FLUE GAS DESULFURIZATION
INSTALLATIONS and OPERATIONS
SEPTEMBER 1974
U.S. ENVIRONMENTAL PROTECTION AGENCY
Washington, D.C. 20460
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11206
FLUE GAS DESULFURIZATION
Installations and Operations
Division of Stationary Source Enforcement
Office of Enforcement and General Counsel
Additional copies of this report may be obtained from the Public
Information Center, Room 2106 Waterside Mall, 401 M Street, S.W.,
Washington, D. C. 20460
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INTRODUCTION
From October 18 to November 2, 1973, the Environmental Pro-
tection Agency held a national public hearing in the Washington, D.C.
area to review the status of power plant compliance with sulfur oxide
(SOy) air pollution emission limitations. Regulations limiting
emissions of SO have been imposed because excess quantities of SO,
seriously affect human health through increased incidences of respira-
tory disease and damage many types of materials. The national
hearing was called because power plants are the largest source of SO,
emissions in the U. S., because large numbers of power plants were not
yet in compliance with SO emission limitations, and because, in most
cases, only 1 1/2 years remained under the established implementation
plans for these plants to achieve compliance.
During the hearing, testimony was taken from some 50 witnesses
representing electric utilities, trade associations, vendors of pollution
control equipment, and other interested groups and individuals. It was
generally agreed by these witnesses that flue gas desulfurization (FGD)
technology must be installed on large numbers of power plants if SO>
emission requirements adopted pursuant to the Clean Air Act are to be met
in the 1970’s. Supplies of low-sulfur fuels are and will continue to
be inadequate to provide the sole means of compliance.
It was also generally agreed at the hearing that EGO systems, when
operating properly, would reduce SO emissions by. 85 to 90%, the levels
required by most states. Questions were, however, raised by many utilities
as to whether FGD systems could be made to operate reliably and as to
whether an environmentally acceptable method existed to dispose of the
sludge produced by some types of FGD systems.
After considering the testimony, the hearing panel found that the
problems allegedly affecting FGD reliability could be, and had been,
solved at one plant or another, and that reliability was sufficiently
demonstrated to warrant widespread commitments by utilities to FGD sys-
tems at coal- and oil-fired power plants. The panel recomended that
EPA create an incentive for such commitments by vigorously enforcing
reasonable schedules to comply with sulfur oxide emission limits. The
panel additionally found that technology was available to reclaim sludge
waste as landfill and that regenerable systems that do not produce any
appreciable waste were available for use where throwaway systems could
not be used.
At the time of the hearing, there. were 44 FGD systems either in
operation, under construction, or being planned by 23 utilities at 26
plants. Only 10 of these systems were operational, 16 under construction,
and 18 planned; 8 of those under construction were projected to start-up
by the end of 1974.
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FGD INSTALLATION STATUS
Nearly 1 year has elapsed since the public hearing arid it is
appropriate to review the present status of FGD installation as an
indication of the effectiveness of the hearing and EPA’s follow-up pro-
gram and as an indication of the continued validity of the hearing panel’s
conclusions.
The data covering the present status of FGD installations follows
in Tables I through V. The total number of FGD units operational, under
construction, or otherwise committed to has more than doubled over this
year--to 93 systems at 51 plants by 39 utilities. The number of units
now on-line has jumped to 19, and three additional systems are scheduled to
start-up by December. In addition to the 19operating units, 14 are now
being constructed, and electric utilities have decided to install 60 more
systems. Contracts have already been awarded for 17 of these 60 planned
units; letters of intent have been signed for 4; bids are being taken
for 7; engineering studies are underway for 17; and preliminary plans
are continuing for 15.
The bulk of the 93 units will have started-up by the end of 1977.
Aside from the 19 operating units and the 3 units scheduled to start-up
this year, companies are projecting start-up dates of 1975 for 10 units, 1976
for 12 units, arid 1977 for 19 more. The remaining 30 desulfurization systems
will begin operation in 1978 or 1979, or have unknown start-up dates. Many
of these 93 units are associated with new plants (47) and their installation
is tied to the start-up dates of the plants.
FGD OPERATING EXPERIENCE
Recent operating experience with FGD systems has demonstrated
increasingly high reliability factors with the elimination of the problems
that plagued many of the early systems. Increasingly higher reliability
(availability to the boiler) factors are seen both for those units re-
cently started-up and for those units with longer operating experience.
Several of these units showing high availability factors for
several months can be characterized as very successful; other units,
which are yet in experimental stages or still undergoing shakedown and/or
adjustment, are also evidencing increasingly reliable performance. Only
one type of FGD system has proven too troublesome to warrant further in-
stallations.
Many problems have, of course, been experienced with FGD system
operation, particularly with earlier installations. Efforts to resolve
these problems have naturally lead to improvements in system design and
operation and to subsequent improvements in reliability. This clear
trend to highly reliable, long—term FGD operation is best illustrated
by reviewing the experience at each of the operating units.
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Two of the earlier FGD installations, a lime scrubbing system and a
magnesium oxide system, can be characterized as very successful by their
recently demonstrated reliabilities. Louisville Gas and Electric
Company’s (LG&E) lime scrubbing system installed on its Paddy’s Run No. 6
station started-up in April 1973 and operated until October 1973
at 70% availability to the boiler;l from October until shutdown in
December 1973, availability was greater than 90%. Because Paddy’s Run
No. 6 is a peak-load boiler, the boiler, and consequently the scrubber,
was shutdown in December because of a low demand for electricity. In-
creased demand caused LG&E to restart the boiler, controlled by the FGD
system, in July 1974. Since the recent start-up, the unit has been.
operating at 100% availability, burning 3% sulfur coal with an S0
removal efficiency of 90%. Early problems with this closed-loop system,
which were minor and mechanical in nature, have been solved. This company
is so convinced of the workability of its system, which has operated
for 5 months at over 90% reliability, that it is committed to the
installation of similar control systems on several additional boilers.
