spray dryer with single
rotary atomizer; lime re-
agent; fabric filter.
Three spray dryers (one per
unit), each with a single
rotary atomizer; lime re-
agent; fabric fitter.
Type
Illinois
bituminous
Eastern
bituminous
Eastern
subbitum-
inous
Eastern
subbitum-
inous
SubbHum-
inous
Bituminous
Indiana
bituminous
Western
suobftum-
inous
HHV Ash"
1 1,800 Btu/lb
8.0% ash
13.000 Btu/lb
NFf
NR
NR
NR
NR
NR
Sulfur
3.5%
2.3 to 3%
2.0%
maximum
1%
0.6 to
0.7%
1.0 to 2.5%
1-3%
1%
Solids
Removal Outlet (Ib/10s8tu) Recycle?
78.7%
75%
70% for 1% S
coal; 86% for
2% S coal
Design removal
of 90%
70%'
Varies with
sulfur content
70 to 90%
85%
1.2
1.2
70 Ib SOi
hr
NFt
NFt
1.2
1.2
NR
Yes
No
No
Yes
No
Provisions will
exist
Yes
Yes
Solids
Disposal
On-site
landfill.
Trucked
to off-
site land-
fill.
Trucked
to off-
site land-
fill.
NFt
NFt
NFt
NR
NR
'Referred to by system purchaser as shown in Table 3.
"HHV = high heating value. Btu/lb; HHV and % ash reported as average for the design coal.
'Where guarantee information not available, design values are reported.
"NR = not reported.
'At a reagent ratio of 1.0.
referred to as G.E. Environmental
Services, Inc.
Table 5 shows that a number of vendors
offer both nozzle and rotary atomizers.
Two vendors, Flakt and Rockwell, offer
multiple rotary atomizers per dryer
designs for utility systems. Some vendors
have recently advocated the use of nozzle
atomizers for industrial boiler systems
less than about 200,000-250,000 acfm.
However, these vendors still tend to favor
rotary atomizers for large systems.
-------
Conventional vertical flow dryers are
still the most common design, although
Babcock and Wilcox offers a horizontal
flow dryer.
Performance Data
Table 6 summarizes recently published
performance and compliance test data
from operating full-scale spray dryer FGD
systems. Data from the Argonne and
Strathmore systems represent high
sulfur coal applications. Argonne reported
that a reagent ratio of about 1.4 was
required for 90 percent SOz removal at a
23° f approach to saturation and a recycle
ratio of about 2 Ib recycle solids per Ib of
fresh lime. At Strathmore, a 1.9 reagent
ratio enabled 92.4 percent average SOz
removal (no solids recycle, with about a
25°F approach).
Figure 1 shows recently published data
on SOz removal as a function of reagent
ratio for several different lime-based
systems. Test conditions for the data
presented are given in Table 7.
Future Commercial Activities
Table 8 shows the utilities reported to
be currently considering dry FGD for new
plants. Spray drying is still being consid-
ered primarily for low sulfur coal applica-
tions.
Spray Drying—Research and
Development Activities
Table 9 shows the status of four recent
spray drying research and development
programs. Results of EPA-funded tests at
Martin Drake, DOE tests at PETC, and the
EPRI-funded pilot and laboratory tests
were presented at the EPA/EPRI FGD
Symposium in May 1982. The final report
on tests conducted for EPA at Comanche
is being reviewed.
EPA-funded testing at Martin Drake
and the PETC work recently focused on
high sulfur coal applications. At Martin
Drake, eastern fly ash was injected into
the flue gas just upstream of the spray
dryer and SOz spiking was used to raise
the inlet SO2 to between 1500 and 4000
ppmv. At PETC, inlet SOz concentrations
of about 2200 ppmv were generated by
burning a 3.1 percent sulfur West
Virginia coal. Over 90 percent SOz
removal was demonstrated in both these
programs.
The Comanche and EPRI-funded pilot
programs have been directed toward low
sulfur western coal applications.
In general, these R&D programs
indicate that the major process variables
influencing SOz removal in the spray
dryer system are fresh reagent ratio,
approach to saturation at the dryer outlet,
and recycle ratio. However, optimization
of gas/liquid contact, atomization quality,
and gas residence time in the dryer have
been shown to be important not only from
an S02 removal standpoint, but also in
ensuring trouble-free spray dryer opera-
tion.
