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: 1977758801

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