A recently completed 2-year FGD test project conducted by the
Boston Edison Company at its oil-burning Mystic station has also been
successful. Since start-up in April 1972, this 150-megawatt magnesium-
oxide scrubber, which is a regenerable system producing sulfuric acid
as a by-product, has experienced most of the typical process and
mechanical problems. During the first year of operation, Chemico, the
vendor, constantly worked on and corrected these problems. Over this
period, the scrubber was available to the boiler only 17% of the time.
Efficiency, however, indicated 90% sulfur oxide removal using 20% virgin
magnesium oxide and 80% regenerated magnesium oxide. Beginning in June
of 1973, reliability figures reached 68%, but declined slowly to 13% in
December due to deterioration of the equipment from erosion and corrosion.
The problems occurring pointed out the need to carefully control the
chemistry of the system, and in January and February of 1974, the company
and the vendor extensively overhauled the system. By March the system
was 87% available to the boiler. Availability figures recently obtained
were: April - 81%, May - 57%, and June - 80%. Despite the good avail-
ability figures shown, the system was shutdown as scheduled because the
2-year test period was completed. Boston Edison seems generally satisfied
with the efficiency and reliability of its Mag-Ox scrubbing unit, has been
quoted as calling it °a viable technology for our particular purpose,”2 and
is still considering whether it will install flue gas scrubbing systems
on its other boilers.
Ilhis April to October 1973 availability factor must be viewed with
caution since the boiler was down much of this time and the FGD
system, while available to the boiler, was run only intermittently.
2 Electrjcal Week , July 29. 1974, p.7.
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Several of the more recently installed units have demonstrated
‘very high reliability factors for several months and are not troubled
with many of the problems experienced at some of the earlier installa-
tions. One of these successful units is a 32-megawatt double alkali
system designed and operated by General Motors at its Parma Chevy,
Transmission plant in Cleveland. With an SO removal efficiency of
98%, the system has been available to the boiler 100% of Operating
time in June, July, and August 1974. Availability at start-up in
April was 87%, but the scrubber was s.hutdown for the month of May be-
cause of unexpected pluggage by calcium carbonate deposits in the
overflow line between the clarifiers and in the line fromone of the
clarifiers to the mix tanks; this subsequently caused overflow into
the scrubber. This problem was solved during shutdown by using a
polymeric flocculating agent to improve settleability and by with-
drawing sludge from the clarifier more frequently. The scrubber has
operated continuously since May 29 except for brief, non-scrubber
related shutdowns.
Two other companies, which started-up their scrubbing uni ts late
in 1973, are also showing good performance. Arizona Public Service
Co. (APS) started-up its 115-megawatt limestone scrubber designed by
Research-Cottrell in December 1973. This 2-module scrubber averaged 89%
availability for-the 7 months from January through July 1974;
module A (SOx and particulate scrubbing) availability was 92% and module
B (particulate scrubbing only) availability was 87%. Downtime was used
to correct wiring, meter calibration, reheater vibration, and instrumenta.-
tion problems and to repair leaks, packing glands, and reheatertube
bundles. Acid condensation on the reheater tubes was solved by proper
insulation, and cross baffles installed at the inlet stopped reheater
vibration. System availability climbed to 93% in August after these
problems were solved, and module A alone showed an availability factor
of 98%. SOx removal efficiency remained at about 92%.
Southern California Edison (SCE) started-up their 160-megawatt
experimental lime scrubber in November 1973 on their Mohave unit No. 2.
The system was designed by the company in conjunction with Stearns—Roger
and SCE has taken over as the operating agent. This lime scrubber is
half of a two-part experimental program that the company will use to de-
cide whether it will use a lime or limestone system at its Mohave station.
A 160-megawatt vertical limestone system designed by Universal Oil Products
is now being constructed on Mohave No. 1 and results from this unit will
be compared to experience with the Mohave No. 2 lime scrubber. The lime-
stone system was scheduled to start—up in January 1974 in order to
parallel experience at No. 2, but extensive unrelated fire damage has
delayed start-up at least until October 1974.
The formal test program for Mohave No. 2 began on January 15, 1974,
and the horizontal absorber has to date operated continuously at 84%
availability to the boiler.
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Operating experience at some of the earliest units, notably those
boiler injection type units at Kansas Power and Light’s Lawrence station and
Kansas City Power and Light’s Hawthorne station, has •not been satisfactory
Both of these companies experimented with two limestone boiler injection
systems using 3.5% sulfur coal. Problems with this type of system included
corrosion, plugging, scaling, settling, and reheater/demister difficulties,
and proved substantially more difficult than those found with tail-end
type FGD systems. The companies have decided to convert their scrubbers
to tail-end scrubbing with limestone and EPA knows of no plans for
additional units of the boiler injection type.
Kansas City Power and Light has already converted its Hawthorne
No. 4 100-megawatt scrubber to tail-end, and seems to have eliminated
many of the problems it experienced with injection. A few problems remain
with the recirculation system but modifications are expected to solve
these problems. Combustion Engineering says that the tail-end system
has operated since Februaryi974 with no major problems, although the
demister must be cleaned by hand during boiler downtime.
Varying degrees of success are being obtained with the rest of
the scrubbing units now operating. In many cases the units have not
been on-line long enough to fully evaluate their performance. From the
limestone systems that could be termed less successful to date than Ari-
zona Public Service’s Cholla installation, several crucial operating
problems have been resolved. Kansas City Power and Light, for instance,
installed an 820-megawatt system at LaCygne No. 1 that started up in
June 1973. Proper design and operation of this unit is complicated by
the fact that it must remove large amounts of both particulate and SO
that result from the burning of coal having especially high sulfur and ash
contents. In addition, this system was built without any means to bypass
the scrubber. 3 Its initial problems are nearly all attributable to poor
pH control, further emphasizing the importance of proper control of system
chemistry for lime and limestone systems.
The City of Key West, operating a 37-megawatt scrubber that collects
both particulates and SO, , has found that one of its major problems is
controlling dust from its unique coral grinding system.
The 2-scrubber system at Commonwealth Edison’s Will County station,
started-up in February 1972, showed rather poor availability factors due
to many problems in the first 2 years of operation. Scrubber B was
shutdown in April 1973 for internal modifications, but scrubber A has
shown marked improvement recently. Availability was 72% in April of this
year and 93% in May. A plugged venturi throat caused some downtime in
June, but following repairs, the unit operated at 95% availability in
July and 91% in August. Although Commonwealth Edison has experienced
many problems at Will County, recent operation shows good signs for
reliable long-term operation.