Other variables that have been shown
to impact SOz removal in the spray drying
system are: inlet SOz concentration,
temperature drop over the spray dryer.
TableS. Firms Offering A Commercial Spray Drying FGD System
Firm or
Team of Firms
Spray Dryer"
Design Features*
Atomization
Number of Systems Sold in U.S.
Utility Industrial
Babcock and Wilcox (B&W)
Combustion Engineering, Inc.
Cottrell Environmental
Sciences. Inc. and Kowline-
Sanderson Inc.
Ecolaire.lnc.
Flakt. Inc.
G.E. Environmental Services
Joy Manufacturing Company
and Niro Atomizer. Inc.
Mikropul, Inc. and Koch
Engineering, Inc.
Rockwell International
Wheelabrator-Frye. Inc.
Horizontal dryer with
hoppers for solids
collection.
Two-point discharge
vertical dryer.
Two-point discharge
vertical dryer.
Two-point discharge
vertical dryer.
Two-point discharge
vertical dryer.
Two-point discharge
vertical dryer.
Two-point discharge
vertical dryer with
central gas disperses
Two-point discharge
vertical dryer with
"propietary" internals.
Single-point discharge
vertical dryer.
Vertical dryer with
nozzle or rotary
atomizers.
12 "Y-jet" air-atomized nozzles
for each full-size reactor.
Multiple (externally mixed)sonic
nozzle atomizers per dryer
Multiple (3) rotary atomizers
per dryer. Nozzle atomizers for
sodium-based systems.
Single rotary atomizer per
dryer. Have tested with
nozzle atomizers.
Multiple atomizers per dryer.
Three rotary per dryer for full-
scale utility module. Ten air-
atomized nozzles/dryer design for
Jim Bridger demonstration unit.
Single rotary atomizer per
dryer.
Single rotary atomizer
per dryer.
Multiple air-atomized nozzles
per dryer. Investigating
rotary atomizers.
Multiple (3) rotary atomizers
per dryer for utility. Single
rotary atomizer per dryer for
industrial.
Multiple air-atomized nozzles
for industrial. Single rotary
atomizer per dryer for utility
or large industrial.
None
1
None
Does not plan to bid
None
None
1
1
9
None
2"
T
None
3C
1
'Based primarily on commercial systems sold to date and reported R&D activities. Vendors may offer other design features.
Two-point discharge dryers have bottom discharge for solids that drop out in dryer.
cThe Fairchild system will have 3 units.
'One sold by Rockwell/Wheelabrator-Frye joint venture, other sold independently.
'Sold by Rockwell/Wheelabrator-Frye joint venture.
-------
Table 6. Performance and Compliance Test Data for Spray Drying Systems
System/ Vendor Performance/Compliance Test Data
Argonne Labs/Niro-Joy
Strathmore/Mikropul-
Koch
Boiler Load
(%MCRf
35
70
82
Test
No.
1
2
3
4
5
6
avg.
Inlet SOz Outlet SOz
(Ib/ICPBtu)
6.69
5.93
6.13
Inlet SOz
(ppmvj
2057
1948
2014
1974
1984
2016
1.36
0.60
0.27
Outlet SOz
132
65
195
166
196
156
SOz Removal
79.7
89.9
95.6
SOz Removal
93.6
96.7
90.3
91.6
90.1
92.3
92.4
Comments
Lime reagent, solids
recycle, 3% S coal, EPA
Method 6 tests.
Lime reagent, no solids
recycle. 3.79% S coal.
EPA Method 6 tests. About
75% boiler load for all
tests.
Jim Bridger/Flakt
Coyote/Rockwell-
Wheelabrator-Frye
Reagent SOz Removal
Soda ash 88.3
Lime with 90.8
recycle
Lime with 64.1
no recycle
Met performance guarantee of 7O% SOz removal at 75% reagent utilization.
Guarantee
(Removal (%)
S&5
74
62
EPA Method 6 tests, about
0.6% S coal.
Soda ash reagent. Recent
data showed 7O% removal at
reagent utilizations of
95% or greater.
