EPA
TECHNOLOGY
TRANSFER
FIRST PROGRESS REPORT:
WELIMAN-LORD
^RECOVERY
PROCESS-
FLUE GAS
DEVELORV\ENT
PROTOTYPE
DESULFURIZM10N DBVlONSTRATlON
PIANT FACILfFY
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EPA
TECHNOLOGY
TRANSFER
EPA-625/2-77-011
FIRST PROGRESS REPORT:
i i s FPA
WELLMAN-LORD OFFICEOF
^RECOVERY RES^RCHAND
PROCESS- DEVELOPMENT
f-LUEGAS PROTOTYPE
DESULFURIZAHON DEMONSTRATION
PIANT FACILITY
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FGD Plant at Dean H. Mitchell Station
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INTRODUCTION
This capsule report describes initial results from;
a joint program being conducted by Northern ;
Indiana Public Service Company (NIPSCO) and the
Environmental Protection Agency (EPA) to dem- ;
onstrate the sulfur dioxide (SO2) removal capa- ;
bilities of the Wellman-Lord/Allied Chemical flue !
gas desulfurization (FGD) facility. The FGD dem-i
onstration plant is retrofitted to the Unit No. 11 '
coal-fired boiler at NIPSCO's Dean H. Mitchell ;
Station in Gary, Indiana. The FGD plant consists \
of the Davy Powergas Inc. (Davy) proprietary i
design Wellman-Lord SO2 Recovery Process (W-L ;
SO2 Recovery), Davy's Purge Treatment Unit,
together with Allied Chemical Corporation's j
(Allied Chemical) SO2 reduction process. i
This interim report summarizes the operational :
progress on the W-L SO2 Recovery portion of the i
FGD facility; it is being released at this time ;
because the Acceptance Test has been delayed
until summer 1977. The delay is the result of a !
mishap that occurred on the Unit No. 11 boiler on:
January 15, 1977. The mishap was completely un-;
related to the FGD plant operation.
Because this report predates the period of for- '•
mal acceptance testing during which the FGD plant
must demonstrate that it can meet specific oper- :
ational criteria for acceptance by the utility, i
NIPSCO reserves public position statements on j
the operability, reliability, and efficiency of the ;
plant until such testing has been concluded. This :
report has been published by EPA with collabora- ;
tion of Davy Powergas and approval by Allied ;
Chemical and NIPSCO to inform interested people;
about the preliminary operational experience with,
the SO2 recovery portion of an FGD plant. ;
As would be expected, startup of the FGD facil-i
ity was done in phases. The first phase, fol-
lowing the initial chemical charge, was the treat-
ment of flue gas in the absorber to remove SO2.
The absorber discharge solutions were stored in the
surge tanks. During the second phase, the SO2-rich
solution from the absorber surge tank was heated
in the evaporator to reverse the absorption reaction
and release a concentrated SO2 gas stream. When
the W-L/Allied Chemical plant is in full operation,
this stream will go to the Allied Chemical SO2
reduction process for conversion to elemental
sulfur. To balance the surge tank inventories, the
absorber was not operated during the second
phase. The third phase was to complete the oper-
ational check of the piping system that recycles
regenerated absorbent from the evaporator to the
absorber. During this period of initial operation,
the SO2 stream was routed to the stack that served
Unit No. 11 before the W-L/Allied Chemical facil-
ity was built.
SUMMARY
Integrated operation of all units was accom-
plished during two abbreviated periods; however,
the W-L SO2 Recovery system was operational
during the period from July 19 through November
28, 1976. There were three sustained runs on the
W-L SO2 Recovery system. During these runs, it
was demonstrated that the system is capable of
removing SO2 from the flue gas at rates greater
than 90 percent.
On completion of the repairs to Unit No. 11, in
May 1977, the FGD facility will be restarted. After
a period of continuous integrated operation, the
Acceptance Test will begin. Successful acceptance
testing will be followed by a full year of contin-
uous operation and testing.
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The FGD facility consists of three major process
units:
• W-L SO2 Recovery
• Davy Purge Treatment Unit
• Allied Chemical SO2 Reduction
The entire FGD plant is operated from a central
control room, conveniently located to allow rapid
and easy access to all plant facilities.
W-L S02 RECOVERY
The W-L SC>2 Recovery system (Figure 1) is a
regenerative process and consists of a flue gas
booster blower, an orifice contactor (prescrubber),
an absorber with three absorption stages, and an
evaporator (crystalIizer).
Flue Gas Pretreatment
The booster blower delivers the flue gas through
the orifice contactor (a variable throat venturi pre-
scrubber) to the absorber. The flue gas is cooled
and saturated in the orifice contactor by water/
slurry recirculated from the bottom of the pre-
scrubber back to the venturi sprays. The fly ash cap-
tured by the scrubbing solution is purged contin-
uously from the system to the pond. Lake water is
used for the makeup of water lost via the purge
and evaporation.