3As recognized by the national hearing panel, bypass systems should be
installed on scrubbing systems to make it easier to repair and adjust
the system and to ensure that generating capacity is not lost during
possible malfunction.
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Experience at operating lime-scrubbing systems other than the
successful performance at LG&E’s Paddy’s Run unit and Southern
California Edison’s Mohave unit, cannot be fully assessed at this
time. Duquesne Light’s Phillips 410-megawatt scrubber, on-line only
for a few months, has achieved availability factors for modules 1 and
4 which were better than 70% from start-up through June. Duquesne is
presently concentrating the load on these two modules and, plans to
place the full plant capacity on all 4 modules in the future.
Dairyland Power Coop. ‘has been running its Alma lime-injection
unit since August 1971, but only as a research system. Short test
runs at 90% availability have been conducted, but no longer runs have
been conducted from which reliability.might be adduced.
EPA is funding a 30-megawatt research unit being operated by IVA
on its Shawnee No. 10 boiler. It is designed to use lime, limestone,
sodium carbonate, or air/water as the scrubbing medium and has been
operating under experimental conditions since April 1972. There are ‘3
different types of scrubbing systems operating in parallel that are
still being evaluated under a variety of operational modes.
Aside from Boston Edison’s successful Mystic unit, only one other
magnesium-oxide system is now in operation. This 100-megawatt scrubber,
also designed by Chernico, is being operated by Potomac Electric Power
Company at Dickerson No. 3. Start-up took place in September 1973, but
full operation was not begun until July 1974 when the regeneration
facility became available. This system represents the first large-scale
application of the magnesium-oxide process to.a coal—fired boiler.
Illinois Power Company has at its Jood River station the only’
catalytic oxidation system operating in the U. S. The 110-megawatt
scrubber designed by Monsanto started—up in September 1972 and was
accepted’ from the vendor after completion of testing in July 1973.
Mechanical difficulties experienced during shakedown called for modifica-
tions which are now nearly complete. The scrubber is scheduled to
start-up for continued operation this month.
The Nevada Power Company is now testing two aqueous sodium base
scrubbers at its Reid Gardner station and will start-up a-third unit
there next year. The 125-megawatt units have only been on-line for a
short time but excellent test results have already been cited and
performance seems promising.
SLUDGE DISPOSAL
It is recognized that large quantities of semi-solid sludge are
produced by lime and limestone scrubbing systems and that this sludge
must be carefully disposed of to avoid any adverse impact on the environ-
ment. EPA does not view sludge disposal as an insurmountable problem,
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however, since disposal methods are now offered commercially that
treat sludge in an environmentally acceptable manner. Wet sludge can
be hardened (fixated) through chemical reactions to form a dry,
solid, largely inert material or it can be ponded.
Although fixation technologies are offered commercially, many
companies have been temporarily ponding sludge while concentrating on im-
proving reliabilities of their FGD systems. Now that scrubber operating
problems are being solved and system reliabilities are improving, more sludge
is being generated by lime/limestone units and utilities are beginning to
focus more attention on techniques for disposing of sludge. For example,
full-scale sludge fixation is now underway at at least two U. S. power
plants. Commonwealth Edison fixates sludge from its Will County scrubber
and stores the product on-site. The company plans to ultimately dispose
of the sludge in an off-site landfill •area. Duquesne Light is now
fixating sludge from three boilers at the Phillips plant. This fixated
sludge is temporarily stored in on-site ponds, then hauled to off-site
lined ponds for disposal. It is ultimately planned to dispose of this
fixated sludge in unlined ravines. In addition, a prototype facility
at Southern California Edison’s Mohave station fixates the sludge, dis-
charging part of the treated sludge to a concrete-lined disposal site.
The remaining sludge is used to manufacture aggregate pellets which can
be used as a concrete admixture.
Chemically fixated sludge has several uses, the most important
of which is landfill. Numerous landfill sites are available in the
U. S., especially in areas where coal has been strip-mined. Fixated
sludge can be used to restore such land to its original condition.
Limited use is possible in such other applications as roadbase.
Wet sludge can also be ponded, and where leaching into ground or
surface water is feared, ponds can be lined with an impermeable liner
or constructed with a drainage system to collect and isolate any
leachate.
Sludge disposal problems occur, however, only with lime and lime-
stone scrubbing systems. Where disposal of such sludges is impractical
because of geographic location, space availability, or other considera-
tions. alternative FGD systems can be used. Reqerierable systems, such as
magnesium-oxide, catalytic oxidation, and Weliman-Lord processes,do
not produce sludge. Rather, these systems regenerate the scrubbing
agent and produce such valuable materials as sulfuric acid and elemental
sulfur.
SUMMARY & CONCLUSIONS
The past year has seen a major increase (over 100%) in the
commitment of utilities to the installation of FGD controls. While
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the commitment to control 35,000 megawatts of generating capacity
is still short of the need, 4 it represents a rapidly growing acceptance
by utilities of the need for and workability of FGD controls.
While a few, utilities continue to argue that FGD systems have not
yet demonstrated reliable operation, actual experience over the past
few months clearly refutes these claims. Experiences at Louisville Gas
and Electric, Arizona Public Service, and Southern California Edison
are illustrative. LG&E’s Paddy’s Run unit has been available to the
boiler for a total of 5 months at well over 90% reliability. APS’s
Cholla unit, has opérated’continuously for 8 months with a reliability
of 90% or better, and SCE’s Mohave unit has operated continuously from
January to September 1974 at 84% reliability.
Based on FGD operating experienceto date, the availability of
commercial methods to treat sludge wastes, and the rapidly growing
commitment of utility companies to install FGD, no other conclusion
can be reached than that flue gas desulfurization systems are avail-
able and can be used to continuously, reliably, and effectively control
sulfur oxide emissions from power plants.
4 1n the national hearing panel’s report, EPA estimated that to meet
primary ambient air quality standards and new source performance
standards through 1980 the use of some 90,000 megawatts of FGD
control would be required.