"MCR — maximum rated capacity.
100
90-
« 80
70-
60
50
40-
OO
O
O
O
A
O
LSC = tow sulfur coal (<2%S)
HSC = high sulfur coal (2.3 - 3.5%)
A7"»s = approach to saturation
O
O
O
O
Key to Symbols
(Also see Table 7)
Symbol
X
O
0
0
D
•
.
Coal Type
HSC
LSC
HSC
HSC
LSC
LSC
HSC
HSC
HSC
LTtofF)
25
35
35
18
27
29
23
30
20
Recycle?
No
Yes
Yes
Yes
Yes
No
Yes
No
No
0.6 0.8 1.0 1.2 1.4 1.6
Reagent Ratio.
moles lime/mole inlet SOz
1.8
2.0 2.2
Figure 1. Comparison of overall SOz removal data for various lime-based spray dryer FGD
systems.
and slaking water quality and lime
reactivity.
Results from R&D programs such as
the ones discussed above, combined with
recent operating data from full-scale
commercial systems and demonstration
programs, have better defined the
important spray dryer FGD design and
operating parameters. However, there
remain a number of areas in which
consistent, well-characterized data have
not been published: atomization, the role
of fly ash and recycle solids, high sulfur
coal applications, the use of less expensive
reagents than lime, and utilization
schemes for solid waste.
Continued research and development
in the atomization area focuses primarily
on improving atomizer designs for FGD
applications and comparing the perfor-
mance of nozzle and rotary atomizers.
Atomizer design research centers on
reducing abrasion and power require-
ments while maintaining a finely atomized
slurry. At least three vendors are investi-
gating the use of nozzle atomizers for
smaller industrial applications (e.g.,
less than 250,000 acfm), but would fa-
vor rotary atomizers for utility and
large industrial systems. The two types
of atomizers are generally compared
on the following bases: droplet size
produced, power requirements, mechan-
ical complexity, spray patterns produced.
-------
Table 7. Process Conditions For Data Shown in Figure 1
Process Conditions
Symbol from
Figure 1 System Description*
O Riverside Station:
1 10 MWe unit;
680,000 acfm; 46-ft
diameter dryer;
rotary atomizer;
fabric filter
% Riverside
C Riverside
CD Jim Bridget Station;
100 MWe unit; 389.000
acfm; tan dual-fluid
nozzle atomizers; ESP
B Jim Bridger
X Strathmore: 85.0OO
Ib steam/hr; 40,000
acfm; 14.5-ft
diameter dryer;
rotary atomizer;
fabric filter
A Argonne Labs:
170.OOO Ib steam/hr
boiler; 75,000 acfm;
25-ft diameter dryer;
nozzle atomizers;
fabric filter.
O PETC: 500 Ib/hr
pulverized coal
furnace; 7 -ft
diameter dryer;
rotary atomizer;
fabric filter
• PETC
'Riverside system is a Joy/Niro design.
Jim Bridger system is a Flakt design.
Argonne system is a Niro/Joy design.
"NR = not reported.
abrasion and/or plugging experiences.
and ability to handle slurry flows associ-
ated with varying boiler load.
Regarding the role of fly ash and
recycle solids in the spray drying process.
the major R&D objective is to maximize
the use of available fly ash alkalinity (or
acidity) and unreactecd reagent in the
recycle solids. Meeting this objective
requires: (1) a more thorough under-
standing of the mechanisms by which fly
ash alkalinity (or acidity) contributes to
SOz removal in systems both with and
without recycle; (2) conclusive data on
the optimum manner in which the recycle
solids are added (e.g., separate ^lurrying
versus direct addition to the fresh reagent
feed tank); and (3) characterization of the
potential role of fly ash as a surface
catalyst in SO2 absorption.