Absorption
The absorption of the SO2 from the pre-
scrubbed flue gas takes place in three absorber
stages. Each absorber stage consists of a valve tray
and a collector tray.
A sodium sulfite solution absorbs and chem-
ically reacts with the sulfur dioxide to form so-
dium bisulfite. A mist eliminator removes en-
trained liquid droplets from the gas exiting up the
absorber stack. There is a direct-fired, natural gas
reheat system in the absorber stack so that the
clean gas can be reheated, if necessary, for dis-
persion of the steam plume.
The reactions that take place in the absorber are
simplified as follows:
• Sulfur dioxide and sodium sulfite react to
form sodium bisulfite:
SO2 + Na2SO3 + H2O -» 2NaHSO3
• Some oxidation of the sodium sulfite takes
place in the absorber and sodium sulfate is
formed:
2Na2SO3 + O2 -»• 2Na2SO4
• Makeup sodium carbonate combines with
sodium bisulfite to form additional sodium
sulfite:
Na2CO3 + 2NaHSO3 -»
2Na2SO3 + CO2 t + H2O
Evaporator-Crystallizer
The product solution collected on the bottom
collector tray of the absorber overflows to the
absorber surge tank. From this tank, the solution is
pumped through a filter to insure that no fly ash
will enter the evaporator system. A small side-
stream of the filtered solution is sent to the purge
treatment area to remove the sodium sulfate. The
bulk of the product solution is pumped to the
evaporator for regeneration of the sodium sulfite.
The evaporation system consists of a forced-
circulation vacuum evaporator. The filtered solu-
tion is recirculated in the evaporator, where low-
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pressure steam is used to evaporate the water from
the sodium bisulfite solution. When sufficient :
water has been removed, sodium sulfite crystals i
form and precipitate. Sulfur dioxide is removed !
with the overhead vapors. The slurry formed by :
the sodium sulfite crystals is withdrawn contin- !
uously to the dump/dissolving tank, where con- i
densate from the evaporator is used to dissolve the1
crystals in the solution that is pumped back to the!
top stage of the absorber. :
The following reaction takes place in the vac-
uum evaporator:
2NaHS03 -> Na2S03 + SO2 t + H2O
The water vapor is removed from the sulfur di-
oxide in water-cooled condensers. The SO2 is com-
pressed by a liquid ring compressor for intro-
duction to the Allied Chemical SO? reduction
facility.
SODIUM CARBONATE
SOLUTION MAKEUP
7 BOOSTER BLOWER
2 ORIFICE CONTACTOR
3 ABSORBER
4 ABSORBER SURGE TANK
5 EVAPORA TOR-CR YSTA LLIZER
6 DUMP-DISSOLVING TANK
7 CONDENSER
8 SO2 COMPRESSOR
9 CHILLER CRYSTALLIZER
W CENTRIFUGE
11 DRYER
72 STORAGEBIN
13 ABSORBER FEED TANK
DRIED SULFATE
PRODUCT
Figure 1. Schematic of W-L SO2 Recovery System
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Makeup
Sodium carbonate (soda ash) is used to replenish
sodium lostassulfate in the Purge Treatment system
by the addition of sodium carbonate to the absorber
solution. The soda ash is brought to the plant in
trucks and is transferred to the storage bin by a
pneumatic conveying system. The soda ash is me-
tered to the slurry tanks by a bin activator and belt
feeder. The soda ash slurry is pumped to the ab-
sorber feed tank by parallel centrifugal pumps.
DAVY PURGE TREATMENT UNIT
The small sidestream of filtered solution from
the absorber is pumped to four chilled-wall crystal-
lizers where sodium sulfate crystals form. The crys-
tallized slurry is centrifuged to extract the sodium
sulfate crystals. The clear solution is returned to
the evaporator feed system. The sodium sulfate
crystals are melted and fed to a steam-heated
dryer. The dryer discharge product is then stored
in a bin until loaded in trucks for shipment. Any
gases that evolve from the purge treatment are
chemically scrubbed and vented to the atmosphere.
ALLIED CHEMICAL SO2 REDUCTION
PROCESS
The compressed SO2 is fed to the Allied Chem-
ical SO2 reduction plant, where it is reacted with
natural gas. The resulting elemental sulfur is con-
densed and stored in molten form for shipment.
The off-gases are burned in a tail gas incinerator
and returned to the absorber inlet.
Orifice Contactor at Absorber Inlet
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OPERATION PERIODS
The sustained runs of the SO2 recovery sys-
tem of the FGD plant cover the periods shown in
Table 1.
SO2 REMOVAL
During the three sustained operating periods,
when operating under normal conditions, the ab-
sorber demonstrated the capability to remove the
SO2 from the incoming gas at higher rates than
those set by the performance criteria. Detailed
efficiencies are shown in Figures 2 through 4.