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September 1973
Table I
SUMMARY OF ELECTRIC UTILITY
FLUE GAS DESULFURIZ.ATION FACILITIES
MW Capacity (No. of Units )
NEW RETROFIT ON
PROCESS OPERATIONAL UNDER CONSTRUCTION PLANNED TOTALS PLANTS EXISTING PLANT
Limestone 1076(3) 1525(4) 1330(2) 3931(9) 4 5
Lime 725(4) 2930(6) 750(1) 4405(11) 7 4
Magnesium’ Oxide 250(2) 120(1) 370(3) 3
Catalytic Oxidation 110(1) --- 110(1) 1
Wellinan-Lord 115(1) --- 115(1) 1
Aqueous Na Based 375(3) 375(3) 3
Dry.Absorption 150(1) 150(1) 1
Process Not Selected 8569(15) 8569(15) 8 7
TOTAL 2161(10) 5215(16) 10649(18) 18025(44)’ 19 25
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0
September 18, 1974
Table II
ELECTRIC UTILITY
FLUE GAS DESULFURIZATION FACILITIES
PROJECTED START-UP DATE
1974 1975 1976 1977 1978 1979 1980 1983 Unknown
3 10 12 19 10 14 4
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september 18, 1974
Table III
SUMMARY OF ELECTRIC UTILITY
FLUE GAS DESULFURIZATION FACILITIES
MW Capacity (No. of Units )
NEW RETROFIT ON
PROCESS OPERATIONAL UNDER CONSTRUCTION PLANNED TOTALS PLANTS EXISTING PLANTS
Limestone 1904 (8) .1570 (4) 13027(27) 16501(39) 29 10
Lime 715 (4) 2910 (5) 5038(18) 8663(27) 8 19
Limestone or Lime 30, (1) 6085(10) 6115(11) 7 4
Magnesi 1 Oxide 250 (2) 120 (1) 487 (2) 857 (5) 5
y Catalytic Oxidation 110 (1) 110 (1) 1
Weliman-Lord 830 (3) 830 (3) 1 2.
Aqueous Na Based 250 (2) 125 (1) 375 (3) 3
Double Alkali ‘ 32 ( 1> 32 (1) . 1
Process Not Selected . - - . - - _ _ , 1900 (3) 1900 (3) 2 ‘ 1
TOTALS 3291(19) 5555(14). 26537(60) 35383(93) 47 46
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Table IV
STATUS
FLUE GAS DESULFUR1ZATION UNITS ON POWER PLANTS
PRESENTLY OPERATIONAL AND UNDER CONSTRUCTION
Utility Company New or Size of FGD Process Fue l, and
Power Station Retrofit Unit (MW) Vendor Sulfur Content Start—Up
Limes tone Scrubbing
Kansas Power & Light 12 ! CE Coal, 3.5% Dec. 1968
Lawrence No. 4
Operational Experience —— Limestone boiler injection; many problems including corrosion, plágging, and
reheater/demister difficulties; no significant scaling problems.
Performance unsatisfactory due to poor scrubber control and lime distribution
in scrubber; efficiency up to 85% but operation erratic -- system to be converted
to tail-end scrubbing with limestone. The two modules on unit No. 4 have been
available essentially 100% during August 1974.
Sludge Practices —— Three unlined ponds; overload encountered.
Kansas Power & Light 400 CE Coal, 3.5% Nov. 1971
Lawrence No. 5
Operational Experience — - Same problems. as Lawrence No. 4 with added problem of scaling when both units
attempted to use an inadequate sized pond.
Performance unsatisfactory due to poor scrubber control and gas distribution.
to the eight modules; efficiency up to 85%, lut operation erratic. The system
will be converted to tail-end scrubbing with Umestone. Unit No. 5 has oper-
ated on gas and oil during August 1974.’
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Utility Company New or Size of FGD Process Fuel and
_ Power Station Retrofit Unit (NW) Vendor Sulfur Content Start—Up
Sludge Practices — — Three unlined ponds; overload encountered.
Commonwealth Edison 167 B&W Coal, 3.5% Feb. 1972
Will County No. 1
Operational Experience .—— Feb. 1972 to ?4ov. 1973 —— intermittent operation with 80—90% SO 2 removal; many
mechanical problems including demisterJreheater pluggage, wearing and plugging
of spray nozzles, reheater vibration and stress corrosion cracking, plugging
of slurry lines, “sulfite blinding”, and scaling. Other reasons for outage are
expansion joint failure, contractor/operator errors, fan trip, water loss, faulty
damper operation, leaks, inadequate limestone supply, and booster fan vibration.
Through the end of 1972, scrubber A operated 1726 hours for an availability of
27%; scrubber B operated 328 hours for an availability of 5.1%.
Nov. 1973 to present —— loss of building heat caused extensive freeze damage;
washing system modified to continuous river—water wash as underspray plus inter-
mittent overspray wash using pond water. Chlorides have caused problems in re—
heaters. Scrubber B was shut down on April 13, 1973, and is awaiting internal
modifications to perforated trays. Scrubber A availability has generally im-
proved recently and was 72% in April, 937 , in May, 54% in June, 95% in July, and
91% in August.- The lower availability in June was- due to a plugged venturi throat.
Company considering conversion of the scrubbers to particulate control only.
Sludge Practices - —— Presently using-lined ponding; working with Chicago Fly Ash on fixed treatment
process; the State has issued a development permit to the Contractor (Materials
Services Company) for sludge disposal at the Contractor—owned site; an oper-
ating permit has been requested and is expected in the near future.
Kansas City Power & R - 100 CE - Coal, 3.5% August 1972
Light, Hawthorn No. 4
Operational Experience —— Formerly limestàne boiler injection, recently converted to tail—end system.
70% SO 2 removal. No recent problems with fans or reheaters; remaining problems
appear to be with recirculation system, including headers and drain pots; de—
mister pluggage was a problem but is presently under control; some settling has
occurred in the recirculEtion tank requiring tank modification and agitation
improvements. - -
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New or
Retrofit
Size of FGD
Unit (MW)
Process
Vendor
Fuel and
Sulfur Content
City of Key West N
Key West
Vendor says system has operated since 2/74 with no major problems, although
scrubber/demister must be cleaned by hand during periods of boiler downtime.