Some of the recent data from high
ulfur coal applications (e.g., Argonne,
Strathmore, Riverside, and Martin Drake)
Inlet 502
Coal Type %S (ppmvj
Co/strip 1.2 850-1000
coal blended
with petroleum
coke
Illinois 3.5 -2000
bituminous
Illinois 3.5 -2000
bituminous
Western sub- -0.6 NFf
bituminous
Western sub- -0.6 NR
bituminous
Eastern 3.8 —2000
bituminous
Illinois 3.0 -2200
bituminous
West Virginia 3. 1 -2200
bituminous
West Virginia 3. 1 NR
bituminous
Inlet Gas Temp. A T*s Recycle
(°F> (°F>
280-315 35 Yes
316-331 32-35 Yes
-315 18 Yes
229 27 Yes
238 29 No
-330 25 No
-300 23 Yes
-400 30 No
NR 20 No
Table 8. Utilities Considering Dry FGD For New Units
Utility Plant Site
Central and Coleto Creek
Southwestern Services Unit 2
East Kentucky Power J.K. Smith,
Cooperative Units 1 and 2
Nebraska Public Fossil III
Power
*NR = Not reported.
have answered previously posed ques-
tions regarding the SOz removal achiev-
able at higher inlet S02 levels. These
results have also provided some informa-
tion on the reagent ratios, approach to
saturation, and recycle ratios required to
obtain high removals (90 percent or
greater) at 2000 to 4000 ppm inlet SO2.
Coal Type Comments
0.4% S average; Considering only
subbituminous dry FGD. 9/86
scheduled
start-up.
NR* Considering dry
and wet for two
650 MWe units.
1985-1986.
0.36% S Considering dry
only for 650 MWe
unit. 1987 sched-
uled start-up.
Research and development activities for
high sulfur coal applications continue to
focus on optimization of atomization.
spray dryer operation, and solids recycle
to reduce fresh reagent requirements.
Reducing reagent requirements will be
important to the relative economics of
spray drying, since reagent-related costs
-------
Table 9. Status of Spray Drying ft&D Activities
Program
Location
System Size, acfm
Status
EPA-funded tests conducted
by Cottrell Environmental
Sciences, Inc.
EPA-funded tests conducted
by G.E. Environmental
Services. Inc..
EPRI-funded pilot and
laboratory tests; prime
contractor: Radian Corporation.
DOE tests
Public Service of
Colorado's Comanche
Station
City of Colorado
Springs' Martin
Drake Station
Public Service of
Colorado's Arapahoe
Station and Radian
Corporation laboratories
Pittsburgh Energy
Technology Center
fPETC)
10.OOO
2O.OOO
Pilot-scale:
9OOO
Laboratory: 40
2.500
Test work completed in
early 1981. Final report to
be completed in 1983.
Test work complete. Finat
report to be completed in
1983.
Testing in progress.
Testing complete. Results
reported at 1982 EPA/
EPRIFGD Symposium.
are a major component of the annual op-
erating costs of the spray dryer systems.
Figure 2 shows limited parametric test
data indicating the reagent ratio required
for between 70 and 90 percent 862 re-
moval at low and high inlet S02 concen-
trations. These data show that for 90 per-
cent SOa removal, a 0.8 reagent ratio is
required for the low sulfur case, but a rea-
gent ratio of about 1.3 is required for the
same removal in the high sulfur case. For
a 500 MWe utility system, this translates
into approximately 63,000 more tons of
lime annually for 2000 ppmv inlet SO2
than for 800 ppmv inlet S02. (These cal-
culations are based on 90 percent S02re-
moval, 75 percent load factor, and 95 per-
cent CaO lime.) Assuming a lime cost of
$75/ton, the increased reagent ratio
translates into an annual cost difference
of $4,725,000.
Because reagent-related costs are
such a significant portion of the total
operating costs for lime-based FGD
systems, there is continued interest in
alternate reagents such as limestone,
adipic acid-enhanced lime and limestone,
and possibly MgO as the basis for a
regenerable spray dryer process for
higher sulfur coals. Both EPA and DOE
have conducted limited tests with lime-
stone and adipic acid enhancement. SO2
removal was less than 40 percent in all of
these tests, even at a close approach to
saturation. A few vendors are also
investigating the use of limestone, but no
data have been published.
In the waste disposal area, efforts are
being directed primarily toward complete
characterization of waste properties as a
function of coal type and FGD process
conditions and development of methods
for utilization of the waste solids, possibly
as road base or cement additives.
Dry Injection
There are no plans for the construction
of any commercial dry injection systems.