There were some days during the sustained
operating periods when only one, two, or three
data points were used to calculate the SO2 removal
averages. This lack of data points was most often
caused by inoperative instruments.
The criteria for acceptance state that during the
Acceptance Test/
The system when operated with a 3.15 to 3.5 weight %
sulfur in the coal shall achieve 90% sulfur removal from
Table 1
PERIODS OF OPERATION OF THE
W-L S02 RECOVERY SYSTEM
/fRun
|No.
fri
r*T-
s 2
t"3
V—
Duration
(days)
15
11
14
• '
Period
Sept. 25 through Oct. 9,
1976
Oct. 13 through Oct. 23,
. 1976
Nov. 15 through Nov. 28
1976
N
i
•1
^*
j
3,000
2,000 -
7,000 -
RUN DURA TION, days
THE SO2 CONCENTRA TION CUR VES HA VE BEEN
EXTRAPOLA TED THROUGH DAYS 3 AND S BECA USE
OF INOPERA Tl VE INSTRUMENTA TION.
Figure 2. Inlet and Outlet SO2 Concentrations
During Run No. 7
2,000
7,500
°- 7,000
s
500
200
0
,-5O2 OUT
5 70
RUN DURA TION, days
75
Figures. Inlet and Outlet SO2 Concentrations
During Run No. 2
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3,000
2,000 -
1,000 -
0 5 JO
RUN DURA TION, days
THE POOR SO, RECO VERIES DURING THIS PERIOD
RESULTED FROM POOR QUALITY SOLUTION CAUSED
BY MECHANICAL PROBLEMS IN THE SODA ASH FEED
SYSTEM AND EVAPORATION AREA, AND LOW FEED
RA TES TO THE ABSORBER WHILE BALANCING TANK
INVENTORIES.
Figured Inlet and Outlet SO2 Concentrations
During Run No. 3
the Hue gas or no more than 200 ppm of SO2 in the
outlet gas stream from the absorber, (which shall be the
only source of SO2 emissions), whichever is the lesser.
For fuels containing less than 3.15 weight % sulfur the
absorber outlet stream shall contain no more the 200
ppm SO,. For fuels containing more than 3.5 weight %
sulfur the absorber outlet stream shall achieve no less
than 90% sulfur removal from the flue gas.
POWER PLANT OPERATION
During the three sustained operation periods,
the booster blower delivered flue gas at the fixed
rate of 320,000 acfm (the 92-MW design level) to
simulate Acceptance Test conditions, while the
load on Unit No. 11 fluctuated from 60 MW to
108 MW. The multileaf stack damper was open
during the operating periods, which, at times,
allowed supplementary flue gas with lower SO2
concentrations from Unit No. 6 to be pulled across
the stack to the absorber.
Absorber Redrculotion Piping
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When the boiler is operable and a period of in-
tegrated operation of the SC>2 recovery and reduc-
tion processes has been achieved, the performance
of the FGD demonstration plant will be evaluated
for EPA by TRW, an independent test and evalua-
tion contractor. The objective of the test program
is to obtain the data and provide the information
needed to determine the applicability of the proc-
ess for potential users within the utility industry.
The Test Program criteria include these major
goals:
• Verify the capability of the W-L SO2 Recov-
ery Process (1) to meet performance guar-
antees and (2) to reduce emissions for min-
imum impact on the environment.
• Verify the capability of the Allied Chemical
SC>2 reduction process to produce sulfur of
quality set forth in acceptance criteria.
• Determine and report the cost of the demon-
stration plant in terms of energy and materials
consumed.
• Determine and report the technical perform-
ance of the demonstration plant, primarily (1)
reliability and availability, (2) effect on boiler
performance, and (3) flexibility.
The Test Program includes three major tasks:
• The Baseline Test
• The Acceptance Test
• The Demonstration Test and Evaluation
The Baseline Test was conducted in the spring of
1974 and the spring of 1975, and the results were
reported in February 1977. During the Baseline
Test, extensive sampling of the flue gas was made
before retrofit of the FGD plant to chemically and
physically characterize the boiler flue gas. Boiler
operating performance was also evaluated; included
was the establishment of heat rates, efficiencies, air
inleakage rates, and electrostatic precipitator (ESP)
performance. These data establish a baseline per-
formance to be compared with boiler performance
after retrofit of the FGD plant.
An Acceptance Test will be conducted to verify
that the process performance guarantees have been
met. Over a period totaling at least 15 days, the
FGD plant must meet the minimum SC>2 removal
requirements of the performance guarantees at two
specified levels of boiler load, and must not exceed
the specified amounts of raw materials and utilities
consumption.