Operational Experience — —
Scrubber is not presently operating because the by—pass damper is jammed open.
During performance tests in August 1973, SO 2 removal efficiency was approximately
75%. The system consists of two Zurn Air Systems Dustraxtor scrubbers, each of
which has 24 vertical 12” ID tubes which pass flue gas and entrained limestone
slurry. Total operation to date consists of 400 hours. A major problem has been
the coral grinding system — — initially the venturi installed for dust removal was un-
satisfactory. The baghouse which replaced the venturi plugs after only 4 hours
of operation; corrective actions (increasing the number of bags, using lighter,
thinner bags, using teflon coated bags, and increasing purge air pressure) are
presently being evaluated.
Kansas City Power & N
Light, LaCygne No. 1
820 B&W Coal, 5% June 1973
Operational Experience — — Seven modules each consisting of a two—stage scrubbing system — — venturi and
grid tower. Very similar to the Commonwealth Edison Will County Unit. This
system is not equipped with by—pass or ESPs. Unit was designed to operate with
Utility Company
Power Station
Sludge Practices —— Presently using ponding, unlined; numerous well points for testing ground
water; fly ash contamination in pond.masks test results; land area for pond—
ing sufficient for 15 years.
Start—Up
I- .
Kansas City Power &
Light, Hawthorn No. 3
R
140
CE
Coal, 3.5%
Nov.
1972
Operational Experience
——
Limestone
as those
boiler injection; no
described for Hawthorn
boiler
No. 4.
pluggage;
problems
essentially
the
same
‘
Sludge Practices
——
Same as
Hawthorn No. 4.
•
37 Zurn Oil, 2.4% Oct. 1972
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Utility Company New or Size of FCD Process Fuel and
Power Station Retrofit Unit (M W) Vendor Sulfur Content Start—Up
7 modules taking the total load. An eighth module was to serve as a spare.
Initial problems included induced draft fan deposits and erosion, demister
pluggage, nozzle pluggage, reheater coil failures (corrosion/erosion), pump
screens pluggage. Most of the problems are attributable to poor pH control
which results from inadequate instrumentation.
Pluggage problems in the venturi hoses and nozzles were solved by the addition
of cyclone separators which reduced the solids content of the spray liquor.
Sulfate scaling on the demisters has been significantly diminished by using 50%
clear H 2 0 for the demister spray. In addition, heavier demisters (1/8” rather
than 1/16”) and overlapping chevrons are expected to improve the operability
of the system. The plant is looking for a way to monitor solids carry—over
which forms deposits on fan blades. The venturis in all seven modules are cur-
rently in use. SOz removal efficiency across the venturi and absorber combina-
tion is approximately 70%. Although the station’s rating is 848 MW, the net
power rate leaving the plant is 790 MW due touse of auxiliary power required
to operate FCD process and “stealing” of hot air from boilers to supplement the
steam reheating of the scrubber effluent gases to 190—200°F.
Sludge Practices — — Presently using ponding, unlined.
ArLzona Public Service R 115 Research— Coal, 0.4—1.0% Dec. 1973
Cholla No. 1 Cottrel l
Operational Experience -- System availability from January 1974 through July 1974 averaged 89°?. for both
modules. Module A (SO 2 and particulate scrubbing) availability was 92% and module B
(particulate scrubbing only) availability was 87% Downtime was attributed to re-
wiring, leak repair, packing gland repair, meter calibration, reheater vibrations,
instrumentation, inspect reheater tube bundles, repair reheater tube bundles.
fparticulate removal efficiencies are 92%/997, --particulates removed in flooded
disc venturi scrubber and SO 2 removed in packed tower. Acid condensation on
reheater tubes stopped by insulating -- reheater vibration stopped by cross baffles
at inlet. 157 , solids sent to pond. Replaced expansion joint on reheater . Scrubber
system availability for August was 93 % Module A availability was 98%
Sludge Practices - — Presently using unlined ponding and evaporation; due to water shortage, Research
Cottre ll is attempting to maximize water recovery and recycling.
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Utility Company New or Size of FGD Process Fuel and
Power Station Retrbflt Unit (NW) Vendor Sulfur Content Start—Up
Southern California R 160 UOP Coal, 0 .5—0.8% Under Con-
Edison (operating struction
agent) Nohave No. 1 (Oct. 1974)
Operational Experience —— Originally scheduled for start—up In January 1974 but delayed until October
by extensive fire damage.
Sludge Practices —— Ponding planned; IUCS & Dravo are developing sludge treatment/disposal tech-
niques on—site and are competing for contract.
Detroit Edison
St. Clair No. 6
R
180
Peabody
Engineering
Coal,
3.7%
Under Con—
struction
(Jan. 1975)
Sludge Practices
——
Unfixed
ponding
planned.
TVA
Widow’s Creek No.
8
R
550
TVA
Coal,
3.7%
Under Con—
struction
(May 1975)
Sludge Practices
——
Unlined ponding planned; have
evaluating chemical fixation
acquired new large
and clay ponditig at
area
TVA’s
for ponding; EPA’s CSL
Shawnee Plant.
Northern States Power N 680 CE Coal, 1% Under Con—
Sherburne County No. 1 struCtion
(May 1976)
Sludge Practices —— Ponding plann d; clay lined.
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Utility Company New or Size of FGD Process Fuel and
Power Station Retrofit Unit (MW) Vendor •Sulfur Content Start—Up
Lime Scrubbing
Louisville Gas & R 65 CE Coal, 3% Apr11 1973
Electric, Paddy’s
Run No. 6
Operational Experience —— ES? followed by 2 parallel, 2—stage marble bed scrubbers. Unit operated at 70%
availability to boiler since start—up in April to December 1973. From October.
to December 1973 the availability was greater than 90%. The boiler was shut—down
in December 1973 because of low demand, and restarted with FGD operation during
July 1974. The FGD unit has been operating at 100% availability since the recent
start—up. SO 2 removal is 90% —— no scaling, plugging, erosion, or corrosion.
Early problems were minor and mechanical in nature. The demisters have caused
no problems. The system is essentially closed loop—operation, and the FGD sys—
tern has effectively followed the varying boiler load.