However, several demonstration pro-
grams have been conducted. Pilot- or
10
100 •
90 . .
80 • -
70 . .
Inlet SOz Concentration
800 ppm 2000 ppm
Typical low sulfur results—Riverside
High sulfur results—Riverside
0.5
1.0 1.S
Reagent Ratio
2.0
Figure 2. Effect of inlet SO2 concentrations - Riverside data.
demonstration-scale dry injection systems
have been operated through funding by
the Department of Energy (DOE), the
Environmental Protection Agency (EPA),
and the Electric Power Research Institute
(EPRI).
General Electric Environmental Ser-
vices (formerly Buell, a division of
Envirotech Corporation) completed EPA-
funded dry injection testing at the City of
Colorado Springs' Martin Drake Station
in May 1980. Experiments with three
reagents (nahcolite, raw trona, and
refined trona) were conducted on the
4500 acfm dry injection baghouse
system. The sorbents were ground to less
than 74 /urn in diameter before being
injected into the duct leading to the fabric
filter. The tests were designed to assess
the effects of reagent type, reagent ratio,
temperature, and air-to-cloth ratio on
S02 removal.
The results showed that nahcolite
provided the best 802 removal, with 70
percent removal at a reagent ratio of 1.05
and 90 percent removal at 1.6. Refined
trona, about 59 percent sodium bicar-
bonate, exhibited lower S02 removals but
showed a parallel trend of increasing SOz
removal with increasing reagent ratio.
DOE conducted research on dry injection
systems at both the Grand Forks Energy
Technology Center (GFETC) and Pitts-
burgh Energy Technology Center (PETC).
These tests were performed to character-
ize the effects of several process param-
eters; e.g., reagent type, inlet 80s
concentrations, inlet gas temperature,
bag material, and air-to-cloth ratio.
Work at GFETC with a 150-scfm
(nominal) dry injection system showed
that up to 90 percent utilization (based on
combined NOX and SOz removal) could be
obtained with trona and nahcolite.
Moderate sulfur western coals were
used, resulting in inlet SOz concentra-
tions of 650-1100 ppmv. Results reported
here are preliminary; a final report has
not been published.
Dry injection work at PETC was
completed in the fall of 1980. The
performance of nahcolite, trona, and
commercial sodium bicarbonate was
evaluated. The average baghouse tem-
perature for the dry injection tests was
400°F. The fabric filter was equipped
with Nomex bags and was operated at an
air-to-cloth ratio of 4 ft/min. In general,
nahcolite showed the greatest SOz
removal capability of the three reagents.
In tests conducted with 1.1,1.6,and 3.5
percent sulfur coals, dry injection of
nahcolite resulted in SO2 removals of up
to 95 percent at a reagent ratio of 1.5
-------
moles NazO per mole of inlet SOz. The
tests also indicated that SOz removal
decreased as inlet SOz concentration
increased. However, 90 percent SOz
removal was reportedly achieved with a
reagent ratio of 1.5, even when 3.5
percent sulfur coal wgs burned.
EPRI has sponsored research on the
technical aspects of a dry injection/bag-
house system. The first phase of the
program consisted of detailed laboratory-
scale tests. More recently, EPRI completed
large-scale dry injection tests at the
Public Service of Colorado's Cameo
Station. The tests were performed by
KVB, Inc. on the 22 MWe Unit 1 boiler at
Cameo, using the existing fabric filter.
Most tests used nahcolite, but some used
trona.
Results of the Cameo dry injection tests
showed that SOz removals of 75 to 83
percent were achievable with nahcolite
at a normalized stoichiometric ratio (NSR
= moles of NazO fed/mole of inlet SOz) of
1.0 and an inlet SO2 concentration of
450 ppm. Other results from the Cameo
dry injection tests showed that the
temperature of the flue gas at the point of
reagent injection had a significant effect
on the rate of reaction between nahcolite
and SOz. An SOz removal of 54 percent
was achieved with trona at an NSR of
0.95.