The Demonstration Test and Evaluation
will comprise a 1-year continuous test program
during which flue gas parameters, boiler
operating parameters, and selected performance
parameters for the FGD plant will be recorded by a
system that permits continuous monitoring of 45
parameters and includes a data acquisition system
for scanning the sensor outputs at 2.5- or
5.0-minute intervals. The data are stored on mag-
netic tape. Where continuous monitoring is not
possible, data are collected at lesser frequencies or
intermittently. Three intensive test periods totaling
approximately 9 weeks have been set aside during
the demonstration year to conduct additional tests,
which include:
• Tests for collection of data not amenable to
continuous monitoring
• Tests at specified normal operating conditions
of the boiler
« Tests at specific operating conditions not
normal for the boiler
• Tests using manual sampling and analytical
techniques for the measurement of flue gas
parameters
In response to the major objectives of the Test
Program, the data will be evaluated with major
emphasis on determining the pollutant reduction
performance of the FGD plant. Data results and
interpretations will be incorporated in a compre-
hensive test report at the completion of the Test
Program, currently scheduled for August 1978.
The results will also be summarized in interim
reports submitted periodically during the demon-
stration.
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During the operation of the FGD plant between
July 19 and November 28, there were some major
problems encountered both by the power plant
and the FGD plant. These problems all played
major roles in the delay of plant startup, integrated
operation, and the Acceptance Test. All these
known problems have been solved at this time, and
there should be no cause for further delays.
The major problems encountered in the FGD
plant, along with the corrective action, are listed in
Table 2.
Table 2
PROBLEM HISTORY OF FGD PLANT
PROBLEM
No absorber turndown. The absorber was
to operate between 46 MW and 110 MW
Without dumping the liquid from valve
trays.
The collector tray seals leaked at the walls.
Absorber roof and stack joint leaks oc-
curred.
Temperature control of the low-pressure
steam was inadequate.
There was corrosion on bottom surface of
the lower collector tray.
; SO2 analyzer sample probes became
plugged.
Piping changes were made to the stack re-
heat system.
Low pressure occurred in emergency steam
supply piping to the FGD plant.
SOLUTION
The valve trays were leveled to within 1/8
inch across a distance of 25 feet. Some
valve cap weights were changed and
some'valves were replaced with a differ-
ent valve type.
The original'seal material between the
metal tray and the tile wall of the
absorber failed. This material was re-
moved and replaced with packing and
silicone caulking.
The gaskets between the top of the ab-
sorber wall and cover and between the
reheat venturi and the stack were rein-
:. farced.,, _
The desuperheater on the low pressure
steam line was relocated to give better
steam saturation and ternperature con-
trols.
The bottom surface of the collector tray
(exposed to flue gas) was sand-blasted
and lined with cured rubber.
Newly designed, traced, and air purged
sample probes have been installed, elim-
inating the plugging.
The size of the ring header supplying
natural gas to the four burners was
increased, and new regulators were in-
stalled to maintain steady gas pressure to
all four burners.
NIPSCO removed the flow meter orifice in
the emergency steam line.
1
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Purge Treatment Crystallizers
Purge Dryer
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NIPSCO is currently making repairs to the
damaged Unit No. 11 boiler. The unit is scheduled
to be back on line in May with the main steam
supply available to the FGD plant shortly there-
after. Total integrated operation is planned for
mid-June, with the Acceptance Test to begin in
July. Figure 5 shows the schedule for the other
related plant activities.
During the Acceptance Test, the FGD plant will
be tested at the 92-MW level for 12 days, and at
the 110-MW level for 83 hours.
During the demonstration year the FGD plant
will be operated at varying levels and on a wide
variety of coals. It will also be tested at varying
particulate matter loadings in the flue gas.
pteteUmtNo.'ll Repairs
m to'FGD Plant
ufpment Checkout
crate Purge Treatment Area
iiiiiii i in ill i ill n ill 11 mi ill in in 11 in
fdditional So'utibn Makeup
CONTINUES
THROUGH i
AUGUST 1978
Figure 5. Davy FGD Plant Operation Schedule in Weeks
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Following successful completion of the Accep- ;
tance Test, EPA will issue another progress report, '
with a final report to follow the 1 -year demonstra- '.
tion period. The Baseline Test report was issued in i
February 1977, and two films reporting progress at •
the FGD plant will be released in future months.
This report has been jointly prepared by the ;
Environmental Research Information Center !
(Technology Transfer) and the Industrial Environ- !
mental Research Laboratory (Research Triangle
Park). Another capsule report is planned to
summarize and discuss the final test results. For
further information on the NIPSCO and other
EPA-sponsored FGD programs, write:
Utilities and Industrial Power Division
Industrial Environmental Research Laboratory
Environmental Protection Agency
Research Triangle Park, N.C.27711
FGD Absorber and Stack With Surge Tanks in Foreground
if US GPO: 1977—758—801
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