Sludge Practices —— Sludge is filtered and used for land fill in a ravine; this is a small plant, it
is a pilot test for large system.
Southern California R 160 SCE/ Coal, 0.5—0.8% Nov. 1973
Edison (operating agent) Stearns—
Mohave No. 2 Roger
Operational Experience - - The formal test program for SCE started January 1974. The horizontal absorber
had logged 3200 operating hours (better than 75% availability) as of July 24, 1974
in the “research mode.” The overall availability of the -horizontal absorber from
January 1, 1974 to September 13, 1974 has been 84 %. The scrubber has operated
with good reliability and no major operational problems to date. No severe plugging
or scaling has occurred in any of the tests.
Sludge Practices —— Ponding planned; IUCS and Dravo are developing sludge treatment/disposal tech-
niques on—site and are competing for contract.
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Utility Company New or Size of FGD Process Fuel and
Power Station Retrofit Unit (MW) Vendor Sulfur Content Start—Up
Duquesne Light Company R 410 Chemico Coal, 2% March 1974
Phillips Station
Operational Experience —- Brief start—up with water for fly ash removal led to erosion problems, par-
ticularly with fans. Shutrdown for fan maintenance, including modification of
fan spray wash and completion of lime feed system.
Restart March 17—22, 1974 with lime added to 2—stage scrubber train and to one
of three one—stage trains. Three of six plant boilers currently tied into
scrubber system (approx. 40% of plant generating capacity). No operating prob-
lems of plugging with scrubbers, although wet induced draft fans have minor
solid deposition and corrosion problems. Other problems include difficulties
with transporting sludge treatment chemical slurry to pond area, excess water
in system (primarily from fan wash and excess fly ash solids because of re-
duced ESP efficiency caused by high velocity in scrubber duct tie—in.
Operating hours for modules 1 through 4 between March 17, 1974 and June 30, 1974
were 1756, 762, 815, 1707 respectively. Modules 1 and 4 are considered primary
scrubbers and the plant attempts to run these continuously.
Sludge Practices —— Three small lined ponds on site; plant has two areas in a ravine for sludge de-
posits; planning fixation process in large ravines using Dravo technology.
Dairyland Power Coop.
R 80 Foster Wheeler Coal, 3.0—3.5% August 1971
Alma Station
Operational Experience
——
The FGD system is a demonstration project consisting of lime (CaO) mixed with
water and injected into the upper boiler under pressure. Short run tests are
conducted in conjunction with a slip stream ESP. During the test runs the
FCD system availability was 90% and efficiency of SO 2 removal was 50%
Duquesne tight Company R 510 Chemico Coal, 2% Under Con-
Elrama Station struction
(1974)
Operational Experience —— The five venturi scrubber trains which were designed to remove particulates
only will eventually be modified to remove SO 2 . The start—up of the scrubbers
was delayed to evaluate operating problems at the Phillips Station.
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New or
Retrofit
Size of FGD
Unit (M W )
Process
Vendor
Fuel and
Sulfur Content
Pennsylvania Power
Mansfield No. 1
Under Con-
struction
(Early 1975)
—— Plan calls for pumping sludge several miles into
calls for treating sludge for fixation.
Pennsylvania Power
N
SOC
Chemico
Coal, 4.3%
Under Con—
Mansfield No. 2
struction
(Early 1975)
•
Sludge Practices
——
Plan
calls
calls
for
for pumping sludge
treating sludge for
several miles
fixation.
into
a dammed ravine;
.
Dravo contract
Montana Power
N
360
CEA
,
Coal, 0.8%
Under Con—
Colstrip No. 1
.
struction
(May 1975)
Montana Power
N
360
CR4
Coal, 0.8%
Under Con—.
Colstrip No. 2
struction
(May 1975)
TVA R
Shawnee No. 10
This is an experimental system funded by U. S. EPA. The facility consists
of 3 parallel scrubber systems: I) venturi followed by a spray tower; 2)
turbulent contact absorber (TCA); and 3) marble bed absorber. Each system
is capable of treating 10 M W equivalent of flue gas containing 1000-4000
ppm °2 and 2-5 grainslscf particulates. --The following test blocks have
been defined for the program: I) air/water testing; 2) sodium carbonate;
3) limestone wet scrubbing; 4) lime wet scrubbing. The major test goals
are: 1) to characterize the effect of process variables on SO 2 and particu-
late removal; 2) to develop mathematical models to allow economic scaleup
of optimum operating configurations; and 3) to perform long-term reliability
testing. Experimental test runs are planned up to 1976. Excellent potential
for high efficiency and reliability is indicated from results to date with
lime and limestone scrubbing employing the TCA and venturi/spray tower.
Utility Company
Power Station
N 880
Sludge Practices
Chemico Coal, 4.3%
Start—Up
a dammed ravine; Dravo contract
‘0
Limestone or Lime
Operational Experience --
30
TVA
Coal
April 1972
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Utility Company New or Size of FGD Process Fuel and
Power Station Retrofit Unit (MW) Vendor Sulfur Content Start—Up
Magnesium Oxide Scrubbing
Boston Edison
Mystic No. 6 R 150 Chemico Oil, 2.5% April 1972
Operational Experience —— From April 1972 to May 1973 many process and mechanical problems developed and
were constantly being worked on and corrected. During this 13 month period the
scrubber availability was approximately 17%. Efficiency during this period from
limited testing indicated 90% SO 2 removal using virgin MgO and 80% using regen-
erated MgO. Slacking and pumping problems occurred during the use of regenerated
MgO.
The following scrubber availability are reported for 1973: June —— 68%, July ——
61%, August —— 73%, September —— 38%, October —— 60%, November —— 26%, and
December —— 13%. The decreasing availability during this seven month period
was due to deterioration of equipment from erosion/corrosion.
The availability during January 1974 was 28% and 25% for Feb. 1974. During this
period a lot of overhaul work was carried out. Near the end of February 1974 a
performance test indicated a SO 2 removal efficiency of 91% and 50% for particu—
lates using regenerated MgO.