Combustion of Coal/Alkali
Fuel Mixtures
As discussed earlier, two processes are
being developed, based on the combus-
tion of coal/alkali fuel mixtures to control
SOz emissions: combustion of coal/lime-
stone pellets in an industrial stoker-fired
boiler, and combustion of a pulverized
coal/alkali fuel mixture in a low-NOx
burner. This second process is commonly
referred to as limestone injection in a
multistage burner (LIMB).
Results of large-scale tests of 3.5:1
calcium-to-sulfur molar ratio coal/lime-
stone pellets, conducted in December
1979, indicated that 50 percent S02
removal was achievable with this technol-
ogy. However, inadequacies in the pellet
production process delayed full-scale
testing. Under EPA funding, Battelle-
Columbus is continuing to investigate
alternate methods of making the pellets.
Meanwhile, only small-scale, short-
duration tests are planned for the future.
Both DOE and EPA are studying
pulverized coal/alkali fuel mixtures,
using calcium-based reagents (mostly
limestone).
EPA's program to develop coal/alkali
fuel mixtures involves studies of three
different wall-fired burners and one
tangentially fired burner. Initial tests on a
1 million Btu/hr wall-fired burner
showed that SOz capture with limestone
injection is highly variable (ranges from 10
to 70 percent, depending on operatng
conditions). The tests showed that SOz
capture was primarily affected by the
average gas temperature and residence
time in the burner.
Tests with a nominal 50 million Btu/hr
medium tunnel (MT) burner and a
nominal 100 million Btu/hr large water-
tube simulator (LWS) were conducted
with a 0.9 percent sulfur Utah coal and a
2.6 percent sulfur Indiana coal. During
these tests, the limestone was either
pulverized with the coal or injected with
tertiary combustion air. Pulverizing the
limestone with the coal showed better or
equivalent SOz capture in all cases. For
the high sulfur Indiana coal, SOz capture
in the LWS was about 50 percent at a
reagent ratio of 2.0. SOz capture in the
LWS was lower for the low sufur Utah
coal. Results for the MT burner and LWS,
shown in Figure 3, show S02 capture in
the furnace to be somewhat lower.
Medium Tunnel
Indiana Coal _
— Reagent w/coal
•. Reagent w/air
Utah Coal
Reagent w/coal
Reagent w/air
234
Reagent Ratio
60
SO
40
330
S
'20-
10
Large Watertube Simulator (L WSJ
'*
Indiana Coal
/—Reagent w/coal
....... Reagent w/air
Utah Coal
Reagent w/coal
• :Reagent w/air
1 I I
DOE recently completed tests with
limestone on the 53 MWe tangentially
fired boiler at Otter Tail Power Company's
Hoot Lake Station. Final results of this
testing are not yet available.
Efforts to optimize SOz and N0> re-
moval using LIMB technology are under-
way. Incentives for the accelerated devel-
opment of this technology include the po-
tential cost savings offered by reduced
equipment requirements relative to con-
ventional wet FGD and the retrofit po-
tential of the technology for existing
boilers.
Electron-Beam Irradiation
The electron-beam (E-beam) process,
in an early developmental state, has not
been applied to a real coal-fired flue gas.
DOE recently signed cost-sharing
agreements with Research Cottrell and
Avco-Everett/EBARA to conduct pilot-
scale demonstrations of E-beam proc-
esses. Research Cottrell will be devel-
oping the E-beam/lime process and
Avco-Everett/EBARA is developing the
E-beam/ammonia process.
Conversion Factors
To Convert
from Non-
metric
cfm
ft
Ib
Btu
short ton
To Metric
rn'/hr
m
kg
J
tonne
Multiply by
1.70
0.305
0.454
0.252
0.91
The temperature conversion formula is:
(°F-32)/9 = °C/5
0 1 2 3 4 5
Reagent Ratio
Figure 3. SOz capture in wall-fired
furnaces.
11
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M. E. Kelly and M. A. Palazzolo are with Radian Corporation. Durham. NC 27705.
Theodore G. Brna is the EPA Project Officer (see below).
The complete report, entitled "Status of Dry SOa Control Systems: Fall 1982,"
(Order No. PB 83-247 585; Cost: $17.50, subject to change) will be available
only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati OH 45268
Official Business
Penalty for Private Use $300
AGENCY
U.S. GOVERNMENT PRINTING OFFICE: 1983-759-102/0781
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