The following availabilities were recently obtained: March 1974 -- 87%,
April 1974 -- 81%, May 1974 -- 57%, and June 1974 -- 80% SO 2 removal
efficiency was 80-90%. The scrubber was shut-down on June 27. It will
not be restarted because the 2 year project is completed and PEPCO
(Dickerson No. 3) is now using the calcining facilities at Rumford, R.I.
Potomac Electric & R 100 Chemico Coal, 2% Sept. 1973
Power
Dickerson No. 3
Operational Experience —— First large scale coal application of the Mag-Ox Process.
-------
Utility Company New or Size of FGD Process Fuel and
Power Station Retrofit Unit (NW) Vendor Sulfur Content Start—Up
Although the system has experienced some start—up difficulties, scrubber oper-
ation has been satisfactory to date. It should be noted that only the scrubber
system had been operated until recently (July 1974) when the Rumford, R.I.
regeneration facility was made available for PEPCO use, at the conclusion of
Boston Edison’s testing program. Plant is presently down for a few days to
allow minor modifications to be made. No major problems reported.
Philadelphia
Electric R
120 United Coal,
2.5% Under
Con—
Eddystone
No.
1
Engineers
struction
(Dec. 1974)
Catalytic Oxidation (Cat—Ox )
Illinois Power Company R 110 Monsanto Coal, 3.2% September 1972
Wood River No. 4
Operational Experience —— 85% SO 2 removal achieved; mechanical difficulties during initial operation indi-
cated need for modifications —— construction completed 10/72, but acceptance
testing completed 7/73.
Operational modifications in process —— reheater burners being converted from
natural gas to fuel oil.
Modifications in process; operation scheduled for September 1974.
Wellman-Lord
Northern Indiana R 115 Davy Powergas/ Coal, 3.5% Under Con—
Public Service, Allied Chemical struction
D. H. Mitchell No. 11 (Mid 1975)
Public Service of N 375 Davy Powergas Coal, 0.8% Under Con—
New Mexico stnsction
San Juan No. 1 (1977)
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New or
Retrofit
Size of FGD
Unit (MW)
Process
Vendor
Fuel and
Sulfur Content
Public Service of
New Mexico
San Juan No. 2
Aqueous Sodium Base Scrubbing, Non—Regenerable
• Under Con-
struction
(1977)
Nevada Power
Reid Gardner No. 1
CEA Coal, 0.5—1.0%
May 1974
Operational Experience -- System performs satisfactorily when there is sufficient Trona (impure
form of sodium carbonate). There are no outstanding process problems.
However, the plant is running out of Trona and operates only intermittent-
ly. Supplier will not deliver Trona before 3d quarter of 1975.
Nevada Power
R
125
CEA
Coal, 0.5—1.0%
May 1974
Reid Gardner
No. 2
Operational
Experience
--
Same
with.
as Reid Gardner No.
Reid Gardner No. 2.
1.
Excellent
initial
test results obtained
Nevada Power
R
125
CEA
Coal, 0.5—1.0%
Under Con—
Reid Gardner
No. 3
struction
(1975)
Double Alkali (Sodium/Calcium) Throwaway Product
General Motors
Parma Chevy
Transmission Plant
Cleveland, Ohio
Coal, 2.5%
April 1974
Operational Experience ——
General Motors announced continuous operation for 624 hours as of April 31, 1974.
the system was shut—down from May 1—May 28 due to the unexpected build—up of
solids in the clarifier with subsequent overflow into the scrubber. This prob—
1cm was corrected by (1) using a polymeric flocculating agent to attain better
settleability and (2) withdrawing sludge from the clarifier at more frequent
Utility Company
Power Station
R 340
Davy Powergas Coal, 0.8%
Start—Up
R 125
R
32 GM
-------
N.)
Utility Company New or Size of FGD Process Fuel and
Power Station Retrofit Unit (MW) Vendor Sulfur Content Start—Up
Intervals. The system has been In operation since May 29 except for brief,
non—scrubber related shut—downs. Pluggage by CaCO 3 deposits in the overflow
line between the clarifiers and in the line from Clarifier 2 to mix tanks has
been a problem. The scrubber availability to the boiler has been 87% in April,
less thanl in May, and 100 percent for June, July and August 1974. The ef-
ficiency of SO 2 removal was determined to be 98 percent.
-------
Utility Company
Power Station
Contract Awarded
Columbus & Southern Ohio
Conesvi lle No. 5
Columbus & Southern Ohio
Conesville No., 6
Kansas Power & Light
Jeff ery No. 1
Kansas Power & Light
Jeff ery No. 2
Kansas Power & Light
Jeffery No. 3
Kansas Power & Light
Jeff ery No. 4
Kentucky Utilities
Green River 1, 2, & 3
Louisville Gas & Electric
Cane Run No. 4
Lime
UOP
Lime
UOP
Limestone
CE
Limes tone
CE
Limestone
CE
Limestone
CE
Lime
Am. Air Filter
Lime
Am. Air Filter
Table V
PLANNED FLUE GAS DESULFURIZATION UNITS ON POWER PLANTS
New or Size of FGD Process
Retrofit Uni jMW ) Vendor
N
N
N
N
N
N
R
R
375
375
700
700
700
700
64
178
Fuel and
Sulfur Content
.
Start—Up
1976
Coal
Coal
1976
Coal, 0.3%
1979
Coal, 0.3%
1979
Coal, 0.3%
1979
Coal, 0.3%
1979
Coal, 3.8%
1975
Coal, 3.5—4.0%
1975
-------
Size of FGD
Unit (MW)
425
680
650
343
200
793
793
793
793
200
205
Fuel and
Sulfur Content
Coal, 3.5—4.0%
Càal, 1.0%
Coal, 1.5%
Coal, 0.5%
Coal
Coal, 0.4%
Coal, 0.4%
Coal, 0.4%
Coal, 0.4%
Start—Up
1977
1977
976
1976
1976
1976
1977
1978
1979
1979
1979
Utility Company New or
Power Station Retrofit
Louisville Gas & Electric R
Mill Creek No. 3
Northern States Power N
Sherburne County No. 2
Public Service Indiana N
Gibson
Southwestern Pub. Ser. N
Harrington No. 1
Springfield Utility Board N
Southwest No. 1
Texas Utilities N
Martin Lake No. 1
Texas Utilities N
Martin Lake No. 2
Texas Utilities N
Martin Lake No. 3
Texas Utilities N
Martin Lake No. 4
Letter of Intent Signed
Arizona Electric Power N
Apache No. 2
Arizona Electric Power N
Apache No. 3
Process
Vendor
Lime
Am. Air Filter
Limes tone
CE
Limes tone
CE
Lime
CE
Limes tone
U0!
Limestone
RC
Limestone
RC
Limestone
RC
Limestone
RC
Limestone Coal, 0.5—0.8%
Research Cottrell
Limestone Coal, 0.5—0.8%
Research Cottrell
-------
Utility Company
Power Station
Arizona Public Service
Cholla No. 2
Arizona Public Service
Cholla No. 3
Out for Bids
Central Illinois Pub. Ser.
Duck Creek No. 1
Central Illinois Pub. Ser.
Newton No. 1
Cincinnati Gas & Electrir
Miami Fort No. 8
General Public Utilities
Homer City No. .3
Indianapolis Power & Light
Petersburg No. 3
South Carolina Pub. Ser.
Georgetotm No. 2
Texas Utilities
Monticello No. 3
Conducting Engineering Studies
Arizona Public Service
Four Corners No. 1
Size of FGD
Unit (NW)
250
250
New or
Retrofit
N
N
Process Fuel and
Vendor Sulfur Content Start—Up
Limestone Coal, 0.4% 1977
Research Cottrell
Limestone Coal, 0.4% 1978
Research Cottrell
Coal 1976
100
600
500
650
515
140
800
N
N
N
N
N
N
N
R
Limes tone
Riley Stoker/
Environeering
Limestone/Lime
Limestone/Lime
Not Selected
Limestone/Lime
Limestone/Lime
Limestone
Coa1 2.8—3.2%
Coal, 3.2%
Coal
Coal, 3.5%
Coal, 1.0%
Coal, 0.8—1.0%
1977
1977
1977
1977
1977
1978
175 Lime
Chemico
Coal, 0.8% 1976
-------
New or
Retrofit
N
N
N
N
N
N
R
R
R
N
N
Size of FGD
Unit (MW)
550
550
550
600
450
450
202
250
650
750
750
Process
VendOr
Limes tone
Limes tone
Limes tone
Not Selected
Limestone
Limestone
Limestone
Limestone
Not Selected
limestone/Lime
Limestone/Lime
Fuel and
Sulfur Content
Coal
Coal
Coal
Coal,
Coal,
Coal,
Coal,
Coal,
Coal,
Coal,
Coal,
Start—Up
1979
1980
1983
1979
1978
1978
1978
1978
1976
1976
Utility Company
Power Station
Basin Electric
Missouri Basin No. 1
Basin Electric
Missouri Basin No. 2
Basin Electric
Missouri Basin No. 3
Cincinnati Gas & Electric
East Bend No. 1
Colorado Utility Electric
Craig No. 1
I ’. )
Colorado Utility Electric
Craig No. 2
Colorado Utility Electric
Hayden No. 1
Colorado Utility Electric
Hayden No. 2
New England Electric System
Brayton Point No. 3
Salt River Project
Navajo No. 1
Salt River Project
Navajo NoV. 2
0.5—0.8%
0.5%
0.5%
0.5%
0.5%
0.3%
0. 5—0. 8%
0.5—0.8%
-------
New or
Re trof it
N
R
R
N
N
N
R
R
R
R
R
Size c’f ECU
Unit (NW)
750
640
640
223
223
372
175
229
800
800
110
Process
Vendor
Limestone/Lime
Limestone/Lime
Limestone/Line
Limestone
Limes tone
Limes tone
Lime
Chemico
Lime
Lime
Chemico
Limestone/Line
Lime
Fuel and
Sulfur Content
Coal, 0.5—0.8%
Coal, 0.5—0.8%
Coal, 0.5—0.8%
Coal
Coal
Coal
Coal, 0.8%
Coal, 0.8%
Coal, 0.8%
Coal, 0.8%
Coal, 3.5—4.0%
Start—Up
1977
1977
1977
1979
1979
1979
1977
1977
1977.
1977
1980
Utility Company
Power Station
Salt River Project
Navajo No. 3
Southern Calif. Edison
Mohave No. 1
Southern Calif. Edison
Mohave No. 2
Southern Miss. Power Co.
Hattiesburg No. 1
Southern Miss. Power Co.
Hattiesburg No. 2
Initial Planning Stage
Arizona Public Service
Cholla No. 4
Arizona Public Service
Four Corners No. 2
Arizona Public Service
Four Corners No. 3
Arizona Public Service
Four Corners No. 4
Arizona Public Service
Four Corners No. 5
Louisville Gas & Electric
Cane Run No. 1
-------
Size of FGD
Unit (MW)
107
137
183
277
330
330
425
153
(or
334
Process
Vendor
Lime
Lime
Lime
Lime
Lime
Lime
Lime
* Mag-ox
United Eng,
Nag - ox
United Eng.
Fuel and
Sulfur Content
Coal, 3.5—4.0%
Coal, 3.5—4.0%
Coal, 3.5—4.0%
Coal, 3.5—4.0%
Coal, 3.5—4.0%
Coal, 3.5—4.0%
Coal, 3.5—4.0%
Coal, 2.5%
Coal, 2.5%
S tart—Up
1980
1980
1976
1977
1979
1978
1979
1978
1978
*
Utility is undecided as to which boiler to retrofit with FGD.
Utility Company New or
Power Station Retrofit
Louisville Gas & Electric R
Cane Run No. 2
Louisville Gas & Electric R
Cane Run No. 3
Louisville Gas & Electric R
Cane Run No. 5
Louisville Gas & Electric R
Cane Run No. 6
Louisville Gas & Electric R
Mill Creek No. 1
Louisville Gas & Electric R
Mill Creek No. 2
Louisville Gas & Electric N
Mill Creek No, 4
Philadelphia Electric * R
Croniby No. 1 (or No. 2)
Philadelphia Electric R
Eddystone No. 2
201)
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